During the past couple of years at renewable energy conferences and industry events, the conversation regarding battery energy storage systems has focused on the prevailing notion that energy storage, from an emerging technology standpoint, is where traditional solar was roughly eight to 10 years ago.

In the utility-scale context, despite the increasing deployment of battery energy storage systems, some utilities are still hesitant to purchase energy storage systems because the costs and technology are still evolving. From a contractual standpoint, utility-scale battery energy storage system transactions present unique legal issues and require special analysis of traditional contract provisions.

Here are the top five legal issues to consider when contracting for utility-scale energy storage:

1. Uptime Guarantee
2. Intellectual Property
3. Security for Payment and Performance
4. Force Majeure and Changes in Law
5. Indemnity and Insurance

Uptime Guarantee

A critical performance component of a battery energy storage system is the guarantee the vendor and/or manufacturer is willing to provide the purchasing utility regarding the amount of time (usually reflected as a percentage and calculated monthly or annually) the system will be fully operational (i.e., the system’s “uptime” or performance assurance).

From a contractual standpoint, several critical issues regarding uptime guarantees must be considered and negotiated:

• How to define uptime, which requires, among other things, the parties’ agreement on
  the scheduled maintenance parameters for the system because scheduled maintenance
  is not counted as downtime for purposes of calculating the system’s uptime;
• How to define and quantify damages from a breach of the system’s uptime guarantee.
  In states such as Texas, where utilities can generate significant revenue from energy
  storage systems by performing frequency regulation, damages from a breach of the
  uptime guarantee are typically tied to the revenue lost by the utility during the time
  the system was down beyond the uptime guarantee;
• The vendor’s and/or manufacturer’s monetary liability caps as a result of revenue lost
  by the purchasing utility due to breaches of the uptime guarantee; and
• Contingencies of the uptime guarantee, such as the requirement that the vendor and/or manufacturer perform operation and maintenance services on the system.

US utilities deployed more than 520MWh of energy storage on their networks in 2017, bringing the country’s cumulative installed capacity of grid-connected energy storage systems to over 1GWh, trade organisation Smart Electric Power Alliance (SEPA) has found.

By the end of 2017, 922.8MW / 1293.6MWh of grid-connected storage capacity was on US networks across 5,167 systems. Throughout 2017, utilities alone interconnected 216.7MW / 523.9MWh to the grid, amounting to 2,588 systems. Surveying 137 utilities, SEPA said 13.3MW / 29.3MWh of residential systems were added during the year, with 59MW / 139.7MWh of non-residential and 144.4MW / 354.9MWh of utility-supply systems.

SEPA, which considers its remit to be that of helping utilities to deploy clean and smart distributed energy solutions, publishes regular ‘Top 10’ lists ranking utilities in the US by the amount of solar deployed in their respective services areas, has this time out issued a 52-page report which can be found on the organisation’s website. As well as including rankings of energy storage utility deployment figures, both in watts and watts-per-customer, the report features in-depth analysis of the national picture state-by-state as well as at national or federal level.

From the top-down perspective, it appears durations of storage are increasing. Overall deployments in megawatts across the US rose by 5% from 2016 to 2017, while the corresponding megawatt-hour figure rose by 104%.

The two ‘Top 10’ tables for utility deployments are as follows:

China is looking to boost its energy storage market and projects as it adds growing renewable power capacities. At the end of last year, the Chinese authorities issued a unified nationwide policy to boost the energy storage industry that has been lagging behind other countries despite the fact that China is leading global investments in renewable energy.

Also thanks to the central government policy boost, and to some regional storage policies, China added nearly as much battery storage capacity in  the first half of 2018 as it had in total at the end of 2017, according to  data by the China Energy Storage Alliance (CNESA).

Between January and June, new energy storage projects of various scale and capacity were announced in the provinces Jiangsu, Henan, Qinghai, and Guangdong. Those projects—including planned, under construction, or already operational—total 340.5 MW. That’s almost as much as the entire Chinese capacity that was operational as of the end of last year—389.4 MW.

So far this year, the newly operational capacity has already surged by 281 percent compared to the entire new capacity for the whole of 2017, the Chinese Alliance says.

“If the entirety of this new capacity begins operation on schedule, China’s domestic energy storage market will see an amount of growth that will make 2018 one of the most significant years yet for the industry,” CNESA said.

The growth looks impressive, but compared to China’s population, territory, and renewable installations, 340.5 MW is not that big of a figure and doesn’t include storage technology for electric vehicles, of which China built 40 GWh worth of batteries in 2017, Quartz reports.

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In energy storage, China hasn’t been a big market player and developer, but according to a GTM Research report on global storage deployments, in five years China could surpass almost everyone except for the United States.

