Energy Storage -- Why Policymakers Should Proceed Carefully

Jack Ellis | Feb 23, 2012

Readers of this publication are undoubtedly aware of a renewed interest in energy storage. Congress is considering the Storage Technology for Renewable and Green Energy Act of 20111, which would provide tax incentives. In the fall of 2010, California enacted AB 2514 2, which originally included a portfolio standard and was later changed to direct state and local governments to assess the need for a portfolio standard. AEP3, Xcel Energy4, Beacon Power5 and AES6 all have operating pilot or commercial-scale storage devices in operation. Storage has been prominently mentioned in connection with distributed generation, integrating renewables, and as an alternative for transmission7 and distribution upgrades. A report from EPRI8 cites numerous storage-related benefits, including capacity deferral, shifting energy from off-peak to on-peak periods, ancillary services and lower T&D losses.

However the high capital cost of storage technologies and a number of practical problems associated with storage implementation and operation are not quite as well documented. My purpose in writing this article is to point out some of the barriers and propose solutions. Rather than trying to address all possible storage applications, this article focuses on storage used to time-shift energy, provide ancillary services, provide peaking capacity, and act as long-term (multi-day) storage.


Perhaps the biggest obstacle to wider adoption of storage is its high capital cost. Pumped storage is probably the least expensive commercially available technology as well as one of the most efficient, but it has higher capital costs than gas-fired peaking plants and suitable locations are limited by geography and geology. Compressed Air Energy Storage is less site-specific and several conceptual designs have been proposed that could be even less costly than pumped storage, but these have not been proven at any scale. The diabatic9 process used at two existing sites employs gas-fired combustion turbines, costs about as much as pumped storage, and is relatively inefficient. Batteries and flywheels have no siting restrictions, but they currently cost significantly more to build than pumped storage, CAES or a gas-fired peaking plant. Lithium ion and sodium sulfur batteries are entering limited use in commercial applications, but while they are relatively efficient, they have very high capital costs. Flow batteries are less expensive to build, but they are also less efficient.

Many proponents are advocating for tax credits and other financial incentives to spur volume production in an effort to drive down costs. This is likely to waste enormous sums of money for several reasons. First, pumped storage costs won't be affected in any material way because most of their costs involve pouring concrete and moving dirt. Second, batteries and other, similar, technologies are still immature and unproven. Reductions in battery costs are likely to require advances in chemistry and materials science that increase the capacity and reduce the cost of existing chemical processes10. It makes more sense to invest money in R&D informed by technology roadmaps that identify obstacles to improving performance and reducing costs, with subsequent rounds of funding tied to cost reduction and performance improvement milestones. Particularly for the time-shifting and long-term storage applications, cost targets of $100/kWh or less have been mentioned in the literature11. For ancillary services applications, where one hour of storage capacity is sufficient, an overnight cost target of $300/kW12 would allow storage to compete with alternatives.

Markets and Prices

Even if storage intended for time-shifting, long-term storage or providing ancillary services could be built for free, it can't be operated cost-effectively in any of the organized wholesale (RTO and ISO) markets in the US. Organized markets employ incremental cost dispatch, which requires the operator of a generating plant to provide the grid or market operator with a price curve that typically reflects the generator's incremental running costs13. However a storage device's incremental costs depend on market prices that are unknown at the time bids (to buy energy) must be submitted to the market operator. Similarly, the prices a storage device would receive for energy it sells to the grid are unknown at the time offers (to sell) must be submitted. Consequently, a storage operator lacks the information it needs to formulate and submit price/quantity offers into the single clearing price auctions that form the basis for all organized electricity markets in the US. Instead, it must estimate next day prices and then blindly submit price and quantity offers without knowing whether their results from the auction are operationally and economically feasible14. As Xcel Energy discovered in the course of its wind-to-battery pilot, estimates are problematic because even small errors have a disproportionate impact on operating profits15.

The grid operator could accommodate storage devices by including them in its market optimization16 and producing an "optimal" charging and discharging schedule. PJM apparently does this for the pumped storage projects in its footprint. Since including storage in the optimization incurs a significant cost in terms of computational effort17, it is done only for the day-ahead time frame, and only for the largest storage projects18. None of the existing organized markets provides storage operators with a way to make beneficial adjustments to their day-ahead schedules in response to changes in grid conditions once the day-ahead market closes. The practical implication is that storage built for time-shifting or long-term storage will never be able to produce forecast levels of operating profits, because those forecasts implicitly assume the storage operator has perfect knowledge about market prices.

