It’s likely a strong indication of the way the world is adopting renewable energy rapidly that just under a month ago, one of the best-established trade shows for solar in the US featured what seemed like almost as much space dedicated to national and international energy storage companies and technologies, as it did for solar.

Solar Power International, which was held this year in Anaheim, California, is co-located with Energy Storage International, but you could almost say that the show as a whole is almost like a solar-plus-storage show in many ways. Sure, the module manufacturers you read about on PV Tech were there, and there’s still clearly markets for ‘standalone solar’ all over the US. But it has become so inevitable that storage – mainly in the form of batteries – will play a huge role coupled with renewables that several conference speakers and sources I spoke to said that it could even be just a handful of years before we no longer talk of solar without storage at all in the US, perhaps excepting a few specific applications or business cases.

“Storage has always been on the horizon for the solar industry but today with time-of-use shifts, the movement of the more valuable electricity to later in the day, makes storage able to provide a uniquely attractive value proposition to the solar industry, to the solar customer, now,” Alan Russo of Stem Inc says.

One of the leaders in providing smart storage systems to commercial and industrial (C&I) operations that want to lower their peak energy costs, Stem has made its first-ever foray into adding solar to its offerings in a rare example of storage industry folk coming to solar rather than the other way around. Russo said Stem believes the combined offering can provide value in several directions too.

“The solar only marketplace is becoming more competitive, the value of solar is dropping as rates are shifting to later in the day,” Russo says.

“When you add storage you increase the gross margin for the engineering, procurement and construction (EPC) partner, you increase customer returns and then you provide utilities with the value they’re seeking by shifting those rates. Rate shifts are designed to change consumer behaviour, [but] we allow customers to operate how they want to, and everyone benefits from the improved economics.”

California recently joined other leading states, provinces, cities, and corporations around the world by setting an ambitious 100 percent carbon-free electricity target

. It’s a landmark, not because California was the first, but because it is the biggest. The state ranks as the fifth-largest economy in the world.

Achieving 100 percent carbon-free electricity means lots of wind and solar. Alongside more-flexible demand, balancing such renewable energy will involve bringing more energy storage onto California’s grid, to store surplus clean generation, which is where the state’s Self-Generation Incentive Program (SGIP) comes in.

SGIP has spurred record-breaking levels of energy storage, all intended to lower California’s overall greenhouse gas (GHG) emissions. But is it working? It turns out: not so well.

Last month, the California Public Utilities Commission (CPUC) released an answer in the form of its 2017 SGIP Advanced Energy Storage Impact Evaluation, and the results were sobering.

The 2017 edition of the report, like the 2016 edition, found that energy storage systems in California are actually increasing emissions across residential and non-residential projects alike. This is not just a California problem. It adds to the growing consensus that, as of today, the operation of energy storage increases emissions.

For Energy Storage Emissions, The Devil Is in the Charge / Discharge Details

The 2017 SGIP impact evaluation evaluated GHG impacts using marginal emissions for each hour of the year. That’s because each time batteries charge, they’re increasing the total amount of demand on the grid; each time they discharge, they’re decreasing overall grid demand.

October 18 (Renewables Now) – In a drive to reduce its energy costs, the San Diego Zoo has awarded EDF Renewables North America Distributed Solutions an energy storage services contract supported by a 1 MW/4 MWh battery.

The contract is in line with San Diego Zoo Global’s fiscal and sustainability planning, says the joint press release Wednesday.

With energy storage, the zoo will be mitigating spikes in usage, thus lowering demand charges. The organisation plans to minimise energy costs by recharging the battery when electricity rates are low, and discharging that power when costs are high.

The EDF Renewables contract is performance-based as the company is only paid for the actual utility bill savings realised by the zoo, as a result of the battery operation. There will be no fixed payments and no performance risk for the zoo, San Diego Zoo Global noted.

The French Energy Regulation Commission (CRE) has selected a pair of battery storage projects by Voltalia that will benefit the function of the Guianese electrical network.

The “Mana Storage” project from Voltalia consists of two battery storage units for an installed capacity totaling 10 MW, and is the main project selected by the CRE in French Guiana and will benefit from a 10-year remuneration contract.

That contract will begin at the commissioning of the project, which is slated for the end of 2019. This battery storage project stands as the first of its kind in Guiana.

Sébastien Clerc, CEO of Voltalia, said: “We are proud to use once again our knowledge of isolated networks and our know-how in terms of storage to better serve the inhabitants of French Guiana. They will benefit from cheaper electricity during peak periods and from a more stable electricity network. In addition, this new storage project is located in the same area as Voltalia’s very first power plant.”

Lithium-ion batteries will be equipped at the project, which stands as the second storage project initiated in French Guiana after the Savane des Pères project (4MW PV and 2MW of storage).

The first unit (5MW)  ill be used for daily arbitrage, storing cheap electricity produced in the middle of the day and releasing it during peak consumption in the evening, while the 5MW second unit will be used to regulate the frequency of the network by discharging stored electricity on the network when there is a drop in frequency due to lower production.

Sometime in the next month or two, the first investment in what will be a significant new stage in the transition to a renewable energy dominated grid in Australia will be made.

It will be confirmation of the world’s first investment in a project that co-locates, for the first time, large-scale solar with a large-scale pumped hydro storage facility – and the first example in Australia of a storage facility with vastly more storage capacity than the renewable energy source it is paired with.

Storage is a new phenomenon in Australia – even though there are a handful of pumped hydro plants scattered around the main grid, from Wivenhoe in the north, to Shoalhaven and Tumut in NSW.

