Emergency Response. U.S. System Frequency with High Wind Penetration. By Nicholas Miller, Clyde Loutan, Miaolei Shao, and Kara Clark

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1 Emergency Response The reliable operation of a power system depends on maintaining frequency within predetermined limits around the nominal operating frequency (60 Hertz in North America). A fundamental aspect of operating an electric power grid reliably is that the amount of power produced at any given instant must match almost exactly the amount of power being consumed. If extra power is produced, the frequency will tend to increase. If less power is produced, the frequency will tend to decrease. The frequency of the interconnected grid is mostly controlled by adjusting the output of generators in order to maintain a balance between generation and load. This balancing and frequency control occur over a continuum of time, using different resources that fall into the categories of primary, secondary, or tertiary controls. Digital Object Identifier /MPE Date of publication: 18 October 2013 U.S. System Frequency with High Wind Penetration Image licensed by ingram publishing By Nicholas Miller, Clyde Loutan, Miaolei Shao, and Kara Clark november/december /13/$ IEEE ieee power & energy magazine 63

2 Primary frequency control, or frequency response, depends on the rapid, autonomous action of resources, particularly generation, in response to significant changes in system frequency. Primary frequency control, or frequency response, depends on the rapid, autonomous action of resources, particularly generation, in response to significant changes in system frequency. Inherent inertial behavior and then primary frequency control actions are the first lines of defense for the system to avoid involuntary interruption of service to customers, which can occur within a few seconds following a system disturbance. Secondary frequency control is the fastest centralized control in the system. Secondary control actions are usually due to automatic generation control (AGC) instructions that are issued through a balancing authority s energy management system (EMS). They start within tens of seconds and dominate system response for the first several minutes following a disturbance. Tertiary control encompasses dispatch actions taken by the system operator to get resources in place to handle current and future contingencies. Reserve deployment and reserve restoration following a disturbance are common types of tertiary control. In the first few seconds following the loss of a large generating plant, the frequency dynamics of the system are dominated by the inertial response of the online generation. Synchronous machines inherently contribute some of their stored inertial energy to the grid, reducing the initial rate of frequency decline. In synchronous machines, the inertial response is inherent to the machine physics and is not controllable. Slower initial rate of frequency decline can be helpful, allowing slower governor actions to nonetheless stabilize grid frequency. In some smaller systems, the initial rate of frequency decline is quite important. This does not appear to be as much of a concern in the major U.S. interconnections. There is widespread and growing concern in North America about system response to underfrequency events. The North American Electric Reliability Corporation (NERC) has led a frequency response initiative. Its report, issued on 30 October 2012, examines the trends in and causes of the deteriorating frequency response that has been observed over the past two decades. It provides the rationale for establishing the responsibilities for maintaining adequate frequency performance laid out in a new standard on frequency response and bias that has recently (29 March 2013) been submitted as a petition to the Federal Energy Regulatory Commission (FERC) for approval. In 2010, FERC sponsored work by the Lawrence Berkeley National Lab (LBNL) that identified metrics useful in planning and operations of a system with large amounts of variable generation. One focus is the concern that the addition of substantial amounts of wind power may exacerbate the observed decline in frequency response. Wind Plant Frequency Response Today There is a fundamental difference between a wind turbine and the turbines supplying motive power to the majority of the world s traditional power plants, be they gas, steam, or hydro turbines. With traditional turbines, the rotational speed is nearly constant and locked to system frequency. The speed of a wind turbine, however, is not synchronous with the grid and is controlled so as to maximize active power production. Wind turbine power production is therefore not inherently coupled to the system frequency and does not provide inertial or governor response unless specifically controlled to do so. Historically, wind plants have usually not been required to participate in frequency regulation. With higher levels of wind and solar penetration, system operation changes. Thermal units may be decommitted as their output is displaced by lower-marginal-cost wind generation, or they may be dispatched to lower power levels. It can