The research was carried out by Robert Mokaya, Professor of Materials Chemistry, and Troy Scott Blankenship, an undergraduate project student, in the School of Chemistry and has been published in the academic journal Energy and Environmental Science.

Professor Mokaya said: “We have utilised cigarette butt waste as starting material to prepare energy materials that offer unprecedented hydrogen storage properties. This may not only address an intractable environmental pollution problem – cigarette butts – but also offers new insights into converting a major waste product into very attractive hydrogen storage materials.”

Hydrogen is attractive as a fuel because whether it is burned to produce heat or reacted with air in a fuel cell to produce electricity, the only by-product is water.

Solving a major waste disposal problem

Every year nearly six trillion cigarettes are smoked worldwide. This generates more than 800,000 metric tons of cigarette butts. Apart from causing unsightly litter, cigarette butts contain contaminants such as toxic heavy metals which can leach into waterways potentially causing harm to both humans and wildlife.

Cigarette butts – used cigarette filters – are a lingering pollution hazard because they mainly contain cellulose acetate which is non-biodegradable. However, the cellulose acetate makes them an attractive starting material for valorisation to porous carbons. Such valorization is in line with the current trend to move away from coal-based carbonaceous precursors to biomass-derived or waste-based starting materials for porous carbon synthesis.

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Energy flows from the Permian Basin in more forms than crude oil and natural gas. West Texas is home to some of the nation’s largest wind farms, and work has been done on developing solar and geothermal energy as well.

Now West Texas is becoming home to the development of energy storage, which will become an important piece of future energy infrastructure. Essen-Germany-based E.ON, an energy network, customer solution and renewables-focused company, has broken ground on two short-duration energy storage projects on its wind farms near Roscoe.

Texas Waves, located on E.ON’s Pyron and Inadale wind farms, consists of two 9.9 megawatt short-duration energy storage projects using lithium-ion battery technology. Texas Waves is designed to provide ancillary services to the Electric Reliability Council of Texas market in order to respond to shifts in power demand quickly and increasing reliability and efficiency. The projects will be E.ON’s second and third grid-connected lithium-ion battery systems installed in North America and are expected to be online by the end of the year.

Mark Frigo, vice president of energy storage, North America, at E.ON, provided some insight on Texas Waves via email.

MRT: This may be an elementary question, but are lithium-ion batteries already a part of the wind farm industry?

Frigo: Actually, not really. These batteries are becoming a growing part of the overall power industry, and especially the renewables industry (wind + solar) because they are becoming much more cost effective. They are a solution to the generation intermittency problem that is inherent with renewable generation.

MRT: Power is an integral part of oil and gas production, which is integral to West Texas. How can Texas Waves impact power availability?

Frigo: The Texas Waves projects will help maintain frequency regulation within the ERCOT grid. In a U.S. electricity grid, the alternating current (AC) frequency needs to be held within tight tolerance bands around 60 Hz. If the frequency falls outside of this tolerance band, generators begin to go out of synchronization triggering events that can quickly lead to catastrophic grid collapse (i.e. blackouts). Energy storage allows grids to quickly maintain that tight tolerance, thus protecting against blackouts.

MRT: What kind of jobs is this project creating and how many?

Frigo: Texas Waves has immediately created 50 construction jobs. Note that the batteries are fairly automated, and integrated into the existing Pyron and Inadale wind farms. These wind farms are managed by our West Texas team, which numbers approximately 100.

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Over the last few weeks, the state of Puerto Rico’s electrical grid has been on everyone’s mind in the power industry. Getting Puerto Rico back online has been the Puerto Rico Electric Power Authority’s (PREPA) top priority, and rightfully so. The devastated country’s grid was knocked almost entirely offline.

Efforts now are focused on getting everyone’s lights back on as soon as possible – not necessarily building out an impressive, ground-breaking new electrical system in the process. Utilities and suppliers across the United States have come together to help rebuild Puerto Rico, but rebuilding should just be the first step. We also need to look to solve Puerto Rico’s long-term power needs.

Once Puerto Rico is back on solid ground, with power running across the country, then the time will come to discuss what to do next.

This U.S. island commonwealth is at great risk for similar destruction the next time a large tropical storm or hurricane rolls through. There is no simple solution to harden the island’s grid, but recent events prove that change needs to happen to address future events.

Even before Hurricane Maria hit, Puerto Rico did not have the most reliable grid. While it is difficult to think about long-term solutions when so much needs to be rebuilt, improving grid reliability and resiliency should be a priority. With that in mind, what if the utility moved to an underground distribution system (at least in part) instead of an entirely overhead distribution system?

