NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Concentrating Solar Power 

Impact on Grid Reliability 

Nicholas W. Miller and Slobodan Pajic

GE Energy Consulting

Kara Clark 

National Renewable Energy Laboratory 

Technical Report

NREL/TP-5D00-70781

August 2018
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Concentrating Solar Power 

Impact on Grid Reliability

Nicholas W. Miller and Slobodan Pajic

GE Energy Consulting

Kara Clark

National Renewable Energy Laboratory

Prepared under Task No. SETP.10304.23.01.10

Technical Report

NREL/TP-5D00-70781

August 2018
NOTICE

This work was authored in part by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding 

provided by the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy Solar Energy 

Technologies Office. The views expressed in the article do not necessarily represent the views of the DOE or the 

U.S. Government. The U.S. Government retains and the publisher, by accepting the article for publication, 

acknowledges that the U.S. Government retains a nonexclusive, paid-up, irrevocable, worldwide license to publish 

or reproduce the published form of this work, or allow others to do so, for U.S. Government purposes.

This report is available at no cost from the National Renewable 

Energy Laboratory (NREL) at www.nrel.gov/publications.

U.S. Department of Energy (DOE) reports produced after 1991 

and a growing number of pre-1991 documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (left to right) NREL 26173, NREL 18302, NREL 19758, NREL 29642, NREL 19795.

NREL prints on paper that contains recycled content.
iii

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Acknowledgments

This work was authored in part by the National Renewable Energy Laboratory, operated by 

Alliance for Sustainable Energy, LLC, for the U.S. Department of Energy (DOE) under Contract 

No. DE-AC36-08GO28308. Funding provided by the U.S. Department of Energy Office of 

Energy Efficiency and Renewable Energy Solar Energy Technologies Office. The views 

expressed in the article do not necessarily represent the views of the DOE or the U.S. 

Government. The National Renewable Energy Laboratory and General Electric also thank the 

members of the technical review committee for their insightful comments and assistance. 

Participation in the committee does not imply agreement with the project findings. The 

committee included: 

• Mark Ahlstrom, WindLogics

• Bradley Albert, APS

• William Anderson, Xcel Energy

• Jamie Austin, PacifiCorp

• Ron Belval, Tucson Electric Power

• Ray Byrne, Sandia National

Laboratories

• Thomas Carr, Western Governors’

Association

• Kemal Celik, U.S. Department of

Energy

• Malati Chaudhary, Public Service

Company of New Mexico

• Bob Cummings, North American

Electric Reliability Corporation

• Donald Davies, Western Electricity

Coordinating Council

• Joe Desmond, BrightSource

• Charles Diep, SolarReserve

• Tom Duane, Public Service

Company of New Mexico

• Bob Easton, WAPA

• Sara Eftekharnejad, Tucson Electric

Power

• Erik Ela, Electric Power Research

Institute

• Tassos Golnas, U.S. Department of

Energy

• Irena Green, California Independent

System Operator

• Rebecca Johnson, Western Area

Power Administration

• Debra Lew, General Electric

• Eddy Lim, Federal Energy

Regulatory Commission

• Clyde Loutan, California

Independent System Operator

• Kate Maracas, Western Grid Group

• Mark O’Malley, University College

Dublin

• Brian Parsons, Independent

consultant

• Henry Price, Independent consultant

• Vikas Singhvi, Electric Power

Research Institute

• Charlie Smith, Utility Variable

Generation Integration Group

• Guohui Yuan, U.S. Department of

Energy

The National Renewable Energy Laboratory regrets any inadvertent omission of project 

participants and contributors.
iv

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Executive Summary

This study examines the impact of concentrating solar power (CSP) on grid reliability by 

investigating the dynamic behavior of the Western Interconnection under conditions of high solar 

and wind generation. Reliability in this case refers to the somewhat narrow context of stability:

transient stability and frequency response; and control stability, especially that associated with 

weak grids.

The objectives of this study were to identify renewable energy penetration levels and mixes, 

severe disturbances, and load conditions where grid performance and reliability could be 

enhanced with CSP plants. Instantaneous penetrations of wind and solar—both photovoltaics

(PV) and CSP—up to approximately 60% were considered. The focus is on situations in the 

Western Interconnection bulk power system during which variable renewable generation has 

displaced other (non-CSP) synchronous thermal generation under highly stressed, weak system 

conditions. Particular attention was given to impacts of frequency-responsive controls and 

synchronous generation characteristics.

This is relatively new ground for the industry, and this investigation is not a substitute for 

detailed planning, but the risks illustrated can be analyzed and mitigated. Tools, data, and the 

current state-of-the-art interconnection and bulk power system stability studies, if used following 

good system engineering practices as systems are built out, will ensure continued reliability of 

power systems.

Key Findings

Grid Build-Out to Support Added Solar and Wind Changes Transient Stability 

Transmission added in solar-rich areas to avoid thermal and voltage violations, plus changes in 

dispatch and commitment (Section 2), have some effect on transient stability. The impacts are 

mixed, with some improvements and decreases (Section 5.2). No stability violations—

noncompliance with Western Electricity Coordinating Council (WECC) criteria—were found for 

the primary fault-clearing cases tested (Section 5.2 and Section 10.2). As noted, good planning 

practice needs to be observed.

WECC-wide system inertia dropped up to 27%–32% from earlier light load planning cases. The 

earlier cases had less wind and solar generation and included synchronous generation, which was 

retired in the final study cases (Section 4.1). The lower system inertia did not present any 

significant stability or frequency response challenges.

We did not observe systemic issues related to frequency and transient stability resulting from the 

solar and wind build-out. That is, the overall behavior was similar in character to the present 

system. The system seems to better tolerate non design-basis north-south separation with the grid

additions (Section 6.6).

For the conditions studied, a simultaneous nonsynchronous penetration (SNSP) of approximately

70% (Section 4.3) did not have an adverse impact on system-wide transient stability (Section 

5.2). Transient stability issues seemed to be rather localized (Section 10.2).
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Primary Frequency Response from Concentrating Solar Power Helps Meet 

Frequency Response Obligation

Because CSP uses a conventional synchronous steam turbine generator system to produce

electricity, it always contributes inertia when running. Further, depending on the design and 

operation of the plant, it can provide primary frequency response (PFR) via governor action. It is 

by no means ensured that CSP plants will necessarily provide this service. Steam systems and 

turbines must be designed with this capability in mind for best economy. This report provides 

some discussion and concepts for possibly squeezing additional frequency response out of steam 

systems (Section 8.1). The discussion includes the concept of a triggered, open-loop control 

based on the accepted practice of fast-valving special protective systems (Section 8.3).

PFR from CSP benefits frequency response, improves the system nadir, and helps the system 

(and regions thereof, such as California) meet their frequency response obligations (FRO) 

(Section 9.3). The contribution of synchronous inertia is observable, but it not very important for 

the conditions and cases examined.

