California's Demand Response Revolution

California is moving another step closer to strengthening its grid through a new mechanism to provide compensation for demand response.

The Demand Response Auction Mechanism (DRAM) is a program which allows demand response providers – including those in solar storage, behind-the-meter batteries, load control, and EV charging – to get compensation for providing services to the grid.

This is good news for a number of California demand-side players including Tesla, SolarCity, Stem, Green Charge Networks, Advanced Microgrid Solutions, EnerNOC and Comverge, to name a handful.

Providers have two ways of getting paid.

First, the California Public Utilities Commission (CPUC) has called on California’s three large investor-owned utilities to collectively procure 22 megawatts of capacity through demand response. The idea is that by having control of resources that can cut down on load during peak times, ratepayers benefit from reduced capital expenditures and the elimination of emissions from gas peaker plants.

Second, demand response will soon be allowed to bid into the wholesale market on a much wider scale. DRAM allows demand response providers to pool together portfolios of EV chargers, smart thermostats, behind-the-meter storage and more, and bid these resources into the wholesale market as an alternative to traditional generation.

Let’s look more closely at these two opportunities.

Capacity payments

In California, electricity retailers are required to demonstrate that they have procured enough generation capacity to meet projected peak loads. Traditionally, this capacity requirement has been met primarily through bilateral contracts with generators.

But since 2014, the California Public Utilities Commission has examined ways of expanding the role of distributed demand response. DRAM introduces a bidding process, allowing any demand response providers who can meet certain requirements to make their assets available to help the utilities meet their capacity requirements. In exchange, utilities pay these demand response providers a capacity fee based on the number of kilowatts they can provide to reduce peak load when the grid needs it.

In the DRAM capacity auction, demand response providers are called on to offer a price for their capacity. Providers are keeping these prices secret, as the market is highly competitive.

The 22-megawatt procurement is a minimum amount set by the utilities commission, so there is the possibility that utilities will procure more. In an effort to drive up residential demand response, the utilities commission has required that at least 20% of the procured capacity should come from the residential sector.

Utilities will select the winners of this procurement at the end of the month.

Wholesale market

Beginning next June, approved demand response resources will be able to bid into California’s wholesale electricity market.

In this system, the wholesale prices paid to these demand response providers will vary depending on their location. Due to the fact that some regions are grid-constrained or may have imbalances in supply and demand throughout the day, the wholesale price of electricity also changes. Using these price signals, demand response providers can choose where to focus their efforts, and then bid their assets into the day-ahead wholesale market.

The first step in the wholesale market process begins in February, and we won't see demand response on the market until June. In the meantime, demand response providers will be tested to make sure they can deliver the load curtailment they say they can. In case they fail to deliver when they hit the market, the providers will have to pay for the load curtailment they fail to provide.

The DRAM program also promises to make changes to how California’s grid looks for solutions to ramping problems caused by California’s rapidly growing solar generation base. This is a topic we will cover in a future piece.

Dispatches from San Diego, pt. 4

This is part four in a series on our trip to San Diego for the Energy Storage North America conference and expo. Here are parts onetwo and three.

It’s a long flight from Beijing to California, so it’s not every day that our Chinese members have the opportunity to visit demonstration projects in the United States. We wanted to make the most of our San Diego trip, and so scheduled a trip to Borrego Springs, a community two hours away hosting a 26 megawatt solar facility and a 4.5 MWh lithium-ion battery energy storage system owned and operated by San Diego Gas & Electric. The batteries were provided and installed by Saft, with PCS from Parker and ABB.

The microgrid was funded in part by the Department of Energy and the California Energy Commission to build energy resilience in a remote community within California’s largest state park. The community’s population fluctuates between 2,500 and 10,000 residents, causing seasonal swings in load. Most importantly, the community is served by only a single transmission line strung in rugged terrain, leaving the community vulnerable to prolonged outages due to fire, lightning strikes, or floods.  

