The burgeoning as-a-service model, offering greater user flexibility and attractive economics, is now a viable option for energy storage. As with transportation, office equipment, and other capital-intensive assets, large-scale energy users both on and off the grid can leverage the benefits of battery storage on a use-only-what-you-need-when-you-need-it basis. What is the main driver behind this new offering? Flexibility.

Removing the Risks

There are several reasons why storage-as-a-service makes sense in today’s fast-evolving energy landscape. First, long-term ownership commitments may lead to stranded assets and tied-up capital (especially with relatively new technology). In certain cases, it might be better to rent a system and see if it proves valuable. Second, as-a-service solutions provide maximum flexibility when market conditions shift. For example, when regulations or the value of ancillary services change, users can more easily adapt. Third, rental customers can generally contract with one supplier who takes responsibility for system design, performance, and maintenance—a “one-stop shop.” These new approaches to system deployment offer a virtually risk-free, 100% reliable solution.

There are also compelling arguments for the as-a-service model that apply in particular to batteries. For example, potential customers may have concerns about battery life and whether their investment will be compromised. New technology is continually coming on the market, which could render their newly acquired asset obsolete. As with solar photovoltaic technology, there’s a perception that prices will continue to decline. Why buy now if it’ll be cheaper tomorrow? Faced with a purchase decision, these concerns can lead to hesitation, limiting a customer’s ability to capture energy storage benefits immediately. The more-flexible as-a-service alternative eliminates these risks.

A final point worth mentioning is that batteries typically have long lead times, ranging from nine to 18 months, depending on market conditions. Most established providers that offer storage-as-a-service have inventory available that can be delivered on short notice (typically less than three months), enabling customers to realize the benefits faster.

Convenient Contracts and Configurations

Storage-as-a-service contracts start with periods as short as a few months (although multi-year terms are far more economical). Typically, agreements are based on a regular monthly or annual fee. Terms can be easily adapted to fit changing business needs. Customers receive guaranteed 24/7 system reliability for zero asset investment and with low implementation costs, including 100% service coverage. All operations and maintenance costs, remote monitoring, performance guarantees, and warranties are covered under one contract and fee.

From both a regulatory and development perspective, 2018 was a significant year for the expansion of energy storage resources (ESRs). From a significant ruling of the Federal Energy Regulatory Commission (FERC), to the presentation and implementation of aggressive state initiatives, rapid ESR deployment continues unabated while ESR technology costs continue to decline precipitously.

Undeniably, ESRs have arrived as a credible, useful component of a resilient and efficient grid. This article explores common ESRs and how they contribute to grid stability, the FERC’s impact on the development of markets to compensate ESRs, and how states are playing a pivotal role in advancing the development of ESRs.

ESRs and the Grid
An electric storage resource is defined by FERC as “a resource capable of receiving electric energy from the grid and storing it for later injection of electricity back to the grid regardless of where the resource is located on the electrical system.” Common examples of ESRs include batteries, pumped storage facilities, and compressed air energy storage.

Because ESRs have the flexibility to consume or inject electricity, they can be used by grid operators and market administrators to balance supply and demand efficiently. Generally, grid operators identify the ability of ESRs to shift load as a consumer when load is low and as a supplier when load is high. ESRs can help manage peak demand, manage the integration of intermittent resources (such as solar and wind facilities), and defer distribution and transmission upgrades.

Because of their ability to store energy for later deployment, ESRs have the capability to mitigate demand during peak consumption periods. Additionally, because certain ESRs have the ability to ramp up and down rapidly in response to grid requirements, they are particularly useful in assisting grid operators in integrating increasing levels of intermittent, renewable sources of power.

Resources such as solar and wind do not have defined production patterns, and often they need to be curtailed for economic reasons. ESRs have the capability to flatten the production curve for such resources, thereby enhancing grid reliability.

Finally, ESRs can help operators manage transmission congestion. Grid operators are often confronted by congestion in areas of the grid that lack sufficient transmission infrastructure, particularly during peak periods. During such periods, lower-cost resources may not be able to be dispatched to serve load. ESRs strategically located on the uncongeste

Ørsted’s first standalone battery energy storage system has now entered operation.

