California Energy commission. June 2010. Research evaluation of wind generation, solar generation, and storage impact on the California Grid. 131 pages.

Excerpts:

This report analyzes the effect of increasing renewable energy generation on California’s electricity system and assesses and quantifies the system’s ability to keep generation and energy consumption (load) in balance under different renewable generation scenarios.

In particular, researchers assessed 4 key elements necessary for integrating large amounts of renewable generation on California’s power system. Researchers concluded that accommodating 33% renewables generation by 2020 will require major alterations to system operations.

They also noted that California may need between 3,000 to 5,000 or more megawatts (MW) of conventional (fossil‐fuel‐powered or hydroelectric) generation to meet load and planning reserve margin requirements.

The study examines the relative benefit of deploying electricity storage versus utilizing conventional generation to regulate and balance load requirements.

Researchers also noted the effectiveness of storage technologies, in comparison to conventional generation, to meet energy systems’ need to accommodate large output changes of energy resources in a relatively short period.

Introduction

The integration of renewable energy resources into the electricity grid has been intensively studied for its effects on energy costs, energy markets, and grid stability. These studies all conclude that the variability and high‐ramping characteristics of renewable generation create operational issues.

Project Purpose

This research identifies key issues and assesses the effects of high renewable penetrations on intra‐hour system operations of the California Independent System Operator (California ISO) control area. It also looks at how grid‐connected electricity storage might be used to accommodate the effects of renewables on the system.

The research focuses on required changes to current systems to balance generation and load second‐by‐second and minute‐by‐minute, and to do so in the most cost‐effective manner. The study also assessed potential benefits of deploying grid‐connected electricity storage to provide some of the required components—including regulation, spinning reserves, automatic governor control response3, and balancing energy—necessary for integrating large amounts renewable generation.

The objective was to measure the effects of the variability associated with large amounts of renewable resources (20 percent and 33 percent renewable energy) on system operation and to ascertain how energy storage and changes in energy dispatch strategies could accommodate those effects and improve grid performance.

Automatic generation control operates the generators that supply regulation services (up and down) every 4 seconds to keep system frequency and net interchange error as scheduled. The real‐time dispatch buys and sells energy from generators participating in the real‐time or balancing market every five minutes to adjust generator schedules to track a system’s load changes.

Regulation in MW is the amount of second‐by‐second bandwidth or controllability used in balancing generation and load.

Spinning reserve is the excess amount of on‐line generation capacity over the amount required to supply load and available to respond to sudden load changes or loss of a generator.

Governor response is the near‐instantaneous adjustment of each generators output in response to system frequency changes, caused by the generator speed‐governing device.

System performance degraded, in terms of maximum area control error excursions and North American Electric Reliability Corporation control performance standards, significantly for 20 percent renewables penetration and became extreme at 33%

Droop is the gain on the generator’s local speed‐governing device, that is, how sensitive the generator’s output is to changes in system frequency. Ancillary services are those services that generators sell to the California ISO to enable system reliability and to follow load. Balancing energy is the energy the California ISO buys and sells every five minutes via real‐time dispatch to follow load.

Automatic generation control is the computer system at the California ISO that controls the generators in real time to balance load and generation second‐by‐second renewables penetration, using the same automatic generation control strategies and amounts of regulation services as today. Without adjustment to the automatic generation control and the amount of regulation procured maximum area control error excursions went from a typical band today of the order of ±100 MW to several times that in the 20 percent renewables scenario and to as much as 3,000 MW of error in the 33 percent scenarios. Such an excursion is not tolerable and would possibly cause other system protective devices to operate such as interrupting transmission flows to adjacent power systems.

 

The amount of regulation, without storage and using existing control algorithms, required to maintain system performance within acceptable limits for a 20 percent renewable case in 2012 was ±800 MW in the up and down direction, roughly double today’s amount.7

The amount of regulation and imbalance energy dispatched in real time, without storage and using existing control systems to maintain system performance, within acceptable limits during morning and evening ramp hours for 33 percent renewable cases in 2020 was 4,800 MW. The amount of regulation and imbalance energy dispatched in real time, without storage and using existing control algorithms, to maintain system performance within acceptable limits during non‐ramp hours to address system volatility for the 33 percent renewable cases in 2020 was approximately an additional 600 MW. By comparison, 1,200 MW of storage added to the baseline 400 MW of regulation provided superior results by comparison. (See Table 1).