There has been extraordinary interest in the performance of the country’s first large-scale battery, the so-called Tesla big battery at Hornsdale, which is also the world’s biggest lithium-ion installation.

This, and the Newman battery in the Pilbara, have stunned observers with the speed, accuracy and flexibility, challenging the primacy of the fossil fuel industry in providing both frequency and inertia, and defying the assumption that you need fossil fuels to keep the grid intact.

One expects as much excitement and scrutiny of the Genex project at Kidston, although that won’t be the only project that is due to get an investment nod around that time. Snowy Hydro is also working feverishly on its own grand plans to recreate the splendor of the original hydro scheme and add a $6 billion plus project to be known as Snowy 2..0

It is not entirely clear, however, that the investment decision to be taken by early December will be a commitment to the whole project, the 2,000MW facility with 175 hours of storage, or to fund extensive tunnelling that will then form the basis of further investment.

Whatever the case, these are not the only pumped hydro schemes that are being looked at in detail.

Everyone agrees that Federal Energy Regulatory Commission Order 841, and its commandment to create participation models for energy storage across the country, is going to be a big deal.

Brattle Group estimates there are about 7,000 megawatts, or more than 20,000 megawatt-hours, of cost-competitive energy storage potential to be unlocked by Order 841’s implementation across the capacity, energy and ancillary services markets run by the country’s independent system operators (ISOs) and regional transmission organizations (RTOs).

But behind these grand-scale projections, there are dozens of key details being worked out that will affect how much of that energy storage potential is unlocked, at what pace, and at what cost. Order 841 implementation is now in the hands of the ISOs and RTOs. And while many of its key provisions are set in stone, many more are left up to the grid operators and various stakeholders to work out in ways that best suit their particular needs.

These are the details that are keeping the energy storage industry, as well as state regulators and public and private utilities, finely tuned for each new Order 841 implementation plan, known as a “straw proposal,” to come from the nation’s ISOs and RTOs. This month so far has seen a final straw proposal from Midcontinent Independent System Operator (MISO) put before stakeholders, as well as the latest iteration of straw proposal from PJM Interconnection. As the country’s biggest grid operator and as host to hundreds of megawatts of batteries playing into its frequency regulation market, PJM is a focus point for the industry.

These proposals are coming at a relatively rapid pace for a process that took nearly two years to move from a proposal to a final rule. ISOs and RTOs have a deadline of December 3 to file the tariff changes needed to “establish a participation model for electric storage resources that ensures eligibility to participate in its market in a way that recognizes the unique physical and operational characteristics of such resources.” By December of 2019, those rules are set to go into effect.

Southern California Edison has selected esVolta to develop, build and operate four energy storage projects totaling 38.5 MWh in Riverside and Ventura counties, the companies reported.

The projects, which are pending approval by the California Public Utilities Commission, include the Wildcat Energy Storage project (3 MW/12 MWh) near Palm Springs and the three Acorn Energy Storage projects (total combined capacity of 6.5 MW/26.5 MWh) in Thousand Oaks.

All four projects, if approved, are expected to go into service by March 2020.

“esVolta is delighted to be selected by SCE for the Wildcat and Acorn projects,” said Randolph Mann, president of esVolta, in a statement. “These contract awards represent a major milestone for esVolta as we continue to grow our energy storage business platform. We look forward to delivering cost-effective storage solutions for SCE, a leading electric utility and a key supporter of advanced energy storage technologies.”

Rosemead-based SCE included the Wildcat and Acorn projects as part of the utility’s integrated distributed energy resources RFO (request for offers).

The overall RFO includes multiple distributed energy resources such as renewables, energy efficiency, demand response, energy storage, substation and circuit upgrades. They are designed to provide incremental capacity at targeted points along SCE’s electric distribution system.

State regulators have tasked California’s three investor-owned utilities—SCE, Pacific Gas & Electric and San Diego Gas & Electric—to procure 1,25 MW of energy storage capacity by 2020. SCE’s share of that target is 580 MW, according to reports.

California-based esVolta has a portfolio of operational and/or contracted storage projects totaling more than 450 MWh, according to the company.

The cost of energy storage has fallen to the point where the power generation industry is moving from demonstration projects to full deployment. Driven by demand and a federal order designed to nurture broader adoption of storage capabilities, practical applications of energy storage are emerging that are competitive with conventional solutions.

In addition, continued annual reductions in the cost for storage will reveal more and more applications where energy storage makes economic sense. A great example can be found in the performance optimization of gas turbines.

In recently establishing Order 841 to integrate energy storage into the power market, FERC declared the order would “enhance competition and promote greater efficiency in the nation’s electric wholesale markets, and will help support the resilience of the bulk power system.” While many initially ascribed storage’s primary value to the capture of renewable energy and subsequent grid resilience, new scenarios are emerging that pair storage with conventional gas turbine generation to deliver more rapid response, milder ramp rates, fewer starts and stops, and emissions reductions.

In a way, gas turbines and renewables are beginning to solve each other’s problems.

Gas turbines have long played a central role in helping supply meet demand, given their ability to quickly flex up or down to demand peaks and dips. But their efficiency is diminished when running under or above optimal load. Meanwhile, the rise of renewable energy sources promises to reduce our carbon footprint, but they also carry hazards for utility managers because their
variability and intermittency complicate loadbalancing and grid-planning efforts.

Enter the battery storage-augmented gas turbine, in which storage performs as a kind of reserve that springs to life to smooth and optimize turbine performance levels.