happen that the units most economical to displace also have the most desirable governor response. This leaves other resources running that do not provide the same governor characteristics. The remaining thermal units are also more frequently operated at a lower power output. This change in system operations is the primary reason for concerns that wind generation may exacerbate existing frequency performance challenges. The Incumbent Generators The frequency response of systems is dominated by the amount and type of generation committed and how it is dispatched. For performance investigations, it is useful to distinguish generators in accordance with how they respond to frequency excursions. Governor-responsive units have speed governors with a droop characteristic and some available headroom (see Governor Basics ). These plants increase power output to support the grid when frequency declines. Other generation does not. This includes some generation that is operated so that it cannot increase output for frequency decline but can decrease output for overfrequency conditions. In the Western Interconnection, these are referred to as base load units. Other generators may either lack governors or be operated with their governors disabled. 64 ieee power & energy magazine november/december 2013

3 Governor Basics Most synchronous generators have a speed governor that, when enabled, helps maintain system frequency. The speed of a synchronous machine is a good proxy for system frequency. In steady state, the speed is always an integer multiple of grid frequency nominally 60 Hz in North America. The blue line in Figure S1 shows a representative governor characteristic. As frequency drops (moving left from nominal in the figure), once the deadband is exceeded, the generator output will increase along the droop line. The steepness of the line the droop is usually set so that a 1% drop in speed (i.e., 0.6 Hz) will result in a 20% increase in power output. The increase in power is limited by the physical limits of the generation: this is the headroom. Therefore, for a unit to usefully contribute to primary frequency response, the governor must be enabled and there must be some headroom. Plant Power Headroom System Short of Generation Plant Power Maximum = Rating for Synchronous Plants = Available for Wind Plants Deadband Plant Power Dispatch = Actual Production Droop System Needs Power 100% (Normal Frequency) Speed (for Synchronous Machines) Frequency (for Wind Plants) figure S1. A representative governor characteristic. The ratio of generation that provides governor response to all generation running on the system is a useful metric used to quantify overall system readiness to provide frequency response. There are a number of physical and economic reasons why many power plants, particularly thermal plants, operate without underfrequency governor response. For example, steam plants are more efficient when operated with valves wide open, in so-called boiler follow mode. Nuclear plants in the United States are not permitted to have underfrequency response. The net result is that it is common in the major U.S. interconnections for only about one-third of generation operating at any given time to provide governor response. This means that careful attention must be given during operation to this important subset of synchronized generation. Two New Investigations of Frequency Response In this article, we present certain key findings of two new investigations of frequency response in the U.S. Western and Eastern interconnections. The work on the Western Interconnection (WI) system was done with California Independent System Operator (CAISO), with a focus on the performance of California. The Eastern Interconnection (EI) work was sponsored by the U.S. Department of Energy (DOE) Office of Electricity Delivery and Energy Reliability and managed by the National Renewable Energy Lab (NREL). The goals of both studies were to illustrate overall system frequency response, investigate the possible impact of large amounts of wind generation, and examine means to improve frequency response with the use of active power controls on wind plants. California This study was specifically designed to investigate the frequency response of California due to large loss-ofgeneration events of the type targeted by NERC Standard BAL b, Frequency Response and Bias, under system conditions with high levels of wind and solar generation, as envisioned in the near future. It addressed the overall frequency response of the Western grid, without considering any changes to the limits of stability-limited transmission paths that may be warranted at higher penetrations of variable energy resources. For this work, CAISO created a number of credible load flow and stability base cases that represent the high penetrations of wind and solar generation expected in California in the near future. These cases were deliberately selected with the expectation that they would represent some of the most challenging conditions for CAISO with respect to frequency response. A weekend morning, high-wind and high-solar condition case represents an operating condition with a large number of synchronous generators displaced by variable renewable energy resources. In addition, some of the thermal power plants with synchronous generators were also assumed to have been retired due to oncethrough-cooling (OTC) regulation. At the snapshot of time represented here, the total WI load is 111 GW. The fraction of California generation coming from wind plants is 28% (8.6 GW total). With an additional 6.7 GW of solar generation included, California s total variable renewable generation reaches 50% (14.3 GW total). Most of the simulations focused on the trip of two units at the Palo Verde Nuclear Power Station. This 2,690-MW event is recognized by NERC as the largest loss-of-generation event in the Western november/december 2013 ieee power & energy magazine 65

