JULY 21, 2004 FINAL ARGUMENT OF TERASEN GAS INC.

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1 BRITISH COLUMBIA HYDRO AND POWER AUTHORITY ( BC HYDRO ) 2004/05 AND 2005/06 REVENUE REQUIREMENTS APPLICATION AND BRITISH COLUMBIA TRANSMISSION CORPORATION ( BCTC ) APPLICATION FOR DEFERRRAL ACCOUNTS PROJECT NO INTRODUCTION JULY 21, 2004 FINAL ARGUMENT OF TERASEN GAS INC. Terasen Gas Inc. ( Terasen Gas ) is an intervenor in the BC Hydro 2004/05 and 2005/06 Revenue Requirements Application ( the Application ) and the BCTC Application for Deferral Accounts ( the BCTC Application ) and makes this submission in accordance with BCUC Order No. G The interests of Terasen Gas relate to the BC Hydro Application and therefore the issues addressed in this submission pertain to that application. The submission is organized in the order of the Revised Hearing Issues List 1. BCUC Role in Review of the BC Hydro s Resource Expenditure and Acquisition Plan ( REAP ) 2 and Integrated Electricity Plan ( IEP ) 3 The Commission s Resource Planning Guidelines 4 cite subsections 45 (6.1) and (6.2) of the Utilities Commission Act ( UCA ) as the legislative background for the Commission s mandate with regard to the preparation and review of utilities resource plans. The Commission indicates that its intent in the oversight of utility resource plans is to facilitate the cost-effective delivery of secure and reliable energy services. Subsection 45 (6.1) of the UCA states that a public utility must file its plans in the form and at the times required by the Commission and subsection 45 (6.2) (a) states that the Commission may establish a process to review all or part of the plan and to consider the proposed expenditures referred to in the plan. BC Hydro indicated in the proceeding that its REAP constituted the required filing under subsection 45 (6.1) and the IEP did not fall under this legislation. The IEP is a planning document that evaluates many scenarios and portfolios of resources but does not contain a specific prescriptive set of 1 Exhibit A-33 2 Exhibit B Exhibit B Exhibit C27-9 1

2 capital expenditures or resource acquisitions. As such the IEP does not, in BC Hydro s view, require approval by the Commission. The REAP, on the other hand, contains specific capital spending and DSM plans for two years and energy purchase plans for a four-year period and is the filing requiring Commission approval. The March 31, 2004 REAP submitted in this proceeding is an abbreviated document since the detail was filed in other parts of the Application. BC Hydro anticipates that future REAP filings will be considerably more extensive 5. Terasen Gas appreciates BC Hydro s desire to control the planning process and to avoid cumbersome regulatory processes in the review of its IEP but also understands the concern of stakeholders that meaningful input into the IEP may be limited if there is no public forum under the auspices of the Commission in which the differing interests of various parties may be pursued. The concern of the IPPBC around financial screens and the decision making process flowing out of the IEP is particularly pertinent in this regard 6. In view of the recently revised UCA, the updated Resource Planning Guidelines, significant changes for BC Hydro arising from the Provincial Energy Policy, as well as BC Hydro s long absence from full regulatory oversight by the Commission, Terasen Gas is of the view that the Commission should allow for public process in the review of the IEP as well as the REAP. The process described by Mr. Elton and Ms. Van Ruyven at Volume 8 of the Transcripts, Pages 1002 to 1019, in which a more extensive REAP filing is made annually for Commission approval and an IEP is filed every other year and forms the contextual background for two successive REAP filings may prove over time to provide an appropriate balance. In the meantime the Commission should use its discretion in establishing the form and times of resource plan filings and its authority to establish a review process to ensure that adequate consideration is given to stakeholder views in the IEP process. Terasen Gas believes that the Commission will best be able to achieve its resource planning goal of facilitating cost-effective delivery of secure and reliable energy services if common filing times and review periods for resource plans are established across utilities in the province. Adopting this approach will promote more consistency in planning assumptions among the utilities and will enable the Commission and stakeholders to be better informed of the energy and resource options at any point in time. This, in turn, will enhance effective and efficient decision making around projects and energy acquisition initiatives arising from utility resource planning across the province. 5 T7: 898/25-899/8; BC Hydro Final Argument, p T21: 3797/ /10 2

