THE REGULATOR’S DILEMMA

Regulators are increasingly confronted with the dilemma posed by proposals to advance electrification or, alternatively, to undertake investments that may appear to oppose electrification. For the regulator, these proposals raise issues with respect to the assessment of benefits and costs and their effect not only on utility rates, but on social welfare. A recent decision of the British Columbia Utilities Commission exemplifies this dilemma.

On December 23, 2023, in Decision and Order G-361-23^[1], the British Columbia Utilities Commission (BCUC) considered an application from FortisBC Energy Inc. (FortisBC) to increase its pipeline capacity to meet a forecast increase in peak demand throughout the central and north Okanagan regions over the next 20 years due to population growth. The project entailed the construction of approximately 30 kilometers of new gas pipeline along with a new pressure control station and related facilities, and the decommissioning of a segment of an existing pipeline, at an estimated total cost $327.4 million.

FortisBC provided a forecast of peak demand relative to annual capacity demonstrating that the system would no longer be able to provide the pressures required to adequately supply gas to the region in an extreme cold weather event by the winter of 2026/2027.^[2] The utility also identified a number of short-term mitigation measures that could be used to manage the peak load while the applied-for longer-term solution was being implemented.

The BCUC expressed concerns that the FortisBC forecast did not consider the potential for a flattening or reversal of the demand curve due to commitments in the province’s CleanBC Roadmap and the changes to the BC Energy Step Code, the Zero Carbon Step Code and other planning guidelines and zoning bylaws.

FortisBC argued that its Revised Renewable Gas Comprehensive Review application to the BCUC, if approved, would enable all new residential connections to receive 100 per cent renewable gas, thereby satisfying the requirements of the Zero Carbon Step Code. The Commission found that although approval of the renewable gas application would “do much to offset some of the concerns regarding the likelihood of continued growth in natural gas peak demand, its approval does not bind the BC Building Code to incorporate renewable natural gas.”^[3]

In a separate parallel proceeding, 2022 Long Term Gas Resource Plan (LTGRP)^[4] FortisBC filed with the BCUC the Kelowna Electrification Case Study – Electrification and the Impacts of Cold Temperature on Peak Demand and System Upgrade Costs. As both the electricity and distribution company serving the City of Kelowna, FortisBC estimated the effects that various levels of electrification of gas demand would have on peak electricity demand, as well as the estimated costs to upgrade and develop the required electricity infrastructure to meet the forecast electricity demand. The study illustrated the factors to be considered in the clean energy transition assuming electrification is the pathway to achieve the province’s decarbonization goals.

The study concluded that:

…at 100 percent electrification of gas load and a mean daily temperature of -26 Celsius, peak demand in 2040 would more than triple, from 472 megawatts (MW) to 1,429 MW, resulting in a high-level estimate of between approximately $2.6 and $3.4 billion in capital expenditures on the electric distribution and transmission system which would be needed in less than 20 years. Even at 25 percent electrification of gas load, peak demand would increase to 711 MW and result in an estimated range of $1.3 to $1.7 billion in capital expenditures over this same timeframe.^[5]

The Kelowna Electrification Case Study was not included in the record of the proceeding leading to Decision and Order G-361-23 and was not considered by the BCUC. In its decision, the Commission noted that:

If the [Okanagan Capacity Upgrade] Project were a minor expenditure the Panel might be inclined to move forward with a favorable Decision at this time. But at last estimate, the total OCU Project cost is $327.4 million with a delivery rate impact of 2.37 percent. This is a very significant expenditure and, for it to be approved, there needs to be greater certainty that the proposed scope of the project is fully required.^[6]

The Commission concluded that “there is a significant risk that the forecast growth flattens or potentially begins to decline due to [FortisBC’s] inability to serve new customers’ space and water heating needs resulting from the Province’s commitments in the CleanBC Roadmap, the changes to the BC Energy Step Code and the [Zero Carbon Step Code].”^[7] The Commission determined that the project was not necessary and denied the application.

