BC Gas Utility Ltd. Integrated Resource Plan July 2, 1996 1.0 INTRODUCTION 1.1 Background BC!Gas Utility Ltd. ("BC!Gas" or "Utility") filed its Integrated Resource Plan (“IRP”) in July 1995. This timing coincided with the development of the Utility's strategic plan and supported the development of a capital facilities plan which formed part of the Utility's 1996-1998 Revenue Requirement Application ("Application"). The Commission reviewed the Application using a negotiated settlement process ("NSP"). The NSP resolved some IRP issues such as overall Demand-Side Management ("DSM") spending levels, and resulted in some specific modifications to the portfolio, but did not address all of the DSM programs or BC!Gas' proposed DSM shareholder incentive mechanism. Neither did the NSP review other components of the IRP such as the objectives, the demand forecasts, the decision analysis methodology, or the supply-side portfolios. The Commission indicated in Order G-96-95 that the IRP would be reviewed by way of a separate written hearing. Four Intervenors supplied written submissions regarding the IRP: the B.C. Energy Coalition ("Energy Coalition"), Westcoast Energy Inc. ("Westcoast, WEI"), the Consumers Association of Canada et al. ("CAC(B.C.) et al.") and the Ecology Circle. BC!Gas filed its written response on February 28, 1996. During the period between the filing of the IRP and its review by the Commission several events occurred which are relevant to the IRP review and the role of IRP. The key issues are the move towards increased levels of competition and customer choice in the electricity sector, and challenges to the Commission's jurisdiction with respect to IRP. Electricity Market Review In September 1995, the Commission submitted its Report and Recommendations to the Lieutenant Governor in Council on the British Columbia Electricity Market Review ("EMR Report"). The report noted that there was significant support among participants in the review for greater and more effective competition in generation and the need for improved and increased customer choice in service options. The Commission made several recommendations in the EMR Report that would tend to further that general objective. Subsequent to the release of the EMR Report, B.C.!Hydro and Power Authority ("B.C.!Hydro") has made applications to the Commission for tariffs which have the potential to increase the level of competition in electricity markets. Changes in the structure and degree of competition in electricity markets could have significant implications for natural gas utilities as well. 1
2 BCUC Social Costing Paper On February 6, 1996, the Commission released a Discussion and Policy Paper on Social Costing ("Social Costing Paper"). Social Costing, which is a critical element of IRP, is the recognition that the evaluation of alternative investments for meeting consumers' energy service needs should include not just financial costs but also the externality costs and benefits such as social or environmental impacts. When the Commission released the Social Costing Paper, it requested and received comments from interested parties. The comments are currently being reviewed. Commission Jurisdiction over IRP On February 23, 1996, the B. C. Court of Appeal issued its judgment regarding an appeal by B.C.!Hydro that the Commission had exceeded its jurisdiction with respect to directions contained in a Commission Decision regarding B.C.!Hydro's IRP. The Court upheld the B.C.!Hydro appeal. The Commission has since filed Notice of Leave to Appeal the B.C. Court of Appeal's Decision to the Supreme Court of Canada. Following the B.C. Court of Appeal Decision, the BCUC held a workshop on March 25, 1996 to discuss a process for assessing utility resource expenditures. The Commission outlined in a letter after the workshop, two alternative regulatory review processes that utilities might follow. The first alternative was for a utility to file annual statements of plans for new facilities or extensions, and those projects which required Certificates of Public Convenience and Necessity (”CPCN”) would be reviewed under CPCN applications. The second alternative was for utilities to prepare IRPs in general accordance with the Commission's February!1993 IRP Guidelines ("IRP Guidelines") and submit these bi-annually to the Commission for review. The information provided in the IRP would be used by the Commission in determining which projects required CPCN designation and, with respect to those projects, could assist in reducing the hearing time for their review. BC!Gas had already indicated that it was committed to the IRP process (BC!Gas Response to Intervenor Submissions, p. 1). Although these events have occurred since the filing of the BC!Gas IRP, BC!Gas has to some extent anticipated and responded to them in its IRP. The BC!Gas IRP notes that changes similar to those currently under discussion with respect to electricity markets have already occurred in the gas sector, and suggests that the need for gas utilities to differentiate themselves by excelling in new customer service areas is driving the IRP process as well as increasing the need to control gas costs, and that "BC!Gas' integrated resource planning must address multiple interests and objectives, including competition, if it is to be viable." (pp. 1-2 and 1-3).
3 On the general topic of social costing, the BC!Gas IRP states that, although the method of applying social costing may need to change as the gas and electricity markets become more competitive, the principles which led to the development of social costing should not be abandoned. In this IRP, BC!Gas has included social costs in its evaluation of resources through a process called Multi-Criteria Decision Method ("MCDM"), which will be discussed at greater length in subsequent sections of this Decision. The BC!Gas IRP does not directly address the issue of the Commission's jurisdiction in this area, but states: "If successful, integrated resource planning should result in better products and services for BC!Gas customers at competitive prices while enhancing the competitive position of BC!Gas, and will provide environmental and social benefits to British Columbia." In keeping with the B.C. Court of Appeal Decision, the Commission's review of the BC!Gas IRP is not an approval process. However, this Decision of the Commission will contain decisions on certain specific items contained within the IRP, such as DSM expenditures as follow-up to the negotiated settlement on BC!Gas' 1996-98 Revenue Requirements and BC!Gas' proposed DSM Incentive Mechanism. Comment on other aspects of the IRP will also be provided, and is intended as constructive feedback to the Utility for reference regarding future Integrated Resource Planning activities. Overview of the IRP BC!Gas' IRP is comprised of two documents: the IRP and the IRP Technical Appendix which is a separate document elaborating on the following aspects of the IRP: (a) Public Involvement; (b) Energy Forecasts, including both the long-term forecasts and the 5-year system plan methodology; (c) Supply Side Resources, including an update of the supply option analysis provided in the 1994 IRP and a description of the avoided costs methodologies; (d) DSM; (e) the Multi-Criteria Decision Method used to assist stakeholders in their evaluation and screening of DSM programs; (f) the DSM shareholder Incentive Mechanism; (g) BC!Gas' Voluntary Action Plan on Greenhouse Gases; (h) Stakeholder group review of BC!Gas' IRP process.
