As US president Donald Trump throws his support behind “beautiful clean coal,” the American state of Arizona — a Republican Party stronghold — is poised to take the lead on energy storage in the country as it tosses up whether to impose an 80% clean energy target by 2050.

The proposed clean energy overhaul, called the Energy Modernisation Plan, would require an impressive 3GW energy storage to be installed by 2030, meaning it would overtake California and New York for the biggest storage mandate in the country.

The proposal was put forward recently by the Arizona Corporation Commission’s Andrew Tobin as a way to both decarbonize the state’s power supply, and to meet its peak power demand in a cheaper and cleaner fashion.

The plan calls for the state’s investor-owned utilities to source 80% of their electricity from a mix of renewable and nuclear energy by 2050 and deploy 3,000MW of energy storage by 2030, along with reforms to boost energy efficiency, electric vehicles, and biomass.

And the plan’s proposed “Clean Peak Standard” would require utilities to deliver an increasing portion of their renewable energy during peak electricity demand hours, thus encouraging the deployment of energy storage capacity.

As Greentech Media reports, the ambitious proposal would “leapfrog” Arizona ahead of California and New York, “which have dominated the grid modernization discussion so far,” both with 50% by 2030 renewable energy targets, and storage targets of 1,300MW and 1,500MW respectively.

It also demonstrates a similar state vs federal government divide as we have seen play out in Australia, with states leading on the shift to decentralized, renewable energy, while conservative national leaders cling desperately to coal and other centralized fossil fuel generation sources.

“We’re not trying to get on the train; we’re trying to be the engine in the train,” Tobin told Greentech Media. “This is Western people doing things and setting lofty goals and reaching them.”

But as well as shifting the state’s focus to renewable energy and storage, a major aim of the plan would also be to shift the focus away from gas generation, which, according to UtilityDive, Arizona utilities have been doubling down on.

“What this plan is saying is we aren’t going to build our future on natural gas — the backbone of the system over the next 40 to 60 years will not be gas,” said Lon Huber, a consultant who worked to craft the original Residential Utility Consumer Office RUCO) proposal.

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Energy storage has frequently been cited as the critical missing link in an electric infrastructure designed to maximize the benefits of cheap, renewable energy.  Because energy from the sun and the wind is inherently intermittent, it has not been able to satisfy a round-the-clock need for electricity.  And in many places we’ve built more renewable capacity than we can use, when the sun is shining, or when the wind is blowing.  For example, in sun-soaked California and the West, electric grid operators have recently been confronted by the challenge of “over-generation” during peak solar hours of the day, which can result in the curtailment of solar generation to avoid overloading the grid with electrons.  Similarly, in Texas, so much wind blows at night that the electricity off-takers can sometimes get paid through “negative” power prices to use the wind power.

For California, a state that has set its electric grid on a path toward 50% renewable by 2030 (SB 350 (De León)), and one that is considering a 100% RPS by 2045 (SB 100(De León)), the question of energy storage has taken on a practical significance.  And regulators at the federal and state level have been quite busy taking down barriers that have made the increased adoption of energy storage resources impracticable.

Today Bud Earley of Covington blogged about the recent approval at the Federal Energy Regulatory Commission (FERC) of its 2017 electric storage rulemaking.  That rule set out broad market criteria for the participation of energy storage resources in regional electricity markets, and left the question of distributed energy resources (DERs), for a later date.

Given its innovative policy work on both fronts, California is a natural market to look to for policy models that may be relevant beyond the California ISO (CAISO).  In California, state regulators have already begun seeking comment and setting rules for the participation of both DERs and energy storage in the market.  The CAISO has begun, for example, reviewing applications from some companies, including investor-owned utility companies, to seek approval as distributed energy resource providers (DERPs); and the CAISO has sought and received approval from FERC to seek tariff proposals that allow DERPs to aggregate and sell resources in the grid.  And with respect to energy storage, the state regulator — the California Public Utilities Commission (CPUC) — recently issued a decision for new “multiple-use” applications for energy storage, which allow storage providers to “stack” various services.