The microgrid has already proven itself as a powerful back-up system. During a planned transmission maintenance outage in May, the utility was able to switch customers to microgrid-supplied power after only a 10-minute outage. According to Jeff Mucha, project manager at SDG&E, that outage length was necessary to maintain personnel safety while flipping switches manually. The company is currently installing automation systems to make it possible to control microgrid services from SDG&E headquarters in San Diego.

This facility demonstrates the myriad values that microgrids can provide. In many ways, it was the ideal bookend to a trip that began with a visit to UC San Diego’s microgrid. One site was a telescope looking at the future technologies and business models that can help achieve grid stability and reduced carbon emissions in an urban, EV-heavy setting. The other, by contrast, showed how microgrids and energy storage can build resilience in isolated communities with plentiful solar resources.

Big thanks to Jeff Mucha and Donna Miyasako-Blanco at SDG&E, and Linda Haddock at the Borrego Springs Chamber of Commerce.

This is the final part of our blog, Dispatches from San Diego. See parts one, two, and three.

Dispatches from San Diego, pt. 3

This is part three in a series on our trip to San Diego for the Energy Storage North America conference and expo. If you haven't yet, check out parts one and two.

Today was the last day of the Energy Storage North America conference. Today's themes were grid services, finance, and technologies. We heard from grid regulators, policymakers, and technical experts, including Dr. Imre Gyuk, Energy Storage Program Manager at the Department of Energy.

Distributed Storage at the Market Edge

A morning panel featuring California policymakers focused on how distributed storage can interface in electricity markets.

The panel noted that utilities were tasked with examining the value of energy storage on their grids. At the time, utilities came back saying that the technologies were mature, economical, or proven enough for widespread use. Five years later, we’re seeing thousands of megawatts of interconnection requests for distributed storage, reflecting the effectiveness of California’s subsidies and the growing value propositions of these technologies.

During the Q&A session, a representative from Trina Solar, asked how policies can help China manage the problem of having long distances and constrained transmission between renewable generation and load centers. The simple answer given was to build more power lines. But the panelists also stressed the importance of building a diversified renewable asset base.

In a later panel, two grid experts continued the conversation about the role distributed energy storage can play on the grid edge.

James Gallagher, executive director of the New York State Smart Grid Consortium, described how New York’s Reforming the Energy Vision (REV) program is trying to better align utility practices with the goal of integrating more grid edge resources. Because New York has the oldest electrical grid in the country, REV also aims to help deal with the challenges of using older grid assets.

To do this, he said, REV is helping utilities procure distributed assets to meet their operational needs. The plan intends to introduce further market mechanisms to incentivize deployment. For example, the cost of electricity distribution is averaged across a utility’s consumer base, but in reality, the actual cost of delivery may vary by a factor of a hundred. Clarifying the actual costs of running a distribution grid gives third parties an opportunity to make a profit by introducing distributed resources like storage to locations where it is needed most.

He also touched on the issue of financing. Because increasing ratepayer fees to finance upgrades can be hard for utilities, there is an opportunity for microgrid players, who can raise money from third party sources to build and operate assets which traditionally were owned and operated by utilities. He also noted that insurance companies are becoming aware that record storms and heat waves driven by climate change are going to put community resilience to the test. Insurance companies have access to big pools of money that can finance power system upgrades, including energy storage, that build resilience in the face of global warming.

Technologies and Standards

Dr. Imre Gyuk, Energy Storage Program Manager at the US Department of Energy, gave a presentation on new technological breakthroughs in energy storage and efforts to establish better codes, standards, and regulations affecting energy storage system safety.

He highlighted work being done in energy storage at several national laboratories. Pacific Northwest National Laboratory (PNNL) has made breakthroughs in mixed acid vanadium redox flow batteries by developing electrolyte with 80% improved temperature stability and 70% better energy density. This technology has been licensed out to several big flow battery producers, including UniEnergy, Imergy, and WattJoule.

