Rate Design and Building Decarbonization: Options and Tradeoffs
The Building Decarbonization Coalition is organizing a core group of building decarbonization enthusiasts to lead a building electrification rate design strategy. This post is the second of a three-part series aiming to raise the profile of how electric rate design impacts a customer looking to decarbonize their home or business. In this post we cover the options and tradeoffs for designing rates to ensure cost recovery, affordability, and environmental protection. The last post in November will cover equity considerations.
The Rate Structure of Yore
For the last forty years, residential electric rates in California have been designed with a focus on encouraging conservation, energy efficiency, and rooftop solar installations, as well as on protecting low-income customers and other small electricity users. These policies have been implemented via an inclining tiered rate structure, with relatively low “baseline” rates for the first tier of usage and increasingly higher rates for larger amounts of consumption (Figure 1). The quantity of usage allowed in the baseline tier varies by climate zone, and also includes larger allowances for electric heat customers and those with special medical needs. This rate structure produces a higher marginal rate for usage above the baseline, which means that customers who install efficiency measures or solar PV can reduce their bills by a greater amount than would be the case with a flat, non-tiered rate and thus achieve a faster payback period for their investment. And since electricity usage generally tends to increase among those with higher incomes, the tiered rate structure is also viewed by many consumer advocates as at least moderately redistributive, i.e., beneficial to those with lower incomes.
As long as energy policy was strongly focused on reducing electricity consumption, the tiered rate structure worked for California. But given the growing proportion of renewable electricity on the grid and expanding markets for electric vehicles (EVs) and building electrification, increasing electricity consumption through fuel substitution is now a key climate policy tool, especially when the increased electricity usage occurs at times when additional renewable electricity is available to serve the new load. The tiered rate structure, however, can make the use of electricity for transportation and space and water heating more expensive for the consumer than incumbent fuels and discourage beneficial electrification.
From Tiered to Timed and Tiers within Times
The California Public Utilities Commission (CPUC) has recognized that the timing of electricity use matters as much or more than the quantity used and begun a transition of residential rates toward a default time-of-use (TOU) rate design, like those already in effect for most business customers. While optional TOU rates have long been available to the relatively few residential customers who chose them, the move to default TOU is now underway for San Diego Gas & Electric (SDG&E) residential consumers and will begin for Pacific Gas and Electric (PG&E) and Southern California Edison (SCE) customers in the fall of 2020.
The default residential TOU rate design will have a mild peak to off-peak rate differential and will contain a “baseline credit” that lowers the effective rates for electricity usage up to the baseline quantity. To make up for the baseline credit and ensure cost recovery within the residential customer class, the rates that apply to usage above the baseline allowance need to be set at a higher cost (Figure 2). These elements were included in the default rate design to mitigate the adverse bill impacts on small users, who could otherwise face higher rates for their baseline usage as the number of usage tiers is consolidated. There have also been concerns expressed that low-income consumers, especially those in hot climates, may find it difficult to shift their usage away from the higher-priced peak period and experience a double hit from higher baseline rates AND higher charges for peak usage.
The CPUC has also directed the utilities to develop several optional TOU rate structures with larger time-based rate differentials, potentially more than two (peak and off-peak) time periods (Figure 3), and at least one with no baseline credit (which results in lower volumetric rates). These optional rates will likely be advantageous for customers with EVs and/or heat pumps, since such customers will have the opportunity to shift the timing of when they use energy to off-peak periods. But advocates for small and lower-income users may be wary of these optional rate designs, particularly those with no baseline credit, because their constituents may not have the ability to shift their energy use as easily.
The Art of Rate Design
The greater the number of rate options available to customers within a given customer class, the harder it can be for the utility to recover the entire allocated class revenue requirement, since customers will naturally gravitate to the rate schedule that is most beneficial for their situation. A rate that offers a better deal to larger users may come at a cost to smaller users, since the utility’s total revenue requirement must be collected from someone. For example, the recovery of the revenue shortfalls that result from larger users selecting more favorable optional rate schedules could cause small and low-income consumers to pay more, and lead to contentious debate over who may be “shifting costs” to whom.
