Why the UK is beating the US on transportation electrification, Part 2: Utility innovation | SEPA Skip to content

Why the UK is beating the US on transportation electrification, Part 2: Utility innovation

Editorial note: Erika Myers, Director of Research at the Smart Electric Power Alliance (SEPA), took part the organization’s annual Executive Fact Finding Mission, which this year spent a week, Oct. 14-19, in the United Kingdom (U.K.). The following blog is the second in a two-part series examining the U.K.’s aggressive approach to transportation electrification.

Complete decarbonization of the power, transportation and heating sectors can only be achieved with the use of demand-side flexibility, which can, in turn, limit the need for expensive grid upgrades.

But, shifting consumption away from peak times and storing cheap, renewable energy are both contingent on flexible storage — in the form of electric vehicles (EVs), smart electric heating and residential storage — located near areas of high energy consumption. At least that’s the vision behind a recent report from the United Kingdom (U.K.), Blueprint for a Post-Carbon Society, authored by Imperial College London and OVO Energy, an innovative clean energy services company.

According to the report, “The energy storage found in these behind-the-meter (BTM) devices can act like an energy reservoir, soaking up cheaper renewable power that can then be used when required or released back into the grid at times of peak demand.”

Toby Ferenzci, Director of Strategy at OVO (pronounced “oh-vee-oh”), boils it down even further.

“Mass electrification of heat and transport powered by renewable energy is not only feasible, but is lower cost than business as usual over the long-term,” he said.

One of OVO Energy’s current demand flexibility pilots will put EV chargers in 50 street lamps in London. (Photo courtesy of OVO Energy)

Staying focused on long-term goals is one of the cornerstones of the U.K.’s aggressive climate action plan to decarbonize its transport and energy sectors. The country aims to cut its carbon dioxide emissions 80 percent below 1990 levels by 2050. Rapid decarbonization is also one of the reasons Britain is well ahead of the U.S. in the rollout of EVs and EV charging infrastructure, as we learned from Ferenzci and other British energy executives we met during SEPA’s recent Fact Finding Mission to the U.K.

Specifically, the U.K. knows it must plan ahead to contain costs to upgrade grid infrastructure, reduce the impacts of the EV fleet on peak power demand, and use EVs as grid assets through managed charging and vehicle-to-grid (V2G) technologies. Those plans include innovative approaches to customer education and engagement, as I discussed in Part 1 of this series, as well as developing new utility business models, my topic for this article.

According to recent estimates, widespread EV growth in the U.K. could result in at least 30 percent of the country’s distribution network requiring upgrades or other investments by 2050. The price tag for these improvements could be up to £2.2 billion ($2.86 billion).

To help contain some of these costs, the U.K. recently became the first nation in the world to pass legislation requiring all EV chargers sold and installed in the country to be capable of managed charging. Such “smart” charging equipment must be able to adjust the rate of charge or discharge via remote signals, transmit information to a prescribed person, monitor and record energy consumption, comply with security requirements and meet certain energy efficiency criteria.

Planning for flexibility

The U.K. is a fully deregulated country with distinct market participants at the transmission, distribution and retail power levels. The country’s transmission network is owned and operated by a single entity — National Grid. Distribution network operators (DNOs) handle distribution, and retailer energy providers (REPs) sell electricity and handle billing, interconnection and other basic services for the customer.

Unlike energy retailers in the U.S, which have more limited roles, REPs in the U.K. can offer a variety of services beyond electricity sales, and customers can choose any REP. For example, OVO was founded in 2009 as a clean energy utility, offering customers renewable energy plans ranging from 33 percent clean power to 100 percent. But the company has since branched out with a variety of services and programs, such as a current pilot to turn 50 street lights in London into public EV chargers.

Leveraging charging infrastructure for demand flexibility was a key theme in the the company’s Blueprint report with Imperial College. Based on three scenarios – business as usual, middle of the road, and complete decarbonization — the report found that the demand flexibility needed for complete decarbonization could save consumers £7 billion ($8.9 billion) per year — about 80 percent less than business as usual. Individual savings penciled out at  £206 ($262) per household per year.

A further breakdown of total decarbonization savings show about £1 billion ($1.3 billion) would come from managed charging, and £3.5 billion ($4.5 billion) from V2G applications.

“What we found was that the market doesn’t actually need subsidies for the technology anymore,” Ferenczi said. “The country just needs to correctly apply free-market principles, which include the cost of carbon. If you cause the damage, you need to pay for the damage. Most of society is not doing that now.”

Another critical step is having distribution system operators take a neutral position on which resources to use. For example, a non-wires alternative incorporating managed charging could provide significant flexibility.