Tripping two of the Palo Verde Nuclear Generating Station units, for a loss of approximately

2,750 MW, is the design basis frequency event for WECC (Section 6.1.2). We have continued to 

use that event extensively in this study. Figure ES-1 shows three cases for that event run on the 

lighter load case (60% instantaneous wind and solar penetration for the U.S. WECC) that 

illustrate two separate points. The red trace shows the reference lighter load case. The CSP units 

are online contributing inertia, but there is no governor response. The blue trace shows the 

impact of enabling the governors on the CSP plants (per the model discussion in Section 3.2). As 

expected, both the frequency nadir and the settling frequency improve. The green trace shows the 

impact of replacing CSP with PV (so difference between this and the red case is the inertia of 10

GW of CSP machines). This case has the same 60% instantaneous penetration, but the SNSP is 

70% because of the increased levels of inverter resources (Section 4.3). As expected, the CSP-toPV case with less inertia shows a faster frequency drop, and the nadir occurs sooner and is 

approximately 1-mHz deeper. For this design basis case, the PFR is much more important than 

the inertia contribution (Section 6.3).
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Figure ES-1. Contribution of concentrating solar power governors and inertia to frequency 

response

Fast Frequency Response from Solar Photovoltaics or Energy Storage Improves

Frequency Nadir and Adds Margin Against Underfrequency Load-Shedding

The provision of fast frequency response (FFR) by utility-scale, transmission-connected PV or 

other inverter-based resources, such as energy storage devices, can improve the system 

frequency nadir and add margin against underfrequency load-shedding. FFR is the rapid 

injection of arresting power to the grid during the time immediately following a disturbance that 

unbalances the grid and causes the frequency to drop (Section 7.1). FFR slows the decline and 

helps make the minimum frequency better.

PV can be designed with FFR capability. This is particularly true for utility-scale PV. In the main 

report (Section 7.2), we include a detailed discussion of the fundamental concepts that allow PV 

to provide FFR. In brief, new controls, adaptive use of rating differences between PV inverters 

and panels, and possible transient overload of inverters can allow utility-scale PV to provide 

FFR.

Considerable effort was applied toward improving understanding of the timing and location 

considerations for FFR (Section 7.3 and Section 7.4). This study found that responding quickly 

after the disturbance produces improved performance (in terms of improved nadir), but 

responding within 1–2 seconds produces most of the of benefit. Faster response produces only 

marginally better performance and introduces robustness concerns.
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Figure ES-2 shows the total results of a sequence of tests and the impact on the nadir as a 

function of timing. Higher nadir is better. The blue trace shows the base case without CSP 

governors enabled. The efficacy of the FFR is almost the same for approximately the first 3 

seconds of the event, then the efficacy of the FFR drops to zero by the time of the nadir,

indicated by the vertical red line. This is an important result that means that there is little 

systemic benefit in applying FFR with undue haste. Waiting for good information with which to 

make the decision to “trigger” the FFR has a small performance penalty and might produce 

significant robustness benefits.

The green trace presents the results in the case with CSP governors enabled. The impact of FFR 

timing on change in nadir is similar to the case without CSP governors enabled. The overall 

curve is better (higher) because of the CSP governor contribution, but otherwise the impact is 

very similar. This is another significant result. It shows that for a given operating condition, the 

beneficial contributions of multiple mitigations (in this case CSP governors plus FFR) are 

complementary and quite linear (they add up). This is not to say that the impacts are linear or 

uniform across very different operating conditions.

Figure ES-2. Impact of fast frequency response timing on frequency nadir

Further similar investigation showed that for energy-limited FFR (e.g., synthetic inertia from 

wind), the best efficacy is for FFR a few seconds into the event.

Figure ES-3 shows regional frequency measurements for two similarly sized events that are 

initiated at very different points in the system (Section 6.4). The blue trace (labeled 2PV) shows 

the trip of two Palo Verde Nuclear Generating Station units in Arizona, and the red trace shows

an event in the middle of the Pacific Northwest. The location aspects dominate for approximately 

2 seconds. Note, for example, how different the two events appear in the Northwest and 

Time of FFR Injection (after event initiated)

 

Time of FFR Injection (seconds after 2 PV unit trip initiated)
viii

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Southwest. Even though these events are approximately the same magnitude from a frequency 

perspective, they look very different during the first 2 seconds. This represents an acute 

challenge for triggering control actions that are sensitive to initial frequency drop or rate of 

change of frequency (ROCOF). Specifically, local differences in frequency during disturbances 

suggest that triggering FFR should be no faster than 0.5 seconds. This is an important 

observation relative to the results of Figure ES-2 because those results show little benefit from 

faster triggering for these system-wide events.

Figure ES-3. The location of the event strongly affects the measured frequency during the first 

seconds.

Investigation of the amount of FFR required to improve the frequency showed that the impact is 

relatively linear for small amounts. As the amount of FFR increases, the marginal benefit

decreases. For the event and condition tested, FFR has good impact up to approximately 250

MW. The relative improvement declines for more FFR capacity; and for FFR greater than 500

MW, it immediately reverses the frequency decline, creating an inflection. The nadir is at the 

time of injection, and it does not change with increased FFR power. In the narrow context of 

arresting frequency and improving nadir, the contribution of the FFR is saturated and any FFR 

greater than 500 MW is wasted. This gives an interesting perspective: the event is approximately

2,750 MW, but more than 500 MW of FFR produces no additional benefit for this specific 

operating condition (Figure 65 in Section 7.4). The FFR works—as always—with the PFR from 

the committed generation that has active governors and headroom to act. The FFR does not 

impact the system in isolation, and the combination of the FFR and the amount and speed of PFR 
ix

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dictates the megawatt-level of this saturation point. For systemic events, the location of the FFR 

resources is not very important.

Note that as (1) system inertia drops, (2) PFR becomes slower or scarcer, and (3) ROCOF

increases, this inflection point becomes a larger fraction of the size (in MW) of the event. The 

authors have observed this in smaller systems with relatively low inertia. In the limit, as for 

example when a system approaches no inertia, the break point becomes equal to the size of the 

disturbance. That is, the FFR must fully, exactly, and quickly match the size of the disturbance to 

meet frequency performance objectives. The WECC system under consideration in this study is 

far from that point.

Frequency Response from Concentrating Solar Power Can Substitute for Fast 

Frequency Response from Photovoltaics or Batteries

Both CSP PFR and FFR from PV improve performance. These can be quantitatively compared 

(Section 8.2). In these cases, the benefit of frequency response from CSP is approximately

equivalent to 3% of FFR from inverter/switched resources. That means, for example, that for 

each 100MW of CSP providing PFR, the equivalent of 3 MW of FFR is provided at that time. In 

this system, with approximately 10 GW of CSP, PFR on all the units would provide the same 

benefit for FRO as 300 MW of inverter-based FFR. Batteries or utility-scale PV, as discussed in 

Section 7.2, have potential to provide FFR. Obtaining FFR from these inverter-based resources 

will have accompanying costs, which might include costs of curtailment. The timing of available 

PFR or FFR will vary by resource. Both the amount (i.e., the number of hours per year that the 

service is available) and the timing (i.e., what hours the service is available) will be different by 

resource. Consequently, the overall (or annualized) economic value of the various alternatives 

derive from overall operational impact (i.e., over the full 8,760 hours of a year).

Figure ES-4 shows an example “equivalence” between the CSP governor and FFR. The 

reference case (black trace) is without FFR or CSP governor contribution. The blue trace shows

the CSP governors enabled with no FFR, and the green trace shows 250 MW of FFR without 

CSP governors. The CSP governors produce a somewhat better frequency nadir than the 250

MW of FFR, giving an improvement equal to approximately 300 MW of FFR. The red trace is 

for both, showing that the impacts are additive.
x

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Figure ES-4. Relative benefit of concentrating solar power governors compared to fast frequency 

response

Tests on the use of fast-valving, open-loop controls on CSP showed that they might increase this 

benefit to approximately 4.5% (Section 8.3). Concepts were presented in the work for such 

controls, which would need further engineering design to ensure feasibility (Section 8.1).

