Energy storage: not so fast

Markets should determine right application, right price

Jack Ellis | Nov 20, 2011


I was among those who reviewed the California Energy Commission's recently released "2020 Strategic Analysis of Energy Storage in California" report, referenced in Phil Carson's column last week, "Energy Storage, EVs and Collaboration." I was listed as an "advisor" to the CEC process that produced the report. In his column, Carson lamented that dissenting views were not published with the report.  I'll provide such a view here.

While I agree that storage could be an attractive resource as California pursues the 33 percent renewable portfolio standard (RPS) target, in my view the report is biased toward advocacy and does not give enough weight to several other critical factors.

The first factor is cost-effectiveness. Storage is currently more expensive than competing alternatives, which is a key reason utilities have been reluctant to deploy it. In California's current market environment, low, stable energy prices and low incremental capacity values make it impossible for storage to compete.

Second, it's unlikely that all of the identified economic benefits can actually be realized, particularly for storage projects that are built to time-shift energy.  Wholesale electricity markets in the United States are designed around thermal plants whose marginal costs are known with a high degree of precision. Even if day-night price differences are sufficiently large, and it is not certain they will be, the only way a storage device can consistently generate operating profits is by being able to purchase and sell electricity at prices that are known with a fair degree of certainty in any or all of the upcoming 24 hours. Today's wholesale markets provide neither the forward price visibility nor the opportunity to trade on those prices once the day-ahead auction is finished. Having an Independent System Operator (ISO) determine how to operate storage is also not a feasible solution. PJM found that trying to determine an optimal day-ahead operating schedule for a single large storage system in its footprint led to a five-fold increase in computing effort. 
Third, subsidized storage may conflict with electric vehicle (EV) deployments. If California policymakers are serious about promoting electric transportation, and if they are also serious about encouraging EV users to charge off-peak, then they should be aware that subsidized storage for time-shifting energy disadvantages EV users in two important ways. First, it will increase competition for access to off-peak energy, which will increase the cost of off-peak charging energy for those EV users who do choose to charge their vehicles at night. Second, EV users will be forced to effectively pay for those subsidies even though they provide many of the same benefits at no cost. 

Fourth, the emissions-related impacts of deploying storage need to be better understood and articulated. While it is true that storage devices other than certain compressed air energy storage (CAES) implementations do not emit CO2 or other pollutants directly, their use either increases emissions from other supply resources or drives the need for more renewable production. A pumped storage plant operating at 75 percent efficiency withdraws one third more energy from the grid when charging than it injects back into the grid when it is discharged. If that additional energy is deemed to be supplied by a fossil-fired plant or from imports, then storage operation leads to a corresponding increase in emissions. If the losses are deemed to be supplied by renewable energy, then additional renewable resources must be built because the RPS is tied to retail sales rather than electric production.  

Fifth, regulators, policymakers and lawmakers need to realize that the benefits of storage used to time-shift renewable production and to provide longer duration balancing services depend on credible economic signals. Wholesale prices that are low and stable make storage operation economically challenging because revenues from discharging the storage device might not cover the cost of charging energy that includes losses. Overly generous supply margins that minimize the likelihood of politically inconvenient price spikes undermine storage economics and needlessly inflate customer bills.

The report also suggests storage is essential in order to meet the 33 percent RPS by citing a conclusion from an analysis prepared in 2010 by KEMA Corporation. This isn't true.  What the KEMA report did say was, "large-scale storage can improve system performance by providing regulation and imbalance energy for ramping or load-following capability. The 3,000 to 4,000 megawatts (MW) range of fast-acting storage with a two-hour duration achieved solid system performance across all renewable penetration scenarios examined."   

Storage has a place in modern electric grids, but only in the right applications and at the right price point. The economic burden of market transformation, which is what this report seeks to promote, should be shared more broadly via carefully targeted, federally sponsored research and development efforts that focus on technology improvements and cost reductions, rather than falling solely on California electricity consumers.

Jack Ellis, ME, works as a consultant to the power industry, advising utilities and other stakeholders on a variety of contemporary regulatory and business issues, including the operational impacts of renewable resources, wholesale electricity market design and policy, and demand response policy and implementation. 


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In reply to the comment about the interaction between renewable energy economics and large scale energy storage economics, the conclusion of incompatibility is erroneous. Large-scale storage is not just about improving TOD value for renewables. It's also about creating firm capacity that has renewable energy as its energy component. If you model the renewable + storage blend (and that's long-duration storage like pumped storage and CAES) versus the default model of renewable + gas plants to provide firm capacity, you get a better deal with the renewable + storage strategy. However, this requires that the renewables and the storage are modeled together, rather than separately.