4 Frequency (Hz) A 59.8 B B f 59.7 C f C C t figure 1. Frequency response to loss of generation (for the base case). Interconnection for which involuntary load shedding and other stability consequences must be avoided. Figure 1 shows the frequency response of the Western Interconnection to the Palo Verde generation tripping event imposed at 1 s for the base case. Measuring the frequency at a specific single node in the grid following a disturbance can be confusing and misleading. Here, an equivalent frequency based on the weighted speed of all the synchronous machines in the system is used. It filters out the local swings and can be regarded analytically as the common mode of the system. The frequency nadir (point C) occurs at about 10 s at a frequency of 59.7 Hz, and the settling frequency (point B) is 59.8 Hz. (For an explanation of these terms, see Table 1.) Figure 2 shows the electrical and mechanical power output of the synchronous machines with enabled governors. By the time of frequency nadir (point Cp), the units on governor control are delivering about an extra 2,000 MW, and by 60 s, the interarea transients have settled out, frequency is largely uniform everywhere, and generator electrical and mechanical power are essentially equal. The change in generation by governor-responsive units represents the vast majority of system response and is nearly equal to the lost generation Starting frequency Frequency nadir Settling frequency table 1. Frequency terminology. This is the system frequency before an upset; it is close to (but rarely exactly) 60 Hz. This is the lowest frequency seen following an upset. It is usually expected to occur within several seconds of a big generation trip. It ought to stay comfortably above underfrequency load-shedding (UFLS) levels, i.e., 59.5 Hz in most of the United States. This is the frequency observed after the big swings are over and the primary frequency controls have acted but before secondary controls become significant. It ought to occur well before 1 min after a big event. (2,690 MW) after 60 s. The frequency nadir gives some margin above the first stage of underfrequency load shedding (UFLS) at 59.5 Hz. A Higher-Wind Case For the base case, the level of wind generation outside of California was relatively low, especially compared with the levels within California. In order to test conditions under which the rest of the WI is also host to significant amounts of wind generation, a higher-renewable-penetration case was developed. The change in commitment and dispatch of the synchronous generation as wind comes in is critical. In this case, changes were based on trends observed in the detailed economic evaluation of the Western Wind and Solar Integration Study (WWSIS). For every 3 MW of additional wind production, there is about 2 MW of reduction in thermal unit commitment and a 1 MW reduction in thermal unit dispatch. The committed thermal units that have the least annual operating time in the WWSIS study were selected to be displaced by wind turbine generators. Initially, the newly added wind turbine generators were assumed to have typical, nonfrequency-responsive controls and were also assumed to be operating at 50% of rated capacity, in order to capture the operational reality that all wind plants in a system are never operating simultaneously at rated power. This assumption for the incremental plants gives a reasonable, if somewhat simple, distribution of loadings on the wind plants in WECC. Thus in this case, 9,508 MW of wind turbines were added to achieve an increased net wind dispatch of 4,754 MW. Coming up Short: Reduced Headroom The system conditions in the higher-renewable-penetration case were further modified to reflect an operating condition with a reduced fraction of generation providing governor response and with those units having reduced headroom. In this case, the overall system headroom was reduced to about 8 GW. The system was deliberately stressed so as to consider the practical minimum headroom. It is worth noting that the condition from which this case was developed was already considered to be challenging and representative of a realistic commitment and dispatch for high wind and solar conditions. This case was designed to push headroom down to levels that we believe might occur relatively infrequently, i.e., when the system is meeting just its minimum operating reserve obligation plus regulation needs. In the most extreme case analyzed, the headroom was further reduced to 3 GW. This was essentially equal to the outage event size. The case was designed as a test and is not necessarily representative of a condition that is either practical or one that the system operator would regard as acceptable. Rather, we were looking to understand what might happen and establish a case for which remediation of extreme conditions might be tested. It is worth reemphasizing that this condition corresponds to about 20 GW of instantaneous production of wind and solar in the WI. Since one postulated cause 66 ieee power & energy magazine november/december 2013