From the standpoint of a storage operator, the ideal market structure is one in which periodic or perhaps even continuous trading is allowed for each of the next 24 hours, and possibly longer for devices with multi-day storage capability. The grid operator's centralized market optimization software would be replaced by a system of decentralized decision-making and complex offer curves would be replaced with single-part bids and offers. Tradable commodities would include hourly energy, point-to-point or point-to-hub transportation (transmission), and options on energy (ancillary services). In 1996, the author and Dr. Edward Cazalet proposed this type of trading arrangement, which uses the same basic principles employed by commodity and equity markets around the world, as an alternative to the market ultimately adopted by California19.

Current prices for market services also act as an impediment to storage adoption. The amount of revenue a storage device can earn from selling capacity, ancillary (spinning reserves, non-spinning reserves and regulation) and time-shifting or long-term storage services is unlikely to be adequate to support most storage technologies at current market prices. With respect to capacity payments, prices for capacity in the centralized capacity markets20 have tended to clear well below the cost of new entry for a combustion turbine plant -- the highest price in PJM seems to be around $80/kW/year21 in a load pocket and the system-wide clearing prices is $45/kW/year or less22.

Although storage built for time-shifting and long-term storage can provide and receive standby payments to provide ancillary services, it can only claim those payments for hours in which ancillary services are less valuable because it is typically operating in either the charging or discharging mode in those hours when ancillary services are most valuable. Consequently, any added revenues from supplying ancillary services when the storage device is not otherwise engaged are likely to be relatively small unless the storage device is specifically built and operated only to provide ancillary services. However, even in this special case, ancillary services revenues are currently relatively meager and are likely to remain that way due to competition from flexible demand23 and fossil-fired generation. Beacon Power's recent bankruptcy filing was prompted in part by falling prices for frequency regulation in the New York ISO market that rendered its new Stephentown flywheel plant uneconomic24. While FERC's recent Order 755 changes the compensation mechanism for frequency regulation in ways that favor fast-acting resources like storage, increased competition is likely to maintain downward pressure on ancillary services prices even as demand increases. In California, for example, the peak need for frequency regulation in 2020 of around 1,100 MW can easily be met by more than 22,000 MW of regulation-capable fossil-fired, hydro and pumped storage capacity25.

Subsidies, Accountability and Performance

At least one analysis has justified subsidies for storage at levels that would make electricity consumers indifferent26, typically in the form of lump sum payments or tax credits once the project enters commercial operation. One of the drawbacks of this approach is that project developers and owners who are the likely recipients of any incentives can earn back their invested capital fairly quickly once the project is operational, while consumers are at risk for both the incentive payments and benefits that may not materialize in accordance with the developer's projections.

In fact, subsidies for storage may be unusually risky from the standpoint of the consumers who will be asked to fund it. Incentives tied to production create a perverse incentive to maximize production even if doing so produces operating losses (the efficiency -adjusted cost of off-peak charging is greater than the value of displaced on-peak generation). Incentives that are not tied to production may allow the developer to meet its financial return targets without ever actually running the storage device. To some extent, these same perverse incentives exist with subsidies for conventional generation, but they are rarely discussed.

Subsidizing storage also means too much of it is likely to be built, which will further weaken the economic rationale for storage and other resource options. In organized markets, subsidies for preferred resources depress market revenues for unsubsidized resources that may also be required to remain in the market for operational reasons, thereby triggering round after round of corrective subsidies to keep everyone whole.


Policymakers and regulators need to carefully consider the cost, performance and operational aspects of storage before they implement aggressive policies aimed at increasing deployment. Generally speaking, storage is still too expensive compared with available alternatives for time-shifting energy and for providing capacity and ancillary services. It is also a much more expensive alternative than fossil-fired generation for meeting demand during periods when renewable energy production simply isn't available. As currently structured, organized markets in the US don't provide the information and the trading opportunities storage operators to maximize their operating profits, and consequently the operating benefits of storage are unlikely to be realized.

Rather than providing direct subsidies to build storage, policymakers should work with manufacturers to develop technology roadmaps that focus on cost and performance improvements, and then fund research and development efforts with clearly defined cost and performance targets.


