Utilities and state regulators are working to scale up charging infrastructure, finding that interoperability is key.

Editor’s Note: GM announced Nov. 26 that it is doubling resources devoted to electric and autonomous vehicles over the next two years. In addition, the Edison Electric Institute plans to host an event Nov. 30 marking the 1 millionth electric vehicle on U.S. roads. But as EV investments and sales rise, challenges remain to even greater penetration in the marketplace. The following piece, from earlier this fall, looks at some of those challenges.

The road to transportation electrification is now driven by demand from policymakers and the public through private sector automakers and charger providers to electric utilities and their regulators.

Networked electric vehicles (EVs) can be a highly flexible distributed energy resource (DER) and, as a distributed storage system, support the power system’s transition to low-cost, low-emissions renewables. Carmakers are rushing to meet consumer demand. And charger providers and utilities are beginning to collaborate on charger infrastructure deployment, when regulators greenlight the build-out.

“Today’s infrastructure is clearly inadequate to accommodate greater penetration of EVs,” according to Philip B. Jones, former Washington utility commissioner and current executive director of the Alliance for Transportation Electrification. “Much more needs to be done quickly by electric utility commissions to set the policy and regulatory framework to meet the needs of this unique transformation.”

Not a single region or use-case is ready for the transformation that is nevertheless gaining momentum, Jones said in a September 13 webinarpreviewing a new paper on transportation electrification from Lawrence Berkeley National Laboratory (LBNL).

Streamlining collaboration between utilities and charger providers and standardizing communications protocols were among Jones’ chief concerns. And “there is no guidance on these things at the federal level because this administration is not interested,” he added in an interview with Utility Dive. “State commissions need to act.”

“The auto industry will change more in the next 5 years than it has in the last 50.”

Mary Barra

Chair and CEO, General Motors

The emerging market

“The auto industry will change more in the next 5 years than it has in the last 50,” General Motors Chair and CEO Mary Barra wrote in the most recent GM annual report.

The numbers agree with Barra. In 2017, annual global sales of EVs passed 1 million and could reach 4.5 million, 5% of the global market, by 2020, according to business consultant McKinsey. That will grow to 11 million in 2025 and 30 million in 2030, Bloomberg New Energy Finance forecasts.

The price of batteries, the EV’s most expensive component, fell from $1,000/kWh in 2010 to $227/kWh in 2017 and is forecast to fall to near $100/kWh by 2020, McKinsey also found. In response to rising demand and falling prices, automakers are expected to introduce an estimated 340 new EV models around the world in the next three years, the consultant added.

EVs could reasonably reach a 20% U.S. market share by 2030, Jones said. That would require an estimated 600,000 level two charging plugs and about 27,500 direct current fast charging plugs (DCFCs), according to a 2017 National Renewable Energy Laboratory (NREL) study.

In 2017, there were only about 43,000 plugs in the U.S., NREL reported. And McKinsey found infrastructure growth is falling behind EV deployment: there were 12.4 EVs in 2015 for every U.S. charging station, and 13.2 EVs per station in 2016.

U.S. charging infrastructure needs to “far exceed current investment plans,” according to Jonathan Levy, VP for strategic initiatives at leading charger installer EVgo. Private sector providers have expanded their reach but still find it’s “too hard to charge.”

To scale transportation electrification, “it makes sense for utilities to be more than mere stakeholders in the process,” he added in the LBNL paper.

But utility action requires regulatory approval. Some regulators, like those in California, Massachusetts and Hawaii, have encouraged utility proposals to advance charger infrastructure build-outs. But most have left it to utilities, resulting in little progress, according to Jones.


Levy, speaking for private vendors, and Jones, speaking for utilities, both acknowledged there is a debate between their industries over the role of utilities in financing, owning and operating charging infrastructure. And both agreed utilities, overseen by their regulators, can accelerate growth.

Arguments that commission-approved utility participation will stifle innovation, lead to an overbuild and stranded assets or prevent private provider growth are wrong, Jones said. “There is room in this nascent market for everybody.”

“[T]he biggest role utilities and their regulators can play is in tariff reform in general and in preventing demand charges from being an impediment.”

Jonathan Levy

VP for strategic initiatives, EVgo

Levy agreed with some qualifications. “The relationship between utilities and EV charging companies is likely to be one of ‘coopetition,'” he wrote. As roles emerge, utilities may take some market share away from charger providers, but they also may become charger providers’ customers, “shar[ing] risk and upside.”

Utilities bring a strong motivation to drive customer demand for electricity and expertise in installing infrastructure, Levy acknowledged. But “the biggest role utilities and their regulators can play is in tariff reform in general and in preventing demand charges from being an impediment.”

Demand charges, especially those already in place for commercial and industrial (C&I) customers with fleets of medium- and heavy-duty vehicles (MHDVs), can be a serious obstacle to electrification.

A demand charge is a price signal to C&I customers to limit sharp demand spikes because it can increase a C&I customer’s bill 50%. This is problematic for early adopters of MHDVs. A demand charge bill spike in an otherwise flat usage pattern caused by vehicle charging could discourage a transition to MHDV electrification.

Rate designs developed by utilities and their regulators should “reflect the economic reality of demand charges inhibiting economic viability,” Levy wrote.

Well-designed time of use (TOU) rates can also drive EV growth by cutting costs for drivers, Levy wrote. They can benefit utilities through increased kWh sales and by shifting utility loads away from peak demand periods and toward times when more renewables are in the power mix.

