Europe, the land of utilities under threat from renewable energy’s effects on traditional grid economics, is starting to see emerging opportunities in the field of demand response -- even if they’re much different from the opportunities that exist in the country where demand response was invented.
In the United States, where the term "demand response" was originally coined, the business of controlling customer power use to match grid needs has mostly involved utilities and grid operators giving customers day-ahead or hour-ahead notices to turn down power use or fire up backup generators.
That’s the model that companies like EnerNOC, Comverge and other demand response “aggregators” have made into a big business, and it has led to others, like CPower and ECS, being acquired by larger energy concerns. But only recently have we seen faster, more grid-interactive forms of demand-side power-shifting emerge from those same contenders.
In Europe, by contrast, demand response in the traditional U.S. form hardly exists. There are many reasons for this, including the availability of lots of pumped hydrostorageto help mitigate system-wide peaks, as well as a grid profile that lacks the all-important summer air conditioning demand that characterizes the U.S. grid.
But the rise of intermittent wind and solar power in Europe is starting to introduce grid instabilities and system-wide economic stresses that are changing that picture. Indeed, major European utility RWE recently revealed plans for a wholesale shift in its business model in order to bring more renewable, distributed resources into play, as a means of counteracting the economic stresses that come from running centralized, fossil-fuel-fired generators in a market that doesn’t promise long-term stability for those assets.
In short, the changing nature of Europe’s energy mix is forcing European utilities and grid operators to turn to customers for help. That, in turn, is opening new opportunities for companies with the right mix of technology and business models to meet those needs. Consider it another example of how disruptive forces at the intersection of traditional energy markets and energy customers -- what Greentech Media calls the grid edge -- are pushing entire energy ecosystems to adapt.
Turning Demand Response Portfolios Into Dispatchable Resources
Take the example of REstore, a Belgian startup that’s built a platform that can aggregate multiple customer loads to respond to grid commands in seconds, rather than minutes. Last week, REstore announced that it’s landed a contract with Elia, Belgium’s transmission system operator (TSO), to provide demand-side grid response that can meet so-called Primary Reserve requirements -- the equivalent of super-fast frequency regulation services in the United States.
It’s the first such contract between a European TSO and a demand aggregator, and it represents the culmination of months of testing to prove its effectiveness, as detailed in this March report from Elia (PDF). But it’s also a noteworthy development compared to the U.S., where demand-side resources are only beginning to play into such markets.
Separate from its Elia contract, REstore has collected over 100 megawatts of customer-side demand in Belgium and the U.K. that can be tapped at speeds and with levels of reliability that match, or even exceed, those provided by natural gas peaker plants, Pieter-Jan Mermans, REstore co-founder, told me in an interview last week.
That’s allowed REstore to offer its resource to French national utility EDF and U.K. grid operator National Grid as an “alternative to an open cycle gas turbine, with all the specifications that go with it,” he said. And, unlike the market structures that govern how demand-side resources are tapped in the U.S., “There’s no limit for them to exploit that virtual turbine.”
Work like this could help create new markets for demand response that simply don’t exist in Europe today, beyond a few vanguard programs like the U.K.’s Short Term Operating Reserve (STOR) program. And with Europe’s needs driven by the unpredictable ups and downs of wind and solar power, these new markets will demand far more responsiveness and automation -- and pay a higher premium for those services -- than the day-ahead or hour-ahead markets that dominate in the U.S.
“Two years back, the market in Europe was pretty much closed for demand response, except of course the STOR in the U.K.,” Mermans said. “The fact that we’ve now met the 100-megawatt milestone means that we consider ourselves as market openers, here in the national markets in continental Europe.”
Of course, there are many different methods to aggregate distributed resources -- whether they consist of interruptible or variable loads, distributed energy resources, or a combination of both -- that could also qualify as market-making in this sense. These range from working projects, such as the virtual power plant created by utility RWE and Siemens, now actively participating in German energy markets, to the partnership between ABB/Ventyx and utility E.ON aimed at integrating transmission-scale systems with distributed resources in Sweden. Scores of European smart grid pilot projects are aimed at creating similar capabilities.