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Powin Energy, the Oregon-based energy storage developer, is expecting to see an uptick in non-recourse financing following a landmark project this month.

The company secured construction financing for an 8.8-megawatt/40.8-megawatt-hour battery plant in Stratford, Ontario, from Brookfield Renewable Partners, one of the largest independent renewable energy businesses in the world. 

“Securing non-recourse financing is a critical step for energy storage assets themselves, as well as the broader market,” said Geoffrey Brown, Powin Energy president, in a press release. “We believe that closing a deal of this nature with a well-respected group like Brookfield is indicative of market maturation and Powin’s future prospects.”

While the non-recourse funding model is commonplace in most renewable energy markets, the track record is more limited in energy storage. Only a handful of deals have made headlines.

Last year, for example, another Ontario project based on flywheels and lithium-ion batteries and built by Convergent Energy and Power was funded through a non-recourse finance package from CJF Capital and SUSI Partners’ Energy Storage Fund I.

“The facility reflects a non-recourse, third-party project financing structure for energy storage assets in a sector dominated by on-balance-sheet financing,” noted Convergent in a press statement.

Previously, non-recourse finance had helped fund Australia’s first utility-scale integrated solar and battery project, built by Conergy with backing from Norddeutsche Landesbank Girozentrale.

And in 2015, half the money for the Jake and Elwood battery storage projects developed by Renewable Energy Systems Americas came from non-recourse senior secured project financing debt.

Brown said he thought many energy storage projects since had been difficult to fund through non-recourse debt because of the nature of their contracts.

Following the Stratford deal, though, Brown told GTM he expected non-recourse funding to become the norm for energy storage projects with clear, fixed revenue streams.

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Historically, the vast majority of the world’s power has been consumed as quickly as it is made, or it’s wasted. But climate change has made governments interested in renewable energy, and renewable energy is variable—it can’t be dispatched on demand. Or can it? As research into utility-sized batteries receives more attention, the economics of adding storage to a grid or wind farm are starting to make more sense.

But grid-tied energy storage is not new; it has just always been limited to whatever resources a local power producer had at the time. Much like electricity production itself, storage schemes differ regionally. Power companies will invest in batteries that make sense on a local level, whether it is pumped storage, compressed air, or lithium-ion cells.

Looking at the kinds of storage that already exist is instructive in helping us see where storage is going to go, too. Lots of the latest battery projects merely build on engineering that has been in service for decades. To better see our way forward, we collected a number of images and diagrams of the world’s biggest energy storage schemes.

Pumped storage

Pumped storage is possibly one of the oldest forms of modern grid-tied energy storage, and it certainly packs the most punch as far as megawatt-hours delivered.

The way it traditionally works is simple: the system has a bottom reservoir of water to draw from and a top reservoir that’s topographically higher than the bottom reservoir. When there’s not a lot of demand for electricity, you use that power to “charge” the battery by pumping water up to the top reservoir. When demand for electricity is high, that reservoir can be drained via a hydroelectric generator, back down to the bottom reservoir.

In the future, Germany is looking at using old coal mines for pumped storage, and some German researchers have been working on building giant concrete spheres that can function as pumped storage containers after they’re placed on the ocean floor.

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Having been subject to discussion for years within the academic sphere, energy storage projects have become a topic of high interest to energy sector focused investors in recent years.

Decreasing cost curves, changing regulatory environments within the energy markets such as deregulation and shifts away from subsidised renewables to market pricing modes, and evolving software capabilities, are increasing investor confidence in energy storage investments and result in increased demand for investment opportunities.

While this seems to be true especially for more mature renewable energy markets like Europe, the United States and several others, investors are facing the problem that energy storage projects as investments are – in most cases – discussed on a very abstract basis. Only considering the “big picture” and seeing the project as a future pillar of the energy market leaves out details such as the complexity coming with energy storage investments in practice.

In my opinion, the propensity to drastically reduce complexity by discussing energy storage as high-level topic has developed based on two major factors:

Firstly, energy storage is still a new topic in the market compared to the long history of energy generation and transmission. Hence, while accumulators and especially batteries seem to be part of consumers’ lives ever since, the discussion about energy storage as a viable part of the electricity market structure is relatively trendy and new. In addition, due to the high diversity of technology types and their evolution, economies of scale and market consolidation (as seen currently in the photovoltaic market) are not yet reached. This leads to different potentials, resulting in an ultimate mess of investment cases. Supported by the fact that storage investments are often declared as a “venture capital topic”.