In light of the Kelowna Electrification Case Study^[8], the decision brings into question the potential for fuel switching, including renewable natural gas, and the role to be played by electrification on the path to achieving the province’s long-term decarbonization commitments. More importantly, it highlights the challenges regulators face when evaluating programs and proposals that contemplate fuel switching, particularly in the absence of all the information required to undertake a robust analysis of the benefits and costs of energy efficiency alternatives.

The Kelowna Electrification Case Study also brings into focus the potential costs of electrification as an alternative to natural gas for space and water heating. A 2022 Natural Resources Canada discussion paper estimates that retrofitting all homes, including electrification of space and water heating, and all commercial and public buildings by 2050 would cost $20 billion to $32 billion a year.^[9] Studies such as these raise questions as to when and in what circumstances electrification is beneficial. The challenge is to determine whether the adoption of electric powered end-use technology as a substitute for direct-use fossil-fuelled technologies for applications such as space heating, transportation, and industrial processes results in a net economic benefit to the customer and net environmental benefits to society.

A transformation in economic regulation is required to review, in a timely manner, the proposals to encourage and facilitate the adoption of new technologies that support emission reductions. The reviews must consider the effect on utility rates and the net benefits to society. This requires regulators to undertake a whole-system analysis to determine whether decarbonization alternatives are indeed both economically advantageous and adequately effective in reducing carbon emissions. To date, evaluating the benefits and costs of utility investments in energy efficiency, load shifting, and fuel switching initiatives, when undertaken by regulators, has generally employed tests originally developed in California’s Standard Practice Manual^[10].

THE EVALUATION CHALLENGE

The California Public Utilities Commission issued its first Standard Practice Manual in 1983. The Manual prescribes cost effectiveness tests to evaluate demand-side energy efficiency programs. The most recent version of the Manual, published in 2001, includes four test criteria to assess the viability of conservation and load management programs.^[11] However, the Manual also contemplated the tests being applied to evaluate proposals for “fuel switching” which was an early reference to what would now be called electrification. These tests have been broadly adopted and applied individually and collectively across North America to determine the economic viability of demand-side management investments. The tests are now being further adapted to evaluate a variety of electrification proposals such as the deployment of electric vehicle (EV) chargers, EV charging demand management programs, and residential heat pump programs.

The fours tests set out in the Manual are:

• The Participant test – assesses the degree to which customers who participate in a program enjoy positive net benefits measured as the net present value of customer benefits and costs over an assumed participation lifetime.
• The Ratepayer Impact Measure (RIM) test – assesses whether utility customers in general will experience a rate increase or decrease from the implementation of a Rate changes are calculated based on changes in the total costs of the service provider and changes in the levels of electricity consumption resulting from the program.
• The Total Resource Cost (TRC) test – combines the results of the Participant and RIM tests to assess the combined impact on program participants and the utility.
• The Program Administrator Cost (PAC) test – Considers utility/program administrator costs, as an input to the RIM test.

These tests have been extensively critiqued in academic literature and numerous shortcomings have been identified. For example, the TRC test has been criticized for its simplifying assumptions about consumer behaviour which are exacerbated with a program that includes fuel switching. The RIM test has been criticized for not providing enough detail to address issues related to cross-subsidies between program participants and non-participants and does not account for whether rate increases will be allocated across all customers classes.

The tests have also been generally criticized for excluding non-energy benefits and costs. The calculated net economic benefits of energy efficiency and electrification programs using these four tests have been incomplete because the evaluation criteria in the standard tests rely on an analysis of utility avoided costs and ignore societal benefits such as air quality improvements and non-energy related consumer benefits beyond utility rate impacts. In addition, often the Total Resource Cost test concluded that a program was viable, while the Ratepayer Impact Measure test concluded that rates would rise, suggesting non-viability. The core problem for the regulator, then, was that no test was comprehensive.

