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Sourced from American Public Power Association, March 10, 2021 Author: Susan Partain
Setting electricity rates is an increasingly complex exercise. For public power utilities, the process is a careful balance in ensuring adequate cost recovery, fair cost allocation between customer classes, affordability, local business growth, and support of community objectives.
“For the past 100 years, we never really had the metering technology to charge customers appropriately,” said Mark Beauchamp, president of Utility Financial Solutions, a consulting group. “What we did was pull together customers with common usage patterns into classes.”
“What’s happened in the past 10 years is that usage patterns started to vary a lot between customers within the same class,” he explained. For example, he noted, some residential customers have taken advantage of energy efficiency programs while others have installed solar panels or purchased electric vehicles.
“Some customers were starting to subsidize other customers because our rate designs were not fine enough to be able to properly recover our costs.”
Beauchamp laid out a few common scenarios for how some rates might lead to some customer segments subsidizing others. These include not setting a proper customer charge for seasonal customers as compared to year-round customers, not having different customer charges for single-phase and three-phase customers, or not having the right customer charge for customers with solar panels.
With more advanced metering technology, Beauchamp sees potential for the industry to shift to more dynamic pricing that he said will allow for proper cost recovery.
He ranked coincident peak demand rates, which look at how much electricity a customer uses at the system peak, as the most accurate form of dynamic pricing. Beauchamp praised public power for being on the forefront of instituting some of the more advanced pricing structures, including coincident peak demand rates.
When Traverse City Light and Power in Michigan did a thorough cost-of-service study in 2017, it identified three key problems to solve: Some commercial customers were paying more than their fair share of costs, there were too many different offerings, and many of the utility’s fixed costs were reliant on being recovered through a variable charge.
Instead of addressing each issue at once, TCLP set up a plan to prioritize and spread out the changes to have the least impact on its customers, said Karla Myers-Beman, controller for TCLP.
The first year after the study, TCLP made some revenue-neutral changes to provide relief to the commercial customers that were paying more than they should have been. Commercial customers saw rates decrease by about 1.5% and residential customers saw a small increase.
Then, the utility moved to simplify its offerings for its 12,000 customers. The public power utility had 19 rates, and some plans only had one or a handful of customers in them. Simplifying the rates included phasing out separate water- and space-heating rates, which had been established in the 1970s, by matching them with the regular electric rates for each customer class.
Myers-Beman said the plan is to continue to make incremental increases over the next several years to get the utility to where it should be to properly recoup fixed costs.
Even with small changes, TCLP wanted to be sure customers were aware of and prepared for any changes.
“With the customer not having a large impact to their bill, there’s not a lot of commentary back from the ratepayers,” said Myers-Beman. She added that for the rate classes that TCLP eliminated, in which only a few customers participated, the utility “did forewarn them that we were looking at closing the rate, [explained] why we were closing the rate, and then we provided financial forecasts of the rate class they were going in so they could be prepared, budget-wise, for the impact of moving to that rate.”
Myers-Beman acknowledged that for more sweeping changes, such as shifting to a time-of-use rate, there is an educational hurdle in helping customers understand the rate and how they might be able to control use so as not to experience “rate shock.”
While the utility originally presented the changes as a five-year plan, Myers-Beman noted that the schedule can change based on an annual rate analysis. TCLP had planned to increase rates by 2.5% in 2020, but it deferred the change given the financial hardships customers were facing because of the pandemic. Being able to shoulder the deferral meant the TCLP team had to determine how to reduce fixed and operational costs, which account for about 30% of the utility’s expenses.
“It is really important to have a guide to follow,” she said. “We have it on our website so customers can go in and see what the five-year rate plan is for their rate class, but it also provides guidance to the board and staff to move forward with the budgeting process.”
Jason Grey, director of utilities for Danville Utilities in Virginia, noted that the utility is in the midst of “aggressively updating to new technology,” including several multimillion-dollar upgrades to substations. Danville Utilities replaced and updated infrastructure at two facilities in 2020 and plans to update four additional facilities in 2021.
Grey and Danville Utilities consulted with Beauchamp and UFS for the most recent cost-of-service study, and Grey noted that future projections of sticking with the current rate showed where adjustments might be necessary.
“We realized that if we kept the same rate structure, we could potentially fall below our adopted financial policies,” said Grey. Those policies include maintaining a certain debt coverage ratio and other financial health indicators.
With a new power contract for lower-cost energy in place, the utility was able to reduce a power cost adjustment charge that got passed on to customers. The changes will allow for the utility to recover more of its fixed costs through increased customer charges while providing customers with a net savings on their monthly bills. Grey shared some projections that showed between 3.5% and 7.9% savings for average customer use across each rate class, including a 4.8% projected reduction for residential customers who use 1,000 kilowatt-hours per month.
