Puerto Rico is still struggling to recover from the damage caused by Hurricane Maria, a Category 5 storm that obliterated the island’s aging and poorly maintained electrical grid. Like many islands, Puerto Rico has depended for years on electricity from diesel and coal powered generators. Virtually all of them were located along the southern coast of the island but the majority of the demand was in the north — not only San Juan but the industrial areas around Bayamòn together with the resort communities of Carolina, Rincon, and Fajardo.

PREPA, the Puerto Rico Electric Power Authority, constructed long distance transmission lines that traversed the mountainous area in the middle of the island to connect supply with demand. Maria decimated those transmission lines. Not only did it rip out the wires, it toppled the towers and stanchions that supported them. After the storm was done venting its wrath on Puerto Rico, there was little left of its electrical grid.

Ahead of a formal announcement on February 12, PREPA has released a draft of its plan to rebuild Puerto Rico’s electrical grid over the next 20 years. According to a report by the Sierra Club, the proposals contained in that draft would divide the country into 8 regional grids that are neither maxi nor mini in size. Let’s call them midi-grids. The regional grids would be interconnected but capable of functioning independently in the event of another storm like Maria. They could be owned by the utility company or private groups.

Taken as a whole, the draft plan calls for the largest build-out of solar and battery storage in the history of the US, according to Solar Industry Magazine. That’s good news for renewable energy advocates. What’s not such good news is the construction of new natural gas powered generating facilities, which will require the creation of three new LNG terminals. Still, natural gas burns cleaner than diesel, especially when it comes to the particulates that contribute to pulmonary and cardiovascular disease that diesel fuels spew into the atmosphere.

“During Hurricane Maria, hundreds of people died simply because they couldn’t keep their insulin refrigerated or their oxygen machines running,” says Adriana Gonzales, environmental justice organizer for Sierra Club de Puerto Rico. “We need the solar and storage in this plan so we can protect health and safety through the next hurricane with distributed, reliable energy infrastructure.

Contemporary Amperex Technology Co. (CATL) launched in China‘s the largest energy storage system with capacity of 100 MWh, which will complement the world’s first multi-mixed energy power station, which combines into one unified system on the grid several renewable sources:

• wind – 400 MW
• photovoltaic – 200 MW
• concentrated solar power – 50 MW

In terms of capacity, the energy storage system is not far from the world’s largest installation of 129 MWh/100 MW, delivered by Tesla in Australia.

The huge battery at the Luneng Haixi Multi-mixed Energy Demonstration Project in Golmud is required to withstand temperatures from -33.6 to 35.5 degrees Celsius over at least 15 years.

More about the system:

California has cleared another obstacle for energy storage installations to be eligible for access to the state’s net metering programme.

The California Public Utilities Commission (CPUC) will continue to break down barriers for energy storage systems. This process ensures on-site renewable energy powers on-site battery systems. Crucially, the CPUC has now said that it is happy with proposals from California Solar and Storage Association (CALSSA).

Solar net metering and storage have not been natural bedfellows thus far with the former nullifying many of the benefits of the battery and contributing to the slow take-up of residential storage systems in the state. The CPUC decision applies to larger systems and is a significant milestone in what has been a lengthy process.

“NEXTracker is overjoyed to see this programme come to fruition and we are so grateful for partners such as the California Solar and Storage Association (CALSSA), the California Public Utilities Commission (CPUC), and SepiSolar for spearheading on the policy front,” said Alex Au, CTO, NEXTracker.

The company has been working with other to demonstrate how solar plus storage systems can use software and firmware to satisfy the conditions set out by the regulator.

“When we set out to enter the PV plus storage marketplace, we envisioned a holistic, fully integrated power plant from the get-go; not a market where individual components roam free, causing delays, sub-optimal performance, and lost opportunities for revenue generation,” explained Au.

“To kick-off this project, NEXTracker worked closely with PG&E, SCE, and SDG&E on the utility side to integrate meter and NEM policy requirements into software functions native to the equipment which would allow for cost reductions in labour and components, maximize NEM credit accruals, and to simplify the approval process. As a unified front, we then took all requirements from key stakeholders and created tests and proposed standards with Nationally Recognized Test Laboratories (NRTLs) such as UL.”

The market for energy storage is poised for rapid growth in New York, but progress could be stymied. A flawed plan from NYISO, the state’s electricity grid operator, threatens to slow the integration of these promising new technologies into the market. The Sustainable FERC Project, Natural Resources Defense Council, Earthjustice, and other groups filed a protest to NYISO’s plan with the Federal Energy Regulatory Commission (FERC) today, urging the nation’s grid regulator to order NYISO to revise its proposal to ensure energy storage resources can participate on even footing in its markets.