Thermal storage should help the sustainability of PFR, and it might help the speed of response 

(Section 9.4). Again, more detailed design is required.

The Benefits of Frequency Response from Concentrating Solar Power During 

Sunset Can Be Substantial and Might Represent Valuable Options During the 

Neck of the Duck Curve

One challenge that has surfaced for systems with high levels of solar is managing the system as 

the sun sets and there is a drop in solar generation. As the solar power drops, there are potential 

issues with exhausting other resources. Thus, this concern is not about high instantaneous 

penetration but rather what might happen shortly afterward, as the sun sets. We looked closely at 

California for insight, but the issues are more general, and the findings apply to other parts of 

WECC and to other systems around the world that have or might have high levels of solar 

generation (Section 9.1). 

The lighter load case is a reasonable proxy for operation during the low net load condition that 

precedes the start of sunset. During the time frames that are the focus of this study, one of the 

most pressing concerns that accompany sunset from high solar, light load conditions is frequency 

response (Section 9.2). During sunset, the system needs to meet the rise of net load by (1) 
xi

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dispatching committed generation that has headroom and (2) committing (starting) additional 

resources.

Exercises aimed at improving understanding of the relationship between this net load following 

and the depletion of generation headroom that accompanies the upward dispatch were pursued.

To that end, the work took the extreme case of looking at what happens if all the loss of solar 

generation is followed by resources that are already committed in California. Two sets of initial 

conditions were considered: (1) the lighter load case and (2) a sensitivity case in which more 

solar, less wind, and less initial synchronous resources were available (Section 9.3). 

In the sequence, the utility solar generation production across WECC, both PV and CSP (if 

deployed without storage), is ramped down uniformly to reflect the drop in insolation that 

accompanies sunset. At each step along sunset, WECC, California, and other frequency response 

performance was tested with the Palo Verde Nuclear Generating Station trip events. The 

committed gas-fired thermal generation, including combined-cycle steam, in California is

dispatched upward. This continues until these units are effectively out of headroom and cannot 

further increase output. At that point, the California hydro with headroom is dispatched upward.

The distinction might be important because when modeling hydro we assume that there is 

sufficient water (and headroom) to allow this upward dispatch. A much closer look at the 

hydrology would be needed to confirm this. As noted in this work and in earlier WWSIS work, 

the contribution of California hydro to meeting the California Independent System Operator FRO 

is significant under these study conditions. Closer inspection of the actual capability and 

performance of these hydro plants is warranted

One set of results is shown in Figure ES-5. The figure shows California’s frequency response (as 

mandated by the North American Electric Reliability Corporation) in units of MW/0.1 Hz1

compared to the amount of solar generation lost in WECC because of sunset. For the sequence 

for the sensitivity case (Low Load, Low Frequency Response), California was initially out of 

compliance. This means that the potential value from adding CSP governors is high. A 

comparison set of cases on the low frequency response sensitivity was run with all CSP 

governors enabled (the purple trace). The benefit to California is substantial, initially adding 150

MW/0.1 Hz of frequency response to California. California can meet its frequency response for 

up to 1,500 MW of sunset (blue arrow). A linear extrapolation (orange dotted line and arrow) 

suggests that enabling the governors on all new CSP in this case is “worth” an approximate

2,500-MW reduction in utility-scale solar generation due to the sun setting.

 1 Meaning MW of response per 0.1 Hz change in frequency
xii

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Figure ES-5. California’s frequency response declines during sunset if headroom is depleted.

Better dynamic response is also similar to effectively postponing sunset because it provides a

frequency response benefit, such as retaining headroom. In this construct, the possible fast 

valving discussed in Section 8.3 is “worth” approximately 1,700 MW of sunset above and in 

addition to the approximately 2500MW benefit shown in Figure ES-5. This is a nontrivial 

contribution to California’s “duck curve.” But whether such capability is possible hinges on 

whether control and/or thermal storage can be used to extract better, i.e., faster and more 

sustained frequency, response from CSP.

Although these specific results are based on one sequence in California, directionally the results 

are applicable to any solar-heavy system facing declining frequency response during sunset. 

Further discussion is provided in Section 9.

Available Dynamic Models Are Good, But They Have Some Limitations

Validation of the dynamic stability models for the CSP thermal plant showed good correlation to 

field tests. CSP models lack modeling detail needed for testing the dynamic impacts of thermal 

energy storage (Section 8.1). Approximations showed significant promise, but more detailed 

modeling efforts are required for definitive quantitative results (Section 8.2 and Section 8.3).

Utility-scale PV models might be optimistic for weak grid conditions. In particular, generic 

models might not accurately capture fast voltage and fast regulator stability concerns under 

short-circuit conditions below equipment specifications. Generic models might show good 
xiii

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performance when the application behaves poorly in low short-circuit ratio (SCR) situations. The 

minimum system strength specified by the converter supplier can provide guidance for when 

different models and tools are required (Section 10.2).

Displacement of fossil-fueled generation by renewables increases dependence on hydro and 

makes modeling fidelity for hydro plants more important (Section 9.3).

Stability Implications of Concentrating Solar Power Compared to Photovoltaics 

Are Mixed, But They Are Not Decisive for the Conditions Studied

Short-circuit strength is one proxy widely used to screen for location-specific weak grid stability 

concerns. Further, SNSP is an emerging metric of systemic concerns about stability with high 

levels of inverter-based resources. A range of tests and screening for both metrics were pursued.

One important finding was that short-circuit levels in the solar-rich areas tended to increase 

because of added transmission necessary to connect the new solar power plants without violating 

local voltage and thermal constraints. The added transmission tends to offset effects of 

decommitting synchronous generation. The only concerns identified tended to be very localized.

These were sensitive to the fact that system strength declines as PV is substituted for CSP 

(Section 4.2).

Because SCR is a key metric for concern about inverter-based generation instability, a 

deliberately challenging test was devised in which the grid was degraded by removing one of the 

230-kV lines providing egress for the power from the solar power plants. In this case, the SCR 

before the fault is 2. Figure ES-6 shows a comparison of two cases with the system degraded. 

The voltages in the upper set of axes show the CSP in blue and the utility-scale PV in red. The 

power swings of the local solar power plants are shown in the next two sets, with the CSP 

synchronous machines swings in the middle and the PV power on the bottom. The swing of the 

synchronous CSP machines is somewhat greater. Both cases meet WECC criteria (Section 

10.2.2).

As the fault becomes longer, voltage recovery will degrade. Eventually, voltage recovery will 

violate criteria, or synchronous CSP machines will lose synchronism. Inverter-based generation, 

including PV, will tend to tolerate longer faults (discussion in Section 10.2.1).

The lowest grid strength here (i.e., SCR of approximately 2) is where inverters for stiffer grids 

might misbehave. Stress tests in simulations, where PV inverters were provided with control 

setting characteristics of very stiff (high short-circuit strength) systems, showed instability like 

that observed in the field; however, this class of instabilities is outside of the accuracy of positive 

sequence simulation (transient stability) tools. More sophisticated analysis is required for 

evaluation and mitigation (Section 10.3).

