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.

The California Public Utilities Commission in mid-January became the first state regulator to issue revenue stacking rules for energy storage projects, but the rules could be more of a starting point than an end point.

Revenue stacking — the layering of uses for a storage system to allow for more than one revenue stream — has become something of a Holy Grail for energy storage projects since the concept was included in a 2015 paper by the Rocky Mountain Institute. The idea is that the economics of energy storage can be optimized by using its unique characteristics to act as both load and supply, which gives it the flexibility to provide multiple uses or applications, sometimes simultaneously, and therefore layer on more than one revenue stream.

“The new rules will provide a framework for authorizing multi-use applications for energy storage projects that should guide both utilities and developers alike,” Alex Morris, vice president of policy for the California Energy Storage Alliance, told Utility Dive.

In addition to drawing up a set of 11 rules on revenue stacking, the underlying order also establishes a working group to develop “clear, actionable recommendations” on issues such as compensation for PUC jurisdictional services, the appropriate metering and measurement of Multi-Use Applications, and PUC enforcement of Multi-Use Application rules. It also includes recommendations on enabling uses for community storage projects and the implementation of AB 2868 — a 2016 law that calls for the “acceleration” of 500 MW of distribution-connected energy storage facilities, such as behind-the-meter and community energy storage installations.

California Public Utilities Commissioner Carla Peterman raised the possibility of opening another proceeding on energy storage, if need be. The CPUC is also exploring the idea of instituting an expedited process for approval of energy storage projects, Morris said.

Stem, Inc., an energy storage optimization company, was chosen by Kilroy Realty Corporation (KRC) to deploy over 7.5 MWh of artificial intelligence (AI)-driven energy storage at eight commercial buildings in KRC’s California portfolio. The selection was facilitated by Black Bear Energy Inc., who acted as the owner’s representative for Kilroy Realty.

Stem will install its Athena^TM-powered storage in 2018 at four KRC office buildings in San Francisco and another four in Los Angeles, representing approximately 20% of KRC’s stabilized office portfolio. The KRC systems, which utilize a uniquely-tailored financial structure for real estate firms, will join the world’s largest digitally-connected storage network. This network uses the systems when idle to support strained local grids and enable higher penetrations of clean power in the community.

“Intelligent energy storage helps reduce the environmental footprint of our building operations,” said Sara Neff, senior vice president of sustainability at KRC. “Black Bear’s expertise with clean energy and Stem’s AI-powered solution will help us achieve our environmental goals while helping to modernize the grid, which is a natural alignment with our business vision.”

“When it comes to real estate and energy storage for commercial buildings, it’s the brains behind the batteries that differentiate solutions,” said John Carrington, CEO of Stem.

Click Here to Read Full Article