Economic consideration can be made for storage that is located close to load versus generation, because there is value in using the transmission asset overnight versus during peak periods, a peak transmission reduction. Regulation services provided by storage are fast acting and require no spinning. In addtion, future contracts can lock in prices that could move such that you are not adversely impacted by the change in off on peak spreads.

Energy Storage

Fossil fuels are in essence a form of energy storage.  If the carbon content of fossil fuels is heavily taxed, then other forms of energy storage become more economic.  Hence the economics of non-fossil fuel energy storage are strongly dependent on the economics of fossil fuels which in turn are dependent on the level of fossil carbon tax.  Until North American governments bite the bullet on the carbon tax issue it is difficult to see how anyone can make money in the energy storage business.

Modelling and Renewables Incentives.

From Steve Browning. Sorry about the formatting; the paragraphs look fine with rich text disengaged but when saving it seems to remove all line feeds!! We need to identify the underlying operational issues properly and then evaluate the options. Renewables are variable and unpredictable; Wind in the UK is synoptic (depressions crossing the Atlantic) while I believe US wind is more thermally induced. With the proposed 30+GW fleet for GB, which will be mainly offshore, large output ramps will occur (16GW+) but forecast accuracy at 4 hours out is expected to be no better than 30-50% of the total. Our Peak demand (Winter weekday 5pm) is 60GW and Trough demand (August Sunday 5am) 24GW. Multi day calm periods can be experienced across the Winter Peak. So, wind has virtually no contribution to system capacity. It has to be replaced by high efficiency plant on calm days while we also need a considerable level of high speed reacting plant to cover the extreme uncertainty of the ramp timings and magnitudes when it does blow. Into this we also need to factor customer reaction and storage mechanisms. No one has yet done an adequate assessment of how the market and then the operator mechanisms will behave with this level of variability and uncertainty and what the options will cost. It requires a 'pseudo real time' market and operator simulation in 'walk through mode', with data changing as new forecasts are made. This needs to cover all Commitment, Scheduling, Rescheduling and Dispatch actions with a final Outturn evaluation, looking at different plant, customer action and storage strategies. From this we will finally get a reasonable idea of which options give the best result (cost, fuel burn and emissions) and what the renewables plant is really worth (or not worth). Then we can also derive properly structured incentives for renewable plant (including the value of time of output production and 'predictability') instead of the flat rate schemes in use currently. Building such a simulation system is not an easy business and running it will involve manual effort, especially on the market side. Existing operator training facilities can be adapted for the operational package. However, the outturn evaluator concept is unique and there will need to be much more reliance on direct automatic control. That in turn is partly at variance with the concept of unbundled ownership of Generation, Transmission, Distribution, Retail Supply and System Operation. We are going from a situation where generation which largely 'does what it is told' and follows demand to one where we have a lot of variable/unpredictable units and the customer side (quite rightly) participates (albeit automatically) in Electricity Supply generation-demand matching. Use of the best type of generation schedulers (Mixed Integer-Linear), which produce snapshot definitive results, has been attempted to evaluate the future. I spent many years 'taming' such beasts to ensure they produce realistic schedules and, as you can see from my above argument on modelling, a single definitive schedule is of no use when high levels of variable unpredictable plant is included. A few thoughts.... At the GB system peak of 60GW we are pushing @85million Brake horsepower through a quite fragile set of wiring. "There are an infinite number of ways of running an Electricity Supply System badly" "The future is out there somewhere, we just have to make sure we get the best one" More 'basics' and insights are in my Future Power Systems articles - please follow the trail through

Energy Storage Not So Fast

I support a market standing on its own merits.  If a government entity wants a market to move quickly, incentives can help jump start a technology to overcome barriers.  Barriers can be inexperience, inexperience with proper application, design and installation know how,etc.  These obstacles can be overcome and their "extra costs" eventually go away.  In the end, however, if a technology has a price issue after those obstacles go away the technology is not market ready in my view.

Thermal energy storage is self supporting today in some markets. TES stores energy in the form it will be used in the application contributing to high summer peaks.  TES has a 30 year life and can be easily, in most cases, recycled or reused.  In areas where TES is not used there exist barriers because of previous experience or inexperience.  Today's products and best practices ensure a reliable and affordable hybrid cooling system.  Rebates can help overcome those extra cost barriers quicker.  Manufacturers and experienced users will help the market overcome those barriers but at a slower pace without rebates.