Solar-exporting areas generally showed better transient stability, i.e., reduced swings and better 

post-fault voltage recovery, with PV compared to CSP. No transient stability issues that resulted 

in violation of WECC criteria were observed for primary cleared faults regardless of the type of 

solar generation (Section 10.2).
xiv

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Figure ES-6. Transient stability of CSP compared to PV in a low-grid-strength location

The range of tests performed here did not show evidence of any widespread concerns about a

weak grid, high SNSP, or low short-circuit levels for the predominantly utility-scale PV case.

These cases do not provide observable motivation to prefer synchronous CSP instead of inverter 

PV regarding system transient and voltage stability.

Executive Summary Closure

This investigation shows that integrating large amounts of solar power in the WECC system for 

the conditions studied does not present any obviously intractable challenges. We find that 

frequency response can be aided significantly by frequency-sensitive controls on CSP and PV 

solar. Stability problems, including those anticipated around weak grid issues, were not 

substantial.
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List of Acronyms

CAISO California Independent System Operator 

COI California-Oregon Interface

CSP Concentrating solar thermal power plant

DG distributed generation, embedded PV

FFR Fast frequency response

FRO Frequency response obligation

GW gigawatt

HVDC high-voltage direct current 

Hz Hertz

mHz millihertz

MVA Megavolt ampere

MW megawatt

NERC North American Electric Reliability Corporation

PDCI Pacific Direct Current Intertie

PFR Primary frequency response

PV Photovoltaic 

ROCOF Rate of change of frequency

SCE Southern California Edison

SCR Short-circuit ratio

SNSP Simultaneous nonsynchronous penetration

WECC Western Electricity Coordinating Council

WWSIS Western Wind and Solar Integration Study
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Table of Contents

Executive Summary................................................................................................................................... iv

Key Findings ......................................................................................................................................... iv

Grid Build-Out to Support Added Solar and Wind Changes Transient Stability......................... iv

Primary Frequency Response from Concentrating Solar Power Helps Meet Frequency Response 

Obligation......................................................................................................................... v

Fast Frequency Response from Solar Photovoltaics or Energy Storage Improves Frequency 

Nadir and Adds Margin Against Underfrequency Load-Shedding................................. vi

Frequency Response from Concentrating Solar Power Can Substitute for Fast Frequency 

Response from Photovoltaics or Batteries....................................................................... ix

Available Dynamic Models Are Good, But They Have Some Limitations................................xii

Stability Implications of Concentrating Solar Power Compared to Photovoltaics Are Mixed, But 

They Are Not Decisive for the Conditions Studied ......................................................xiii

Executive Summary Closure ............................................................................................................... xiv

1 Introduction........................................................................................................................................... 1

1.1 Project Structure............................................................................................................................ 1

1.1.1 Year 1 ............................................................................................................................... 1

1.1.2 Year 2 ............................................................................................................................... 2

1.2 Background and Related Work ..................................................................................................... 2

1.2.1 Western Wind and Solar Integration Study: Phase 1 ....................................................... 2

1.2.2 Western Wind and Solar Integration Study: Phase 2 ....................................................... 3

1.2.3 Western Wind and Solar Integration Study: Phase 3 ....................................................... 3

1.2.4 Western Wind and Solar Integration Study: Phase 3A .................................................... 3

1.3 Planning Context........................................................................................................................... 3

2 Database Refinement........................................................................................................................... 4

2.1 Case Evolution/Summary.............................................................................................................. 4

2.2 Case Summaries............................................................................................................................ 5

2.3 Western Interconnection Power Plant Retirements....................................................................... 7

2.4 Study Regions ............................................................................................................................... 9

2.5 Concentrating Solar Power Plants................................................................................................. 9

2.6 Lighter Load................................................................................................................................ 10

2.6.1 Lighter Load Analysis.................................................................................................... 11

2.6.2 Redispatch for Increased Solar and Lighter Load .......................................................... 12

2.7 Transmission Improvements....................................................................................................... 14

2.7.1 Pacific DC Intertie Upgrade........................................................................................... 14

2.7.2 Improvements to Accommodate Increased Solar Production ........................................ 15

2.8 Heavy Summer Retirement Case ................................................................................................ 17

2.9 Replacement of CSP with PV (CSP-to-PV) Sensitivity Case ..................................................... 19

3 CSP Model Validation......................................................................................................................... 20

3.1 Exciter Model Validation Testing ............................................................................................... 20

3.2 Governor Model Validation Testing ........................................................................................... 22

3.3 Load Model Validation ............................................................................................................... 24

4 System Characterization.................................................................................................................... 27

4.1 System Inertia.............................................................................................................................. 27

4.2 Short-Circuit Strength ................................................................................................................. 29

4.3 Simultaneous Nonsynchronous Penetration: General Discussion............................................... 32

4.3.1 Simultaneous Nonsynchronous Penetration: Effect of CSP to PV Conversion on Lighter 

Load Results................................................................................................................... 35

5 System Transient Stability Performance ......................................................................................... 39

5.1 Overview..................................................................................................................................... 39
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5.1.1 Transient Stability Visualization.................................................................................... 39

5.1.2 Previous Transient Stability Work: Western Wind Solar Integration Study: Phase 3 and 

Phase 3A......................................................................................................................... 40

5.2 Regional Transient Stability Impacts of Required Transmission Changes................................. 41

5.2.1 Heavy Summer Pacific DC Intertie Event Case: Initial Investigation ........................... 41

5.2.2 Investigation of Transmission Additions Impact on Transient Stability for Pacific DC 

Intertie Event.................................................................................................................. 43

5.2.3 California-Oregon Interface Event................................................................................. 45

5.2.4 Overall Observations on Transient Stability Impact of Transmission Additions........... 46

6 Frequency Performance .................................................................................................................... 47

6.1 Frequency Response Overview................................................................................................... 47

6.1.1 Frequency Response Visualization ................................................................................ 47

6.1.2 Frequency Response Obligation..................................................................................... 50

6.1.3 Palo Verde Reference Event .......................................................................................... 51

6.2 Impacts of CSP and Load Condition on Dispatch....................................................................... 51

6.3 CSP Governor and Inertia Contributions .................................................................................... 54

6.3.1 Lighter Load................................................................................................................... 54

6.3.2 Inertia impact on Rate of Change of Frequency............................................................. 55

6.4 Locational Aspects of Inertia and Frequency Response.............................................................. 56

6.4.1 Locational Aspects of Primary Frequency Response..................................................... 58

6.5 Heavy Summer............................................................................................................................ 62

6.5.1 Impact of Retirements and DC Upgrade ........................................................................ 62

6.5.2 Heavy Summer Impact of CSP Governors..................................................................... 63

6.5.3 Localized Damping Concerns........................................................................................ 64

6.6 North-South Separation Disturbance........................................................................................... 65

6.6.1 Heavy Summer North-South Separation........................................................................ 66

6.6.2 Impact of PV Compared to CSP on Separation Dynamics ............................................ 69

6.6.3 Spring Lighter Load North-South Separation ................................................................ 70

7 Fast Frequency Response and Enhanced PV Response............................................................... 72

7.1 Fast Frequency Response Discussion.......................................................................................... 72

7.2 Concepts for Transient Fast Frequency Response from PV........................................................ 72

7.2.1 Solar PV Components and Fast Frequency Response.................................................... 72

7.2.2 Curtailment, Overload, and Fast Frequency Response .................................................. 74

7.2.3 Inverter and Panel Rating............................................................................................... 77

