One of the big issues with sustainable energy systems is how to store electricity that’s generated from wind, solar and waves. At present, no existing technology provides large-scale storage and energy retrieval for sustainable energy at a low financial and environmental cost.

Engineered electroactive microbes could be part of the solution; these microbes are capable of borrowing an electron from solar or wind electricity and using the energy to break apart carbon dioxide molecules from the air. The microbes can then take the carbon atoms to make biofuels, such as isobutanol or propanol, that could be burned in a generator or added to gasoline, for example.

“We think biology plays a significant role in creating a sustainable energy infrastructure,” said Buz Barstow, assistant professor of biological and environmental engineering. “Some roles will be supporting roles and some will be major roles, and we’re trying to find all of those places where biology can work.”

Barstow is the senior author of “Electrical Energy Storage With Engineered Biological Systems,” published May 3 in the Journal of Biological Engineering.

Adding electrically engineered (synthetic or non-biological) elements could make this approach even more productive and efficient than microbes alone. At the same time, having many options also creates too many engineering choices. The study supplies information to determine the best design based on needs.

“We are suggesting a new approach where we stitch together biological and non-biological electrochemical engineering to create a new method to store energy,” said Farshid Salimijazi, a graduate student in Barstow’s lab and the paper’s first author.

Natural photosynthesis already offers an example for storing solar energy at a huge scale, and turning it into biofuels in a closed carbon loop. It captures about six times as much solar energy in a year as all civilization uses over the same time. But, photosynthesis is really inefficient at harvesting sunlight, absorbing less than one percent of the energy that hits photosynthesizing cells.

In an Order on Rehearing and Clarification issued at its May open meeting, the Federal Energy Regulatory Commission (FERC or “Commission”) generally affirmed Order No. 841, its 2018 Final Rule on electric storage.1 Electric storage resources—including batteries, flywheels, and pumped-hydro projects—are capable of receiving electricity from the grid and storing it for later injection back into the grid. Order No. 841 is intended to pave the way for storage to play a larger role in the wholesale power markets regulated by FERC—a necessity, some argue, as the grid becomes increasingly reliant on intermittent resources such as wind and solar.

In Order No. 841, issued February 15, 2018, FERC determined that current Regional Transmission Organization (RTO) and Independent System Operator (ISO) market rules are unjust and unreasonable.2 FERC determined that the existing rules impose unlawful barriers to participation for storage resources, thereby reducing competition and failing to ensure just and reasonable rates.3 FERC required each RTO/ISO to revise its tariff to establish rules that facilitate storage participation in the wholesale markets.4 Each RTO/ISO must ensure that storage resources can provide all of the energy, capacity and ancillary services they are capable of providing and are eligible to set wholesale market clearing prices as both a seller and a buyer.5

The most contentious issue in the proceeding was a familiar one: where, exactly, is the line between federal and state jurisdiction in the power markets?6 Under the Federal Power Act (FPA), FERC has jurisdiction over wholesale sales of electric energy, including the ISO/RTO markets, as well as the transmission of electric energy in interstate commerce.7 States, meanwhile, have jurisdiction over retail sales of electric energy and the local distribution of electric energy to end users.8 Many electric generators, particularly renewables and other nontraditional resources like electric storage, are interconnected at the state-regulated distribution level, but sell their output into the FERC-regulated wholesale markets. Order No. 841 applies to all storage resources that meet certain technical requirements, regardless of whether they are interconnected to the transmission system, the distribution system or are located “behind-the-meter.”

Several parties argued on rehearing that FERC exceeded its jurisdiction in the Final Rule when it determined that states may not decide whether storage resources interconnected at the distribution level may participate in the RTO/ISO markets. According to these parties, the Final Rule would mandate that storage resources be given access to local distribution facilities, over which FERC has no authority, so that they may reach the FERC-regulated wholesale markets. Putting aside the jurisdictional question, other parties asked FERC to exercise its discretion to adopt a state “opt out” for facilities interconnected to state-jurisdictional distribution facilities, similar to the opt-out provision FERC has provided for demand response.

One must wonder if New Hampshire, after seeing the large size of Vermont’s demand charge savings, has its own peaker envy.

The New Hampshire House & Senate have sent a veto-proof increase to 5 MWac in the capacity of systems that can quality for net metering to the governor’s office to sign. As well, the Senate has passed, and the House is currently reviewing, a bill that will start the process of the state getting 15% of its peak demand from energy storage resources.

Concurrently with the legislative pushes, are increases in solar power that is being built in the state, but not necessarily for the state. Per coverage by Bob Sanders of the local NH Business Review, there is more than 215 MWac (below image) in the state’s queue.

NextEra Energy has two projects totaling 80 MWac of capacity in the pipeline, one of which is the 30 MW Chinook Solar Project in Fitzwilliam that has power purchase agreements bid into Rhode Island, Massachusetts and Connecticut with a two-year delayed completion date scheduled for the end of 2021.

The net metering legislation also has language that doesn’t allow net metered solar electricity to be resold into the ISO New England regional market, as state legislatures wanted to protect in-state electric consumers. The report from the Public Utilities Commission of the state noted that there were 25 projects in the state with a nameplate capacity between 1 and 5 MWac that, once they “no longer have a capacity commitment with ISO-NE or are no longer a registered generator with ISO-NE”, could shift to net metering status. However it was noted that this process takes a long time and wouldn’t have an effect until after fiscal year 2023.