4 2.0 PUBLIC INVOLVEMENT As suggested by item (h) above, BC!Gas invited various representatives of interest groups to participate in the IRP process and development. Not all invited organizations assigned a representative, and the final stakeholder group was comprised of 16 representatives (IRP, pp. 4-6 and 4-7). In the IRP Technical Appendices, BC!Gas included meeting agendas and summaries of the stakeholder meetings (Appendix A) and a report titled "Stakeholder Group Review of BC!Gas' IRP Process" ("Stakeholder Review"). The IRP indicates that the primary task of the stakeholder group was the selection of a supply and DSM portfolio, and that this involved significant time and effort in developing IRP principles and objectives (IRP, p. 4-7). BC!Gas asked the stakeholder group to assist in the consideration and or development of policies or mechanisms on several issues, including: • a DSM shareholder incentive mechanism; • technology development and supply side issues; • DSM program development; and • externalities. CAC(B.C.) et al. in its submission, argued that the public involvement process of BC!Gas was inadequate in several aspects. First, it argued that representation in the stakeholder group was inadequate insofar as representation was not proportional to the revenues received by the Utility from a particular customer class. Second, it claimed that the identification of alternative resources was inadequate in the absence of independent stakeholder resources, and suggested that BC!Gas should be required to provide funding to non-profit groups to obtain independent advice on DSM measures. Third, it claimed that the evaluation of alternatives was "imbalanced and subject to excessively tight Company control" (CAC(B.C.) et al. submission, p. 5). The Commission finds little evidence of the concerns raised by the CAC(B.C.) et al. in the Stakeholder Review, nor in the submissions raised by other intervenors in the written hearing. The Commission's interpretation of the Stakeholder Review is that, although stakeholders varied in support for individual aspects of the process or the decisions reached, the stakeholders generally regarded the process favourably. The Commission notes that one of the recommendations of the stakeholder group regarding future process was that the size of the group be restricted to a maximum of 18 to 20 (IRP Technical Appendix H, p. 14). Moreover, the Commission notes that the role of the stakeholder group was considered to be consultative and that 14 of the 16 members of the group endorsed this role (IRP Technical Appendix H, pp. 9-10).
5 In general, the Commission believes that the implementation of the suggestions of CAC(B.C.) et al. could lead to a potentially cumbersome and expensive stakeholder group process. The Commission finds that the BC!Gas stakeholder process was an acceptable process and one that had the general support of the stakeholders involved. Moreover, the Commission wishes to commend participants in the stakeholder process for their assistance in the development of BC!Gas' IRP. The IRP Guidelines recognize that management must make the final IRP decisions, having regard to the valuable input of the stakeholder group and other relevant factors. 3.0. EVALUATION OF THE IRP The evaluation of the IRP involves considering the answers to two or three basic questions. First, is the IRP useful in communicating the major issues confronting the utility? That is, does it contain sufficient information for readers to understand why the utility is planning to do what it intends to do? Second, has BC!Gas responded to the Commission's directions in the its last IRP? If not, why not? Have circumstances changed, or is there some other reason? Finally, are all of the necessary elements there to justify BC!Gas' plans? With respect to the last question the IRP Guidelines provide some assistance. In the Commission's view, IRP has evolved sufficiently since the IRP Guidelines were issued that it is no longer necessary to provide commentary on every aspect of the IRP and its correspondence to every one of the IRP Guidelines. 3.1 IRP Principles, Objectives and Selection Criteria BC!Gas' IRP includes a section titled "IRP Principles and Objectives". The IRP defines the objectives as "...a concise and measurable set of criteria for determining which resources should be selected in the resource selection process". The IRP principles are defined as the framework within which the IRP objectives and resource selection processes operate. The IRP principles were developed based on stakeholder concerns that there were "overarching considerations" in IRP that were important but were not used to choose between resources and so did not qualify as IRP objectives. BC!Gas distinguished between IRP process principles, which are guidelines the IRP process should follow, and IRP implementation principles, which govern how the various activities resulting from the IRP process are carried out.
6 The IRP principles developed by BC!Gas and the stakeholder group go beyond the Commission's IRP guidelines. Examples of the IRP Principles include: support for consistency between IRP and corporate strategic planning; sustainable development; provision of value added service; and ensuring customers have alternative service and supply options. In this regard, the Commission believes the development of IRP Principles represents a significant improvement in the evolution of IRP, in aiding the utility to define its direction into a future which may include greater competition in energy markets and simultaneously greater pressure to minimize environmental impacts. The Objectives of the BC!Gas IRP are complete and unchanged in only one respect from the 1994 IRP. The one change reformulates the objective relating to shareholder value and is, in the Commission's view, a positive change. No party in the written hearing submitted that the objectives were inappropriate. In the Commission's view, the objectives in the 1995 IRP are essentially complete and appropriate objectives for an IRP. BC!Gas and the stakeholder group also developed various criteria associated with each objective. Each criterion, in order to be meaningful, was required to be measurable, useful for ranking resources, distinct, and "directionally preferable". The latter criterion meant that, if all else was equal, all stakeholders would prefer to move in the direction of achieving the criterion. 3.2 Demand Forecasts The BC!Gas IRP incorporates the results of both end-use and econometric models. Aggregated econometric model results are used to develop firm sales forecasts for residential, commercial and firm industrial consumption. These are further refined by a regional allocation model to forecast natural gas demand in each sector by region and by Monte Carlo simulation models to develop a forecast "confidence interval" which gives a range of possible demand forecasts. The BC!Gas IRP Reference case demand forecast indicates that gas demand for all customer categories will increase from 207 petajoules (PJ) to approximately 285 PJ by 2012, an average annual increase of about 1.7 percent. The reference case forecast is based on assumptions that approximate current conditions and which are generally considered to represent the consensus view of future conditions. Growth in residential sector demand is forecast to slow toward the end of the study period due to a decreasing rate of population growth and increasing appliance efficiencies. Demand in the commercial and industrial sectors is forecast to continue at a higher level throughout the study period based on assumptions of continuing economic growth and competitive natural gas prices compared to other fuel prices.