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Cheap energy storage, long-hailed as renewable energy’s younger cousin that once of age would create a dynamic duo strong enough to upend the electricity system as we know it got a steroid shot this week when FERC announced that it was going to let energy storage operate in the wholesale markets as both a buyer and a seller.

While this development plays to storage’s benefit, the market (at current prices) is still relatively small. For energy storage to make a big play, costs still needs to come down by about half and the market itself might have to change.

In the U.S. most energy storage comes from pumped hydro facilities, but these systems require large amounts of co-located land, elevation, and water. Batteries have been (or will be) built in both Texas and Arizona in order to defer expensive transmission line upgrades.

But battery prices are now declining to the point where they are starting to move into new markets. Tesla’s 100MW/129MWh battery in South Australia appears to be taking full advantage of market price fluctuations and helping the grid ride through multiple coal plant trips this (Australian) summer.

In the U.S., Tucson Electric Power recently entered into a power purchase agreement with a 100MW solar + 30MW/120MWh battery project for about 4.5 cents/kWh and Arizona Public Service (APS) just this month contracted with First Solar to build a 65MW solar + 50MW/135MWh project with the stipulation that its capacity be available summer afternoons from 3-8pm. At other times, the battery is free to provide other services to the market. Both of these projects benefit from the fact that, if a battery charges mainly from solar, it is eligible for the same 30% investment tax credit as the solar itself.

Battery energy storage is starting to target peak demand hours. Peak demand usually happens on summer afternoons (both north and south) when people are getting home from work and air-conditioners are straining to keep homes cool. There are also winter peaks for cold weatherwhich can occur on cold mornings when people are just waking up and getting ready for the day.

In the U.S. we usually meet our peak demand with natural gas combustion turbines. These types of power plants are basically jet engines bolted to the ground and hooked up to a generator. They can start and ramp their output quickly, making them good for following swings in load. Some areas of the country utilize diesel engines as peakers and lately natural gas internal combustion engines (diesel engines reconfigured to run on natural gas) are frequently deployed.

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The automotive industry increasingly is looking toward electrification as a solution to meet changing emissions standards across the globe and as regulations become stricter, they are taking these initiatives even further.

While automakers traditionally have approached vehicle electrification in micro-hybrid vehicles through start-stop technology, which shuts off the engine when the car comes to a stop, the industry is evaluating new electrification strategies to meet future carbon-dioxide emissions standards while increasing performance and features.

Several of these new technologies will be adopted in mild-hybrid vehicles where an electric motor assists the combustion engine during short accelerations or braking and by allowing it to turn off for longer periods of time while the car is coasting. As a consequence, the combustion engine potentially can be downsized to significantly reduce emissions without compromising performance.

To push fuel economy even further, mild-hybrid vehicles often combine the efficiency advantage of an electric turbocharger with an electric braking system for recuperation.

In addition, premium vehicles will continue offering a wide variety of new, innovative electric features that provide comfort for the driver and the passengers, such as electric active-roll control, electric power steering and electro-turbocharging. Collectively, these features have demanding power requirements and each requires frequent, quick, high-power charge and discharge events, which is pushing energy-storage engineers to revolutionize the board-net strategy for the platform.

The Limits of Lead-acid and Lithium-ion Batteries

Traditionally, lead-acid batteries have been used in automotive applications due to low cost and simple monitoring. But, when exposed to high discharge rates or rapid cycling applications, those batteries experience accelerated aging, which automakers traditionally have overcome by oversizing the battery. However, using larger lead-acid batteries cannot reasonably compensate for peak power demands that can be up to 10 times higher than traditional architectures, while still meeting strict weight and size objectives.

In recent years, lithium-ion batteries have been increasingly adopted by the automotive industry because of their improved power and energy density performance compared to lead-acid batteries. Although the technology has made significant performance improvements, their low temperature profile and sophisticated battery-management system with heating and cooling remain a constraint to achieve optimal performance and lifetime.

