Battery storage is a “necessity” for Hawaii to reach its 100% renewable energy by 2045 target, leading to electric cooperative KIUC becoming the top-ranked US utility for watts of energy storage deployed per customer in 2017.

The US Smart Electric Power Alliance (SEPA), has just published a set of four Top 10 lists, ranking utilities in the country by annual megawatts of utility solar deployed as well as a separate table for annual watts per customer. California investor-owned utilities Pacific Gas & Electric (PG&E) and Southern California Edison topped the megawatt-rankings for utility-scale solar with Xcel Energy’s Minnesota branch in third. For watts deployed per customer, municipal utility Madison Electric Works in Maine took the top spot.

SEPA repeated the format for energy storage, looking at watts per customer, which KIUC (Kaua’i Island Utility Cooperation) topped. In second place was Tucson Electric Power (TEP) in Arizona, which in May last year claimed it had arrived at the lowest recorded prices to date for energy bought from a solar-plus-storage installation. Arizona is also now among the US states considering a large energy storage procurement target. In third for customer-facing storage deployment was another Hawaii utility, Maui Electric. KIUC managed 415.3 watts of energy storage deployments per customer, with TEP trailing in the distance on just 50 watts per customer and Maui Electric on 36.5 watts per customer.

SEPA repeated the ranking process for total megawatts deployed. As regular readers of the site will know, California’s position as the leading state for energy storage deployment in the US, making it one of the biggest markets in the world at present, is based on several market drivers. Preeminent among those drivers, where applicable to utilities, would be AB2514, California’s state mandate for investor-owned utilities to deploy 1.325GW of energy storage by 2025.

Also in the past year, energy storage systems charged from solar arrays have started to be considered a suitable capacity resource for California utilities, particularly as legacy natural gas generation starts to reach the end of its lifetime in some cases. Going forward, that dynamic of gas versus storage and the greater consideration of energy storage in utilities’ Integrated Resource Plans is expected to continue pushing the utility market forward.

Energy storage (batteries and other ways of storing electricity, like pumped water, compressed air, or molten salt) has generally been hailed as a “green” technology, key to enabling more renewable energy and reducing greenhouse gas emissions.

But energy storage has a dirty secret. The way it’s typically used in the US today, it enables more fossil-fueled energy and higher carbon emissions. Emissions are higher today than they would have been if no storage had ever been deployed in the US.

This is not intrinsic to the technology, by any means. If deployed strategically, energy storage can do all the things boosters say, making the grid more flexible, unlocking renewable energy, and reducing emissions.

But only if it is deployed strategically, which it generally hasn’t been.

In and of itself, energy storage is neither clean nor dirty — it is neutral, as likely to boost the revenue of fossil fuel plants as it is to help clean energy. If policymakers want to use it as a tool to enable clean energy, they need to be conscious of its characteristics and smarter about its deployment.

Why energy storage increases emissions

There is a growing body of scholarly research around energy storage; the key paper on its emission effects is by the Rochester Institute of Technology’s Eric Hittinger and Carnegie Mellon’s Inês Azevedo, in Environmental Science & Technology.

Modeling energy mixes and energy prices across the country, Hittinger and Azevedo determine that the deployment of energy storage increases emissions almost everywhere in the US today. Yikes.

Gas distributer Northern Gas Networks (NGN) has hailed the results of a power-to-gas feasibility study which suggest that hydrogen’s potential as a form of energy storage could be delivered at scale.

The collaborative desktop study, funded by the Department for Business, Energy and Industrial Strategy (BEIS), was led by Sheffield-based energy and clean fuel company ITM Power, using network planning models and data from the gas distributer for the North of England.

It highlights the opportunity available to the UK to take a lead in cutting edge energy storage technology, and the potential for a new era in green gas solutions for customers.

As renewable electricity increases in the UK, effective storage and transmission of surplus power is set to become increasingly important.

Power-to-gas technology turns this excess power into hydrogen, injected into the natural gas network using it as a renewable energy store for use in heat, electricity generation or transport via hydrogen fuel cell vehicles.

Using nothing more than clean water and electricity, power is turned into zero-carbon hydrogen through an electrolyser developed by ITM Power.

A blend of natural gas and hydrogen would then help to decarbonise the heat used in UK homes and industry.

Mark Horsley, CEO of Northern Gas Networks said: “Power-to-gas technology has the potential to answer some of our key energy storage challenges because of the gas network’s sheer size and flexibility.

“This study has delivered some compelling results and insight into how a whole systems approach and green hydrogen can facilitate decarbonisation across all energy vectors.

NGN has led gas industry research into hydrogen as an energy source and is actively pursuing its use for heating in the UK through the pioneering H21 project, focused on converting the UK gas network to 100% hydrogen.

