Nearly 50 public utilities have yet to account for the recent corporate income tax cut in their transmission rate formulas, and the Federal Energy Regulatory Commission wants to know why.

FERC is asking the utilities to explain why they are still showing a maximum 35 percent corporate tax rates in their formulas which ultimately factor in costs for customers. The corporate income tax rate was cut to a flat 21 percent as part of the Tax Cuts and Jobs Act signed by President Trump into law late last year.

One of FERC’s show-cause orders identified 34 generation and/or integrated utilities still including the higher rates in their costs when it should have been reduced beginning January 1. Those companies include Avista, El Paso Electric, Florida Power & Light, Potomac Edison, Portland General Electric, Dayton Power & Light and Tucson Electric, among others. (See the complete order here).

“When tax expense decreases, so does the cost of service,” FERC’s show-cause order reads. “The commission must ensure that the rates, terms and conditions of jurisdictional services under the FPA (Federal Power Act) are just, reasonable and not unduly discriminatory or preferential.”

The second show-cause order focused on transmission rate formulas with 12 utility units of larger holding companies. Those include AEP’s transmission units Appalachia, Indian Michigan, Kentucky, Ohio, West Virginia, Oklahoma and Southwestern. (See order here).

Other utilities named in that order included Baltimore Gas & Electric, Black Hills Power, San Diego Gas & Electric, Transource and UNS. The parties named in the orders have two months to respond once the notice is published in the Federal Register.

The FERC notice also questioned the same issue with interstate natural gas pipeline companies. The cost of fuel transport and expense also are reflected in utility’s customer rate formulas filed with state regulators, many of which have expressed a desire for those cuts.

Energy storage is a tough concept to grasp. And until now, it’s been an even tougher technology to deploy. But the market for such technology is forecast to exceed the previous four years in this year alone because of falling prices and favorable policies.

Most people envision energy storage as a system that siphons power from the grid at night and harnesses that electricity inside of a device. It is then released during the day at peak demand. That’s coming — and the evidence is starting to mount. The more immediate application, though, is infusing the grid with electrons if the lights start to flicker out.

What’s the proof that the energy storage market is getting past its infancy? GTM Research and the Energy Storage Association have just released the U.S. Energy Storage Monitor 2017 Year-in-Review, which says that 1,000 megawatt-hours were deployed between 2013 and 2017 and which predicts that more than 1,200 megawatt-hours of energy storage will get deployed in 2018 alone; last year, it was 431 megawatt-hours. Altogether, GTM estimates that the annual value of the U.S. energy storage market will exceed $1.2 billion in 2019.

Moreover, the Federal Energy Regulatory Commission voted in mid February to allow grid managers to compensate energy storage in the same way they do traditional power generators. Energy storage would thus graduate beyond the injection of electrons to prevent lights from flickering out and into the wholesale energy markets.

The regional transmission organizations and independent system operators are required to present their plans on how to achieve the commission’s goals later this year. The PJM Interconnection has delivered about 250 megawatts of cumulative energy storage power since 2013. California’s Independent System Operator is also actively trying to incorporate energy storage into mix of generation assets, as PG&E Corp., Sempra Energy and Edison International must collectively buy 1,325 megawatts of energy storage by 2020.

The San Diego County Water Authority is expecting to save approximately $100,000 per year with commercial-scale batteries installed at the agency’s solar-powered Twin Oaks Valley Water Treatment Plant near San Marcos.

The energy storage system is designed to reduce operational costs at the facility by storing low-cost energy for use during high-demand periods when energy prices increase.

The batteries were installed at no charge to the agency as part of an agreement with Santa Clara-based ENGIE Storage, formerly known as Green Charge.

The system charges from either the grid or on-site solar energy production to store energy. ENGIE Storage’s GridSynergy software allows the water authority to use that energy for plant operations during high-demand periods when market prices typically peak. At the Twin Oaks facility, on-site energy is generated by more than 4,800 solar panels that produce an estimated 1.75 million kWh of electricity each year.

“Energy storage is a strategic addition to the water authority’s solar energy installations, which have already reduced power costs and made the agency more environmentally friendly,” says Mark Muir, chair of the water authority’s board of directors. “This project is a good example of how we continually look for ways to maximize investments in the regional water treatment and delivery system to the benefit of our ratepayers. This includes advances in our growing list of energy initiatives.”

ENGIE Storage installed the batteries at Twin Oaks through a power efficiency agreement to install, at no cost to the water authority, a 1 MW/2 MWh energy storage system. ENGIE will own, operate and maintain the $2 million system on water authority land for 10 years, after which the agency can choose to extend the agreement, purchase the batteries, or have them removed and the site returned to its original condition.

A $1 million incentive from the California Public Utilities Commission (CPUC) helped fund the project. The incentive, awarded in 2017 under the CPUC’s Self Generation Incentive Program, encourages the adoption of energy storage technologies that reduce both electricity demand and greenhouse gases.

GE has released a containerized energy storage product with a competitive advantage for installation time.

The 1.2-megawatt, 4-megawatt-hour Reservoir system marks a new entry into the standardized, large-scale battery market. It reflects a strategic shift at GE’s storage practice, which recently reorganized after an initial foray into battery manufacturing and a detour in commercial and industrial energy services.

Reservoir sounds like many other containerized battery solutions already available from companies like Fluence, BYD, Mitsubishi, LG, Samsung and others. The goal is to lower costs to developers by standardizing the product and factory-testing the enclosures for quality control.

What GE does differently is ship the containers fully loaded.