  1. Storage Technology for Renewable and Green Energy Act of 2011 (

  2. AB 2514 (









  11. Lawrence Berkeley Labs cites an ARPA-E cost target of $100/kWh. See, slide 3.

  12. Current prices for frequency regulation

  13. Or in the case of flexible demand, decremental costs.

  14. For example, they could end up "winning" all of their trades to sell energy and none of their trades to buy, in which case they must buy energy in the real-time market at uncertain prices that might result in operating losses.

  15. Add reference to report.

  16. Market optimization software performs much the same role as a vertically integrated utility's economic dispatch algorithm. It uses bids and offers from buyers and sellers to matches supply and demand at least cost while observing a number of system constraints.

  17. See slides 17-22.

  18. Since prices in all hours dictate storage operation and since storage operation influences prices, several iterations through the market software may be required to converge on an optimal solution.

  19. In addition to facilitating storage operation, the approach outlined in our paper has a number of advantages for market operators, other resource owners, retailers, market monitors and regulators.

  20. Centralized capacity markets are operated by PJM, the New York ISO and ISO New England.

  21. PJM reports capacity prices in $/MW/day. As reported, the price was $225/MW/day.

  22. $125/MW/day.

  23. For example, an aggregation of commercial buildings with HVAC plants powered by variable frequency drives could easily provide frequency regulation at a lower cost than storage.


  25. Conversation with Donald Tretheway at the California ISO.

  26. See California's Statewide Joint IOU Study on Permanent Load Shifting at

Related Topics


Very interesting article Jack. The storage of energy is the holy grail of the energy business and is one of the methods used in an attempt to flatten out consumer demand curves so that generation can be operated at optimum efficiency.

Storage is not necessary if generators can follow load cheaply which essentially requires that low cost generation like nuclear is required to operate both as base and peaking load without additional fuel costs. Some nuclear plant designs can do this although none of the currently operating designs can operated like that. The French have devised an ingenious fueling scheme that allows their reactors to perform limited load following since they have a very high nuclear percentage - far in excess of base load requirements. However most nuclear installations operate strictly as base load generators.

The solution of the storage problem will benefit nuclear generation more than any other since it would allow the grid to operate on 100% nuclear installations without need of gas turbine or coal plant peaking plants. A completely hydrocarbon free generation of electricity.

But, like you, I consider most of the technologies proposed to be prohibitively expensive and not competitive at present state of the technologies. It would be a wiser use of funds to develop load following nuclear reactors then there is no need for storage of any sort.


"Rather than providing direct subsidies to build storage, policymakers should work with manufacturers to develop technology roadmaps that focus on cost and performance improvements, and then fund research and development efforts with clearly defined cost and performance targets."

This is music to my ears Jack. By aggressively subsidizing building and deployment of storage technology but ignoring its research and development beforehand, the government is putting the cart before the horse. This is a common problem for governments when trying to push changes onto a regulated industry like utility companies that are totally separate from the unregulated technology manufacturers. It risks deploying technology prematurely that is not cost effective, at taxpayers' expense.

Here in Ontario it happened with our smart metering deployment. Our provincial government forced utility companies through legislation to deploy interval smart meters to all 5 million customers in the province by the end of 2010 with only minimum capability requirements to implement TOU billing. As such most of them now deployed are orphaned without the necessary added electronics functionality required for the envisioned smart grid (such as communications into homes for DR and energy monitoring, or with the emerging electric vehicles to properly bill vehicle owners to recharge.) Ontario faces the sad situation of having to swap out millions of smart meters from the field in the future to upgrade them to handle the emerging smart-grid applications.

Interesting article. There are 2-sides to grid-scale energy storage . . . overnight storage and seasonal storage, with potential market applications for both. Ontario has literally paid outside utilities to take in excess off-peak generating capacity, as it is cheaper to run a nuclear power station at steady output that to shut it down overnight. The cost of repairs caused by the build-up of thermal stresses far exceeds the cost of excess power generation.

Ontario and New York have ready access to massive pumped hydraulic energy storage capacity . . . between Lake Ontario and Lake Erie. There is a control dam at Niagara and hydroelectric turbines that can be modified and exchanged for pumping turbines. There is ready potential to develop an additional 3,000MW to 4,500MW of overnight pumped hydraulic storage capacity at Niagara, using the existing and soon-to-be-opened hydro-tunnels. All that is needed is the political will to move forward with this.

