Energy storage market growing rapidly but big hurdles remain in Alberta

Author: Mark Lowey


Publish Date: Wednesday, February 22, 2017

Large photo is of a 2.5-megawatt Highview Power Storage liquid air energy storage pilot plant at the University of Birmingham in the U.K.

The global market for energy storage is expected to increase dramatically within a decade but such technologies face several hurdles in Alberta, speakers told a symposium in Calgary.

Challenges range from reducing the cost of the technologies and proving they work, to a provincial electricity system and policies that discourage energy storage, the Alberta Energy Storage 101 symposium, held in late January, was told.

“If we want to move more toward renewable energy, renewables without having energy storage has no meaning,” said Kourosh Khaje, founder and president of EnSciTech, which organized the event. Because renewable energy sources such as solar and wind power are intermittent, “we need a way we can save all the energy during the daytime or nighttime, and then [feed] it back to the grid,” he said.

Khaje said he wanted to bring together industry, government, technology developers and the research community to share their knowledge, identify gaps in being able to deploy energy storage, and find ways to close those gaps. The symposium, sponsored by Alberta Innovates, attracted more than 80 people.

Alex Eller, energy storage research analyst for Navigant Research, told participants that energy storage is playing a growing role in energy systems, as the cost of storage technologies continues to decrease. The cost of battery energy storage systems fell by about 23 per cent between 2014 and 2016, he said. By 2025, average or “end-install” costs are expected to drop by another 35 per cent.

According to Navigant Research, there were 362.8 megawatts of energy storage projects announced worldwide in 2013-2014, an almost equal distribution between North America, Asia Pacific, and Western Europe. Navigant Research expects global installed energy storage for the grid and ancillary services power capacity to grow from 538 megawatts in 2014 to 21 gigawatts in 2024. It predicts that worldwide revenue from energy storage will increase from $675 million in 2014 to $15.6 billion in 2024.

Energy storage will grow much faster than wind and solar power, with lithium batteries dominating the market, Eller said.

He described current energy storage market segments as being “utility-scale” (the largest systems), “behind-the-meter” (distributed systems) for residential and commercial/industrial buildings, and remote community power systems that reduce consumption of diesel fuel and other greenhouse gas-intensive fuels. Bulk storage and ancillary power services are the two major applications in the market.

Three major components of the market segments are storage technologies, thermal management systems, and power conversion and system software and controls. Significant advances have been achieved in software and controls, particularly for system day-to-day operations and system optimization, Eller noted. “Software really provides the brains of the energy storage system.”

The behind-the-meter market segment is in a very early stage, and the major driver in coming decades will be evolving utility rate structures and regulations, he said. Lithium-ion battery technology is capturing increased market share, with more vendors offering integrated solutions including centralized command and control of distributed energy systems.

Utilities are becoming more involved in the residential energy storage market, especially where customers or third parties provide electricity generated by rooftop solar systems, Eller said. Distributed solar photovoltaic technology has seen significant growth, with a new model being the sharing of costs and control of the system between utilities and customers.

Utility-scale energy storage is the most established of the market segments, with lithium-ion batteries being one of the most popular technologies.

In Canada, energy storage for remote community power systems is expected to increase, especially wherever there’s strong government support as there is in Ontario, Eller said.

Navigant Research’s forecast for energy storage in Canada from 2015-2025, published in late 2015, was “very positive at the time,” particularly for Ontario, he said. Since that forecast, the growth in the market has been slower than expected, especially in distributed systems, but significant growth is still expected in Canada. Some 400 MW of energy storage projects are either under construction or in the planning stage in the country, mostly in Ontario.

Barriers to deploying energy storage in Canada include an existing large amount of hydroelectric capacity, which reduces the need for energy storage in many jurisdictions, along with high upfront costs of energy storage technologies, Eller said.

He suggested several ways to accelerate the market in Canada, including: reforming energy market rules as well as regulations for utilities to allow distributed systems for customers and the procurement of third-party systems from providers. Utilities should look to energy storage to defer new investment in electrical transmission and distribution infrastructure, Eller said.


Alberta faces multiple and unique challenges

In Alberta, energy storage deployment faces multiple and unique challenges that make it not cost-competitive at this time, Maureen Kolla, manager of renewable energy for Alberta Innovates, told the symposium. Those challenges include:



  • a province-wide electrical grid with infrastructure and supporting services set up for centralized coal-fired power production rather than distributed systems with energy storage;

  • technical and operating requirements needed to connect distributed systems and energy storage to the grid;

  • an abundance of renewable energy resources, especially wind, concentrated in southern Alberta but with a large demand for power located in northern Alberta;

  • electricity demand dominated by industry (70 to 80 per cent of provincial demand) that requires a 24/7 supply;

  • energy storage technologies that are still emerging and costly, and have yet to be demonstrated commercially;

  • lack of certainty in Alberta’s deregulated electricity market when it comes to tariff rates, especially in an energy-only market where generators get paid only for the electricity they actually put on the grid.

