California’s grid is hindering its climate goals. Can a new law fix it?

Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems.

California may be one of the first states to face the risk of its power grid growing too slowly to support the surging adoption of electric vehicles, heat pumps and more — but it won’t be the last.

That’s why Colleen Quinn, co-administrator of the National EV Charging Initiative, is excited about SB 410, a new California law aimed at speeding up the state’s grid buildout. In fact, she’d like to see it serve as a model for other states across the country.

“We’re focused on state utility policy because utilities have the ability to either slow down or accelerate the growth of the market,” Quinn said. ​“We need to understand and deal with this big problem — the timing and the process that’s needed…to support the utilities and the industry.”

SB 410, written by state Senator Josh Becker (D) and signed into law by Governor Gavin Newsom (D) in October, takes a comprehensive approach to a complicated problem, she said. Simply put, California’s utilities aren’t expanding their power grids fast enough to meet the state’s decarbonization goals.

The lag in grid buildout is already leading to yearslong delays in energizing EV truck-charging depots across the state, Quinn noted. That’s a problem for trucking and freight companies trying to comply with California’s Advanced Clean Fleets rule, which sets deadlines for converting hundreds of thousands of diesel trucks to zero-emissions models over the next 12 years.

“They can’t get the power from the utilities fast enough,” she said.

The slow pace of charging infrastructure buildout is also a thorn in the side of local governments, workplaces and everyday homeowners trying to secure charging for smaller EVs — and the challenge will only increase. Right now, California has 1.5 million plug-in electric and hybrid vehicles on the road; that figure is expected to be 8 million by 2030.

Though it’s most acutely felt by EV owners who need charging equipment right now, the slow pace of grid expansion is a drag on electrification efforts beyond transportation. In fact, over the past year, utility Pacific Gas & Electric has failed to deliver timely grid hookups to hundreds of commercial and multifamily buildings due to a combination of misaligned grid planning, supply and workforce shortages, and the utility’s focus on burying and hardening power lines to forestall grid-sparked wildfires.

Eventually, grid constraints will threaten a whole host of other climate priorities as well, said Max Baumhefner, a senior attorney with the Natural Resources Defense Council climate and clean energy program. It could stymie the push to convert buildings from fossil-fueled furnaces and water heaters to heat pumps, as is increasingly required under state building codes and emissions standards. Grid constraints could also restrict the role of distributed solar and battery systems, which studies indicate are vital to augment the utility-scale renewable energy resources that face their own interconnection bottlenecks on the state’s high-voltage transmission grid.

“PG&E’s territory is bigger than the state of Florida,” Baumhefner said. ​“We can’t write off a territory that big” by failing to take action to unclog the backlog in grid interconnections and expansions ​“and still meet the state’s clean energy and climate goals. […] We have to get to work now.”

A comprehensive plan to solve a complex problem

The climate and economic harms posed by California’s sluggish grid buildout have united an unusually broad coalition. Among SB 410’s supporters are dozens of environmental groups, including the Natural Resources Defense Council, the Sierra Club and the Environmental Defense Fund. Labor unions, including the International Brotherhood of Electrical Workers and Coalition of California Utility Employees, are also on board, as are business groups including the California Chamber of Commerce and California Building Industry Association.

SB 410 gives the California Public Utilities Commission until September 2024 to set target timelines for utilities to connect and upgrade customers to the grid. It also orders the CPUC to include state and local government air quality, transportation and building electrification plans and workforce development needs in those plans — and to control the costs of those grid expansions even as it sets deadlines and penalties for utilities that fail to build fast enough.

Revamping the regulations that dictate how utilities plan for and expand distribution grids — the low-voltage networks that carry power from substations to customers — is far from simple, however. It’s particularly complicated when that buildout must happen in advance of the expected future influx of EV charging and electrification loads that will require the new capacity.

The first step is to refine forecasting of where new grid demand will show up, Baumhefner said. Utilities and state agencies have traditionally structured those forecasts on typical timelines for large construction projects like schools, shopping malls and residential subdivisions.

But that forecasting process hasn’t kept up with the state’s aggressive transportation and building-electrification goals — including the speed at which certain projects can move. Truck-charging depots can draw as much power as sports stadiums, he noted, ​“but unlike a sports stadium, which the utility sees coming years if not decades in advance, it only takes six months” to install dozens of high-voltage EV chargers in a parking lot.

But grid delays can’t be blamed entirely on slow utility planning and forecasting cycles, noted Marc Joseph, an attorney for the Coalition of California Utility Employees. The supply-chain disruptions of the past few years have lengthened the time it takes to secure critical grid gear like transformers from months to years, for example. What’s more, training and apprenticeship programs for utility lineworkers typically take four to five years to complete.