7.2.4 Fast Frequency Response Control.................................................................................. 79

7.3 Generalized Fast Frequency Response: Energy Impulse ............................................................ 80

7.4 Generalized Fast Frequency Response: Sustained Response...................................................... 84

7.4.1 Linearity of Fast Frequency Response Impacts ............................................................. 87

7.4.2 Locational Aspects of Fast Frequency Response ........................................................... 88

7.4.3 Temporal Relationship Between Fast Frequency Response and Rate of Change of 

Frequency....................................................................................................................... 90

8 Enhanced Frequency Response from CSP ..................................................................................... 92

8.1 Concepts for Enhanced Frequency Response from CSP............................................................. 92

8.2 CSP Governor Response Compared to Inverter-Based Fast Frequency Response ..................... 94

8.3 Fast Valving and Enhanced CSP Response Results.................................................................... 97

8.3.1 Frequency Response Comparison of CSP Fast Valving to Fast Frequency Response 

from PV.......................................................................................................................... 99

9 Sunset Net Load Ramp and Frequency Response ....................................................................... 101

9.1 Discussion: California Duck Curve........................................................................................... 101

9.2 Depletion of Headroom............................................................................................................. 102

9.3 Lighter Load Low Frequency Response Sunset Sensitivity Investigation................................ 106
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9.3.1 Effect of Enabling CSP Governors During Sunset ...................................................... 112

9.3.2 Governor: Headroom, Frequency Response, and Storage............................................ 119

9.4 Implications for CSP Thermal Storage ..................................................................................... 120

9.5 Synopsis of Sunset Investigation............................................................................................... 121

10 Local Weak Grid and Regional High Simultaneous Nonsynchronous Penetration .................. 123

10.1 Introduction ............................................................................................................................... 123

10.1.1 Weak Grid Visualization.............................................................................................. 123

10.1.2 Investigation of Short-Circuit Strength on Weak and High-Change Buses................. 123

10.2 Investigation of Low Short-Circuit Strength at Solar Power Plants.......................................... 124

10.2.1 Gila Bend ..................................................................................................................... 124

10.2.2 Eagle Eye ..................................................................................................................... 126

10.2.3 Discussion of Mechanisms of Weak Grid Inverter Instability ..................................... 128

10.2.4 Experiments with Deliberately Induced PV Regulator Instability ............................... 130

10.3 Key Observations on Low Levels of Synchronous Generation ................................................ 131

11 Key Findings and Conclusions....................................................................................................... 133

11.1 Key Findings............................................................................................................................. 133

11.1.1 Changes in Frequency and Transient Stability Resulting from Solar and Wind BuildOut................................................................................................................................ 133

11.1.2 Primary Frequency Response from CSP...................................................................... 133

11.1.3 Fast Frequency Response ............................................................................................. 134

11.1.4 Dynamic Models.......................................................................................................... 134

11.1.5 Stability Implications of CSP Compared to PV ........................................................... 135

11.1.6 Economic Implications of CSP Compared to PV ........................................................ 135

11.2 Future Work .............................................................................................................................. 136

11.2.1 Western Interconnection Analysis ............................................................................... 136

11.2.2 Protection and Relaying Investigation ......................................................................... 136

11.2.3 Load Modeling ............................................................................................................. 136

12 References ........................................................................................................................................ 137
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List of Figures

Figure ES-1. Contribution of concentrating solar power governors and inertia to frequency response ...... vi

Figure ES-2. Impact of fast frequency response timing on frequency nadir............................................... vii

Figure ES-3. The location of the event strongly affects the measured frequency during the first seconds.

............................................................................................................................................... viii

Figure ES-4. Relative benefit of concentrating solar power governors compared to fast frequency 

response.................................................................................................................................... x

Figure ES-5. California’s frequency response declines during sunset if headroom is depleted. ................xii

Figure ES-6. Transient stability of CSP compared to PV in a low-grid-strength location ........................ xiv

Figure 1. Definition of regions...................................................................................................................... 9

Figure 2. Geographic distribution of added CSP units ............................................................................... 10

Figure 3. Lighter load duration analysis curves.......................................................................................... 11

Figure 4. Lighter load final commitment and dispatch............................................................................... 12

Figure 5. Lighter load final dispatch with imports...................................................................................... 13

Figure 6. Lighter load wind and solar (PV plus CSP) penetration.............................................................. 14

Figure 7. Final commitment and dispatch for heavy summary retirement case ......................................... 18

Figure 8. Final dispatch with imports for heavy summer retirement case .................................................. 18

Figure 9. Excitation test of Genesis CSP plant ........................................................................................... 21

Figure 10. Simulation validation of exciter model(s) ................................................................................. 22

Figure 11. Governor test of Genesis CSP plant .......................................................................................... 23

Figure 12. Simulation validation of governor models ................................................................................ 23

Figure 13. Load data March 30, 2012, 10–11 a.m. ..................................................................................... 24

Figure 14. Composite load model with embedded PV ............................................................................... 25

Figure 15. Dynamic behavior of composite load model for a selected bus................................................ 26

Figure 16. Spring: Western Interconnection system inertia........................................................................ 28

Figure 17. Spring: regional impact on inertia ............................................................................................. 29

Figure 18. Spring: impact on short-circuit strength .................................................................................... 30

Figure 19. Short-circuit strength detail in SCE Zone.................................................................................. 31

Figure 20. Changes in short-circuit strength from lighter load to lighter load PV-to-CSP case................. 32

Figure 21. Lighter load simultaneous nonsynchronous penetration for system based on generation 

(dispatch)................................................................................................................................ 33

Figure 22. Lighter load regional simultaneous nonsynchronous penetration based on generation (dispatch)

................................................................................................................................................ 34

Figure 23. Lighter load simultaneous nonsynchronous penetration based on capacity (generator rating). 35

Figure 24. Contribution of CSP to reducing simultaneous nonsynchronous penetration ........................... 36

Figure 25. Simultaneous nonsynchronous penetration for CSP-to-PV sensitivity ..................................... 37

Figure 26. Lighter load CSP-to-PV case distribution of inverter-based resources..................................... 38

Figure 27. Lighter load CSP-to PV case changes in resources in the Southwest ....................................... 38

Figure 28. Visualization of transient stability with synchronous generators and wind power plants......... 40

Figure 29. Frequency Pacific DC Intertie result ......................................................................................... 42

Figure 30. California-Oregon Interface Pacific DC Intertie event: key path flows.................................... 43

Figure 31. Pacific DC Intertie disturbance performance degraded by transmission additions................... 44

Figure 32. Path flow comparisons for PDCI disturbance showing performance degraded by transmission 

additions................................................................................................................................. 45

Figure 33. California-Oregon Intertie event stability test details................................................................ 46

Figure 34. Balance analogy for frequency stability .................................................................................... 48

Figure 35. Electricity demand exceeds electricity generation and frequency drops................................... 48

Figure 36. System frequency in response to a large generation trip ........................................................... 49

Figure 37. Light spring compared to lighter load frequency (no contribution from CSP).......................... 52
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Figure 38. Light spring compared to lighter load regional primary frequency response (no contribution 

from CSP) .............................................................................................................................. 53

Figure 39. Light spring compared to lighter load regional primary frequency response in areas with 

significant CSP capacity (no contribution from CSP) ........................................................... 54

Figure 40. Impact of CSP governors and inertia on frequency for Lighter Load case ............................... 55