The energy storage legislation first seeks to set up a commission by the end of 2019, that will set in process at least two energy storage pilot projects per utility by the end of 2021. Concurrently, this commission will start a proceeding to determine if an energy storage target, or goal of reducing the state’s peak demand by a specific percentage of up to 15% when discharging coincidentally, would provide net financial benefits to ratepayers.

If it finds that this creates such a financial benefit, some goal – or the 15% specifically – will be set to be met by 2030. The legislation also notes that if it can be done competently, then at least half of the energy storage will be procured by non-utility actors.

“Hard cases make bad law,” or so goes the old legal adage. In light of the Federal Energy Regulatory Commission’s broad attack on state and local jurisdiction in its recent denial of rehearing in Order No. 841, we would suggest you can add, “Popularity contests make for bad overreach.”

At issue are matters related to how energy storage resources will connect to the grid and be compensated for the services they provide. And by any measure, storage is the popular new kid in the school of energy resources. It’s not hard to see why. Energy storage helps solve one of the great conundrums of the electricity world: the need for electricity to be generated at precisely the time it is consumed. 

The more widespread adoption of energy storage holds the potential of making markets more efficient and better enabling resources like wind and solar, whose Achilles’ heels are their intermittency. It’s not hard to see why FERC, and regulators generally, have a crush on the new kid.

Alas, infatuation can lead to decisions with far-reaching consequences. That brings us to the Order No. 841 rehearing requests.

A sweeping expansion of federal authority

A broad coalition of interveners, from non-profit public power, to rural electric cooperatives, to investor-owned utilities and state utility regulators, pointed out the obvious: the way FERC went about effectuating Order 841 was through a sweeping expansion of federal authority over matters once thought to be solely outside of its jurisdiction. 

Specifically, FERC took aim at storage resources embedded within distribution assets. Under the construct of the Federal Power Act (FPA), FERC is supposedly handcuffed when it comes to regulating the distribution side of the utility business.

German renewable energy company Enertrag, Italy’s Enel Green Power and Swiss specialist Leclanché have inaugurated a 22 MW storage facility in Cremzow, in Brandenburg, northeastern Germany. The consortium has invested around €17 million into construction of the large scale energy storage system, which will provide primary control power and help stabilize the grid.

“The Cremzow project shows how storage is increasingly becoming an integral part of renewable energy systems because they make the energy system safer, more flexible and more stable overall,” said Antonio Cammisecra, CEO of Enel Green Power. In addition to the daily contribution to network stabilization, the storage system was also conceived to ensure security of supply. In case of failure of supply, Enertrag CEO Jörg Müller said, the system can be easily restarted.

Müller added, storage can now be developed without public support and can turn a profit. “Renewable energy systems are ready for the market,” he said.

Wind farm storage

According to the consortium, the large scale system in Cremzow will provide primary control power in real time to support the frequency stability of the power network. If grid frequency drops due to high demand for electricity, the battery storage supplies power from the stored energy within 30 seconds. If, in turn, frequency increases due to low demand, the storage system stabilizes the level.

The storage project will also be integrated as a primary control unit for the electricity generated by Enertrag wind farms. The company intends to analyze how excess wind power can be stored in the battery to avoid shutting down turbines.

The owner of the storage project is a special purpose vehicle in which the German subsidiary of Enel owns 90%, with Enertrag having the balance. Leclanché is supplier of the turnkey storage system and is responsible for integrating the battery, power unit and control software.

May 17 (Renewables Now) – Italy’s Enel SpA (BIT:ENEL) celebrated on Thursday the completion and commissioning of a 22-MW energy storage plant in the German state of Brandenburg.

The Cremzow Battery Energy Storage System (BESS) required a total investment of EUR 17 million (USD 19m). It will provide frequency regulation services to the country’s Primary Control Reserve (PCR) market, helping to stabilise the local grid. The facility could also be integrated with ENERTRAG’s wind farms at a later stage.

Enel Green Power Germany (EGP Germany) holds 90% of the special purpose vehicle (SPV) that owns the battery park, while local renewable power company ENERTRAG has the remaining 10%. Swiss energy storage solutions company Leclanche acted as the engineering, procurement and construction (EPC) contractor and manager, Enel noted.

Upcoming electric rate changes in parts of the U.S. mean that almost every home and business here will eventually benefit from a battery connected to their solar system.

These combined systems provide tangible economic benefits: time-shifting energy use, energy arbitrage, preserving the benefits of net metering and demand-charge reduction.

But surprisingly, the vast majority of residential customers are installing battery storage systems for emotional benefits: backup power and cutting their utility ties. Just as it was in the early days of the PV industry, it is challenging for contractors to correlate these economic and emotional needs of customers with the practical realities of currently available (and reliable) battery storage systems.

As our company got back into the energy storage business with lithium-ion batteries, we did extensive research into battery systems and their compatible inverters, into manufacturers, into software and operating modes, and into the interconnection and incentive process.

In spite of our efforts, we encountered a wide range of challenges on our first few installations. There were relatively minor learning experiences such as finding the best ways to transport and mount a 200+ pound battery, streamlining a battery structural permit, and ensuring the battery doesn’t die before being interconnected. And there were major (expensive) learning experiences such as discovering that the battery cannot provide the startup current for even a relatively low horsepower motor (such as a well pump or small air conditioner).

The good news is that we are encountering zero safety issues with regard to residential lithium-ion battery installations. Popular systems on the market are UL 9540 listed, and are equipped with safety features that make it almost impossible to short the battery and create a fire.

In many regards, batteries are safer to install than rooftop solar. Anecdotally, the only safety incident of which I am aware occurred when a battery fell on someone’s foot.