Getting the Rates Right for a Public EV Charging Build-Out

Demand charges can tank the economics of early-stage electric-vehicle charging rollouts. Replacements must balance support for EV growth with fair cost-sharing.

Cathy Zoi, CEO of EVgo, pays a lot of attention to the economics of public electric vehicle charging, both in terms of the widely varying upfront costs from location to location, and the long-term calculations that go into making sure their revenue exceeds their costs over their lifetime.

“We have a first-mover advantage, but we also have a first-learner advantage,” she said, with data collected from about 1,500 fast chargers across 800 locations to date. That’s allowed the decade-old EV charging provider to develop “proprietary utilization forecasting tools” aimed at ensuring that the early years of a fast-charging site, when relatively few EVs are on the roads to use it, can eventually be made up by the end of its life as EVs proliferate in its region. “That’s some of our secret sauce.”

But this long-range payoff is threatened by the utility rates known as demand charges, which assess fees based on a customer’s peak electricity draw at any moment during a monthly billing cycle. For charging sites dominated by relatively rare, yet very power-intensive, bouts of fast charging, demand charges can add up to 90 percent of total electricity costs, leaving many sites deeply in the red.

That’s why “we really need to address rate structures,” said David Nanus, EVgo chairman and co-head of private equity for EVgo owner LS Power. “We’re really in the early innings of the game in terms of EV adoption,” and until the volume of EVs on the road rises, “that demand charge has to be amortized over a lower number of charging sessions.”

Back in 2017, EVgo and the nonprofit research group Rocky Mountain Institute studied the demand-charge problem across 230 charging sites in California. The results indicated “how it was killing the business case for [direct-current] fast chargers,” said Chris Nelder, RMI’s carbon-free mobility practice manager.

“Now it’s a commonly understood problem,” he said, and not just for public charging providers like EVgo and Electrify America but also for the government agencies, transit authorities and corporate fleet owners seeking to convert to EVs.

A balancing act for EV charging and demand charges

That’s why states with decarbonization goals are increasingly pushing regulators and utilities to come up with alternatives to demand charges for the direct-current fast-charging networks seen as a prerequisite for mass-market EV adoption.

“There are different takes around the country about what demand-charge reform looks like, from an indefinite holiday from demand charges, to a five-year holiday, to more complicated ways to optimize utilization with pricing that’s reflective of grid conditions,” said Amanda Myers, senior policy analyst with the nonpartisan policy firm Energy Innovation.

But the attempts to solve the problem, starting with California’s big investor-owned utilities and spreading to other utilities in other states, haven’t always hit the right balance, RMI’s Nelder said. For example, Southern California Edison’s 2017 decision to offer a “demand-charge holiday” for large-scale EV charging sites will relieve the burden through 2024, and then slowly ramp up those charges to their conventional rate over the next five years.

That’s not an ideal solution, however, because “all chargers are not going to experience the same demand growth over time,” he said. “If you want to have a really functional network, you have to have some chargers that are located in remote areas where they’re not going to get used eight hours a day.” Delaying demand charges for those sites could simply postpone the low-utilization demand-charge trap facing most chargers today.

Northern California utility Pacific Gas & Electric’s solution is even harder for EV charging owners and operators to plan around, he said. It’s built on a subscription rate that asks EV charging operators to predict how much electricity they’ll use per month. While it assesses no demand charges for use up to that amount, it does impose overage fees when they exceed it.

Other workarounds, like New York’s decision to offer upfront rebates to EV charging installations to offset the demand charges they’ll face, fail to engage in matching utilization rates with cost structures, he noted.

In light of these unpredictable cost structures, the EV charging industry “tends to want to see a full holiday” from demand charges, Energy Innovation’s Myers said. But “folks that look at the nexus between high electrification and how [to] keep emissions low and the grid build-out in check want to see a more sophisticated optimization of encouraging increased utilization.”

That’s because demand charges are designed to recover the costs of building and maintaining the grid infrastructure to serve peak loads. “These rates were designed for factories or office buildings, not for these charging stations that happen to spike to 250 kilowatts maybe once or twice a month,” Nelder said. Before smart meters and other technologies were available to track individual loads’ contributions to overall grid stresses, that was a reasonable approach to assessing a customers’ share of covering the “fixed costs” of utility transmission and distribution networks.

Densely packed EV charging in parking lots in shopping centers or highway rest stops, or at public and corporate vehicle depots, may require significant grid upgrades, and can be expected to put stress on circuits and transformers that will increase maintenance costs. Rate structures that don’t find a way to account for that may end up shifting excessive costs onto utility ratepayers.

That means that a successful solution to the demand-charge problem needs to take individual charging stations’ utilization rates into account, Myers said. It also needs to balance costs borne by utilities with costs borne by EV charging owners and operators if it’s to gain support from both sides.

A sliding-scale rate to balance consumption and demand

That’s where RMI hopes its new rate design may help. In 2019, Nelder’s team released a study detailing a proposed replacement rate for Xcel Energy in Colorado. The fundamental challenge is to come up with a rate that doesn’t undercut direct-current fast-charger economics in the early years but also doesn’t leave the utility, and by extension utility ratepayers, shouldering extra costs.

RMI’s rate does that by using a sliding-scale approach, with “volumetric charges starting high and demand charges starting low” to account for the early days of low utilization, Nelder explained. As more and more vehicles start using the chargers, those volumetric charges — that is, the prices per kilowatt-hour for the energy consumed — start dropping, while the demand charges — that is, the prices based on raw peak kilowatts of usage being borne by the connecting utility infrastructure — scale up.

Early bus electrification efforts ran squarely into the demand-charge problem under Xcel’s previous rate regime, which was replaced with a new rate structure approved by the Colorado Public Utilities Commission last year. RMI’s proposed rate includes the same fixed charges and time-of-use structures to encourage off-peak charging and discourage on-peak charging. It’s also designed to “recover the exact amount that Xcel would have recovered from their own rate” but “without killing the early business case for fast chargers.”

Xcel’s Minnesota utility has proposed a somewhat similar sliding-rate design, albeit with a far more complicated approach that involves dividing the maximum actual demand by a percentage of power factor, and then setting minimum and maximum ranges for the demand charges that will be assessed.

Connecticut’s Public Utilities Regulatory Authority has included RMI’s rate design concept in early-stage direction to the state’s utilities as part of a broader grid modernization docket, although it’s unclear if the state’s utilities will take it up, Nelder said. Tracking utilization and shifting rate structures on a charger-by-charger basis does require more advanced data collection and billing methodologies.

The growth of EVs will create major new markets for the electricity utilities sell, as well as supporting a big capital build-out for the grid infrastructure needed to support that charging, Zoi said. That gives utilities an incentive to consider ways to bridge the rate-design divide that could stymie early-stage charging build-out.

“The utilities have a sincere interest in the growth of electrified transportation,” she said. “They’re looking inward to see if their rate structures are incentivizing this or disincentivizing this.”

Source : greentechmedia