“VPP” is the latest electricity-system-of-the-future phrase in the expanding smart-grid lexicon. Virtual power plants (VPP) are the latest concept promising to improve distribution-system reliability and, possibly, to limit the need for new peak-period generating capacity, enabled by improved communications and response technologies.
As the word “virtual” implies, this vocabulary addition refers to power resources accessed through software, instead of physical generating facilities. These resources may be in the form of a rooftop solar panel, a garaged electric vehicle’s battery or the ability to take designated customer equipment offline to reduce system demand. Developers now are testing ways to combine both supply and demand options for rapid response to changing power requirements.
“A virtual power plant combines elements of demand response and distributed generation in a way that allows them to be dispatched as if they were another power plant,” said John Simmins, a senior project manager with the Electric Power Research Institute, a group leading a number of VPP demonstration projects. “It doesn’t matter if you’re reducing capacity or adding it. It all results in the same thing.”
Like the phrase “smart grid,” the meaning of VPP can vary, according to Peter Asmus, senior analyst with Pike Research, an energy-technology research and consulting firm. In Europe, especially in Germany, VPPs are focused primarily on the supply side of the energy-delivery equation, he said. There, Siemens is a major player, initiating VPP efforts by tying together the output of nine smaller hydroelectric operations as though these distributed resources were a single power plant. Currently, Asmus said, the company is harnessing the output of approximately 30 different renewable-energy installations scattered throughout Germany to create an even larger scale VPP.
In the United States, VPP plans have targeted demand-response options.
“You’re basically just aggregating demand reduction,” he said.
Through research, some major industry groups are looking to combine both demand and supply-side options, along with energy storage, to create what VPP developers call a “mixed-asset” power plant.
The advantages of mixed-asset designs at the local distribution level are pretty obvious. At periods of peak demand, the utility could rapidly send signals to participating customers’ equipment to reduce demand. The company also then could tap into customer-side supply resources, such as the batteries in connected electric vehicles, to gain the marginal amount of power needed to stabilize grid operations. The temporary additional supply would cost considerably less than the electricity the utility would otherwise have to purchase.
Billions and billions
Regardless of the configuration, VPPs are becoming a big business. Global VPP revenues reached $5.2 billion in 2010, according to Pike Research, which expects it to hit at least $7.4 billion—possibly as high as $12.7 billion—by 2015. Capacity could rise to 67.5 gigawatts (GW) during that time, from the 2009 global total of 19.4 GW.
One reason for this potential growth is the effect VPPs could have on utility efforts to boost distribution-system reliability. According to Simmins, New York City’s Con Edison is reaching out to commercial customers with generating capacity, renewable or otherwise to see if VPPs are a viable alternative to conventional backup substation-transformer designs.
A substation site in Queens designed with “N+1” redundancy is the basis of a pilot effort that is testing such a strategy; that is, a backup transformer is in place and ready to come online should any of the site’s other three transformers fail. The utility, backed by a Department of Energy grant, is investigating whether distributed generation and demand-response resources could be pooled to keep the distribution system running if a second transformer failed, called “N+2” redundancy.
Such a capability could prove invaluable in New York’s congested and expensive real estate environment, saving much more than just the cost of additional transformer equipment. For example, adding a second backup transformer could require a larger site, and costly infrastructure improvements would be needed. Creating the same capability with software and algorithms could mean big savings for utilities and their ratepayers.
Operators of regional transmission systems also are interested in new power resources of the virtual variety. As the overseers of networks supported by multiple generation sources, system operators face the challenge of maintaining power quality, for example, ensuring electricity is delivered at a steady 60-hertz (Hz) frequency over great distances. Doing so can require operators to call on generators to add or drop generation to the broader system in a process called regulation.
According to Chantal Hendrzak, general manager of applied solutions, PJM Interconnection, the regulation market is small—about 1 percent of PJM’s total load—but expensive. Generation companies bid to participate, turning control of a plant over to PJM, which can pulse generated electricity into the transmission system to maintain 60-Hz performance.
