By Matt Gamache, Vice President, Analytics & Operations
To reduce greenhouse gas emissions and take advantage of an increasingly renewable electricity grid, our energy systems must begin electrifying fossil fuel-based sources of emissions, such as replacing fossil fuel heating with heat pumps and shifting the transportation sector towards electric vehicles. This transition is referred to as beneficial electrification. Driven by new incentives and falling technology costs, the beneficial electrification trend is gaining momentum and as a result, our electricity grid will need to adapt. Demand for more and more renewable electricity will require continued investment not only in new renewable generation, but also expanded transmission and distribution infrastructure to deliver this electricity to consumers.
Many of the costs associated with these grid upgrades will be collected through the rates charged to use electricity and the way in which these costs are collected will have major implications for consumers. Rate design and implementation will determine how much it will cost to adopt or use a new technology. In this way, the implications of utility rate design decisions could be significant in accelerating or hindering progress towards beneficial electrification and other energy policy goals.
Policymakers and regulators are recognizing this fact. In Maine, for example, during the 2021 legislative session, the Maine Legislature enacted several laws that required the Maine Public Utilities Commission (the “PUC”) to examine whether Maine electric utilities’ rate designs support policies related to the state’s decarbonization efforts. The results of these proceedings are beginning to be seen in recent rate changes being implemented by Central Maine Power, Maine’s largest utility (“CMP”). They include changes to how stranded costs are collected, a new “coincident peak tariff” that changes how transmission costs are assessed, and upcoming changes to distribution rates. In all three cases, the approach to rate design considers the impact on beneficial electrification and will significantly alter the way many Mainers pay for their electricity.
STRANDED COSTS
Stranded costs for utilities typically represent costs associated with the restructuring of electricity markets. When electricity markets were restructured to allow ratepayers to purchase generation services from third-party suppliers in the competitive market, utilities were left with costs associated with generation services that are eligible to be recovered through stranded cost rates. For some utilities, these may be referred to as transition charges.
Recently, in Maine, these stranded costs have been determined to also include costs associated with Maine’s Net Energy Billing (“NEB”) program. The NEB program requires utilities to credit qualified NEB projects at a specified retail rate. While the utilities receive the wholesale market value of electricity generated by NEB projects, partially offsetting the cost of issuing the credits, the net cost incurred by the utilities is recovered from ratepayers. With the recent growth in Maine’s NEB program, the associated stranded costs have grown as well.
Historically, stranded costs have been recovered through a combination of Demand (per kilowatt or “kW”) and Energy (per kilowatt-hour or “kWh”) charges, with the majority recovered through kWh charges. However, this rate design was revised through a recent PUC proceeding which shifted CMP’s collection of NEB-related costs to a fixed, monthly customer charge. The PUC’s reasoning was based on ensuring all customers pay a fair share of the NEB program costs while also promoting beneficial electrification. The NEB program is part of Maine’s overall climate policy, by creating a strong incentive for the development of distributed, renewable generation. Maine’s climate policy also calls for beneficial electrification, most specifically through heat pump and EV adoption. Assessing NEB program costs through a per kWh charge would have provided a disincentive to electrification, by making each additional kWh consumed by a heat pump or EV that much more expensive. Instead, by collecting these program costs through a fixed monthly charge, an individual customer’s electricity consumption will not increase or decrease their share of NEB program costs.
COINCIDENT PEAK TARIFF
A more direct outcome of the PUC’s investigation into rate design to support the state’s climate policies is a new, voluntary transmission tariff available to Medium, Intermediate, and Large customers. Transmission charges fund maintenance and upgrades to both the regional and local electricity transmission system. This new tariff revises the way in which transmission-based charges are assessed to customers, by implementing a “coincident peak” charge.