5 Electrical and Mechanical Power (MW) 38,000 37,500 37,000 36,500 36,000 35,500 35,000 C p Electrical Power (MW) Mechanical Power (MW) 0 C t of instantaneous operation at such acutely reduced headroom is from an unexpected drop in wind or solar production, one could reasonably suppose that this case is representative of a future condition in which much more than the 25 GW of nameplate rating of wind plus solar of this case is operating in the WI. The loss of 5 GW of headroom thus represents a drop of roughly 20% of the total generation. The statistical expectation of such an extreme drop is small. A final important point B p figure 2. Base case electrical and mechanical power response. Frequency (Hz) Base Case Higher Renewable Penetration Case Practical Minimum Headroom Extreme Minimum Headroom figure 3. Frequency response to loss of generation. for this particular case is that the UFLS was disabled to allow the comparison of frequency response with other cases without the complexity of considering UFLS effects. The frequency response for the three higher-renewable-penetration and reduced-headroom cases is shown in Figure 3. The red trace shows the response for the higher-renewable-penetration case; the green trace shows the response for the higher-renewable-penetration and New System Tools: Active Power Control from Wind Plants Since wind generation tends to displace thermal generation, under some conditions the system would benefit from the frequency-sensitive response of wind plants to 1) overfrequency events caused by load rejections, since thermal plants are less likely to have substantial down-regulation capability, and 2) underfrequency events caused by generation trips. Some wind plants with modern turbines and plant controls have the ability to control active power output in response to grid frequency. A number of grid operators around the world have started requiring that wind plants have these controls. Inertial Controls Most modern MW-class wind generation does not inherently exhibit inertial response. It is possible, however, to program the wind plant controls to provide a form of inertial response. For large underfrequency events, the inertial control feature temporarily increases the power output of the wind turbine by about 5 10% of rated power for several seconds. Below rated wind, stored kinetic energy from the turbine-generator rotor is temporarily donated to the grid but is recovered later. This inertial response is not quite energy-neutral, meaning that the period of increased power is followed by a longer period of decreased power. Governorlike Controls It is also possible to implement wind plant controls that provide something similar to governor response. Some active power controls that are commercially available are closely akin to governor controls for thermal and hydro generation. They respond to significant deviations in grid frequency, increasing or decreasing power output in response to low- or high-frequency events, respectively. To do this, the control alters the active power control reference targeted by the turbine controls. In order to allow for an increase of wind plant active power output in response to an underfrequency condition, some active power production must be kept in reserve this is the headroom shown in the governor figure. The maximum power production of the wind plant is therefore constrained to a value less than that available from the wind. This results in unrecoverable loss of energy production (much like spilled water on hydro generation) and so has significant economic implications. (Alternatively, some energy could be stored in a different medium, such as a battery, for delivery at this critical time, but that is a discussion for a different article.) The potential for wind generation to respond quickly makes this resource effective in arresting and correcting frequency deviations, much as fast governor response does on thermal generation. november/december 2013 ieee power & energy magazine 67