The 20MW battery, located in Carnegie Road, Liverpool, consists of three battery units as well as a power conversion system.

The firm said infrastructure of this kind is vital to help balance the UK’s electricity grid by ensuring consumption matches the amount of power generated at any given moment.

Highly flexible batteries can quickly respond to grid requirements and are seen as a valuable component of a modern, decarbonised energy system.

Matthew Wright, UK Managing Director at Ørsted, said: “Climate change is a real and pressing threat to our planet and in order to minimise its effects, we urgently need to decarbonise our electricity system.

“Batteries and other innovative storage technologies will form a critical part of an integrated green energy system required to ensure we keep the lights on without harming our planet.”

The project is the first large energy storage facility built by EMC Lendlease, the joint venture between Energy Made Clean, a wholly-owned subsidiary of Carnegie, and Lendlease, an engineering, procurement and construction (EPC) provider. As the module supplier, Risen Energy provided more than 30,000 mono-crystalline modules to the facility.

The modules have been tested by Clean Energy Associates, an American owned and operated global solar PV engineering and quality assurance technical services advisory firm, and are highly adaptable to the local climate conditions in Western Australia in that they can maintain stable power output in hot and dry environments and ensure a high ROI by reducing costs.

The 25-hectare PV power station has now been fully connected to the grid and is estimated to be capable of generating 24 GWh of clean electricity over the next 25 years.

According to the latest data from the China Photovoltaic Industry Association (CPIA), module exports by Chinese PV manufacturers maintained growth during the first ten months of 2018, with the proportion of exports to Australia climbing from 6.0 in 2017 to 10.7 percent. Risen Energy has successfully exported its modules to Australia but also participated in the construction of many large power stations across the country, in full compliance with local standards for project design and development. Among the several projects, Yarranlea, in which Risen Energy played an important role, was specifically pointed out for praise by Dr. Anthony Lynham, Queensland Minister for Natural Resources, Mines and Energy.

Li Bin, general manager of Risen Energy Australia, said, “Our steady expansion in Australia is driven by the company’s innovative products and technologies which can meet the needs of consumers in different regions. Looking ahead, our company plans to invest in renewable energy projects totaling over 2GW in Australia and will continue to expand in the energy storage sector. As for some upcoming acquisitions, we are in the process of seeking financing or EPC partners as well as looking for co-developers.”

2018 is over, and a new year of energy evolution is upon us.

The past year laid a robust foundation for growth in 2019. It ended with six states and territories, including two of the three largest state economies, committing to 100 percent clean electricity. The solar industry weathered the much-feared tariffs without excessive bleeding. The list of cleantech failures was much shorter than in previous years.

There’s still plenty of room to grow. Solar only accounts for 1.3 percent of U.S. electricity generation, and wind produces 6.3 percent. Grid edge technologies are helping the grid adapt, but they’re still in limited real world use.

Keeping in mind that contrast between heady potential and modest achievement so far, we shall venture into the prediction game to identify key clean energy developments to come over the new year.

More states commit to clean
GTM’s Emma Foehringer Merchant dubbed 2018 the year of 100 percent clean energy. Watch for another waves of jurisdictions to follow the past year’s trailblazers.

In 2018, California joined Hawaii in legislatively committing to a carbon-free electricity system. Governors in New Jersey, New York and Puerto Rico made their own executive commitments to that end. Washington, D.C.’s city council passed a target of 100 percent renewables by 2032.

For a while, debates over 100 percent clean energy policy broke down into intellectual tribalism, as different factions jostled over who had the better vision for a clean energy future. Meanwhile, skeptics could dismiss the whole exercise as a folly.

Once economic and demographic powerhouses like California and New York got on board, it became exceedingly difficult to dismiss the policy as a fairy tale. Suddenly, passing the target switched from seeming intractably difficult to eminently achievable; following through is now the hard part.

December13, 2018: Academics at University of California San Diego have developed a suite of tools using a combination of chemistry and economic know-how to predict the best battery technology for an energy storage project, the university announced on December 3.

The tools take into account a region’s energy markets and the operating characteristics of the battery to predict if a storage project will be financially viable.

