Three Ways Energy Storage Can Generate Revenue In America's ...

Energy storage is surging across America.  Total installed capacity passed 1,000 megawatt-hours (MWh) during a record-setting , and the U.S. market is forecast to nearly double by adding more than 1,000 MWh new capacity in - adding as much capacity in one year as it did in the previous four.

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However, this exponential growth has mainly been limited to vertically integrated utilities operating outside of the country’s organized power markets, which serve two-thirds of all U.S. electricity consumers. So how can energy storage plug into these markets?

In a word, revenue.

Energy storage can collect revenue in America’s organized power markets three ways: platforms, products, and pay-days.  However, different projects will tap these potential revenue streams in different ways, and investors should seek nimble developers who can navigate a complex and evolving regulatory and market landscape.

In part two of this series, we’ll explore how storage will disrupt power markets as more and more capacity comes online, but first let’s cover the three ways it can tap the U.S. organized market opportunity.

Platforms: The Best Laid Plans…

Independent system operators (ISOs) go through a planning process where they identify opportunities for new transmission to improve reliability or market efficiency. Similarly, it’s normal to think about energy storage as a reliability asset, and it can become integrated as a lower-cost, non-transmission alternative to boost reliability.

Here's an example: A relatively isolated area on the grid must plan for losing a transmission line or local generator during peak demand.  Rather than adding new transmission or local generation, building a storage project can carry a local grid through an emergency.  If the economics add up, the project will then be built, and paid on a cost-of-service basis financed through transmissions charges.

If storage in this example plays the same role as transmission for so-called “reliability transmission expansion”, it should also enjoy an analog to “economic transmission” – transmission built to move surplus energy to constrained areas to create benefits for market buyers and sellers.  But to date, only one such project exists within the U.S. independent system operators (ISOs), located near Baltimore on the PJM grid.

One reason ISOs have hesitated to fund such projects is that while “reliability” storage is tied to a definite risk of an emergency on the grid which determines how it will be used, “economic” storage requires instructions from the ISO about when to buy and sell power.  ISOs worry this could challenge their market independence since the way they dispatch storage will invariably affect prices, and could make them look like self-dealing market participants.

However, ISOs already regulate power flow over transmission lines, which certainly affects power prices. When a new transmission project is proposed to relieve congestion in an area of the grid with high demand (and thus high prices), local generators are first in line to complain about lost revenue.

What preserves ISO independence in this case is transparent cost-benefit-analysis and security constrained economic dispatch with financial transmission rights – a standard methodology for fairly moving power across transmission lines and distributing revenue from arbitraging local price differences.

If or when markets start doing more multi-period dispatch, they can dispatch storage in the same way, according the transparent optimization, and assign financial storage rights to whomever pays the costs of economic storage.

Products: Fee for Services

While ISOs are uncomfortable paying for storage services through transmission access charges that passively incorporate storage into the grid, they have been receptive to storage competing to provide fixed services like fast frequency response, capacity, or regulation that projects can compete to provide on a “technology-neutral” basis. But keep in mind these services were defined by markets before batteries and other clean technologies like renewables changed the game.

Theoretically, fitting energy storage into these technology-neutral products should be simple.  But storage resources are energy limited (they can’t just convert fuel to electricity ad infinitum), they must be charged, they take more energy to charge then they provide back, and they may be entirely driven by power electronics (no spinning inertia).

These differences mean existing market product definitions are often ill-suited to include storage, and while most incumbent participants often provide ancillary services for just a fraction of their revenues, storage projects dedicated to a single service (such as regulation) could have their entire business model upended by simple rule changes.

Storage resources also have attributes that are not always valued in markets, like how fast they can change their output, their ability to reduce air pollution, or the quick and modular pace at which they can be deployed.  These attributes provide grid benefits but need revised power market rules to be properly valued.  The standard equivalence for utilities between batteries and natural gas peakers seems to require a 1:4 power ratio, i.e. a 1 megawatt (MW)/4 MWh battery, so you might expect that product definition.

However, shoehorning batteries this way is not necessarily economically efficient – some peak needs may last longer, some may be more sporadic, and a battery’s highest value application may involve a different power ratio.

Collecting storage revenue by providing grid-need products will always be dependent on the fine print.  As a new competitive entrant to most market, storage – especially battery storage – is not always in the best position to make sure rules value them at their best.

Pay-days: Profiteer or Just an Independent Businessman?

One way for storage resources to avoid being shoehorned into the wrong glass slipper is to compete directly in energy markets.  What could be simpler than arbitrage: buy low, sell high?

