LETTER NO. L-24-94 SIXTH FLOOR. 900 HOWE STREET. BOX 250 VANCOUVER. B.C. CANADA V6Z 2N3 TELEPHONE: (60") 660-"700 ROBERT J. PELLATT BC TOLL FREE: 1-800-663-1385 COMMISSION SECRETARY FACSIMILE: (60") 660-1102 VIA FACSIMILE September 19, 1994 Mr. Greg Krueger Manager, Business Planning Centra Gas British Columbia Inc. 1675 Douglas Street P.O. Box 3777 Victoria, B.C. V8W3V3 Dear Mr. Krueger: Re: Centra Gas British Columbia Inc. - Fan St. John 1994 Integrated Resource Plan QRP) Commission staff have reviewed the 1994 Integrated Resource Plan for the Centra Gas - Fon St. John utility ("Centra-FSJ) and determined that it contains a number of serious deficiencies. Accordingly, the Commission cannot accept the IRP as filed and directs the utility to rectify the deficiencies identified by the Commission staff and refile the IRP by the earlier of March 31, 1995 or the filing of a CPCN looping Application. A copy of the staff review is attached. The Centra-FSJ lRP indicates that a public meeting to present summary comments of the Commission and other interested parties, as well as results of funher analysis, will be held this autumn. The Commission believes that such a meeting is premature and may prove more fruitful if it were held early in the new year. This would allow Centra-FSJ time to establish a stakeholder group as suggested in the staff repon. Commission staff are prepared to aid the utility in this endeavor. Should you choose to go ahead with a public meeting this autumn, the Commission would like to be advised as to the date and location of the public meeting so that staff may attend. Yours truly, DWFJssc Attch. cc: Registered Intervenors CG/CorIIRP-FSJ-L-24-94
Centra Gas British Columbia Inc. - Fort St. John Integrated Resource Plan (" IRP" ) Staff Evaluation Report BACKGROUND Centra Gas - Fon St John Division ("Centra-FSJ") serves approximately 7,320 customers in the City of Fon St. John and its surrounding communities. Approximately 28 percent of volumes are sold to industrial customers, predominantly in the oil and gas sector, 38 percent to commercial customers and 34 percent to residential customers. On November 24,1993 Centra-FSJ flIed an application with the Commission for a Certificate of Public Convenience and Necessity ("CPCN") to loop the transmission pipeline from the interconnect with Wesrcoast Energy Inc. (,'Westcoast") in Taylor to a location just beyond Fort St. John district regulating Station No.2. Uncertainty about several aspectS of the looping project convinced the Commission that a public review of the O'CN application was required. This review took place during the course of the Revenue Requirements Application hearing which commenced February 8. 1994. Although Centra Gas British Columbia ("Centra BCj had filed a draft IRP with Commission staff for its review and comment at the end of 1993, this draft contained a significant number of deficiencies, such as a lack of public involvement, an incomplete review of potential demand side resources ("DSM It ), and no avoided cost study. As a result, the Commission indicated that the draft was unhelpful for utility planning purposes, making evaluation of the looping project substantially more difficult. Accordingly. the Commission was forced to rely on the evidence adduced at the hearing for a preliminary exploration of alternatives to the loop. Based on this evidence. the Commission found that Centra-FSJ had not adequately assessed the demand growth projections upon which the loop proposal was based. The Commission stated that if the demand growth, particularly peak load growth. was less than forecast, the only other principal justification for the loop was increased capacity to reliably handle current peak requirement. Until other less costly measures to mitigate this concern were reviewed, the Commission stated that it was not convinced that improved reliability of deliveries and reduced threat of winter interruption were sufficient to justify the magnitude of expenditure entailed by the loop proposal. As a result the CPCN for the looping project was denied and Centra-FSJ was advised to conduct a more complete assessment of options for addressing its concerns about system capacity in the context of its IRP. In particular, the Commission directed Centra-FSJ to provide a completed IRP for its Fort St. John Division by June 30. 1994. The completed document was filed with the Commission July 11, 1994. Staff have reviewed the document against the Commission's February 1993 IRP Guidelines and have the following comments and concerns. For ease, the discussion has been categorized by BCUC Guideline. Guideline 1: Identification of the Objectives of the plan The BCUe Guidelines call for the identification of those objectives which the utility wishes to achieve through the selection of resources. The Centra-FSJ IRP identifies six objectives. In order of priority, these are: 1. Provide reliable service by minimizing the frequency and length of service outages. 2a. Keep the customers energy bill down by minimizing the service cost. 2b. Preservation of the financial integrity of the Company by providing stable returns to the shareholders and obtaining reasonable financial coSts.
