BRITISH COLUMBIA UTILITIES COMMISSION

Transcription

1 C8-24 BRITISH COLUMBIA UTILITIES COMMISSION Project No , FortisBC Inc. (FBC), Application for Approval of a Multi-Year Performance Based Ratemaking Plan for , and FBC Application for Acceptance of Demand-Side Measures Expenditure Schedule for British Columbia Sustainable Energy Association and Sierra Club British Columbia Response to Commission Information Request No. 2 on Intervener Evidence [FBC Exhibit A-37] February 25, Reference: Exhibit C4-13, BCUC 1.1.1, Attachment a, p. 2; BCUC Total Resource Cost Test Mr. Plunkett and Mr. Chernick state in Exhibit C4-13, BCUC 1.1.1: s. 4(1.1) [of the Demand Side Measures (DSM) Regulation] requires that the commission must make determinations of cost effectiveness by applying the total resource cost [TRC] test as modified by a set of instructions. Efficiency Vermont Policy 1029: Efficiency Cost-Effectiveness Analysis Policy and Practice, attached as Attachment to Exhibit C4-13, BCUC 1.1.1, states on page 2: The Vermont Public Service Board recognizes three tests for the cost-effectiveness or value of ratepayer-funded energy-efficiency investments from three perspectives: a) The economic welfare of society as a whole - the Societal test; b) Confining benefits and cost only to resources priced in the marketplace the Total Resource Cost (TRC) test; and c) Focusing exclusively on efficiency investment benefits realized and costs incurred by utility ratepayers the Energy System (a/k/a the utility) test. Mr. Plunkett and Mr. Chernick state in Exhibit C4-13, BCUC The simplest way to incorporate the environmental benefits of an FBC demand-side measure into the cost-effectiveness analysis is to rely on the Modified Total Resource Cost and to refrain from exercising discretion, if it is available under s. 4 (1.8) of the [Demand Side Measures] DSM Regulation, to find the measure to be not cost-effective if it fails the [Utility Cost Test] UCT. 1.1 Given that the TRC test does not include the cost of an incentive a utility may provide, do Mr. Plunkett and Mr. Chernick consider that such an approach is appropriate as available incentives are not relevant in determining whether a customer is making efficient energy related investment and consumption decisions from a BC perspective? Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is FEI PBR RRA 1 BCUC IR No. 2 to BCSEA

2 Yes. Incorporating the environmental benefits of an FBC demand-side measure into the cost-effectiveness analysis by using the mtrc and not the UCT is appropriate. The UCT is not indicative of the allocative efficiency of resource allocation between competing supply and demand-side resources. Rather, as explained in the testimony, the UCT gauges the distributional equity of the utility expenditures supported by ratepayers in exchange for the benefits they receive in terms of lower total utility revenue requirements. Nor does the UCT account for the environmental benefits of avoided supply from a BC perspective. 1.2 Do Mr. Plunkett and Mr. Chernick consider that the DSM Regulations require that the TRC does not include: (i) any energy-efficiency related benefit for emissions reduction (for example, by including an estimate of the long-run marginal cost of emissions), (ii) reduced financial, project and portfolio risk (if any), and (iii) non-energy benefits? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is i. Mr. Plunkett and Mr. Chernick do not believe that the DSM Regulations require that the TRC exclude the benefit of emissions reduction. ii. Mr. Plunkett and Mr. Chernick do not believe that the DSM Regulations require the exclusion of avoided risks. In general, monetized avoided risks would be an avoided cost for TRC purposes. iii. Mr. Plunkett and Mr. Chernick do not believe that the DSM Regulations require the exclusion of non-energy benefits. In general, participant non-energy benefits would be included in the TRC, or both participant non-energy benefits and costs would be excluded from the TRC. 1.3 Do Mr. Plunkett and Mr. Chernick consider that, where customer non-energy benefits are difficult to quantify (for example, if they vary significantly between customers), risks that the Energy Efficiency and Conservation (EEC) program would not pass a Societal test could be addressed by clearly communicating to customers how much they will save in terms of energy cost by undertaking energy efficiency measures (such as installing double glazing), so that customers with high non-energy benefits (for example, noise reduction) can self-select themselves into the program? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is In principle, the societal test should include all costs and benefits, including non-energy benefits. Quantifying the non-energy benefits can be difficult. In the case of replacement windows, one solution to this problem, as suggested in the question, is for the EEC program to offer to pay the incremental cost of new efficient windows over new FBC PBR RRA 2 BCSEA Response to BCUC IR No. 2