With the costs of energy storage technologies like large batteries rapidly falling and their vast potential becoming clear, FERC has made it a top priority for grid operators to update their market rules to eliminate barriers that prevent storage companies from selling their many valuable grid services to utilities and other large energy users. These barriers can slow technological innovation, reduce competition, and increase prices. Markets run by the nation’s regional grid operators were originally set up with power plants and not energy storage resources in mind. Due to operational differences between the technologies, it can be hard for energy storage resources to efficiently participate in those markets.

In February 2018, FERC issued a landmark order (known in the industry as “Order 841”, discussed here) requiring the country’s several regional grid operators to eliminate their market barriers for energy storage resources. Meanwhile, states like New York have taken complementary action to jumpstart the energy storage industry. For example, the New York Public Service Commission (PSC) recently announced a target of 3000 Megawatts of energy storage by 2030, issuing an order that established the regulatory groundwork for a suite of policies designed to galvanize the market. But NYISO’s failure to adequately implement Order 841 now threatens to hinder the state’s plan.

Our coalition is challenging NYISO’s faulty proposal, urging FERC to order NYISO to improve it in three critical areas:

Traditionally, utilities built and operated a portfolio of generation plants consisting of a few large baseload units – typically nuclear or coal – some intermediate plants, and a number of peakers – typically natural gas-fired units with rapid ramping capability. Baseload units ran close to flat out year-round, 24/7; the intermediate units were used to fill the fluctuations in demand; while the peakers were used sparingly to meet occasional surges in demand — say, on hot summer afternoons when air conditioning load would spike for a few hours.

Fast forward to 2019 and beyond and one is likely to encounter a different paradigm, where on many networks an increasing share of generation is provided by renewable resources, most likely wind and solar, neither of which is dispatchable nor totally predictable. In this environment, what the grid operators crave the most is the flexible generation, especially options with a rapid ramping capability to fill in any unexpected shortfalls in renewable generation and to maintain the system’s reliability.

This much is old news. What is new is that recent advances in energy storage technology, especially batteries, coupled with dramatic cost declines is making storage increasingly attractive relative to gas-fired peaking plants, which are not particularly efficient, are highly polluting, and are expensive to maintain. Moreover, since peakers are infrequently used and only for a limited number of hours, they tend to be poor investments, sitting idle most of the time.

A case in point was a decision by San Francisco–based Pacific Gas & Electric Company (PG&E), backed by the regulator the California Public Utilities Commission (CPUC) in Nov 2018, to replace 3 gas peakers with large battery storage units that would be among the world’s largest when completed.

The approved batteries would have a total of 567.5 MW of power capacity with 2,270 MWh of energy storage consisting of a 300 MW, 1,200 MWh project from Vistra Energy and a 182.5 MW, 730 MWh Tesla battery that PG&E would own – all lithium-ion batteries.

Currently, the world’s largest lithium-ion battery is Tesla’s 100 MW, 127 MWh facility in South Australia, followed by Kyushu Electric Power Co. in Japan, which has a 50 MW, 300 MWh sodium-sulfur battery.

The CPUC directed PG&E to proceed with the batteries rather than signing contracts for 3 gas peakers based on analysis that showed that the cost of the batteries is likely to be lower than continuing to operate the gas plants. This, despite the fact that natural gas is plentiful and cheap, is newsworthy.

A megawatt-scale energy storage system will be rented out to power a gold mine in Western Australia by Aggreko, the mobile power solutions company which bought up energy storage provider Younicos last year.

Granny Smith gold mine, open since 1989 and operated by gold producer Gold Fields, will get an 8MWp solar PV array and a 2MW / 1MWh energy storage system which will be integrated with 24.2MW of existing natural gas generation capacity. As with all other Aggreko-Younicos projects since the takeover, the customer will procure the energy storage system under a rental contract.

The US commercial and industrial (C&I) market for energy storage, in particular, has started to see this type of “energy storage as-a-service” offering become more common, with the recognition that many businesses are not willing to pay the upfront capital cost for battery storage. Instead, such business models rely on the customer making savings on energy costs and the provider potentially earning some revenues from grid services, with the benefits shared between the two parties.

Aggreko said that the single service contract Gold Fields signed up to required no capital outlay from the customer, which Aggreko said eliminates technology risk, increases flexibility and ensures accountability over performance.

Construction will commence in May and is expected to finish towards the end of 2019. Fuel consumption at the mine could be reduced by 10% to 13%, with nearly all energy demand required for gold processing to be supplied by the hybrid power system.

The solar will reduce the need for thermal generation, while the battery will be used for a variety of applications, such as providing spinning reserve to local networks, ramp rate control for the PV plant and voltage and frequency support.