“What is hard for policymakers is to set the right pricing signals, so that the capital markets can make the right investments to realize these future savings projected in the report,” Ferenzci said.

“Pricing signals need to be forward looking and take into account that we need to replace fossil fuels with low-carbon alternatives,” he said. “That way we will incentivize tools such as demand flexibility to save everyone money in the long-term.”

Ferenczi believes the U.K. could do more to push the DNOs to consider demand flexibility as an equally important resource. OVO has been campaigning to create incentives for DNOs to procure flexibility services from the demand side, not only from traditional thermal generation, that is, fossil fuels. As long as DNOs are incentivized to continue building out the distribution network, rather than aiming for particular performance goals (including decarbonization and procuring demand-side flexibility services), they are not going to be incentivized to change behavior, he said.

Piloting V2G

To prove out some of these demand flexibility concepts, OVO is now part of a two-year pilot program that will install free V2G chargers in the homes of 1,000 Nissan LEAF owners across the country. The chargers also come with an app that allows customers to input when they typically use and charge their cars and set a minimum charging level.

As a full partner on the effort, Nissan will not void the warranty on its LEAF batteries, which has been a point of concern for other V2G pilots. The V2G charger used in this program will be commercially available and uses the CHAdeMO protocol, an emerging standard for fast-charging. It also includes VCharge software, a platform that can optimize the use and flexibility of distributed resources, including fast chargers. In the U.S., PJM Interconnection has used VCharge for frequency response services that draw on aggregated electric thermal storage heaters (hot bricks).

One of the V2G chargers to be used in the OVO pilot. (Photo courtesy of OVO Energy)

In the U.K. pilot, OVO will control the chargers, using cheap, off-peak energy for charging, and tapping EV batteries for extra power during times of peak demand, all scheduled around customers’ normal use of their vehicles, as set up in the app.

“Based on our research, there are ways aggregators can manage the charge and discharge of the on-board vehicle battery to minimize degradation and potentially even extend the life of the battery,” Ferenczi said.

OVO is still working out the details of how pilot participants will be compensated for the flexibility the V2G chargers will provide, he said. It will most likely be based on the value streams the company can extract from the chargers. The three value streams identified thus far include ancillary services on the transmission level, primarily frequency regulation; energy arbitrage in wholesale energy markets (using an energy trading team); and local balancing services at the DNO level to address local constraints.

DNOs in the U.K. are only beginning to seek out these services, but OVO expects that market to increase over time. Based on V2G technology and the fast response timeframes it offers, Ferenczi feels that in some cases, services such as energy arbitrage and frequency regulation could be performed simultaneously.

He anticipates that the program could be commercially viable without government support in the near term, offsetting the additional cost of the V2G chargers over traditional smart chargers.

In Denmark, aggregators like the San Diego-based Nuuve Corp. have successfully tested out the V2G capabilities of a small fleet of commercial vehicles. Based on average frequency regulation prices in Denmark, the company estimates that the average vehicle could yield approximately €1,400 ($1,587) per year (assuming participation levels of 6,150 hours per year).

Is the U.K. vision replicable?

Ferenczi sees “the value of managed charging and V2G evolving over time as the market transforms and third-party aggregators are able to provide more grid services from behind-the-meter resources.”

Is such a vision transferable to the U.S.? Or will we always be playing catch-up with the U.K. and most of Europe on the deployment of renewable energy and other distributed energy resources, such as EVs?

The lack of a national energy policy built on a compelling call to action remains a major challenge for the U.S. But as individual states, utilities and other stakeholders plan for the future, our first question should be, “What will our long game look like, and how do we expect to achieve it?”

While we don’t have a national roadmap for transportation electrification, an end state that allows us to leverage EVs as grid assets could be an aspirational goal, and a starting point for cross-industry collaboration. Managed charging is a first step, but will require the industry to work together on common standards.

Further, as we think about V2G opportunities, we will need to consider how these DERs may participate in the future marketplace — an issue already sparking national and regional discussions.

Finally, beyond transportation electrification, how will we leverage all beneficial electrification opportunities to introduce our own versions of demand flexibility and ultimately achieve our long-term goals?

SEPA will be focusing on these and similar topics as part of our transportation electrification efforts in 2019. While we know there are no easy answers, the discussions to develop that vision and drive innovative solutions are vital.

For more information on what U.S. utilities are doing to prepare for EVs, see Myers’ recent report, Utilities and Electric Vehicles: Evolving to Unlock Grid Value and her article in the December issue of Public Utilities Fortnightly, Economic Development Rates to Encourage EV Infrastructure Investments.

Erika Myers also leads SEPA’s EV Working Group and, beginning in 2019, will head up its new Transportation Electrification Pathway. For more information on how to get involved, contact her at [email protected].