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 first 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 first post we cover the fundamentals of rate design, laying the groundwork for parts two (October) and three (November). Those installments will consider potential rate design changes to improve customer decarbonization economics, the corresponding key tradeoffs, and equity implications.
Those unfamiliar with the utility ratemaking process may hear the term “rate design” and look for someone else to talk to. In the simplest terms, rate design sets the actual retail prices for the products (e.g., electricity) and services (e.g., distribution line maintenance) that a utility provides to its customers. Although one can summarize the steps to design rates in a few bullets, the process for actually establishing and adopting them is much more complicated and involves many parties. While most states in the U.S. follow the same general process in regulating their investor-owned utilities (IOUs), I will focus here on the specifics for the California (CA) IOUs, as practiced by the California Public Utilities Commission (CPUC).
What are the steps in rate design?
As a regulated entity, an electric utility must receive approval from its state PUC for the prices it charges to consumers. This is a complex process that includes several distinct parts. The first step is for the PUC to establish the utility’s “revenue requirement,” or the total amount of money the utility is allowed to collect from its customers. This must cover expenditures related to all of the utility’s activities, including investment in plant and equipment, operations and maintenance expenses, annual fuel and purchased power cost adjustments (the “ERRA” in CA) and demand-side programs such as Energy Efficiency, Demand Response, Transportation Electrification, and others. For most of the utility’s operations, the revenue requirement is determined in what CA calls “Phase 1” of a General Rate Case (GRC) proceeding, which each company currently files with the CPUC every three years. Today, a major utility’s GRC typically takes a year and a half or more to resolve. For instance, Phase 1 of PG&E’s rate case for 2020 was filed in December 2018 and a decision is not expected until the spring of 2020 at the earliest. Delays are frequent and sometimes lengthy.
The second step in the ratemaking process is called “cost allocation,” and occurs in “Phase 2” of a GRC in CA. It takes the authorized revenue requirement and divides it among the various customer classes that the utility serves – typically residential, small commercial, large commercial, industrial, agricultural and perhaps others. This process is often hotly disputed among intervening parties, because it determines how various cost categories – generation, transmission, distribution, etc. – will be spread among the different customer classes. In recent years cost allocation, although controversial, has often been settled by the parties, including the utility, the CPUC’s Public Advocates Office, and the representatives of the various classes. Cost allocation is generally not considered again outside of Phase 2 GRCs, although there may be exceptions to that general rule.
Rate design is the third step in the ratemaking process and is also addressed in Phase 2 GRCs every three years. It determines the specific types and levels of the charges that will apply to the customers in each class. In addition, each utility can file a “Rate Design Window” application in the years between Phase 2 GRCs, but these are usually limited to a few specific topics, such as the potential offering of a new rate option for a particular customer class, to allow for speedier resolution. The CPUC can also open an investigatory or rulemaking proceeding on its own initiative to address particular rate design issues on a statewide basis. For instance, CA has had a residential rate reform proceeding open for a number of years (R.12-06-013).
The essence of “rate design” is to establish a set of prices that will recover the costs allocated to each customer class over the course of the year. That will often involve the establishment of a “default” tariff for each customer class, as well as one or more optional rate schedules for customers that desire an alternative structure (e.g., an electric vehicle rate option for residential customers). The proportion of the class’s revenue requirement to be recovered from each optional rate schedule is usually a topic of intense negotiations among the parties.
For over 30 years, CA has followed a policy called “decoupling,” which tracks the amount of revenue actually paid by customers and compares that to the utility’s authorized revenue requirement, with any shortfall or excess recovered in rates the following year. This policy was designed to remove the incentive the utility would otherwise have to increases sales and discourage conservation and energy efficiency during the rate period, rendering the company indifferent to the amount of electricity that customers actually consume, at least in the near term.
How many parts does it take to make a whole rate?
The actual prices included in the utility’s rate schedules (tariffs) typically consist of a few basic components. The energy charge is the simplest to understand—it is simply a cost per kilowatt-hour (kWh) of energy consumed over the billing period, and is sometimes called a “volumetric” rate. For residential customers in CA, almost all of the utilities costs are recovered through volumetric charges– including generation, transmission, distribution, and other miscellaneous costs such as public purpose programs. The generation portion of the volumetric charge is the primary one that Community Choice Aggregators (CCAs) in CA can set for their own customers.
There may also be other types of charges. Many utilities, including some in CA, assess a fixed monthly fee, often referred to as a “customer charge,” for each customer in a given customer class. These charges are designed to recover certain costs that are specific to each customer, such as the meter and the service line to the building, as well as revenue cycle services such as billing, that do not vary with the quantity of energy consumed. In some cases, rather than allowing a fixed customer charge, which can be controversial because it reduces the volumetric charge, the PUC adopts a Minimum Bill, which assures that every customer will pay at least some minimum amount to cover the utility’s fixed costs, but does not reduce the volumetric charge nearly as much as a customer charge that applies to everyone.