He foresees the system cost for vanadium redox flow batteries (RFB) to fall from $325/kWh in 2015 to $275 by 2017. He also shared projections that aqueous soluble organic flow batteries will become commercially viable in the medium term, with projected system costs falling to $150/kWh by 2021.

The Department of Energy is also working to resolve energy storage safety issues. The Department has published an inventory of codes and standards to help industry players better design, install, and operate their technology. The document also provides a list of best practices to respond to incidents involving energy storage technology.

The conference finished off with free beer at a reception at the San Diego Convention Center. It struck us how large this event is – a signal that the industry is really picking up speed, especially in the United States. This year, there were over 1800 attendees, 110 exhibitors, and over 150 speakers. We’re happy to have come – we’ll certainly be back next year.

Our fourth and final part in this series takes us to Borrego Springs, where SDG&E is pioneering microgrids and solar power to bring energy resilience to an isolated community in the desert.

Dispatches from San Diego, pt. 2

This is part two in a series on our trip to San Diego for the Energy Storage North America Conference and Expo. If you haven't yet, check out part one.

The first day of the expo and conference featured our debut on the conference floor, and discussions about California's massive storage procurement and the future of solar storage.

Sharing What We Know…

Vivian Wei, director of member services, and I made the final touches CNESA’s booth on day one of the expo. We’re here to share information about our efforts to promote energy storage policies and technologies in China. CNESA member companies we saw in the crowd included Primus Power, Schneider Electric, NGK, Sifang, Today Energy, ENN Group, Parker, Trina Solar, Sumitomo Electric, Imergy, Saft, ABB, GE and more.

The expo was a great opportunity for manufacturers, integrators and other energy storage players to share their technologies and business models with potential customers. For industry associations like CNESA, this is a chance to show the world what we do, and bring new members into the fold.

…And Learning from the Experts

Conference sessions also began today, focusing on three themes: distributed energy, hot markets, and utility-scale storage.

In a utility session, representatives from California’s three largest utilities discussed what lessons can be learned from their procurement of 350+ MW of energy storage capacity. Although the representatives were in consensus that their energy storage portfolios should be diverse, commercially sustainable, and flexible, questions posed in the Q&A segment about how utilities value different energy storage technologies, both now and in the future, were left largely unanswered.

Utility representatives said that their procurement requirement standards are expected to rise in 2016, which suggests that Chinese and other international companies should find suitable and experienced local partners if they intend to bid their products into California’s electricity markets.

In a distributed energy session, three industry experts from different backgrounds looked ahead at opportunities for solar-plus-storage. The panel featured Boris von Bormann, CEO of German battery business Sonnenbatterie; Ruud Kempener, analyst at the International Renewable Energy Agency (IRENA); and Barbara Lockwood, general manager at a US utility, Arizona Public Service.

Ruud Kempener challenged industry watchers to expand their perspectives beyond large-scale projects in developed countries, and consider the market possibilities for small-scale solar-plus-storage projects in countries with unstable grids and low rates of electrification. He remarked that although the cost of solar-plus-storage systems are often still too high to be considered cost competitive, they hold great value by providing grid reliability and resilience. Nonetheless, in the United States and Europe, cost competitiveness is still the most critical factor for the success of solar-storage projects.

Barbara Lockwood described how her utility is restructuring rates to encourage smart energy decisions. She argued that net metering – which reduces electricity bills for solar customers by subtracting total electricity produced from the electricity consumed from the grid – doesn’t accurately reflect the cost of electricity at various times, and discourages the adoption of technologies which can help utilities keep the grid stable. Solar panels cease to produce electricity at sundown, but load remains high well into the evening. In areas with high solar penetration, this means that utilities have to quickly ramp up generation in ways which can be costly and inefficient. Lockwood claimed that new rate structures, such as demand rates – which charge a consumer a separate fee based on the level of their peak consumption during a month or year – can encourage the use of energy storage technologies to even out load spikes which can cause instability and inefficiency in the grid.