Generally, the largest deviations in system performance occurred twice per day, once during the morning and once during the evening, corresponding to the interaction of diurnal production of wind and solar resources and fluctuation of demand. Accordingly, degradation of system performance appears to be predominantly caused by renewable ramping in the morning and evening along with traditional morning and evening load ramps.

Increasing regulation amounts, without the use of storage and improved control algorithms, can improve system performance. However, roughly 2‐to‐10 times the amount of today’s regulation and balancing capacity would be required to maintain system performance absent other operating protocols, such as limiting ramp rates and new services that could be developed as alternatives to address renewable ramping as well as scheduling and forecasting errors.

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 MW range of fast‐acting storage with a two‐hour duration achieved solid system performance across all renewable penetration scenarios examined.

storage can be up to 2 to 3 times as effective as adding a combustion turbine to the system for regulation purposes. The relative effect of each depends on how much storage or regulation and balancing is already in the system. When the system has sufficient resources for stabilizing system performance, the incremental benefit of either technology approaches zero. This is an incremental ratio of the effect a combustion turbine or a storage device each have on system performance, and not an indicator of how much total capacity of each technology may be needed to manage the large ramping phenomena.

 

Without the use of storage, ramping of combustion turbine generators and hydro‐electric generation is likely to increase. This may likely have detrimental effects on equipment maintenance costs and life of the equipment, and greenhouse gas emissions because the resources will be asked to generate more often at less than optimal production ranges as well as to remain committed—that is, on‐line—in anticipation of ramping needs.

Governors’ executive order S‐14‐08 established a goal of 33% energy from renewable resources to serve California customer load by 2020. This will require significant increases in ancillary services (regulation) and real‐time dispatch energy, with attendant changes in the day ahead schedules of generation production by hour to ensure that such services are available— that is, that enough generators will be on‐line with excess capacity available during each hour. Such a change in scheduling practice will incur additional economic costs in the production of power. The use of storage in conjunction with new control and generation ramping strategies offers innovative solutions that are consistent with the need to continue to comply with current North American Electric Reliability Corporation system performance standards. Electricity storage promises to be a useful tool to provide environmentally benign additional ancillary service and ramping capability to make renewable integration easier. However, while this report concludes that the system flexibility provided by storage is more efficient than equivalent conventional generation capacity, it has not performed a comparative cost‐benefit analysis either in terms of fixed capital or variable costs.

The California ISO control area as simulated would require between 3,000 and 5,000 MW of regulation and energy for balancing and ramping services from fast resources (hydroelectric generators and combustion turbines) for the scenario of 33% renewable penetration scenario in 2020, absent other measures to address renewable ramping characteristics (See Table 1). The range reflects the different seasonal patterns in the days studied, as well as the mix of fast storage (capable of 10MW/second ramping) versus fast new and upgraded conventional units (combustion turbine and hydro expected as of 2020). The large ramping requirement is driven by the combination of solar generation and wind generation variability that is forecasted for the 33% scenario. Included within this variability is the steep, yet highly predictable, production curve associated with solar resources as the sun comes up in the morning and sets in the evening. 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 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 potential solution.

Finally, altering or controlling the ramp rate of wind and solar resources for known ramping events such as sunrise and sunset can reduce regulation, balancing, and ramping requirements, but at the cost of curtailing renewable output.

 

The moment‐by‐moment volatility of renewable resources may need up to twice the amount of automatic generation control or regulation compared to todayʹs levels in the 20 percent scenario and somewhat more in the 33%. This is consistent with prior studies and manageable based on simulations using existing and anticipated sources of supply.

Generation ramping requirements to meet the morning load increase and the evening load decrease, as well as potentially other large changes in net load during the day, require large changes to generation dispatch in very short periods and may be the major operational challenge to ensuring reliability under a 33% renewable scenario.