That’s why SB 410 orders the CPUC to ​“come up with realistic standards” for supply chains and workforce development, ​“and then require utilities to do annual reporting, and, if they’re falling behind, submit a plan for how to catch up.”

Finally, he said, there’s the matter of how utilities will pay for all the grid upgrades they’ll be asked to complete much faster than they’ve typically done. A recent study warned that California’s major utilities will likely need to invest from $30 billion to $50 billion by 2035 to expand their distribution grids to enable the state’s electrification goals, with EVs driving the majority of that demand.

That brings up what he described as ​“the only controversial thing in the whole bill — how do we help PG&E catch up?”

Why California’s largest utility needs to catch up on its grid buildout

The need for this catch-up stems from California’s utility regulatory structure, Joseph explained. Utilities recover the cost of grid upgrades by winning permission from regulators to pass those costs onto the bills of customers in the form of rate increases.

In California, those plans, known as general rate cases, come every three years, but their preparation begins years before they’re submitted.

PG&E’s current plans are based on data from back in 2019, before state agencies had fully grasped how EV mandates would cause a surge in electricity demand. In other words, ​“PG&E fell behind because they weren’t expecting it,” he said — which is a big part of why the utility is now months behind in providing basic electrical hookups for more than 300 already-built commercial and multifamily properties, according to data submitted to California lawmakers. 

California’s other major investor-owned utilities aren’t in quite as bad a situation, Baumhefner noted. In May, Southern California Edison, the state’s second-largest utility, filed its plans for a three-year rate case that includes extensive grid expansion and electrification targets based on more recent forecasts. Those plans were boosted by a state law passed last year, AB 2700, which explicitly orders the CPUC and utilities to build the latest EV growth forecasts into their grid expansion plans.

But AB 2700 does not grant PG&E any ​“catch-up mechanism” to alter the plans already set in place three years ago, he said. That’s why SB 410 orders the CPUC to create structures that will allow utilities to assess rate increases on customers outside today’s standard three-year rate-case cycles.

PG&E, which serves 5.6 million customer accounts and about 16 million people across Northern California, has other troubles as well. The utility filed for bankruptcy protection in January 2019, two months after one of its power lines failed in high winds and sparked a wildfire that killed 84 people and caused tens of billions of dollars in damages. It emerged from bankruptcy in 2020 still burdened by a portion of those liabilities, as well as heavy debt loads, and it has since focused much of its capital spending on a multibillion-dollar program of burying and hardening its grid to forestall future wildfires, reducing its capacity to connect new customers.

Matt Ventura, PG&E’s senior director of service planning and design, said in an email that SB 410 will ​“accelerate our strategy to improve service delivery to new-business customers.” The utility has improved performance on connecting customer on a timely basis by 25 percentage points so far in 2023 compared to last year and expects to energize 1,000 more new-business customers in 2023 compared to last year, he said. 

Public trust in PG&E remains low despite these wildfire prevention investments and changes in top corporate leadership. The utility triggered a new round of public outrage when it filed its new rate-case proposal last month, in which it asked the CPUC to approve a 26 percent rate hike. (CPUC has since rejected its request and instead approved a smaller rate hike of 11 percent.)

Given those dynamics, SB 410 specifically calls on the CPUC to ensure that any utility rate-increase requests are subject to ​“extremely strict accounting” to ensure any additional spending is limited to what’s needed to meet its distribution-grid capacity upgrade deadlines, Joseph said.

A grid expansion that pays for itself? 

Joseph and Baumhefner acknowledged the long-recognized problems inherent in allowing utilities to earn a guaranteed rate of return on additional grid spending that customers will be required to shoulder.

They also acknowledged the fact that grid investments made to help particular customers electrify their trucking fleets or build EV-charging depots could be seen as benefiting those customers directly, while socializing the costs across the entire utility customer base.

But Baumhefner pointed out that the grid investments that California needs cannot be compared to the so-called ​“gold-plating” utility grid-investment plans of past years, in which utilities proposed expensive grid upgrades that appeared to be well in excess of what was needed to ensure reliable service. ​“We don’t have to worry too much about gold-plating when utilities can’t even get a paper plate at this point,” he said.

What’s more, a growing body of evidence indicates that the higher rates customers will bear for grid upgrades to support EVs and building electrification will actually lead to lower rates over time, he said.

That seems counterintuitive, but as Baumhefner explained it, it’s relatively simple math. Grid investments are evenly spread across all utility ratepayer bills as a certain fraction of the cost of every kilowatt-hour of electricity each customer uses. But if those investments can allow more EVs to start charging and more buildings to switch from fossil gas to electric heating, that increases the total amount of electricity that utilities can sell to customers.