Hybrid cooling systems with energy storage hedges cooling costs with an energy source shown not to be any more expensive according to EEI, in today's dollars, that it was 40 years ago - night time electric generation.  It does this while allowing designers to lower the projects overall connected load and helping the viability of renewable energy so states can meet their goals.

actual conclusions from KEMA 2010 report (excerpt)

There are five major conclusions from this research work:
• The California ISO control area will require between 3,000 and 4,000 MW of regulation / ramping services from ʺfastʺ resources in the scenario of 33 percent renewable penetration in 2020 that was studied. The large ramping requirement is driven by the combination of solar generation and wind generation variability that is forecasted for the 33% scenario. Some of this ramping requirement can be satisfied by altering the likely system commitment for conventional generation to maintain a large amount of gas fired combustion turbines on‐line available for ramping. It also may be possible to alter the scheduling of hydroelectric facilities and pump‐storage facilities so as to assure adequate ramping potential at critical periods, although there are environmental and operational difficulties associated with this.

•The moment by moment volatility of renewable resources will require additional AGC regulation services in amounts (up to doubling todayʹs levels) that can be reasonably procured.

•The ramping requirements twice a day or more require much more response and will be the major operational challenge.

•Fast storage (capable of 5 MW/second in aggregate) is more effective than conventional generation in meeting this need and carries no emissions penalties and limited energy cost penalties.

•Use of storage also avoids greenhouse gas emissions increases associated with scheduling combustion turbines ʺonʺ strictly for regulation and ramping duty.

An alternative to providing large‐scale fast system ramping is to constrain the ramp rates of wind farms and central thermal solar plants so as to reduce the need for system ramping resources. This is an interconnection requirement in some island systems today. Meeting ramp rate limits on up ramping is easy enough to do at some lost energy production; meeting down ramp requirements is more technically difficult.

Storage at the site of the renewable resources or as a market service that renewable producers can acquire is an alternative to a system ancillary service with identical benefits and results. There are a number of policy issues at the state and federal level around this concept today which are elaborated in the report. The most important is to determine if ramping restrictions and support are the financial responsibility of the renewables operator or the market; and related to that what storage investments will qualify for what investment tax credits and how these are linked to renewables facilitating increased renewable generation.


I agree with Jack's premise that storage should be driven by economics and environmental benefits (which need to be internalized into economcs) rather than driven by politics. I do, however, have some questions and comments:

1. Jack, you write of "subsidized storage." What subsidies are you referring to?

2. Pumped storage is now generally 80% efficient, not 75%. Other, newer storage technologies are, what, 90%. And if we're talking about pumped storage, a major value stream there will be firm peaking capacity in addition to ancillary services. While load growth is slow due to the economy, an estimated 22,000 MW of "once-through cooling" gas turbines will need to be retired.

3. On the environmental aspect, there is a presumption that off-peak energy would be drawn from fossil sources, particularly out-of-state sources. Since renewables are driving the talk of storage, wouldn't it be more likely that off-peak wind, rather than fossil, would be driving the pumps? Particuarly with California divestment in out-of-state coal plants?


Thanks for your questions and comments.

California utilities are under a legislative directive to determine whether it makes sense to require minimum levels of energy storage.  The CPUC has several programs that pay "incentives" for certain technologies, including storage.  I also consider storage built by a utility that operates in one of the RTOs/ISOs to be subsidized if the facility is afforded rate base treatment.

I'm aware that pumped storage may have efficiencies in the 80% range.  Most battery technologies are not nearly that good.  Flow battery efficiencies are in the 50-70% range.

Capacity credits do indeed narrow the gap, but for many storage technologies, capacity credits are not enough.  A new CT costs $1400/kW.  Flow batteries cost about the same, but their effective fuel cost net of losses is 30-40% higher than the cost of energy from the combined cycle plant that will provide it.

As I pointed out in the article, if charging energy is deemed to be drawn from a renewable resource, under the California RPS that energy would have to be supplied by overbuilding renewable energy production, since the 33% target is tied to retail sales rather than production at the generator busbar. 

Energy storage: not so fast

Your article points out several weaknesses in the case for electricity storage.  In system regulaiton applications, energy storage competes with other approaches to system regulations.  While it may be an excellent option, it remains to be seen if it is cost competitive.

In the area of time shifting, there is more that one can add.  Presumably we do not do time shifting for the sake of time shifting.  We would do it to encourage the penetration of renewables.  Renewable penetration would only be increased if the prices paid to renewable generators in off peak hours were to increase. However, energy storage becomes less profitable as the off peak prices increase.  The economics of renewable generation and large scale energy storage are not very compatible.  There are circumstances where it could work, but they may be rare.