“It’s a bit surprising that China hasn’t adopted storage any faster, because it has all the right ingredients to be a major storage market,” Ravi Manghani, energy storage director at GTM Research, said.

The energy storage sector has been growing robustly, despite some concerns about the global supply chain for one key material, lithium. Well, that question could soon be moot. The California-based startup Lilac Solutions has just received a major financial boost for an innovative, low-impact method for extracting lithium from abundant brines around the globe.

Diversifying the global supply chain could help alleviate one source of anxiety for US energy policymakers. Currently, the top lithium producers are concentrated in a relatively small number of countries overseas, and uncertainty over President* Trump’s trade policy has layered another layer of complexity onto an already fraught situation.

Energy Storage And Lithium

For those of you new to the topic, lithium-ion technology is the gold standard for energy storage today. A more diverse field of options is beginning to emerge, but for now lithium is powering everything from smart phones and electric vehicles, on up to utility-scale batteries for grid use.

Though the reserves are mostly concentrated in just a few countries, lithium is relatively abundant. The primary source is salt brine, and the conventional extraction process is based on evaporation.

Last week, Lilac Solutions was among three startups selected for investment by the non-profit organization PRIME Coalition, which focuses on a high tech approach to manage climate change.

The company’s new technology addresses a couple of key issues involved in conventional lithium extraction. Lilac describes the problem in a nutshell:

Following news of SB100, legislation that would set California on a path to 100% renewables by 2045, the state is also on the brink of setting up a rebate programme for energy storage equipment sales.

Senate Bill 700 (SB700), authored by Senator Scott Wiener, would extend the state’s feted SGIP (Self-generation incentive programme) policy to 2024 and make more provisions to include energy storage. SGIP supports the deployment of solar, wind turbines, microturbines, fuel cells, energy storage and other distributed energy technologies by utility customers.

The rebate for energy storage equipment had been proposed some time ago. Last summer, Energy-Storage.news reported in June that the policy’s introduction appeared imminent, designed for mitigating the effects of California’s famous ‘duck curve’ of solar production versus load demand. Then, in July, the passing of the bill appeared to stumble, taken off the voting agenda at a California Assembly meeting.

At the time, analyst Brett Simon of GTM Research (now Wood Mackenzie), said it “spoke volumes” that the bill was excluded from the vote rather than “struck down” completely. Simon said that it was likely SB700 was being put to one side as California lawmakers sought to determine the future of the SGIP programme first before committing to new policy directions.

Yesterday, the California Storage + Solar Association trade group applauded as SB700 was passed by the California Assembly with a 57-18 final vote after passing the Senate with 25 votes to 13. It will now go to the attention of Governor Jerry Brown for his approval. The association said the Assembly’s vote was a “broad, bipartisan victory for local clean energy”, likening it to the start of 2006’s California ‘Million solar roofs’ programme.

Xcel Energy CEO Ben Fowke observed earlier this year that time is running out for coal-fired power plants in the U.S.

“I will tell you, it’s not a matter of if we’re going to retire our coal fleet in this nation, it’s just a matter of when,” Fowke said on stage at the EEI Annual Convention in San Diego in June.

For the Public Service Company of Colorado (PSCo), an Xcel Energy subsidiary, that time is now.

On Monday, the utility won preliminary approval for its coal plant retirement plan. The Colorado Public Utilities Commission voted unanimously to allow for the early closure of coal-fired units 1 and 2 at Xcel’s Comanche Generating Station in Pueblo County. The units are capable of producing a combined 660 megawatts of coal-fired generation, which represents approximately one-third of PSCo’s remaining coal fleet.

Under Xcel’s Colorado Clean Energy Plan (CEP), the Comanche coal units will be replaced with a $2.5 billion investment in renewables and battery storage — including of 1,131 megawatts of wind, 707 megawatts of solar PV, and 275 megawatts of battery storage across the state, including in Pueblo. Xcel estimates the transition will save ratepayers between $213 million and $374 million.

The decision comes as Xcel is attracting record-low clean energy prices. In January, the results of Xcel’s all-source solicitation returned a median price bid of $21 per megawatt-hour for wind-plus-storage projects and a median bid of $36 per megawatt-hour for solar-plus-storage.

Bids highlighted in the CEP are even lower. The plan includes wind at pricing of $11 to $18 per megawatt-hour, solar at $23 to $27 per megawatt-hour, and solar-plus-storage at $30 to $32 per megawatt-hour.

By 2026, the CEP will bring PSCo’s energy mix to nearly 55 percent renewable energy, up from 28 percent in 2017. Coal made up 44 percent of Colorado’s electric generation last year, which would decrease to about 24 percent under the plan. Natural gas will remain roughly the same.