2 3. Consideration of environmental impacts taking into account disruption of local habitat and the production of greenhouse gases and air pollutants. 4. Education of the public by creating awareness of conservation, efficiency developments in energy use and an increased understanding of the regulatory process. 5. Expand rural service where economic. The fIrst four objectives were determined by a review of the objectives stated in the BCUC guidelines, the results of the BC Gas IRP Stakeholder workshop, and objectives identified in other utilities' IRPs. The last two objectives arose from public meetings where the attendees were asked to comment on and rank the relative importance of each of the utility identified objectives. In general, staff accept objectives 1 through 3 as reasonable targets for which to strive through resource selection. However, staff have concerns with regard. to objectives 4 and 5. Educating the public with respect to conservation, efficiency developments and the regulatory process may broaden the public's awareness of the range of resources available and may help to make certain resources more attractive to the public and so more feasible to attain but it does not help determine whether resource A is more attractive than resource B. As such, objective 4 seems to be more properly classified as a strategy or an action to undertake to achieve other objectives than an objective in itself. With respect to objective 5 - expand rural service where economic - staff are concerned that the emphasis is on expansion of the system as a goal in contrast to meeting demand for the services nattIral. gas can provide as efficiently as possible. Meeting this demand may be most economically done in ways other than 'expansion of the grid. Staff is particularly concerned to see this stated as an objective since the Man:h II, 1994 Decision ("the Decision") directed Centra to review the main extension test determinations made by the Commission in the Be Gas Phase B Rate Design Decision and subsequent determinations expected to arise from the 1994 BC Gas Revenue Requirements hearing, and to come forward. with their own test, consistent with these determinations, within two months of the issuance of the latter Decision. Subsequently, Centra-PSJ has applied for an extension on the requirement to come forward. with a new main extension test. In addition, staff are concerned that there is no explicit mention of risk minimization (Le. that a wrong facilities decision will be made) as an objective. Although one might argue that the objective of providing stable returns to shareholders requires that risks be minimi~ so that this objective might be said to subsume risk minimization, a more explicit recognition of the risk minimization objective may lead to a more comprehensive assessment of the actual sources of risk attached to resource selection. Finally, the IRP does not identify any objectives which might be said to go to a social account, e.g. employment impacts. Such objectives have been identified by some of the larger utilities but may be inappropriate for a utility the size of Centra-FSJ. As mentioned above, the objectives are listed in the IRP in order of priority as determined by Centra-FSJ. Although an ordering of objectives was determined at the public meeting. this was revised to give environmental considerations a greater weight. Presumably this ranking reflects the weights that the various objectives would be given in any trade-off analysis undertaken as part of the resource selection or portfolio evaluation process. However, exactly what these weights are is not specified, nor is it clear how the ordering of objectives affected the development of alternative resource portfolios. For each of the six objectives listed above, Centra has chosen corresponding attributes to use when evaluating alternative resources. These attributes are primarily but not exclusively quantitativ~. Gen.~ly, staff believe that the attributes chosen are appropriate with the exception of the public educauon objectIve which would measure the extent to which the objective is achieved by the number of programs implemented. This tends to measure effon rather than results. rj
3 With respect to environmental considerations, Centra-FSJ has identified habitat disruption, greenhouse gases and air pollutants as the attributes it will use. Air emissions will be measured in terms of kilograms per gigajoule. Centra-FSJ may wish to consider providing monetized air emissions values although staff do not recommend that these values be incorporated into the fmancial analysis of individual resources. In addition, the IRP appears to assume that environmental impacts will always be negative; however, if Centra-FSJ were to expand its load to compressor stations currently using sour gas for fuel, there may be environmental benefits for which there should be an accounting. Centra-FSJ plans to measure habitat disruptions qualitatively. No information is given as to how this will be done or what types of disruptions will be considered. As such, it is difficult to assess how well the assessment will be done. Where a particular objective is measured