7 The Commission in its August 4, 1994 BC!Gas Phase 2 Decision ("Phase 2 Decision") raised two concerns about the Company's econometric forecasting methodology. The first involved the apparent calculation of elasticities, used to adjust downward the use per account, from data that included all historical natural gas consumption without normalizing for changes in the number of accounts. The second concern involved the exclusion of the electricity variable from the model, leading to a potential reduction in the explanatory power of the model. In the 1995 IRP, the basic form of the econometric models appears unchanged from the basic form of the models referred to in the Phase 2 Decision. However, BC!Gas in its IRP has added additional elasticity estimation for the residential and commercial sectors using BC!Gas' end-use models. The end-use forecasts for the residential and commercial sectors provide forecasts of sales by end-use activity which are coupled with scenario analysis to plan and develop demand-side activities. In the Commission's August 1994 BC!Gas Phase 3 Decision ("Phase 3 Decision"), BC!Gas was directed to continue exploring alternative end-use models. Since the Phase!3 Decision, BC!Gas selected the Residential End-Use Energy Planning System ("REEPS") and the Commercial End-Use Energy Planning System ("COMMEND"). Both of these models employ a common structure and methodology. Both REEPS and COMMEND are commonly used end-use models, and, assuming that BC!Gas has the appropriate data to run the models for its service area, the Commission, at this time, sees no problem with their continued use. 3.3 Evaluation of Portfolios 3.3.1Multi-Criteria Decision Methods ("MCDM") for Evaluating and Selecting Resources The IRP stakeholder group evaluated the various resource options based on the objectives and selection criteria described in section 3.1. Each criterion had an associated measure to be used in evaluating how a given resource ranked relative to other resources for that criterion. For instance, the objective "minimize CO 2 emissions" ranked resources based on Tonnes of CO 2 (or CO 2 equivalent) per year. After weighing the various resources against all of the economic, financial, environmental and social criteria, the stakeholder group recommended a DSM portfolio to the utility. BC!Gas considered the recommendations of the stakeholder group in selecting a final resource portfolio, but was not bound to follow them. Generally, few programs will be unambiguously better than any other programs, since not all of the objectives and criteria will rank equally relative to other programs. (For instance, some programs may
8 perform well on financial considerations but poorly on environmental criteria, while other programs which do well on environmental criteria may perform less well on financial criteria.) The intent of the resource selection process was to assist stakeholders in understanding the trade-offs involved in selecting and recommending resource options. Therefore, consultants for BC!Gas assisted stakeholders in assessing preferences or weights attached to the different objectives and criteria using various Multi-Criteria Decision Methods (“MCDM”). This was done using three different MCDM techniques in order to cross-check results, and to prepare initial program evaluations based on the weights from the MCDM analyses. (Such analysis is also often referred to as Multi-Attribute Trade-Off Analysis or MATA.) The preliminary evaluations were followed by individual interviews to explore and understand variances in the weights given to the same programs using the different techniques and to develop a consistent set of weights from each person. Once reasonably consistent recommendations were developed for each stakeholder, the results were presented anonymously to the entire stakeholder group for discussion and identification of areas of consensus. At the discussion and consensus seeking stage, two additional portfolio level criteria were considered: portfolio diversity and equity. The latter criterion considered the degree to which a given resource portfolio allowed for broad customer participation. CAC(B.C.) et al. contended that BC!Gas did not properly take externalities into account. They proposed a pass/fail Societal Test, a participant's test, and a portfolio consideration of the impact on rates. They also suggested that financing and low income programs should be available to offset non-participant inequities (CAC(B.C.) et al. submission, pp. 9-10). The Commission notes that BC!Gas did consider externalities in its MCDM analysis which it undertook with its stakeholder group, and that equity was considered in the MCDM analysis at the portfolio level. The Commission is of the view that BC!Gas has done a thorough and proper analysis of resource options given the state of knowledge and government policy at this time.