Unfortunately, today’s markets just don’t provide enough revenue this way.  Consider daily wholesale electricity price differentials in two ISOs with the most market spikes, California's CAISO and Texas' ERCOT, where crudely estimated annual revenues from buying low and selling high each day (with no roundtrip losses) come out to $10-20 per kilowatt-hours(kWh) year, not quite enough to be in the money yet but close to some of the prices we see coming out of vertical utilities like NV Energy’s recent announcement to add 100 MW of battery storage.

One thing is clear:  The closer to a real-time market storage operates in, and the higher the power ratio, the more revenue is available from arbitrage.  For example, a battery storage unit with a 4:1 power ratio and 20% round-trip losses operating in the Houston load-zone real-time market could be making as much as $57/kWh-year.  This system would likely cost $300-400/kWh, making it an attractive investment, especially with high prices expected across ERCOT in coming summers.

This contrasts with other ISOs, and highlights the efficiency with which energy-only power markets can point to where investments have the most value.

Even if energy arbitrage revenues become sufficient to support storage investments, today’s markets still maintain some barriers.  Not all ISOs offer the right kind of market “participation model” to offer efficiently in the markets.  The Federal Energy Regulatory Commission’s (FERC) recent Order 841 directly addresses this, and the storage industry is eagerly awaiting new tariff structures and participation models in response.

Still, markets must contend with the fact that storage resources are energy limited, which begs the question: how should they play in markets?  Most storage today bids on an opportunity cost basis, and will buy or sell from the market based on its state of charge: If the battery is low, its bids may not be structured to buy right away in case prices go lower, and if the battery is high and could provide power, its bids might make it more likely to wait for higher prices to discharge.

Opportunity-cost based bids may efficiently dispatch batteries for maximum system benefit, but such an approach inherently accepts a battery resource’s right to withhold its capacity.  As more and more storage appears in markets as the marginal price-setting resource this may become an issue from a market-monitoring perspective.

The rapid pace of machine learning improvements mean storage bid patterns could be determined by software black-boxes that are impossible for market monitors and regulators to understand, or create strange market artifacts like stock market “flash crashes” we’ve seen with increased algorithmic participation.

One possible route to resolving these issues would be for ISOs to increase their use of probabilistic multi-period optimization in market dispatch algorithms. Then the ISO can be in charge of dispatching the battery in the most optimal way over time (hence multi-period), lowering the need for opaque and potentially problematic bid patterns.

Today’s Energy Storage Opportunity, Tomorrow’s Energy System Disruptor

Energy storage has jumped from tomorrow’s clean technology to today’s investment opportunity, but the industry’s true potential has yet to be tapped. As investors consider energy storage, they should seek nimble projects capable of navigating the complex and ever-evolving regulatory and market landscape.

And as more and more energy storage comes online, ISOs will need to evolve through new rules and market structures to accommodate the technology’s potential. In part two of this series, we’ll explore two ways energy storage will be a disruptor.

Renewable energy generation in North America continues to rise. The Energy Information Administration (EIA), part of the American federal government, projects that renewables will generate 42 gigawatts of power in , accounting for nearly a quarter of America’s electricity generation. Canada’s renewable capacity grew by 2.3 gigawatts in to a total installed capacity of 21.9 gigawatts.

Growth like that means mitigating the volatility of renewable power generation is crucial. Renewables come with peaks and valleys. Nowhere in the world is it always windy or always sunny (not even in Philadelphia). A battery energy storage system, or BESS, is one of the best ways of smoothing out that variance.

“You can’t control the sun, but you can control your batteries,” says Walter Schachtschneider, director of engineering for the solar arm of PCL’s team in Ontario.

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Schachtschneider has worked with BESS systems for decades.

“I spent 28 years working for the company. We had rooms of lead-acid batteries. Each was the size of a mini-fridge and would generate two volts,” he says. “Now the batteries are little lithium-ion cells and you can have millions of them.

“The chemistry has changed and the applications have changed too.”

These days a typical BESS installation consists of one or more containers filled with lithium-ion battery cells, plus some safety, HVAC and electrical connectivity equipment. The containers are wired together, if applicable, and connected to a broader power system. That broader system often includes renewables and commercial power users.

For example, PCL installed more than 1,500 solar modules at the largest community center in Summerside, Prince Edward Island. The solar array saves the facility more than $100,000 per year, but its generating capacity of 336 kilowatt-hours (kWh) produces more power than the building needs when the sun is shining.

That’s why the project also included a BESS. With 890 kWh of storage capacity, the BESS charges up when the sun shines in Summerside and discharges on cloudy days. It also provides backup power for the host facility connected to the grid in Summerside, which isn’t connected to a major grid and relies on diesel generation for most of its power.

