Already on the map for its public service microgrids, Montgomery County is advancing into the next frontier of the technology — its nexus with transportation — with plans for a microgrid-ready depot to charge electric buses.

The Maryland county on Wednesday issued a solicitation seeking proposals for energy infrastructure to power electric buses at its Brookville Maintenance Facility in Silver Spring.

A neighbor to the nation’s capital, Montgomery County is Maryland’s most affluent and populated county. It’s also become a leader in microgrids, creating prototype contracts and development procedures for local governments to study and use.

Seeks public-private partnership
The county began exploring microgrids after a violent storm in 2012 knocked out power to 480,000 county residents for several days. Last year it activated two advanced microgrids at its Public Safety Headquarters and Correctional Facility. The microgrids were built in a public-private partnership with Duke Energy Renewables and Schneider Electric under an energy-as-a-service contract.

Now Montgomery County seeks to duplicate the approach. It’s in search of a partner to develop and help finance the smart depot using a minimum amount of county capital and leveraging tax credits, environmental credits and other incentives. The partner will design, build, finance, operate and maintain the smart energy facility.

Microgrid-ready and green
Like a growing number of jurisdictions, Montgomery County has set clean energy goals; it hopes to achieve zero greenhouse gas emissions by 2035. So it seeks clean — as well as resilient — resources to charge the electric buses.

A new project called Advanced Clean Energy Storage has been launched in Utah by a consortium of partners including Mitsubishi Hitachi Power Systems to store energy in a salt cavern. The $1bn project will be able to store as much as 1,000MW in wind and solar power in the form of hydrogen or compressed air by 2025. Umar Ali takes a look.

According to statistics from Carnegie Mellon University, carbon emissions in the US energy sector have decreased by 30% since 2005 due to a combination of renewable energy and natural gas replacing coal-fired power plants.

Having become a global market share leader for heavy duty gas turbines Mitsubishi Hitachi Power Systems (MHPS) has become an important part of the US’ energy transition efforts, and has developed gas turbine technology that allows natural gas and hydrogen to produce power with even lower emissions.

However in many parts of the western US, there are times of day when production of renewable energy is higher than the demand for electricity. This can lead to negative energy pricing and restrictions on renewable generation.

For renewable energy to be viable in the long-term the excess power needs to be stored for later use, which requires a system with a large storage capacity to meet the demands of the entire western US.

A potential solution to the dilemma has come in the form of the Advanced Clean Energy Storage (ACES) project in Utah, which MHPS along with a consortium of partners announced of on 30 May 2019. They are planning to develop 1,000MW of clean energy storage in the world’s largest project of its kind. [Main body]

How does the ACES project work?
The ACES initiative makes use of a domal-quality salt formation owned and controlled by Magnum Development, a “geographically rare geologic formation” and the only known formation of its kind in the western US. Five salt caverns are already in operation for storage of liquid fuels, and Magnum is now developing options for renewable energy like wind and solar power to be stored as compressed air or hydrogen within this salt dome.

The partnership between sonnen, the Wasatch Group and Rocky Mountain Power provides a first-of-a-kind network of solar powered battery storage systems, better known as a Virtual Power Plant (VPP), fully managed by Rocky Mountain Power. The Soleil Lofts apartment community in Herriman, Utah is the result of this partnership. It’s an all-electric residential community design that standardizes on-site energy storage in every unit.

The project features more than 600 individual sonnen ecoLinx batteries, totaling 12.6 megawatt-hours of solar energy storage that is managed by Rocky Mountain Power, the local utility, to provide emergency back-up power, daily management of peak energy use and demand response for the overall management of the electric grid.

Residents will begin moving into the Soleil Lofts apartments in September 2019 and the final building will be complete in December of 2020. Upon completion, the Soleil Lofts community will be the largest fully installed and operational residential battery demand response solution in the United States.

Most people think of energy storage as a thing to run when the lights shut off, however the 112 minutes of downtime that the average rate payer experienced in 2016 doesn’t seem to motivate much energy storage buying in this commercial developer’s experience. What does motivate buyers are demand charges (commercial customers), no solar export laws (Hawaii) and time of use charges (California for residential and commercial customers).

Researchers at the US Department of Energy’s Lawrence Berkeley National Laboratory (LBNL) have published “Implications of Rate Design for the Customer Economics of Behind the Meter Storage.” The document models how electric company demand charges and electricity pricing arbitrage drive the economic payback of energy storage when installed on the customer’s side of the electric meter (behind the meter).

