The age of storage serving peak power has only just begun, so the size of that market is very much up for debate.

California has already halted a new gas plant in favor of deploying energy storage in its place. Elsewhere, regulators called on PG&E to acquire storage instead of paying to maintain two existing gas peaker plants. An Arizona utility recently procured asolarand battery project specifically to serve capacity for system peak hours.

These are early signs of a dramatic shift in how the grid gets electricity when demand is highest. “The amount of press written on storage as a peaker replacement has grown tremendously over the last several years,” said Paul Denholm, a researcher at the National Renewable Energy Laboratory. “My concern was, this might be exciting, but is there a real market there?”

When a new market appears and draws investment, it comes with the risk of proving shorter-lived than developers hoped. That dynamic played out in the early storage market for frequency regulation in PJM, which has mostly dried up due to oversaturation and rule changes.

Denholm and colleague Robert Margolis decided to test the market potential for storage-as-peakers, using load data and simulated solar PV production from California. Their new study suggests that peak power in California alone constitutes a massive market opportunity, which will continue to grow as solar capacity increases.

First, Denholm and Margolis established a baseline of how much storage could compete for peak capacity without any intermittent renewables to deal with. They modeled 4-hour storage, because that’s the threshold that California rewards with a full resource adequacy credit. As more batteries come online, they incrementally flatten the peak, eventually requiring longer-duration units to meet additional peak demands, as illustrated in the following chart.

The US Department of Energy recently floated the idea of carving out a place for small coal power plants in the distributed energy landscape of the future, but it looks like the agency’s latest attempt to save coal is a day late and a dollar short. In the latest development, GE has just begun pitching a new energy storage project with the evocative name The Reservoir, and it puts the prospect of a coal powered future where it belongs: on the shelf.

Last week CleanTechnica grabbed a few minutes on the phone with Eric Gebhardt, GE’s Vice President and Strategic Technology Officer, to get some insights into the Reservoir, and he had something to say that will bring little comfort to coal fans.

So, What Is The Reservoir?

When GE announced The Reservoir, it made the implications for renewable energyabundantly clear. GE described the new energy storage project as a “comprehensive” platform that “delivers a suite of customized storage solutions to help customers address new challenges and seek new opportunities in a rapidly transforming power grid that is becoming more highly diversified and distributed.”

That’s kind of a mouthful. What it means in practice is a lesson that grid planners have already absorbed: the old model of large scale, centralized energy generation is, well, old.  The rise of digital technology, renewable energy, and distributed energy have resulted in a “paradigm shift” in energy generation and distribution.

Gebhardt’s statement in a press release for The Reservoir is definitive on that score:

GE’s Reservoir platform enables cost-effective distribution, storage, and utilization of cleaner, more reliable power where and when it is needed most. It can fit into most any setting, from centralized grid systems to the most remote villages and communities. The Reservoir also allows energy providers new degrees of flexibility for more intelligently managing and getting the most out of all their power assets.

That sounds pretty fancy, right? The innards consist of a fairly standard lithium-ion energy storage arrangement of 1.2 megawatts and 4 megawatt-hours, but all the system control and operation overlays are exclusive to GE. The “reservoir” name evokes energy storage but it could just as easily refer to the storehouse of knowledge GE brings to the design. Here’s another snippet from the press release:

…It is a modular solution that integrates GE’s Battery Blade design (module stack design) with key technologies from across the company’s portfolio to achieve an industry-leading energy density, footprint and lifetime performance. GE’s proprietary Blade Protection Unit (BPU) actively balances the safety, life, and production of each battery Blade, extending battery life by up to 15 % and reducing fault currents by up to 5X.

Vertically integrated energy company Scottish Power has submitted a proposal to extend recently introduced battery de-rating factors in Britain’s Capacity Market to storage included in demand side response bids in what has been described as a latest attack on the battery market.

The utility submitted the proposal on 13 March, which would create DSR technology classes with different minimum durations, and apply the extended performance testing to these newly created groups.

Among these would be a ‘Storage DSR’ class, which National Grid’s electricity market reform delivery body would be obligated to consult on applying the lower de-rating factors to.

Scottish Power argues that under current market rules if a DSR CMU (Capacity Market Unit – “a unit of electricity generation capacity or electricity demand reduction that can then be put forward in a future Capacity Market auction” according to the government definition), consisting of energy storage, is located behind the meter (BTM) it will not be subject to duration de-rating.

“This risks over-rewarding such storage and increasing costs to consumers. It is also contrary to the CM policy of technology neutrality and unfair to other market participants,” the company stated.

It adds that without such a change, storage developers are able to bypass the extended performance tests which are applied to capacity storage generating technology classes by going behind the meter.

The proposal suggests that each applicant for an unproven DSR CMU “must include details of any known intention to use a generating unit that is categorised as a DSR storage technology class”, a suggestion that has been refuted by those offering behind the meter battery services for DSR.

The agreement will see Rolls-Royce combine its material science and technical expertise with Superdielectrics’ novel hydrophilic polymers that have been shown, in partnership with researchers from the Universities of Bristol and Surrey, to have potentially outstanding energy storage properties.

Dr Dave Smith, director of Central Technology, Rolls-Royce, said: “We believe that electrification will play an increasingly important role in many of our markets over the coming years and by working with partners on potential new technologies for energy storage we can ensure that Rolls-Royce is well positioned to take advantage of new developments.”

Jim Heathcote CEO of Superdielectrics, said: “We are delighted to be working with Rolls-Royce in the global race to develop advanced energy storage systems. This agreement gives us access to their unparalleled scientific and technical expertise. I hope this agreement will ultimately create new jobs and business opportunities in the UK.”

Working with researchers from the Universities of Bristol and Surrey, Superdielectrics has been developing hydrophilic materials, similar to those originally designed for soft contact lenses, to increase the electricity storage capabilities of capacitors, which store electricity by creating electrostatic fields.

These dielectric polymers may provide an opportunity to create capacitors that are able to rival – and even exceed – the storage capacity of traditional rechargeable batteries. The resulting supercapacitors may also be able to charge much faster than existing lithium-ion batteries.

According to the current estimate of the German Energy Storage Association (BVES), the energy storage industry will grow by around 11% in 2018 and will generate a turnover of approximately EUR 5.1 billion. Medium-sized companies are the main driving force behind this increase. The development of Energy Storage Europe reflects this industry trend: With a total of 170 exhibitors and about 4.500 visitors, this year’s energy storage trade fair and the two conferences ESE and IRES continued the positive development of the past years.

“No other trade fair in the world covers the entire spectrum of energy storage solutions. Every year, new players enter the still young market with innovative solutions – often with new technological approaches to energy storage,” stated Hans Werner Reinhard, Managing Director of Messe Düsseldorf.

Urban Windelen, Executive Director of the BVES, added: “Energy Storage Europe 2018 once again demonstrated the solid growth of the industry across all storage technologies and various applications. The event is the decisive international business platform for energy storage systems and its success confirms the growing industry figures predicted by the BVES.”

Increasing international participation
Internationalization is a further industry trend apparent in the visitor structure of Energy Storage Europe and the IRES Conference: this year, the organizers welcomed delegations from Mexico, Costa Rica, El Salvador and other Central American countries as well as from Greece, Norway and Poland, Portugal. Overall, participants from 61 countries attended the conferences and trade fair.

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.