Second, the high variety of different operational modes results in a high density in varying underlying business models. This depends heavily on local electricity market structures, including installed generation capacities, energy balance, share of renewables and subsidy situation.

In summary, the combining factors of a high density of different technology types and development stages as well as the high variety of different usage types have led to a situation where energy storage is often considered only as party of the big picture, thus not helping investors in getting viable information most relevant to them.

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The Indian energy storage industry hopes a 28-megawatt-hour battery plant in the Andaman and Nicobar Islands will kick-start a utility-scale market that has been slow to emerge.

“This will help open up opportunities for such hybrid projects in India,” said Dr. Rahul Walawalkar, executive director of the India Energy Storage Alliance (IESA), after Indian EPC provider Mahindra Susten this month won the project tendered by state-owned coal mining company NLC India.

“With the development of a local ecosystem and skills training, we are confident that solar and storage will continue to have accelerated adoption in India in coming years,” Walawalkar said. “This should also help companies that are considering setting up manufacturing in India.”

IESA has a vision of making India a global advanced energy storage systems manufacturing hub by 2020, he said. Given India’s track record on utility-scale energy storage, the aim is ambitious, to say the least.

Prior to the Andaman and Nicobar project, the Solar Energy Corporation of India (SECI) and NTPC, India’s largest power utility, had already launched three other utility-scale energy storage tenders in the country.

However, “all these tenders, with aggregate capacity of 35 megawatt-hours, have been scrapped without any reasons being given,” noted analyst firm Bridge to India in a blog post.

“Our view is that storage will need three [to] four years of techno-commercial advancements before finding scale in India,” wrote the organization. 

The lack of progress on utility-scale storage in one of the most important renewable energy markets in the world is due to a mix of pricing challenges and lack of technical expertise, according to Bridge to India.

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While the global transition of energy systems away from fossil fuels and towards renewable energy, electrification and distributed energy solutions is being increasingly accepted as inevitable, that does not mean that it is either easy or simple.

There are few regions in the United States where this is more true than in New England. While the overall region lags well below the national average in terms of solar and wind deployment, several states have pushed bold policies and are at times among the national leaders in terms of sophisticated approaches to system transformation.

Yesterday’s New England Solar and Storage Symposium by Greentech Media took a deeper look at the policy and market conditions of the region, without shying away from the very real challenges that New England faces.

Distributed solar in the crosshairs

For renewable energy, geography matters. New England has a wet climate with poor year-round solar radiation, and is one of the most densely populated regions in the United States. Both population pressures and an over-representation of affluent residents who are not used to seeing energy infrastructure has hindered land-based and even offshore wind.

And while the clouds, the density and historical settlement patterns also present challenges to large-scale PV projects, New England has excelled in deployment of distributed solar. Massachusetts and Vermont in particular boast some of the highest levels of residential and commercial installations on a per-capita basis in the United States.

This has been backed by aggressive policies, and one entire panel was dedicated to Massachusetts’ SMART program, a declining block grant incentive program designed to replace Solar Renewable Energy Credits (SRECs) and facilitate Governor Charlie Baker’s goal to deploy an additional 1.6 GW of solar on top of the 1.6 GW under the previous program.

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With costs plunging, Portland General Electric Company (NYSE: POR) is prepared to pursue a lot more energy storage than the puny amount required under an Oregon mandate.

In its quarterly earnings call on Friday, the utility told analysts it will soon propose spending between $50 million and $100 million on 39 megawatts of energy storage.

Oregon legislation passed in 2015 requires PGE and Pacific Power, the state’s big investor-owned utilities, to acquire at least 5 megawatt-hours each of energy storage, with a limit of 1 percent of their 2014 peak loads.

PGE’s 2014 peak load was 3,866 megawatts, so at 39 megawatts it would be maxing out the opportunity.

How many megawatt-hours 39 megawatts translates to will depend on the nature of the proposed systems — some could provide short-term grid support services, others longer-duration energy storage.

With their costs falling rapidly, lithium-ion batteries are the dominant storage technology today, and some systems now going in can operate at full power for four hours (in other words, a 1 megawatt system can deliver 4 megawatt-hours of electricity).

PGE spokesman Steve Corson said details of the company’s plans would be made public when it files a proposal next week with the Oregon Public Utility Commission, but he outlined a wide range of possible projects.

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