The value of this document is to help a developer determine which leads are valuable – i.e. higher probability to close because they have a fast payback period – and to continue chasing early on in the sales cycle. Go to the end of the article for a real life example of solar+storage lowering a bill wonderfully in California.

The above images focus various demand charge savings, and how they affect payback periods. The specific analysis here is of a shopping center, as the analysis suggested this type of customer would be able to benefit due to their load profile. The document also looked at a flat demand charge manufacturing facility, as well as a shopping center with solar power – whose returns were higher than the shopping center without solar.

What the charts on the left suggests is that a $7/kW demand charge (the dotted line) will drive a ten year payback (right chart). As well, it shows that if your demand peak aligns with the evening demand window the payback period is higher, shorter demand charge billing intervals pay better, and that seasonal and “Ratch” rates don’t really have much of an effect.

Prior research by the National Renewable Energy Labs gives insight into what regions across the country – 70% of electricity tariffs (pdf) – have viable cost structures that would in fact drive the economic paybacks shown above. This research is a couple of years old now, and the regions have expanded as energy storage pricing has fallen.

The above image shows various types of electricity pricing arbitrage can drive electricity bills savings over a year (left image). Customers with Time of Use and Critical Pricing Period + Time of Use billing tariffs have the greatest opportunity by far. These opportunities are less abundant than demand charges though, but they offer potentially greater revenue opportunities than demand charges because of their extreme nature. Texas and Kentucky are noted as the highest paying regions, with California, Florida, Arizona, and a few other states having economic paybacks of interest.

A new report from Navigant Research analyses the global market for energy storage systems (ESSs), providing forecasts of software vendor revenue for upfront system deployment and annual platform access/maintenance fees through 2028.

As the energy storage market matures, technological progress and legislative and regulatory tailwinds have propelled ESS’s to the forefront of industry consciousness. Breakthroughs in adjacent digital technologies, including the Internet of Things (IoT), machine learning, and blockchain, have engendered the creation of innovative software platforms that advance the technical capabilities, economic viability, and bankability of ESS’s. According to the report, Asia Pacific is anticipated to be the largest regional market for energy storage software platforms. Driven by a rapidly growing battery ESS (BESS) market, the region is expected to account for $10.7 billion in cumulative software vendor revenue through 2028.

“Energy storage is flexible, can be deployed rapidly, has numerous applications, and can generate multiple value streams for utilities and their customers,” says Ricardo Rodriguez, research analyst at Navigant Research. “ESS software platforms augment these capabilities and are evolving across market segments, enhanced by underlying digital technologies, to provide complex solutions.”

According to the report, software is expected to play an important role in the energy storage industry as power grids transition toward a distributed, digitised, and decentralised system that Navigant Research refers to as the Energy Cloud. Although energy storage is viewed as a key building block for the grid of the future, without sophisticated platforms for design and control, these systems have limited value.

The report, Energy Storage Software, analyses the global market for ESSs with a focus on aggregation, asset management, and grid services. The study examines business models and pricing strategies for software vendors across three major grid-tied energy storage market segments: utility-scale, commercial and industrial (C&I), and residential. The report also examines the competitive landscape and key technologies related to ESSs.

An Executive Summary of the report is available for free download on the Navigant Research website.

Are you part of the smart energy transition in Asia? If you want to share insights with the leading minds on the continent and around the globe, make sure you’re at Asian Utility Week, co-located with POWERGEN Asia.

Australia, just like the rest of the world, has an increasing voracity for energy. The country has shown its growing propensity for renewable energy sources over fossil fuels.

Renewable Energy – A Logical Choice
With the elevated awareness of the escalating scarceness of non-renewable energy, coupled with the motivation of consumers, governments and industries to not only future-proof their energy sources but to also reduce the damage that energy consumption does to our planet, renewables are the logical choice going forward.

Around 21% of Australia’s energy is already provided by renewable sources, tripling its usage since the earlier 2000s. Renewable energy use in the country is set to continue to grow as Australia hopes to ensure the development of a sustainable energy sector.

The challenge facing this plan is that renewable energy is intermittent, wind and solar energy sources aren’t readily available around the clock. Therefore the energy they generate when the power source is abundant needs to be stored for those times when input is down, to provide a feasible system that provides energy in a consistent manner that the fossil fuel supported grid does. Storage is an issue for renewable energy as power that is generated is usually lost if it is not used.