A BESS and a renewable power generation project offer complementary benefits for clients. But the benefits of a BESS go beyond this. Efficient local power storage and discharge is a potent concept with powerful applications for a wide variety of businesses and utilities.

“There’s a whole compendium of uses as the world evolves and the grid gets smarter,” says Schachtschneider. “A typical BESS container installation can store 4,000 kWh, which can run hundreds of houses or a typical shopping center for hours and reduce peak generation requirements. It can also, for example, allow you to finish painting cars during a power interruption on your painting system at a car factory. There are all these valuable or critical applications.”

Many of those uses will grow more attractive and urgent as demand for electricity continues to climb. EIA forecasts project that power consumption in the U.S. will reach almost 4,096 billion kWh in and 4,125 billion kWh in . This growth is driven both by population expansion and the shift from fossil fuels to electricity for heat and transportation.

That growing demand will place greater demand on the grid. The strain of this has already been seen. In early , for instance, the Alberta Electric System Operator issued grid alerts for three consecutive days to residents in the province. In the spring, rotating brownouts hit Alberta.

California, meanwhile, has long grappled with a problem known as the “duck curve.”

“It’s basically a mismatch between peak generation and peak demand,” says Schachtschneider. “Typical peak generation is solar noon. Peak consumption is when everybody goes home and turns their stove on, when the sun is on its way down.

“There’s great opportunity in California to store surplus energy in the 10-to-2 window and inject it into the grid during peak demand, which is around 5 to 7 p.m.”

Depending on specific market regulations and client needs, BESS installations could be used to boost grid reliability, defer or avoid infrastructure expansion, boost the bottom line by selling power at times of peak demand or avoiding power purchases at that time, or reduce expenditure on power.

The money-saving angle is salient in markets like Ontario.

“The electrical system here bills based on your peak hour of electrical demand,” says Schachtschneider. “So big users might have battery systems for when they anticipate that peak hour to occur. They disconnect from the grid for that time and turn on a BESS. It can save huge money.

“It’s similar to flying home for the holidays. Airlines and airports don’t have infinite capacity. A ticket home on December 23 might cost $3,000, but three weeks before it’s $400.”

The benefits and many possible uses of BESS projects have driven demand across the country. PCL has built BESS projects from the Maritimes to Alberta for renewable energy firms, water treatment plants, community centers, and grid operators.

But peak demand for BESS probably lies somewhere in the future. And it might be here sooner than you suppose.

“The first BESS project I did was in in downtown Toronto,” says Andrew Fleetwood, chief estimator and manager of preconstruction services for PCL Solar. “It was 12 megawatt-hours.

“Now people are looking for 300, 800, 1,200 megawatt-hours in a single project. The grid operator in Ontario recently put out an RFP for six gigawatts of battery storage. Our grid is not going to be able to support our needs in 10, 20, 30 years without systems like this to push and pull power.”

Fleetwood has worked on solar projects since . In that time, he’s seen the cost to purchase and install photovoltaic panels plummet and the efficiency of the panels rise. This changing math has nudged countless solar projects from concept to reality.

He sees a similar trend right now with BESS projects.

“We might see other cell technologies beyond lithium-ion,” he says. “Battery efficiency is going to get better just like panels did. Just like electric cars did. Batteries won’t lose as much performance over time. Projects are only going to get bigger.”

Fleetwood’s colleague Andi Kasapi shares this view.

“When I started working on solar, the solar facilities would be fixed — the panels would all face in one direction,” says Kasapi, a senior project manager with PCL. “The cost for moving them east to west to follow the sun over the day was too high.

“But as the market developed and more suppliers entered it, the math changed. The extra power you get from following the sun and the lower cost of the panels made it viable. I see batteries making the same journey. More people are interested and asking. The market will get more efficient.”

Of course, tipping points are only obvious in retrospect. A BESS-curious organization today looking at the math needs a construction partner that can help them accurately assess the potential return on investment.

“Thanks to the expertise of Walter and his team, we can evaluate return on investment on a battery project at a really early phase,” says Kasapi.

Fleetwood adds that PCL’s partnerships and breadth of experience can also help clients lower costs and manage risk.

“About 80% of the cost of a BESS project is the batteries themselves,” he says. “We have relationships with the battery technology providers that can help clients keep capital expenditure down.

“And these systems are also really powerful and fast. They don’t need to turn on or warm up to discharge, which is great, but it means that when something goes wrong, it goes wrong really fast.”

PCL’s extensive experience working on critical infrastructure like hospitals and power plants can help clients identify and manage risks in using BESS.

And with demand for BESS projects rising, picking the right partner can make a huge difference to many different organizations.

“In a world of renewable energy,” says Schachtschneider, “BESS lets you control supply.”

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