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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In an overwhelming show of solidarity, 37 energy-storage companies and associations have written a letter to Congressional leaders asking them for clarification on whether their products qualify for the investment tax credit (ITC) and urged them to support their inclusion in upcoming tax legislation.

With a vote on the Trump Administration’s comprehensive tax reform bill looming on the horizon, the group is asking Congress to codify the Internal Revenue Service’s previous Private Letter Rulings and guidance on the issue.

The group also said the energy-storage industry supports 70,000 employees that would benefit from this clarification because it would encourage further investment in the segment and grow that  number even further.

If those arguments sound familiar, it’s because they echo the arguments made by the solar industry in 2008 when it lobbied for the original ITC for the industry, and reiterated most recently in 2015, when the ITC was extended.

Recently, the solar ITC came under attack in the Senate’s version of the tax reform bill, but intense lobbying by the solar industry helped mitigate the damage, though it did not emerge unscathed. It appears the energy storage industry learned from that experience and is trying to codify its ITC eligibility in a separate law to keep any tax legislation from harming it.

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In Massachusetts, grants totaling $20 million were recently awarded to 26 projects that will develop the state’s energy storage market.

The programs are positioned to deliver benefits to the Massachusetts’s ratepayers and the electrical grid. The awarded projects will benefit 25 communities and draw in $32 million in matching funds, helping to grow the Commonwealth’s energy storage economy.

According to telegram.com, the grants were awarded as part of the Baker-Polito Administration’s Energy Storage Initiative (ESI) Advancing Commonwealth Energy Storage (ACES) program, funded by the Department of Energy Resources (DOER) through Alternative Compliance Payments (ACP) and administered by the Massachusetts Clean Energy Center (MassCEC).

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‘The cornerstone of the redesign of the electricity market’

California has already postponed and even canceled plans to build new natural-gas-fired power plants in favor of distributed energy. But it hasn’t proposed to replace an existing power plant with them — until now.

Early this month, the California Public Utilities Commission issued a resolution that would direct utility Pacific Gas & Electric to open competitive solicitations for DERs — energystorage mostly, but with room for other carbon-neutral “preferred resources” like demand response — to cover the grid capacity and voltage needs now being served by three Northern California natural-gas-fired power plants. 

Choosing which power plants are vital to keep the transmission grid running is the domain of the California Independent System Operator, not the CPUC. And the grid operator has designated the 580-megawatt Metcalf Energy Center south of San Jose, as well as the 47.6-megawatt Yuba River and Feather River generators as reliability must-run (RMR) resources. 

These RMR contracts come with secure, high payments for running relatively few hours per year — mainly during hot summer afternoons when air conditioning loads surge, demand spikes, and CAISO struggles to maintain the reserves to cover potential emergencies. Calpine, the owner of the plants, said they aren’t cost-competitive without RMR, and intends to seek that status with federal regulators, having passed over opportunities to bid their energy or capacity into resource adequacy or bilateral agreements. 

But California regulators argue that these must-run contracts are too expensive, and that distributed resources can replace them at lower cost to ratepayers. It also states that Calpine’s contracts failed to go through CAISO’s procurement process for flexible capacity, which could “lead to market distortions and unjust rates for power” in years to come.

That, the CPUC contends, gives it broad authority to allow solicitation of resources that can “fill local deficiencies.”

While the resolution doesn’t set a specific megawatt-hour target on what PG&E should procure, it does set some clear deadlines. If the resolution is passed, PG&E will have no more than 30 days to issue its first solicitations. Any resources the utility does procure will have to prove they’ll be ready in time to assure the RMR contracts won’t be renewed in 2019.

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Battery energy storage systems have always been in news. Given that inefficiencies in the power sector are always attributed to the fact that power can’t be stored at scale (so you need to over-build in every part of the value chain), grid scale storage solutions have been the holy grail for quite some time! As recent data suggests, this is not too far in the future. Bloomberg New Energy Finance (BNEF) has predicted cost of storage systems to fall to 1/10th of the 2010 levels by 2025 (see below). The learning curve of storage lies at 20%, which means that cost reduces by 20% for every doubling of storage capacity.

In addition to this story of energy storage becoming more mainstream, generally speaking, there are a few examples where BESS have solved here-and-now challenges for the grid. I want to highlight three such cases which highlight the coming of age of BESS. Two of them are for solving real, grid-scale challenges and one for grid planning.

Case 1: South Australia

This definitely is the most public of the cases so I might as well not talk about it! Legend has it that South Australia was suffering through a major grid instability back in December, 2016. Elon offered to solve the problem (through a series of tweets, mind you!) by installing a 100 MW/129 MWh battery pack in 100 days and ended up achieving it in 60 days!

Not only did this battery pack help solve a real problem for the customers in South Australia, it ended up doing it in record time. What’s more impressive is that another, larger, BESS system (100 MW/400 MWh) is already being deployed next to this system. BESS as a grid-scale solution has really arrived.

Case 2: Aliso Canyon (Southern California)

Although not talked about as broadly as South Australia, Aliso Canyon set the benchmark for speed of execution just earlier this year. For background, Aliso Canyon is a massive natural gas storage site in Southern California that experienced a catastrophic gas leak back in October, 2015, which impacted fuel supply for the gas plants in the area. This led to a declaration of state of emergency in California, with blackouts, and the Government hastily sanctioned procurement of 100 MW of BESS in Southern California.

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New York is the birthplace of our modern electrical grid. It’s a point of pride, but also a source of pain for New Yorkers since it means that we have the oldest and most outdated system in the nation. The inefficiencies and periodic failures of our electric grid cost New York businesses and citizens billions of dollars every year.

Entrepreneurs and investors are ready to deploy more advanced, cleaner technologies and services that will reduce the vulnerability of our grid to natural disasters (like Hurricanes Sandy and Irene) and terrorist threats. They’re ready to deploy solutions that will benefit both urban and rural communities.

There’s one problem: They’re prevented by outdated electricity sector regulations. 

In an effort to address the outmoded rules and regulations that prevent innovation in our electrical system, New York state has been working for three and a half years on the Reforming the Energy Vision (REV) process. The purpose is to enable the transition to a modern, distributed and clean electrical grid that includes critical energystoragetechnologies.

Much emphasis has been put on solar power and other renewables, but there are still no clear market guidelines for energy storage — meaning that many of the critical technologies needed to modernize and harden our grid to both natural and manmade disasters cannot be deployed at meaningful scale in the Empire State.

This inability of the New York Public Service Commission (PSC) to successfully implement REV has forced the legislature to take action. In June legislators unanimously passed an energy storage bill (A.6571 in the Assembly and S.5190 in the Senate). Thankfully, Governor Cuomo signed it into law at the beginning of December.

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