3 standard windows, and to let the participating customers decide whether the nonenergy benefits of new windows (ease of operation, noise reduction) cover the base cost of replacing the windows. 1.4 Do Mr. Plunkett and Mr. Chernick consider that a Societal test (rather than the TRC) is best able to determine if a customer is making efficiency energy and consumption decisions from a BC perspective? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Yes. The purpose of the Societal Cost test is to determine the cost-effectiveness of a DSM program or portfolio from a whole BC perspective, i.e., including the benefits and costs of externalities that are not included in the TRC test Do Mr. Plunkett and Mr. Chernick consider that, where the DSM Regulations are not prescriptive as to how inputs into the TRC/modified TRC (mtrc) are determined, the methodology used should be consistent with that used for the Societal test? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. Where the DSM Regulations are not prescriptive as to how inputs into the TRC/mTRC are determined, Mr. Plunkett and Mr. Chernick believe that the normal TRC methodology should be used for inputs to the TRC and that a societal test methodology should be used for inputs to the mtrc Is it Mr. Plunkett s and Mr. Chernick s position that the best way to address any remaining differences between the TRC/mTRC and the Societal test are to disregard the UCT results? If yes, please explain why and if this could result in sub-optimal outcomes. Please specifically address if disregarding the UCT result could result in (i) reduced utility focus on optimizing the level of incentive provided to participants (and so increase equity concerns between participants and non-participants), and/or (ii) ratepayers being required to pay to obtain non-energy related BC benefits (such as noise reduction, health) which may be more appropriately paid for by other parties (such as participants or taxpayer). Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. Mr. Plunkett and Mr. Chernick are not suggesting that the UCT results be disregarded. The DSM Regulation requires the mtrc, which approximates a Societal Cost Test, to be used in specific circumstances. Use of the mtrc as required by the FBC PBR RRA 3 BCSEA Response to BCUC IR No. 2

4 DSM Regulation would be undermined by improper use of the UCT as the primary resource screening or portfolio optimization tool, as would least-cost resource allocation. The UCT indicates the extent to which DSM savings reduce future utility revenue requirements in relation to the DSM expenditures incurred. Thus, the UCT can play an important role in determining whether specific incentive levels are reasonable for an individual project, program or group of programs (e.g., at the sector level). For example, assume a DSM portfolio is cost-effective under the TRC: it would not be cost-effective for the utility (i.e., ratepayers) to spend more on incentives than the induced savings are worth in terms of avoided supply costs. But the UCT should not be used to override the results of the mtrc or TRC in determining whether a DSM program or portfolio is cost-effective. (i) Messrs. Plunkett and Chernick do not recommend disregarding the UCT. Doing so could lead programs to pay more than necessary to achieve target levels of program participation or market penetration. (ii) A reasonable way to avoid the situation described in the IR is to cap incentives so that the DSM program passes the UCT. 1.5 Please complete this table below for (i) the TRC and (ii) the mtrc. As filed by FBC DSM Regs (where prescriptive) Efficiency Vermont Societal test Proposed by BCSEA Rationale Discount rate Emission reduction benefit of energy efficiency Risk reduction benefits of energy efficiency Non-energy benefits (i) TRC As filed by FBC (electric) DSM Reg Efficiency Vermont Societal test Proposed by BCSEA Rationale Discount rate 8% nominal Not prescriptive EVT uses 3% as the societal discount rate for the societal test, and 4.08% real FBC cost of capital, net of taxes FBC PBR RRA 4 BCSEA Response to BCUC IR No. 2

5 (i) TRC As filed by FBC (electric) DSM Reg Efficiency Vermont Societal test Proposed by BCSEA Rationale average utility after-tax cost of capital for the TRC test (i.e., calculating Total Resource Benefits, a key performance indicator Emission reduction benefit of energy efficiency Risk reduction benefits of energy efficiency Non-energy benefits none Not prescriptive Not prescriptive Not prescriptive Carbon externalities net of monetized value. $100/ton CO2e (2013$) or $5.88/MMBtu gas (2013$) 11.1% adder to avoided cost 15% benefits adder for nonenergy benefits generally from building shell measures, plus 15% for lowincome efficiency See Response to BCUC Also, deriving avoided costs from the cost of emission-free renewable energy would internalize emission benefits by 2017 Partially reflected by use of BC renewable energy by 2017 Varies by measure and program (ii) mtrc As filed by FBC (electric) DSM Regs (where prescriptive) Efficiency Vermont Societal test Proposed by BCSEA Rationale Discount rate 8% nominal Not prescriptive Emission reduction Not benefit of energy prescriptive No such test Not evaluated Not evaluated FBC PBR RRA 5 BCSEA Response to BCUC IR No. 2

6 (ii) mtrc As filed by FBC (electric) DSM Regs (where prescriptive) Efficiency Vermont Societal test Proposed by BCSEA Rationale efficiency Risk reduction benefits of energy efficiency Non-energy benefits Not explicitly prescriptive Not explicitly prescriptive Not evaluated Not evaluated 1.6 Do Mr. Plunkett and Mr. Chernick consider that, for evaluation of (i) conservation rates and (ii) codes and standards, the TRC should be focused on the action that the rate design/code incents (for example, home insulation, fuel switching, etc.), and not assume that all energy savings are obtained at no cost to the customer and provide a net societal benefit? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. The TRC should reflect all costs and benefits. Energy-efficiency programs can encourage the early adoption of codes and standards, and in some cases can increase compliance and accelerate the future adoption of more stringent codes and standards. The principles for evaluating cost-effectiveness are the same for codes and standards as they are for EEC programs. The TRC generally includes the monetized benefits and costs of changes in energy usage induced by the demand-side measure, regardless of whether its installation was due to conservation rates, codes and standards, or DSM programs. The TRC does not assume that the induced energy savings are obtained at no cost to the customer. On the contrary, the TRC includes the total costs (and benefits) of the measure borne by the participating customer, other parties, and the utility. While neither FEU nor FBC is seeking approval of conservation rates in the current proceeding, that issue is raised by the IR. Conservation rates cannot be evaluated in the same manner as demand-side programs. In setting a rate design, the regulator may know the utility s cost of the metering, billing, controls and communications equipment, but will not know the customer s costs, if any, or the customer s non-energy benefits, if any, of responding to the conservation rate. A change in rate design may encourage a customer to take many actions, ranging from minor changes in habit with negligible cost to the customer, to reductions in the energy service taken, to increased capital and non-energy operating costs. The benefits of conservation rates are typically estimated using elasticity estimates, observed changes in consumption, and sometimes surveys of customer changes in behaviour and investments. In general, conservation rates have FBC PBR RRA 6 BCSEA Response to BCUC IR No. 2

