Renewables’ Ripple Effect on the Grid

Extraordinary growth in developing renewable energy resources is bringing ever-larger quantities of decarbonized power online. This is dramatically changing the balance of generation portfolios. It is a promising and necessary development on the road to reducing carbon emissions and shifting to sustainable power.

It is also prompting an unprecedented reevaluation of the electrical grid, as that infrastructure is experiencing tremendous new strain.

The success of this influx of renewable generation depends on getting that power from those dispersed sites to consumers. The existing electrical transmission and distribution grid needs significant reworking to address the ripple effects of renewable additions on the network.

The old model of generation often involved putting large-scale power plants in the hinterlands and running long transmission lines to load centers. The influx of renewables is changing that dynamic.

“We’re putting solar fields much closer to cities and towns, requiring investment in the transmission system, but we’re also seeing rooftop solar installed on residences and commercial facilities, which means we’re having generation occurring on the distribution system for the first time,” says Matt Kapusta, a regional practice manager at Burns & McDonnell who has worked on numerous solar interconnection projects. “The distribution grid was not designed for that.”

And it’s not just solar; a huge quantity of renewable generation is being added to the system. Hundreds of sources — solar, wind and other renewables — are being added at the transmission level, which is designed for bidirectional power. Meanwhile at the distribution level, millions of smaller sources are putting bidirectional power demands on a grid that was designed to be a one-way path.

Doug Houseman identifies two very different challenges from these renewable energy additions.

“Transmission is mostly handled by independent system operators (ISOs), which determine where the utilities are interconnecting these new sources at the transmission and subtransmission levels,” says Houseman, a principal consultant at 1898 & Co., a part of Burns & McDonnell. “For distribution-level systems, utilities are in a sink-or-swim situation. They have to figure out what to do to make stuff fit, and if it doesn’t, justify why it won’t fit on their grid.”

“There’s also the court of public opinion driving a lot of these investments,” Kapusta says. “Utility customers are pushing for decarbonization. Every utility we talk to has a program in place because their customers are asking for it.”

In the United Kingdom, the national government is the primary driver, says Jonathan Chapman, managing director for Burns & McDonnell in the U.K.

“The investment in the national grid system is coming from government policy demanding we move toward a decarbonized, net zero future,” he says. “As well, the government has made that bold policy to incentivize developers to invest in assets like energy storage and other assets that require additional capacity to be built into the distribution system and then into the transmission system.”

How are utilities facing these unprecedented changes? At the distribution level in particular, Houseman says, the scope is massive.

“As you consider the impact of electric vehicles and electrifying fossil fuel uses, we’re probably going to touch almost every circuit in almost every utility to increase capacity,” he says, “and potentially even upgrade their voltage in order to support loads that we used to be able to deal with using natural gas, the corner gas station, etc.

“This is not a little change. This is basically taking it all down and putting it back up again over the next probably 30 years, compared to a typical cycle of 80 to 100 years. It’s going to take a vast increase over current capital spending to be ready to do this.”

Source: S&P Global Market Intelligence

When residential customers put in rooftop solar and begin feeding excess daytime power production back onto the grid — becoming producer/consumers, or “prosumers” — they are typically compensated for the power, says Meghan Calabro, distribution modernization director at Burns & McDonnell.

“The utility is having to bear the burden of the infrastructure to handle that, as well as the intelligent devices to make sure those rapid changes in directionality don’t have damaging impacts on the grid,” she says.

Alongside grid hardening measures intended to boost service reliability and resiliency, some utilities are trying to be proactive about electrification demands as well.

“If you’ve got a lot of people adding EV chargers in their garages and increasing those loads, far fewer customers can be served off one distribution feeder and transformer allocation,” Calabro says. “We’re seeing utilities working to beef up their feeders, and while they’re doing that, they’re having to consider the intelligence and protections to maintain power quality as they facilitate the anticipated bidirectional power flow from those distributed energy resources.”

Distribution automation devices are being added to maintain a high level of power quality, and utilities increasingly must consider deploying volt/VAR optimization. Many utilities already have hundreds or thousands of capacitor banks deployed on their systems that operate in a local mode, automatically adjusting at certain times or based on temperature thresholds.

“Now utilities are adding in communications capabilities and trying to gain more granular control options, because the influx of intermittent renewable power demands much more rapid and accurate responses,” Calabro says.

Besides upsizing feeders and transformers, distribution upgrades by utilities include installing smart equipment such as reclosers and smart fuses to help the grid manage the two-way power flow, Kapusta says. More distribution systems will be put underground, which should minimize outage impacts but add complexity to projects.

On the transmission side, the boom in solar interconnection requests is leading utilities to invest in new switching stations and explore adding batteries to some solar sites, which adds another layer of complexity.

“Utilities that had large capital spends on their transmission system for the last 15-plus years are now experiencing a big shift in capital spending toward the distribution side to prepare for the impacts,” Kapusta says.

Ideally, every renewable generation site would have the ability to store excess energy for use on-site when it’s needed, but Calabro sees that as remaining impractical for now: “The reality is we don’t have a good silver bullet for storage, either at a very small-scale level or at grid scale.”

