Power grids of the future may consist largely of the same wires and transformers they’ve used for the past century — but they’ll be operated in a completely different way.
The proliferation of distributed energy resources is making customers an equal partner with generators in supplying the power that keeps the grid humming. And the rapid shift from fossil fuels to electricity is forcing utilities and customers to think in new ways about how and when that power is used.
Adapting to these new realities is the primary imperative for the 21st-century electric grid, but the transformation is not happening in a smooth, coordinated fashion. Instead, it’s being driven by new technologies, early-adopter utilities, and innovative grid operators and regulators. Over the coming weeks, GTM will take a look at five mega-trends at the grid edge, who is shaping them and what they mean.
While many utilities and grid operators still see intermittent renewables as a disruption to their power grids, a growing number are thinking creatively about how to enlist distributed energy resources to help with the challenge.
Such solutions can come in the form of distributed energy resource management systems that can manage the moment-to-moment interactions that batteries, electric cars and controllable loads have with the grid. They can also come in the form of non-wires alternatives that make distributed energy resources an integral part of grid planning going forward.
UK Power Networks, the company that operates the grid that provides electricity to about 20 million people in London and the southeastern U.K., is doing both — and not just in pilot projects, but across its entire system.
This week, UK Power Networks announced it has secured 123 megawatts of grid flexibility capacity from 16 different providers, ranging from large-scale renewable energy and energy storage systems to heat pumps and “virtual power stations” backed by household batteries and electric vehicles.
UKPN has been conducting similar “flexibility tenders” for the past two years, but this one is the biggest, making up the majority of its 142.3 megawatts of capacity contracted to date. The £14 million ($17.6 million) in contracts are also for longer periods of time than previous tenders, with an average of five years of commitment, and some running through 2027.
This week’s tender marks several “firsts” for UKPN, including its first contracts for the low-voltage grid and the first EV chargers among its mix of resources. That’s an important factor for a grid operator expecting between 2 million and 4 million new electric vehicles by 2030.
To manage these customer-owned assets, UKPN uses an active network management system, built by partners Smarter Grid Solutions and Nexant, that monitors grid conditions in real time and taps the responsiveness of wind and solar farms, batteries, EV chargers and flexible loads to mitigate emerging constraints.
That’s less expensive than making the grid investments that would otherwise be required to allow an increasing number of wind and solar projects — 9.4 gigawatts of them as of January 2020 — to continue to be interconnected to UKPN’s grid. It also allows UKPN to incorporate these resources as part of its long-range grid investment plans.
These are vital capabilities for UKPN and the country’s other grid operators as they transition from distribution network operators to “distribution systems operators” — in other words, from running one-way electricity delivery systems to operating complex networks of generation and load, much of it beyond their direct control.
Transmission and distribution network operators across the U.K. have committed to making similar transitions, and other distribution network operators are making progress on similar flexibility tenders. They’ll need to if they’re going to be able to integrate the growing share of renewables the U.K. needs to hit its 2050 net-zero emissions target without being forced to curtail an increasing share of that intermittent energy.
“Flexibility is the future because it is arguably the single most important element of a decarbonized smart electricity network,” Sotiris Georgiopoulos, UKPN’s head of smart grid development, said in a statement. While the rest of the U.K.’s grid operators have been securing flexibility contracts through tenders similar to UKPN’s, “hitting more than 100 [megawatts] is an important milestone that shows the market is really gathering pace.”
All told, UKPN’s combination of capabilities represents “one of the most advanced grid planning and operations digitalization efforts in the electricity industry,” according to a new case study from Wood Mackenzie Power & Renewables. In fact, it’s one of the most complete “enterprise DERMS” platforms that WoodMac has identified, as this chart indicates.
Sourc: Wood Mackenzie's recent case study on UKPN
By combining network operations, grid planning and customer engagement in one system, UKPN is “trying to create a system that is their business-as-usual approach to regulating DERs and managing the grid,” WoodMac grid edge analyst and case study author Francesco Menonna said. He points out that that’s a noteworthy distinction separating UKPN from the “piecemeal approach...at other utilities, where they’re trying to address each problem when it arises, separately from the others.”
Why it's more advanced than anything in the U.S.
For the most part, utilities still tend to look at managing the grid impacts of increasing DER interconnections distinctly from long-term grid planning. Likewise, they tend to differentiate between using behind-the-meter resources as demand response to reduce system peak demands and tapping their flexibility to solve local grid challenges.