Demand charges are an important component of the rate structure for more sophisticated customers, like industrial and larger commercial users. These charges are assessed on the maximum amount of power in kilowatts (kW) that a customer draws from the grid over a brief period of time, often fifteen minutes. The basis for these charges is that portions of the grid must be sized to meet these maximum demands. Demand charges can be coincident, meaning that they are based on the individual customer’s demand at the time of the peak demand over the entire grid, or noncoincident, based solely on the individual customers’ maximum demand. Most utilities in the U.S. do not apply demand charges to residential customers, and recover the associated costs in volumetric rates instead. The application of demand charges can be controversial, and they are not currently applied to residential and small business customers in CA, although a CCA could theoretically recover some of its generation costs through a demand charge if it so chose.
What types of rate structures exist for residential customers in California?
Historically most utilities in CA and across the country employed only a flat energy charge per kWh, with no differentiation by time of use, because traditional meters only registered the cumulative amount of usage flowing through the device. Prior to the rapid escalation of energy costs in the 1970’s, many utilities even established “declining block rates” that charged less per kWh as customers used more electricity. These “promotional” rates were designed to encourage more consumption at a time when utilities often faced a declining average cost curve. These were eliminated in CA by the 1970’s as energy conservation became a matter of pressing public concern.
In the mid-1970’s CA adopted a baseline or “tiered” rate structure that charged residential customers more per unit of consumption at increased levels of usage. The first tier covered a “baseline” quantity of usage that was considered necessary to meet minimum essential human needs, and a higher per-kWh rate applied to usage beyond that level. A later legislative enactment essentially gave up on the effort to define minimum essential needs and substituted a formula that set the baseline allowance as a percentage of average use in each climate zone. There are separate and larger baseline allowances for customers with electric space heating, and for those with certain identified medical needs (Medical Baseline). The number of “tiers” in the residential rate structure varied over the years, from as few as two to as many as five.
While each customer class has a default rate schedule that applies to any customer who does not choose otherwise, CA has long offered optional rate structures that customers could select if they so desire. Time-of-Use (TOU) rates, which vary by time of day and season, have been available to residential customers for many years, but few have opted for these alternative rates. In order to promote customer understanding, such rates have typically included only two (peak and off-peak) or three (including a mid-peak) different rate levels. CA determined that residential customers would be transitioned to a default TOU rate structure by 2019, but that transition has been postponed to the fall of 2020 for PG&E and SCE. The initial default residential TOU rate structure will contain “mild” rate differentials between the various time periods to avoid adverse customer bill impacts, but the CPUC also provided for alternative rate options with larger time-based rate differentials.
A critical element of any TOU rate structure is the definition of the various time periods for pricing. Traditionally TOU rates defined the peak period as summer weekday afternoons, often from noon to 6 pm. With the dramatic increase in solar power in CA, generation now tends to be more abundant during the middle of the day, and the grid is most stressed around sunset, when solar output drops off dramatically. Recent changes to the TOU period definitions now provide for a peak period from 4 or 5 pm until 8 or 9 pm.
Today, the imperative to reduce GHG emissions has changed the equation from focusing primarily on conservation and efficiency to shifting electricity demand to times of high renewable generation. Increasing electricity demand through transportation and building electrification is now encouraged, as it can result in the substitution of increasingly clean electricity for more carbon-intensive gasoline, diesel fuel, and fossil natural gas. Indeed, the PUC had these changes in mind when it approved the shift from tiered residential electric rates to default TOU.
At the same time, default TOU could lead to higher bills for small users who previously benefited from the steeply-tiered residential rate structure or for rooftop solar customers whose daytime generation may be devalued and evening consumption penalized. These customer groups will undoubtedly complain loudly if they perceive the default TOU rate structure as disadvantageous for them. Therefore, the need for balance and compromise, long a staple of rate design conversations, will continue.
Real-Time Pricing (RTP) is a “dynamic” rate design in which the generation charge (and potentially other rate components) varies with conditions on the grid in hourly or even smaller increments. It is often considered to be the ideal rate design by economists, because the retail price to the consumer is directly linked to prices in the wholesale market. While RTP has been discussed in CA for years, only a very limited number of such optional tariffs are currently available from the IOUs. A CCA could potentially offer an RTP-based generation rate to its customers, but there are currently challenges stemming from the practice of consolidated billing, in which the utility bills the customer on behalf of the CCA. (Some of these challenges are discussed in the recent Virtual Power Plant Options Analysis from Silicon Valley Clean Energy and Gridworks). RTP is one of many topics that can be discussed in a Phase 2 GRC, but the CPUC recently rejected an effort to take up the issue outside of its established rate design proceedings.
Advocates for building and/or transportation electrification will often prefer RTP or TOU-based rate designs that do not contain any sort of premium for higher monthly usage, yet such a premium was a hallmark of the longstanding tiered residential rate structure designed to protect small users and promote energy conservation and efficiency. If changes are not pursued thoughtfully and carefully, conflicts could arise with the traditional parties who have participated in residential rate design conversations for many years, with a focus on low-income and other small users. These options and their corresponding trade-offs will be the subject of our next blog in October.