Navigant Research Blog

With New Plant, Alevo Claims Major Battery Advances

— November 10, 2014

Swiss manufacturer Alevo has launched a new battery and grid storage division in North Carolina that it promises will lead to hundreds of megawatts worth of battery-based grid storage projects.  The U.S. subsidiary hopes to manufacture its formulation of lithium iron phosphate (known in the industry as LFP) batteries in the 3.5-million-square-foot Concord, North Carolina factory.

Alevo’s battery chemistry is not new – there are dozens of LFP manufacturers (most based in China) cranking out hundreds of megawatts of batteries for portable power and grid storage applications.  However, Alevo claims that its formulation of the chemistry (primarily its secret electrolyte additives) will enable its LFP batteries to last as long as 43,000 cycles of full discharge.  If such a cycle life is proven in the field, this chemistry will represent the most durable lithium ion (Li-ion) battery available today.

An Impressive Debut

Alevo also claims that it uses a non-flammable electrolyte, which makes its battery less prone to catching fire than most grid storage batteries.  Although the company won’t discuss manufacturing costs, LFP batteries have relatively cheap material inputs, opening up a potential path toward low-cost cells.

During the unveiling ceremony at the Concord plant (complete with a drawing back of the curtains on stage, swirling searchlights, and wolf whistles from the employees that packed the audience – all for a 20-foot shipping container), the air-cooled battery bank was displayed, along with its Parker Hannifin inverter and fire detection and suppression equipment.  Alevo also highlighted its big data and analytics capabilities, which it says are needed to help deploy and optimize the energy storage system.

While Alevo seems to have plenty of capital behind it (Reuters reported that Swiss investors have put up more than $1 billion), as well as several global partnerships, it has significant challenges ahead.  The most important of these focus on the battery cells themselves: real-life durability and manufacturing cost.

Two Challenges

On the durability front, Alevo’s internal accelerated testing of 43,000 deep discharge cycles is indeed impressive.  But accelerated testing is an imperfect science.  Batteries tend to perform very differently in the real world over the course of decades, as opposed to laboratory benchmark tests that model expected long-term battery durability.

As for manufacturing costs, Alevo has a hard mountain to climb to learn how to become a battery manufacturer, especially with the challenges that LFP technology brings to the factory.  Unlike other Li-ion chemistries, LFP requires very finicky vacuum technologies that make large-scale manufacturing hard to do efficiently.  Many other LFP manufacturers have assumed cheap manufacturing costs only to find that the chemistry left them with much higher costs, lower yields, and more failures than expected.  While other cobalt-based Li-ion chemistries have higher costs for material inputs, the manufacturing processes are much simpler and easier to scale.  Alevo’s claims are impressive; proving them will be another matter.

 

Energy Storage Enjoys a Breakthrough Day

— November 5, 2014

While most Americans were paying attention to election results, news emerged out of California that truly heralds a new era for the energy storage industry.  Southern California Edison (SCE) announced that it will acquire 2,221 MW of new generation assets, of which 250 MW will be energy storage systems.  This is the end result of the lowest-cost resource request for proposal (RFP) that is designed to eventually replace the generation provided by the shuttered San Onofre nuclear power plant.

While the sheer scale of the announcement is staggering (no utility has ever purchased 250 MW of non-pumped hydro energy storage before), the details of the announcement are even more impactful.  SCE was expected to use some of this bid for energy storage (it listed energy storage as a preferred resource on the RFP), and Navigant Research assumed the energy storage part of the purchase would be about 50 MW.  By ordering 5 times that amount of energy storage, SCE is making a very loud statement about how highly it values energy storage as a grid management tool.

The Land Rush Begins

Another important aspect of this move is that it was done on a completely level playing field.  SCE decided to purchase 250 MW of energy storage because it felt it had a higher value than any other generation asset (including natural gas, wind and solar).  That in itself is an extremely important positive note for the energy storage industry.

Even more important for the industry is that SCE’s big vote of confidence for energy storage happened just before the launch of three big RFPs that were designed as part of the energy storage mandate that California is forcing on the big utilities.  By December 1, 2014, all three of the large investor-owned utilities in the state will introduce a total of more than 200 MW of energy storage purchases.  It’s the energy storage industry’s equivalent of the Oklahoma land rush.

Other Big Deals

A couple of other important nuggets regarding the SCE announcement:

  • AES Energy Storage will be building a 100 MW battery plant that will dwarf all existing battery power plants.  Over the last few years, AES Energy Storage has discussed how such a plant might work, but now it will have a chance to actually implement a battery peaking plant.  If this project is successful, it will open up a completely new business model for the energy storage industry that could, in the long run, be the largest segment of the stationary storage market.
  • San Francisco-based startup STEM won an 84 MW contract that will make up hundreds (if not thousands) of distributed battery packs working on the customer side of the meter.  Like many other behind-the-meter energy storage system integrators, STEM has preached the concept of distributed battery packs that, in aggregation, work like a virtual power plant (see Navigant Research’s report, Virtual Power Plants).  STEM will be the first company to implement such an idea at scale in the real world.  If it succeeds, then other players like Coda Energy and GreenCharge Networks will also benefit.

Whatever your politics, for the energy storage industry it is morning in America.

 

A Better Way to Extract Shale Oil

— November 5, 2014

Last month the Colorado Fuel Cell Center (CFCC) at Colorado School of Mines hosted the first public demonstration of IEP Technology’s Geothermic Fuel Cell (GFC).  This innovative technology uses the waste heat produced by fuel cells to convert the kerogen in oil shale into unconventional hydrocarbons onsite.