by more than one attribute, e.g. environmental considerations, no information is given as to how the attributes within the account will be weighted. As one of the goals of IRP is to make the planning process more transparent, this is a flaw in the current document. Guideline 2: Development of a Range of Gross (pre-DSM) Demand Forecasts The BCUC Guidelines encourage the use of end-use forecasting and require the development of more than one forecast in order to reflect uncertainty about the future. Centra-FSJ's forecast methodology uses a hybrid of econometric and end-use techniques. Specifically, Centra-FSJ forecasts demand by multiplying the forecast number of customer by their forecast average use. The average use is based on historical data, adjusted to incorporate reductions in use per customer due to energy efficiency legislation and naturally occurring conservation. The result is then adjusted for price and income elasticities determined through a literature search as well as an econometric analysis based on FoIt St. John data. This approach appears to reflect Centra-FSfs concern that end-use forecasting is costly. Staff suggest that Centra-FSJ review the BC Gas Phase 2 Decision, dated August 4, 1994, particularly as it regards the Commission's concerns about BC Gas' econometric methodology for estimating elasticities. As well, staff believe that Centra-FSJ's concern about the expense of end-use forecasting may be misplaced. Much of the expense of end-use forecasting is in data collection. For a small system, such as Centra-FSJ, with a customer load that may be fairly homogeneous, the expense of end-use modeling may be relatively low. Staff believe that Centra-FSJ should not reject the benefits of end-use modeling before it has explored the actual costs and benefits. Centra-FSJ should also review the BC Gas Phase 3 Decision, dated August 12, 1994 as well as the IRPs of other utilities in its further development of cost-efficient, effective demand forecasting. The IRP does not explain how the peak: day demand forecast is established. Staff consider this a serious flaw in being able to evaluate the IRP as the peak day demand forecast is critical for an evaluation of the need for looping. In its March 11, 1994 Decision, the Commission stated that "additional data are needed to validate the simulation model (for the Centra-FSJ transmission pipeline) and confmn the design flow rates under circumstances when liquids are not a problem". On Page 18, the Decision directed Centra-FSJ to upgrade the Taylor check meter station in 1994. The IRP should set out the basis for the estimate of current peak day requirements for the Taylor/Fon St. John system, clarify if this is send-out to customers or receipt from Westcoast and identify the corresponding peak hourly quantity. This information will be necessary before the Commission can reach a decision on any re-filed CPCN looping application. As suggested by the BCUC Guidelines, Centra-FSJ has provided three different demand forecasts: a most likely forecast, an optimistic forecast and a conservative forecast. These differ primarily with respect to assumptions made regarding the oil and gas industry in the area and the possibility that the burning of sour gas couid be prohibited over the forecast horizon. Staff believe these forecasts cover one source of major uncertainty with respect to demand likely to be faced by Centra-FSJ over the next fifteen years. However,
4 they do not explicitly address the impact of alternate natural gas price forecasts which are likely to be another source of uncenainty. In addition to the methodological concerns identified above, staff have found several mistakes in the presentation of the results of the forecast. Table 5-1 shows expected annual volumes and expected peak day volumes at the end of the fifteen year forecast period under each of the three scenarios. The average annual growth rates shown in this table have been incorrectly calculated since they assume 1993 base year annual and peak day volumes which are inconsistent with values given elsewhere in the report (See Figure 2-2 and Appendix B) and are simple rather than compound rates of growth. As a resul~ the growth rates shown in the summary table significantly over-state the actual forecast growth rates based on Appendix B. For example, under the most likely scenario, annual and peak day volume growth rates are shown at 3.30 percent and 1.97 percent per year respectively, when the true compound growth rates are in the order of 0.6 percent and 0.8 percent. Similarly, under the optimistic forecas~ annual and peak day volume growth rates are shown at 9.44 percent and 3.76 percent per year while the true compound rates are in the order of 4.0 percent and 2.0 percent. Fmally, under the conservative forecas~ the growth rates shown are 1.08 percent and 0.60 percent respectively while the compound rates are approximately -1.0 percent and -0.4 percent. Presumably the demand forecasts used in the Resource Optimization model (See Section 8 of the IRP) do not rely on the summary table so that the assessment of the various portfolios against varying levels of demand is unaffected. Guideline 