Solving Batteries’ Shortcomings With Ultracapacitors

Because of batteries’ high-power performance limitations, ultracapacitors are gaining traction as an alternative energy-storage technology. There are two possible ways to integrate ultracapacitors to the energy-distribution network: as exclusive energy storage in a sub-network, also called an island solution; and in parallel with batteries, creating a hybrid energy-storage system.

While the first topology has been designed multiple times to assist high peak-power loads of a single function, hybrid energy storage is gaining traction in combining the high-energy density of the battery with the high-power density of the ultracapacitor.

The Federal Energy Regulatory Commission has passed a rule that will open U.S. wholesale energy markets to energy storage on an equal footing with generators and other grid resources. But it hasn’t yet figured out how to address the same challenge for distributed energy resources.

On Thursday, FERC commissioners unanimously approved the final version of a rule, first proposed in November 2016, designed to “remove barriers to the participation of electric storage resources” in the wholesale energy markets that make up about three-quarters of the country’s electricity supply.

Within the next nine months, each of these regional transmission organizations (RTOs) and independent system operators (ISOs) will be required to come back with a plan for revising its tariffs to establish a participation mode for energy storage, “consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, facilitates their participation” across the range of markets that make up a regional transmission grid.

That’s a much broader set of opportunities than those currently available to large-scale batteries, pumped hydro systems, thermal energy storage and other types of energy storage now participating in ISO and RTO markets. To date, those have been limited in geography and in type, with the vast majority of storage playing in fast-responding frequency regulation markets, and with viable markets in only a handful of jurisdictions.

This biggest, mid-Atlantic grid operator PJM’s frequency regulation market, has also became the largest U.S. market for energy storage, with about 250 megawatts of cumulative deployments since 2013 — although it’s largely tapped out at present and suffering from some of the side effects of its own success.

FERC’s new rule will expand the scope of energy storage’s participation beyond frequency regulation and into larger ancillary services and wholesale energy and capacity markets, and for all ISOs, not just the handful like PJM and California grid operator CAISO that have taken the lead on the matter.

ISOs and RTOs still have a year to implement these future energy storage market participation rules. But when they do, they will likely become one of the largest opportunities for energy storage in the country, noted GTM Research’s Ravi Manghani. “This opens the floodgates for storage participation,” he said.

Energy storage and clean energy groups also praised the decision, noting the benefits that grid-scale batteries are already providing in the limited applications where they’re cost-effective, and hold promise for much broader applications as battery prices continue to fall in years to come.

FERC’s commissioners concurred in their written statements. Commissioner Cheryl LaFleur, a Democrat, called storage a “Swiss army knife” in its ability to provide energy alongside variable renewable generation, provide frequency regulation and other ancillary services, and help defer distribution and transmission needs.

Large businesses in Ontario have experienced a drastic increase in electricity costs in the past decade. In Toronto and Ottawa, for example, electricity costs grew 53% and 46% from 2010 to 2016, compared to an average increase of 14% in other Canadian cities over that period, according to a report released in October by the Fraser Institute. Last year, large industrial organizations in the province paid nearly three times as much for electricity as their counterparts in Montreal and Calgary, the report added.

However, this increase in total electricity costs has coincided with a steady decline in hourly energy prices in Ontario. The Fraser Institute’s report shows that while the total commodity cost for electricity has grown from about 8¢/KWh in 2005 to nearly 12¢/KWh in 2016, the hourly Ontario energy price has declined from roughly 9¢/KWh to less than 2¢/KWh.

What’s Behind Rising Electricity Costs in Ontario?

The primary driver of increased electricity costs in Ontario has been the Global Adjustment (GA) charge, which is passed onto Ontario customers’ hydro bills. Energy providers impose GA costs to cover their costs of providing adequate generating capacity and conservation programs throughout Ontario. Generally, when the wholesale market price for energy is low, GA is higher to cover generation costs. The GA rate is also impacted when new conservation projects are launched, when contract payments take effect, and when electricity demand shifts in Ontario.