7 little cost to the utility, and are designed so that the customer is rewarded with a lower bill to the extent the customer has reduced system supply costs. So long as customers do not take actions in response to the rate design that are more expensive than their bill savings, a conservation rate would be expected to reduce total costs. The TRC does not assume that a demand-side measure provides a net social benefit. The TRC includes monetized benefits of induced energy savings. The TRC tests whether a measure provides net benefits; the TRC does not assume that the total benefits of a measure will exceed the total costs. 2.0 Reference: Exhibit C8-14, BCUC 1.1.1, Attachment a, p. 3; BCUC , Attachment a, p. 27; BCUC Attachment b, pp. 4, 6 Utility Cost Test Efficiency Vermont Policy 1029: Efficiency Cost-Effectiveness Analysis Policy and Practice, attached as an Attachment a to Exhibit C4-13, BCUC 1.1.1, states on page 3: Efficiency Vermont uses all three cost-effectiveness tests [Societal test, Total Resource Cost test, Utility test] recognized by the Board for two distinct yet inter-related purposes: for making decisions about efficiency investments prospectively; and for reporting the results of those decisions retrospectively. The State of Vermont Public Service Board 2/7/2012 Order re: Cost Effectiveness Screening of Heating and Process-Fuel Efficiency Measures (attached as Attachment a to Exhibit C4-13, BCUC ) states on page 27: We also conclude that energy efficiency providers that we regulate should not pay incentives to participants that exceed the value of the lifetime energy savings of the efficiency measures (we discuss the special case of low-income customers in the following section). There are limited ratepayer funds available for energy efficiency programs; such programs should remain focused on acquiring energy savings. Energy Efficiency Screening Coalition 2013 paper titled Recommendations for Reforming Energy Efficiency Cost-Effectiveness Screening in the United States (included as Attachment b to Exhibit C4-13, BCUC ) states on page 4 and 6: The Utility Cost test and the Societal Cost test both represent reasonable methods for identifying the cost-effectiveness of energy efficiency resources. Ideally, both tests should be considered when screening energy efficiency resources, because they both provide useful information regarding cost effectiveness. regulators may decide that certain lost opportunity or market transformation efficiency programs whose Utility Cost test benefit-cost ratios are less than one are nonetheless in the public interest because of their unquantified benefits, without specifying proxy adders or alternative benchmarks. 2.1 Do Mr. Plunkett and Mr. Chernick consider that, as a general principle, (i) the amount spent by ratepayers on EEC program incentives should not exceed the energy benefit received, and/or (ii) the total amount spent by ratepayers on EEC programs (including incentives) should not exceed the energy benefit received? Please explain why/why not. FBC PBR RRA 7 BCSEA Response to BCUC IR No. 2

8 Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Mr. Plunkett and Mr. Chernick believe that the utility cost test should be used to test whether condition (ii) is met: total benefits to the utility system (commodity, capacity and distribution) should exceed the program costs, including incentive costs. Without some such test, the EEC portfolio could end up providing mostly non-energy services (comfort, aesthetics, safety, etc.) with funding from energy utility customers. Mr. Plunkett and Mr. Chernick do not believe that utilities should be the delivery mechanism for programs that are not primarily energy-related, with limited exceptions (e.g., solving the energy-consumption problems of some low-income households may require solving related housing problems). 2.2 Please explain how, for the purpose of the UCT, energy benefits should be defined. Specifically, should it include emission reduction benefits and any reduced risk? Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is For the purpose of the UCT, energy benefits are defined as the monetized value of the induced energy- and demand-related (meaning commodity, capacity and distribution) savings to the utility. The UCT should include emission reduction benefits and any reduced risk to the extent that these are costs that flow through the utility system. 2.3 Please complete the table below to identify how well the UCT determines if the EEC program provides a net benefit to ratepayers: As filed by FBC DSM Regs (where prescriptive) Efficiency Vermont Utility test Proposed by BCSEA Rationale Discount rate Emission reduction benefit of energy efficiency Risk reduction benefits of energy efficiency FBC PBR RRA 8 BCSEA Response to BCUC IR No. 2

