I recently had an interesting conversation with a colleague about our work with microgrid engineering projects. A common theme emerged: Many of the bad experiences involved a lack of cross-discipline knowledge or, maybe, a lack of overlap with other engineers on the project.

Other engineers either didn’t know how the other components or systems in the microgrid worked together, or they just didn’t consider it.

At POWER Engineers, we work hard to facilitate cross-discipline training and experience. It became clear to us that “microgrid engineering” takes this to a new level. Microgrids present a new paradigm for power system engineers.

Being the analytical engineers we are, what did we do next? We went to the white board, of course. We mapped out in broad brush strokes the engineering disciplines of the macrogrid vs. the microgrid.  We broke down the macrogrid into:

• Generation
• Transmission
• Substation
• Distribution
• Loads

The microgrid breaks down into:

• Connection to the macrogrid (PCC – point of common coupling)
• generation sources
• Distribution circuits
• Loads

The topologies between the macrogrid and the microgrid are, of course, fundamentally different. In the macrogrid, the transmission system is highly interconnected with a diverse mix of generation. Historically, loads are fairly isolated from generation. They are separated by substations, maybe sub-transmission and a distribution system. Although microgrids topologies are highly diverse, a generator and a load might be in the same room.

In macrogrids, generating plants run relatively autonomously, held together by the collective inertia of millions of pounds of rotating mass and the electrical grid that connects it. Microgrid generation requires tightly coordinated operation controlled by a carefully engineered master control system.

A quick scan of the headlines in the industry press would suggest energy storage is busting out, as utilityscale storage systems are being built to deal with the infamous duck curve, or imbalance of power production from renewable energy. The use of storage will be part of one big happy scenario of cheap, clean power, the theory goes. Every day you can read about another municipality, state or utility that has adopted a 100 percent renewable power grid goal, and despite derailment of the Clean Power Plan, utilities have not altered their renewable objectives.

A report by research firm GTM Research and the Energy Storage Association that showed utility-scale battery storage installed capacity grew by 221 MW in 2016, or about double that of 2015. Total utility storage is 622 MW. The figures are proof of growth of long-duration batteries and an increased confidence that large energy storage will help manage peak demand, the report argued. GTM analysts predict a 10-fold revenue increase in storage system sales by 2022 to $3.3 billion.

Another report by Navigant Research released in mid-2017 predicted that the global market for distributed energy storage will reach 27.4 GW and $49 billion by 2026.

The premise is that utilities can’t have a high percentage of renewable energy in their system without some storage to have power available when the sun isn’t shining or the wind isn’t blowing. Most peak uses are early evenings and during the hottest parts of the day for air conditioning. If fossil fuel is to be taboo, storage must be part of the answer.

Considering the above, here’s our question: Why are there not more battery energy storage systems being installed? At the current rate of growth, getting from 622 MW to 27 GW in eight years appears to be an impossibility.

Most of the new storage added last year – 120 MW – was built in California, and that was required by state regulators. Storage isn’t a part of most utility resource integration plans because they have a variety of power generation sources for spinning reserves, demand side management and grid sharing arrangements.

The simple answer to our question is that storage isn’t cost-effective – yet. Storage costs are falling; therefore, it is frequently prognosticated by many – particularly storage vendors and their associations – that storage will fill the void in the grid created by intermittent output by renewable sources. But is that assumption true? When will storage become cost-effective? The answer is intertwined with the technology that will eventually win out.

Enel has become the latest big name to spy opportunities in the commercial and industrial (C&I) energy storage space in Ontario, Canada, signing an agreement this week for its first project in the region.

Due to come online in the first half of this year, Enel X, Enel’s advanced energy services division, through its acquired US subsidiary EnerNOC Inc, has done a deal with an apple orchard group, Algoma Orchards of Ontario, Canada, to install a 1MWh lithium-ion battery energy storage system at the latter’s facilities.

Under an 11-year agreement, EnerNOC will continue to operate the behind-the-meter system and will reap financial benefits on two fronts: firstly from reducing the apple producer’s peak demand from the grid, as is common in such installations, and also by using the battery to participate in Ontario’s regional demand response programme.

Back in 2016, Energy-Storage.News reported from talks with the trade group Energy Storage Ontario (now known as Energy Storage Canada) that the clean energy industry credited the province’s regulators and policymakers for sticking to a “clean, reliable and affordable” remit when it came to grid and energy infrastructure planning.

This has lead not only to support for front-of-meter, grid-scale energy storage deployed directly to benefit the grid, but also created the likes of the Global Adjustment Charge, by which grid upgrades, decarbonisation and modernisation of the network are partly paid for by charging business electricity ratepayers’ peak demand costs. In its release yesterday Enel said the 1MWh Algoma Orchards battery would indeed benefit from financial savings under that policy.