With regard to seasonal storage, advances in air-over-water CAES can make this possible in many parts of the world, including around the Gulf of Mexico and several coastal locations around the Middle East.

Harry, You are missing a very important consideration. People like to see water falling over the falls at Niagara. If we take much more water out of the Niagara River there will be none left for the tourists. It is nothing to do with political will Harry. This is dirt cheap electricity and we would use it if it was practical It isn't.

Summertime demand is almost all caused by air conditioning, a load that can easily be shifted with THERMAL energy storage (TES). TES is proven, reliable and affordable, yet it is never mentioned as one part of the energy storage solution. I realize that TES is not on the grid side of the meter, but their combined impact can add up to significant capacity.

Think of the infrastructure that is saved by the residential use of water heaters that store hot water! Yet the commercial building industry and HVAC designers still choos to provide over sized, just in time cooling systems. They have done a good job of increasing efficiency and so the return on investment for increasing equipment efficiency even further show a poor return. Lowering connected load and shifting load is the next logical step.

I realize that summer is not year round in most places so the grid sized storage technologies you mention are indeed an important part of the equation. However, TES can make a huge impact and is affordable. Subsidies are not needed unless the utility industry wants quick adoption. This industry is surviving with only a small percentage of cooling systems using storage today ASHRAE 90.1, LEED, and Demand response revenue opportunities like those you mention are causing TES applications to increase. A Manufacturer of HVAC equipment has recently announced a commercial pre-engineered HVAC storage system that includes pumps, controls, chiller, and storage further reducing costs and implementation barriers.

TES systems can last longer than 30 years, are reliable, are affordable, and are easily recycled. Its time to mention TES in the storage conversation.

Gravity Power ( is developing a modular, in-ground and closed pumped storage hydropower (PSH)-based technology called the Gravity Power Module (or GPM). We intend to sell and build turnkey energy storage-based peaking power plants.

Based on the proven principles of PSH, we eliminate much of the siting and permitting challenges of PSH due to our small footprint and not requiring the conventional geographical features needed for elevation changes with PSH. The powerhouse is at ground level, and most everything else in the technology is underground and not visible. The system is filled with clean water once and then closed; no use of navigable or natural waterways is included. GPMs can be sited next to generating assets or near the load, wherever the owners decide is most optimal for their system. GPMs also do not require decades to reach commercial operation, and, as each GPM comes online over a year or two, it is put into service. This eliminates the need to secure the standard $1 - $3 billion in upfront capital to construct PSH before one sees a Watt of service or a return on this capital over many years as one endeavors with PSH to find a site, get the permits, secure the financing and then build the plant.

Eventual capital costs projections show the GPM system competing well with simple cycle gas turbines, which will allow GPMs to replace these less efficient, slower responding and carbon emitting turbines seen as a $30 billion annual market. Once you have installed this fast responding, efficient, clean and flexibly-sited peaking capacity, we have energy storage-based power plants to work in tandem with renewable generation assets as they penetrate more and more of the world's power grids.

We see the strong near-term demand not in the U.S. or Canada, but in Germany, other parts of the EU, China, South Africa and a few additional select locations. Gravity Power will first seek to replace the proposed new, conventional and the emerging underground PSH programs we feel will be expensive and not result in any significant new capacity for decades. This while the need in these regions is much nearer-term.

As the GPM technology matures, we intend to replace or be the technology of choice for new peaking capacity and to work with renewable generation assets so they may be viewed as grid operators as capacity themselves.

First, I echo and fully support the comments made by Paul Valenta above, regarding overlooked value of cool TES (Thermal Energy Storage) as a commercially available, proven, high-efficiency and low cost means of multi-hour (daily) Energy Storage for addressing electric demand peaks driven by air-conditioning loads. But I wish to also emphasize that TES can be applied not only on the demand-side (by air-conditioning users), but also on the supply-side (as part of a Turbine Inlet Cooling (TIC) system at a simple-cycle, combined cycle, or Combined Heat & Power (CHP) gas-turbine power plant.

Below are two tables extracted from my paper presented at the Electric Power Conference (May 2009): "Supporting Renewable Power Generation with Energy Storage – supply-side and demand-side storage that is practical and economical" by John S. Andrepont, President - The Cool Solutions Company. They compare actual suplly-side and demand-side examples of TES to other available or proposed Energy Storage technologies.