A Reliable System for Storing Excess Energy

To overcome this challenge, A$15 million are being invested in a project that aims to create a reliable system for storing excess energy produced by solar and wind energy by converting it into hydrogen. Australia’s government will be providing half the funds for this venture, inspired by what has already been achieved in Europe with the TSO 2020 project, which was able to create a system with the capacity of storing 8.3 metric tonnes of hydrogen in underground salt caverns in Holland. Australia’s Jemena H2GO project will develop a 500 KW electrolyzer in western Sydney to split hydrogen from water using excess power generated from renewable sources.

The H2GO project will go further than exploring how to overcome the challenge of intermittent energy supplies from renewables, it will also look into how the hydrogen produced from excess power can be used to support the country’s growing hydrogen-vehicle industry. The project will also utilize existing infrastructure, currently in place to support gas transportation, showing how its process will be more efficient than the alternative, which is storing excess energy in batteries.

Importance of Battery Storage
While battery storage may be less efficient, it is likely to play a role alongside hydrogen energy storage in Australia’s future. The country is currently leading the way in this kind of energy storage, it’s home to 100 MW/129 MWh Hornsdale Power Reserve, the world’s largest lithium-ion battery.

The efforts to lift our power generation and electrical grid into the 21st century is a multipronged effort. It needs a new generation mix of low-carbon sources that include hydro, renewables and nuclear, ways to capture carbon that don’t cost a zillion dollars, and ways to make the grid smart.

But battery and storage technologies have had a hard time keeping up. And they are critical for any success in a carbon-constrained world that uses intermittent sources like solar and wind, or that worries about resilience in the face of natural disasters and malicious attempts at sabotage.

This was pressed home this week by the Department of Energy’s decision to build a multimillion dollar electric grid research complex at the Pacific Northwest National Laboratory. And better, larger batteries are a main component of this research.

Jud Virden, PNNL Associate Lab Director for energy and environment, noted that it took 40 years to get the current lithium-ion batteries to the current state of technology.

We don’t have 40 years to get to the next level. We need do it in 10.

It’s not like we’ve been idle. We just haven’t been wildly successful. Battery technologies do keep getting better. Recently, Jack Goodenough, the inventor of the Li-ion battery, came out with a new fast-charging battery technology using that uses a glass electrode instead of a liquid one, sodium instead of lithium, and may have three times as much energy density as lithium-ion batteries.

And in addition to batteries, we do have other technologies for storing intermittent energy, such thermal energy storage, which allows cooling to be created at night and stored for use the next day during peak times.

At present, the most widely used storage method is pumped hydro storage, which uses surplus electricity to pump water up to a reservoir behind a dam. Later, when demand for energy is high, the stored water is released through turbines in the dam to generate electricity.

Pumped hydro is used in 99% of grid storage today, but there are geologic and environmental constraints on where pumped hydro can be deployed.

Long-duration storage startup Form Energy thought that solving the problem of months-long grid storage would take a decade. But its last year of work advanced faster than expected.

Based on that progress, the team of industry veterans has fast-tracked development and raised a $40 million Series B, co-founder Mateo Jaramillo told Greentech Media. Italian oil and gas major Eni signed on as lead investor, joined by Capricorn Investment Group and most of the existing investors from last year’s $9 million Series A.

Those original investors include some big names, too: Breakthrough Energy Ventures, Prelude Ventures, Macquarie Capital, Saudi Aramco (which didn’t join the Series B), and Massachusetts Institute of Technology offshoot The Engine.

Jaramillo, who previously built Tesla’s energy storage program, teamed up with MIT professor and prolific battery inventor Yet-Ming Chiang and Aquion alum Ted Wiley to found the company last year, with the goal of creating a product to make renewable energy fully dispatchable.

Market for baseload renewables coming soon
Today’s lithium-ion batteries can shift solar power into the evening for a few hours, but they become prohibitively expensive as a tool for weeks or months of guaranteed power delivery. Form Energy tackled that problem in the lab with an aqueous sulfur flow battery chemistry and an undisclosed electrochemical solution.

Meanwhile, the team modeled the economics of a lower-carbon grid to discern where this new type of power plant could go to market, and then performed similar analyses for paying customers.

“It’s gone better than I could have guessed and as well as we could have hoped,” Jaramillo said. “We have gone and had all those conversations with the major industry stakeholders that confirmed this is of interest right now.”