Under the 33% renewable scenario, these ramps will be difficult to manage in the current paradigm of regulation and balancing energy/real‐time dispatch, where automatic generation control and real‐time energy dispatch must be used to counteract large renewable ramping behavior and scheduling / forecast errors. There should be an investigation into new protocols for renewable ramping and provide incentives for incentivizing the needed flexibility to reduce its effects would appear to be in order.

Fast storage (capable of at least 5 MW/second if not up to 10 MW/second in aggregate) is more effective than generally slower conventional generation in meeting the need for regulation and ramping capability

Use of storage avoids greenhouse gas emissions increases associated with committing combustion turbines strictly for regulation, balancing, and ramping duty.

A 30‐to‐50 MW storage device is as effective or more effective as a 100 MW combustion turbine used for regulation purposes, given the use of the storage‐specific control algorithms as mentioned in (4) above, the faster response of the storage as compared to a gas turbine,

Table 1 summarizes the quantitative benefits of using storage to address minute‐to‐minute volatility

this analysis recommends at least 400 MW or more additional regulation (but not balancing energy) for the 20 percent Renewables Portfolio Standard scenario while the California ISO report recommends 250 to 500 MW more depending on the season.

Possible imposition of requirements on renewable resources to accommodate their effects on grid operation, such as ramp rate limits on renewable resources, more accurate short‐term forecasting, sub‐hourly scheduling, and other possibilities.

Should electricity storage be directly linked to renewable installations or be procured by the California ISO as an ancillary service on behalf of the system as a whole? Whether renewable developers are required to provide or procure storage capabilities or the California ISO is required to procure it on behalf of the system as a whole will affect the stateʹs generation resource planning. The location of the storage (at the renewable resourceʹs location or elsewhere) will affect the planning of future power transmission lines as well.

 

The prospective benefits to California from the development of fast electricity storage resources for use in system regulation, balancing, and renewable ramping mitigation are significant. Specific benefits of fast electricity storage include:

• Management of large renewable energy ramping and management of increased minute‐ to‐minute volatility without degrading system performance and risking interconnection reliability.
• Reduced procurement of very large amounts of regulation, balancing, and reserves from conventional generators, which may be either very expensive or infeasible.

Avoidance of keeping combustion turbines on at minimum or midpoint power levels to support regulation and load following.

o Avoids increased greenhouse gas emissions.

o Avoids higher energy costs due to combustion turbine energy displacing lower cost combined‐cycle gas turbines and/or hydroelectric energy.

Can the California ISO system withstand a disturbance control standard event with 20 percent and 33 percent renewable resources, assuming that they displace existing thermal resources?

• What is the storage equivalent of a 100 MW combustion turbine (CT)?

These values were provided to the research team by the California ISO, based on projects currently in the interconnection queue which would realize the 20 to 33 percent renewable portfolio standard level. Between 2009 and the high case for 2020, wind generation nameplate capacity increases by over fourfold.19 Concentrated solar generation increases by a factor of 25 over the same time period. Table 3. Generation Capacity by Type (MW)

Under typical circumstances the California ISO’s frequency regulation needs are achieved today by having about a dozen generators on AGC control in order to meet its WECC/NERC frequency performance obligations. However, under high renewable scenarios, the number of units needed on AGC may need to be many times greater. In addition to AGC service, the California ISO also operates a balancing energy market to respond to deviations between the scheduled and actual level of generation output on an hour‐to‐hour basis in real‐time operation. Although balancing energy responds at a slower rate than AGC, the operation of both of these markets overlap significantly, and they both impact the California ISO’s overall frequency and ACE performance. Therefore, both AGC and balancing energy needs are examined in this study.

 

The 2020 High scenario required very large amounts of regulation. Consequently, in order to ensure that units with higher ramp rates were available to provide sufficient regulation, some additional cases were run where all the CTs and hydro units remained on at 20 percent minimum so as to have the required regulation bandwidth available. (Otherwise regulation duty would fall on CCGT and other slower units, degrading performance).

The goal of this task was to define storage facility scenarios above and beyond the existing pumped storage facilities that exist in California (e.g., Helms and Castaic plants). The researchers began by using an infinite storage capacity model in order to see how much would be used by the system for each of the modeled days in 2012 and 2020. For this purpose infinite storage was defined as 10,000 MW with a 12‐hour discharge duration. The amount of power used from this stored energy source used by the model in 2012 and 2020 provides an indication of how much storage power capacity is required in various RPS and AGC scenarios. The energy used (charging or discharging) during major ramping periods is an indication of the energy needed.