Figure 41. Inertia impact on initial rate of change of frequency................................................................. 56

Figure 42. Locational aspects of rate of change of frequency impacts....................................................... 57

Figure 43. Comparison: loss of two Palo Verde units (approximately 2,750 MW) compared to 3,000 MW 

load increase in the Northwest ............................................................................................... 59

Figure 44. Primary frequency response: loss of two Palo Verde units compared to 3,000 MW load 

increase in the Northwest....................................................................................................... 60

Figure 45. Voltage: loss of two Palo Verde units compared to 3,000 MW load increase in the Northwest

................................................................................................................................................ 61

Figure 46. Initial regional frequency decline: loss of two Palo Verde units compared to 3,000 MW load 

increase in the Northwest....................................................................................................... 62

Figure 47. Heavy summer: impact of retirements and DC upgrade ........................................................... 63

Figure 48. Heavy summer retirement case: impact of CSP governors ....................................................... 64

Figure 49. Illustration of local damping risk with CSP on long radial interconnection ............................. 65

Figure 50. Illustrative North-South separation ........................................................................................... 66

Figure 51. Heavy summer: regional frequencies for North-South system separation ................................ 67

Figure 52. Heavy summer retirement case: North-South separation—key path flows............................... 68

Figure 53. Heavy summer retirement case: North-South separation—selected bus voltages..................... 69

Figure 54. CSP compared to PV separation dynamics ............................................................................... 70

Figure 55. Lighter load spring case: North-South separation ..................................................................... 71

Figure 56. Illustration of DC power impact of tracking.............................................................................. 74

Figure 57. Inverter rating concept............................................................................................................... 75

Figure 58. PV current phasor for normal operation .................................................................................... 76

Figure 59. Normal operation at steady-state current limits......................................................................... 77

Figure 60. DC power (different trackers) compared to AC inverter rating................................................. 78

Figure 61. Fast frequency response capability for reduced-rating PV inverters......................................... 79

Figure 62. Generic fast frequency response calibration simulations .......................................................... 81

Figure 63. Sweep of fast frequency response impulses .............................................................................. 82

Figure 64. Nadir improvement compared to timing of arresting power injection ...................................... 83

Figure 65. Sustained fast frequency response: two different amplitudes.................................................... 85

Figure 66. A 250-MW fast frequency response at Vincent 500 kV: varied trigger timing ........................ 86

Figure 67. Timing and efficacy of 250-MW sustained fast frequency response ........................................ 87

Figure 68. Impact of sustained fast frequency response magnitude ........................................................... 88

Figure 69. Distributed (at utility-scale PV plants) compared to single node fast frequency response ....... 89

Figure 70. Fast frequency response impact on rate of change of frequency............................................... 91

Figure 71. CSP frequency control and steam balance................................................................................. 93

Figure 72. CSP governor compared to fast frequency response: impact on frequency .............................. 94

Figure 73. CSP governor compared to fast frequency response: power response ...................................... 95

Figure 74. Synchronous units with governor.............................................................................................. 96

Figure 75. Delta of governor response........................................................................................................ 96

Figure 76. Frequency with CSP fast valving .............................................................................................. 98

Figure 77. All CSP response with fast valving ........................................................................................... 98

Figure 78. Fast valving on a single CSP unit.............................................................................................. 99

Figure 79. CAISO duck curve .................................................................................................................. 102

Figure 80. California headroom - before and after reduction of 4,000 MW of utility-scale solar generation 

due to sunset......................................................................................................................... 103

Figure 81. Frequency response to Palo Verde event during sunset .......................................................... 104
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Figure 82. California frequency response during sunset........................................................................... 105

Figure 83. System-wide frequency response during sunset...................................................................... 106

Figure 84. Lighter load compared to California low frequency response case: commitment and dispatch

.............................................................................................................................................. 107

Figure 85. Lighter load low frequency response: dispatch at beginning and “end” of sunset .................. 109

Figure 86. Lighter load low frequency response CSP sunset scenario ..................................................... 109

Figure 87. Sunset impact on California frequency response: low frequency response case..................... 110

Figure 88. Sunset impact on WECC frequency response: low frequency response case ......................... 111

Figure 89. Sunset impact on frequency nadir: low frequency response case............................................ 112

Figure 90. Lighter load low frequency response during sunset with CSP governors on .......................... 113

Figure 91. Nadirs with enabled CSP governors........................................................................................ 114

Figure 92. CSP governor response with headroom increase..................................................................... 115

Figure 93. Details of one CSP governor response as sun sets .................................................................. 116

Figure 94. Sunset with CSP governors plus fast valving.......................................................................... 117

Figure 95. Fast valving during sunset ....................................................................................................... 118

Figure 96. CSP fast-valving benefit during sunset.................................................................................... 119

Figure 97. Thermal dispatch during sunset............................................................................................... 120

Figure 98. Fast frequency response and storage impact on frequency response during sunset ................ 121

Figure 99. Small wind power plant relative to the electric grid................................................................ 123

Figure 100. Large wind power plant relative to the electric grid.............................................................. 123

Figure 101. Gila Bend disturbance: CSP compared to PV dynamics....................................................... 125

Figure 102. Gila Bend disturbance: CSP compared to PV stuck breaker case ......................................... 126

Figure 103. Eagle Eye fault: CSP compared to utility-scale PV............................................................... 127

Figure 104. Eagle Eye fault: with initially lower short-circuit ratio ......................................................... 128

Figure 105. Measured utility-scale PV inverter instability ....................................................................... 130

Figure 106. PV voltage regulator induced instability ............................................................................... 131

List of Tables

Table 1. Case Summary Synopsis................................................................................................................. 6

Table 2. Generation Retirements .................................................................................................................. 8

Table 3. Once-Through Cooling Unit Retirements....................................................................................... 8

Table 4. Transmission Additions................................................................................................................ 16

Table 5. Transformer Additions.................................................................................................................. 17

Table 6. Capacitor Additions...................................................................................................................... 17

Table 7. Heavy Summer Synchronous Condenser Additions..................................................................... 17

Table 8. Dispatch of CSP-to-PV Sensitivity Case ...................................................................................... 19

Table 9. Western Interconnection Frequency Response Obligation and Approximate Regional and Area 

Frequency Response Obligations........................................................................................... 50

Table 10. Lighter Load Initial Rate of Change of Frequency ..................................................................... 58

Table 11. Frequency Response: CSP Fast Valving Compared to Fast Frequency Response from PV ...... 99

Table 12. Lighter Load Low Frequency Response CSP Scenario ............................................................ 108
1

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1 Introduction

The stability of the North American electric power grids under conditions of high penetrations of

wind and solar is a significant concern and possible impediment to reaching renewable energy 

goals. The 33% wind and solar annual energy penetration considered in this study results in 

substantial changes to the characteristics of the bulk power system. This includes different power 

flow patterns, different commitment and dispatch of existing synchronous generation, and 

different dynamic behavior from wind and solar generation.

The investigation reported in this document builds on the foundation of the different phases of 

the Western Wind and Solar Integration Study (WWSIS) described later. The specific focus of 

this work is on the frequency response, and the accompanying transient stability, of systems with 

substantial generation from concentrating solar power (CSP), wind, and solar photovoltaics (PV)

(both transmission-connected utility-scale and distributed). The focus is on conditions in the 

Western Interconnection bulk power system during which variable renewable generation has 

displaced non-CSP synchronous thermal generation under highly stressed, weak system

conditions.