Using standard fuel cell technology, the GFC flips the application on its head by taking a heat-first, power-second approach.  The system uses solid-oxide fuel cells, manufactured by Delphi Automotive, in tubular modules that can be linked end-to-end to create a long string of fuel cells encased in a steel cylinder.  The long term plan is to insert vertical stacks that are up to 1000 feet long into oil shale formations, spaced 10 to 15 feet apart in a grid pattern.  In this configuration, the fuel cells can generate temperatures of up to 1200 degrees Fahrenheit, which will be used to heat the formation and drive pyrolysis (thermal decomposition of the oil shale).

Giving Shale Oil a Better Name

Currently, shale oil is most commonly extracted ex situ, or offsite.  The oil shale is mined and taken to an above-ground processing facility where it is crushed, heated to temperatures suitable for pyrolysis (500-1,100 °F), and the unconventional hydrocarbons (shale oil and natural gas) are collected, cooled, and refined.  This process is expensive, inefficient, and extremely damaging to the environment, and it has earned shale oil extraction a bad name.

IEP’s technology, on the other hand, performs the processing in situ, or onsite, by applying heat underground and extracting the shale oil and natural gas via wells that sit among the boreholes, leaving the formation intact.  The only byproducts are electricity that can be sold back to the grid, small amounts of clean water, and CO2.  It may seem odd to think of the electricity as a byproduct, but that’s the beauty of IEP’s approach.  If a single 1000 foot stack contains 100 to 300 of Delphi’s 1.5 kW fuel cells, you’re talking 150 kW to 450 kW of baseload power per stack over a projected 5-year lifespan, which is no small thing when you consider the potential revenue.

IEP estimates that the gross capital and operating costs of a GFC installation will be less than $30 per barrel of shale oil when the revenue from the sale of electricity and surplus gases are taken into consideration.  This would give GFCs a significant cost advantage over the competition.  More significantly, IEP’s technology allegedly has an energy return on energy invested (EROEI) of 22:1, which would be a monumental improvement on the current best-in-class EROEI for oil shale, which is closer to 5:1.  The technology seems easy enough to replicate, but IEP has patented their idea, which should give them some protection from competitors.

The Real Cost

However, a couple of questions come to mind.  First, what will the actual installed cost of the systems be?  It could take thousands of fuel cells to develop a single formation.

Second, you have to run a fuel source out to the site, which is probably fairly remote, in order to run the GFC.  You also have to run transmission lines out to the site and build a substation in order to sell power back to the grid, and the fuel cells will only be running at that site for 5 years, so it’s a temporary installation.  How many utilities would be interested in doing that?  These questions must be addressed, and we won’t know how the economics and EROEI shake out until mid-2015, when the GFC is expected to be field-tested.  But this appears to be a very promising technology.

 

Severe Drought Hastens Hydropower’s Slow Decline

— November 4, 2014

Coal retirements, the shale gas bonanza, post-Fukushima nuclear curtailments, the rising adoption of distributed generation, and emerging price parity for solar PV and wind – the dynamic changes impacting electricity grids worldwide are many.  Now, with prolonged droughts affecting leading global economies, like Brazil and California (the world’s seventh and eighth largest economies by gross domestic product [GDP], respectively), a slow decline in the prominence of hydropower is in the mix.

Historically, hydropower has been the primary source of clean and renewable energy in both economies.  Its decline has had a more severe impact on Brazil’s grid, but in both places, this development is expected to continue to coincide with a further rise in gas-fired generation and renewables.  Due to the current cost of renewables, the consequences of this shift may be a rise in greenhouse gas emissions in each country’s electric power sector.

California Copes

With a fleet of 300 dams, California is among the nation’s leaders in hydropower generation.  However, hydro in the state has declined from peaks in the 1950s, when it was responsible for more than half of the state’s generation mix, to just 9% in 2013.  Having prepared for hydro’s decline by broadening its generation mix over the last several decades, the California grid remains mostly insulated from the worst effects of nearly a half decade of severe drought.

California generates around 55% to 60% of its power from natural gas and has seen a 30% increase in gas-fired generation since 2002.  Meanwhile, California’s leading investor-owned utilities across the state – Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) – are on track to meet or exceed their 33% renewable procurement obligations by 2020 under the state’s Renewable Portfolio Standard (RPS) policy.

Brazil Gasps

Facing its worst drought in 40 years, meanwhile, Brazil has been more severely affected by reduced hydropower generation than California.  Currently, the second leading producer of hydroelectric power in the world, trailing only China, Brazil relies on hydro for more than three-fourths of its generation.  According to data published by BP earlier this year, hydropower consumption fell 7% in 2013.

This rapid decline has prompted severe rationing in 19 cities, undermined hydropower generation, and resulted in blackouts across the country.  In the run up to the 2014 World Cup, the Brazilian government provided more than $5 billion to subsidize electric utilities, replacing lost hydroelectric generation with fossil fuel-fired generation, including large amounts of liquefied natural gas.  While this helped stabilize the grid during the event, it has nearly doubled greenhouse gas emissions from the power sector.

Brazil’s experience provides a harsh lesson for drought-stricken areas with a high dependence on hydropower.  While natural gas is a low-carbon alternative relative to coal-based generation, it may stall or reverse carbon mitigation efforts when used in place of hydropower.  Renewables can help make up the difference, but even with sharp declines in the price of solar PV and wind, they remain far more expensive than hydropower or natural gas.  While both California and Brazil are in a hole with respect to water supply and hydroelectric generation, persistent drought is unlikely to result in a significant increase in new renewables spending without the introduction of new subsidies.

 

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