“We will fully assemble and test the equipment in a controlled environment and drop ship to the site fully assembled,” said Eric Gebhardt, vice president and strategic technology officer at GE Power.

Typically, containerized battery systems ship without the battery cells inside, due to weight, safety or quality concerns. GE bucked the trend by designing a box that can travel with batteries in place but disconnected. A technician with a hot stick can flip a switch onsite to reconnect the electrical circuit and get the system operational again.

That could cut installation time in half, Gebhardt said, because it eliminates time-intensive battery installation onsite.

This appears to be the first large-scale battery design with this capability.

The 50 percent cut to installation time “seems plausible and realistic,” said Ravi Manghani, energy storage director at GTM Research. That still leaves other tasks like putting in a transformer, wiring different containers together and connecting to the broader grid.

“These assets can come online and start making money faster than another system that has to be assembled onsite,” Manghani noted.

On day one of Energy Storage Europe, which runs until March 15 in Düsseldorf, Germany, a vivid panel discussion involving energy industry luminaries from Engie, the International Renewable Energy Agency (IRENA), the U.S. Department of Energy and the National Renewable Energy Laboratory (NREL) tackled the question: Energy storage or grid extension?

The question was intentionally blunt and obtuse, and found uniform disagreement among the panelists.

“It is the wrong question to be asking,” said Martin Keller of NREL. “The right question should be: what combination of energy infrastructure, together with flexibility options, is better?”

Michael Taylor of IRENA said that storage will instead begin “nibbling at the edges of the grid”, particularly in regions where grid capacity expansion is difficult or prohibitively expensive.

Thierry Lepercq, executive VP at French utility, Engie, pressed home the point that the very nature of storage means more flexibility, and goes beyond mere batteries supporting the grid during times of peak demand.

“It is my belief that a power and gas approach can offer a range of tools better equipped to solve the issue of storage and grid integration,” Lepercq said. “We do know that the performance of storage is going to improve, and with that costs will come down, deployment grows, research grows – it’s a virtuous circle.”

Lepercq told the audience that Engie is intent on tackling the ‘diffused’ nature of energy consumption, and believes that the firm is close to solving one of the major stumbling blocks for stored energy – costs.

“In Chile we can use hydrogen to store solar energy produced at $11 MWh,” he said. “Chile has vast amounts of land, space and sun. I believe we can produce 3,000 terrawatt hours of production over 18,000 square kilometers – this is just a small part of the Atacama desert, but could produce enough to cover Europe.”

The energy storage provider Blue Planet Energy recently deployed its Blue Ion energy storage systems to support the electrification efforts in Puerto Rico. These deployments took place in areas where there has not been reliable electricity since September of 2017, when Hurricane Maria struck. One site is a volunteer housing facility in the Isabela municipality and the other is located in the Corozal municipality to provide electricity to a clean water pumping system. Blue Planet Energy is also providing support through training and education sessions.

“Too many of Puerto Rico’s residents have not had a functioning electric grid since Hurricane Maria’s landfall in September. Our Blue Ion units will provide critical sites with reliable, safe and self-sustained power to ensure they can continue providing essential services to their communities. We’re proud to be able to lend our support to Puerto Rico and to contribute to its mission of rebuilding with stronger, cleaner and more reliable energy infrastructure,” said Henk Rogers, Blue Planet Energy CEO and founder.

A 16 kilowatt-hour (kWh) Blue Ion 2.0 battery unit was installed at the well pumping system in Corozal. The energy storage technology is working with a 7 kW solar power system in a remote neighborhood called Palos Blanco. This area was experiencing a lack of both clean water and reliable electricity, so the solar power and energy storage system is helping to produce both.

“Our mission on the ground in Puerto Rico is to coordinate with the EPA and FEMA to install safe drinking water stations and solar-powered pumping systems to service those that need it most, ” explained Mark Baker, Director of Disaster Response for Water Mission. This organization is working to address water safety in many rural communities in Puerto Rico.

As the market for stationary storage grows, it is becoming more mobile. With the rental model that Younicos is introducing, a storage device can be put in place for a limited amount of time and moved when conditions change.

While not the first example of such leasing, Younicos’s move demonstrates another way for storage companies to differentiate themselves.

“We believe that this offering extends the benefits of energy storage to a new segment of customers who, for one reason or another, value financial flexibility,” Alexander Schönfeldt, head of Europe, the Middle East and Africa sales for Younicos, said in a statement.

Under the company’s “Energy-Storage-as-a-Service” model, customers pay a rental fee, as well as mobilization and de-mobilization charges, but incur no other costs. The storage systems are housed in containers and can be shipped to the site, dropped in place and operated by Younicos.

“Younicos’s move makes sense,” considering that the company’s corporate parent is Aggreko, one of the largest rental providers of power generating equipment in the world, Tim Grejtak, an analyst at Lux Research, told Utility Dive. Younicos was acquired by Aggreko last year in a $52 million cash deal.

The move is another sign of a wider trend under way in the energy storage industry, Grejtak said. “We are starting to see more differentiation in financial business models, which is important,” he said.

At first, companies differentiated themselves by the assets or technology they offered. But the ubiquity of lithium-ion batteries obviated that, Grejtak said. Next, companies differentiated themselves with control software, but most companies now offer some form of software. “Now, companies are looking at differentiation by finance. We saw a similar differentiation in the solar industry when companies began to adopt the solar lease model,” Grejtak said.

Younicos’s model may be unique, but it is not the first company to offer an alternative to the outright purchase of a storage system or even a temporary storage solution.