Loading weight to take weight off the load
September 28, 2016: Despite a proliferation of highly nuanced business models, utilities and solar-and-storage companies continue to fine-tune their approach to using energy storage as part of a virtual power plant, reports Sara Verbruggen.
In the US a variety of drivers, which vary by region or state, are responsible for the growing demand for solar-plus-storage.
In Hawaii, where its island grids are straining under the pressure that peak generation from renewables — mainly rooftop solar — exerts, consumers face some of the highest energy costs, meaning an investment in a solar-plus-storage system can pay for itself within 61/2 years.
However, back-up is emerging as a key selling point across many parts of the US. In states such as Utah and South Dakota, back-up goes hand in hand with customers wanting more energy independence.
In New York, a recently announced pilot led by Con Edison intends to find out what residential electricity customers are prepared to pay for resiliency.
Unlike Germany, the largest residential solar-plus-storage market by installed capacity and demand, where the technology might achieve payback in 10 years — that’s with an incentive — in the US the conversation has always been about monetizing solar-plus-storage.
That requires joined-up thinking among utilities, technology providers, regulators and the buy-in, of course, from energy customers.
To monetize solar-plus-storage a battery must cater to multiple parties, each of which derives a saving or a revenue stream from the asset.
First the battery’s primary application must be for the customer’s benefit, such as back-up and energy bill savings, by increasing solar consumption. The remaining capacity of the individual storage unit can also be harnessed, along with other units, to provide grid balancing.
Eventually, the grid as a whole is expected to benefit from distributed storage on the tips of the network because growth in renewable energy, like rooftop solar, is decoupled from the need to make investments in expanding the grid.
But an odd benefit all the same.
This requires utilities working with technology providers to see how distributed solar-plus-storage can be deployed as virtual power plants on their networks, in doing so extending the potential for rooftop solar PV uptake.
The Molokai solution
On the Hawaiian island of Molokai, the end of net metering has paved the way for solar-plus-storage. But the grid is unable to connect any of the tail-end of net-metering customers.
So the utility Hawaiian Electric Companies (HECO) is working with energy storage and software developer E-Gear. E-Gear was set up by Chris DeBone and Steve Godmere, the founders of solar installer Hawaii Energy Connection.
E-Gear’s offering consists of a hardware and software platform that enables self-consumption for the residential electricity customer but which connects individual systems in a network and makes them act as a single virtual power plant that the utility can control and manage.
“How does energy storage compare with solar PV? In 2016, you have to be fast, nimble and quick to market. This is a long way from dumb rooftop solar PV systems,” says DeBone.
On Hawaii some solar installers have branched out into installing batteries and solar, systems that can enable consumers to virtually go off-grid by taking solar and pumping it into batteries — DC-coupling.
“What’s left is scraps for the utilities, when consumers start taking loads off the grid. This grid defection is not the way to go. What consumers want is lower bills and security of supply. They shouldn’t have to go virtually off-grid to achieve this,” DeBone says.
E-Gear has developed a proprietary energy management controller — a circuit board with software embedded in it that interfaces with cloudware. Every system installed is interconnected in the cloud. The company has sourced an AC battery from Eguana Technologies in Canada, which comprises Eguana’s bidirectional inverter connected to a lithium ion battery module from LG Chem.
However, the energy management control and software developed by E-Gear is hardware agnostic.
The software tools, including those for aggregation, which E-Gear has developed, enable the consumer to have functions such as self-consumption and back-up.
But the tools also allow a party such as an installer, an aggregator or a utility to manage fleets, which collectively can be deployed as virtual power plants. The software is open platform/ protocol — Sunspec — so that it can be overlaid over different inverter hardware makes.
In the pilot on Molokai, HECO is buying 10 of E-Gear’s energy storage systems, which will interface directly with the utility’s own grid software.
“The problem faced on Molokai is that renewables penetration has reached such high levels no new rooftop solar can be added as it will create system level problems.
“This is because large amounts of intermittent solar generation are now causing frequency and contingency issues on the island. The existing fossil fuel generators are not able to idle down far enough on some peak solar days,” says DeBone.
When California Independent System Operator (CAISO) presented its now-notorious duck curve chart, it was based on a prediction into how the grid would look with increasing amounts of solar capacity connected, becoming more acute towards the end of this decade.
More solar means greater reliance on base load power generation. On some of Hawaii’s grids the duck curve has already come home to roost and utilities are turning to solar integrated with battery storage to alleviate the problem.
On a neighbouring island, Kauai, the local utility, Kauai Island Utility Cooperative (KIUC) signed a power purchase agreement with SolarCity in September 2015 for electricity from what will be the largest integrated solar PV and battery storage facility project commissioned to date.
The facility when fully operational at the end of 2016 will supply power from stored solar energy to the grid in the evening — when demand is highest.