This discussion illustrates the tradeoffs that are inherent in the art of rate design—it can be like squeezing a balloon, only to see it pop out in another direction. Who is going to pay—the high-usage, low-emissions customer who drives an EV and installs an electric heat pump? The customer with rooftop solar that only relies on the grid for backup? The frugal senior citizen who watches every kWh and uses as little as possible? The low-income family with children at home during the peak period? There are no easy answers to these questions.
The CPUC has established a set of Rate Design Principles to help guide their rate reform process:
- Low-income and medical baseline customers should have access to enough electricity to ensure basic needs (such as health and comfort) are met at an affordable cost;
- Rates should be based on marginal cost;
- Rates should be based on cost-causation principles;
- Rates should encourage conservation and energy efficiency;
- Rates should encourage reduction of both coincident and non-coincident peak demand;
- Rates should be stable and understandable and provide stability, simplicity and customer choice;
- Rates should generally avoid cross-subsidies, unless the cross-subsidies appropriately support explicit state policy goals;
- Incentives should be explicit and transparent;
- Rates should encourage economically efficient decision-making; and
- Transitions to the new rate structures should emphasize customer education and outreach that enhances customer understanding and acceptance of new rates, and minimizes and appropriately considers the bill impacts associated with such transitions.
As the Commission itself has observed, these principles can, and often do, conflict with one another to some degree. A fully cost-based rate may be quite complex and not particularly understandable for the typical consumer. The current tiered rate structure (which will still be available as an option after default TOU takes effect) emphasizes conservation and affordability over cost-based rates and is highly valued by advocates for small and low-income customers. And cost-based rates today take into account only the prevailing cap-and-trade market price for GHG emissions and not the much higher societal cost of carbon emissions.
Rate Design in a Decarbonized, High-Renewables Future
The CPUC’s Rate Design Principles do not explicitly mention GHG emissions reductions, though the concept may be implicit in some of them. Nonetheless, the Commission has taken emissions impacts into account in some of its more recent rate design decisions. There is also no explicit mention of shaping load to provide grid services and flatten the “duck curve,” although again this may be implicit in some of the principles. Demand Response programs exist that provide monetary incentives to customers who commit to reducing load at certain key times, but these are only just beginning to reflect the benefits of adding load at times of surplus renewable energy.
Because of the economic impact that electric rates can have on different technologies, it will necessarily be a high priority for building decarbonization advocates to promote rate designs that support increasing electricity usage during lower-cost time periods when renewable energy is abundant. What follows is a discussion of key elements that will need to be considered in designing rates that do not discourage beneficial electrification.
The existence of a “baseline credit” in a TOU rate structure may or may not be problematic for a customer with an electrified building. Generally speaking, the baseline credit will benefit customers who use up to about twice their baseline allowance, and disadvantage those who use more than that. A consumer with heat-pump space heating would qualify for the larger “all-electric” baseline allowance for that climate zone, which may offset the impact of increased electricity usage, but this will vary from case to case. But a customer with a heat-pump water heater and gas space heating would not qualify for the larger all-electric allowance under today’s rules. SCE has agreed to study allowing electric water heating customers to receive the all-electric baseline allowance, but this will not necessarily lead to any change. Another option might be to create a special baseline allotment just for electric water heating customers, but it is not entirely clear whether or not the baseline statute allows this, and the data necessary to calculate such an additional allowance would have to be collected.
Many customers with electrified dwellings may find one of the optional TOU rates to be more beneficial than the default rate. It will be important to publicize the availability of these rates for early adopters. The CPUC recently authorized SCE to offer the “TOU-D-PRIME” rate with larger time-based rate differentials, no baseline credit, and a $12 per month fixed charge, primarily for customers with EVs, heat pumps, and/or energy storage devices (Figure 4). A Critical Peak Pricing overlay is also available as an additional option under this tariff. There were concerns voiced by parties in that proceeding about potential revenue losses that could result from large users electing the new rate schedule, and the Commission provided for a meet-and-confer process if those losses reach a certain level. That question will merit careful monitoring. Similar rate offerings from the other IOUs would be desirable for customers pursuing building electrification.