The other form of coopetition is in charging infrastructure deployment. “There is largely industry and stakeholder consensus — even among those who oppose utility ownership of EV chargers — around the importance of utilities installing make-ready infrastructure,” Levy wrote. A make-ready is all the hardware, from a utility’s distribution system to the customer, that readies a site for a charger.

“The debate over whether utilities should own and operate chargers has been counterproductive and there would be a lot more EVs on the road if there had been consensus around the need for utility investment earlier.”

Lang Reynolds

Manager of electric transportation, Duke Energy

Not all utilities are satisfied with this business model. A pilot announced August 29 by Xcel Energy will be for residential customers but the utility plans to eventually have different charger build-out models for different market segments, Xcel Electric Vehicle Product Developer Mathias Bell told Utility Dive.

Xcel’s plan calls for it to own and operate chargers for its residential customers but will build make readies for public chargers, he added. It will use both models with fleet customers.

Duke Energy’s recently announced Florida pilot will have the utility own and operate 530 level 2 chargers and DCFCs “to test different types of hardware,” electric transportation manager Lang Reynolds told Utility Dive. “The debate over whether utilities should own and operate chargers has been counterproductive and there would be a lot more EVs on the road if there had been consensus around the need for utility investment earlier.”

Utilities benefit by rate basing the make readies, and charger providers benefit from utilities “buying down the costs of installing the rest of the charging equipment,” Levy said. “Private capital and public capital have different risk appetites and goals, and there is an opportunity for them to complement one another.”

Where rates or adoption curves impede the payback needed by private providers, rate-based utility capital expenditures can take over. Where rapid market expansion makes streamlined responsiveness to customer demand important, “utilities should work in partnership with experienced EV charging partners,” Levy said.

Transportation electrification “is going to be so big, so substantial, and so critical to our nation’s economy and infrastructure that the commissions have to oversee it,” Jones said. The problem of greatest concern to Jones may require an especially hard push from state regulators.


Drivers need “a consistent charging experience,” Levy wrote. They may be alienated if there is not “a reliable and easy to understand user interface and customer service approach.”

Pilot projects have moved the industry past early adoption and into “the early majority stage,” Jones agreed. “We now need strong rules on interoperability because consumers are going to get very upset if they can’t move seamlessly and simply between proprietary networks.”

Multiple proprietary charging and communications systems are being deployed, but they do not communicate easily with other networks, preventing “a truly open system,” he added.

The first thing needed for an open system is a universal plug that connects the charger to the car, Jones wrote. Another is an automated secure universal payment procedure that matches what consumers are used to at gas pumps.

The biggest hurdle may be charger providers’ balkanized network management systems. Each is a complex software platform “that remotely controls the charging stations deployed in the field and collects large amounts of data from both the EV user and the vehicle,” Jones wrote. The data is protected because it is key to the provider’s marketing of services or products.

It is built on the internet protocol through which a charging system can, via the internet, become a DER and deliver grid services like energy storage and demand response. Most industries that function through such software platforms guard this intellectual property vigilantly.

Only interoperability, like that achieved for computers with USB ports, will give EV drivers easy, reliable and uniform charging at every charging station, Jones wrote. Network management systems must interact seamlessly without compromising vendors’ intellectual property.

Utilities and vendors “are gravitating toward” open standards and Open Charge Point Protocol (OCPP), Jones wrote. OCPP allows drivers to charge at any participating vendor’s station without compromising proprietary data in the same way that different vendors’ cell phones can connect with each other. It was developed through the globally-based Open Charge Allianceand has been demonstrated internationally to be flexible and secure.

“If the federal government is unwilling to act, states need to do so,” Jones said. It would not resolve the issue nationally, but state commissions could begin the process by requiring utilities to specify in solicitations that charger providers use OCPP to make their networks interoperable.

“Waiting for the market to get the system in place and scale it will not work. Utilities have to start investing and commissions have to take the lead.”

Philip B. Jones

Executive director, Alliance for Transportation Electrification

Southern California Edison is building a $22 million, 3,500 plug make-ready pilot and has proposed a $760 million, 48,000 plug make-ready build-out. Private providers will install all chargers, SCE President Ron Nichols told Utility Dive.

But SCE’s solicitation requires bidders to use interoperable systems that include the open standards and protocols Jones is calling for, Nichols said. “As we get more charging infrastructure in place, this will ameliorate concerns about interoperability.”

In Avista’s early pilots, it has solicited partnerships with private providers specifically to assure network interoperability through open communication protocols like OCPP, Avista’s electric transportation manager, Randall Farley, emailed Utility Dive.

Ideally, the industry would select one of the three types of DCFC connectors now in use and one from among the current variety of user-charger station interfaces to further improve the customer experience, he added.

The electric power and automotive industries are at a tipping point, Jones said. “Waiting for the market to get the system in place and scale it will not work. Utilities have to start investing and commissions have to take the lead.”

The most important DER

In California, which leads the U.S. in EV use and charging station deployments but still has a very low share of the car market, “EVgo has dispensed over 1 GWh each month for the last 12 months,” Levy said. As carmakers introduce new models and charging infrastructure becomes more common, “the numbers will grow.”

Executives and regulators reluctant to support investment in transportation could cost utilities customers if they miss out on this “huge opportunity to fuel the transportation future,” Jones wrote.

They should instead be “planning the necessary infrastructure upgrades and doing the necessary cost-benefit analyses,” he added. “This is not just about load growth, it is about an asset to utility distribution systems that can absorb renewables over-generation and meet system demand spikes. It is about utility access to what could be the grid of the future’s most important DER.”