This work focuses on “traditional” fundamental frequency stability issues, such as maintaining 

synchronism, frequency, and voltage. This work does not explore nonfundamental frequency 

issues, such as subsynchronous phenomena, harmonics, unbalances, transients, and small-signal 

analysis.

The objectives of this study are to identify renewable energy penetration levels and mixes, severe 

disturbances, and load conditions where grid performance and reliability could be enhanced with 

frequency-responsive controls on CSP plants.

1.1 Project Structure

This 2-year project followed a sequence of tasks in the execution of the work. This report 

includes the results of the 2-year effort, but it does not exactly follow the task sequence. The 

project held regular meetings with a highly knowledgeable industry technical review committee.

Participation and guidance from these industry representatives was critical to the success of the 

project. Acknowledgement to these contributors is provided in the acknowledgments section. A 

brief synopsis of the task structure and task objectives follows.

1.1.1 Year 1

Develop study scenarios and databases. Activities included reviewing and modifying existing 

databases, modeling and validating CSP plant and load models, and adding various levels and 

mixes of other renewable (i.e., inverter-based) generation.

Task 1.1: Develop study databases. The starting databases were those developed for the Western 

Wind and Solar Integration Study: Phase 3 (WWSIS-3) and the follow-up analysis focusing on 

low levels of synchronous generation. These were compared to the current Western Electricity 

Coordinating Council (WECC) outlook and updated. The databases were updated to

accommodate CSP plants, including local transmission to enable interconnection, and to include 

appropriate future transmission projects and generation retirements. The work included an

examination of load model performance and comparison of the load model to National 
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Renewable Energy Laboratory-provided measurements. The task also identified disturbances and 

developed scripts for simulation.

Task 1.2: Develop and validate CSP models. This task developed appropriate CSP plant-specific 

models for positive-sequence power flow and dynamic analysis. The models were tested and 

validated for performance against measured data from operational plants.

1.1.2 Year 2

Year 2 included performing the bulk of the frequency response/transient stability simulation and 

analysis as well as preparing this final report. The work was specifically charged with examining

the impact of CSP plants on frequency response and transient stability.

Task 2.1: Perform detailed analysis of CSP impact on grid performance. Building on the models 

and databases developed in Year 1, this task examined grid performance and reliability for the 

various study scenarios. Performance was measured against applicable North American Electric 

Reliability Corporation (NERC), regional, and local criteria. The project specifically set out to

examine inverter-based generation that meets or exceeds 70% instantaneous penetration—i.e.,

70% simultaneous nonsynchronous penetration (SNSP)—with the remaining 30% met by 

synchronous generation, including CSP.

Task 2.2: Pursue detailed analysis of mitigation strategies to address a variety of performance 

concerns and opportunities in response to large system disturbances. The work identified

mitigation strategies and how they might change under the various study scenarios. The 

mitigation work had emphasis on frequency-responsive controls for CSP plants, but frequency 

response from transmission-connected utility-scale PV and other resources (such as energy 

storage) were also addressed.

Task 2.3: Prepare final report—this document.

1.2 Background and Related Work

The WWSIS, sponsored by the U.S. Department of Energy, is one of the largest regional solar 

and wind integration study sequences to date. In multiple phases, it explored different aspects of 

the question: Can we integrate large amounts of wind and solar energy into the electric power 

system of the West? An overview of the WWSIS research program is provided next.

1.2.1 Western Wind and Solar Integration Study: Phase 1

The first phase of WWSIS (GE Energy 2010a; GE Energy 2010b) investigated the benefits and 

challenges of integrating up to 35% wind and solar energy in the WestConnect subregion and, 

more broadly, the Western Interconnection in 2017. The study showed that it is operationally 

feasible to accommodate 30% wind and 5% solar energy if utilities substantially increase their 

coordination of operations throughout wider geographic areas and schedule their generation and 

interchanges on an intra-hour basis.
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1.2.2 Western Wind and Solar Integration Study: Phase 2

Phase 2 of WWSIS was initiated to determine the wear-and-tear costs and emissions impacts of 

cycling and to simulate grid operations to investigate the detailed impacts of wind and solar 

power on the fossil-fueled fleet in the West (Lew and Brinkman 2013; Lew et al. 2013).

1.2.3 Western Wind and Solar Integration Study: Phase 3

Phase 3 of WWSIS delved into the dynamic performance of the grid in the fractions of a second 

to 1 minute following a large disturbance (e.g., loss of a large power plant or a major 

transmission line), which is critical to system reliability. This study examined the large-scale 

transient stability and frequency response of the Western Interconnection with high penetrations 

of wind and solar, and it identified means to mitigate any adverse performance impacts via 

transmission reinforcements, storage, advanced control capabilities, or other alternatives (Miller 

et al. 2014a; Miller et al. 2014b). 

1.2.4 Western Wind and Solar Integration Study: Phase 3A

Phase 3A of WWSIS delved further into the transient stability of the grid under weak grid

conditions and very low levels of synchronous generation. The work focused on the challenges 

and characterization of the behavior of a portion of the Western Interconnection with very high 

levels of wind generation that exports power to the rest of the interconnection and that displaces

the fossil-fueled synchronous generation for which the regional transmission system was 

originally designed (Miller, Leonardi, and D’Aquila 2015).

1.3 Planning Context

This is not a planning study. The investigations are intended to provide insight into how the 

Western Interconnection, and more broadly how other real systems, behave dynamically with 

high levels of solar generation. The data sets, discussed in detail in the next chapter, include a 

high level of accurate detail about the Western Interconnection, but they are not official planning 

databases. A comprehensive planning study would start with different databases and evaluate 

more scenarios, more disturbances, more paths, and more types of analysis (e.g., steady-state 

contingency analysis).
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2 Database Refinement

As noted in the introduction, this study relies heavily on the foundation of work of the preceding 

WWSIS. Building credible load flows and dynamic models for the investigation is key to 

creating meaningful results. The reports (listed in Section 1.2) from the earlier work provide 

details of the evolution of the data up to the beginning of this study.

2.1 Case Evolution/Summary

As with the preceding WWSIS, we kept two broad groups of models of the western system: a set 

of light spring load conditions and a set of heavy summer load conditions.

The overall evolution of the data sets for this study are presented here, and then in the next 

sections various details of the creation of the new cases are presented. In this study, we started 

with two pairs of databases:

1. Circa 2013 WECC “base” power flow cases: These cases were improved at the beginning 

of WWSIS-3.

A. Heavy summer 2023: Planning case with minor wind and solar expansion.

B. Light spring 2022: Planning case with moderate wind and solar (no distributed 

generation)

2. High-mix cases: These cases were developed for WWSIS-3 and improved further for 

WWSIS-3A.

A. Mix of 33% wind and solar annual energy, evenly split (annual energy)

B. Mix of CSP, utility PV, and distributed PV.

In this report, we include summary information about these cases, but the details of the creation 

of these cases are included in the respective WWSIS reports. This project did not have the option 

to start with completely new databases. Rather, the intent was to capture plant retirements and

major transmission projects that are likely to impact the transient stability of the system, 

particularly in the focus area with high levels of solar generation. As such, focus was directed 

particularly at changes in the Southwest and California areas of the system. There was no intent 

to get exact topologies. From the high-mix cases, we created for this project:

1. New “retirement” and “lighter load” cases: These were intended to capture current 

expectations about aspects of the Western Interconnection that are germane to this study. 