6 Frequency (Hz) Type Three Wind Power (MW) Frequency (Hz) ,000 16,500 16,000 15,500 15,000 14,500 14, Extreme Minimum Headroom Case Extreme Minimum Headroom Case With Frequency Droop Extreme Minimum Headroom Case Extreme Minimum Headroom Case With Frequency Droop figure 5. Wind power response, with and without frequency droop function figure 4. Frequency response, with and without wind plant frequency droop function Frequency Power figure 6. Frequency and governor response of the EI, using the old model. Power (GW) practical-minimum-headroom case; and the black trace shows the higher-renewable-penetration and extreme-minimum-headroom case. In comparison, the response of the base case is plotted as the blue trace. Compared with the base case, the higher-renewablepenetration case has better frequency response. This is because the dispatch increased headroom when wind generation was added. This effect is nowhere near in proportion to the amount of wind generation added, yet it helps the system response. This case illustrates the possibility that normal economic operation of the system may result in improved system frequency performance as wind power levels increase. The initial rate of change of frequency (ROCOF) is essentially unchanged between the cases, indicating that the reduction in system inertia that accompanies displacement of some synchronous generation has little impact. For the higher renewable penetration and practical minimum headroom case, the frequency nadir is low and probably represents the lowest nadir that could be considered acceptable. For the extreme-minimum-headroom case, the frequency nadir would have impinged on the UFLS threshold an unacceptable result. The settling frequency is barely above the minimum to avoid UFLS. This is evidence that the performance is limited by the generators range of available response and static droop and not just the speed of response of the governors. These cases indicate that extremely depleted headroom will result in unacceptable system performance. The fraction of generation providing governor response, while important, is insufficient to anticipate frequency performance. Headroom needs to be considered at least when it is in short supply. Turning to Wind for Help Ultimately, wind plant controls can provide system operators with yet another tool to manage frequency (see New System Tools: Active Power Control from Wind Plants ). Under conditions of high stress that result in a shortage of headroom and generation providing governor response, wind generation may well be the least costly means of achieving the necessary primary frequency response. In another test scenario, we start with the extreme-minimumheadroom case (the dark blue trace in Figure 3). That case had unacceptable frequency performance, due to an insufficient supply of primary response. In the new case, about 41% of the wind generation is assumed to be operating slightly curtailed and with governorlike response enabled, using standard droop and deadbands. This adds 1,812 MW of headroom. A comparison of the cases is shown in Figure 4 for frequency response and in Figure 5 for the power output of those wind plants with the controls on. The performance of this case is dramatically better. This case shows that, if necessary, primary frequency response from wind generation 68 ieee power & energy magazine november/december 2013

7 As wind penetration increases, the potential participation or wind plants in frequency control becomes more important to the system. has the potential to greatly improve the system frequency performance of the entire grid. These cases do not include the inertial control that in general would be complementary to this control. Eastern Frequency Response Study A recently completed study of the EI investigated some of the same issues as the study of the WI, again focusing on the evaluation of frequency response and generation control with increasing wind penetration. While the studies were similar in focus, one particularly important difference required attention. Although there are efforts under way to improve matters, the dynamic representations of the EI that are in widespread use today are known to poorly reflect the interconnection s observed behavior. The main goals of this work were therefore to: create a realistic baseline model of the EI for examining frequency response illustrate overall system frequency response investigate the possible impact of large amounts of wind generation examine means of improving EI frequency response with the use of active power controls on wind plants. For this investigation, a light-load power flow case was again deliberately selected with the expectation that it would represent one of the more challenging conditions for the EI with respect to frequency response. At the snapshot of time represented in this case, the total EI load was 272 GW. Most of the simulations focused on the trip of multiple thermal plants in the region of Rockport, Indiana. This 4,455-MW event was patterned after the largest loss-of-generation event in the EI for which involuntary load shedding and other stability consequences must be avoided. Some Wrinkles in the Model A simulation of the loss of 4,455 MW of generation using this widely used model is shown in Figure 6. The blue trace shows the frequency dropping slightly and rapidly recovering. Over 200 GW of generation is shown in the red trace to rapidly and effectively respond. This is nice performance. Unfortunately, it does not resemble the observed behavior of the EI. This is mainly because the vast majority of synchronous generation in the dynamic model of the EI has active governors modeled. Thus, the fraction of generation with governor response is 78.9% for the EI