9 As filed by FBC DSM Regs (where prescriptive) Efficiency Vermont Utility test Proposed by BCSEA Rationale Discount rate 8% nominal n/a See the response to BCUC above Emission reduction benefit of energy efficiency Risk reduction benefits of energy efficiency n/a n/a As monetized in wholesale electric energy prices n/a n/a See response to BCUC above See response to BCUC below As reflected in BC carbon tax None proposed 2.4 Do Mr. Plunkett and Mr. Chernick consider that (i) conservation rates and (ii) codes and standards, should be excluded from a portfolio based UCT review on the basis that energy savings associated with these measures can be so cost effective from a utility perspective that their inclusion in a portfolio based UCT review could be distortionary? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Mr. Plunkett and Mr. Chernick intended that the UCT be applied to the EEC programs, not to conservation rates, or codes and standards. Rates, codes and standards generally involve very small outlays by the utility. 3.0 Reference: Exhibit C8-14, BCUC 1.1.3, 1.5.3, ; FBC PBR Exhibit C10-7, Appendix A, p. 34; BCUC 1.9.3; Exhibit C4-8, p. 56 Rate vs. Bill impact/regulatory Treatment of EEC In response to Exhibit C4-13, BCUC Mr. Plunkett and Mr. Chernick consider that the DSM Regulation does not allow the Commission to determine that an entire DSM portfolio is not costeffective based on the RIM test. Mr. Plunkett and Mr. Chernick state in response to Exhibit C4-13, BCUC Shareholder incentive mechanisms concerning FEI and FBC s EEC and DSM portfolios are within the scope of the present proceeding. A 2006 CAMPUT [Canadian Association of Members of Public Utility Tribunals] report titled Demand- Side Management: Determining Appropriate Spending Levels and Cost-Effectiveness Testing, attached as Appendix A to Exhibit C10-7, states: FBC PBR RRA 9 BCSEA Response to BCUC IR No. 2

10 Most utilities and regulators prefer the practice of expensing energy efficiency costs; in the long run, this approach costs less than capitalizing deferring and amortizing costs. The only exception is in cases where programs are being started from scratch, and decision-makers are worried about rate impacts. Capitalizing energy efficiency costs from a period of one year to the average lives of the program measures is done in some jurisdictions. This practice does reduce the immediate cost to implement programs, but there are problems. The carrying cost (at the utility average cost of capital, 7-9% these days) of the unamortized balances adds cost to consumers, quite a lot if the amortization period is long. Eventually, consumers are paying each year s amortized balances, which add up to the annual amount spent on efficiency, plus the carrying cost. Utilities are also concerned about increasing regulatory asset balances, assets on the utility books not backed by actual equipment. Once this practice starts, it is hard to convert to expensing, again due to rate impact concerns. (p. 34) Mr. Pullman states in FBC PBR, Exhibit C10-7, BCUC 1.9.3: the Commission last address accounting for DSM expenditures in 1995 [Order G-55-95]. Mr. Pullman certainly considers that a separate review process would be timely and useful. Mr. Plunkett and Mr. Chernick state in Exhibit C4-8, p. 56: [FBC Discount rate assumptions] were based on weighted average cost of capital, using 40% equity at 9.15% and 60% debt at 5.79% (averaging 7.13%), from FBC Exhibit B-1, pp Mr. Plunkett and Mr. Chernick state in response to Exhibit C4-13, BCUC Thus, 1-3% is reasonable range for a societal discount rate for calculating and comparing present worths of competing resource alternatives. 3.1 Do Mr. Plunkett and Mr. Chernick consider that potential equity issues with EEC programs between participants and non-participants within a customer class could be addressed by (i) ensuring all customers have an opportunity to participate in at least one (or two) DSM programs, and (ii) ensuring the utility offers targeted EEC programs to address market barriers specific to hard to reach customer segments (for example, low-income, renters, First-Nation communities)? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is (i) Yes. Ensuring that all customers within a customer class have an opportunity to participate in DSM programs that address the bulk of their energy usage is an effective way to address potential equity issues between participants and non-participants, by reducing the number of non-participants. (ii) Yes. Providing EEC programs targeted to address market barriers specific to hard to reach customer segments (for example, low-income, renters, First-Nation communities) is an effective way to address potential equity issues between participants and nonparticipants, by reducing the number of non-participants, especially in disadvantaged groups. 3.2 Do Mr. Plunkett and Mr. Chernick consider that, while potential equity issues with EEC programs between existing and future customers can be addressed by deferring and amortizing EEC costs FBC PBR RRA 10 BCSEA Response to BCUC IR No. 2

11 (and so matching costs with benefits), this treatment can push up EEC costs higher than would otherwise be the case where the utility s cost of financing is higher than the societal cost of financing? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Yes. If the utility s cost of capital is C and the discount rate is r, the present value of deferring a dollar with return is (1+C) (1+r). If C>r, the present value of a deferred dollar is higher than the present value of an expensed dollar Commission staff has prepared the following analysis to estimate the additional cost to FBC ratepayers of deferring and amortizing $100 of EEC expenditures over 10 years compared to expensing DSM expenditures as incurred. This estimate assumes the cost to the ratepayers of the utility financing these deferred balance is 7.13%, while the societal cost if EEC expenses were not deferred would be 3%. Please update the analysis for FEU, and comment on whether the assumptions made in this estimation are reasonable. If the assumptions are not considered reasonable, please provide a revised estimate. Year DSM Balance Net cost 7.19% - 3% Year DSM Balance Net cost 7.19% - 3% 1 $ $ $50.00 $ $90.00 $ $40.00 $ $80.00 $ $30.00 $ $70.00 $ $20.00 $ $60.00 $ $10.00 $0.42 $20.53 Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is The IR is premised on a fundamental error, in that it assumes that it is appropriate to mix the utility s private cost of capital for the deferral with the societal discount rate. This approach would be inappropriate for the UCT, TRC, mtrc and the societal test. The use of a social discount rate to discount the recovery of the utility cost is inappropriate, since it mixes the social and private financing models. The UCT and TRC are usually computed using a discount rate equal to the utility s weighted average cost of capital (or the after-tax cost of capital), so the cost of deferral would be zero. A more theoretically valid computation of the TRC or UCT effect of the deferral would FBC PBR RRA 11 BCSEA Response to BCUC IR No. 2