Our trip blog continues in part three, where we hear from experts on distributed storage and breakthrough technologies.

California’s Integrated Demand Side Management Proposal

California’s utility regulators are proposing to take the grid a step further towards the edge.

Earlier this September, CPUC Commissioner Mike Florio released a proposal that would represent the next step towards larger deployments of grid-connected distributed energy resources (DER).

This summer saw California’s major utilities each present a Distributed Resource Plan. These explored how distributed energy resources could provide value to grid operators. Commissioner Florio’s new proposal aims to clarify how that value can be passed on to consumers through novel pricing signals and other mechanisms. This proposal, the “Decision Adopting an Expanded Scope, a Definition, and a Goal for the Integration of Demand Side Resources,” set a new goal to integrate demand side resources “that provide optimal customer and system benefits, while enabling California to reach its climate objectives.”

According to Greentech Media, the proposed decision was the result of workshops that included CNESA partner, the California Energy Storage Alliance, among other advocacy, business, and regulatory organizations.

While the actual mechanisms for compensating and sourcing demand side resources that perform grid services are yet to be discussed in future workshops, this proposal marks a further step for California on the path towards integrating demand side resources into the grid. Stem’s policy director, Ted Ko, remarked in a CPUC meeting that the proposal could allow utilities to look to their customers to provide grid services like capacity, ramping, and voltage support.

Nonetheless, some participants expressed concerns about the scope of the proposal. In particular, utilities and CAISO, the California grid operator, asked for clarification about the risks involved with decentralizing grid resources. If the resources don’t show up when they’re needed, who should be responsible? How should mechanisms be designed to ensure that the electric system is reliable?

To answer remaining questions about how specific mechanisms should be designed, the CPUC will hold further workshops. In a later phase, the Commission will look at potential pilot programs to provide data on sourcing and pricing mechanisms. 

Energy Storage in the Philippines

As a country of more than 7,000 islands with a lagging power system and some of the highest electricity prices in Asia, one might expect the Philippines to be a hotspot for energy storage.

Credit:  Renz Ticsay

Credit: Renz Ticsay

Although widespread deployment of energy storage in the Philippines is yet to come, there are some significant drivers, both on and off-grid, that are already attracting energy storage players to this emerging market.

Market drivers

As a tropical archipelago with few fossil fuel resources, the Philippines faces unique energy challenges. According to the Philippines Department of Energy (DOE) 49% of installed capacity relied on imported oil and coal in 2011, leaving Filipinos highly exposed to international price volatility. This is especially true in rural islands, where microgrids are powered primarily through diesel generators.

The Philippines is also expected to undergo significant demand growth. By 2030, projected demand is expected to be 29.3 GW, a 60% increase from 2012, according to a KPMG report from 2013.

Filipinos are also concerned about the effects of climate change. Because the Philippines is densely populated near coastlines and is highly reliant on agriculture, it faces some of the most serious consequences of climate change. This reality has driven the Philippines to search for clean energy solutions that are resilient to extreme climate events.

In this context, the Philippines are actively promoting an energy reform agenda that aims to ensure energy security, improve energy prices, and develop sustainability.  Since 2008, favorable policies for renewable energy have driven growth in solar and wind deployments. As intermittent renewables begin to take up a greater share of power generation, the grid is likely to require energy storage technology to ensure grid reliability.

Applications for energy storage in the Philippines

Several potential applications for energy storage stand out in the Philippines, particularly in grid-side storage, island storage, and behind-the-meter applications. At this time, lithium-ion batteries are the primary advanced energy storage technology in use, though lead acid batteries -- mostly imported from China -- have been used in off-grid storage applications for at least a decade.