Table 1 – Comparison of Actual Supply-Side Energy Storage Systems

Turbine Inlet
Cooling (TIC)
Pumped Hydro CAES with CHW TES*

Location Michigan, USA Iowa, USA Riyadh, KSA
Year of Initial Operation circa 1990 201X ? 2005
Electric Power Peaking Capacity 1,200 MW 268 MW 180 MW
Energy Storage Peaking Duration 8 hrs 6 hrs 6 hrs
Electric Energy Storage Capacity 9,600 MWh 1,608 MWh 1,080 MWh
Round-trip Energy Efficiency ~70% <70% near 100%
Projected Life Expectancy 30+ yrs 20+ yrs 30+ yrs
Technology Status Commercial Developmental Commercial
Capital Cost per Unit of Power $2,000+/kW ~$900/kW ? $250/kW
Capital Cost per Unit of Storage $250+/kWh ~$150/kWh ? $42/kWh

* Note: Example includes performance and cost of entire Turbine Inlet Cooling and TES system.

Table 2 – Comparison of Actual Demand-Side Energy Storage Systems

“Utility-Scale” CHW TES for CHW TES for
Sodium-Sulfur Turbine Inlet District Cooling
Battery Storage Cooling (TIC)** Air-Conditioning

Location W. Virginia, USA Riyadh, KSA Florida, USA
Year of Initial Operation 2006 2005 2003
Electric Power Peaking Capacity 1.2 MW 48 MW 15 MW
Energy Storage Peaking Duration 6 hrs 6 hrs 8 hrs
Electric Energy Storage Capacity 7.2 MWh 288 MWh 120 MWh
Round-trip Energy Efficiency ~70% near 100% near 100%
Projected Life Expectancy 15+ yrs 30+ yrs 30+ yrs
Technology Status “Pioneering” Commercial Commercial
Capital Cost per Unit of Power $4,500/kW $83/kW $200/kW
Capital Cost per Unit of Storage $750/kWh $14/kWh $25/kWh

** Note: Example includes performance and cost impacts of only TES portion of the TIC system.

Neither TES nor any other Energy Storage technology is the "silver bullet" for all Energy Storage needs of the electric power system. However, TES should be considered and applied far more than it is currently, and on both the demand-side and the supply-side.

Paul Valenta and John Andrepont have raised a good point re seasonal thermal storage. In Alberta, a pocket of water-soaked porous rock is heated during summer, to 80-deg C using solar thermal trough technology . . . then during winter with temperatures dropping to minus 40-C, provides heating for an entire community. Quebec has peak energy consumption during winter, courtesy of low cost electric power and base board heaters.

In other regions, it is definitely possible to cool the ground water in pockets of porous rock during winter, down to just above the freezing point of water. During summer, it can serve as a heat sink by which to cool buildings.


Sorry, but the formating of my comments posted above left a confusing message, so I am attempting to clarify it here now.

First, I echo and fully support the comments made by Paul Valenta above, regarding the overlooked value of cool TES (Thermal Energy Storage) as a commercially available, proven, high-efficiency and low cost means of multi-hour (daily) Energy Storage for addressing electric demand peaks driven by air-conditioning loads. But I wish to also emphasize that TES can be applied not only on the demand-side (by air-conditioning users), but also on the supply-side (as part of a Turbine Inlet Cooling (TIC) system at a simple-cycle, combined cycle, or Combined Heat & Power (CHP) gas-turbine power plant.

Below are data from two tables extracted from my paper presented at the Electric Power Conference (May 2009): "Supporting Renewable Power Generation with Energy Storage – supply-side and demand-side storage that is practical and economical" by John S. Andrepont, President - The Cool Solutions Company. The tables compare actual supply-side and demand-side examples of TES to other available or proposed Energy Storage technologies.

Table 1 – Comparison of Actual Supply-Side Energy Storage Systems

A) Pumped Hydro, Michigan, circa 1990, 1200 MW x 8 hrs = 9600 MWh, ~70% round-trip energy efficiency, 30+ yrs expected life, current technolgy status: commercial, total unit capital costs: >$2000/kW or >$250/kWh

B) CAES, Iowa, planned 201X?, 268 MW x 6 hrs = 1608 MWh, <70% effic, 20+ yrs life, tech status: developmental, ~$900/kW target? or ~$150/kWh target?