A report from the Fraser Institute found that electricity costs for large businesses in Toronto and Ottawa, both cities in Ontario, rose by around 50% in each between 2010 and 2016, compared to an average of 14% for other cities in Canada. However, hourly energy costs have steadily declined almost five times over in that period.

A new research by Greentech Media (GMT) shows that Australia is leading the global race in energy storage, having installed the most storage technology in the world during 2017, ahead of Germany, the United States and Japan.

According to GMT’s “Global Energy Storage: 2017 Year in Review and 2018-22 Outlook” Australia installed an astonishing 246 megawatts (MW) of energy storage power capacity, enough to power almost 400,000 homes at one time, while also taking second place for energy capacity (MWh).

“Australia is on an energy storage winning streak and was also recognised as having the biggest household storage market anywhere in the world last year,” climate councillor and energy expert Greg Bourne said.

“Our transition to clean, reliable and affordable renewable energy and storage technology is already in full swing, with the nation home to the most powerful lithium ion battery in the world plus a collection of new storage projects in the pipeline.”

Bourne, the former President of BP Australasia, said renewables plus storage technology was a winning combination for tackling worsening climate change, while also making economic sense.

“In the past eight years the price of lithium-ion batteries has dropped by 80% and is tipped to halve again by 2025, which is driving investment in this booming industry both here and abroad,” he said.

Earlier this week, the United Nations also released the latest renewable energy data for 2017 where Australia again was ahead of the pack, with investments jumping 147% to $11 billion (AU).

Accept the inevitable

In the battery industry, records seem set to be broken almost as soon as they are hit. This is what may be about to happen with the largest battery storage system to date, if a California company gets all the permits it needs to build a 350-MW installation in the desert near Palm Springs.

When Tesla completed its 100 MW/129 MWh last year, it became a hallmark in the evolution of renewable power, signaling that the race for bigger and better storage systems was just beginning. Now, Recurrent Battery has staked its own claim in this race.

The San Francisco-based company is the U.S. unit of Canadian Solar and it has plans to build a 350-MW solar farm in the California desert along with a battery storage system of the same size. The Crimson project will span 2,500 acres. However, it is far from certain it will be completed.

The idea is certainly great. Tesla’s battery can power several tens of thousands of households. This one—if built—would power three times that, reducing this part of California’s dependence on natural gas power plants. These are now used after sunset for lack of enough solar energy storage installations. But the key is to find a buyer for the energy that will be produced by the solar farm—and this client needs to be large enough to justify the investment.

In other words, for now, the battery that will have triple the size of Tesla’s jewel is still just a possibility. Another project, however, is not: A British billionaire is building a 120 MW/140 MWhinstallation not far from Tesla’s installation in Australia.

Sanjeev Gupta, owner of Australian steelworks Whyalla, is building the battery to use both as storage for electricity produced by a solar farm, and in construction at the steelworks site. What we’re seeing there is likely just the beginning of ever-bigger battery storage systems that will accompany every large-scale solar or wind project.

There’s been plenty of talk about how Australian solar households are warming to the idea of battery storage, but little concrete data to back this up. Until now.

A new report from solar analysts, SunWiz, has revealed almost 21,000 behind the meter energy storage systems were installed in Australia in 2017, a three-fold increase on the year before.

On top of that, the report finds that 12 per cent of the 172,000 new solar systems installed in the booming 2017 market included a battery, up from six per cent in 2016.

But what does this trebling of battery storage uptake mean? Is it a sign that batteries now make economic sense to the average Australian household?

Well, it’s complicated.

If your metric is return on investment (ROI), there are a lot of variables that you need to weigh up – and they change from home to home, and state to state, and even from one distribution company to another. And we look into all that in-depth below.

But for those not banking on ROI – and plenty of consumers are not (think cars, couches, TVs) – then it’s pretty straight forward.

“With energy prices rising this year, Australians are embracing the idea of being able to control their energy consumption and costs,” said SunWiz founder and managing director, Warwick Johnston.

And battery storage can certainly do that, as long as you can afford to install it in the first place. ‘

As the SunWiz report shows – and the charts below illustrate – a Sydney household that invests in solar PV and a Tesla Powerwall 2 can achieve a $1,931 reduction (or 72 per cent) reduction in their annual power bills.

For those who can’t afford the up-front cost, there are deals like sonnenFlat – where households can install a 10kWh battery by German manufacturer sonnen at no up-front cost, instead paying a fixed monthly fee of $30, $40 or $50, depending on the system size and energy usage.

According to sonnen, this deal has already been popular in Australia – popular enough that the company is building a manufacturing plant here.