An inability to withstand deep discharge cycles means, in effect, that additional capacity needs to be installed in order to provide effective capacity. Thus, if a technology were deployed that were limited to 50 percent discharge, it would be necessary to provide twice the capacity of a technology of one that had no such limit. Thus, a storage system with a 50 percent limit would in effect need 12,000 MWh of storage where the study had determined that a 3,000 MW, 2‐hour unit was required.

The United States Congress is considering legislation to establish tax incentives for large‐scale electricity storage

Table 4. Outcomes summary Year / Renewable Scenario Current 20% RPS 33% RPS Low Estimate 33% RPS High Estimate

Determining Levels of Storage Required to Accommodate Renewables (Infinite Storage Approach)

Cases studied with storage levels of 10,000 MW and 12 hr duration Maximum ACE > 3000 MW in 2020 3200 – 4800 MW Required variously Some improvement via altered scheduling Results varied numerically but were qualitatively consistent 3,000 MW of storage was “sweet spot” except in April

For all study days, researchers observed increasing degradation of ACE as the share of renewables increased in the generation portfolio. ACE performance was severely degraded in all of the 2012 and 2020 cases, with maximum ACE levels more than doubling and tripling the 2009 levels as shown in Figure 20. With an AGC bandwidth of 400 MW and no storage additions, the maximum observed ACE variation within one day was ‐600 MW to +1,100 MW for July 2012, and ‐1,900 MW to over +3,000 MW for July 2020 High. These results were obtained with all conventional units (CT, hydro, and CCGT) on regulation. The CCGT units are actually much slower than the others and are normally not in regulation.

 

As illustrated in Figure 21, frequency deviation is fairly unchanged across scenarios, varying up to around 0.06 Hz. This is because the bias of the WECC system is such that it takes a very large imbalance to generate a 0.1 Hz deviation.

The predominant cause of ACE degradation in future years is the ramping of wind down and solar up in the mornings, and vice versa in the evenings. Variability of renewable production in the high renewables cases of 2020 cause additional ACE movement. Wind production decreases in the morning roughly an hour before solar production increases, depending on the day of the year. As such, there is a large drop in wind production in the morning, followed by a rapid pick up of solar an hour later. This occurs just as load is ramping up. The reverse occurs at the end of the day. Commitment of the combustion turbines and combined‐cycle turbines as needed to accommodate the renewable generation greatly restricts the ramping ability of the remaining conventional generation.

Droop adjustments have little impact on system performance because the ramp rates required to make up for sudden changes in renewable production are beyond what conventional generation can provide. Note that this does not mean that droop should be revisited for conditions where the amount of conventional generation on line is greatly reduced and insufficient system droop is available for a large unit trip. However, the conventional unit droop is sufficient today for evening conditions and light load in the event of a nuclear plant trip and can be reasonably expected to be so in the future.

The amount of regulation required for AGC to maintain ACE within todayʹs limits was 800 MW in 2012, roughly double today’s amount, and 3,200 to 4,800 MW in the 2020 High renewables scenarios, roughly 8 to 12 times today’s amount. Infinite storage at first failed to adequately control ACE as expected, using the output of the conventional AGC system. When large‐scale storage was configured as a resource similar to conventional generation, providing regulation services results were suboptimal. Using a fast and very large storage system resulted in excellent ACE performance in all scenarios once the storage control algorithms were developed, as described in the following section.

The ability of AGC to control renewables volatility and ramping using todayʹs controls and protocols was evaluated. Researchers found that the amount of regulation required for AGC to maintain ACE within todayʹs limits was 3,200 to 4,800 MW in the2020 High renewables scenario. This was not because of momentary volatility; lesser increases are needed for that. Rather, such amounts were required to address diurnal ramping, especially that of the centralizing thermal solar production.

Analysis of the 2020 High scenario for the July day show that 3,200 MW of regulation is needed to accommodate the renewable evening ramping. Still more is required to maintain ACE at nominal levels. Researchers found that April 2020 would require in excess of 4, 000 MW of regulation. Even then, the performance is marginal.