“We’re able to take care of all of our needs,” said Grey. “We also want to be able to have competitive rates with our neighbor co-ops and IOUs, and [we] need to be a financially sound utility, maintain a good bond rating, and meet all our financial policies.”
The utility commission approved the changes in January 2021, and the city council will review the change in March. The last step is for the utility to hold two public hearings on the changes later in the spring. Danville has not made changes affecting every rate class since 2015, said Grey. Assuming there are no challenges to the changes, the new rates will go into effect in summer 2021.
“We are giving back as much as possible,” said Grey. “The commission feels that we can and remain financially sound with our ratings agency and bond agency.”
In Coldwater, Michigan, a rapidly growing community in the southern part of the state, change started from the top.
Jeff Budd, utilities director at the Coldwater Board of Public Utilities, estimated that about half of the utility’s current load was added within the past 10 years, including from a new large industrial customer that set up in the area in the past few years.
Coldwater decided to dip its toe into the TOU waters by providing the rate option for its three largest industrial customers.
“We wanted to give them the opportunity to have some say in their power usage,” said Budd. “The intent was to provide them some rate relief due to their sheer volume and provide them some incentives to shift some of their load to off-peak.”
Budd pointed to the municipal ownership of the BPU in allowing for the conversations about rates and energy usage to be mutually beneficial. “They were happy to feel that we as a municipal electric were working with them. We don’t have the profit motive, so we tried to really dig into how they are impacting our costs and what they can do to contain them, but also, if they could help us to contain some of our costs, how could they get the benefit of that — whether that’s in peak reduction or moving some of their larger electric usage to off-peak.”
Budd said the previous design offered little enticement for the customers to move load to off-peak hours and was not reflective of the true cost to the system.
Coldwater began offering the TOU rate to the customers in October 2020, and two of the three had moved over to the rate by January 2021. Although it is still early in the offering, Budd said that the customers have already started to see some savings from the change.
“We’ve got to make sure that we’re providing them an equitable and fair rate so they can expand their business and compete in the global markets,” said Budd.
He stressed that the change was an educational effort and discussion that went beyond just costs. “They are becoming more aware of what they can do to reduce their demand and how the electric markets actually work and how to avoid transmission peaks,” he said.
“If they can shave some of their peak, they save money, but we also save money,” he said. “The goal was to try not to have them subsidize any of the other rate classes. Now, they are a little more engaged as to how they continue to watch their peak demand.”
“Over the course of the next five years, if you want to stay in the electric industry business and be effective at it, you need to put in [advanced metering infrastructure],” said Beauchamp. “Dynamic pricing is going to become common … and there will be rate options for customers. There has to be a plan for utilities to move their rates from where they are today to these dynamic pricing schedules.”
Beauchamp recommends that utilities take a gradual, phased approach, possibly over five to 10 years, toward instituting mandatory or opt-out dynamic rates to avoid creating backlash.
Both Danville Utilities and Coldwater BPU, which have worked with Beauchamp and UFS, are looking to take such an approach.
Danville plans to phase in a residential TOU rate over the next six years, by first introducing the concept of different peak periods and gradually adjusting the on-peak and off-peak rates to have more differentiation, along with its biannual cost-of-service study. Grey said this approach will help customers “get acclimated” to the concept of TOU rates, and that the timeline aligns with an expected increase in EVs on the market.
“Our customers are becoming more educated on their habits and [our] pricing structures,” said Grey. “Customers should be fully aware of what TOU is and what the benefits are and [how they] can fully maximize the value of TOU,” said Grey.
“For us it is about fairness and making sure that the other rate classes aren’t subsidizing one or the other,” said Budd. “We ultimately feel that everyone should be on a TOU rate when you talk about fairness,” he added, noting that the utility needs to complete a shift to AMI before it can roll out a TOU rate. As of February 2021, about 80% of the utility’s customers have AMI, and Budd expects the deployment to be completed by June 2021.
TCLP’s board reviewed a proposal for piloting a TOU rate in February 2021. If the pilot is approved, Myers-Beman said that she will be interested to see how much the price signals change customer behavior.
Rate changes aren’t just about cost recovery, noted Budd, but about getting people to shift their behavior in a way that will help net energy savings and reduce network outages. “The only way people will change their habits is if there’s a financial consideration that goes with that.”
Beauchamp noted that rate design is meant to support community objectives and that communities need to be able to understand how any change will support or undermine such objectives.
For example, he cautioned that inclining block rates can harm some customers with lower incomes who have higher energy needs, and that demand charges can be punitive for commercial EV charging stations with a low load factor.
The important factor is that any rate structure or change is intentional in how it supports the utility’s unique objectives and community, said Beauchamp, and that any decisions on changing rates are made with an informed picture of how certain customers might be affected.
“The biggest thing that concerns me,” he said, “is if the governing body makes a decision without being properly informed as to the cost of the consequence.”