A new way to fix grid bottlenecks for EV charging: flexible connection

At a Tesla high-speed EV charging site in California’s Central Valley, utility Pacific Gas & Electric has switched on a pilot project that could mark a major advance in getting big customers connected to stressed-out power grids. It’s called Flex Connect, and it’s based on a simple concept — let customers control how much power they use so that they don’t exceed what the grid can safely deliver from hour to hour.

Actually making this happen in the real world is far from simple, said Alex Portilla, PG&E’s director of grid edge innovation. In fact, it’s taken the utility and technology partners Schneider Electric and Microsoft more than a year to set up the system that makes it possible and for PG&E to find the right customers.

But after months of testing, the first two Flex Connect pilot projects — the Tesla charging site and an undisclosed grid-connected battery system — were turned on in late October. So far, things are looking good, with both sites showing that they’re reliably responsive to utility commands and can keep their grid demands in check when needed, Portilla told Canary Media in a November interview.

Several other customers are participating in the Flex Connect pilot, Portilla said, including some Tesla Supercharger sites and a PepsiCo manufacturing facility in the Central California city of Fresno that’s deploying 50 Tesla electric semitrucks over the next six months. PG&E hopes to get many more customers to sign up next year.

“We need to build a track record” to prove that the program creates value for customers and reliably supports the grid, he said. But PG&E’s eventual goal is for Flex Connect to be ​“a standard offering” for anybody looking to hook their site up to the grid.

If widely adopted, the program could help unblock major bottlenecks for EV charging and other heavy electricity users on grids across the country. But it’s particularly important in California, where aggressive goals to get more EVs on the road are running up against a grid that isn’t ready to support the charging they’ll need.

Today, many big EV charging depots in the state are facing years-long wait times to get the utility grid upgrades necessary to operate at full capacity. ​“We can’t build the grid fast enough based on historical grid planning paradigms, which are based on planning for a peak,” Portilla said.

Portilla was referring to the standard utility practice of building out grid infrastructure that is robust enough to respond to a worst-case scenario at any given moment throughout the year. But in California, grid stress is at its highest usually only during a handful of hours on the hottest summer afternoons and evenings, when lots of customers are cranking up air conditioning.

Letting a bunch of chargers pull grid power at their maximum capacity at those periods of time could overload local grid substations. That’s why under normal circumstances, PG&E would tell a charging developer that they can’t connect to the grid at all until it has been upgraded to be able to serve them at their peak loads.

“There’s a lot of conservatism built into that approach,” Portilla said. ​“You’re building a system that can operate at 100 percent capacity, 24/7/365.”

But if PG&E was sure that its EV charging customer could be relied on to not use some of its chargers at those peak times — or, perhaps, supply its own power from on-site solar panels, batteries, or generators to make up the difference — the utility could allow the site to hook up to the grid and start accessing that power years in advance, he said. That’s what PG&E is aiming to achieve with Flex Connect, but first it must prove through the pilot tests that the concept can work in the real world.

Why flexible interconnection is so difficult to carry out

To be clear, this isn’t how most customers, who are accustomed to using energy without any restrictions, would choose to get their power, Portilla said. ​“They’d love to connect their full load tomorrow.”

That’s why PG&E and fellow major utility Southern California Edison have launched their flexible interconnection pilot projects as a ​“bridging solution” for the growing backlog of EV charging sites that their grids can’t yet accommodate.

PG&E and SCE laid out the difficulties of implementing flexible interconnection in a May workshop hosted by the California Public Utilities Commission. The first challenge is finding customers willing to take on the cost and complexity of limiting how much power they use during certain hours of the year.

PG&E’s pilot targets customers at existing sites as well as those who are not able to choose alternative locations, he said. Some developers of yet-to-be-built EV charging hubs may prefer to look for another spot on the grid where they don’t face those constraints.

The second challenge is knowing exactly how much power a big customer can use during certain hours of the year without overloading local circuits, transformers, and substations, Portilla said.

Utilities typically build their grids with plenty of headroom so as to avoid the risk of putting their grids in unsafe overload conditions. They also need to plan for sudden changes, like when some parts of the grid fail and the utility has to reconfigure circuits and redirect power flows around those hot spots.

Pushing the limits of how much power customers can use at any point in time is ​“using up headroom in the system, essentially — and that decreases operational flexibility,” he said.