in this case. This value is significantly higher than the 30 40% of recent U.S. industry experience. Based on a better understanding of thermal plant controls, the initial model was modified. Governors on plant types that typically do not have active governors were disabled. The fraction of generation with governor response was reduced to 32%. Further, plant controls representative of those that tend to override primary governor response creating governor withdrawal were added. These relatively common controls are intended to make certain that power plants adhere to their dispatch schedule. Governor action in response to frequency excursions drives machines away from their dispatch (see Governor Basics ). These controls return the plants to schedule, regardless of whether system frequency has returned to normal. The system response to the loss of 4,455 MW of generation for the new base case is shown in Figure 7. The blue trace shows the frequency of the EI. The frequency drops initially and stays generally depressed. This is the so-called lazy-l behavior that has been observed for actual largegeneration disturbances in the EI. This modified model was found to reasonably reproduce a large event that occurred on 13 May The red trace in Figure 7 shows the mechanical power output of the governor-responsive units. It presents quite a contrast to the red trace in Figure 6. To examine the possible impact of high levels of wind penetration on the EI, a test case was devised with new wind generation of approximately 85 GW rating, operating at a total of 68 GW production, added across all of the NERC regions except those of the Southeast Electric Reliability Corporation (SERC) and the Florida Reliability Coordinating Council (FRCC). This represents an instantaneous Frequency (Hz) Frequency Power figure 7. Frequency and governor response of the EI, using the new model. Power (GW) november/december 2013 ieee power & energy magazine 69

8 These studies showed that adjustments to the models can greatly improve model fidelity. penetration of about 40% for those regions and of 25% for the EI as a whole. As noted earlier, wind generation normally displaces thermal generation during operations. An initial high-wind case displaced governor-responsive thermal generation such that the fraction of generation providing frequency response was reduced to about 27%. That resulted in somewhat poorer frequency response. By modifying the Frequency (Hz) Power (GW) New Base Case High Wind Penetration with WTG Governor Response and Inertial Control Base figure 8. Frequency comparison: EI without wind versus high wind with governor and inertial response. High Wind Penetration Case High Wind Penetration with WTG Governor Response Case High Wind Penetration with WTG Governor Response and Inertial Control Case figure 9. Wind turbine generator power comparison: three different controls. case to bring the fraction of generation providing frequency response back to 32%, the frequency response was restored. Wind Plant Controls: Governor and Inertial Controls Combined To illustrate the potential benefits of frequency-sensitive wind plant control, most of the wind generation was again curtailed by 5% of the available wind power, and the governor like controls were enabled. This condition added a total of 3.4 GW of headroom. Unlike the WI case shown in figures 4 and 5, for this case inertial control on the wind turbines was enabled as well. The system frequency, as shown in Figure 8, is substantially better in the high-wind case with these controls as compared with the no-wind base case. The electrical power of all the wind turbines is shown in Figure 9. The green trace shows the combined response of the governor and inertial controls. To help understand the impact of the inertial control, the red trace shows only the contribution from the governor control. The energy associated with the inertial control is the area between the green and red curves. Notice that even though the inertial control is almost energy-neutral, it produces a performance benefit by delivering extra energy to the system earlier, as the frequency is declining. This can be a substantial benefit, if there is sufficient primary reserve on the system, as is the case here. Conclusions These investigations provide evidence that high levels of wind and solar generation can be well tolerated within the major U.S. interconnections with respect to system frequency response. The tendency for wind and solar generation to displace other synchronous thermal generation that may contribute to healthy frequency response needs to be considered during system operation. These findings reinforce the work of others who have found that the fraction of generators providing governor response at any given time is a critical operational metric. Minimum levels on the order of 25 35% of total online generation are needed at all times. This is true independent of wind generation. There is evidence that these minimum levels are occasionally reached today. The fact that roughly two out of three operating generators may not contribute to primary frequency response under normal operating conditions is an economic reality of operation. The headroom available for the fraction of generation that is contributing to primary frequency response can also be 70 ieee power & energy magazine november/december 2013