The researchers and the California ISO observed that procuring this much regulation from conventional units when renewable production was quite high posed problems in and of itself. Renewable production in these scenarios peaks at 10,000 MW or more, well in excess of 20 percent of generation required. If the conventional units are scheduled strictly on an economic basis, the CTs will be the first units to be displaced by the renewables. Hydroelectric and nuclear generation will generally be the last to be displaced. CTs normally provide a significant amount of the regulation capacity in the system. CCT units generally have much lower maximum ramp rates and cannot provide the same regulation service as combustion turbines. As noted above, the generation schedules were constrained to maintain combustion turbines on during the day and available for regulation service so that these very high levels of regulation could be realistically provided. Aside from the ramping phenomena, the renewables cause increased volatility during normal operation. This was observed to result in increased ACE and degraded performance, but nearly to the same degree as the ramping phenomena. Accordingly, it was investigated how much additional regulation would be required to maintain system performance during the hours 10 AM to 6 PM – i.e., between ramps. The results of this are shown in Table 5. It can be seen that if ACE maximum should be maintained below 500 MW and CPS1 above 180, for example, increased regulation will be needed in 2012 and 2020. As a general observation, it seems that in 2012 800 MW or more is required and in 2020 as much as 1,600 MW. Hey, it looks to me like 3200 MW:

 

When large‐scale storage was configured as a resource similar to conventional generation providing regulation services results were suboptimal. The conventional AGC had primarily proportional control with limited integral gains in the control algorithm. This is because in the California ISO area, the AGC is not the primary mechanism for following ramping; the real time dispatch is. As a result, the AGC typically has to deal with relatively small fluctuations (at 400 MW of regulation procured, the California ISO AGC regulation bandwidth is 1 to 2 percent of system load or less). A ramp of 20 to 25 percent greatly exceeds AGC ability to respond.

The conventional generators overall are slower than the storage and would not be stable with as aggressive an integral gain as the storage system will be. Also, the amounts of storage employed versus conventional generation will be different.

3.6. Requirements for Storage Characteristics The key parameters for system storage are the power level, the duration or energy capacity, and the rate limit on changes to power output.

It was determined that the California ISO control area has maximum benefit from (a) 3,000 MW of storage power capacity with at least (b) a two‐hour duration and that the (c) ramping capabilities have to be 10 MW/second or greater. The 10 MW/second requirement translates to achieving 3,000 MW of output from zero in five minutes. Thus, if there is 3,000 MW of storage with a 5 MW/minute ramp capability (and a 2 hour duration) it would seem that there is a need for faster storage capable of making up the 1,500 MW deficiency that accrues at the end of five minutes – so that 1,500 MW of 10 MW/second storage is required, but with less duration. (Much less; it would need to produce a ramp down over the next five minutes; so that the total energy would be 125 MW hours; e.g. the duration is 125 MWh/1,500 MW or 5 minutes. A similar set of mathematics can be performed for any combinations of technologies with differing rate limits. This implies that a lower capacity cost technology such as CAES can be combined with high performance and higher cost technology such as Li‐Ion batteries or super‐capacitors.

The rate limit performance of the storage system overall is a critical parameter. As noted above, researchers assessed system performance for differing rate limits on the storage. The storage system must have an aggregate rate limit of at least 5 MW/second for a 3,000 MW aggregate system, and 10 MW/second is preferable. (10 MW/second out of 3,000 MW equates to 0.33 percent/second or 20 percent/minute in general).

A key policy question in developing a portfolio of renewable integration solutions is, how does equivalent storage compare to an investment in a new gas turbine for the same service? Storage is more expensive per MW provided, and it has a limited amount of energy it can supply to the system.

A gas turbine, on the other hand, can continuously inject energy to system as long as it has a fuel supply.

 

To help assess the question of whether a gas turbine provides more benefits for less money, researchers determined the rough equivalency of storage by examining the incremental impact of a single additional 100 MW CT. In particular, researchers evaluated the system performance impact of 100 MW of incremental CT dedicated to regulation and load following and compared that with the incremental impact of storage systems of different sizes.