9 3.3.2 Marginal Electric Resource In the case of fuel substitution programs which encouraged electricity to natural gas equipment conversions, it was necessary to consider the marginal electric resource in order to determine if environmental impacts of such conversions were positive or negative. In order to determine which electric resource was the marginal electric resource, BC!Gas staff discussed the issue with B.C.!Hydro and subsequently contracted with Bovar-Concord Environmental to assist in resolving the issue. Bovar-Concord was asked to develop a range of scenarios for future electric power generation options and to evaluate the air emissions impacts related to the scenarios. The IRP, using results taken from a draft Bovar-Concord report, indicates the two extremes of the possible range of air emissions, a heavy emissions case and a minimal emissions case. The heavy emissions case is based on greater reliance on the Burrard Thermal plant, new gas turbine generation and Alberta coal generation, while the minimal emissions case places more reliance for marginal electricity on existing and small hydro power. Both cases were used to assess the environmental impacts of electric to gas fuel switching programs. "Off-electric" programs were discouraged by the Commission's 1994 Phase 3 Decision, and were removed from BC!Gas' more recent DSM portfolio as a result of the NSP in 1995. With respect to the possibility of future off-electric DSM program proposals, the Commission can offer no clear direction at the present time and notes that the analysis of such programs is complex, involving such issues as government policy, the specific end-uses targeted by the programs, and the current electricity supply outlooks. 3.3.3 Avoided Costs In order to evaluate the economic or rate impacts of DSM programs, it was necessary to consider the "avoided cost", which is the cost of the supply or demand-side resource which is avoided by the selection of a program or project under review. For instance, if a proposed DSM energy efficiency program is under review, the avoided cost is the cost of the alternative (usually supply-side) resource or resources which would not be necessary because of the impact of the DSM program. Evaluation of the financial and rate impacts of the DSM programs is typically done using standard economic tests which include, as one of their inputs, the avoided cost. Therefore, in order for the stakeholder group to evaluate the slate of proposed BC!Gas programs, it was necessary for BC!Gas to develop estimates of the avoided cost in each case. In its 1994 IRP, BC!Gas developed two sets of avoided costs based on two alternative methodologies. The Customer Incremental Avoided Costs (“CIAC”) are based on the cost of satisfying incremental demand given the existing (rolled-in) tolls paid by BC!Gas for upstream supply and transportation
10 services. The Total Investment Avoided Cost (“TIAC”) estimates are based on estimates of "proxy" investment costs at each step in the supply chain required to supply incremental demand. For its 1995 IRP, BC!Gas updated its previous CIAC and TIAC estimates based on new information but utilizing the previous methodologies. Moreover, the most recent analysis used a more optimal supply portfolio than was used previously to develop the CIAC estimates. As with the previous estimates, both the CIAC and the TIAC estimates vary depending on the load shape of the service class being analyzed. In the 1995 IRP, the TIAC estimates are higher than the CIAC estimates for all service classes and for all load shapes except needle-peaking loads. In its Phase 3 Decision, the Commission stated that it accepted BC!Gas' Long Run Avoided Cost Study, which incorporated the CIAC and TIAC methodologies, as a good approximation of the avoided costs at that time. In its 1995 IRP, the methodology has not changed with the exception of using the Probable gas supply portfolio rather than the Status Quo portfolio. In the IRP (p. 12-5), BC!Gas indicates that its DSM monitoring strategy and the purchase of a Resource Optimization Model ("ROM") or an upgrade to its existing Gas Supply Optimization Model ("GSOM") will improve BC!Gas avoided cost estimates. The Utility also states that it will review the avoided cost estimates in 1996 and the net benefits of DSM programs and that, if there are significant changes, these will be reviewed with Commission staff and the stakeholder group. In the view of the Commission, development of the avoided cost estimates based on the Probable portfolio, which includes the addition of an incremental LNG plant, is an improvement, since this represents a more likely avoided resource than the Status Quo portfolio. The Commission anticipates that further improvements to the IRP will take place as BC!Gas develops better end-use data as a result of its DSM Monitoring Study, and as it implements a new ROM or continues to upgrade its GSOM. 3.4 Supply-Side Resources BC!Gas supply-side planning can be considered from both long-term and short-term perspectives. The long-term perspective is addressed by the Company's IRP. The short-term perspective (the period of a single gas year from November 1 to the following October 31) is addressed by the Utility filing an annual "Gas Contracting Plan" for Commission approval. Due to the commercially sensitive nature of information contained in this plan, this material is reviewed by the Commission on a confidential basis and the review is typically conducted without public participation.
11 In this hearing, only Westcoast Energy Inc. questioned BC!Gas about its supply-side planning. In its responses, BC!Gas declined to fully answer a number of the questions posed by WEI. In some cases, no answer was provided. Understandably, WEI used this as a basis for concluding in its submission to the Commission that: "...the Commission is equally unable to assess the conclusions reached in the report and the recommendations contained therein ought not to be endorsed by the Commission." In its reply submission, BC!Gas attempted to address some of the WEI concerns by providing reasons why the long-term information was not provided. Essentially this reply submission indicates that the Company is presently evaluating a number of long range alternatives including underground storage, an LNG project and a pipeline looping project known as the Southern Crossing project. The Company stated that a number of significant developments had occurred since the filing of the IRP in mid-1995, so that while the IRP was still generally valid with respect to which long-term alternatives deserved further study, it was not relevant to respond to WEI with detailed analyses based on out-of date information. In particular, BC!Gas cited the following significant developments with respect to its peak day supply circumstances since the filing of the IRP: • new cost-effective underground storage options previously identified have now been realized; • higher rates of Westcoast toll escalation have been confirmed; • new peaking options through the curtailment of cogeneration or B.C.!Hydro's Burrard Thermal Plant, which may be repowered, are possible; and • evidence shows that peak day system load growth is higher than the rate previously forecast. The Commission accepts this explanation for BC!Gas not providing detailed responses to the WEI long-term supply questions. However, given this degree of uncertainty, the Commission agrees with WEI that BC!Gas must submit further substantive information to the Commission before the Commission will be able to provide any endorsement of the Company's long-term supply plans. The Commission also will expect BC!Gas to demonstrate that it has integrated its supply-side and demand-side analyses. With respect to the Company's short-term supply planning, the Commission is satisfied that its current annual review process for the Company's Gas Contracting Plan is sufficient to ensure prudent short-term use of gas supply resources. 3.5 Demand-Side Management Services (“DSMS”) In its November 28, 1995 Decision, the Commission accepted in its entirety, the terms of a Negotiated Settlement of the BC!Gas 1996-1998 Revenue Requirements Application. That settlement included major revisions
12 to the expenditure level and content of the utility's proposed DSMS. Overall 1996 and 1997 proposed expenditures were reduced by close to $4.6 million or 28%. Major reductions were negotiated to the NGV program, $2.3 million; to off-electric fuel substitution programs, $1.6 million; and to the efficient boiler program, $0.4 million. A preliminary reconciliation table prepared by Commission staff is provided below as Table 3.1. Having determined the expenditure levels and the major strategies of the DSMS portfolio by negotiation, the program specific review was referred to the IRP review. In addition the proposed DSM Shareholder Incentive Mechanism was also referred to the IRP review. The purpose of an ongoing review of specific DSMS programs is to ensure that BC!Gas is aware of the Commission's primary concern that these programs attempt the optimum achievement of DSMS objectives on the basis of costs and benefits that are fair, just and reasonable. This concern includes both prudency and the equitable distribution of costs and benefits among customers. The review extends beyond the proposed portfolio of programs to a consideration of other programs that may be useful. BC!Gas is directed to provide tables showing revised DSMS expenditure budgets for 1996 and 1997 and showing how BC!Gas has complied with the Terms of the Negotiated Settlement.