Currently, CMP customers are charged for transmission costs based on their individual account’s peak kW demand (as measured on 15-minute intervals) during a monthly billing period. This is referred to as a “non-coincident peak” charge. The new tariff would measure a customer’s peak kW demand during the hour that CMP’s grid reaches its peak demand during that month and use that kW reading to assess transmission charges. Importantly, the tariff also applies a higher rate per kW of demand so that CMP can still collect adequate transmission revenues.
By electing to take advantage of this new tariff option, customers could see a greater financial benefit from avoiding electricity consumption during high demand periods or deploying load shifting technologies like battery storage. The ability to meet peak demand will drive future capital investment in the grid and by aligning customer costs with their use during these periods, this rate will send a better price signal to consumers. It also makes increased electricity demand outside of these periods less costly, and therefore incentivizes increased electrification. When a larger user installs new EV charging stations or adopts heat pumps, they will be able to increase demand for electricity during most hours of the month without impacting their overall transmission costs. Perhaps more importantly, this increased value placed on a single hour each month creates a stronger value proposition for battery storage adoption. Increased battery storage capacity will also be key in enabling the type of electricity load shifting that can help mitigate the costs of expanding the electricity grid.
DISTRIBUTION RATE CASE
After more than a year-long process, a stipulation was approved by the Maine PUC this past June in CMP’s request for a rate change. The case was primarily focused on distribution costs, which fund the networks of electricity distribution infrastructure in CMP territory. While CMP will be increasing distribution revenues incrementally every six months over the next two years, there were some other aspects of this case that represent a shift in distribution rate design.
First, in an effort to better align distribution costs with the hours that are most costly, CMP expects to shift “On-Peak” hours from the current period of 7:00 a.m. to 12:00 p.m. and 4:00 p.m. to 8:00 p.m. on weekdays, to only the 5:00 p.m. to 9:00 p.m. hours on weekdays. All other hours would be treated as “Off-Peak” hours. This not only narrows the window in which CMP assesses its most costly charges, but it also better aligns that window with periods in which the grid is most stressed. As solar adoption has proliferated throughout CMP territory, peak electricity loads are shifting later in the day, when the sun sets, and solar generation drops off. Charging more for the 5:00 p.m. to 9:00 p.m. hours will send a better price signal to consumers and conversely encourages more electricity consumption in other hours, when there is excess capacity on existing distribution and transmission infrastructure.
In addition, CMP will be making investments in metering and billing that will allow customers to better understand rate implications and manage their grid demand accordingly. These investments will be critical so that these rate design tools can be employed more effectively in the future, helping to mitigate costly investments in the grid and maximize economic efficiency.
Finally, as an outcome to the rate case, there will be a follow-on proceeding to examine rate design for residential customers that will be focused on incentivizing use of heat pumps in the winter and disincentivizing electricity consumption during the highest demand periods in the summer. These changes will be critical in keeping electricity affordable and not slowing down heat pump adoption. At the same time, more dynamic pricing is needed to provide a disincentive for every customer to charge their EV during high demand periods and trigger the need for even more costly investments in distribution and transmission systems.
CONCLUSION
While the aspects of rate design discussed above are specific to CMP, we are seeing similar trends play out across the country, as other regions adapt to increased electrification and pursue policy goals. Pacific Gas & Electric in California has implemented dynamic time-of-use pricing to adapt to an increasingly renewable grid, incentivize battery storage and send better price signals to customers. Eversource has expanded a coincident peak tariff design in Massachusetts that has complemented state policy goals related to battery storage and beneficial electrification.
While utility ratemaking is often a topic that is primarily of interest to energy nerds (like those of us at Competitive Energy Services), as the economy electrifies and new rate designs become widespread, consumers will need to understand the implications. Rate design will be a critical tool in ensuring that the electricity grid can expand, and rapidly transition to integrate new technologies while also remaining affordable. CES is always monitoring, and often participating in, rate proceedings on behalf of our clients, and we are always eager to help organizations understand and respond to changes in order to achieve their energy goals.
Photo by Karsten Wurth