CAES - Lies and Damned Lies

With apologies to Mark Twain, I keep thinking of his categorization of whoppers when I hear the misleading, if not willfully false, claims made for Compressed Air Energy Storage - CAES.

The Wall Street Journal has a story on the DOE grants for CAES, due to be announced soon. $60 million is planned to "promote a patented technology that stores energy until it is needed".

First, referring to CAES as "energy storage", is a stretch, if not downright misleading. The WSJ doesn't mention that the compressed air is "stored" for the purpose of firing a natural gas generator! Yes, that's true - a natural gas, greenhouse gas emitting, fossil fueled generator.

Advocates of CAES are quick to point out that using compressed air increases the efficiency of natural gas generators, from about 33% to as much as 88%, so less GHG is emitted. That's great for fossil fueled generation, but don't call it energy storage. However, as discussed in an earlier blog, on an energy in - energy out basis, counting the energy used to compress the air, actual energy efficiency is about 54% or less. But I digress...

Second, how can anyone compare CAES to advanced batteries - like the VRB-ESS - and conclude that it's, "much cheaper than battery storage and far more durable"? The article quotes Robert Schainker of EPRI advising that batteries are too expensive. Elsewhere he is quoted as saying CAES costs about $700 per kWhr. If the PG&E project stays on budget - how likely is that? - then PG&E will get 10 hours at 300 MW, or 3,000 MWHrs for under $400 million, about $133 per kWhr? Wow, what a deal - if it happens. However, what about the cost of the natural gas? No information has been provided yet, but 8 million MMBtu per year seems in the ballpark. At $7 MMbtu, that's at least $560 million over 10 years. Twice that over 20 years. And what are the O&M costs? The generators are typically completely overhauled every 10,000 hours. We need more information...

By contrast, Prudent Energy is expecting the VRB-ESS to run about $500 per kWhr for 6 hours of storage within 2 years, and much cheaper for a 10 hour system. Refurbishment at 10 years, for about $60 kWhr for a 10 hour system, will allow the ESS to run another 10 years. And, wind power can be stored and delivered as needed, without emissions, with about 75% efficiency.

One final digression - if renewable energy, subsidized by taxpayers, is used to enhance a natural gas generator, is it still "renewable". Renewable wind power is consumed to run the air compressors. The compressed air is then released to enhance natural gas generation, turning "clean" energy into "dirty" energy. What does this do to the Renewable Portfolio Standards? Does wind energy, that is not delivered to consumers, but instead is consumed to produce natural gas fired electricity, count toward the 20% - 33% RPS?

There's no guarantee a 300 MW CAES will or can get built as expected, or that it will ultimately cost under $400 million. However, VRB systems can begin to be installed at wind farms and end-users now. It's more likely that 300 MW of VRB batteries can get installed in 5 years than CAES, and we won't have to substitute wind power for natural gas.

How Do You Value Grid Connected Energy Storage?

This is almost a part II to my earlier post, but I was reminded again of the problems we face when it comes to defining, and then valuing, Grid Connected Energy Storage (GCES).

The recent New York Times article, "Companies Race to Develop Utility-Scale Power Storage" pointed up the problems and potential for confusion. "Power storage" technologies listed included the Beacon flywheel, the NGK molton sodium-sulfur battery, the A123 lithim ion battery, and compressed air (again!). Quoting a report by GTM Research, this article made a very insightful distinction between "power oriented" technologies, used mainly to regulate short-term changes to grid frequency, and "energy oriented" storage -- in which energy use is shifted to other times of the day. However, the author could have done a better job applying this distinction and pointing out the difference in cost.

For example, the article discussed the $69 million Beacon project in New York, where they will install, "...hundreds of "flywheels" to store 20 megawatts of electricity, enough to power 200 homes for a day." In reality, the flywheel is designed to store only 15 minutes of power and falls into the "power oriented" category above. Its total energy storage will only be 5 MW hrs, about enough to power 40 homes for a day, although it will never be used for that purpose.