3: Identification of Supply and Demand Resources Guideline 4: Characterizing Supply and Demand Resources Smmly Side Resources Currently Fort St. John is supplied through a single base load supply contract which is supplemented with winter seasonal contracts. This contract expires in 1996 and is expected to be replaced with contracts containing a fixed demand charge. Page 21 of the March II, 1994 Decision directed Centra-FSJ to bring its baseload contraCt into confonnity with the Commission's Energy Supply Contract Rules by the end of 1994 and to provide justification in the context of IRP that all changes are in the public interest. When discussing the gas supply contracts, the IRP is sometimes unclear if it is referring to supply at the Westcoast interconnect or delivered to consumers. For supply at the interconnect, staff expect an assessment of alternative supply arrangements that can be used to evaluate the appropriateness of the new gas supply contraCts portfolio and to calculate the gas cost portion of avoided costs. This should include a setting out of the costs of potential baseload, seasonal, peaking and storage supplies. The IRP states that storage is reponed to be uneconomic at this time, a result which staff consider somewhat surprising considering the cmrent 37 percent load factor for the utility. Staff are unclear as to how the gas supply contracts were used in terms of evaluating supply options to Centra-FSJ. Page 7.1 of the IRP states that a "set of gas contracts by season were incorporated into the (Resource Optimization) model that were tied to the historical Sumas market index" but no details are given. Similarly, the IRP indicates that an increment of approximately 4 - 5 percent based on design versus average day is incorporated into daily winter season gas requirements for reliability, but goes on to say one would pay this premium. As a result. it is not clear if the 4 - 5 percent increment refers to volume or price. Lastly, the price forecast for 1994 and 1995 shown in Table 7-1 are about 25 percent higher than current wellhead prices of $1.85 per GJ. Centra-FSJ has relied on the Energy, Mines and Resources Canada July 14, 1993 forecast and has not explained why it has used a forecast approximately one year out of date. An analysis of gas supply that started with typical current supply arrangements and prices (probably 'j
5 with a demand/commodity structure) would likely give more understandable and reliable results. As gas costs are a significant portion of overall costs and are relatively unpredictable over time, the IRP should include a limited amount of sensitivity analysis related to alternative price forecasts. Currently, the gas is delivered to the Centra-FSI grid via the Westcoast system at a minimum contract pressure of 500 psig per day_ Although actual delivery pressure is usually greater than the contract minimum, it has from time to time dropped to the minimum. When this occurs, the IRP indicates that deliveries are insufficient to meet peak day demand and emergency operations must be performed by Centra staff to ensure gas supply to FSI customers. This involves manually bypassing regulators on the transmission system, a practice which is characterized as creating a hazardous condition and contravening safety codes and practices. Evidence at the 1993 hearing indicated that delivery pressmes approaching the 500 psig contraCt minimum resulted from upsets on the Westcoast system and were often compounded by hydrocarbon liquids and water in the gas. On page 13 of the March 11. 1994 Decision, the Commission directed Centta-FSJ to expeditiously relocate and increase the size of the Westcaast supply tap and interconnect piping in order to increase supply ptessme and prevent liquids from entering the Centta-FSJ system. Staff understand this work is proceeding in 1994 but it is not clear if the information in the IRP reflects the effects of these efforts. The utility has also investigated a number of other options to meet peak demand and increase system reliability. These include pipeline expansion options as well as addition of a compressor. Centta-FSJ has also examined the possibility of storage either through liquid namral gas. propane/air. or storage contracts. The liquid natural gas and propane/air options have been rejected as impractical or uneconomic due to the high capital outlay and the relatively small scale requirements for such facilities. Details on the costs involved were not provided. Storage contracts are seen as possible for the future but, as indicated earlier. aIe dismissed as uneconomic at this time. Again, no costs are provided to support this judgmenL The IRP indicates that the Resource Optimization Model can choose the appropriate pipeline addition but gives no details about the size, location, and cost of alternatives made available to the model. Staff note that the High Reliability and High DSM portfolios discussed in Section 8 of the IRP, all use 9.7 km of loop compared to the 17.2 Ian applied for in the original CPCN application. Staff are surprised that one length would be optimal for peak day requirements ranging from 17.0 to 24.4{fJ per day. A