C) Turbine Inlet Cooling with Chilled Water TES*, Saudi Arabia, 2005, 180 MW x 6 hrs = 1080 MWh, near 100% effic, 30+ yrs life, tech status: commercial, $250/kW or $42/kWh

* Note: Example includes performance and cost of the entire Turbine Inlet Cooling and TES system.

Table 2 – Comparison of Actual Demand-Side Energy Storage Systems

A) "Utility-Scale" Sodium-Sulfur Battery Storage, West Virginia, 2006, 1.2 MW x 6 hrs = 7.2 MWh, ~70% effic, 15+ yrs life, tech status: "pioneering", $4500/kW or $750/kWh

B) Chilled Water TES for Turbine Inlet Cooling**, Saudi Arabia, 2005, 48 MW x 6 hrs = 288 MWh, near 100% effic, 30+yrs life, tech status: commercial, $83/kW or $14/kWh

C) Chilled Water TES for District Cooling Air-Conditioning, Florida, 2003, 15 MW x 8 hrs = 120 MWh, near 100% effic, tech status: commercial, $200/kW or $25/kWh

** Note: Example includes performance and cost impacts of only the TES portion of the TIC system.

Numerous other actual examples of large Chilled Water TES applied to District Energy Systems (demand-side) and to Turbine Inlet Cooling (supply-side) have shown similarly attractive results.

Neither TES nor any other Energy Storage technology is the "silver bullet" for all Energy Storage needs of the electric power system. However, TES should be considered and applied far more than it is currently, and on both the demand-side and the supply-side, for multi-hout stoarge applications.

I certainly do NOT recommend further centrally controlled subsidy programs which invariably primarily benefit those industries or firms with the best connected or best funded lobbyists, and invariably produce negative unintended consequences. Lets instead let the free market work (and succeed) again, as it did many times in the past.

If you don't want a weird subsidy mix, then tax gasoline/diesel more. Energy storage for non-transportation issues is economically and commercially silly at this point. [Maybe there are some niche areas.]

If as a society we agree it's best to reduce our dependence on oil-based fuels, then we should tax them to get us to move from them. (Like cigarettes, liquor, and marijuana (if they were smart) ).

Good article. I definitely agree that the present market system used in deregulated markets is "too dumb" to provide the market signals storage owners require. And present "smart meters" are "too dumb" for the required markets as well. I'd also add that likely the best energy "storage" system in the forseeable future is / will be selective charging of electric vehicle batteries, with PERHAPS some use of vehicle-to-grid capability in dire emergencies. However, this again requires a much smarter metering system, grid and market than any regulator has so far proposed, or apparently even thought of. My IMEUC proposed market system seems to resolve most if not all of these issues, as intended. See my articles this site.

Thanks for all of the thoughtful comments.

John, tables don't reproduce well in this format. Perhaps there's a link to the paper?

John and Paul, I'm familiar with thermal energy storage. Ice Energy has had a tough time selling its product to utilities for reasons I don't fully understand. Some commercial building operators have done the same thing by taking advantage of thermal mass, which eliminates the capital cost and space requirements for ice tanks and plumbing.

Chris, I'm afraid I'm not entirely persuaded by your arguments. Storage has to be cheaper than a peaking plant in order to be cost-competitive. It has to rely entirely on making up storage losses with renewable energy to be cleaner, which diminishes its cost-effectiveness.

Cost does matter. Consumers in Germany are only just beginning to feel the cost impacts of their government's aggressive stance on renewable energy, and the government is apparently worried. In Spain, above-market costs for solar are continuing to pile up on someone's balance sheet, which are eventually going to have to be paid by someone. Waiting only makes the problem worse.

Jack: Thanks for your thermal energy storage comments. Ice Energy Storage Systems are different from Commercial Thermal Storage Systems and as such, their business model and costs are different. The ice storage industry in the commercial sector is thriving. Driving the business is utility rates. The Edison Electric Institute has said that the only form of energy not to increase in cost when converted to today's dollars, is off peak electricity. So storage is a great hedge against rising costs.