12 compute the revenue requirements using the utility cost of capital and discount them using customer discount rates. Since customers are paying the revenue requirements, their discount rates should be used. The latter are difficult to assess, and individual customer discount rates vary widely. Those are likely much higher than 3% for most customers; the average customer discount rate may be higher than the utility cost of capital. Indeed, in the experience of Mr. Plunkett and Mr. Chernick, representatives of residential, commercial and industrial ratepayers generally advocate lower depreciation rates and longer amortization periods, consistent with the belief that the utility financing costs are lower than the customer discount rates. The cost of capital for most businesses would usually be higher than the cost of capital for a public utility. Households face a wide range of financing costs, from perhaps 2% for a few customers taking money out of a savings account, to around the utility cost of capital for customers taking money out of a balanced mutual fund, to 10% 20% for customers allowing credit card debt to rise to pay their utility bill. In addition, many customers are uncertain whether they will be FEU customers in a decade, so they would prefer not to pay in year one for programs that will benefit future customers for decades to come. In short, most customers are likely to consider themselves better off if the utility defers recovery. The application of the societal test to the deferral of recovery of DSM investment is very different from the application of the TRC or UCT. Simply put, the deferral of the DSM revenue requirements does not defer any costs to society, which are incurred as society uses the resources. Deferring revenue requirements does not defer the use of materials, equipment and labor. Applying the social discount rate to a stream of revenues between parties within society (FEU and its customers) would be nonsensical. Having addressed the deeper conceptual issues raised in the IR, BCSEA-SCBC believe that the following comments about the numbers in the IR table will be helpful for clarification: 1. The IR refers to both FBC and FEU. We assume that this was an error, and that the IR intended to refer to FEU throughout. 2. The table uses 3% for the societal discount rate proposed by Mr. Plunkett and Mr. Chernick. The societal discount rate they propose is 1 3% real, which would be 3 5% nominal. The utility s cost of capital (7.19% in the table) is apparently a nominal figure (see the response to BCUC 2.6.1). Assuming the table compares nominal to nominal, it is understood that means a 3% nominal societal discount rate, which is the low-end of Plunkett and Chernick s proposed nominal societal discount rate of 3 5%. 3. The table in the IR uses 7.19% for the utility s cost of capital; whereas the text in the IR states 7.13% for the utility s cost of capital. The 7.13% figure is assumed to be an error. The conceptual and directional results of the analysis would not vary significantly for the range of return on capital reported in the filings (7.25% 7.31% for FEU September update, Appendix G-1, Schedule 6; 6.98% 7.13% for FBC Appendix G, Schedule 5). 4. The table in the IR shows the results of a calculation assuming that all the DSM FBC PBR RRA 12 BCSEA Response to BCUC IR No. 2

13 funds are spent at the beginning of year 1 and that the balance is paid down only at the end of each year. Those assumptions are atypical. In the tables that follow it is assumed that the DSM funds are expended over the course of year 1 and ratepayers pay the amortization over the course of the year. Correcting those errors, but retaining the rest of the IR methodology and assumptions yields the following result: Year DSM Balance Net cost 7.19% - 3% Year DSM Balance Net cost 7.19% - 3% 1 $45.00 $ $45.00 $ $85.00 $ $40.00 $ $75.00 $ $30.00 $ $65.00 $ $20.00 $ $55.00 $ $10.00 $0.42 $ The table in the IR attempts to estimate the present value of the revenue requirements related to return on the unamortized balance, which may be increased by deferral (depending on the cost of capital and discount rate), but ignores the present value of the recovery of the balance, which is reduced by deferral. Using the IR assumptions yields the following result of reducing of year 1 revenue requirements by $90 and increasing revenue requirements by $10 in each of the next nine years: Year DSM amortization Year DSM amortization 1 ($90) 6 $10 2 $10 7 $10 3 $10 8 $10 4 $10 9 $10 5 $10 10 $10 ($11.79) Thus, the corrected present value of the deferral, with the IR assumptions, the corrected timing and inclusion of the amortization revenue requirements is $17.36 $ = $ The IR methodology for estimating the NPV of the cash flow is unusual. The straightforward computation would compute the net deferred cash flow as the sum of the $10 amortization (minus $100 in year one) and the 7.19% cost of capital times the average balance in the year (the average of the balance at the beginning of the year, or BOY, and the beginning of the next year). The result is shown in the following table: FBC PBR RRA 13 BCSEA Response to BCUC IR No. 2