3 Capital Structure BC Hydro s evidence with regard to the revenue requirements arising from the debt and equity in its capital structure is that these have been determined through a formulaic application of the provisions of Heritage Special Directions #1 and #2 ( HSD#1 and HSD#2 ) to its debt and equity forecasts for F2005 and F2006. BC Hydro s position is that there is little or no room to modify the application of the provisions of these Special Directions. Some of the provisions, such as the definition of equity, have pre-dated HSD#1 and HSD#2 by being included in earlier Special Directions from the Province. The Province has reaffirmed its view on these matters by leaving the definitions the same. In the case of the treatment of future removal and site restoration costs ( FRSRs ) and asset retirement obligations ( AROs ) the provincial government was made aware that an accounting change governing these issues which had the effect of increasing BC Hydro s equity component and yet indicated that the requirements of GAAP should be followed 7. Terasen Gas appreciates that intervenors in this proceeding and stakeholders in previous BC Hydro matters have issues with the implications of HSD#1 and HSD#2 and the resulting differences in the regulatory treatment of BC Hydro relative to investorowned utilities in the province. In spite of this, Terasen Gas agrees with BC Hydro that the hearing was not about whether the provisions of Special Directions are appropriate or fair 8 and that it is the prerogative of the provincial government to issue Special Directions that determine the basis upon which its return will be calculated 9. Further, if the provisions of the Special Directions are to be modified, it must be the provincial government that does so by amending or replacing them. Beyond the limitations imposed by the Special Directions, Terasen Gas submits that the extent and quality of the evidence in the proceeding with respect to capital structure and return issues, other than that of the Applicant, does not provide an adequate basis for a Commission determination on these matters. Proceedings before the Commission that deal with capital structure and equity return issues normally include expert testimony, and extensive discovery and cross-examination phases in order to have the issues fully explored before the Commission panel making the decision. This did not occur in this 7 T6: 698/ BC Hydro Final Argument, p. 7 9 BC Hydro Final Argument, p. 19 3

4 hearing primarily because participants knew that these aspects of BC Hydro s revenue requirements were governed by the Special Directions and such evidence would not provide any basis for a decision that is within the Commission s jurisdiction. If circumstances were different and it was within the Commission s jurisdiction to conduct a full review of BC Hydro s capital structure and return and issue a decision, Terasen Gas believes that debt/equity ratios and returns on equity should be similar to those awarded to comparable utilities. Power Smart and Demand Side Management Terasen Gas has noted the variety of intervenor views on the Power Smart that were elicited during the course of the hearing and the pre-hearing discovery process. These ranged from the view that DSM initiatives should be expanded significantly (the Sierra Club) to intervenor groups opposing the Power Smart programs directed to customer segments other than those they represented (BCOAPO et al, JIESC and IPPBC) and overall contraction of Power Smart in general (Citizens for Public Power). Terasen Gas believes BC Hydro has provided reasonable evidence that Power Smart is a low cost contributor to the Company s portfolio of resources and should be approved. Beyond that general recommendation Terasen Gas has specific submissions. There was considerable interchange with Panel 4 on the issue of indirect Power Smart costs and whether or not they should be allocated down to the level of individual programs 10. These interchanges led to the preparation by BC Hydro of Exhibit B1-81 in which the indirect or portfolio-level costs were allocated to the individual Power Smart programs on the basis of energy savings. Terasen Gas agrees with BC Hydro that such an allocation of the indirect costs is likely to produce arbitrary results and therefore the Commission should not use the results in the right-hand set of columns in the table of Exhibit B1-81 as a basis for modifying or eliminating programs. The issue of the appropriate level of indirect or portfolio-level Power Smart spending should be considered by the Commission as a separate matter from DSM program selection. BC Hydro includes the indirect costs (as indicated in Exhibit B1-81 and other places) at the portfolio level and in doing so, demonstrates that the overall Power Smart program is a 10 See, for example T11:

5 cost-effective resource. Terasen Gas submits that BC Hydro s treatment with respect to the indirect and portfolio-level Power Smart costs is appropriate. Further cross-examination on Power Smart dealt with the matter of what an appropriate threshold level should be for the RIM test in order for a particular DSM program to proceed. Some intervenors supported employing a RIM ratio of 1.0 as the program threshold. This view that a program must exceed a RIM ratio of 1.0 suggests that all ratepayers must benefit from a DSM program through lower rates and therefore lower bills. This starts from an assumption that there is an equitable collection of revenues from the rates prior to the DSM programs that will no longer be equitable if DSM benefits flow to participating customers and non-participating customers pay a bit more. In reality, utility rate classes are aggregations of customers that may have widely varying energy usage and characteristics. While the revenues collected from a class as a whole may appropriately recover the costs to serve that class, the revenues collected from individual customers may not equally match their associated costs. For example, revenues from higher consumption residential customers may be higher than the associated costs to serve them and revenues from lower consumption residential customers may be too little. Further, customers that impose disproportionate loads on the system during peak conditions may benefit from those in the same class with more even load characteristics. These are issues that rate design seeks to rectify (in addition to inter-class concerns) but which are not possible to fully eliminate. In spite of such intra-class revenue-to-cost differences the rates are found to be just and reasonable by utility commissions. It has also been the case that this Commission has approved rates out of rate design proceedings where revenue-to-cost ratios are not exclusively set at one to one but that a range of reasonableness such as +/-10% is accepted. DSM and Power Smart programs that are widely available but which only a portion of the customers avail themselves of, may cause minor rate increases for non-participants. Terasen Gas notes the testimony of Mr. Woolf on behalf of the Sierra Club that some jurisdictions in the United States have ceased to consider the RIM test in their evaluation of DSM programs because the rate impacts are quite small relative to the benefits achieved 11. Terasen Gas submits that the small effects of DSM programs on revenues and costs within rate classes and between rate classes are well within the intra- and 11 T21: 3779/3-9 and 3788/