The 52MWh battery system will feed up to 13MW of electricity into the grid to shave the amount of conventional power generation needed to meet the evening peak, which lasts from 5pm to 10pm.
Bob Rudd, vice president of energy storage and microgrids at SolarCity, says: “It’s very apt to take CAISO’s duck curve and apply it to Hawaii, where Kaua’i’s grid is already experiencing these extreme effects where traditional generation plants have to be ramped up to meet the peak evening energy demand that solar cannot.”
Though the solar and storage facility will meet 5% of the island’s energy demand over the year, which does not sound like much, it will meet between 20%-25% of evening peak demand, as the 13MW can offset the 55MW of base-load generation.
The integrated battery gives KIUC the opportunity to use solar PV as a dispatchable resource, operating it like a thermal generation plant, by scheduling how much power they need it to provide at various times.
On Molokai, there are about 100 remaining net-metering customers that are in the queue. It doesn’t necessarily mean that HECO will need to install a storage system with the remaining 90. It may mean that the peak shifting that the one battery enables and the grid services that the batteries in aggregate can provide, could allow a further two or three more customers to be grid-connected just with rooftop solar.
DeBone describes Hawaii as a petri dish of problems that larger, more resilient, usually mainland grids will come to face in future. On the islands, which are really a group of separate microgrids, these problems have occurred in a compressed amount of time.
“As Hawaii nears 100% renewable energy levels, there will likely be a need for storage at the transmission, distribution and meter levels but the recent interest is in what storage at the meter or circuit level can do, because it can do a lot, with the right software,” says DeBone.
The first storage projects to mitigate intermittent wind and solar built on the islands of Hawaii were bulk storage plants designed for energy shifting but little more.
Now intelligent distributed energy resources in the form of solar-plus-storage systems promise a more sophisticated solution. Not only do these systems control loads in the home, when to charge up and release power, and where to send it, they also let the utility access some of the capacity that is not being used to perform critical grid services such as frequency response and reactive power.
In the pilot on Molokai, E-Gear’s storage systems will allow HECO to deploy a suite of tools including frequency control, voltage control, fast frequency responses, power factor and control as well as time shifting to ease the duck curve effect.
E-Gear’s storage units are autonomously programmed to start charging, taking into consideration their location in relation to the sun’s trajectory. On the eastern side of the island, the sun is up earlier than on the west. Vice versa, the sun sets later in the western side of the island than on the east, so depending on where each storage system is located on the island they are programmed accordingly.
E-Gear also has a pilot in California in Fontana, with Southern California Edison and the Electric Power Research Institute, where nine new homes all on one distribution connection will have solar and storage installed to demonstrate that they can have zero impact on the grid.
With battery prices falling and solar-plus-storage becoming more affordable each year, it could be a blueprint for all new homes construction in future, says DeBone.
E-Gear has five dealers in southern California and just took possession of a warehouse in the state. It will shortly begin exporting its battery systems there.
In Hawaii, E-Gear continues to establish further dealerships. Business is brisk and picking up, it says, with the company having ordered a container of battery systems, about 500kWh worth. This is already sold, with the company placing repeat orders.
PG&E, SolarCity pilot
SolarCity, one of the largest rooftop solar installation businesses in the US, announced a project in July with investor owner utility Pacific Gas & Electric (PG&E).
In the pilot, which starts in September and runs until December 2017, 150 residential customers in San Jose, in California, will have smart inverters, with their rooftop solar systems installed.
Some of the participants will also have residential battery storage systems installed. PG&E will coordinate the smart inverters and behind the meter battery storage to improve electric distribution planning and operations.
For the pilot SolarCity is enrolling new customers in addition to installing the systems within some of its existing customer base in the San Jose. As they are installed, the smart inverters and storage systems will be integrated into SolarCity’s software control platform Gridlogic.
PG&E is running several pilot programmes to demonstrate different technologies and use cases, some of which include smart inverters on their own and some thatinclude smart inverters paired with batteries. SolarCity is to take part in both versions of the project, by providing smart inverters paired with solar PV, as well as smart inverters paired with batteries.
Smart inverters — either paired only with solar, or paired with solar and batteries — offer a host of grid benefits, including improving power quality, supporting voltage regulation needs, providing reactive power support, reducing line losses, and enabling dynamic control of PV generation output.
“By deploying smart inverters along with solar PV, this project will offer services that would otherwise have been performed by traditional grid investments,” says SolarCity’s Ryan Hanley, vice president of grid engineering solutions at SolarCity.
Energy storage systems paired with smart inverters offer all the benefits of smart inverters, but with additional capabilities enabled by the battery.
Battery storage systems can provide services such as peak shaving, dynamic capacity, spinning reserves, frequency regulation, and frequency response. They can be dispatched almost instantaneously to provide additional power when it’s needed most, whereas traditional generators often take between 20 and 60 minutes to respond to grid operator control signals.