I like to think of a hybrid car comparison. Standard cars have bigger engines in them for when there is a larger load or a burst of speed is needed for merging on highways. Hybrid cars have smaller engines which provide greater efficiency and power is adequate most of the time. When more power is needed, or during times of slow speeds, the storage is used to either provide that burst of power to merge or improve efficiency when crawling in traffic or on short commutes. Commercial cooling with energy storage is similar. Engineers design systems for peak design days and unanticipated cooling loads. This results in large cooling systems with large supporting infrastructure. Adding storage into these designs requires smaller cooling systems that are more efficient over a wider operating range. When prices are high, or the load is great and a boost is need, the storage provides capacity. Connected load is smaller, the safety capacity is provided by storage which is paid for by using a smaller electric chiller and support equipment.

According to a KEMA study, TES has provided about 1 GW of storage to the grid, more than double pumped hydro and more than all storage technologies combined, so I have to ask why is it never mentioned as part of the solution?

Storage is indeed the holy grail for the electricity industry. We have had to live with electricity price regulation for all customers for decades because of the lack of practical large-scale widespread storage among other reasons.

Consider what would be necessary if economical large-scale storage became practical. Our regulated price systems would become virtually obsolete. Independent retailers could set up their own businesses using large storage systems much in the same way automobile gas stations have, only instead of roads connecting them to customers, they would be connected by the grid's distribution and transmission wires to all local customers. In this scenario, only a truly “Independent Market for Every Utility Customer” with unregulated prices would work effectively, just as the free market does for many other commodities consumers purchase. Lo and behold, this is exactly what would be realized by Len Gould’s IMEUC market system proposals.

Now combine an IMEUC market system with large numbers of micro-generators being connected to the grid. such as the growing renewables industry, all competing to sell their energy to the retailers with storage. I’ll bet most of the existing large central generating stations on the grid wouldn’t like this very much because of the unprecedented competition they would face.

I have news for the TV audience, this futuristic scenario is exactly where the electricity system is headed for over the coming decades. Ultimately such a market system would become very efficient where it would eventually make sense for ordinary residential consumers to buy storage systems and then sell their stored energy to anyone they want whenever they want, including to their neighbors on the same street.

Excellent, Bob. Agreed, a genuinely economical electricity storage system which could be distributed, combined with a genuinely free market for electricity and perhaps distributed N Gas fuel cell combined heat-power packages, would radically alter the calculations on which the present grid is based. Perhaps one reason why we may never see it.

Electric autos anyone? LOL.

There are many aspects of energy storage that do not need to involve government. The list would include onsite Thermal Energy Storage (making giant ice blocks in the basement overnight, during summer) and onsite battery (electrical, hydro-mechanical) technologies. TES makes far more economic sense than using the batteries of electric cars to store grid-scale power.

With growing demand for electric power in many nations, perhaps a future power installation would include nearby grid-scale energy storage. Under this scenario, a nuclear power station may be built next to a hydro dam that includes pumped storage, or building the power station above a location where CAES would be possible.

Jack, there are several (many) conventional and large, underground pumped hydro storage projects being proposed in Europe. We are told these projects target coming in at $1700/kW (and that is doubtful for underground projects) and at GW scales, if ever sited, permitted and financed.

Are you suggesting the large, well-known utilties and EPCs pursuing them should just be building more gas peakers? I am just trying to get clarity on your comment as it pertains to the market that is not the U.S. market which is an entirely different animal......Thank you....


I'm suggesting a) it's tough to justify storage over the other alternatives based on current capital costs, b) it's tough to get value out of storage built to participate in the RTO and ISO markets based on current market designs and business rules, c) policymakers should focus in the short-term on directing any public funding efforts toward improving efficiency and reducing capital costs.

Throwing subsidy money at storage deployments in an effort to drive down costs is probably a waste of money at this juncture because most storage technologies aren't even close to being cost-effective and even if they were shown to be cost-effective based on production cost simulations, the operating cost savings are too optimistic based on current operating practices.

TES is still not mentioned by your readers as part of the storage solution as more and more renewable energy become available. Since my first comment it is interesting to note recent KEMA study for the copper industry shows that over 1 GW of TES is currently installed. That is twice as much as pumped hydro and more that all other technologies combined. The five year prediction shows the trend to follow a similar path because of technology, costs, and siting issues. While people wait for the holy grail of grid scale storage and how to pay for it, TES capacity will increase because of energy cost savings opportunities and Demand Response revenue opportunities. Is not reducing summer peak while providing a place to store renewable energy important too?