6 inter-class tolerances of what has been found just and reasonable in this jurisdiction in the past. Fairness is found in a variety of DSM programs made broadly available and providing all customers with options for reducing their energy consumption. Terasen Gas further notes the evidence of BC Hydro witnesses that the DSM program results filed in the proceeding for the RIM, TRC and UC tests are conservative in that they do not include any quantification of transmission and distribution capacity benefits that result from DSM programs deferring the need for system improvements in these areas 12. Additionally, the effect of lost revenues in the RIM test may be overstated to the extent that the lost sales to BC Hydro customers can be marketed as off-system sales or market purchases can be reduced 13. These factors, pointing to tangible but un-quantified additional benefits or lower costs, provide further support for the merit of approving the Power Smart portfolio. Terasen Gas agrees with the Joint Industry Electricity Steering Council in the matter of BC Hydro needing to expand their development of capacity-based DSM initiatives 14. Terasen Gas also believes that BC Hydro should develop a complete inventory of fuel substitution potential rather than remain with a preliminary sample as has been included in the Power Smart 10-Year Plan 15. Cost-effective fuel substitution programs will promote the efficient use of energy in the province 16, in keeping with the provincial energy plan 17 and provide energy consumers with appropriate signals to make the right energy choices. System Extension Test BC Hydro s application of its System Extension Test ( SET ) consists of a blend of current estimates and calculations for some elements and out-dated input factors in other areas. Current construction costs are used for the system extension as well as up- 12 T11: 1672/4 1674/17 13 T21: 3766/7 3767/4 14 T11: Exhibit B1-2, Appendix H, Page 1, Fuel Switching paragraph 16 Exhibit B1-2, Appendix N, Pages 28, 30, 32 and 34. BC Hydro s fuel substitution programs indicate that it is more efficient to burn natural gas at the end use than BC Hydro generating electricity on the margin with natural gas, delivering that electricity to the home, and then finally using that electricity in the end use appliance. 17 Exhibit C4-6, Page 33 6

7 to-date estimates of upstream system improvements and transmission costs. These estimates take account of whether or not there are capacity constraints in the locale of the proposed extension and also of the load characteristics of the customers being added 18. Other input factors such as the Cost of Electricity have not been updated since 1998 when the current SET tariff was initially approved by the Commission. BC Hydro indicates that the inputs have not been updated in part due to the fact that rates have been frozen in the intervening six-year period. BC Hydro also considers that the coming rate design proceeding is the appropriate forum in which to update these factors and revisit the System Extension Test in general 19. Terasen Gas does not see anything in BC Hydro s SET tariff 20 which would link the updating of input factors such as the Cost of Electricity with whether or not rate changes had been approved in the period in question. BC Hydro s tariff does not list or identify the current values for the various SET inputs but rather provides definitions of the items included. The implication is that input factors can be updated as costs and market conditions change without the need for any filing of tariff changes. While the provisions of the SET tariff do not specify a frequency for updating the input factors, Terasen Gas respectfully submits that this should be done on a regular basis, at least annually and certainly much more frequently than six year intervals. Since the SET input factors have not been updated since 1998 Terasen Gas submits that BC Hydro does not know if the SET results are appropriate. Any accuracy in the estimation of capital costs for a system extension may be completely overshadowed by the out-of-date input factors. A swing of one or two cents per kilowatt hour in the cost of electricity in the SET could make the difference between every kilowatt hour of forecast load on a system extension making a positive contribution to every kilowatt hour causing a larger deficit. Terasen Gas is particularly concerned about this in the case of electricity being used for space heating. An out-of-date low cost of electricity being used in the SET could well be encouraging the use of electric space heating by understating the costs of attaching to the system. Expanded use of electric space heating will, in turn, 18 T15: 2633/4-9 and Exhibit B T15: 2631/ /12 20 Exhibit A41-3 7