9 There is a fundamental difference between a wind turbine and the turbines supplying motive power to the majority of the world s traditional power plants. important under conditions of high stress. The system must maintain a minimum MW level of synchronized, responsive generation in order to provide adequate frequency performance. The speed of response of these reserves is important, since the frequency nadir following a major loss-of-generation event typically occurs within several seconds of the event. Contributions to primary frequency must be sustained until secondary frequency response, i.e., automatic generation control, asserts control typically, within the space of several minutes. The fact that many thermal plants have controls in place that quickly withdraw their primary response contributes to degraded frequency performance. The WI work showed a roughly 20% degradation in performance due to such controls. The modeling of primary frequency response, including the capture of key elements such as which generators are actually contributing, which generators have controls that withdraw primary response, and the contribution of load behavior, requires careful attention. In the EI, today s commonly used dynamic models capture observed frequency behavior poorly. These studies showed that adjustments to the models can greatly improve model fidelity. But more work should and is being done to improve the EI models. As wind penetration increases, the potential participation of wind plants in frequency control becomes more important to the system. These investigations show that frequencysensitive controls on wind plants can have a substantial beneficial impact on system performance. Inertial controls from wind generation provide fast transient support, via a controlled inertial response from wind turbines, that can significantly improve the system s frequency nadir. This is particularly the case if the frequency nadir is significantly lower than the settling frequency, which tends to be the case if the system has generators with adequate but slower control action. This means that these types of controls can reduce the need to worry about the speed of individual unit governor response. They do relatively little to correct a shortage in the amount of available response, however. Under normal conditions, these controls will add margin in avoiding UFLS. The participation of wind plants in providing primary frequency response, i.e., by exploiting plants with governorlike controls, will have significant beneficial impacts on both the frequency nadir and the settling frequency. This should prove valuable under conditions when the system is short of other resources. To provide this function, wind plants must be dispatched below available wind power, causing an opportunity cost equal to the value of the lost production. Like spilling water over a hydro dam, this can be expensive unless there is a means to be paid for providing this service to the grid. Since the controls can be quite fast relative to conventional thermal and hydro generation, the benefit is greater. Other types of generation, active load controls, and energy storage devices may all be able to provide comparable benefits. These investigations did not examine the operational practices or institutional mechanisms necessary to take advantage of the technical options identified, nor did they consider whether existing practice is sufficient to ensure adequate frequency response. The new NERC standards establish quantitative performance objectives. It is possible that new market mechanisms will be required to assure adequate frequency response. These should be structured to achieve economy of operations by allowing all qualifying resources, including variable renewable generation, to participate. These investigations, while extensive, are by no means exhaustive. Further experience and analysis will help steer practice as levels of wind generation increase. For Further Reading N. W. Miller, M. Shao, and S. Venkataraman, California ISO (CAISO) frequency response study, GE Energy, U.S. Department of Energy. (2013). Eastern frequency response study. [Online]. Available: purl/ / The reliability role of frequency response, NERC Frequency Response Initiative Report, NERC, Atlanta, GA, Oct. 30, J. H. Eto, J. Undrill, P. Mackin, R. Daschmans, B. Williams, B. Haney, R. Hunt, J. Ellis, H. Illian, C. Martinez, M. O Malley, K. Coughlin, and K. H. lacammare, Use of frequency response metrics to assess the planning and operating requirements for reliable integration of variable renewable generation, Lawrence Berkeley National Laboratory, Report LBNL-4142E, Dec Biographies Nicholas Miller is with GE Energy Consulting, Schenectady, New York. Clyde Loutan is a California Independent System Operator, Folsom, California. Miaolei Shao is with GE Energy Consulting, Schenectady, New York. Kara Clark is with the National Renewable Energy Laboratory, Golden, Colorado. p&e november/december 2013 ieee power & energy magazine 71