Changes to the de-rating factors for battery storage projects competing in the UK’s Capacity Market (CM) will push the sector towards longer-duration batteries, while potentially sparking a shift towards energy arbitrage as a source of revenue for shorter duration applications.

That is the view of storage sector participants in the UK following the announcement last Monday, which cut the de-rating factors for 30 minute duration batteries by almost 80%.

UK Power Reserve, which secured pre-qualification for 400MW of battery storage across the upcoming T-1 and T-4 auctions, has said attention will now be directed towards technologies which can be better rewarded in the CM. UK Power Reserve is a provider of electricity and related services and a developer of low carbon energy projects. 

Michael Jenner, director of policy and regulation at UK Power Reserve, told our sister site Clean Energy News: “We support the de-rating factor because the CM is designed to ameliorate stress events, so you should be rewarding assets for their ability to help reduce those stress events. The incentive now is there for investors to think about building longer duration battery storage, there’s no question about that.

“I still think there’s value in the bankable 15 year revenue of a CM even after the de-rating rates, so investors certainly won’t discount that but the incentive now is firmly there for investors to think about longer duration assets that can actually help to ameliorate a CM stress event.”

Speaking to CEN earlier this week at the Low Carbon Network Innovation (LCNI) conference in Telford, Georgina Penfold, chief executive of trade association Electricity Storage Network (ESN), added that “the writing has been on the wall for a long time” regarding the changes and that investors were already considering their options.

“The initial consultation documents did say that if it went ahead their proposal was from January and it was something we put in our consultation response. It’s not a surprise to the industry.

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I’m back with my yearly list of predictions for the rooftop solar industry. I did OK on last year’s predictions, only completely whiffing on two.

This year, I’m combining my solar predictions with storage, since battery storage is rapidly becoming integrated with PV systems.

1. U.S. solar cell manufacturing won’t restart anytime soon

Billions of dollars in long-term investments are required to achieve large-scale production of the next generation of high-efficiency solar cells. With the right solar industrial policies in place, the cell industry can indeed recover, and bring along associated panel and component manufacturing. Unfortunately, implementing policies to support these investments does not seem to be a priority in Washington, D.C.

2. The panel shortage will not mitigate until the end of Q2

The threat of tariffs is already causing a panel shortage. It takes about a month to finalize and ship orders to a port, and another month to ship containers from overseas — assuming panels are in stock. Without solar panels there can be no completed systems, so there will be a commensurate decline in revenue among all system components.

3. Wires will disappear from solar system monitoring 

Cellular cloud-based solutions will prove to be more cost effective for monitoring. Experienced contractors are realizing that spending a few hundred dollars more on cellular monitoring is much cheaper than Ethernet-WiFi-ZigBee fiddling, and the inevitable customer callbacks as a result of home network failures.

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Changes to the de-rating factors for battery storage projects competing in the UK’s Capacity Market (CM) will push the sector towards longer-duration batteries, while potentially sparking a shift towards energy arbitrage as a source of revenue for shorter duration applications.

That is the view of storage sector participants in the UK following the announcement last Monday, which cut the de-rating factors for 30 minute duration batteries by almost 80%.

UK Power Reserve, which secured pre-qualification for 400MW of battery storage across the upcoming T-1 and T-4 auctions, has said attention will now be directed towards technologies which can be better rewarded in the CM. UK Power Reserve is a provider of electricity and related services and a developer of low carbon energy projects. 

Michael Jenner, director of policy and regulation at UK Power Reserve, told our sister site Clean Energy News: “We support the de-rating factor because the CM is designed to ameliorate stress events, so you should be rewarding assets for their ability to help reduce those stress events. The incentive now is there for investors to think about building longer duration battery storage, there’s no question about that.

“I still think there’s value in the bankable 15 year revenue of a CM even after the de-rating rates, so investors certainly won’t discount that but the incentive now is firmly there for investors to think about longer duration assets that can actually help to ameliorate a CM stress event.”