System-regulation needs are greatest at night, when demand is low, but generation plants are still active. In fact, wind turbines are most productive at night. Hendrzak said a new and potentially widespread resource, electric vehicle batteries, could provide an alternative to large, centralized generating plants for grid-balancing needs during such off-peak periods. Previously, systems like PJM’s weren’t capable of addressing such small loads, but with addressability now down to as little as 100 kilowatts, virtual power plants composed of a collection of individual homes could help meet regulation demands.
PJM’s interest in this topic is important because of its ranking as the world’s largest competitive wholesale electricity market, with more than 54 million customers, according to its figures. As a regional transmission organization, it coordinates the purchase and movement of electricity over transmission lines in all or part of 13 states and the District of Columbia. It is not a utility or generating company itself, but it has the capability to control generator operations, depending on the agreements with those facilities’ operators.
In a VPP scenario, PJM could have similar control agreements with the owners of both on-site generating equipment and building owners who are able to curtail their demand quickly. The group has pilot projects underway to test both equipment responsiveness to PJM signals and bottom-line business cases. And, recognizing the potential of new electric vehicles, PJM also is working with standards groups to help incorporate communications and controls into developing technologies.
“We’re really engaged with the Society of Automotive Engineers because we want to talk with them about managed charging and what it means to integrate with the grid,” Hendrzak said.
Many of the technology hurdles, including issues involved in connecting renewables and energy-storage devices to the grid, have been crossed, she said. However, bringing these various technologies together poses challenges today.
“Batteries are old technology; so is solar,” she said, adding that VPPs, however, require software-based optimization engines and algorithms to evaluate the combinations of generation and demand response best suited to meet current grid needs.
Policies and pricing
Beyond the required technologies, VPP developers also are investigating the policies and pricing questions these new virtual resources could raise. After all, when it comes to electricity, the word “regulation” has two meanings, and the policies that regulate electricity pricing will require just as much attention if VPPs are to become more common as all those algorithms.
“In some ways, you can create this right now; a lot of it is not technology-based, but regulatory,” Asmus said, noting the complicating factors facing utilities and public utilities commissions must face before bringing VPPs to market. He cited just a couple of the bigger questions all parties will need to answer: How will you get paid? How will you bill?
The billing and payment questions will become very complex very quickly, especially if utilities start reaching down to individual homeowners to build out their VPP networks. Smart meters will help managers track residential contributions, but deployment of these intelligent devices now is under fire in some regions, Asmus said. Some of his sources have suggested customer pushback in California and other areas may have delayed VPP development by as much as a year.
PJM is pursuing answers to these questions, as well. As a marketplace, PJM is constantly monitoring demand across its network and making estimates of immediate and future electricity needs. It sends signals out to electricity suppliers for bids to meet those needs, and those vendors might be VPP operators capable of aggregating demand and supply resources. Hendrzak said future success in these efforts depends on addressing a range of hypothetical questions today.
One such query from a VPP supplier might be, “If I go and sell my automated demand response to buildings or businesses, where will I make money?” PJM has historical data that can provide direction. PJM, itself, might need to consider variable reimbursement rates for some VPP configurations, such as those including rapidly evolving energy-storage devices.
“They are increasingly responsive, so we’re looking at should we be paying more for higher performance?” she said.
And, like Asmus, Hendrzak said some of the biggest questions target current rate schedules for residential customers. This means working with state public utility commissions and local distribution companies to develop time-of-use pricing programs to tie retail electricity costs to actual market conditions, so you get the right incentives from virtual power plants down to the retail customer.
As Hendrzak said, these users now pay flat rates, regardless of overall grid-demand conditions.
“If we can get more transparency down to the virtual power plants, we will give them the price signals that will be a benefit to the grid and a benefit to the customer,” Hendrzak said.
ROSS is a freelance writer located in Brewster, Mass. He can be reached at firstname.lastname@example.org.