The Manual also discusses the Societal test, an expansion of the Total Resource Cost test that proposes to account for externalities, including non-energy benefits, and utilizes a societal discount rate to assess net societal benefits. The Societal test is intended to determine the overall benefits and costs to society of energy efficiency and electrification programs. However, the Manual does not fully define the boundaries of the proposed test, and it has been criticized for being “too open ended.” Efforts are now being made to expand the scope and define the boundaries of the assessment tools, in part to make them more applicable to the type of complex analysis that would be required to assess the societal benefits and costs of significant electrification programs.

EVALUATING ELECTRIFICATION INITIATIVES: CURRENT PRACTICE

A study by The Brattle Group in 2019, commissioned by the Electric Power Research Institute, assessed the California Standard Practice Manual and proposed a framework for evaluating electrification projects called the Total Value Test. The test is intended for “regulators who view their role as implementing social policy.”^[12]

The Total Value Test has, as its objectives, to take the broadest possible perspective on the benefits and costs of electrification programs, to include non-energy benefits and costs, and to account for policy goals and provide for greater flexibility to account for externalities. The test also allows for an evaluation of the cost-effectiveness of electrification programs over a longer study period to account for elements such as stranded costs or technology costs, the full effects of which may only be truly assessed over a longer study horizon. The test authors propose that the traditional Standard Practice Manual tests are either subsumed by the Total Value Test or become irrelevant. They still see value in retaining the Ratepayer Impact Measure test, but also propose that the test be modified to analyze the effects on specific relevant classes of customers or customer sub-classes, to identify implications for low-income consumers and other affected customer segments.

The Total Value Test sets out a robust list of elements to include in the analysis:

Program costs

• Administration costs, Incentive payments
• Participant contribution to costs
• Third-party contribution to costs

System impacts

• Production capacity costs
• Production energy costs
• Cost of environmental regulations
• Fuel transmission capacity costs
• Fuel distribution capacity costs
• Line losses
• Ancillary services
• Risk to the utility
• Renewable resource obligation
• Energy market price effect

Participant impacts

• Other resource costs
• O&M costs
• Health impacts
• Productivity
• Asset value
• Economic well-being
• Comfort

Societal impacts

• Air quality
• Employment
• Economic development
• Energy security
• Public health

The study authors recognize that while there are well established methodologies for the analysis of some of the elements in the test (for example direct program costs), methodologies will need to be developed for some of the more obscure elements, such as economic well-being, energy security or public health. Many of the more speculative elements have no well-established methodology for quantifying their impact. There are also issues with some of the test elements related to data collection.

The study provides three case studies to demonstrate practical applications of the test, applying the Total Value Test to a City Bus Electrification program, an Indoor Agriculture program and a Water Heater Electrification program. The case studies account for the effect of the program on CO₂ emissions, based on assumptions about the CO₂ emissions for alternative fuels, including the CO₂ emissions emanating from the assumed fuel mix in electricity generation under the electrification alternative.

Proper carbon accounting is an important element of any test that seeks to determine the benefits and costs of electrification programs, given that one of the principal objectives is to achieve decarbonization policy targets preferably at the lowest societal cost. The Total Value Test facilitates carbon accounting as an element of the analysis. The authors state that the test is “objective and not predisposed to favor any particular type of technology based on how it is powered or fueled.”^[13] It is noteworthy that the water heating example concluded that, under different circumstances, either the electric or non-electric technology was most favourable.

One of the challenges when applying the Total Value Test is estimating the benefits and costs associated with changes in the consumption of energy that are not fully captured directly in retail electricity prices, referred to as non-energy impacts. Non-energy impacts associated with electrification may include noise reduction, improved home air quality, improved comfort and productivity, aesthetics, reduced maintenance effort, and perhaps more importantly the value ascribed by consumers to the related mitigation of climate change. These elements in a Total Value Test are in the nature of product attributes; direct and indirect benefits that an electrification program, for example a heat pump conversion, may provide. The challenge in adequately accounting for the value of these attributes in the test is to estimate the extent to which consumers value them in their preferences among competing energy alternatives.