Kolla said to advance energy storage, the focus should be on doing a grid-scale demonstration project, closing the knowledge gaps, informing policy and developing regulations, and development to prove out the technologies and bring down the price point. The National Research Council is working on an energy storage ‘roadmap’ for Alberta, she said.

Alberta Innovates in 2014 issued a call-for-proposals on energy storage and announced a total of $1.5 million in funding for six projects, three of which are still active, she said. They are:

  • a project, led by Ted Roberts, professor of chemical and petroleum engineering and associate head (research) at the University of Calgary, to develop a low-cost, redox flow battery technology for large-scale electrical energy storage;

  • a project, led by Vancouver-based ZincNyx Energy Solutions Inc., to develop a zinc-air fuel cell for renewable energy storage, and prioritize the development of larger systems for deployment in Alberta’s micro generation systems.

  • a project, led by Equana Technologies in Calgary, to develop distributed lithium-ion battery and power conversion technology designed to help smooth the renewable power output to the electrical system and to shave peak load, potentially reducing strain on the electrical system and demand charges on the building’s utility bills. The technology is to be installed and demonstrated at a commercial building in Alberta.

Kolla said the potential applications for energy storage in Alberta include: time-shifting/arbitrage (storing energy generated during periods of low demand and delivering it during periods of high demand); variable generation; curtailment; ancillary services (support services, such as spinning reserve and load following, used to keep the regional grid operating); and optimizing transmission and distribution n. She noted that a report by Alberta Innovates and Solas Energy Consulting is expected soon that will look at when energy storage helps reduce greenhouse gas emissions and the barriers to implementing energy storage.

David Layzell, professor and director of the Canadian Energy Systems Analysis (CESAR) initiative at the University of Calgary, said in his presentation that the challenge to reduce greenhouse gas (GHG) emissions is driving the interest in energy storage. Eighty-one per cent of Canada’s GHG emissions are associated with energy systems, he said.

However, from a GHG perspective, energy is not the problem – carbon is, Layzell said. The focus in Alberta should be on examining the energy and carbon flows used within the province, rather than on export products (such as oil and natural gas) because the carbon is also exported, he said. When it comes to carbon flows, Alberta is second in the country to Saskatchewan on a per-capita basis, he noted.

About 50 per cent of natural gas in Alberta is used by the energy industry, while there are also large energy conversion losses in the province, Layzell said. He suggested several ways to reduce GHG emissions in the province, including:


  • improve energy efficiency and conservation, including behaviour change;

  • deploy biofuels targeted at commercial freight transportation;

  • electrify the energy systems, including the personal transportation sector and space heating in residential and commercial buildings;

  • encourage low- to zero-carbon power generation;

  • develop an East-West electrical grid to import large-reservoir hydro power from British Columbia and Manitoba, while developing Alberta’s untapped hydro; and

  • deploy geological and biological technologies for carbon dioxide removal and storage.

Layzell noted that CESAR’s energy systems analysis and other research show that in recent years, there has been a decoupling of energy use from Gross Domestic Product. “I think we can grow our GDP and reduce our emissions,” we just need to do it more efficiently, he said.


Advancing energy storage in Alberta

Binnu Jeyakumar, energy analyst at the Pembina Institute, told the symposium that as Alberta phases out coal-fired power, “There is a risk of (natural) gas being overdeveloped and taking away the opportunities for renewables and energy storage to participate in our electricity system.”

She suggested some guiding principles to help ensure a flexible and diverse electrical grid in Alberta. They include:



  • prevent overbuild of “default” natural gas-fired generation;

  • offer incentives for utilities and technology providers to innovate and compete;

  • provide incentives for distributed generation, which fits well with energy storage;

  • allow energy efficiency, demand response, energy storage and renewables all to compete by defining different capacity contracts for each;

  • allow for different types of capacity (e.g. less flexible, fast ramping, etc.);

  • provide short-term capacity contracts (e.g. one to three years); and

  • develop technology-neutral mechanism for monetizing grid services.

Alberta’s Renewable Electricity Program, administered by the Alberta Electric System Operator, will encourage, through a competitive bidding process, the development of 5,000 megawatts of renewable electricity generation capacity by 2030. The provincial government is looking for projects that can be commissioned immediately, including about 400 MW in the program’s first round of competition.

Jeyakumar said there is an opportunity within this program for energy storage technologies to compete in the medium term, with changes that allow for capturing additional value. She suggested several ways for Alberta to monetize flexibility in its electricity market, including:

  • pay for attributes such as availability of electricity at times of power scarcity;

  • set a target for energy storage procurement (California’s target, for example is 1.3 gigawatts);

  • offer incentives to attract technology providers;

  • encourage transmission providers to consider non-transmission alternatives (such as energy storage);

  • institute sub-hourly dispatching of power, rather than only the current hourly market which serves large, incumbent power generators;

  • provide distributed system market incentives and mandates for utilities, including programs for behind-the-meter storage that enable peak shaving to reduce electrical power consumption during periods of maximum demand (as New York City did);

  • enable distributors to own and operate energy storage and pass on net costs to their rate base;

  • allow distributed energy resource aggregators to participate in the wholesale electricity market; and

  • encourage electric vehicle deployment and other forms of electrification in the energy system.