final supply side option discussed in the IRP is interruptibility of both residential and commerciallindustrial customers. The estimate of residential interrUptibility, approximately 800 to 900/GI per day. was based on a customer survey. The IRP indicates that significant costs could be associated with accessing residential interruptible supplies and lower costs with industrial interruptible supplies. However, as the costs are not finn at this time, within the Resource Optimization Model the costs have been assumed to be zero. Partly as a result of the associated costs, the IRP suggests that the actual potential of residential interruption is likely to be less than that indicated in the survey. A further, 1,500/GJ per day is assumed to be available from industrial and commercial customers. This estimate is based on a grouping of billing data by standard industrial classification ("SIC") code. It is not clear from the text what assumptions were made in order to derive the volume estimate but it appears that the estimate of interruptibility was not varied by level of overall demand. Staff believe this should be taken into account. For example, in discussing the optimistic demand forecast, the IRP notes the possibility of additional compressor load based on producers changing from sour gas as a fuel to processed gas. The possibility may exist for compressor operators to optimize economic and/or environmental benefits by operating the compressors as interruptible loads with sour gas as a back up fuel. It would be useful if the IRP discussed this option and, if it is not a possibility, briefly explained why. Overall, an explanation of the assumptions that were used to derive the estimate of interruptible supply would be helpful.
6 The IRP does not discuss whether increased supply and added reliability can be addressed through buying additional pressure at an existing purchase point or adding a purchase meter station to provide a back feed at a new point. As these options were discussed at the recent hearing, it was expected that these options would be addressed. In addition, staff found the description and evaluation of the options which were discussed to be extremely brief. For example, the map of the Centra-FSJ system does not indicate where the desired pipeline loop would be routed or the location of existing low pressure areas which require reinforcement. Similarly, the IRP does not provide the financial costs associated with any of the resource options, estimates of the impacts on customers bills, or a discussion of any of the environmental impacts. Stable investor returns. minimum customer bills. and consideration of environmental impacts were all identified as objectives to be achieved through the IRP resource selection process. Without the provision of this information, it is impossible to tell if the IRP meets these objectives. Staff anticipate Centra-FSJ will not re-file the looping application until it can provide more complete justification of the alternative it proposes. However. the utility does intend to hold a public meeting in the fall of 1994 to address the requirement for a loop of the transmission line. Staff consider it essential that Centra-FSJ present complete information about loops and other alternatives to provide capacity to meet peak day requirements. This should include information on alternative locations for loops and the impact on rates to each customer class. For example, discussion at the 1994 hearing indicated that it may be advantageous to replace a section of pipeline downstream of the Town Border Station with a larger line that has a higher pressure rating. In addition, the reliability analysis under Appendix E of the IRP indicates that, if peak demand coincides with low delivery pressure (which is projected to occur for 12 hours in 15 years) Centra will be able to deliver 80 to 90 percent of its peak load. in which case an alternative to looping might be selective curtailments. This option should be canvassed with customers. especially larger industrial customers. such as the Stoddart Compressor Station. In summary. if a higher delivery pressure from Westcoast cannot be negotiated, Commission staff does not object to 500 psig as a design basis receipt pressure for the Centra-FSJ transmission system. However, the need for. and amount of looping should be re--evaluated after the upgrade at the Westcoast interconnect referred to in the Decision are installed and the peak day supply requirements of customers have been more accurately determined. Demand Side Resources In addition to the supply-side options, Centra-PSJ undertook a literature search to identify potential DSM options. As a result, four DSM programs are seen as potentially cost effective for Fort St. John. The chosen programs are a Residential Water Heater Replacement Program, a Residential Home Visit Program, a Commercial New Envelope Upgrade Program and an Existing Heating Upgrade Program. All programs target conservation and efficiency and appear cost effective although only the Residential Home Visit Program has a TRe above 2 and a RIM above 1 when using a 100 percent incentive level. As all the assessments are