Also, the article reported on the $25 million requested by Southern California Edison for an A123 "32-megawatt-hour battery" - but is it really 32 MW hrs? I pose the question because the system will be designed as an 8 MW battery with 4 hours of storage (32 MW hr), but the application is at a wind farm, where multiple cycling is needed to firm wind - a "power oriented" application. Lithium ion batteries are good for about 500 - 600 complete charge and discharge cycles. If it is used in an "energy oriented" application, shifting wind power at night to the day, then it will only last about 2 years. However, in a "power" application, where the battery is barely discharged, it will last for many thousands of cycles. In fact, this is how it is currently applied. In this case it would be operated like an 8 MW flywheel, with usable energy storage of only about 2 MW hrs.

So how do you value these installations? If we value the flywheel and the li-ion systems by the MW hr, then their cost is $13.8 million and $12.5 million respectively. However, if all we care about is their power capacity, then the cost is $3.45 million and $3.125 per MW. (The NGK battery is the only energy oriented technology mentioned in the article, but no cost information was provided.)

By contrast, a VRB-ESS (vanadium redox flow battery - energy storage system) will provide both energy and power, with nearly unlimited cycles, full or partial, for about the same cost per MW of the flywheel or li-ion battery. However, the VRB-ESS will also include 4 - 8 hours of storage, dropping the cost per MW hr to a fraction of the cost for a "power oriented" system.

For example, a 5 MW system with 6 hours of storage would cost about $18 million, with all costs included - a complete turn-key system. That would provide 30 MW hrs of energy at a cost of about $600 thousand per MW hr. The cost of power is only $3.6 million per MW.

Although not directly relevant to the discussion, it's good to know that the VRB-ESS will last 10 years before needing refurbishment. This consists of replacing the PEM (proton exchange membrane) at a cost of about $3 million. The system is then good for another 10 years!

Bottom-line? - It's important to understand the application, whether energy, power or both, and then determine the cost per energy (MW) and/or the cost for power (MW hr), when evaluating the technology.

What is Grid Connected Energy Storage?

The California Energy Commission recently requested input on what the definition should be for "utility connected energy storage". Here are some of my thoughts:

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1. How do you define utility scale energy storage?

I would suggest looking at several common sense issues to get a handle on what is utility scale or grid connected energy storage (GCES).

First, we should define energy storage as "electrical" energy storage. That means electrical energy storage in and electrical storage out. For utility or grid applications, we need to store electrical energy for use when needed; meaning excess electrical energy is shifted to a time when electric energy is scarce. This excludes some types of valuable energy storage, like thermal energy storage, but it clarifies what we are doing.

Thermal storage is a good thing and useful, but it cannot be used to produce electrical power for the grid, so it should be excluded from our consideration. This is not to single out thermal energy, but to illustrate the need to focus on electric energy storage. The distinctive of utility or grid energy storage should be the storage of electricity. Storing electricity energy for use as some other type of useful energy does not provide the grid with the electric energy when needed. It is load only. Electric energy storage should be a two way street, not a one way street.

Logically, this also excludes electric energy generators. Again, this is an example of taking a different type of energy and converting it to electricity. Unless we define GCES as electricity in and electricity out, then a coal plant could be considered as GCES since it stores energy in the form of coal and provides energy as needed. If we do not specify electric in - electric out, then our discussion will be so broad as to be meaningless.

And, if we are careful to define GCES as electric in - electric out, then this will also exclude fuel driven compressed air energy storage systems. Such CAES systems are more clearly understood as highly efficient natural gas generators. Electric energy is used to run compressors. The compressed air is used to run natural gas generators more efficiently. Burning natural gas to produce electricity is not electric energy storage. It may be very desirable in some ways, but it should not be in the same box as other technologies that store electricity. If we include fuel driven technologies, then, again, our discussion becomes meaningless.

The second concept to address is the "storage" issue. The common sense expectation is that we are focused on storing and delivering useful amounts of electrical energy.

For example, there is a difference between delivering energy and providing power quality services. Various devices and technologies can store and deliver short bursts or pulses of power to balance short term variations in power quality. Utilities and energy users install various devices for this purpose. But their use is for power quality, not energy.