Without on-site storage, excess power gets fed back into the grid. This can become problematic quickly on the distribution grid, Houseman says.

“In some circuits in Hawaii, we’re seeing reverse power flows that are twice the peak load. Utilities are having to completely rethink their protection systems: the settings on them, the processes involved, and all the software that operates them,” he says. “In the past, we could install a protection scheme on a distribution circuit and might not touch it for decades. Now it might need to be reset eight to 10 times a day, depending on the weather.

“If you’ve got subtransmission that loops from one transmission substation to the next and has three to five distribution substations on it, you might see circulating currents, backfeed, reverse paths and other things the protection schemes weren’t designed for.”

The necessary resources, from additional operators to computing parameters, represent another strain on electric utilities. But getting protection right is critical to maintaining safe, reliable power.

“Getting it right won’t be noticed by the end consumer, but if you get it really wrong, resulting in live conductors on the ground or experiencing overvoltage to the point it starts fires, they’re going to notice,” Houseman says. “We don’t notice when the lights are on and working, but we sure notice when they’re not working.”

California is widely seen as being at the forefront of renewables in the U.S., but the phenomenon is reaching into every corner of the country. Every state is jumping in, even those where one wouldn’t expect a lot of solar penetration, as solar farms, wind farms and offshore wind development expand.

In Florida, a lot of solar power has been developed in the northern part of the state because that’s where the real estate is more affordable.

Interconnections that were put in five or six years ago are producing more per kilowatt of installed capacity than today, Houseman says, because utilities and developers back then used the highest-quality, highest-capacity locations to maximize the power they could produce. More recent installations in places like Minnesota and upstate New York have less than half the capacity factors of what’s available in Arizona.

"There’s a trade-off between putting in more transmission capacity and putting interconnections with lesser capacity closer to loads,” he says.

Renewables expansion in the U.K. is largely taking the form of growth in offshore wind development. The British government has targeted expanding from the current 10 gigawatts (GW) of offshore wind to 50 GW by 2030 as set out in the British Energy Security Strategy. Most of that growth is anticipated along the east coast of England and the north and east coasts of Scotland. (The U.S. is similarly looking for 30 GW of offshore wind by 2030, according to the U.S. Department of Energy.)

There will be significant investment in onshore grid infrastructure to accommodate the new renewable power coming onto the system, Chapman says, citing government estimates of £10 billion in England and £5 billion in Scotland to reinforce and adapt the onshore network.

“The power is typically needed in the south, where more power is consumed, so there’s a need to build transmission lines from Scotland into England and down toward the southern population centers,” he says. “We will reinforce the onshore network with new transmission lines, but it’s also going to be easier to lay HVDC offshore cables coming down from Scotland to England.”

This will be the first time that high-voltage direct current  (HVDC) is part of the U.K.’s regulated transmission system. The knowledge to connect those cables through converter stations to the onshore high-voltage alternating current (HVAC) system is specialized, driving a significant increase in demand for the capability to design and build HVDC converter stations.

Once back onshore, the idea of “modernizing the grid” to accommodate this new renewable power is somewhat hyperbolic, Chapman says: “Fundamentally, the way the transmission system is designed and built is not changing. We’re talking about adding more capacity, replacing and upgrading cables and systems at distribution voltage, and building new lines and substations at transmission voltage.”

End consumers are likely to be largely unaware of the changes being made in the transmission and distribution system. There may be some impact to their electric bills, although in the U.K. grid investment is typically only 20% of that bill. Still, consumers are changing their behaviors in terms of moving toward EVs and shifting from gas heating toward electric heat pumps, Chapman says.

“The intention is that the end consumer can make free-market choices, and the utilities respond in sufficient time,” he says. “One of the challenges is that to build a new transmission system, from identification of need through to power on, it can take nine years for a major asset. The government and regulators are trying to find ways to halve that time frame.”

Adjusting to the multiplying ripple effects of interconnecting so much renewable power in so many places is a process demanding urgent response.

One U.S. utility in the Upper Midwest, for example, routinely gets 20 interconnection requests daily, he says — up from the average of only one per day it received just five years ago. Such growth is no small matter, especially as the sizes of such interconnections continue to expand as well.

Utilities need to take the long view, to consider what their renewable penetration might look like in 10 years and what electrification may look like in 20 years as they plan their modernization efforts. Distribution infrastructure is not intended to be replaced on a frequent basis; the average life span of most distribution assets extends beyond 40 years.

For those that can, Kapusta says, a program approach can help utilities make these grid improvements as economically feasible as possible.

“They have to get the solar panels and major, long-lead equipment ordered ahead of time, get the land secured and perform the feasibility studies,” he says, “so many of them have programs of five to 10 years, if not more.”

Kapusta expects the industry to learn rapidly, out of necessity.

“The industry has never changed as much or as fast as in the last three years,” he says. “In the next three to five years, we’ll see what does and doesn’t work and how we pivot and learn from those mistakes. It’s going to be interesting to watch it unfold.”