13 Table 3.1 Preliminary Reconciliation of Proposed Programs with Settlement Agreement. 1996 1997 1996 NSP 1997 NSP Difference PROGRAM (increase) R- hot water savers 158,545 0 140,864 10,000 7,681 R- hi efficiency furnace 193,049 263,158 200,251 270,602 (14,646) R- advisory and retrofit. 249,282 445,011 233,144 411,922 49,227 R- renovation 22,472 48,935 24,334 52,144 (5,071) R- off-oil 363,898 266,843 371,089 277,845 (18,193) Residential RD & A 100,000 100,000 (200,000) (181,002) C- apt. hot water saver 303,898 422,898 201,333 280,260 245,203 C- efficient boiler 1,396,002 1,653,458 1,222,701 1,422,085 404,674 C- construction drying 58,288 58,288 19,659 1,349 95,568 C- process retrofit 309,450 309,450 153,654 152,279 312,967 C- HVAC controls 234,884 271,931 237,335 167,781 101,699 C- rate 3 to 7 530,987 1,041 531,441 3,123 (2,536) C- water heating 210,816 183,380 0 0 394,196 C- multi-family construct 417,519 393,283 0 0 810,802 C- Boiler tune-up research 77,089 (77,089) C- demand meters 24,000 (24,000) Commercial RD & A 100,000 100,000 (200,000) 2,061,484 NGV- status quo 678,579 689,118 678,579 689,118 0 NGV- vehicle upgrade 395,000 395,000 395,000 395,000 0 NGV- refuel infrastructure278,733 365,244 125,400 180,800 337,777 NGV- comm. vehicle. convert. 1,061,722 991,167 1,061,722 991,167 0 NGV- OEM intro. lt. & med 618,500 958,500 100,000 200,000 1,277,000 NGV- heavy duty OEM 257,500 259,500 0 0 517,000 NGV- contract refueling 56,000 66,000 0 0 122,000 2,253,777 RD & A (relocated above) 262,300 262,900 0 0 525,200 Total Utility Costs $8,057,424 $8,305,105 $5,997,595 $5,705,475 $4,659,459 decreases agreed to $2,133,000 $2,505,000 $4,638,000 decreases made $2,059,829 $2,599,630 $4,659,459 Difference $21,459 [Note: In total expenditures, BC!Gas has complied with the NSP, although it has resorted some amounts and reduced expenditures to residential programs rather than commercial programs.]
14 3.5.1 Specific DSMS Programs 3.5.1.1 Natural Gas Fireplaces BC!Gas, in a response to a BCUC staff information request, shows a higher market penetration of decorative log sets in new dwellings than in old dwellings (Response to BCUC staff Supplemental Information Request, p. 11, Tables 3.1 and 3.2). The Energy Coalition in its Argument recommended that BC!Gas "develop a DSM program based on improving the penetration of high efficiency natural gas fireplaces in the market for multi-family dwellings." (p. 8). The Energy Coalition also identified the issue of a minimum efficiency standard for natural gas fireplaces and suggested that an effective DSM program could accomplish the following (Energy Coalition Argument, Attachment G): 1. create a useful test protocol to determine energy efficiency; 2. assist in setting of minimum standards under the Energy Efficiency Act; 3. market appliance labeling 4 implement a DSM program designed to transform the market. BC!Gas, in response to the Energy Coalition suggestion for an efficient fireplace program, indicated that it had been working with industry to develop an appropriate efficiency standard, but the Utility would not be in a position to develop a DSM program for encouraging higher efficiency fireplaces until realistic comparative efficiency ratings were developed. BC!Gas also noted the B.C. government's, "Clean Choice" program that promotes gas fireplaces on Vancouver Island and the intention to use the Canadian Gas Association CGA P.4 test protocol developed by the industry for approving fireplace grants (BC!Gas Reply, p. 5). The majority of new multi-family construction that could include natural gas fireplaces may occur largely in the lower Fraser Basin air shed. Natural gas fireplaces not only contribute to greenhouse and ground level emissions but also contribute to peak demand on the system. The Commission supports the efforts of BC!Gas to assist in development of appropriate efficiency standards for appliances such as natural gas fireplaces. In future, if BC!Gas should propose to develop an incentive program to encourage the use of high efficiency gas fireplaces in the multi-family residential market, the Commission anticipates that such a program would be sized according to the extra cost of a highly efficient gas fireplace as compared to the "Clean Choice" or Energy Efficiency Act minimum
15 standard. Such a proposal would also require resolution of some of the issues discussed in section 3.3.2, regarding fuel substitution programs. Given the continued high market penetration of inefficient decorative log sets, the Commission believes that BC!Gas should only be encouraging high efficiency natural gas fireplaces and should consider information in their brochures to discourage decorative log sets. The Commission directs BC!Gas to prepare and file an action plan by September 30, 1996 to address its involvement in the natural gas fireplace market. 3.5.1.2 New Home Program B.C.!Hydro and West Kootenay Power Ltd. ("WKP") both have new home programs that apply whether the house is electric or gas heated. These are informational/promotional and in WKP's case the program specifically excludes window upgrades. BC!Gas did evaluate a "Designed Comfort" new home program but concluded that it did not make economic sense. The "Designed Comfort" pilot program of BC!Gas for residential construction offered energy efficiency through air tightness and the program did not proceed. BC!Gas has canceled its involvement with R2000, a federally funded program emphasizing air tightness, insulation and heat recovery ventilation (Response to CAC(B.C.) et al. Information Request, p.!11, Response to BCUC staff Information Request No.!2, Items 15 and 55). There are efficiency standards for appliances and minimum energy efficiency requirements in building codes throughout the province. New home programs encourage developers and owners to opt for even higher levels of energy efficiency for a combination of cost and comfort reasons. The Commission by Order No. G-30-96 approved WKP's new home program with a direction to "seek the cooperation of both BC!Gas and B.C.!Hydro in order to optimize the performance of their new home program". Joint promotion could improve the paybacks to all three utilities if BC!Gas joined with B.C.!Hydro and WKP in this initiative. A supportive promotional/educational program would also encourage compliance with the Energy Efficiency Act and building codes. Therefore the Commission directs BC!Gas to seek the cooperation of both WKP and B.C.!Hydro in order to optimize the performance of BC!Gas' new home program.