Yesterday, solar and energy storage advocates had their second win in less than 24 hours. Following on the dramatic and narrow passage of a bill to mandate 100% carbon-free electricity by 2045, another bill which may contain one of the keys to making that happen has passed the Assembly.

SB 700 will extend the state’s Self Generation Incentive Program (SGIP) through 2026, which by the estimates of the California Solar and Storage Association (CALSSA) will support the installation of nearly 3 GW of behind-the-meter storage.

A very large volume of energy storage will likely be necessary for California to achieve the very high penetrations of wind and solar that will come online as the state approaches 100% clean electricity, a fact which was not lost on the bill’s sponsor.

“If we are going to get to 100% clean energy, we need to be using solar power every hour of the day, not just when the sun is shining,” stated California Senator Scott Wiener (D-San Francisco), the author of SB 700.

However, SB 700 is critical for another reason: it may enable the state’s residential solar industry to survive. As part of the move to net metering 2.0, new residential installations in the state are subject to time-of-use rates. Not only does this add greater complexity to the sales process, but with solar driving down mid-day demand, increasingly the most highly priced hours are after the sun sets.

Increasingly, the solution to this is energy storage, as the addition of batteries allows residential solar customers to store electricity from their PV systems during the day and either use it or export it to the grid during peak evening demand.

However, energy storage systems are expensive, as adding batteries typically doubles the cost of a residential PV system. That’s where SGIP comes in, by providing incentives that can help to put solar plus storage within the reach of more consumers.

The current version of SGIP allows state regulators to collect up to $166 million per year from the state’s three large investor-owned utilities to fund SGIP; however the program was set to expire at the end of 2019. SB 700 will add another five years and up to $800 million in funding for the program.

Germany helped make solar power cheap. As of June this year, it boasts 1 million homes that have installed rooftop solar panels. That means the country produces a lot of renewable energy—sometimes more than it can use.

At such times, German grid operators have had to pay neighboring countries or grids to use the excess electricity. Since the beginning of this year, German grids have accumulated 194 hours (paywall) with negative power prices.

Now Germany is turning to energy storage as a solution to the problem of excess electricity. On Aug. 28, an energy ministry official attended the commissioning (link in German) of the 100,000th home to install a battery-storage system that’s connected to the grid.

Home battery-storage systems can soak up energy from the sun during the day, when typically household consumption is low. Then the batteries can kick after the sun sets and consumption tends to rise. Since 2013, lithium-ion battery costs have fallen by 50%. That’s made the economic case for home battery-storage systems more attractive.

The advantage of having the batteries connected to the grid is that, beyond household usage, grid operators can combine this distributed storage resource to create a virtual power plant. So if a home battery has more energy than the homeowner can use, the excess energy could be sold onto the grid and used by another home that doesn’t have a battery-storage system of its own. Put another way, virtual power plants allow homes to gain the benefits of a battery, such as lower-price electricity, without having to pay upfront for battery installation.

This August brought the collapse of two emblematic energy storage firms.

In the U.S., lead-carbon battery maker Axion Power International filed for Chapter 7 bankruptcy. In the U.K., grid-scale storage system developer Camborne Energy Storage went into administration.

Both firms ran aground after failing to secure cash to fund operations. Axion, of New Castle, Pennsylvania, had $6.6 million in debts and only around $47,000 in assets, according to local press reports.

The company was a veteran of the energy storage industry, having been founded in 2003. As reported in GTM back in 2009,  Axion aimed to give lithium-ion a run for its money with an advanced lead-acid battery equipped with carbon electrodes.

The electrode technology, from a Russian company that had been developing it for superconductors, was supposed to give the battery a lifespan three to four times longer than batteries using traditional lead negative electrodes.

Axion invested about $50 million in adopting it for use in batteries and secured a supply deal with big battery maker Exide Technologies. After having been listed on the over-the-counter bulletin board in 2003, in 2014 the company graduated to Nasdaq.

It struggled, though, and delisted a year and a half later after its stock spent a month trading below $1. Attempts to commercialize the technology ran into difficulties, too.

In March last year, Axion filed an 8-K form with the U.S. Securities and Exchange Commission (SEC), warning shareholders of significant financial hardship after a dozen attempts to get the lead-carbon battery to market.

The company’s production line had not made a battery since 2016, it later emerged. Desperately seeking a way out, Axion pivoted away from manufacturing and toward research and development with a business model based on technology licensing.

Even that didn’t work, though. A 10-K SEC form filed in July revealed that Axion was operating with a skeleton staff of four and pinning all its hopes on a single commercial agreement, with a Chinese company called Fengfan Co Ltd.

From 2015 through 2018, the filing said, “Axion initiated over 30 separate efforts to identify shareholder-enhancing transactions. Except for Fengfan’s interest in partnering with the company, all other efforts have failed.”