As you can see in the chart below, GA costs spiked in 2009, and continue to drive up overall commodity costs for customers.

How Ontario Businesses Can Reduce Electricity Costs

Thanks to a recent policy change, large businesses in Ontario can start to gain control of the GA charges that drive up their annual electricity costs.

Since 2010, Ontario businesses that qualified for the Industrial Conservation Initiative (ICI) were assessed an annual GA rate based on their contribution to peak demand on the grid. The GA charge for each building was calculated based on that building’s demand at the top five peak demand hours for the Ontario grid every year. This created the opportunity for these buildings to reduce their annual GA charges—if you can predict when peak demand is most likely to occur and temporarily reduce your demand for that period, you can reduce your GA charge.

In 2017, Ontario expanded eligibility for the ICI. Whereas the program was previously limited to buildings with an average peak demand of 5 MW or greater, the program is now open to all buildings with a peak demand of 1 MW or greater, as well as those in select industries with a peak demand of 500 kW or greater.

Greensmith Energy, a part of the Wärtsilä technology group, was selected by Origis Energy USA to provide advanced energy storage integrated with solar photovoltaic (PV) in Sterling, Massachusetts, USA. The resultant hybrid system will allow the PV installation to better handle peak loads and provide secure, reliable electricity supply to the Municipality and State.

Greensmith Energy will deliver the 1 MW / 2 MWh energy storage system using LG Chem batteries and Sungrow inverters to Origis Energy, a leading US-based provider of solar energy and storage solutions, with over 1 gigawatt of developed solar capacity. The order was booked in the fourth quarter of 2017.

“Energy storage is the integrative component to deployable community solar plus storage projects like the system we are installing for the Sterling Municipal Light Department,” said Josh Teigiser, Director of Development & Energy Storage, Origis Energy. “Greensmith is an acknowledged leader in this field and we are pleased to partner with them on this project.”

“We are delighted to partner with Origis Energy as Massachusetts and the entire region embarks on a strategy to maximize renewable resources, integrated with our advanced energy storage technology and software,” said John G. Jung, CEO of Greensmith. “Milestone installations like the Sterling Community Solar + Energy Storage project will serve as benchmark technology for the region, and is made possible through the development knowledge and expertise of the Origis Energy team.”

Over 9,000MWh of battery energy storage could be deployed in Britain over the next five years as the sector enjoys a trend towards “explosive growth” driven largely by the country’s clean energy transition, a market analyst has said.

Lauren Cook of Solar Media’s Market Research division spoke to CEN sister publication Energy-Storage.News this week on the publication of ‘UK Battery storage: Opportunities & Market Entry Strategies for 2018-2022’, a new report.

Cook found that in just 12 months, the UK’s pipeline for new battery storage projects has grown by over 240%, with forecasted installations in 2018 set to rise more than 200% year-on-year. Opportunities are being created by a range of drivers including a national commitment to phase out coal, falling technology costs and more than 30GW of wind and solar capacity ripe for co-location with batteries.

“The market is growing and it’s changing rapidly. There’s now projects completed on the ground. Once global companies start to see it’s not just a speculative market, it will make sense for them to think about how to enter the market and what the opportunities are for them.

“They will then need to know who is active in the market, who has these opportunities and who they will have to work with to take advantage of those opportunities.”

Going beyond the deployment figures, Solar Media Market Research also looked extensively at business models, another aspect of the industry analyst Cook said is changing fast. With an emphasis on projects earning long-term revenues, it is becoming commonplace to speak of a “revenue stack” – earning multiple revenues streams for providing a range of services. However, Cook said, there is no such thing as a “typical” stack in the market today.

“I’m not sure there’s any such thing as a typical stack because there are many factors involved, but if you look at the timeline from the EFR of 2016 you had those projects were successful, those projects then went on to apply for the Capacity Market (CM), T-1 and T-4 in early 2017,” Cook said.

“Some of those were successful, some of those weren’t. We then saw the FFR auctions happening throughout 2017. Those projects also participated in those auctions, new projects also came in.