The drive for better batteries

In a presentation on energy storage technologies, Ted Roberts, professor of chemical and petroleum engineering at the University of Calgary, said pumped-storage hydroelectricity currently represents more than 96 per cent of global grid energy storage. It involves pumping water from a lower-elevation reservoir to a higher elevation. Low-cost, surplus, off-peak power is typically used to run the pumps. During periods of high electrical demand, the stored water is released through turbines to produce power. Pumped hydro provides an average of six hours of storage at relatively low cost and lasts many decades, Roberts said.

Other mechanical energy storage technologies include compressed air and flywheels; chemical technologies, such as electrolysis to make hydrogen and carbon dioxide reduction to convert CO2 into fuels for fuel cells; electrical technologies such as capacitors and superconducting magnetic coils; and thermal or heat storage.

Pumped hydro and compressed air energy storage make the most sense right now, in terms of cost and technological readiness, Roberts said.

The Calgary Advanced Energy Storage & Research Technologies (CAESR-Tech) at the University of Calgary is doing research on several of these technologies, said fuel cells researcher Viola Birss, professor of chemistry and CAESR-Tech’s scientific director. For example, Venkataraman Thangadurai, professor of chemistry and associate director of CAESR-Tech, in a project with colleagues at the University of Maryland, have developed a next-generation, all solid-state lithium battery that is chemically stable, non-flammable and can operate safely at a higher voltage than existing batteries.

Roberts said the energy storage market needs batteries that can last many hours, run for a long time and don’t cost very much. Current battery technologies are based on lithium or lead acid or nickel cadmium or sodium sulphur. The life cycle of these batteries are dependent on the materials used and the chemistry involved, and their capacity or power is dependent on design.

The rechargeable “redox flow battery” is another approach that stores chemical energy in solution in large tanks outside the battery. The capacity of these batteries depends on the tank size and their power depends on the electrode area and materials used. However, the technology’s cost and availability are still big challenges.

 A redox flow battery using the elemental metal vanadium is the most developed, although the cost of the vanadium needs to be reduced, Roberts said.

Roberts said the project he’s heading that is funded by Alberta Innovates is investigating new redox chemistry (using aqueous metal organic complexes), improved electrode materials and better cell design.

Khaje’s EnSciTech firm has partnered with Vancouver-based mining company VanadiumCorp., which has projects in Quebec, to develop technology for extracting vanadium from oilsands/heavy oil waste fly ash and coal fly ash. The vanadium would be used to produce  electrolyte for use in a vanadium redox flow battery. Instead of the waste ash being landfilled, the material can be used for energy storage, Khaje said.


Using energy storage to accelerate decarbonization

The Calgary symposium concluded with an expert panel, moderated by Carol-Ann Brown, a director at the Delphi Group, tackling the question: “How can Alberta use energy storage to accelerate decarbonization?”

Paula McGarrigle, co-founder and managing director at Solas Energy Consulting, said energy storage can encompass power generation, transmission and distribution, as well as in customer or behind-the-meter applications.

In Alberta, curtailment/mitigation in which the electrical system is ramped up or down is a key consideration for the Alberta Electric System Operator, she said. This can involve physical curtailment where the grid cannot take the energy right now for various reasons, or a supply surplus where there’s too much power available on the grid.

Energy storage would enable renewable energy to be stored so it’s not lost during times of curtailment, with a resulting carbon penalty on the lost ‘green’ energy. For example, there is no way to shut off rooftop solar PV, so wind-generated energy is sometimes curtailed.  The energy storage opportunity in Alberta lies in having a more flexible grid “so you’re not spilling” wind and solar power, McGarrigle said, noting that curtailment is likely to increase as more renewables are brought onto the grid.

Panelist Barend Dronkers, an advisor at the Pembina Institute, said the more power that can be produced at the point it is consumed makes the most sense in terms of energy efficiency and reducing greenhouse gas emissions. Behind-the-meter applications, involving non-traditional players, is where innovation can happen given that the grid level is very regulated, he said.

Dronkers noted that seven remote communities in Alberta are completely reliant on diesel fueled-power. Energy storage, coupled with increased renewables, can help reduce diesel fuel costs in these communities, he said.

Trevor Wills, director of growth and acquisitions at ATCO Power Canada Ltd., agreed that behind-the-meter opportunities are happening in Germany and Spain and in remote communities in Alaska. However, Alberta’s hourly-based power pricing system and centralized grid structure don’t currently support such applications, while diesel fuel is cheap here, he said.

There are more opportunities for energy storage in other jurisdictions simply because they have bigger problems in their energy systems than Alberta has, Wills said. High power costs in Japan, for example, compelled that country’s move into solar power and solid oxide fuel cells. Alberta should learn what other jurisdictions are doing, take the best of everything and implement it here, Wills said.


  • Its to bad I missed this 1 as we could have done a demonstration of our hybrid production storage device we have been using for a little over 3yrs but is in 132 homes & 34 farms across Canada with over half in Alberta We will be testing our 1st microfusion system in a few weeks which we are excited about

    Terry Kashuba - 2017-03-06T10:22:05

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