16 3.5.1.3 Commercial Efficient Boiler Program In the Negotiated Settlement Agreement (p. 7, paragraph 3), BC!Gas agreed to reduce the forecast cost of the efficient boiler program by $202k in 1996 and by $250k in 1997 1 by replacing some rebates with loans. Although this program was initially approved by the Commission in its Phase!3 Decision, the Commission is concerned about the reliance on very significant rebates by BC!Gas for this program. The economic tests do reflect reasonable benefit-cost performance targets. The issue is whether the energy savings could be achieved with lower utility costs. Market research and the monitoring and evaluation of this program should attempt to address this issue. The Commission is aware that this program was originally intended for both the new and retrofit markets and that BC!Gas has responded that it will explain and justify marketing this program in the new construction market (Response to BCUC staff Supplemental Information Request, p. 23). If a new construction version of the efficient boiler program is contemplated by BC!Gas, the Commission directs BC!Gas to apply for Commission approval for such an offering. Financing and fairness would be considered in such an application. 3.5.2 DSM Monitoring and Evaluation BC!Gas has developed a draft monitoring and evaluation ("M & E") plan and indicated in an information response that the plan would be reviewed by outside consultants in January 1996 (Response to BCUC staff Supplemental Information Request, p. 24). BC!Gas is directed to file the consultant's review with the Commission. In its Final Response to Intervenors (p. 4), BC!Gas states that agreement from stakeholders on appropriate M & E methods would facilitate consensus on mechanisms for encouraging optimal utility DSM efforts and suggests that the BCUC convene a workshop on M & E protocols to be used for measuring DSM performance. As a preliminary step, the Commission recommends that BC!Gas communicate with B.C.!Hydro and WKP on the approach taken by these utilities in conducting and reporting the results of DSM monitoring and evaluation to the Commission. WKP reports on a semi-annual basis and B.C.!Hydro provides its 1 As noted in section 3.5, Table 3.1 is preliminary and some subsequent adjustments to specific planned program expenditures have occurred.
17 annual DSM Monitoring and Evaluation Summary report. Both utilities provide copies of completed evaluations. BC!Gas should review both WKP's and B.C.!Hydro's approaches to M & E and consider the possibility of combined efforts. A customer may be involved in programs offered by more than one utility, so the possibility may exist to economize on information gathering through joint data gathering or other aspects of M & E. While essential to successful DSM, M & E needs to be cost effective. The linkage between a mature M & E system and a mature DSM shareholder incentive mechanism is clear from the submissions of both the BC!Gas and Energy Coalition consultants. Impact evaluations typically require two to three years of data, so BC!Gas may not be able to offer these results before 1999. 3.5.3 DSM Shareholder Incentive Mechanism In its Phase 2 Decision, the Commission directed BC!Gas to develop a proposal for demand-side management incentive mechanisms. BC!Gas did propose an incentive in its Revenue Requirements Application, but the incentive proposal was not included in the final settlement agreement. BC!Gas also included its proposed DSM incentive mechanism in its IRP, and a report by the BC!Gas consultant which discusses the rationale and design of the BC!Gas shareholder incentive mechanism is found at Technical Appendix F of the IRP. In the view of BC!Gas and its consultant, there are several types of costs and risks to the utility created by the pursuit of DSM. According to the report, these costs and risks can create a gap between the private value of DSM to a utility and DSM's societal value. By increasing the value of DSM to the utility, DSM benefits that would otherwise be lost can be captured (IRP Technical App. F, p. 3). BC!Gas and its consultant stated that any shareholder incentive mechanism is made up of five major components: 1. the earnings basis on which the shareholders' earnings will be calculated; 2. the threshold requirements that a utility must meet to receive earnings; 3. the share or percentage of the earnings that can be received by the utility; 4. the method and timing of the incentive payment to the utility; 5. the necessary Measurement and Evaluation protocols that the utility must perform to verify the savings that underpin the earnings basis.