14 Year DSM Balance BOY Amortization + Return Year DSM Balance BOY Amortization + Return 1 $0 ($86.76) 6 $50 $ $90 $ $40 $ $80 $ $30 $ $70 $ $20 $ $60 $ $10 $10.42 $50.00 $ Do Mr. Plunkett and Mr. Chernick consider that an alternative option to maintaining intergeneration equity could be to defer and amortize EEC expenditures only where required to maintain bill impacts to acceptable levels (for example, longer EEC amortization periods may be acceptable during times of rapidly rising energy prices)? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Mr. Plunkett and Mr. Chernick believe that in general it is appropriate to amortize any expenditure (including those for EEC) over the expected duration of the benefit from the expenditure. That logic applies to EEC as well as to distribution pipe. This matching principle notwithstanding, it is not necessary to defer and amortize EEC expenditures, where the bill impacts of expensing the program costs would be acceptable. Whether expensing is practical may depend on the extent of other upward pressure on rates, such as from rising energy costs Do Mr. Plunkett and Mr. Chernick consider that reducing the level of EEC spending as a result of concerns over bill increases (i.e., applying RIM at the portfolio level), could (i) raise costs for customers overall, and (ii) could make it harder for customers to mitigate the impact of rate increases on their monthly bills? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Yes to both parts. (i) Reducing EEC spending in response to the results of the RIM applied at the portfolio level would raise costs for customers overall, because cost-effective measures would be deferred or (for market-driven opportunities) lost. (ii) Reducing EEC spending in response to the results of the RIM applied at the portfolio level would make it harder for customers to mitigate the impact of rate increases on their monthly bills, because the customers who would have benefited from the curtailed programs will find it harder to reduce their bills. FBC PBR RRA 14 BCSEA Response to BCUC IR No. 2

15 3.3.2 Do Mr. Plunkett and Mr. Chernick consider that rate shock concerns could justify retaining the existing 10 year EEC amortization period, compared to using an amortization shorter than 10 years? Please explain why/why not. Yes, in practice, if FBC were dramatically increasing its EEC spending (which it is not) and other factors were contributing to rate shock then there would be an argument for retaining rather than shortening the EEC amortization period. In principle, however, the EEC amortization period should reflect the duration of the savings benefits. 3.4 What regulatory treatment of EEC expenditures (both in terms of what is amortized vs. expensed, and the length of the amortization period) would Mr. Plunkett and Mr. Chernick propose to both maintain intergenerational equity while not unnecessarily increasing EEC costs recovered from customers where the utility s financing costs are higher than the societal discount rate? Please explain. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is The cost-recovery schedule is affected by a number of factors (current economic conditions, current and future rate increases for non-eec costs) that are beyond the scope of BCSEA-SCBC s engagement of Mr. Plunkett and Mr. Chernick in this proceeding. As explained in response to BCUC , comparisons of societal discount rates and the utility s financing costs are irrelevant. 3.5 Do Mr. Plunkett and Mr. Chernick consider that the current EEC regulatory treatment provides advantages to the FBC shareholders in that it results in an increase in the rate base and therefore results in income growth for shareholders? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. If the BCUC has set the cost of capital properly, the cost to existing shareholders of raising additional capital to support the higher rate base would exactly match the return on the additional rate base, resulting in no growth in income per share or benefits to shareholders. Fortis managers may prefer to manage a larger company than a smaller one, but that has nothing to do with any benefit to shareholders Do Mr. Plunkett and Mr. Chernick consider that if the current EEC regulatory treatment were to change (for example, by decreasing the amortization period or requiring that some DSM costs could no longer be amortized), an alternative incentive mechanism should be put in place to ensure that the utility does not prefer supply side investments (which, excluding commodity purchases, could grow the rate base) to demand side investments which do not? Please explain why/why not. FBC PBR RRA 15 BCSEA Response to BCUC IR No. 2

16 Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. See response to BCUC (immediately above) Please describe best industry practice to ensure that an electric utility s demand-side investments are treated on a level playing field with supply side investments. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Efficiency Vermont s energy efficiency cost-effectiveness policy and procedures represent best industry practice for unbiased comparisons between competing demand and supply-side resource alternatives. While originally intended for the state s electric efficiency resource acquisition, they apply equally to natural gas (and have been expanded in scope to apply to non-electric unregulated fuel efficiency). See Exhibit C4-13, Attachment FEI BCUC 1.1a.pdf. As for cost recovery, British Columbia s practice of amortizing DSM expenditures over 10 years represents industry best practice. 4.0 Reference: FBC PBR Exhibit C8-14, BCUC Conservation Potential Review (CPR) Mr. Plunkett and Mr. Chernick state in response to Exhibit C8-14, BCUC 1.6.1: Best industry practice is to conduct a program potential analysis for achieving alternative scenarios involving different levels of efficiency savings over the period covered by the DSM plan. 4.1 How do Mr. Plunkett and Mr. Chernick consider the next CPR should be undertaken? Please specifically address (i) if it should be undertaken separately for each utility or by combination (for example, FBC/BC Hydro, FBC/FEU, FBC/FEU/BC Hydro) and (ii) if this should be undertaken by the utility or an independent third party, and if a third party who should be responsible for commissioning the work, and how should differences in opinion as to the inputs into the CPR (such as the avoided cost of energy and discount rates) be addressed? Please explain. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is As indicated in the response to BCUC (FBC PBR Exhibit C8-14), an updated or new Conservation Potential Review is not a necessary prerequisite for FEU to scale up their EEC portfolio. That said, the next CPR should be designed to support increased coordination of DSM activities among FEU, FBC, BC Hydro and LiveSmart. It would make sense for the next CPR to address both gas and electric savings across the Province. As CPRs are normally prepared by a consulting firm engaged by the utility, the relevant utilities and LiveSmart should jointly commission the work, with stakeholder involvement. FBC PBR RRA 16 BCSEA Response to BCUC IR No. 2