based on data from other utilities, Centra-PSJ plans to update the analysis of the programs for Fort St. John before selecting programs for development and implementation. Staff agree that the analysis should be redone considering the specifics of the utility's service area. However, this is not the staffs only concern with respect to these programs. The tests appear to have been done using an avoided cost of $2.50 per GJ, a value which staff finds low, particularly considering that the residential tariff is approximately $4.00 per GJ. No information is provided as to how the $2.50 per GJ value was derived. As a result, it is unclear whether this represents solely the avoided cost of gas or whether it includes the avoided cost of facilities. Staff consider this to be a major flaw in the IRP. As discussed on page 11 of the Decision, the cost of looping can be used along with other costs to estimate avoided costs either as the value of DSM to bring loads with system capability or as the cost of expanding the system to handle higher volumes. Staff recommend that Centra-FSJ review the Commission's comments in the BC Gas Phase 3 Decision regarding DSM programs. In addition, Centra-FSJ should review the Commission's comments regarding (\
7 the BC Gas Home Visit Program and the opportunity for more information on the benefits of such programs as a result of a joint utility Greater Vancouver Regional District pilot project. Finally, staff recommend that Centra-FSJ review the Commission's statements on avoided cost made in the BC Gas Phase B Rate Design Decision, the subsequent avoided cost studies undertaken by BC Gas, the Commission's comments in the BC Gas Phase 3 Decision, dated August 11, 1994 and prepare an avoided cost study consistent with the Commission's statements. Guideline 5: Development of Multiple Integrated Resource Portfolios Guideline 6: Evaluation and Selection of Resource Portfolios. The IRP presents three possible resource portfolios: least cost at high reliability; least cost with large interruptibility; and additional DSM beyond avoided costs. The first assumes that the existing system operates at the minimum contract pressure and that new pipeline capability is available in different sizes. No interruptibility is assumed. The second assumes that in addition to pipeline looping options, interrUptibility of about 2400/GJ per day is available at no cost. This assumption was made since it was difficult to price interruptibility with certainty but likely over-estimates the amount of interruptibility available. The third portfolio assumes an avoided cost of $3.50 per OJ which allows for the development of increased DSM. It is not clear what assumption about interruptibility has been made with respect to this portfolio although it appears that no intemlptibility has been assumed. Portfolios 1 and 3 assume 9.7 km of loop for all demand forecast cases. Each portfolios has been put through a resource optimization model, briefly described. in the text, and assessed against each of the demand forecasts developed earlier. Total net present value of the portfolio, the levelized unit cost of the portfolio, whether or not new pipeline would be needed assuming the portfolio, and the expected hours of intemlption over the next 15 years given the portfolio, are calculated and presented. These values relate to the financial and reliability objectives identified in the IRP. As with the assessment of the individual resources, no attempt has been made to assess the portfolio with respect to environmental impacts. The interruptibility portfolio shows 12 hours of expected system interruption over the next IS years and a financial cost that is approximately 6 cents less, on a unit cost basis, than the other two portfolios. This is the average unit costs, staff expect the costs to the residential class would be substantially higher. The IRP does not present a preferred portfolio; however, the action plan states that a public meeting will be held in the autumn to specifically address the requirement for a loop of the transmission line. As indicated earlier, it would be useful if the weights attached to the various objectives and related atuibutes were made specific and their use in portfolio development fully explained. Staff recommend that Centra-FSJ review the work done in this area by West Kootenay Power Ltd. in support of its IRP. In addition, it would be useful to know more about the resource optimization model used by Centra-FSJ. Is it a model developed in-house or was it brought in from elsewhere? What are the exogenous inputs and what elements are treated endogenously? How are the DSM resources handled? The answer to all of these questions would improve the understandability of the IRP. Guideline 7: The Action Plan The action plan outlines a variety of actions which the utility plans to undertake to improve the quality of the IRP. These actions relate primarily to improvements in the demand forecast and in the analysis of DSM programs. Staff recommend that the utility proceed with the items identified in a timely way and integrate into the Action Plan the suggestions made elsewhere in the body of this report.