18 Moreover, BC!Gas suggested that the key aspects of an incentive threshold are: • Is something of value created for ratepayers and society? • Is the incentive threshold realistically attainable? • Is the potential incentive worth the risks and costs? (BC!Gas Response to BCUC staff Information Request No. 2, Item 46, p. 3) The specific mechanism suggested by BC!Gas is based on the five point structure noted above and discussed in the IRP (section 10) and Technical Appendix F (pp.!7-11). The most salient features of the proposal are as follows: • the mechanism would apply only to efficiency - strategic conservation programs, and would only apply to programs which passed the Total Resource Cost test. • the threshold requirement for a shareholder incentive in any year is 50 percent of the total forecast savings from eligible efficiency programs; • the shared saving percentage is 25 percent of savings on programs where customers pay the full cost of the measure or with a payback longer than 2 years, and 15% on all other programs; • payment of the incentive earnings is based upon verification of meeting the threshold and determination of the amount of the incentive. The utility would recover one-half of its incentive in the next year based on a per-gigajoule surcharge and the remaining half of the incentive payment would be recovered in the year following, based on an impact evaluation of the first year program and a revised saving estimate used to calculate the second half award; • impact verification would be used to verify the number of participants or measures installed and operating, and would attempt to assess the actual savings which resulted from the installed measures. Some intervenors, while supporting the general concept of a DSM incentive mechanism, suggested alternative mechanisms to the one proposed by BC!Gas. The Energy Coalition suggested that an incentive must be designed to reward the achievement of specific results, rather than levels of expenditures or number of DSM programs implemented, and that performance in achieving results must be measurable, based on specific, predetermined measurement methods (Energy Coalition Argument, p. 5). The Energy Coalition argued that the BC!Gas proposal was one-sided rather than balanced, allowed the utility to easily earn a premium return, and was sufficiently vague as to create the potential for problems of interpretation. The Energy Coalition proposed a two part mechanism comprised of a return on equity incentive or penalty tied inversely to growth rate in use per customer, and a shared savings incentive
19 designed to minimize the cost of acquiring DSM. In the view of the Energy Coalition, this proposal would provide the benefit of symmetrically tying rewards and penalties for the achievement of or failure to achieve IRP goals (Energy Coalition Argument, p. 7). CAC(BC) et al. also supported carefully designed and well aimed financial incentives which could help offset the inherent contradictions between the interests of the Company and the interests of the public at large with respect to the achievement of DSM. In its submission the CAC(BC) et al. observed that regulatory "sticks" could be used in conjunction with "carrots" to encourage improved performance (similar to the Energy Coalition proposal that rewards and penalties should be linked symmetrically), but that such a mechanism would require a more proactive role on the part of the Commission and its staff (CAC(BC) et al. Submission, p. 4). BC!Gas, in its response to intervenor submissions, argued that the Energy Coalition proposal to base a DSM shareholder incentive tied inversely to the growth rate in use per customer would not target DSM program impacts specifically enough, but would include several other factors beyond the control of the utility (BC!Gas Response, p. 3). BC!Gas also argued that the incorporation of a penalty mechanism would tend to discourage DSM efforts, and suggested that a workshop to discuss measurement and evaluation protocols for determining DSM performance would facilitate agreement on appropriate incentive mechanisms (BC!Gas Response, p. 4). The Commission appreciates the innovative approaches that both BC!Gas and the Energy Coalition have proposed in response to the Commission's request in its last BC!Gas Decision. Both approaches have desirable features and some features that are problematic. For this reason the Commission is not prepared to approve either approach at the present time. However, the Commission is convinced that a DSM shareholder incentive is appropriate for BC!Gas because of the perceived risk of shortfalls in DSM savings performance and the need to encourage greater efficiency in the use of natural gas to support B.C.'s Greenhouse Gas Action Plan. One possible alternative is suggested by adopting the best features of the BC!Gas and the Energy Coalition approaches and blending these with the framework recently proposed for use by West Kootenay Power Ltd. The WKP mechanism relies on verified participation; sets a savings threshold of 90% (3% higher than experience to date); and shares positive price variances in variable costs equally on a pre-tax basis. BC!Gas is directed to review these suggestions and file a new proposal by September 30, 1996.
20 4.0 CONVERGENCE - COGENERATION OR COMBINED HEAT AND POWER In its written argument, the Energy Coalition raised the issue of convergence, which it defined as "the crossover of previously distinct industries. In the electricity restructuring literature it refers primarily to the merging of the natural gas industry with electricity generation and distribution." (Energy Coalition Argument, Exhibit C, p. 1). More specifically it refers to the potential for the co-generation of electricity from natural gas. The increasing opportunities for economic cogeneration or the production of combined heat and power result in the potential for a greater degree of convergence of the natural gas and electricity industries. The Energy Coalition argued that: "As a condition of acceptance of the BC!Gas IRP, the British Columbia Utilities Commission should direct BC!Gas to file a report on convergence opportunities identifying the total cost and benefits as well as the regulatory and financial barriers. As a further action arising from the BC Greenhouse Gas Action Plan the Commission should then hold a proceeding on the appropriate regulatory treatment of convergence technologies and issues." (Energy Coalition Argument, p. 5). The convergence issue cannot be dealt with one utility at a time as it is a generic issue which will also need a linkage with stated government energy policy and the restructuring of the electricity market. Resolution of the convergence issue will also require consideration of the need for a provincial policy on fuel substitution. Moreover, B.C.!Hydro's approach to net metering, the purchase of surplus power and provision of backup service also needs to be resolved. This issue is of singular importance for the future of the energy service industry in B.C. and related greenhouse gas policies. The Commission anticipates that the development of competitive markets in both natural gas and electricity will substantially improve the opportunities to realize convergence. With this in mind, BC!Gas should continue to monitor the developments in electricity and natural gas markets as the opportunities for convergence evolve and should provide an update on the status of convergence opportunities in its next IRP. 5.0 COMMISSION CONCLUSIONS The Commission finds that overall, the BC!Gas IRP and the processes that created it were valid and useful planning and informational tools. BC!Gas staff, members of the stakeholder group and others who assisted in its preparation are commended.