17 Substantively, Mr. Plunkett and Mr. Chernick recommend that long-range demand-side resource planning be based on the assessment of two or three alternative scenarios for multi-year program spending and savings over a 5 to 20 year period. In general, the scenarios analyzed should reflect the timing and composition of resource needs and alternatives available for the jurisdiction, for both energy and capacity. Competing alternative DSM scenarios should be analyzed for cost-effectiveness under the mtrc/trc tests and the UCT tests as discussed and demonstrated for alternative DSM Plan scenarios in the testimony. DSM scenarios should be developed provincewide, i.e., for both BC Hydro and FBC and for FEU. Ideally, analysis should be integrated between gas and electricity. The analysis should be conducted and scrutinized through a transparent regulatory process open to critical review and input by stakeholders. Experience shows that unbiased results are possible either from a third party analysis or one by the administrators of the portfolio, utilities or otherwise, as long as the review process allows for enough critical input by other stakeholders. This is how the approach has evolved through the Vermont Public Service Board s triennial 20-year Demand Resource Plan (DRP) process. For example, in its second DRP in progress now, Vermont is considering three scenarios: (1) fixed real budgets, and thus steadily declining savings over time due to diminishing returns; (2) continuation of savings projected forward from the current DRP at about 2% of electricity sales per year, and thus gradually increasing spending; and (3) 3% annual savings each year, with steadily increasing budgets. The three scenarios differ in terms of participation, measures targeted, and incentive levels. In addition to the scenarios to be analyzed, the PSB also approves in advance basic analysis parameters such as discount rates and avoided costs. In Vermont, the efficiency utility is authorized to submit analyses of the approved scenarios, as well as any additional scenarios if recommended. The state s statutory consumer representative, the Public Service Department, also analyses one or more of the alternative scenarios. Close consultation and collaboration between the EEUs and the PSD leads to a narrowing of differences in projected savings, spending, and costeffectiveness. The PSB selects either one of the scenarios presented or a hybrid, and then directs the EEU to submit a final DRP consistent with the adopted 20-year savings and spending, the first three years of which become the 3-yeaar budget and performance targets for the EEUs. This process is just now being established for Vermont s lone and expanding gas utility (which happens to be owned by the same Canadian gas utility that recently acquired Vermont s largest electric utility, Gaz Metro) Do Mr. Plunkett and Mr. Chernick consider the next CPR should include scenario analysis to model different key inputs (for example, alternative avoided energy cost estimates)? Please explain why/why not. If yes, please describe the key variables that should be modelled. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is FBC PBR RRA 17 BCSEA Response to BCUC IR No. 2

18 See the response to the preceding question. In general, only a single trajectory of avoided costs is recommended unless there is a high degree of variance or volatility in expectations, in which case two avoided cost scenarios would be recommended. 4.2 Do Mr. Plunkett and Mr. Chernick consider that, while use of a 2% target may be a useful way to estimate if the proposed DSM portfolio is in the right ballpark, a bottom-up evaluation using a CPR as a starting point should better result in a portfolio that meets the Energy Plan s objective of pursuing all cost effective and competitive DSM programs? If no, please explain. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is See the response to BCUC A full CPR studying the maximum economically achievable potential is not automatically necessary. Utility DSM plans for annual savings and spending should be predicated on bottom up construction and costeffectiveness analysis of a scenario specifying participation levels, measure costs and performance per participant. The performance of a utility s DSM plan should be benchmarked against industry peers to demonstrate its reasonableness. 4.3 Do Mr. Plunkett and Mr. Chernick consider that a DSM target linked to DSM spending could risk an increased focus on DSM incentive based programs, and/or unnecessary increases in incentives paid, in order to spend the budget? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is As explained in the testimony and illustrated in Exh. JPPC-3 (FEI Exhibit C4-8), the least-cost planning objective is to pursue a DSM portfolio that will eventually realize all cost-effectively achievable savings. Mr. Plunkett and Mr. Chernick use depth of savings as a way to benchmark a DSM portfolio in comparison with industry peers. They do not propose that DSM spending limits be set arbitrarily. Further, they consider energyefficiency spending limits to be ill-advised, other than possibly to address the distribution of effort among sectors, as long as the additional spending produces additional cost-effective savings Do Mr. Plunkett and Mr. Chernick consider that a DSM target based on DSM savings achieved, could raise conflict of interest issues if the utility is both responsible for achieving the DSM results and the evaluation of whether those results were achieved? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Regardless of how or by whom the DSM portfolio savings target is set there is an issue FBC PBR RRA 18 BCSEA Response to BCUC IR No. 2

19 of how best to structure the evaluation of portfolio implementation and portfolio administrator performance. Mr. Plunkett and Mr. Chernick consider that ideally evaluation should be performed by independent third-party experts chosen or approved by the Commission or in consultation with stakeholders. A second-best alternative is to have program administrators engage unbiased, independent experts to conduct the evaluations as long as there is a transparent process for stakeholder input into research design and critical review of study findings, conclusions, and recommendations Do Mr. Plunkett and Mr. Chernick consider that a utility both being responsible for achieving DSM results, and the evaluation of whether those results were achieved, are best industry practice? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. While program administrators are responsible for measuring, monitoring, and reporting savings, best industry practice is for an independent part to verify claimed savings and evaluate program performance. This is the case in Vermont, for example. The Public Service Board requires that the savings claims of the energy efficiency utility be verified annually by the Public Service Department, which usually leads to a nontrivial reduction in the amount of savings recognized in judging EEU performance. 4.4 Please provide an estimate of the additional cost (as a percentage of total DSM costs) that would be required to ensure DSM Evaluation Measurement and Verification (EM&V) results prepared by FBC are subject to independent review. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is As a general rule, EM&V activities require spending representing about 3-5 percent of portfolio spending, depending on the maturity and scale of the portfolio Do Mr. Plunkett and Mr. Chernick consider that subjecting EM&V results to scrutiny only during regulatory hearings is more efficient than an audit of the EM&V results as they are released by an industry expert? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is No. Technical workshops are generally sufficient without the expense and adversarial nature of contested proceedings. In practice, such workshops can be conducted with a court reporter to transcribe the proceedings and one or more members of the regulatory staff to preside over them. FBC PBR RRA 19 BCSEA Response to BCUC IR No. 2

