Utility and transmission executives from the UK, US, and Canada say the power grid wasn’t designed to handle intermittent renewable sources and an influx of electric vehicles.
Speaking at two separate conferences, the top officials of UK Power Networks, American Electric Power (AEP), and Ontario Power Generation (OPG) also acknowledged the challenge of providing safe, reliable, and affordable power across grids that were not designed to withstand climate-fueled events, such as sub-zero temperatures, wildfires, flooding, or torrential downpours.
However, they all agreed the challenges can be overcome with planning, and through better integration of energy generation and storage to smooth out daily and seasonal variations. They added that nuclear power can provide the baseload service that until recently was often the domain of coal-fired power plants.
“The electrical grids were not designed to handle decentralized sources of power,” such as solar panels atop homes and businesses, through which customers can buy from and sell power to the network, Basil Scarsella, CEO of UK Power Networks, observed in a 26 April conversation with AEP CEO Nick Atkins during an Edison Electric Institute (EEI) conference, which ran 24-29 April.
UK Power Networks maintains about 119,000 kilometers of cables and lines across London, the southeast, and east of England that deliver electricity to about 20 million people, while AEP, as one of the largest utilities in the US, maintains a transmission network that stretches across 40,000 miles while delivering power in 11 states.
Decarbonizing the grid will not be easy or cheap though, according to Atkins.
The average age of power lines and transformers on AEP’s transmission network is about 57 years, and it takes about $3 billion just to maintain the transmission network each year, Atkins said.
“So, we have a long way to go in terms of refurbishment of the grid, expansion of the grid, the ability to put renewables in place, and I see more renewables being put in place as well,” said Atkins.
EV demand will be spread out
UK Power Networks’ Scarsella said he is relying on big data analytics to predict where the power load for EVs or consumption for heating purposes will emerge. Heating is currently supplied via natural gas, which Scarsella said is going to change in the coming years.
“It all will not emerge from one location,” Scarsella said.
Canada, the US, and the UK have each set net-zero goals that include boosting the share of EV sales and renewables.
In 2021, the US set a goal of having EVs make up half of all new car and van sales by 2030, while the UK joined more than 30 countries in both the developing and developed world in calling for an end to sales of all cars and light vans running on petroleum products by 2030 and “to work towards all sales of new cars and light vans being zero emission by 2040 or earlier.” The UK put out a consultation on 7 April seeking to see how it should go about implementing its zero-emission EV (ZEV) target.
By 2026, Canada aims to have at least 20% of new light-duty vehicle sales be ZEVs, at least 60% of sales be ZEVs by 2030, and reach 100% by 2035.
Can the grid handle EVs?
Whether the grid can handle the surge in EVs is another matter though.
“So, if everyone bought an EV tomorrow, would the grid work? The short answer is no. You know, the grids have not been built, especially in cities, for heavy adoption, so there is heavy catching up to do,” OPG CEO Ken Hartwick said during a Foreign Policy magazine 27 April discussion on decarbonizing the grid.
Hartwick said OPG is planning to meet Canada’s EV influx through diversifying its energy mix, which includes nuclear energy providing baseload power and natural gas plants for peaking demand, though it is aware that gas plants will go the way of coal-fired generation. OPG already has 4 GW of wind and a hydro-electric portfolio with a combined capacity of more than 7 GW, but owing to the intermittency of wind, is relying on gas-fired and nuclear generation to stabilize power flows.
The Canadian utility is investing C$12.8 billion ($9.9 billion) to install a small modular reactor made by GE Hitachi Nuclear at its Darlington nuclear plant and looking to invest another C$13 billion ($10.5 billion) to refurbish six of the eight reactors at the Bruce Power plant.
Power sector is key
Policymakers participating in the two events said they are aware of the challenges posed by the electrification of the economy and decarbonization of the grid, and the key role that utilities play in this transition.
Speaking on the opening day of the EEI forum, US Special Presidential Envoy on Climate Change John Kerry said: “If we can’t do it in the power sector, we’re not going to get it done anywhere.”
Sally Benson, who serves as chief energy transition strategist and deputy director for energy in the White House Office of Science and Technology Policy and participated in the discussion with Hartwick and the CEO of the Nuclear Energy Institute, agreed with Hartwick.
Looking for that “Goldilocks sweet spot”
Benson said the grid has been designed to operate with predictable supply (from baseload coal, gas, or nuclear units and to a lesser extent from oil) that could be switched on when demand increased. But it was not designed to quickly provide power from those sources when intermittent power such as wind and solar declined.
When wind and solar began to scale up, grid operators had to learn, and actually became quite good at handling power flows that were not just dependent on weather and time of the day, but also on the season of the year, she said.
What’s more, Benson said these models have revealed that the more diverse the mix, meaning nuclear, natural gas, wind, solar mixed with storage, the lower the cost of dispatching power. So, the key now is to “kind of find that Goldilocks sweet spot” for maintaining reliability and affordability.
In its 2021 Climate Impact analysis, AEP said it plans to phase out 73% of its coal generation capacity by 2030. It’s already retired 13.5 GW and plans to retire an additional 1,633 MW of coal generation by 2028. At the same time, the utility plans to have 10 GW of renewable power installed by 2025 and then to add another 6 GW of renewables by 2030.
Like OPG, AEP is making significant grid investments, including in energy storage, but also exploring new types of generation, such as modular nuclear and research into the future use of hydrogen. AEP said in the analysis that gas-fired and nuclear generation are critical to any discussion about providing a “firm” baseload to complement intermittent renewables.
With electrification of sectors of the economy such as transportation and heating on the rise, Atkins said “we have to be very careful about how we make up that transition.”
AEP’s customers, as well as investors who are driving the business, are increasingly demanding clean energy, but they also want to make sure the grid system is reliable and resilient, Atkins said.
Regulatory regimes not keeping apace
However, he said, the US regulatory regimes are not moving fast enough to keep up with consumer and investor expectations, “so we continue to have this chasm.”
The six regional transmission organizations (RTO) and independent system operators (ISO) that manage grids in the US were set up to review a fairly small number of coal and gas projects. Now, there are hundreds or even thousands of applications on file.
Earlier this year, PJM Interconnection, the ISO that coordinates power for the District of Columbia and all or parts of 13 states in the US Midwest and East, proposed a two-year delay on accepting any new applications for connections, as it has a backlog of more than 2,500 requests for permits. It has a task force now studying solutions.
The federal government is still playing catch up as well. After a staff white paper and four technical conferences in 2021 that explored the changing nature of power markets and their operations, the US Federal Energy Regulatory Commission (FERC) took two major steps on 21 April.
Proposed changes to energy planning
FERC, which regulates interstate transmission of electricity, proposed reforms to its 2011 Order No. 1000 that outlines how RTOs plan their transmission needs and allocate costs. The proposed rule requires that RTOs write plans that are forward-looking enough to anticipate changes in transmission needs driven by changes in resource mix and demand.
“The generation fleet is changing rapidly” because customers are demanding clean energy and utilities are responding to those requests with commitments to procure renewables, FERC said.
FERC said it is also aware that the traditional electricity usage patterns or load profiles are changing as the needs of the customers change, such as greater demand for electricity to power 24-7 data centers that service the Internet.
The regulator also ordered the RTOs and ISOs that it oversees to submit detailed reports within 60 days about how they see the energy resource needs and load profiles, or profiles of electricity usage, changing in the next five to 10 years.
“These changes in the resource mix and demand, operational challenges, and increasing regional integration increase the importance of engaging in regional transmission planning and cost allocation to meet long-term transmission needs more efficiently or cost-effectively,” FERC said.
This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.