That’s why PG&E has typically offered big customers on constrained portions of the grid what Portilla described as a ​“low-tech bridging solution” — a class of service known as a ​“load limit.”

In simple terms, load-limited customers can still connect to the grid and draw power for years while they wait for the utility to make the upgrades to accommodate their full draw. But those allotments are very conservative and are designed for entire seasons of the year, rather than hour-to-hour adjustments.

In fact, PG&E and Tesla had a load limit in place at the EV charging site taking part in the Flex Connect pilot, Portilla said. Under that arrangement, PG&E had essentially told Tesla, ​“In the summer months we can serve 20 percent of your load, and during the rest of the year you can have 71 percent of your load.”

“This is the lowest-tech way to provide partial energization,” he said. Of course, that’s not a great deal for an EV charging site that wants to be able to serve drivers during peak summer road-trip season.

But it was the best the utility could safely offer until the technology was in place to monitor the true hour-by-hour conditions at the substation serving that charging site — and for the utility to communicate to the charging site how it might need to adjust its operations in response to unexpected changes in grid conditions.

Making flexible interconnection a reality

That’s where PG&E’s distributed energy resource management system (DERMS) has come into play, Portilla explained. PG&E launched its DERMS project last summer with Schneider Electric, the French electrical equipment giant that operates software systems for utilities across the globe, and Microsoft, which provides the cloud computing platform to run the software for PG&E.

DERMS is a catch-all term for a wide array of software platforms that can monitor and control not only utility grid equipment but also the solar inverters, batteries, EV chargers, and other electrical equipment at homes and businesses. That’s a complicated task, and Portilla stressed that it’s ​“still emerging technology” for PG&E and other utilities. In fact, the utility’s Flex Connect project is among the first instances of it being applied to real-world grid operations.

According to Portilla, the basic process goes something like this: First, PG&E forecasts what the limitations will be at a particular substation — say, for the following day.

“Our DERMS product does the forecasting and allocates the capacity, and it sends [the Flex Connect participant] day-ahead hourly limits,” Portilla said. For example, DERMS may communicate that ​“from 5 p.m. to 6 p.m. we can give you 90 percent; between 7 p.m. and 8 p.m. we can give you 50 percent.”

Then ​“the signal goes out automatically,” he continued. A participant receives it and commissions its site to keep EV charging loads in check. ​“Just how that’s done is up to the customer,” he said. An EV charging site could limit all chargers to a fraction of their maximum capacity. It could disable some chargers while keeping others at full capacity. Or it could turn on batteries to cover the additional load, if it has them. The key, Portillo said, is that all these processes are automated. 

Getting to the point where PG&E can trust this system to work under all circumstances has taken several months, Portilla noted. ​“We failed commissioning at the two sites multiple times. That’s part of the learning process,” he said. ​“This is operational technology — it has to work. And it can’t just work on average and in normal conditions. It has to work when things have failed upstream of it.”

That’s why PG&E and its Flex Connect pilot customers have built-in contingency plans. If communications between the utility DERMS and the customers’ power management systems are lost, the charging site will ramp down to its previously set lower limits.

All of this has required significant work for the customers participating in the Flex Connect program, Portilla emphasized. Each participant has to invest in the technology needed to control their power usage across their site as well as specialized systems to communicate with DERMS. And if they violate the limits that PG&E has set for them, they may not be able to remain in the pilot.

But for a fast-charging site that sees much of its peak customer demand during summer and summer-adjacent holidays, getting the extra capacity during what would otherwise be highly constrained months may well be worth the trouble. This chart shows the difference between the constraints put on the Tesla charging site under its ​“load limit” arrangement with PG&E and the far more generous grid capacity it has under Flex Connect. 

The other big win for participants is getting their high-speed charging up and running faster, Portilla said. He cited the example of the PepsiCo distribution center in Fresno, where PG&E doesn’t expect to be able to complete its grid substation upgrades until mid-2026.

Charging for the Tesla semitrucks being added to the fleet ​“had been very limited during daytime hours,” he said. But with Flex Connect operating, that site will be able to access enough electricity to serve the bulk of its charging needs throughout most of the year starting this month — about a year and a half earlier than anticipated.

Getting to the big payoffs for flexible interconnection 

Flexible interconnection is something of a holy grail for a power grid that’s facing increasing demand for electricity. In a July report, the U.S. Department of Energy cited ​“flexible service connections” as an important tool for ​“larger loads such as EV fleet charging and data centers.”