20 4.5 Do Mr. Plunkett and Mr. Chernick consider that FBC DSM funding approval should be for a 5 year period, or that a shorter period may be appropriate (say, 3 years) so that DSM funding can be adjusted to reflect the results of an updated CPR? Please explain. Yes. The FBC DSM funding approval should be for a 5-year period as requested by FBC, with annual evaluation reports to be filed. In addition, there should be an opportunity for periodic review and revision within the 5 years, e.g., every 1-2 years. The revisions should consider changes in energy-efficiency technology and practice, program designs, program staging, evaluation reports, progress toward goals, distributional equity, and changing avoided costs. Vermont s EEU and PGW submit both annual reports of program results and annual plans for the remainder of the multi-year period covered by their DSM plans (3 years for Efficiency Vermont, 5 years for PGW) Do Mr. Plunkett and Mr. Chernick consider that FBC should be allowed to transfer DSM funding between years during the PBR period? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Changes in the timing of DSM spending may be prudent, but should be subject to BCUC review Do Mr. Plunkett and Mr. Chernick consider that FBC should be allowed to launch new DSM programs without Commission approval during the PBR period? Please explain why/why not. Please see the BCSEA-SCBC response to BCUC IR in FEI Exhibit C4-19, which is Some level of review of proposed programs is appropriate. If the spending is relatively small and is supported by the interested parties, the BCUC may be able to approve the utility proposal based on little more than a letter filing. Less formal technical workshops, as discussed in response to , would generally suffice Do Mr. Plunkett and Mr. Chernick consider that FBC should be allowed to file DSM reports annually instead of semi-annually? Please explain why/why not. FBC should be allowed to file DSM reports annually instead of semi-annually. Most DSM administrators report annually. Reporting semi-annually can be an unnecessary administrative burden in which the effort doesn t contribute to additional energy savings, but increases administrative costs. FBC PBR RRA 20 BCSEA Response to BCUC IR No. 2

21 5.0 Reference: Exhibit C8-14, BCUC , Appendix a, pp. 6, 15, 23 BC Hydro November 2013 Integrated Resource Plan (IRP), Chapter 9, p. 9-53; Exhibit C8-9, p. 84 FBC Avoided Energy Cost The State of Vermont Public Service Board 2/7/2012 Order re. Cost Effectiveness Screening of Heating and Process-Fuel Efficiency Measures (attached as Attachment a to Exhibit C8-14, BCUC ) states: Since the Board Staff Memorandum was issued, the 2011 AESC study was completed, and we approved EEU new avoided costs for electricity, natural gas, and other heating-and process fuels based in large part on that study. We intend to continue to review EEU avoided costs every two years, and we determine that future consideration of avoided costs for heating and process fuels should occur in those EEU avoided-cost proceedings. (p. 6) The types of risks associated with different fuels are different, with the most significant being the risk of price volatility and infrastructure risk. We accept the DPS's and the 2011 Joint Commenters' recommendation that the 10 percent discount to the price of demand-side options be applied when screening efficiency investments of all fuel types. (p. 23) Vermont regulated entities, including the EEUs, have long used Board-approved environmental externality values for fuel-consuming end-use efficiency measures. (p. 15) BC Hydro states on page 9-53 of its November 2013 IRP: BC Hydro expects to negotiate [Independent Power Producer (IPP) Energy Purchase Agreements (EPA)] prices at or close to the spot market price forecast but must consider factors such as energy product attributes and associated non-energy benefits. Mr. Plunkett and Mr. Chernick state in Exhibit C8-9, p. 84: Assuming that the marginal source of energy supply is entirely spot market purchases through 2019, and entirely new renewables from 2020 onward, with no incremental generation capacity cost before 2020, the levelized LRMC over would be about $140/MWh, compared to FBC s estimate of about $50/MWh. 5.1 Please provide the avoided energy cost for each year from 2014 to 2043 proposed by Mr. Plunkett and Mr. Chernick, and show how these annual estimates result in a levelized LRMC estimate over 2014 to 2043 of $140/MWh. The following table shows the computation of the short-term avoided generation cost for , and the levelization of the avoided generation cost, including a minimal estimate of the LRMC, at a range of real discount rates. The adjustments to the shortterm avoided costs are described in BCUC In the longer term, from 2020 onward, Mr. Chernick used the $120/MWh from the BC Hydro supply curve, which is underestimated by the amount of required transmission and reserve. The following table provides the derivation of the near-term avoided costs and the levelization for at 4.1% and 4.9% real. Avoided T&D, equivalent to $46/MWh., should be added to both the short- and long-term avoided costs. FBC PBR RRA 21 BCSEA Response to BCUC IR No. 2