Sorena Rahi is a PhD Candidate in Business, Economics, and Public Policy at the Ivey Business School and a Research Assistant with the Ivey Energy Policy and Management Centre. He shares the key takeaways from each panel event as part of the Centre’s annual Workshop on the Economics of Policy and Markets.
The Ivey Energy Policy and Management Centre is hosting its 5th annual workshop on the Economics of Electricity Policy and Markets. The theme of this year’s workshop revolves around electrification as part of the transition to a clean energy economy. On October 20, in the third of the workshop’s four sessions, panellists from academia, government, and industry shed light on some of the challenges with electricity rate design as the energy sector transitions toward decarbonization. The session was hosted by Brian Rivard, Director of Research for the Ivey Energy Centre, and moderated by Brandon Schaufele, Ivey Energy Consortium Fellow and Associate Professor of Business, Economics, and Public Policy at Ivey Business School.
The challenges with rate design and dynamic pricing
Carlos Batlle, Research Scholar at MIT Energy Initiative and Professor at Comillas Pontifical University in Madrid, argued that electricity rate design is critical to decarbonization and for electrifying the economy. Infrastructure decision-making in the power system is becoming more decentralized with an increasing number of customers on the distribution system making long-term investment decisions. Effective rate design is the key to providing the right signals for these investments.
Professor Batlle noted three main challenges for achieving effective rate design. First, dynamic energy pricing models should be implemented to induce customers to make efficient investment decisions. However, the billing effects of dynamic pricing are not always understood or well-received by customers. For instance, research in Europe shows that many customers are reluctant to accept the degree of price volatility that comes with the implementation of dynamic energy prices and time of use (TOU) demand charges. The risk of customer backlash may impede some policy-makers from implementing dynamic pricing.
Second, the way in which sunk legacy charges (a.k.a. residual costs) are recovered will become increasingly important as technology advances and the cost to self-supply (at least partially) becomes more affordable. Charges should be carefully designed, to avoid inducing customers to invest inefficiently in distributed alternatives in order to avoid paying for the sunk network costs. Batlle and his colleagues address potential solutions to this issue in a recently published academic article.[1]
Third, innovative policies and regulatory solutions are required to ensure a “just transition” to a cleaner economy where all members of society have the means and ability to participate. Decarbonization through increased electrification will be costly and likely lead to energy price increases that may affect low-income customers disproportionately. Low-income customers are less likely to have the means to adapt to new technologies and therefore, are exposed to greater risk of being “disconnected” from the new framework.
View Batlle’s presentation here
Alberta’s transition to decarbonization
Nicole LeBlanc, Director of Markets & Tariff at the AESO, explained some of the recent developments in Alberta on its path to decarbonization and AESO’s regulatory role in the process. She argued that as the different aspects of the transmission and distribution systems move toward supporting new technologies that enable a two-way flow of power on the grid, regulators need to not only review the technical standards and requirements of the system, but also assess how rates and markets should be designed and regulated.
She highlighted various changes that are driving Alberta’s transition toward decarbonization and electrification. These include, but are not limited to, new economic sectors that are creating new users of electricity, carbon pricing policies, and technological changes, as well as consumer choices for renewable options in their energy mix. AESO’s regulatory role is to design the market to align price signals across the value chain so that consumers and generators make choices that make efficient use of the infrastructure. Alberta has also seen a growth in renewable sources of power generation as well as energy storage, but the main driver of the province’s transition toward decarbonization has been the switch from coal to natural gas generation. Carbon pricing policies and off-coal requirements at the federal and provincial levels have set the stage for a shift in the province’s generation mix, which will lead to an estimated reduction in GHG emissions of more than 60 per cent by 2030 compared to the level of emissions in 2005. LeBlanc maintained that the conversion would introduce a range of costs for generators, which will partly flow to customers through higher prices. Further, a handful of coal generation assets will be stranded as a result of the transition and the Government of Alberta will be providing transition payments to compensate generators. These payments will be funded through carbon taxes collected from high emitters.
View LeBlanc’s presentation here
Cost implications of electrification for natural gas utilities
Catherine H. Hausman, Associate Professor in the School of Public Policy at the University of Michigan and Research Associate at the National Bureau of Economic Research, presented results from an academic working paper she has conducted with a colleague[2] that studies the cost implications of electrification for natural gas utilities and their customers. She argued that as customers make the switch from natural gas to electricity, the gas infrastructure and pipelines that were serving them do not disappear, and the fixed costs of that infrastructure such as maintenance and legacy costs will have to be borne by the remaining customers on the system. As more and more customers exit the natural gas system, bill totals for remaining customers will increase. She also provided insight into the different cost components of a natural gas utility and examined which portions leave or stay once a customer exits the system. Capital-related expenditures, such as recovering depreciation costs and returns for investors, will stay and have to be completely recovered from remaining customers. Further, a portion of operation-related expenditures and taxes will also continue to remain on the system. These estimates will vary based on the level of new capital investments and the size of already depreciated assets in the gas sector. In terms of policy implications, Hausman maintained that the main challenge is to achieve the goals of decarbonization while at the same time not leaving low-income customers behind, serving remaining gas customers during the transition, and maintaining the safety and reliability of the natural gas infrastructure. Their study offers a list of potential solutions that policymakers could adopt to address these concerns.
View Hausman’s presentation here
[1] Batlle, Carlos, Paolo Mastropietro, and Pablo Rodilla. "Redesigning residual cost allocation in electricity tariffs: A proposal to balance efficiency, equity and cost recovery." Renewable Energy 155 (2020): 257-266. https://www.sciencedirect.com/science/article/pii/S0960148120304857
[2] Davis, Lucas W., and Catherine Hausman. Who will pay for legacy utility costs?. No. w28955. National Bureau of Economic Research, 2021. https://www.nber.org/papers/w28955