Flexible interconnection is also a valuable approach to connecting distributed solar and battery projects to utility grids, the DOE report stated. California regulators have already approved a plan requiring utilities to find ways to allow solar farms and batteries to interconnect to the grid under flexible operating conditions.

Getting from pilot projects to a standard flexible interconnection process won’t be easy. A number of technical, operational, and regulatory barriers remain, as Roger Salas, Southern California Edison’s principal manager of distribution system analysis, said in his May presentation to California regulators for the utility’s Load Control Management System (LCMS) pilot, its analog to PG&E’s Flex Connect pilot.

On the technical side, “[t]here are no national standards for testing and certifying” the automated load management equipment needed to ensure that customer sites keep their grid draws under prescribed limits, Salas noted. Until those standards are in place, every utility must ​“enforce their own requirements to ensure safety.”

On the operational side, flexible interconnection ​“introduces a new variable for grid operators to consider,” he said. That job is already complicated, with hour-by-hour shifts in generation and demand and unexpected emergencies to manage. ​“New procedures need to be developed to operationalize and integrate into grid operations,” he wrote — including ​“contingency measures in the event LCMS fails.”

Finally, utilities and regulators will need to develop ​“established regulatory procedures to govern the use of LCMS technology” outside of the case-by-case basis being used for pilot projects, Salas wrote.

So far, neither PG&E nor SCE have signed up any new customers for their flexible grid pilots. The two utilities have yet to set up the legally binding rules — or ​“tariffs” in utility parlance — that would give new customers confidence that they’ll be required to curtail power use only during well-defined times of the day or seasons of the year.

But once those rules are in place, customers might be willing to commit to building at a grid-constrained site rather than abandoning it for greener pastures, in confidence that they’ll be able to access at least enough power to get by for a few years until the utility has upgraded its grid.

These tariffs are also critical for designing a system that treats all participants fairly, Portilla noted. Right now, PG&E is working with only individual customers at any one particular substation, for example. Adding a second site, or a third — or more — will complicate the task of forecasting and allocating the grid limits for each of those customers and instructing them on how much power they can or can’t use from hour to hour.

Then there’s the complication of factoring the grid benefits of flexible interconnection into how utilities plan future grid investments, he said. Right now, Flex Connect is essentially ​“moving a planning constraint into the operational time horizon,” he explained — a real-time work-around addressing the fact that PG&E hasn’t already planned and built the grid the EV charging customer would need for unimpeded access to all the electricity they might want during every hour of the year.

But the big payoffs from flexible interconnection won’t just flow to EV charging sites and other major power-using customers. Standardizing the practice could help reduce costs for PG&E customers at large, Portilla explained.

California’s major utilities will need to spend tens of billions of dollars over the coming decades to build out their distribution grids, both to supply fast-growing demand for power and to harden them against the threat of sparking wildfires.

Those costs are driving California’s major utilities to raise their customers’ rates, with PG&E’s rates more than doubling over the past decade.

But if California’s utilities could get big EV charging sites connected faster, these hubs can start providing power to more EV drivers sooner. Those electricity sales represent new sources of utility revenue — customers switching from buying gasoline and diesel fuel to buying electricity instead — which reduces pressure on utilities to increase rates.

In that sense, EV charging represents a major opportunity for utilities to spread the costs of building their grids across a much wider base of customers than they’ve been able to serve before.

That’s why the Environmental Defense Fund has promoted utility spending on increasing capacity for EV charging as a way to reduce the cost of delivering electricity to customers at large — and why it’s promoting flexible interconnection as a way to ​“speed deployment of charging infrastructure and get interconnected quicker.”

The more that EV charging hubs can use flexible interconnection to start serving customers, the more utilities can increase electricity sales without blowing out their grid budgets. ​“It’s about PG&E’s ability to increase the throughput of the system to a greater extent than the investments required to do that,” Portilla said. In other words, it’s about growing the electricity demand that the grid can serve at a faster pace than the rise of the grid infrastructure costs.

“What we’re doing first is opportunistic and reactive, in a sense,” he said. But ​“PG&E’s mission is how to serve the highly electrified and cleaner grid of the 2040s while managing rates. If we want people to electrify, the rates have to be competitive.”