“By installing smart inverters and home batteries together, pilot participants will be able to provide a wider range of services to the grid,” says Hanley.
A virtual power plant is not anasset that a utility owns and operates in the traditional sense, so there have to be some adaptations to how such platforms are connected to the grid, to respond to the utility’s commands without actually being controlled by the utility.
SolarCity — soon to become part of Tesla after a sale price of $2.6 billion has apparently been agreed — is providing PG&E with two ways to control its virtual power plant of aggregated smart inverters through its Grid Logic software control platform.
Hanley says: “The first control method is directly through the Grid Logic user interface, which SolarCity offers to utilities and grid operators to control the portfolio of distributed energy resources.
“Through the Grid Logic interface, utilities can control both the individual smart inverter or battery assets in the pilot, as well as aggregate and control the entire portfolio as a fleet. The second control method is through integration with a utility Distributed Energy Resource Management System (DERMS) platform.”
In this project, SolarCity’s software will be integrated with General Electric’s DERMS platform. “PG&E will issue controls that are then passed through SolarCity’s Grid Logic software controls, to control the smart inverters and battery management systems,” says Hanley.
Once control through Grid Logic and DERMS is established, PG&E and SolarCity will demonstrate the ability of the asset portfolio to carry out several technical use cases. These include dynamic capacity, peak shaving, and voltage and reactive power support. Grid Logic enables both the control of these assets, as well as monitors them to ensure they perform as expected.
SolarCity provides both utility-scale and distributed grid services for utilities and grid operators.
Hanley says: “Our products are available for less than it might cost to build traditional generation from fossil fuel plants or T&D infrastructure investments. Grid needs that can be addressed include peak demand shaving, voltage and reactive power support, frequency regulation, and grid situational intelligence.
“These frequently use distributed energy resources, such as smart solar connected inverters, or batteries, that are already deployed, and so are available to utilities at a discount to traditional investments needed to meet these needs.”
Given the company’s integrated product offering, large customer base, operational scale, and full-service support, SolarCity is in a strong position as an energy services provider for utilities and grid operators.
“The company’s Grid Logic platform comes pre-integrated with the systems it installs. As the number one residential solar provider in America, we already have an extensive customer base and can rapidly deploy new distributed energy resource portfolios across the country,” says Hanley.
Germany-headquartered Sonnen is working with several utilities, spanning cooperatives, municipal utilities as well as investor-owned utilities that will be piloting its systems to see how they perform aggregated as virtual power plants. These will be announced later this year.
Recently Sonnen partnered with Enbala Networks, a vendor of aggregation software, which is looking to integrate distributed energy storage systems into its platform and take this offering to utilities.
Third party software
“From a utility’s perspective they don’t want a Sonnen software platform as well as various other platforms to manage,” says Boris von Bormann, chief executive of US subsidiary Sonnen Inc. “They want to manage these units in the same way, which means that third party software providers, independent of storage system manufacturers, will be important.”
Enbala was set up seven years ago, initially to design software for manipulating energy loads for purposes of frequency regulation for PJM Interconnection and continues to manage 10MW of aggregated loads for PJM.
When Enbala’s chief executive Bud Vos joined, the company began extending the software into other areas, including demand response, and voltage response/optimization applications.
In its partnership with Sonnen, Enbala is able to overlay its distributed energy control and aggregation software over Sonnen’s energy storage technology. The partnership will allow utilities and energy companies, including third party energy service providers, to control and manage solar-plus-storage resources as virtual power plants to provide grid ancillary services.
Sonnen is not the first provider of meter-level energy storage systems using Enbala’s software. It is also used by two other energy storage system providers, which are active in the commercial and industrial segment but which prefer not to publicize that they use the company’s software technology.
Enbala’s customers include utilities, grid operators and energy service providers, mainly in North America.
Vos says: “We teamed up after Sonnen could see that unlike the grid system in Germany, which is unified, the system in the US is very different across the various states.”
In the US Sonnen wants to focus on improving its storage system technology, including the behind the meter energy management system controls side, which addresses how its systems interact with the rooftop solar PV system as well as the different loads in the house or the building.
The partnership allows Sonnen to focus on expanding its distribution network with installers while Enbala can target utilities and grid operators. Regional markets that the partnership will focus on include Hawaii, California and Texas.
As well as trialling various different types of distributed energy resources, such as solar-plus-storage systems connected to advanced software control platforms, the virtual power plant pilots taking place will help inform new policy and regulation.
This is critical if utilities are to be able to adapt what their role is going to be in future — how they continue, fundamentally, to manage the grid and maintain a good quality of service, affordably, but not doing it the traditional way of building as many power stations as possible or expanding the grid network via conventional means of installing new cables, wires and transformers.