8 exacerbate the impact of marginal cost increases on BC Hydro s system and future revenue requirements. Terasen Gas respectfully requests that the Commission require BC Hydro to update the SET input factors to current levels. Making these updates is not a rate design issue; it is consistent with the current SET tariff and does not require any tariff changes. Terasen Gas does agree that further changes to the SET beyond these regular updates are appropriately in the realm of rate design. Burrard Generating Station and Thermal Generation Issues At the close of the evidentiary phase of the hearing the Commission Chair identified a legal issue with respect to Burrard Thermal, asking whether the principles of imminence of return to service and certainty of return to service as indicated in the Bonbright text extract (Exhibit A-50) were applicable in the determination of the depreciation rates at the plant 21. The section of the Bonbright text deals with a plant that is temporarily out of service and asks whether such a plant should be in rate base. Terasen Gas submits that Burrard Thermal is not out of service so the particular circumstances referred to in Exhibit A-50 are not applicable. The evidence is that Burrard Thermal has three units providing VAR support to the Lower Mainland transmission system and three units are in backup generation mode. The VAR support role is significant in that to replace that capability BC Hydro (or now BCTC) would have to initiate a project to acquire and install static VAR compensators, a project that would take several years to complete. The three units that are in backup generation mode can be brought into service in a period of 6 to 12 hours. With the current relationship between gas prices and electricity prices, and the high heat rate at the Burrard plant it has made more sense to buy power in the market than to dispatch Burrard. Burrard Thermal s backup generation role, particularly with the location of the plant in the major market area, provides an important risk mitigation element in BC Hydro s portfolio and contributes to the security and reliability of supply. While Burrard Thermal is currently operating below its capability and there is uncertainty about the plant s future, the facts above demonstrate that Burrard is a valuable contributor in BC Hydro s portfolio of resources. Terasen Gas submits that the 21 T21: 3994/6-10 8

9 referenced principles from Exhibit A-50 are not applicable in the determination of depreciation rates for Burrard Thermal. With respect to BC Hydro s gas supply contracts and mitigation of the costs Terasen Gas notes BC Hydro s testimony that there is ongoing reselling of their capacity on the Duke Energy system that recovers a significant portion of costs 22. Currently, BC Hydro does not appear to be taking advantage of available mitigation opportunities of its capacity on the Nova and TCPL(BC) systems but if BC Hydro exercises its option to return its Southern Crossing Pipeline capacity to the owner it may attempt to re-market its Alberta capacity 23. An earlier interchange between Commission counsel and BC Hydro s Panel 7 indicated that the Burrard Bypass Agreement had given BC Hydro firm access to a liquid gas market at Sumas 24. Additionally, under cross-examination by counsel for IPPBC Mr. Spafford indicated that we don t believe that upstream gas transportation is an absolute requirement to purchase gas at Sumas. It may be desirable and we do have certain upstream gas contracts and later in response a question about the possibility of buying large volumes of gas in the day market that You could choose to do that, but I don t think that would be the wisest way to dispatch that situation 25. Mr. Spafford goes on to outline a prudent approach to gas supply acquisition as involving careful forward planning over the next two years. While acknowledging its direct interest in many of BC Hydro s gas transportation matters Terasen Gas has several comments on the issues outlined above. While it was not explored in depth, Terasen Gas has strong reservations regarding the reference to the Sumas hub as a liquid trading point due to the relatively small volume of gas traded at that point and the reduced number of counterparties available to transact business at that point. Regional gas price isolation at Sumas similar to that experienced in 2000/01 could recur. If BC Hydro had to purchase large volumes of gas at Sumas in peak conditions its added demands would further exacerbate the high gas prices. The premium it might have to pay could amount to the equivalent of several years of gas supply transportation costs in only a few months. Terasen Gas believes that BC Hydro s ability to access multiple gas trading hubs through the holding of upstream gas 22 T20: 3515/ T20: 3516/ /8 24 T20: 3472/ /3 25 T19: 3274/

10 transportation contracts provides significant risk mitigation benefits to BC Hydro and its customers. BC Hydro s efforts to mitigate its gas transportation contracts should be done in a way which maximizes its ability, in peak conditions, to continue to have access to multiple trading points, multiple trading counterparties and diversity of supply in order to fulfill its mandate for secure and reliable supply of electricity to its customers. All of which is respectfully submitted Terasen Gas Inc. Original signed by David Perttula 10