Instead of the initial plan to study the markets and technology for five years and go to market in 10, the analysis showed that an addressable market for “baseload renewables” would arise in the next three to five years, said Jaramillo.

As the behind-the-meter distributed energy storage market continues to mature, a series of factors have propelled residential energy storage systems (RESSs) to the forefront of industry consciousness. These factors include technological progress, legislative and regulatory tailwinds, and new grid challenges associated with intermittent renewable generation.

RESSs can be a highly flexible and valuable resource, improving efficiencies for system owners and the power grid. While residential battery storage has been a growing market in select geographies for several years, the market was primarily driven by early adopters concerned with supporting clean energy or self-sufficiency more than economic self-interest. RESSs were largely regarded by utilities as a niche product for clean energy connoisseurs.

Many utilities see RESSs as a new avenue to improve their services and relationships with customers at a time when new technologies present a real risk of load defection. Utilities around the world recognize these benefits (particularly the ability to reduce congestion on the network and limit the need for peak capacity resources) and have launched programs to deploy RESSs. Utility involvement, cost declines, government incentives, and increased solar photovoltaic (PV) integration are driving increased RESS deployments.

The global RESS market is gaining momentum, with installation growth rates soaring in geographies including Germany, Japan, Australia, and several U.S. states. However, long-standing uncertainties concerning feasible uses and cost-effectiveness remain. As a result, it is vital to support residential utility customers’ ability to tap into RESS value streams that go beyond traditional solar self-consumption. Such support will likely improve the value proposition and increased adoption of RESSs.

Emerging RESS Virtual Power Plants

For residential utility customers, aggregation through a virtual power plant (VPP) is a foundation for unlocking RESS potential to provide grid services. As energy markets evolve toward a greater dependence on distributed energy resources (DERs), strategies to generate more value from smaller, cleaner, and smarter systems are being designed and implemented — including the use of aggregation and VPPs. VPPs transform previously passive consumers into dynamic prosumers that can deliver services customized to their own needs while delivering services to the grid.

At the same time, utility DER management systems (DERMSs) are being designed, piloted, and closely examined for their potential to provide localized grid services. These systems are employed by utilities to control the same DER assets as prosumers, regardless of whether they own the systems or not. Although demand-side VPPs and supply-side DERMSs are closely related, their integration into a common solution set is yet to be fully realized.

On Thursday, Hawaiian Electric issued a long-awaited request for proposals for about 900 megawatts of renewable energy and energy storage projects. It’s the utility’s second major round of contracts in the past year seeking to marry variable solar and wind power with the capacity and flexibility of batteries.

But the Variable Renewable Dispatchable Generation and Energy Storage RFPs that opened on Thursday are a bit more complicated than their headline figures — seeking “technologies equal to 594 megawatts of solar for Oahu, 135 megawatts for Maui and up to 203 megawatts for Hawaii Island” — might indicate.

Unlike its first massive solar-storage procurement in January, HECO’s new RFPs are broken into a number of specific projects and specific needs across its three islands, with a mix of different technologies required. This complexity comes from the fact that these RFPs have been structured to help replace two big fossil-fuel-fired power plants to close in the next five years — the AES Hawaii coal-fired power plant that serves about one-sixth of Oahu’s peak demand, set to retire in 2022, and the oil-fired Kahului plant on Maui, set to close in 2024.

This impending loss of two big spinning generators has pushed HECO and regulators to approve a mix-and-match of technology combination to replace them. That will make them hard to compare directly to HECO’s first round of procurements, as well as the utility-scale solar-plus-storage bids on the mainland.

Developers winning HECO’s first-round RFP in January shocked the industry with prices ranging from 12 cents per kilowatt-hour to a record-breaking 8 cents per kilowatt-hour, as compared to average Hawaiian solar-storage project prices of 11 cents per kilowatt-hour in 2017 and 13.9 cents per kilowatt-hour in 2016.

They also came with some novel structures, such as PPAs that replaced payments based on energy deliveries to lump sums based on net energy potential and availability, to ensure greater dispatchability for critical hours of the day, Ravi Manghani, head of solar research for Wood Mackenzie Power & Renewables, noted.

But “the Phase 2 RFP takes a more technically advanced approach toward resource planning,” Manghani stated in a July GTM Squared article in July, soon after HECO submitted its plan to the Hawaii Public Utilities Commission.