Then one CT with a capacity of 110 MW with 50 percent of capacity allocated to regulation was added to the mix. This CT had a very high rate limit – 120 percent of capacity in 5 minutes. (The large CT units (over 500 MW) are significantly slower. The very small units are this fast or faster).

Then, instead of the CT, storage units of 50 and 100 MW were added to the model, and the test cases were repeated. Again, this was run twice. As expected, the 50 MW storage unit produced benefits similar to the CT in some cases and varied in others. The 100 MW unit exceeded the metrics improvement of the CT by far.

3.8. Issues With Incorporating Large Scale Storage in California

The results of this report indicate that renewable ramping creates volatility in the system and that storage has the technical potential to help address this volatility. However, key policy questions are how to best promote various ramping solutions and how to account for tradeoffs among them. Imposing ramping limits on renewable resources as an interconnection requirement would address volatility and leave open the question of which solution to use (storage, combustion turbine, or other means). Resource ramping limits are feasible for the ramp up phenomena (at some lost energy production), but not for the ramp down, which is technically difficult (requires storage in some form either at the resource or at the system level).

However, compared to other solutions, storage appears to have benefits and may be preferred in some instances. Without storage, CT ramping would need to increase. This has three basic impacts: • Increased maintenance costs and reduced lifetime from additional wear and tear • Postponed de‐commitment of CT units • Increased GHG emissions

Storage could absorb the volatility and limit CT ramping, diminishing these adverse impacts. Though storage units are more expensive than CTs, the avoided emissions and wear and tear may make the incremental cost worthwhile. Additional research needed to assess additional CT maintenance costs and to value emissions reductions. Figure 42 and Figure 43 show the benefits storage has for both CT and hydro generators in terms of reduced ramping in response to renewables. As the amount of storage increases, the amount of unit ramping decreases.

Excessive ramping up and down of hydro units has environmental implications for downstream water levels and may even by impractical in extreme cases.

 

The acquisition of regulation and ramping services from storage in the amounts identified will be a significant cost to the system. How these costs will be allocated – either to the entire market as an ancillary service or to renewable resources in effect by imposition of ramping rate limits has profound economic implications for renewable developers and the future economic viability of renewable resources.

Conclusions and Recommendations

There are five major conclusions from this research work:

1. 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.
2. 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.
3. The ramping requirements twice a day or more require much more response and will be the major operational challenge.
4. 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.
5. 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.

The accommodation of 33% renewable generation resources is the goal established by the Governor for the state. To achieve this goal will require major alterations in system scheduling and operations under current paradigms, which will be costly in terms of energy costs and GHG emissions. The use of storage in conjunction with new control and ramping strategies offers a way to avoid these costs and provide current levels of system reliability and performance at lower risk. While it is yet to be investigated, storage also promises to be a useful tool in making use of DR as an additional ancillary service provider to facilitate renewable integration.

The 3,000 to 4,000 MW of storage which could be used to address renewables management requires a ramp rate capacity of 5 to 10 MW/second, or 0 to full power charging / discharging in 5 minutes. This equals or exceeds the ramping capabilities of most conventional generating units, and particularly the larger combustion turbines. Smaller combustion turbines in the California ISO database can meet this ramp rate requirement, but there are insufficient quantities of such units to provide the required 3,000 to 4,000 MW of fast ramping. Hydroelectric units are capable of changing output levels at these rates. However, it is unclear if the hydroelectric units have sufficient range available for regulation at these levels without having to operate in hydraulic forbidden zones. The hydro units also have very limited amount of water available in the fall and winter months, so they are not available as a regulation resource during a number of months.

A duration of two hours for the storage systems was found to be sufficient for the regulation, ramping and load following applications. The measurement of the relative effectiveness of storage to a combustion turbine demonstrates that, depending upon system conditions and other factors, a 30 to 50 MW storage device is as effective as a 100 MW CT used for regulation and ramping purposes. This is an incremental figure measured across a range of system scenarios; that relative performance figure of merit would not obtain across the entire range of regulation resources0 – 5,000 MW of course.

The acquisition of regulation and ramping services from storage in the amounts identified will be a significant cost to the system. How these costs will be allocated – either to the entire market as an ancillary service, or to renewable resources in effect by imposition of ramping rate limits, has profound economic implications for renewable developers and the future economic viability of the renewable resources.