In 2020, Electric Power Research Institute engaged Christensen Associates Energy Consulting to explore methods for estimating non-energy impacts.^[14] The Christensen report identified survey and statistical techniques to assist in estimating the value consumers impute to non-energy benefits. Two categories of analytical methods are used to assess consumer preferences for the non-energy attributes associated with electrification programs. Revealed preference analysis observes customer product purchasing behaviour to reveal preferences for underlying attributes. Stated preference analysis surveys customers directly to gather information about customer preferences. The information is then used in statistical analyses to estimate customer valuations.

The Christensen study references a couple of home electrification studies that employed these methods to account for non-energy impacts. One study evaluating home energy management systems assessed the extent to which consumers valued personal benefits such as home comfort and altruistic impacts such as the mitigation of climate change. Another study determined that home comfort was statistically significant in consumer preferences among residential heating system alternatives. The study points out that this type of analysis has not been widely applied in residential electrification programs to date and that methodological problems remain, suggesting that further research is required.

BARRIERS TO ADOPTION

Although the Total Value Test is intended for regulators, the complexity of the test and the methodological challenges that remain may make the test unattractive to many regulators. The difficulty of determining on a case-by-case basis what impacts should be measured presents an initial challenge. The absence of agreed-upon methodologies and available data sets for many of the impacts adds an additional challenge that may be a further deterrent. Even in the best of circumstances, the regulator may be concerned with whether the results of the analysis will be sufficiently determinative.

An alternative approach may be to return to the widely accepted methodology in the Standard Practice Manual for calculating fuel switching impacts and applying publicly available estimates of avoided costs that include an estimate of the marginal cost of carbon.^[15] Marginal avoided costs for the alternatives under study would include production services costs (energy, reserves, capacity) and delivery services costs (transmission, distribution, billing etc.) for both electricity and the fuel being supplanted.

There is a broad range of available estimates of the marginal cost of CO₂. Where a carbon tax that approximates the market price for CO₂ is present, the carbon tax provides a convenient proxy for the marginal cost of CO₂. Otherwise, a marginal cost of carbon based on the range of publicly available estimates would suffice, provided that the value chosen is beyond the control of any of the stakeholders in the evaluation process.

While objective estimates of the marginal cost of CO₂ may be readily available and may be used in evaluating the viability of a project from the perspective of net benefits, the marginal cost of CO₂ cannot necessarily be used for computing the compensation of parties who reduce their carbon footprint by switching to electric power. For example, in a program to assist in electrifying commercial transportation, the avoided CO₂ cost of reduced diesel fuel consumption factors into the benefits of the program, however the fleet owner who converts to electricity does not necessarily receive the value of the reduction in CO₂ that the conversion generates, but merely the savings in diesel fuel cost, in the absence of an avoided carbon tax. In this circumstance, a discount could be conferred on the fleet owner by way of a government subsidy and accounted for in the analysis. Ideally, the government would be collecting a carbon tax from the diesel-using customer and the electric conversion would create the appropriate reduction in cost to the fleet owner. Moving prices of non-renewable fuels toward an agreed-upon estimate of marginal cost that includes a carbon tax that reflects the marginal cost of CO₂ would facilitate the evaluation of the net benefits of electrification alternatives.^[16]

Since the marginal costs in the proposed analysis are usually comprehensive and often the result of years of study, publicly available, and beyond the influence of parties to an evaluation, they avoid lengthy debates over alternative methodologies. Nonetheless, there may be criticism that the marginal costs included in the study are not appropriate or sufficient for the project to be evaluated. Critics may rightly complain that significant elements of cost or benefit are absent, as the approach eliminates or simplifies the review of a long list of impacts. However, the regulator faces the challenge of evaluating proposals in a finite amount of time and at a finite cost. Balancing the benefits of reduced time and cost against the benefits of a more thorough methodology suggests that it should be incumbent upon a stakeholder to justify a departure from the simplified methodology. However, where the results of the simplified analysis overwhelmingly favour one alternative, it is unlikely that the addition of additional elements to the analysis will alter the result sufficiently to favour the other alternative.