This piecemeal approach starts to break down as DERs become a significant part of the grid. But it’s hard for utilities to change it, given the regulatory and economic realities that drive their behavior.
For instance, while many U.S. utilities have been ordered by state regulators to consider DERs as non-wires alternatives (NWAs) to grid investments, the record of success in those efforts has been spotty. In California, a complicated utility-driven process has led to only a few identified NWA opportunities, and no contracts to date, although a handful of projects are in the tendering phase this year.
In New York, where NWAs have been driven by state policy since 2015, a handful of projects including Consolidated Edison’s Brooklyn-Queens Demand Management initiative and Central Hudson Gas & Electric’s Peak Perks targeted demand management program have been completed. But scores of other potential projects have failed to overcome the disconnects between traditional utility grid investment methods and the complexities of enrolling DERs as alternatives, although new opportunities are expected after the state's utilities submit grid plans later this month.
One big difference between the U.S. and the U.K. in this regard is how utilities are compensated for different investments. In the U.S., grid investments and other capital expenditures earn guaranteed rates of return that are more attractive to the utilities than operating expenses that don’t, such as NWA contracts. But under the U.K.’s Revenue = Incentives + Innovation + Output (RIIO) framework, grid operators are compensated on total controllable expenditures, or “totex,” a combination of operational and capital expenditures, which provides incentives to reduce costs across both domains.
“Flexibility services open up new markets for distributed generation [that] is already connected and helps to lower the costs for new connections in the future,” Efstathios Mokkas, energy markets lead for UK Power Networks, said in an email. But the contracts it has secured could also “be considered the equivalent of NWAs” since they “allow us to defer reinforcement in demand-constrained areas” — deferrals that it can earn a return on under RIIO’s totex model.
UKPN has also built up a comprehensive and transparent set of methods to calculate the value of DER flexibility to defer grid investments, a challenge that’s stymied many U.S. NWA projects. “We have a robust methodology for calculating the value of flexibility and comparing it with the network upgrades cost, and we will only ever proceed when it’s the lowest-cost option for customers,” Mokkas wrote. “All of our prices are open, transparent and linked to the cost of alternative action.”
This array of capabilities hasn’t been built overnight, nor has it been completely bankrolled by UKPN. “There were government grants to help them along the way,” said Ben Kellison, WoodMac's director of grid research, “to see what types of solutions might be effective and prove the performance necessary for them to assure a strong return on their expenditures.”
For example, UKPN’s first work with Smarter Grid Solutions — its “flexible plug-and-play” project started in 2012 — was aimed at actively managing renewables to obviate the need for expensive grid upgrades to keep adding wind and solar to its distribution grids. Likewise, more than half of the £33 million that UKPN invested in its Flexible Urban Networks and Smart Urban Low Voltage Network programs to provide visibility and control to constrained grids in London and other cities, came from the Low Carbon Network Fund.
A model for other utilities to follow
All of this work has laid the foundation for UKPN’s ongoing series of flexibility tenders — including its first in April 2019 that secured contracts for on-site generator aggregator Amp Clean Energy and energy storage aggregators Limejump, Moixa and Powervault, and its second in November 2019 that secured contracts with demand response aggregator KiWi Power and residential solar-battery provider Social Energy.
UKPN hasn’t yet announced the names of the 16 companies that won its latest tender. But it has noted that it’s the first to secure contracts to manage low-voltage network constraints — an important accomplishment for a grid operator providing electricity to London and other urban centers where grid upgrades can be very expensive.
John Dirkman, senior vice president at Nexant, described how the active network management (ANM) platform works. It starts with forecasts built on UKPN’s grid data by Nexant’s Grid360 software, which yields heat maps and forecasts of grid constraints that need to be solved, and the combination of renewable curtailments, stored energy injections or load reductions that could solve them.
That analysis informs the bidding system that secures commitments through UKPN’s tenders, he said. It also determines “what contracts have been accumulated and what dispatches do we make to solve the problems” when they arise. Smarter Grid Solutions’ ANM Strata software manages the combination of dispatched reactions with other grid control systems to maintain grid stability in an automated fashion: “The system will run itself.”
The resulting system can manage wind and solar farm curtailment, demand response and grid controls in a holistic way. It can also bridge to new use cases, such as EV charging controls, in ways that don’t require “buying a separate package” to handle it.
“They have a very good vision of where they want to go,” Dirkman concluded. “We’re kind of waiting for other utilities to catch up.”