In PG&E’s most recent GRC Phase 2 proceeding, the CPUC made a number of noteworthy policy statements on the topic of rate design:
Specifically, the DER Action Plan identifies “consideration of fixed charges, TOU periods and rates, nonresidential rate design, including enhancements to dynamic rates” as a “continuing” element in Rate Design Window and GRC Phase II proceedings, as well as “appropriate rate designs to absorb renewables oversupply.” (p.50).
PG&E’s proposed substantial increases to its non-coincident demand charges at the expense of its coincident demand charges do not comply with state policies seeking to incent socially beneficially electricity usage. (COL 27. p.170).
There is a public interest in creating differentials between peak and off-peak pricing throughout the year that may help incent energy storage operation that leads to reductions in GHG emissions. (COL 37, p.171).
With these statements the CPUC has recognized the value of rates that incent socially beneficial electricity usage, as well as price signals that encourage reductions in GHG emissions. Yet, as noted above, existing rates currently only reflect the prevailing cap-and-trade market price for GHG emissions, not the societal cost.
But changes may lie ahead.
In the Integrated Resource Plan (IRP) proceeding the CPUC adopted a GHG Adder for use in demand-side cost-effectiveness analysis, ranging from $80.31 per metric ton of CO2e emissions in 2020 up to $150 in 2030. And in the Self-Generation Incentive Program (SGIP) proceeding the Commission required the utilities to obtain marginal GHG emission values (in kg of GHG per kWh) in real-time five-minute intervals, which will provide the data needed to assign GHG costs to time periods. Once the data are collected, these values could also be used in rate design, which may tend to increase the peak to off-peak rate differential in ways that reward beneficial electrification. Building decarbonization advocates may find it appropriate to intervene in future rate design proceedings to advance this concept.
SCE’s TOU-D-PRIME rate also raises the issue of fixed customer charges, which the Commission is considering in various proceedings. The addition of a customer charge lowers the volumetric rates for that rate schedule by the amount of revenue collected via the fixed charge, which may be advantageous for larger customers who have electrified their dwellings. On the other hand, residential consumer advocates have traditionally strongly opposed fixed per-customer charges because of the bill impact on the smallest users and their effect of dampening the price signal for energy efficiency and conservation. Building decarbonization advocates will have to strike the right balance with rates that support beneficial uses of renewable electricity without inflicting more costs on California’s most vulnerable families.
CCAs set their own generation rates and are able to control at least that portion of the customer’s bill, as long as the utility is able to provide them with the necessary granular usage data. Thus, a CCA could design its rates with larger peak to off-peak rate differentials, more TOU seasons, critical-peak or even real-time volumetric rates, and/or generation peak demand charges to recover Resource Adequacy costs. A CCA could also establish Demand Response programs for its customers, with incentives to reduce peak demand and/or shift load from high-cost to low-cost periods. Whether or not to pursue such options will be a decision for the governing body of each individual CCA.
What could the future hold?
The promise of beneficial electrification is that it can reduce GHG emissions from fossil fuel combustion and, at the same time, reduce costs for the electric utility and all its ratepayers by adding more load to the system when power is cheap, and potentially reducing load when power is expensive. But this win-win can only occur if customers who electrify are careful about the timing of their usage. Just adding more electric demand, regardless of timing, could increase utility costs and place additional stress on the system. This would not be “socially beneficial” electrification.
Therefore it is critical that new building electrification loads, especially space and water heating, be price-responsive, so as to run appliances and add load when costs are low, and paired with energy efficiency improvements like insulation and low flow faucets, to at least keep the load on the system from growing during peak periods. Where control of appliances remains manual, rates must be simple enough for the customer to understand and act upon. Predictable load shifting is especially valuable to the system and can be compensated through incentives for demand response or some other form of rate credit, but establishing the right programs can be complex and time-consuming. Load shift product options are discussed in the Final Report of the CPUC’s Working Group on Load Shift.
It will also be critical to design rates that encourage beneficial electrification and do not punish customers who increase their consumption of renewable power at times when doing so actually reduces everyone else’s costs. But as this discussion indicates, doing so is more art than science, and care must be taken to ensure the low-income and other vulnerable populations that may not be able to afford building electrification are not disadvantaged in the process.