More work is required to fine tune this simplified approach, including exploring the range of avoided CO₂ cost values and their applicability and objectivity, and comparing the benefits of the simplified approach with more detailed analyses provided by a Total Value Test evaluation.

WHERE TO NEXT?

Strategies to assist regulators, policy makers and industry stakeholders in the analysis of electrification projects continue to be developed and assessed. However, many regulators lack the experience with or expertise in these emerging analytical models, and their adoption for the purposes of assessing electrification programs appears to be sporadic at best. Parties filing regulatory applications for approval of electrification programs can and should include an analysis of the benefits and costs of electrification projects using the available models, whether or not an analysis is required by the regulator. Although an analysis is unlikely to be determinative in and of itself, and will necessarily be debated, it provides a framework for assessment by the regulator who must consider potentially competing objectives such as affordability and decarbonization policies when making a public interest determination. Regulators would be well served to require that applications for electrification proposals include an appropriate analysis of the relevant benefits and costs that considers the effect on utility rates and the net costs or benefits to society. In addition, the ensuing regulatory proceedings will assist in further fine-tuning these analytical methodologies.

* Mark Kolesar is a researcher, author and consultant in utility regulation and policy development, and a frequent participant in webinars and conferences in Canada and the U.S. He was a member of the Alberta Utilities Commission for twelve years, including six years as Vice Chair and two years as Chair. Mark is now managing principal at Kolesar Buchanan & Associates Ltd., where he advises on utility regulation matters. Mark is grateful to Bruce Chapman of Christensen Associates Energy Consulting for his contributions to this article.

1. FortisBC Energy Inc (22 December 2023), G-316-23, online (pdf ): BCUB <www.ordersdecisions.bcuc.com/bcuc/decisions/en/522057/1/document.do>.
2. See letter from Diane Roy to Sara Hardgrave (23 August 2022) Application for Acceptance of Demand-Side Management (DSM) Expenditures Plan for the period covering from 2023 to 2027, online (pdf ): <www.cdn.fortisbc.com/libraries/docs/default-source/about-us-documents/regulatory-affairs-documents/electric-utility/220823-fbc-2023-27-dsm-expenditures-bcuc-ir1-response-ff.pdf?sfvrsn=b8bf00ec_2>.
3. Supra note 1 at 4.
4. See letter from FortisBC Energy Inc to British Columbia Utilities Commission (24 February 2023) 2022 Long Term Gas Resource Plan (LTGRP) ~ Project No. 1599324 FEI Evidentiary Update, online (pdf ): <www.docs.bcuc.com/documents/proceedings/2023/doc_70278_b-20-fei-evidentiary-update.pdf>.
5. Ibid at 1.
6. Supra note 1 at 4.
7. Ibid.
8. Supra note 4.
9. Natural Resources Canada, The Canada Green Buildings Strategy, discussion paper (July 2022) at 5, online (pdf ): <www.natural-resources.canada.ca/sites/nrcan/files/engagements/green-building-strategy/CGBS%20Discussion%20Paper%20-%20EN.pdf>.
10. California Public Utilities Commission, California Standard Practice Manual: Economic Analysis of Demand-Side Programs and Projects (California: Governor’s Office of Planning and Research, 2021).
11. Ibid.
12. The Brattle Group, “The Total Value Test: A Framework for Evaluating the Cost Effectiveness of Efficient Electrification” (August 2019), Electric Power Research Institute, Document No 3002017017, at 4, online (pdf): <www.evtransportationalliance.org/wp-content/uploads/2021/11/2019-EPRI-TVT-paper.pdf>.
13. Ibid at 38.
14. Christensen Associates Energy Consulting, “Estimating Non-Energy Impacts for Utility Load Shaping Programs”, (30 November 2020), Electric Power Research Institute, Document No 3002018534.
15. This alternative approach arose in discussions with colleagues at Christensen Associates Energy Consulting.
16. Including the marginal cost of carbon in a carbon tax would require a reasonable estimate of the market price, which changes daily, over the term of the carbon tax.