8 Guideline 8: Public Input As indicated earlier, Centra-FSJ is a small utility with approximately 7,300 customers. As a result, the utility has tried to obtain public involvement in its IRP in manners which do not involve a substantial outlay of funds. To this end, the utility organized a public meeting held June 20, 1994 at which several IRP topics were discussed and input as to customer values was sought. Another meeting is planned for the autumn. In addition, the utility has conducted informal interviews with key stakeholder groups such as large industrial customers, the Chamber of Commerce, local government officials, etc. The utility also plans to join with other utility stakeholder processes where common intereSts make such a course of action desirable. In general, staffbelieve the scale and approach to public involvement taken by Centra-FSJ to date has been reasonable given the size of the utility. However, staff suggest that a more focused approach to public participation would now be advisable. In particular, staff suggest that Centra-FSJ form. a small voluntary stakeholder committee made up of representatives from key interests, e.g. industrial customers, local businesses, local government, environmental groups, residential customers, etc. The process would not need to be on the scale of that undertaken by BC Gas. Staff does not believe it would be necessary to hire a professional facilitator or provide per diems to volunteers. Relevant information from the BC Gas stakeholder group could be provided to the group along with copies of the most recent Commission Decision with respect to Centra-FSJ and this staff evaluation repon to help inform the volunteers on the issues which they need to consider. Evening meetings on the order of once per month would likely be sufficient. Staff axe prepared to help the utility with this endeavor. Accordingly, staff believe the public meeting proposed for this fall is premature and would be better held early in the new year after the stakeholder group has had time to inform themselves on the issues and understand the ramifications of resomce decisions. In addition to the above suggestion, staff have some comments on the public participation process to date. FU'St, the public meeting was held June 20. 1994 some 10 days before the IRP was due to be med with the Commission. It is unclear how the utility hoped to integrate the information received from the public into the IRP in such a shon period of time. In fact, this may be one of the reason for the lack of follow through between the objectives and the resource assessment noted above. In addition, such a short time frame may give rise to the concern that the request for public input is more a request for public blessing of an essentially finished product. Second, the IRP indicates that key stakeholders were invited to the public meeting but it does not indicate specifically who these stakeholders were or whether or not they attended. It would have been useful to have been given this information in order to assess the extent to which the public was involved. Similarly, as indicated earlier, the public was asked to rank the IRP objectives. It is unclear as to the method used to adduce the ranking from the public or how much time the public was given to consider these rankings. It would have been useful to have been given this information as well. Third, as indicated earlier, staff are concerned that the quality of information provided the public be as accurate as possible. For example, on page A-I, the statement is made that "Over the long term competition should result in prices that avera~e the cost of service". Staff believe the intended term was "cover" the cost of service. UnfortUnately, this statement, as it stands, could be interpreted to mean that competition leads to prices which equal the average cost of service instead of the marginal cost of service. In terms of current thought at the Commission, with respect to regulation and pricing, this distinction is critical. As well, it appears that the Commission's directions to Centra-FSJ with respect to seasonal rates and equal payment billing were inaccurately relayed to the public. Staff recommend that Centra-FSJ make every attempt to avoid such errors in future by providing the public with accurate information initially or indicating to the public if the utility is unsure as to whether the information it is giving out is correct.
9 Guideline 9: Regulatory Input Guideline 10: Government Policy Input Guideline 11: Regulatory Review The Guidelines indicate that the BCUC staff should be given opponunities to review and comment during the various phases of preparation of the IRP. Staff provided comments to the utility on the December 1993 draft IRP. In addition, the utility received comments via the March 11, 1994 decision. The utility has indicated that it considers the current IRP to be a final rather than draft document SUMMARY The July 8, 1994 IRP constitutes a significant improvement over the December 31, 1993 riling. Commission staff note that the utility has attempted to respond to some of the criticisms made during the course of the previous hearing. In particular, the utility has made progress with respect to the determination of objectives and attributes, has begun an assessment of the DSM resources available to the utility, and has begun a public participation program. However, the plan is flawed by an incomplete identification and assessment of potential resources. Staff consider this flaw to be of enough significance to recommend that the Commission not accept the Centra-FSJ IRP as filed. CG/Cor!FSJ·IRP EvltnRpt.
You are being directed to the most recent version of the statute which may not be the version considered at the time of the judgment.