Similarly, the CAISO operates a market for frequency regulation that is considered a "capacity" market, as distinguished from their "energy" markets. Some ISO's are developing opportunities for Limited Energy Storage Resources (LESRs) to provide capacity - not energy - services, because they recognize the benefit from the quick response of such technologies. However, these systems are, by definition, limited in their energy and are not valued for their volume but for their capacity. Although valuable, they are not useful for energy delivery. At a minimum, a GCES facility should be able to store and deliver electric energy in hours, not minutes. We refer to the technical parameters used by the California Public Utilities Commission in their definition of advanced energy storage for the Self Generation Incentive Program. (Decision 08-11-044 November 21, 2008, page 12, “Ability to be discharged for at least four hours of its rated capacity to fully capture peak load reductions in most utility service territories (required AES duration of discharge will depend on each customer’s specific load shape, and the duration of its peak demand during peak utility periods).”)

LESRs should be in their own separate category for the valuable power quality benefits they provide to the grid, but they should be excluded from the GCES discussion because they cannot deliver energy in useful quantity.

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Any comments?

PG&E Compressed Air Project - Quick Thoughts

Now that the deadline has passed to file for grid storage projects under the ARRA , we're beginning to see some of the concepts and projects that have applied for funds - see post below - including the 300 MW compressed air project by PG&E I believe PG&E will have to deal with some of the following issues on this project.

• First, the $25 million requested is only for "initial analysis and design". The anticipated cost for the project will be $368 million. And that's before we see the cost over runs, delays and unexpected problems a huge project like this will invariably incur.
  
• Then the utility will have to explain why they want to take "clean" wind energy and make it "dirty". Because, you see, the compressed air will be used for natural gas turbines! The argument is that the compressed air will make the natural gas turbines run more efficiently, requiring less natural gas - which is great if you're trying to make your natural gas turbines more efficient. But we thought the point of wind energy was to produce clean and renewable power - not more fossil fueled power.
• And how much energy will we lose in this process? We create a certain amount of energy with wind and then burn it away by compressing it and burning natural gas. What is the net delivered energy when all of this is finished? I've seen reports of as little as 54%. So we take wind energy, throw away 40% or more, increase the price volatility through the natural gas market, and add emissions and GHGs. Why is this a good idea?

Utilities like CAES because it increases their power as a utility. They get to spend a bunch of ratepayer money on a huge central power plant which they control. This is why they have problems with distributed advanced batteries like the VRB-ESS. We could install 300 MW of the VRB-ESS in less time then they can get a CAES plant - if they ever get it built at all. And, the batteries would be built where it's needed, close to the load, reducing the need for more transmission wires, reducing the cost of distribution, improving energy security and power quality, and with greater efficiencies - less loss of wind energy - no emissions and no volatility on the cost of power.

Largest Grid Battery Ever? What's the Real Story?

Southern California Edison has announced, apparently, that they have applied to the DOE, under the smart grid stimulus program, for $25 million to build the largest grid battery ever. I have many questions about this story and I'm hoping we'll get more clarification in the near future.

We are well aware of the DOE grant program because we are involved in several applications for the VRB-ESS. We'll provide more information as we have developments we can share.

Here are the issues and questions I have with the story:

• First, I cannot find a press release from SCE. The story appears to based on an interview with Paul De Martini, Southern California Edison's vice president of advanced technologies. This makes it a bit difficult to get more detail or clarification. We'll ask Mr. De Martini for clarification.
• Next, the story says the grant is for 32 megawatt hours of storage. Since the current A123 grid systems in place are for grid stabilization, with only about 15 minutes of storage, Edison would need to install 128 MW of capacity to get 32 hours of energy. That would make it a huge, unheard of capacity battery, but with very short term storage. So, I'm not sure what the application would be for wind energy. 4:1 capacity to energy storage is normally conceived for frequency regulation, which is the current application for A123. That type of application can be anywhere on the grid - there is no need to place it at a wind farm. We normally think of storage for wind for the purpose of shifting generation from night time production to the day - something you can't do with 15 min. of storage.
• If the project is 32 MWHrs of storage, then it isn't the biggest project by a long shot. The 238 MWHr system by NGK in Japan wins that contest with their 34 MW by 7 hours of storage system. Sure, they can only use half the capacity at a time to avoid overcharging, but the total is still greater than the Edison project - if the story is correct.
• The ARRA grant is a matching grant, so we assume Edison will need to seek approval from the California Public Utilities Commission for an additional $25 million, or more, for a total cost of $50 million. That's $1,500 per kilowatt hour! - pretty darn expensive. For comparison, the flow batteries and NGK are between $500 and $700. However, on a capacity basis, at 128 MW, it's only $390 per kW.
• If the story meant to state a 32 MW capacity, then the economics make no sense.