Speaking to CEN earlier this week at the Low Carbon Network Innovation (LCNI) conference in Telford, Georgina Penfold, chief executive of trade association Electricity Storage Network (ESN), added that “the writing has been on the wall for a long time” regarding the changes and that investors were already considering their options.

“The initial consultation documents did say that if it went ahead their proposal was from January and it was something we put in our consultation response. It’s not a surprise to the industry.

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On Friday, December 15, the Energy Storage Association, along with 36 other companies and associations, asked congressional leadership to clarify eligibility of energy storage for the Investment Tax Credit in any end-of-year energy tax legislation, based on bipartisan, bicameral support for the Energy Storage Tax Incentive and Deployment Act (S. 1868 and H.R. 4649).

Read the letter here >>

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Developers of energy storage projects have complained in the past that existing regulations regarding tax credits for energy storage force projects to operate in ways that do not necessarily make the best use of storage assets.

An energy storage project can make use of the ITC only if it is part of a solar power installation and meets specific criteria.

The energy storage device must be charged by the renewable resource 75% of the time, and falling under 100% renewable charging docks the tax credit by a commensurate amount. The rule also looks backward for the first several years of a project and so could threaten the tax credit at any point during that period.

Energy storage interests are now seeking to remedy that situation. They see an opening for energy storage in a potential tax extenders bill that has been talked about recently in the context of the pending tax cut legislation that Congress is expected to vote on soon.

In one view, the tax extenders bill would provide extensions for technologies that were left out, or orphaned in Beltway lingo, when the ITC and the production tax credit (PTC) were extended in a 2015 bill.

The letter by the ESA and other storage interests is a “direct response to public discussions of an energy tax extenders bill,” Jason Burwen told Utility Dive via email. The tax extender provisions could be part of a continuing resolution that Congress must pass by Dec. 22 in order to continue funding the government. The more likely vehicle, however, would be as part of a January omnibus bill.

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Solar power and energy storage (batteries) have fallen in price enough that they’re now competing with the cost of natural gas peaker plants in specific markets. New analysis is suggesting 10GW of natural gas peaker plants are at risk through 2027 in the USA specifically.

Other, more aggressive suggestions don’t see a place for gas peaker plants after 2020 in the USA. It seems the age of the renewable energy plus energy storage power plant is upon us.

Part of the use of Tesla’s 100MW/129MWh project is an example of this in the real world. So is the collection of projects in California that partially replaced the natural gas plant at Aliso Canyon (which Tesla also participated in). Elsewhere in California there are discussions to replace two additional peaker plants in the near future, and one large gas power plant, that regulators say are systemically important to the grid with batteries.

The two Tesla battery power plants – and peaker plants in general – are participating in an electricity market that pays for filling gaps with fast response time electricity during times when electricity demand changes (like in California as the sun goes down and everyone goes home).

A report in Minnesota suggested that right now, the net cost of a solar power plus storage power plant is cheaper than a natural gas peaker power plant – as seen in the right two columns in the graph below. In fact, energy storage alone – without the cheap electricity coming from a renewable plant – is almost the same cost as a peaker plant.

Major CEOs of power companies have also suggested, in a much more aggressive time frame, that peaker plants will go away entirely by 2020 in the USA.

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Italy could be poised to overtake Germany as Europe’s top energystoragemarket after the turn of the decade, a new report predicts. 

The European Market Monitor on Energy Storage, compiled by Delta-ee on behalf of the European Association for Storage of Energy (EASE), forecasts Italian behind-the-meter installations could soar after 2021.

The market will be driven by local subsidies, coupled with a strong solar market, said report author Valts Grintals, product manager for the energy storage research service at Delta-ee.

Unlike previous reports, which tended of focus on single European energy storage markets, this market monitor has a pan-European scope, covering Germany, the United Kingdom, Italy, France, Iberia, the Nordics, Central and Eastern Europe, and the rest of the continent. 

It shows, for example, that the Nordic countries could see strong demand for commercial and industrial energy storage systems, coupled to the growth of data centers in the region. The research also allows for comparisons between subsidy- and non-subsidy-driven markets.  