From System-Wide Scale to Pinpoint Demand Response
In the meantime, Europe is trying out different mechanisms to provide economic incentives to bring combinations of resources like these into alignment with the grid’s needs. These can apply both at the grand scale of nationwide transmission systems and energy markets, and at the pinpoint scale of specific buildings and specific distribution circuits.
In the U.K., for example, National Grid’s STOR program is being joined by a set of newly created programs under the government’s Low Carbon Network Fund, aimed at relieving grid congestion at the distribution network operator (DNO) level.
One such program is U.K. Power Networks’ Low Carbon London project, which just completed a summer trial run. As part of that project, U.K. startup KiWi Power recently announced that it successfully predicted grid demand and adjusted power use at a set of hotels, hospitals, commercial offices, water treatment plants and public buildings to deliver a total of 47 megawatt-hours of demand response over the course of 45 events.
Distribution utilities like U.K. Power Networks “don’t really care about peak power or supply and demand,” Yoav Zingher, co-founder of KiWi Power, said in an interview earlier this month. “Their primary motivation is network congestion.” In London and other big cities, “The last cables in the ground went in ten to fifteen years ago, and the consumption on those cables has been rising.”
That means that many DNOs are facing a choice, he said. Either they can request billions of pounds to upgrade their circuits to meet growing demand that may peak only during a few moments of the year, or they can invest in demand management technology that can reduce those momentary peaks to stay within operating limits.
In exchange, participating customers get paid a premium for their participation, including extra money when they can reduce demand through demand reduction, rather than tapping polluting on-site diesel generators, he said. U.S. companies with demand response technology, such as Honeywell and EnerNOC, are also working on U.K. projects like these.
Stacking Up Customer Payoffs With Grid Requirements
Coordinating a lot of disparate building-side equipment to reduce power in concert is no trivial task, of course. Both KiWi Power and REstore require customers to install quite a bit of on-site hardware and communications that allow them to measure and adjust power use in ways that add up to just what the grid operator is demanding.
They’ve also invested a lot of time and money into the back-end IT systems to manage the coordination, predictions and economic calculations that help them realize the returns they’ve promised their customers. One example, being pursued by both companies, is so-called “Triad Management” services -- helping customers massage their portfolio-wide energy usage to avoid paying outsized bills in years to come.
As with many commercial and industrial energy buyers, U.K. companies have their rates set in certain periods of the year that represent peak usage times for the grid. In the U.K., those periods are called “triads,” and come during the three hours at which National Grid experiences its peak load -- the year before new rates are actually set.
That means that many power customers can find themselves facing much higher power bills based on peak usage that occurred a year ago, at moments that can’t be pinpointed until long after they’ve already happened. Being able to predict when those moments are going to occur, and then reduce on-site power use across portfolios at those times, can be a big future money-saver.
“Given the amount of data in our system, we have a good prediction engine to help industrial customers to lower their consumption at the best times to avoid these charges,” Jan-Willem Rombouts, co-founder of REstore, said. Likewise, KiWi Power’s Zingher said that triad management is a “pretty good driver of value for our system.” (In the United States, similar market structures, such as mid-Atlantic grid operator PJM’s peak load contribution system, are also being predicted and managed by companies like Viridity Energy.)
Not all European energy markets operate in this way. But companies like KiWi and REstore see them starting to shift in this direction, driven by the disruptive growth of renewable energy and customer-owned generation, as well as European Union mandates for energy efficiency and flexibility. That’s also driving Europe’s interest in the OpenADR standard for automating the interplay between building loads and grid requirements, in a way that the U.S., where the standard was created, is just starting to explore.
“From day one, we planned everything we want to do to be exportable,” Zingher said. “Part of the way we do that is to make everything scalable and cloud-based from our back end.” KiWi also finances its projects from future revenues, in the hopes of reducing buy-in costs from customers.
REstore, for its part, has recently been granted a U.S. patent pertaining to its methods of aggregating a diverse portfolio of energy loads, Rombouts noted. “You really need to manage large flows of data in a very efficient way, and you also need to process that data in a very efficient way,” he explained. “There’s a lot of value in that data.”