Prepa Wants 8 Minigrids, Various Microgrids With Storage

Editor’s note: The following originally appeared in the Feb. 7 -13, 2019, issue of Caribbean Business.

The Puerto Rico Electric Power Authority (Prepa) is proposing the division of the island’s transmission and distribution system into eight minigrids and a host of microgrids with energy storage. On the supply side, Prepa is proposing at least eight installations, including liquefied natural gas (LNG) projects.

The initiatives are contained in a draft of the integrated resource plan (IRP) that Prepa is scheduled to finalize and submit to the Energy Bureau Feb. 12 as required by Act 57 of 2014.

The IRP focuses on a more resilient energy system that would decentralize power production to avoid the repeat of the islandwide outages caused by hurricanes Irma and Maria. It calls for a shift from centralized generation in the south to more decentralized generation resources distributed across the island.

The IRP is centered on the concept of minigrids, which are defined as zones of resiliency into which the system can be segregated during and after a major weather event or natural disaster, ensuring the load can be served using local resources and supporting the effective and timely recovery from the event. Its implementation will transition the Puerto Rico electric system from one centered on fossil fuels to one in which renewable resources play a central, if not predominant role.

Complementary to the minigrids, smaller microgrids have been identified for those areas, due to geography and system topology, and are likely to remain isolated. Several of these projects are already being recommended for Puerto Rico.

On the supply side, Siemens, which prepared the IRP, examined various long-term capacity-expansion plans and agreed to the following:

  1. Maximize the installation rate for solar photovoltaic (PV) generation for the first four years (2019 to 2022) of the plan. The recommendation is to issue requests for proposals (RFPs) in blocks of about 250 megawatts (MWs), and depending on pricing and Prepa’s capability to interconnect, continue to add blocks with a goal of interconnecting at least 750 MWs and possibly 1,200 MWs over this period.
  2. Install between 500 MWs and 1,100 MWs of battery energy storage in the first four years of the plan. The amounts of battery storage are heavily correlated with the total number of PVs to be installed and the local energy supply required for the minigrids into which the system is expected to segregate during major events.
  3. Convert the San Juan Units 5 & 6 combined cycle (CC) to burn natural gas. This option is an ongoing initiative using a ship-based LNG terminal and was adopted as a given in the formulation of all plans where there is new gas development.
  4. Develop a land-based LNG terminal in San Juan to supply a new CC gas turbine (CCGT) and San Juan’s Units 5 & 6 CC.
  5. Install a CC gas turbine at Costa Sur Steam Plant or extend a renegotiated contract with EcoEléctrica. Under all cases, unless the contract with EcoEléctrica is renegotiated to significantly reduce the fixed payments and the plant is allowed to cycle frequently, EcoEléctrica is replaced by a 300 MW CCGT after the contract expires in 2022.
  6. Install new GTs capable of burning containerized natural gas. The need to serve critical and priority loads within the minigrids for resiliency resulted in the necessity to add 17 to 18 small GTs of 23 MWs each at selected locations in the grid; specifically, Caguas (Yabucoa), 5 units; Carolina (Daguao), 5 units; Cayey, 2 units; Ponce East (Jobos), 2 units; and Mayagüez North (Aguadilla), 2 units, among others.
  7. Develop a ship-based LNG terminal in Mayagüez.
  8. Develop a ship-based LNG terminal in Yabucoa.

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U.S. energy storage market to nearly triple this year: report

U.S. deployments of energy storage systems will nearly triple this year thanks to sharply lower costs and state policies that support the case for installing batteries in homes, businesses and along the power grid.

That forecasted growth of 186 percent to 1,233 megawatt-hours of storage from 431 MWh compares with the 27 percent increase in 2017, according to a report by GTM Research and the Energy Storage Association trade group published on Tuesday.

That’s in part because some large projects that had been expected for 2017 were pushed into the early months of 2018, but also because the market for batteries in homes and businesses is finally taking off, according to GTM analyst Ravi Manghani, who said that part of the market logged growth of 79 percent last year.

The growth in the use of batteries for electricity storage has been a boon to manufacturers such as Tesla Inc., LG Corp. and others.

The Tesla Energy Powerwall Home Battery is unveiled by Tesla Motors CEO Elon Musk during an event in Hawthorne, California April 30, 2015. (REUTERS/Patrick T. Fallon/File Photo)

Storage system costs have fallen by roughly two thirds in the last five years, Manghani said. In addition, more states are mandating utilities procure storage systems.

The market for energy storage is still small, generating just $300 million in value last year, the report said. But batteries have long held the promise of solving the intermittent nature of renewable energy sources such as wind and solar, so their development is closely watched by investors, regulators and power companies. The market is expected to exceed $1 billion in 2019, the report said.

 

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Pairing big batteries with renewable energy projects improves reliability without creating climate-changing emissions, and more homeowners and businesses are looking to batteries for backup power and to capture the excess energy from rooftop systems to use when the sun is not shining.

Large systems for utilities are still the biggest segment of the market, and more utilities are including storage in their solicitations for solar projects, Manghani said, adding that a year from now he would expect most solar project solicitations to include a storage component.

“There is a big sort of shift in mindset,” he said.

(Reporting by Nichola Groom; Editing by Susan Thomas)

Public comment period on Puerto Rico microgrid regulations opened




Tesla to build giant battery in Australia amid energy crisis

Tesla CEO Elon Musk talks about the development of the worlds biggest lithium-ion battery in Adelaide, Australia, Friday, July 7, 2017.  (Ben Macmahon/AAP Image via AP)

SYDNEY – Tesla announced on Friday it will build the world’s largest lithium-ion battery in southern Australia, part of a bid to solve an energy crisis that has led to ongoing blackouts across the region.

Tesla will partner with French renewable energy company Neoen to build the 100-megawatt battery farm in South Australia state, with Tesla CEO Elon Musk promising to deliver the system within 100 days of signing the contract or it will be free. The billionaire entrepreneur originally made the 100-day pledge via Twitter in March, and he and South Australia’s government confirmed on Friday that the deadline was part of their official agreement.

“The system will be three times more powerful than any system on earth,” Musk told reporters in the state capital, Adelaide. “This is not like a minor foray into the frontier – this is like going three times further than anyone’s gone before.”

South Australia, which relies heavily on solar and wind-generated energy, has been scrambling to find a way to bolster its fragile power grid since the entire state suffered a blackout during a storm last year. Further blackouts plagued the state over the next few months.

The battery farm is part of a AU$550 million ($420 million) plan announced in March by South Australia Premier Jay Weatherill to make the state independent of the nation’s power grid. The Australian Energy Market Operator, which manages the national grid, has warned of potential shortages of gas-fired electricity across southeast Australia by late next year. The shortage is looming as Australia is expected to soon overtake Qatar as the world’s biggest exporter of liquid natural gas. Australia is also a major exporter of coal, which fires much of its electricity generation.

The South Australia battery will store energy from Neoen’s Hornsdale Wind Farm near Jamestown, about 200 kilometers (120 miles) north of Adelaide. It will deliver energy during peak usage hours to help maintain the state’s supply, and could power 30,000 homes, Tesla said.

“You can essentially charge up the battery packs when you have excess power and where the cost is very low, and it discharges when the cost of production is high – this lowers the average cost per hour to the customer,” Musk said. “It’s a fundamental efficiency improvement.”

The installation of the battery is expected to be complete by December. The cost of the project has not been released.