Shirley Meng from UC San Diego nano-engineering, and co-author of the paper, says the research was the first step towards re-thinking how battery storage should be viewed by energy storage system practitioners.

She also urged people to look at new chemistries such as sodium ion batteries.

The tools take into account the battery type, its task (such as frequency response, load shifting), price, and market rules of the specific region to help project developers select the appropriate grid-connected battery storage.

The study titled Combined economic and technological evaluation of battery energy storage for grid applications was published in the peer reviewed scientific journal Nature Energy on December 3.

Meng told ESJ: “We are using real California grid (energy market) data to do revenue projection, and the focus is really on understanding how different chemistries can deliver different efficiency under different duty cycles.

“Most of the batteries that have been commercialized have optimum operation temperatures in the range of 0°C to 40°C. From this aspect, lead acid and lithium ion are the same.

“For this reason, most of the grid storage units have temperature control (cooling unit); lead acid batteries still occupy the majority of the grid storage market, but in terms of new storage units (coming up online) lithium ion batteries definitely dominate.

“This is because some lithium ion battery chemistries such a LFP are robust at cycling at 40°C. LFP based batteries have demonstrated over 10,000 cycles at 25°C, making it ideal for grid storage.”

Last year, tense debate over the feasibility of 100 percent renewables entirely consumed the energy industry. Stanford professor Dr. Mark Jacobson stood on one side, arguing 100 percent renewables will be technically possible by 2050, while Dr. Christopher Clack led critiques picking apart that modeling. The controversy even spurred a lawsuit.

In 2018 those conversations didn’t entirely dissolve, but they were overshadowed by action.

Two states, California and New Jersey, joined Hawaii in committing to 100 percent clean energy (Hawaii’s goal is actually 100 percent renewables). In December, the number of cities committed to 100 percent clean or renewable energy surpassed 100. And recent progress for the “Green New Deal” in Congress has federal policymakers also mulling a 100 percent renewable future.

Deal or no deal

Supporters of the Green New Deal call for a select committee to develop a mobilization plan to tackle climate change and aid the transition to a just economy.

As the Washington Post recently reported, the phrase itself has been used many times in recent history. But it’s gained momentum in its latest form due to protests from groups like the Sunrise Movement and through endorsements by incoming progressive lawmakers like Alexandria Ocasio-Cortez.

This week, Democratic leaders indicated they would move ahead in creating a select committee on climate change, but it will not consider the Green New Deal as its “sole focus,” according to chosen chair Rep. Kathy Castor of Florida.

Despite the defeat of a more aggressive agenda, attention at the federal level has spurred hope for many 100 percent renewables and environmental advocates.

U.S. actions at the latest climate talks in Poland, however, did not.

The Trump administration continues to say it will exit the Paris climate agreement — which, based on the pact, it cannot legally do until 2020 — and promote fossil fuels on the sidelines of climate talks. Meanwhile, U.S. corporations, states and other subnational players are continuing to assert their support of the Paris Agreement. But that sideline diplomacy didn’t entirely fill the vacuum left by U.S. leadership at official negotiations.

South Texas utility El Paso Electric Co. (EPE) has selected more than 600 MW of new generation capacity to help meet summer peak loads more than three years ahead.

EPE announced this week that it plans to add multiple cleaner emitting sources for capacity needed during the 2022-2023 summer peak season. The winning bids include expected purchases of 200 MW in utility-scale solar, 100 MW of battery storage and the construction of a 226-MW natural gas-fired combustion turbine unit at EPE’s Newman Power Station.

The $143 million Newman turbine addition is expected to be operational by 2023. In addition, EPE will seek another 50 to 150 MW of wind and solar power.

Kipp

“These technologies provide a mix of carbon-free renewable and clean burning natural gas generation that will enable us to meet the growing need for power in our region in a safe, clean, reliable, and cost-effective manner,” said Mary Kipp, El Paso Electric President and Chief Executive Officer. “This balanced combination of resources will work with our existing energy portfolio as we move to retire aging, less efficient plants while continuing to meet our customers’ changing energy needs.”

The El Paso utility, which serves some 425,000 customers in south Texas, reached coal-free generation status two years ago. EPE sold out its ownership stake in the coal-fired plant on the Navajo Indian Reservation in New Mexico for $32 million to Arizona Public Service.