I think the actual story is that Edison wants to install a large capacity system for grid stabilization, not an energy storage system to shift wind generation. Does it make sense? A 120 MW VRB-ESS with 6 hours of storage would cost around $300 million - 6X more expensive. However, along with fast response like the A123, you would also have 720 hours of energy storage! Is a 15 minute, fast response battery going to do the job, even if it is cheaper? This will be interesting to get the rest of the story and see how Edison presents the project to the CPUC.

VRB-ESS Government Incentives

This is a big month for us and many other energy storage companies. The American Recovery and Reinvestment Act - ARRA - a.k.a the Obama Stimulus Legislation - contains many incentives for energy storage and the smart grid. We're currently submitting several projects under the Smart Grid Demonstration Grant, which targets energy storage demonstrations. The deadline for submission is August 26th, and the total package will probably run to over 100 pages. We don't know how many projects will be submitted for the VRB-ESS - several sites are under evaluation - but, due to the complexity of the grant application process, we'll probably have to shut the door to additional projects around the 15th.

The Smart Grid Demonstration Grant is looking for several different types of demonstrations. The VRB-ESS is a good candidate for each category except one that is specifically set aside for compressed air energy storage. Grants are running from a couple million dollars for 1-3 MW installations to $25 million for 8-15 MW.

Here is the current breakdown of incentives for the VRB-ESS. We believe that the VRB-ESS specifically qualifies for these incentives in California - other energy storage technologies may not qualify.

• ARRA - Under the current grant opportunity, the Department of Energy will fund 50% of an eligible project.
• SGIP - the California Self Generation Incentive Program will provide a rebate of $2 Watt ($2 million per MW) for the VRB-ESS in association with on-site fuel cells or wind turbines. We believe the VRB-ESS will also qualify for an additional 20% ($2.40 per Watt) under a specific provision for California suppliers.
• ITC - The Investment Tax Credit cash grant is equal to 30% of a project cost when integrated with other renewable energy projects. There are many conditions to this grant, but it's actually very liberal for the VRB-ESS. It will apply to VRB-ESS retrofits to existing cogeneration, fuel cells, biomass, hydro, wind, solar, etc. installations.

Bottom-line - a short term opportunity exists to fund up to 90% of the installation cost for a VRB-ESS system. Such a system would provide a generator or industrial site with many economic benefits, including load / generation shifting, power quality, energy security - and provide the potential to earn revenue from CAISO ancillary services or demand response programs. Most evaluations we've done show a payback in months. If you think your site could qualify, contact us at ctoca @ utility-savings.com for an evaluation.

ITC Cash Grant for Storage

While the new guidelines from Treasury for the ITC grant are garnering headlines, a slightly overlooked item is the extension of the grant to energy storage!

Developers and vendors have had mixed views over the potential application of the Investment Tax Credit to energy storage equipment at renewable energy facilities. Guidance was lacking and opinions were mixed, including those of government agencies. Storage would allow PV and other intermittent renewables to increase their revenue per kW by providing firm and dispatchable power, increased sales of energy during the highest paid peak period, and the ability to offer additional ancillary services of great value to the grid operator. But, without the assurance of a tax credit, developers were cautious about figuring storage into their calculations.

However, the Treasury has now issued guidance on the ITC cash grant in lieu of a credit, and storage facilities are included. (see page 11) Storage must be "integrated" into the project, but the guidance on that is not restrictive. Now, the additional revenue from using storage can be factored into a project, and the investors can benefit from the tax credit/grant.