The development of the ancillary service protocols for storage will definitely affect the R&D and engineering directions taken by the grid storage industry and need to be validated and made known as soon as practical. For instance, the two‐hour duration requirement is a significant parameter that will affect which storage technologies are in play or not. Similarly, the ramp rate requirements for grid storage in this application will have implications for the technologies developed and deployed. A careful study of the implications of acquiring very large amounts of regulation / reserves / load following via the market is in order.

The California ISO is considering changes to the market and the energy management system to integrate several hundred MWs of limited energy storage resources such as flywheels and batteries in the regulation market. These devices typically have very fast response rates and can switch between charge and discharge modes within 1 second. They also have very limited amount of energy storage capability, typically 15 minutes of energy, and therefore require constant monitoring to ensure they can continue to provide their full regulation range and are energy‐neutral over a 10 to 15 minute period.

The study was optimistic in one critical way – the impact of large forecast errors for renewable production, especially forecast errors associated with wind production, was not studied. The wind forecast errors assumed in the scheduling and dispatch were as actually observed on the studied days in 2008‐2009 and were not significant. Addressing larger wind power forecast error problems will further emphasize the benefits of storage as compared to conventional generation used for regulation as these units would have to be kept on for longer periods in order to provide against forecast error.

Note that the system has to be able to withstand the expected worst case scenario for coincident ramping seasonally –it cannot be designed and operated for averages if there are significant probabilities of reliability‐threatening coincident ramping. Literally hundreds of second‐by‐second simulation of the California power system were performed for each of the four days and four renewable scenarios developed. These simulations produced the conclusions and results described above. The conclusions and recommended control algorithms and dispatch protocols need to be validated across a much larger sample of days than the four seasonal typical weekdays chosen.

Finally, the study scope did not include examination of the costs of either greatly increasing procurement of ancillary services or of deploying large amounts of grid connected storage.

As indicated by this study, procurement of very large amounts of regulation and reserves from conventional units may cause market distortions. If so, new market and regulatory protocols may be required.

• What incentives at the federal or state level are indicated to support storage resource development? And how should these be linked to renewable facilitation? It seems that storage should meet the technical performance characteristics identified in this report as validated and amended by the California ISO in order to qualify. The state may wish to communicate this concept to the U.S. Congress which is contemplating investment tax credits for storage.

Third, the Energy Commission should fund additional research on new energy storage technologies that can be integrated with large concentrated solar and PV installations. The goal is to reduce the variability of the solar energy production and to reduce the rapid and large ramp ups in the morning and ramp downs at sunset. Existing molten salt thermal storage is both expensive and operationally challenging. New technologies are needed now before the large solar plants are all designed and built.

Specific benefits of fast storage include: • Management of large renewable ramping as well as increased minute to minute volatility without degrading system performance and risking interconnection reliability. • Management of renewable volatility and ramping without having to procure very large amounts of regulation and reserves, which may be either very expensive or infeasible. • Reduced breakage and maintenance of the thermal and hydro generation fleet as they will be subject to less volatility and stress as the energy storage resources will absorb a lot of the rapid changes in energy production. • Avoidance of keeping combustion turbines on at minimum or midpoint power levels to support regulation and load following. o Avoids increased GHG emissions. o Avoids higher energy costs due to combustion turbine energy displacing lower cost CCGT and/or hydroelectric energy.

7.0 Glossary ACE Area Control Error AGC Automatic Generation Control CAES Compressed Air Energy Storage California ISO California Independent System Operator CCGT Combined‐cycle gas turbine CPS Control Performance Standard CPUC California Public Utilities Commission CS Concentrated solar CT Combustion turbine EAP I Energy Action Plan I EAP II Energy Action Plan II Energy Commission California Energy Commission GW gigawatt GWh gigawatt‐hour IOU investor‐owned utility kW kilowatt kWh kilowatt‐hour MRTU Market Redesign and Technology Upgrade MW megawatt MWh megawatt‐hour PIER Public Interest Energy Research NERC North American Electric Reliability Corporation T&D transmission and distribution VAR volt‐ampere reactive WECC Western Electricity Coordinating Council