The utility’s electricity output is primarily generated by natural gas units, most of those built in the 1960s, ‘70s or ‘80s. EPE also has a minority stake in nuclear-powered generation through the Palo Verde Generation Station near Phoenix, Arizona.

The future solar, gas and battery storage resource plan still needs Texas state Public Utility Commission approval.

(Rod Walton is content manager for PowerGen International and the Power Engineering website. He can be reached at 918-831-9177 and rod.walton@clarionevents.com).

New York manufacturing is poised for a job boom in 2019 and beyond.

That’s according to the American Jobs Project, which predicts that New York’s so-called “energy storage industry” could support 27,400 manufacturing and installation jobs by 2030.

The organization, in conjunction with the New York Battery and Energy Storage Technology Consortium (NY-BEST), published their findings in a new report.

American Jobs managing director Kate Ringness, who co-authored the report, explained that new policies are in place to help bolster this particular niche:

Amplifying the role of local manufacturing in New York’s energy storage industry could provide stable employment for thousands of middle-class workers while creating follow-on benefits for the broader labor market. New York’s leaders are creating strong policies to ensure there will be local demand for energy storage. We want to support these efforts by ensuring a healthy ecosystem that supports local job creation in manufacturing, as well as deployment.
New York’s job target is 30,000, according to a recent statement from Gov. Andrew Cuomo.

Currently, New York ranks fifth in the nation for energy storage patents. And while the report praises the Empire State for its testing facilities to support energy storage technology development, it suggested that early-stage startups are at a disadvantage.

They often face the “technological valley of death.”

“They require thorough performance data to build investor confidence in their prototypes, but often struggle to secure funding to pay for testing and validation resources,” Ringness wrote.

Among the players to keep an eye on due to their work in the “energy storage” sector, include General Electric Co. (NYSE: GE), Ioxus Inc., and Lockheed Martin Corp. (NYSE: LMT). Various startups are also driving growth, including C4V, Urban Electric Power, and NOHMs Technologies.

New York is also expanding critical capabilities in battery recycling, with investment in the new SungEel MCC Americas lithium-ion battery recycling plant, the report added.

China is poised to add a significant amount of battery storage to its utility grid next year. And it’s backing two horses in the energy storage race — both lithium-ion and flow batteries are part of the plan. China’s renewable energy portfolio now stands at 706 gigawatts according to Bloomberg but too much of that is wasted, or curtailed as they say in the utility industry. 7.7% of the electricity generated by wind turbines is curtailed as is 2.9% of electricity from solar panels.

Chinese regulators have approved a $174 million investment in the northwestern province of Gansu for the installation of a 720 MWh lithium-ion grid storage battery. It will be the first part phase of a new energy storage project in the region. When completed it will be able to store electricity for up to 4 hours, says Bloomberg.

The Gansu Provincial Development & Reform Commission says subsequent expansion of the project will depend on market conditions and the needs of the electrical grid. Once completed, it will be the country’s largest virtual power plant.

VRB Energy, a developer of vanadium flow batteries, says it plans to build a 100MW/500MWh storage system in Hubei province located in central China. It has begun commissioning a 250 kW/1 MW demonstration unit that it plans to expand to a 3 MW/12MWh battery later this year.

Jim Stover, vice president of business development at VRB Energy, tells TechCrunch, “The Chinese government I think in particular is happy to incentivize or call out vanadium like this. They want to push a number of technologies, but there is an awful lot of vanadium resources in China, both from mine sites and from steel slag recovery. They’re trying to seize that as a good and natural fit, they don’t have a lot of lithium. They have a lot of lithium manufacturers but not a lot of lithium itself, or cobalt, or nickel even.”

The China National Development and Reform Commission has issued a call for greater investment in flow batteries and set up programs to develop vast projects comprised of two or more 100MW installations. One such project — a 200MW / 800MWh vanadium energy storage project in Dalian Province — is already under way. Flow batteries potentially have the ability to provide electricity to the grid for longer than the 1 to 4 hours that is common with lithium-ion batteries. They also can support more charge/discharge cycles than lithium-ion batteries leading to longer life and lower total cost.