Germany and Italy are good examples subsidy-driven markets. Alternatively, the U.K. has scaled purely on the back of decreasing costs for energy storage and market signals, just as solar feed-in tariffs are phased out.

In the U.K., behind-the-meter storage still does not really make much economic sense. But the market is starting to take off regardless, in part thanks to off-the-shelf solar-plus-storage offerings such the one launched by Ikea in August.

Ikea estimates the systems will save homeowners up to £560 ($741) per year, or about 67 percent more than the savings from solar panels alone, allowing for a 12-year payback for a typical customer, or a 6 percent annual return on investment.

The growth in behind-the-meter storage in Britain reflects a predicted decline in the importance of front-of-meter installations across Europe.

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The colonization of American grid innovation by European utilities has advanced with remarkable speed.

A promising U.S. energy startup, tackling such problems as energystorage EV charging or demand response, is more likely to find its way into the hands of Enel, Engie, Innogy or E.ON than their U.S. counterparts. This allows the Europeans to test out future business models far from their home markets, with negligible risk of cannibalizing their own core businesses.

Groupe EDF, which runs the electricity system in France and develops renewables around the world, has taken an inquisitive but less acquisitive approach to mining the U.S. energy sector.

It bought Maryland-based* groSolar in 2016 and turned that into the New World distributed development arm of its Renewable Energy practice. This past year it expanded that team with a new Distributed Energy and Storage unit, making use of the Store & Forecast software developed in France.

As a result, the company responsible for massive grid storage to balance France’s nuclear fleet has moved into distributed, behind-the-meter storage in the U.S.

Earlier this month, EDF won a 10-megawatt/40-megawatt-hour contract with Pacific Gas & Electric. If approved by regulators, EDF will tap a group of commercial customers to host batteries to fulfill the utility’s resource adequacy obligation, while generating savings for the customers.

This was not an obvious or guaranteed chain of events, but EDF determined that there’s a market for distributed storage that it cannot afford to ignore.

“Jumping over the fence and getting behind the meter comes from solar,” said Raphael Declercq, vice president of portfolio strategy at EDF Renewable Energy. “It was really a realization that customers were interested in this and there could be a very substantial reduction in their energy costs in some places.”

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In our previous article, we covered how technology costs aren’t yet low enough for energy storage to be economically viable as standalone projects, and some of the innovative ways developers are using to overcome these limitations. Here we’ll flesh out one of the more attractive – yet elusive – options: revenue stacking.

Mentions of revenue stacking frequently crop up in energy storage publications and in our own interviews, but why does it appeal so much? It’s simple. When making a business case for a new project and examining all the potential sources of revenue one could think “Why not offer many of these services, increase our revenue and diversify our income stream?”

If this sounds simplistic and too good to be true to you, you’re absolutely correct.

Most obviously, some revenue streams are not suitable for stacking, with different and even opposing technical requirements for optimum operation – frequency response and arbitrage, for example. Even for applications where operational requirements are more closely aligned, there’s a real risk of being forced into a solution that is average for every application rather than great for one.

Another challenge is that regulation still lags behind energy storage advancements. Existing revenue streams are subject to complex regulatory policies, which again, can inhibit or oppose one another. The restrictions in most countries, such as the UK, as to who can own and operate energy storage assets make co-ordinating grid-level applications difficult.

While there is no question that current regulations are outdated for today’s energy storage landscape, it is equally true that regulation changes can be introduced rapidly – for example, last week’s announced change in Capacity Market de-rating factors. The future is inherently uncertain, characterised by rapidly falling technology costs, saturated markets, planned regulatory changes and changing contract lengths. Accurate forecasting is a risky business for one revenue stream, let alone three, or six.

So does this mean that the benefits of revenue stacking should be discounted? We think not, and we can look to successful examples to see who is making it work, and how:

Don’t take on too much: There are far more successful examples focusing on two or three complimentary revenue streams than four/five. Fewer variables mean more accurate forecasting and better optimisation. An example of this strategy include solar plus storage “virtual power plants”, which receive income from direct energy consumers as well as for grid ancillary services.

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