California is among the two dozen states that have ​“decoupled” electricity sales from utility revenue, meaning that the utility doesn’t make more money when it sells more electricity or less money when it sells less. Instead, utilities and regulators use formulas to determine the revenue they expect to collect from electricity sales, then adjust future rates upward or downward to mitigate overcollection or undercollection in previous rate cycles. That means that increasing electricity sales — exactly what grid upgrades would enable — tends to lead to lower rates over time.

As Natural Resources Defense Council senior scientist Mohit Chhabra described it in a 2020 blog post, it’s ​“akin to what happens when you spread the same amount of peanut butter over a larger slice of bread; there is less peanut butter in every bite,” with the peanut butter in this case being the per-customer cost of paying for grid upgrades.

That differentiates the cost of grid investments that encourage increased electricity sales from the grid costs that California customers are now bearing from utility wildfire prevention and hardening investments, Chhabra noted. While electrification-focused grid investments won’t completely reverse the cost increases from those wildfire-prevention grid investments, they will lead to lower bills by 2030 compared to a future in which they don’t happen, his analysis found.

“The reason I think you should give some credence to those forward-looking studies is that that’s what we’ve seen happening for the past decade,” Baumhefner added. A 2022 study by Synapse Energy Economics found that between 2012 and 2021, EV drivers in the territories of PG&E, Southern California Edison and San Diego Gas & Electric have ​“increased utility revenues more than they have increased utility costs, leading to downward pressure on electric rates” that helped all customers avoid higher rate hikes.

And this math doesn’t account for all the other benefits of speeding the shift from fossil-fueled to electric vehicles, he added. Those range from lower carbon emissions and healthier air to the money that EV owners can save by buying electricity that’s cheaper than gasoline.

“The timeframe over which we’re covering these costs from customers corresponds to the timeframe in which beneficial electrification brings in tens of billions of dollars that would otherwise have been going to international oil companies,” he said.

A model for solving a nationwide problem

California is on the cutting edge of the grid challenges posed by EVs, but it’s hardly alone. A growing body of evidence indicates that the traditional regulatory structures for utility grid plans and investments can’t keep up with EV mandates — let alone additional electrification goals.

Project-by-project grid expansions are unlikely to move fast enough to support the grid upgrades needed to accommodate EV charging demand, according to a May report from the nonprofit International Council on Clean Transportation. Instead, ​“investments must be made at scale and at strategic locations.”

Similar findings emerged from a 2022 report that focused on highway charging in areas served by utility National Grid in New York and Massachusetts, two states that have set a 2035 deadline for ending the sale of new gasoline-fueled passenger cars. The analysis found that many of the sites it studied will require proactive grid upgrades to handle megawatts’ worth of peak charging demand.

States that don’t give utilities some leeway to build out grids to support EV charging risk slowing EV adoption and missing out on the rate and climate benefits they can deliver. A May study from the Environmental Defense Fund found that allowing New York utilities to upgrade their grids for heavy-duty EV fleets could reduce overall utility customer bills compared to forcing fleet operators to take on the cost of grid upgrades themselves.

To date, California’s SB 410 represents the most forward-looking legislation aimed at solving the disconnect, said Colleen Quinn of the National EV Charging Initiative. It’s a logical next step for states that have already authorized utilities to spend hundreds of millions of dollars on ​“make-ready” investments that help prepare EV charging sites for faster grid interconnection.

Quinn also highlighted efforts aimed at supplying the data that utilities and regulators need to plan for proactive grid investments. Earlier this year, the nonprofit research group Electric Power Research Institute launched a program with utilities, major EV truck manufacturers, government agencies and regulators to map out hot spots of growing demand for EV charging, for example.

The next step ​“is to speed the energization of charging infrastructure — and that’s where SB 410 comes into play,” both for California itself and as a model for other states.

The National EV Charging Initiative is planning to introduce legislation modeled on SB 410 in states including Colorado, Illinois, New Jersey and New Mexico in the coming months, she said.

“We believe complementary policies enacted and active in the states are the only way we’re going to get steel in the ground and leverage the funding from Washington that’s going to be required to build out this network,” she said. The Biden administration has set a goal of having EVs make up half of all new car sales by 2030, and the Bipartisan Infrastructure Law and Inflation Reduction Act have directed billions of dollars at EV charging tax credits and grants.

But ​“it’s the states, not Congress, that regulate this sector,” she said. ​“Utilities don’t have the ability to invest in a timely manner.”