Grid-side storage

Frequency regulation is in its early stages in the Philippines. A local subsidiary of energy giant AES Corporation announced plans in July 2015 to deploy 200-250 MW of battery energy storage in the Philippines. This announcement came on the heels of a resolution made by the Energy Regulatory Commission (ERC) allowing battery energy storage systems to provide ancillary services.

The Philippines is also shifting toward renewables in power generation. In April 2014, the ERC revised its solar target from 50 MW to 500 MW, and raised its solar feed-in tariff cap accordingly. As of June 2015, that cap was already maxed out, and industry advocates are pushing for a further revision. This suggests that the Philippines solar market is picking up speed. The rise of renewable energy as a significant part of the Philippines’ energy mix will necessitate further energy storage deployments to ensure the stability of the electric grid

Off-grid applications

Although the Philippines achieved 86% electrification in 2013, that rate falls to 65% in rural areas. According to the National Electrification Administration, there is a market potential of 2.5 million unconnected households in the Philippines.

Additionally, electrified rural island communities often rely heavily on diesel generation, which is both expensive and sensitive to disruption. A study conducted by the Reiner Lemoine Institute in 2014 estimated that a hybrid system comprised of 6.7 MW of solar PV plus a 1 MW lead acid battery system and an existing diesel generator could achieve savings of $0.073 per kWh, serving over 100,000 inhabitants.

Another study from German development organization GIZ estimated that, given the deployments of off-grid diesel generation in the Philippines, the expected potential revenue from battery sales in off-grid diesel hybrid applications will be around $27 million in 2030.

Due to the fact that the price of diesel has dropped significantly since these studies were conducted, the value proposition for diesel hybrid systems may not be as attractive as it was in 2013, but energy security remains a key driver for battery systems that can reduce diesel consumption.

Behind-the-meter applications

Consumers in the Philippines pay some of the highest electricity tariffs in Asia. At least one utility, the Manila Electric Company, offers voluntary time-of-use rates for their customers, which could provide a value opportunity for battery installers.

More importantly, as the GIZ report notes, consumers such as factories and hotels benefit highly from back-up energy storage devices due to the unreliability of the grid. These entities are also more likely to have access to the financing necessary to install these systems.


As is true of other emerging energy storage industries, there are regulatory and market challenges to the deployment of energy storage technologies in the Philippines.

AES planned to begin operation of a 40 MW battery storage project in Kabankalan, Negros Occidental to provide ancillary services as early as March 2015. Regulatory hurdles have resulted in delays, and the project has yet to come online. This suggests that challenges from regulatory bodies and grid operators continue to hamper the deployment of energy storage technology. According to a GIZ report, this may be especially true for foreign enterprises, which are most likely find success by partnering with local players.

The GIZ report also notes that access to capital is a particular challenge. Projects under EUR 5-10 million may have difficulty acquiring funding from development banks. However the report also notes that there is a growing number of programs organized by the International Finance Corporation and the Philippines DOE which provide financing for sustainable energy projects.

In terms of off-grid battery storage applications, the sharp decline in the cost of diesel will likely impact the attractiveness of hybrid solar/diesel/storage projects.  According to statistics from the DOE, diesel prices in the Philippines have fallen by 40% since the summer of 2014. This will squeeze margins for potential solar storage projects, which rely on long-term fuel savings to counterbalance high upfront costs.

Due to the fact that the Philippines are prone to natural disasters such as flooding and typhoons, energy storage systems must be built to withstand extreme weather. This may increase the upfront cost of energy storage systems. However, successful demonstrations may also highlight the advantages of battery-supported systems in the aftermath of natural disasters, when logistics networks, grid services, and diesel deliveries are disrupted.

Overall, while the challenges facing energy storage technology in the Philippines are significant, the fundamental drivers of storage are strong. Partnerships with local developers and support from development agencies may help overcome regulatory and financing hurdles.

Additionally, as battery prices continue to fall, this market will become increasingly attractive.