The BEIS/ITM Power-to-Gas study examined potential deployment of large-scale storage capacity of 50 megawatts (MW) and above within the boundaries of NGN’s distribution network.

We have been hearing concerns that moving to a regional transmission operator to connect the Western U.S. somehow harms the prospects for greater development of distributed energy resources, especially localsolarand storage, and could lead to an increase in the use of fossil fuels elsewhere in the region. A careful analysis of the facts shows these concerns are unfounded and that in fact, the opposite is true. A regional grid operator will be beneficial for renewable energy development, including distributed generation, for multiple reasons.

Replacing a highly balkanized and inefficient group of grid operators (see the WECC balancing area map below), many of which rely on outdated and highly polluting power plants, with a fully coordinated regional system operator will make better use of the existing interconnected grid, more efficiently share electricity reserves allowing for the accelerated retirement of unneeded facilities, and give more value to cleaner, renewable power sources.

Renewable energy benefits

A regional grid operator makes managing each renewable energy generator’s variable output easier to coordinate and creates more value that can be shared by utility customers and renewable energy developers. It does this by blending renewable power from across the West, including the output from many smaller customer-owned or community-based systems located on dispersed distribution systems. This widespread diversity of resources can be used to meet energy demand at times when fossil fuel generators that are part of local systems would otherwise have to be switched on to fill in the gap.

Solar energy ramps up and down in a quite predictable manner, but varies by longitude and latitude. The availability of other renewable resources can now be forecast with ever-increasing accuracy. A regional grid operator can use renewable power resources across a much wider geography that experiences different weather patterns and energy loads to better meet both systemwide and local needs. This wider area coordination can reduce not only greenhouse gas emissions but also local air pollutants that harm public health, particularly for the most vulnerable.

NEC Energy Solutions (NEC ES), a wholly-owned subsidiary of NEC Corporation, is supplying Ørsted UK with a 20-MW GSS Grid Storage Solution.

“The future energy system will be completely transformed from what it is today, with a smarter, more flexible grid, balancing supply and demand with new technology and cleaner energy generation,” said Matthew Wright, Managing Director of Ørsted UK. “We want to continue to be at the forefront of this exciting shift towards a decarbonized energy system. Acquiring the Carnegie Road plant is an important step forward as it’s our first commercial-scale battery storage project. We’re investing billions of pounds in the UK’s energy infrastructure and this is another significant investment that puts the UK at the heart of the global energy transition.”

Once completed and operational by the end of 2018, the system will be used to provide services to the UK’s National Grid to help manage grid stability during changes between peak and low power demand.

“We could not be more thrilled to be working again with NEC Energy Solutions who have a strong presence in Massachusetts and are recognized as a global leader in battery storage technology and products,” said Thomas Brostrøm, President of Ørsted North America. “NEC Energy Solutions will serve as a partner on our Bay State Wind project in Massachusetts and will now work with us in the UK, which is an exciting step as we develop our energy storage solutions in the U.S.”

The Carnegie Road battery storage project was originally developed by Shaw Energi, which will support Ørsted in the execution of the project. The grid connection agreement and permits are already in place and construction is expected to start in May, with the project operational by the end of the year.

Tucked away in the Federal Energy Regulatory Commission’s April 19 revision of its large generator interconnection agreement are easily overlooked provisions that could benefit energy storage providers.

Order 845 revises the commission’s large generator interconnection agreement in several ways. It’s the conclusion of a process that began with a notice of proposed rulemaking in 2016 that was prompted by a complaint filed by the American Wind Energy Association.

For energy storage, the most obvious change in Order 845 is that it revises the definition of generating facility to explicitly include electricity storage. But the scope of 845 is much wider than energy storage. It revises interconnection rules and protocols for any generator larger than 20 MW.

One of the main changes FERC is putting in place with Order 845 is to allow interconnection customers to request a level of interconnection service that is lower than the capacity of their generating facility.

That is an issue that has become increasingly prevalent with the rise of renewable resources such as wind and solar power for which electrical output seldom equals nameplate capacity.

Improving the interconnection process

FERC says that changes such as more closely aligning output and nameplate capacity will help improve the interconnection process. Many interconnection customers experience delays and some interconnection queues have significant backlogs, according to FERC. As a result, there is also a recurring problem of late interconnection request withdrawals that can lead to interconnection restudies that can increase costs and timelines for other participants in the interconnection queue, FERC says.

Among the other changes brought about by Order 845 is that it requires transmission providers to allow for provisional interconnection agreements for limited operation of a generating facility prior to completion of the full interconnection process. The order also requires transmission providers to create a process for interconnection customers to use surplus interconnection service at existing points of interconnection.