21 The Commission has noted the comments and criticisms of the intervenors, and has offered its own views where appropriate. The Commission trusts that BC!Gas will take intervenor and Commission comments into consideration in the preparation of its next IRP update and in its ongoing utility operations. The Commission also concludes that some issues, such as Technology Development were adequately dealt with in the NSP settlement and require no further comment in this Decision. In those areas such as Gas Supply, DSM, or the Shareholder Incentive Mechanism proposal, where more specific direction is given, the Commission expects that BC!Gas will carefully consider these suggestions for its next IRP update. DATED at the City of Vancouver, in the Province of British Columbia, this !!!!!!!!!day of July, 1996. Dr. Mark K. Jaccard Lorna R. Barr Deputy Chairperson
22 G-72-96 IN THE MATTER OF the Utilities Commission Act, S.B.C. 1980, c. 60, as amended and An Application by BC Gas Utility Ltd. for Approval of its 1995 Integrated Resource Plan BEFORE: M.K. Jaccard, Chairperson; and ) L.R. Barr, Deputy Chairperson ) June 28, 1996 O R D E R WHEREAS: A. On August 4, 1995 BC Gas Utility Ltd. ("BC!Gas") filed with the Commission its 1995 Integrated Resource Plan ("IRP") that was part of its 1996, 1997 and 1998 Revenue Requirements Application; and B. The Commission used the Alternative Dispute Resolution process on the 1996-98 Revenue Requirements Application, approved by Order No.!G-99-95, and indicated that the BC!Gas IRP would be dealt with through a separate review process; and C. The Commission ordered that a written public hearing into the BC!Gas 1995 IRP be held as set out in Order G-96-95; and D. A public hearing in written form for reviewing the issues related to the BC!Gas 1995 IRP was held; and E. The Commission has considered the BC Gas IRP and evidence adduced thereto all as set forth in the Decision issued concurrently with this Order. NOW THEREFORE the Commission, for reasons stated in the Decision, orders as follows: 1. BC Gas is to comply with all directions contained in the Decision accompanying this Order. DATED at the City of Vancouver, in the Province of British Columbia, this !!!!!!!!!!!!!!!!!!!!!!!!day of July, 1996. BY ORDER Dr. Mark K. Jaccard Chairperson
Appendix A 23 ORDER NO. G-96-95 IN THE MATTER OF the Utilities Commission Act, S.B.C. 1980, c. 60, as amended and An Application by BC Gas Utility Ltd. for Approval of its 1995 Integrated Resource Plan BEFORE: M.K. Jaccard, Chairperson; and ) L.R. Barr, Deputy Chairperson ) November 27, 1995 O R D E R WHEREAS: A. On August 4, 1995 BC Gas Utility Ltd. ("BC!Gas") filed with the Commission its 1995 Integrated Resource Plan ("IRP") that was part of its 1996, 1997 and 1998 Revenue Requirements Application; and B. The Commission used the Alternative Dispute Resolution ("ADR") process on the 1996-98 Revenue Requirements Application and indicated that the BC!Gas IRP would be dealt with through a separate review process; and C. The Commission has reviewed these factors and finds that a written public hearing into BC!Gas' 1995 IRP is required. NOW THEREFORE the Commission orders as follows: 1. A public hearing in written form for reviewing the issues related to the BC!Gas 1995 IRP is required. The Commission issues the following regulatory schedule and timetable of deadlines: Action Date (1996) (a) Information Requests made of BC!Gas by Intervenors January 8 (b) BC Gas to respond to information requests January 22 (c) Written submissions from Intervenors due February 12 (d) BC!Gas' responses to submissions February 26
24 2. The Commission requires that Intervenors intending to participate in the written hearing follow the timing deadlines noted above, and advise the Commission, in writing, of their intention to participate. A preliminary list of issues will be prepared by the Commission and issued to those parties participating in the written hearing. 3. All parties intending to apply for Participant Funding must file a budget by December 22, 1995 consistent with the Commission's Policy and Rate Sheet as outlined in Order No.!G-117-93. Copies of the Participant Funding Policy and Rate Sheet are available upon request. DATED at the City of Vancouver, in the Province of British Columbia, this !!!!!28th!!day of November, 1995. BY ORDER Original signed by Author Dr.!Mark K. Jaccard Chairperson
25 Appendix B List of Registered Intervenors Mr. Bob Boxwell B.C. Environment Network Mr. Fred Pearson B.C. Health Services Ltd. Mr. C.P. Donohue Pacific Northern Gas Ltd. Mr. Allan Fogwill Centra Gas British Columbia Inc. Mr. Dermot Foley B.C. Energy Coalition Mr. R.H. Hobbs West Kootenay Power Ltd. Mr. Huub Ledderhof Ecology Circle Ms. Lynn Meyer Novagas Clearinghouse Ltd. Ms. Jane L. Peverett Westcoast Energy Inc. Mr. Jim Quail CAC(B.C.) et al.
26 TABLE OF CONTENTS Page No. 1.0 INTRODUCTION 1 1.1 Background 1 2.0 PUBLIC INVOLVEMENT 4 3.0. EVALUATION OF THE IRP 5 3.1 IRP Principles, Objectives and Selection Criteria 5 3.2 Demand Forecasts 6 3.3 Evaluation of Portfolios 7 3.3.1 Multi-Criteria Decision Methods ("MCDM") for 7 Evaluating and Selecting Resources 7 3.3.2 Marginal Electric Resource 9 3.3.3 Avoided Costs 9 3.4 Supply-Side Resources 10 3.5 Demand-Side Management Services (“DSMS”) 11 3.5.1 Specific DSMS Programs 14 3.5.1.1 Natural Gas Fireplaces 14 3.5.1.2 New Home Program 15 3.5.1.3 Commercial Efficient Boiler Program 16 3.5.2 DSM Monitoring and Evaluation 16 3.5.3 DSM Shareholder Incentive Mechanism 17 4.0 CONVERGENCE - COGENERATION OR COMBINED HEAT AND POWER 20 5.0 COMMISSION CONCLUSIONS 20 COMMISSION ORDER NO. G-72-96 Appendix A Commission Order No. G-96-95 Appendix B Registered Intervenors
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