Specifically, for both heavy summer and light spring, these new cases included:

A. Thermal plant retirements (mainly important for the Heavy Summer case)

B. Transmission improvements.

Further, for the light spring case, the system load was reduced, creating a lighter load

case. The effect of retirements is minimal in the spring case, since most of the retired 

units were not committed anyway.

2. New “CSP-to-PV” sensitivity cases, with future CSP plants converted to utility-scale PV 

plants for the lighter load condition.
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For context, note that the sequence of database improvements, starting with WWSIS-3 have 

focused on incremental improvements rather than on developing a substantially different wind 

and solar penetration level. The databases have undergone many changes from the original 

generation and topology found in the WECC 2022–2023 cases, including the latest inputs 

discussed in Section 2.3. The intent of this project is to gain insight into grid dynamics with high 

levels of solar generation, not to perform a system planning study.

For clarity, note that in this study we continued the practice adopted for all the WWSIS work of 

making a distinction between utility-scale PV and distributed PV or distributed generation.

Throughout this work, utility-scale means PV projects large enough to be connected to 

transmission buses explicitly represented in Western Interconnection databases. These PV plants 

are all assumed to have, and are modeled with, dedicated plant transformers between the 

transmission bus and an explicitly represented lower voltage collector bus.

The selection of the initial condition for the stability analysis was a key consideration. During the 

WWSIS-3 process, lengthy discussions were held regarding which conditions should be 

examined. Some of that decision-making process is recorded in the study report, but it is useful 

to provide some context here. To evaluate the impact on transient stability and frequency 

response of high levels of wind and solar generation, it is useful to select conditions in which the 

penetration levels of these resources are high. Further, it is well known that light load conditions 

represent some of the more challenging conditions, especially for frequency response. The 

California Independent System Operator and others are particularly worried about light load in 

the spring, when there is a high level of hydropower production. Thus, light spring conditions 

with high levels of wind and solar are of particular interest. Because it must be daytime for there 

to be solar generation, such light load conditions (e.g., a sunny, windy weekend morning) are not 

the absolute minimum load condition. That is likely to happen in the early, presunrise hours of 

the morning. But there will be only wind generation then, so the maximum instantaneous 

penetration for this mix of variable renewable generation is expected to be lower. Although these 

cases were expected to be both challenging and illuminating for this investigation, there is no 

implication that these cases are necessarily the most difficult in all regards.

2.2 Case Summaries

A detailed summary of the critical metrics for all the study cases for this project is given in Table 

1. Generation levels in the table are power production, not equipment ratings. Then, in the 

subsequent subsections of this section, details of the cases are provided. The table includes 

metrics for the lighter load low frequency response sensitivity case, discussed in Section 9.3.
6

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Table 1. Case Summary Synopsis
7

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2.3 Western Interconnection Power Plant Retirements 

Unit retirements, especially in California, will alter the system dynamics considerably. Further, it 

is part of California’s energy plan that renewable resources displace some of the existing fossilfueled thermal plants. Retirements in the study database are made by decommitting the retired 

units and redispatching other resources upward to fill in the lost generation. Retirements are 

based on the California Independent System Operator (CAISO) 2016 unified planning 

assumptions document (CAISO 2016b). The retirements imposed in the study data sets fall into 

three categories:

• Nuclear units: All the remaining nuclear power plants in California—e.g., Diablo 

Canyon—are shut down.

• Scheduled retirements (listed in Table A3-1 of the planning appendix as “to be retired in 

planning horizon”): These are listed in Table 2, with the capacity of the units in Southern 

California Edison from the WECC heavy summer planning case for this study 

overwriting the rating from the table.

• Retirements resulting from the once-through cooling policy (listed as “Potential OTC2

Generating Unit Early Retirement to Accommodate CPUC3

-Approved Repowering 

Projects in planning horizon”): These are listed in Table 3, again with the unit ratings 

from the study database overwriting the table entry. The two synchronous condenser 

conversions are included in the study.

Overall, approximately 5,700 MW of generation dispatch is displaced with the removal of these 

units from the heavy summer case. These units were not committed in the light spring case.

To make up for the lost thermal generation, utility-scale PV and CSP solar are dispatched 

upward, reflecting a condition with higher insolation that the original case. The CSP plants, 

especially in California, are producing power at levels closer to their rating. That is, we have 

assumed that there is more solar insolation in the snapshot of time that is being studied. (This 

higher production is relevant throughout the study, especially in the sunset investigation of 

Section 9.)

 2 Once-through cooling 3 California Public Utilities Commission
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Table 2. Generation Retirements

Table 3. Once-Through Cooling Unit Retirements
9

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2.4 Study Regions

One of the objectives of this study is to better understand the locational aspects of system 

stability and solar generation. The WECC model includes representation of 20 “areas” that are, 

for the most part, representative of the major balancing authority boundaries in the 

interconnection. The study also includes four U.S. regions, as shown in Figure 1. The boundaries 

of the regions have been modified from previous WWSIS studies to more closely align with 

those used in other WECC activities. Results presented throughout this report are for these four 

regions, which do not include non-U.S. contributions. When WECC-wide results are presented, 

the non-U.S. contributions are included, so the sum of the four regions does not always equal the 

WECC totals.

Figure 1. Definition of regions

2.5 Concentrating Solar Power Plants

CSP plants are a key element of this study. The Western Interconnection system model (i.e., the 

original WECC planning case) included 14 CSP plants. During the preceding WWSIS studies, 

78 new CSP plants were sited and added to the system. Originally, these plants as well as the 

other PV and wind generation in the system had their dispatch (production) modeled based on a 

representative weather condition with good solar and wind. As noted, the CSP in the retirement 
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cases was dispatched farther upward to account for the displacement from the retired plants. The 

final commitment and dispatch for the heavy summer retirement cases are: 

• Fourteen existing CSP plants with a total rating of 954 MW in the original planning cases

at 860-MW dispatch/production

• Seventy-eight new CSP plants with a total rating of 10,211 MW added to the study cases 

at 7,589-MW dispatch/production.

The geographic distribution of the CSP plants is shown in Figure 2, with the plants concentrated 

in the sunny southern part of the West.

Figure 2. Geographic distribution of added CSP units

2.6 Lighter Load

The light spring cases used in the preceding WWSIS studies had operating conditions and system 

load selected by the WECC stakeholder process. The system load in the U.S. portion of WECC 

for those cases was 93 GW, and it was based on the consensus at the time. Concerns were raised 

that this load level is relatively high for a “light load” condition and that investigation of system 

dynamics at low load and high solar and wind might be more illuminating at lower load levels.
11

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2.6.1 Lighter Load Analysis

Two data sources were used to check on both the historical spring load levels and forecasts for 

future spring load conditions.

Historical load analysis was performed for the U.S. WECC region. Only daytime hours (defined 

as the hours during which the average hourly PV output was more than 10% of the PV max for 

the year) were considered. We performed both an annual analysis and one for the spring season 

(defined here as March, April, and May).

Creating a forecast for the lighter load for the year 2023 was done using two methods:

• Linear regression

• Analysis of MAPS (i.e., from General Electric data) forecast.

The historical U.S. WECC daytime spring loads for the decade 2005–2014 were bucketed in 

deciles. The results are shown in Figure 3, with the load level of the original light spring case 

indicated by the left arrow. For the lighter load scenario, we opted to target loading in the lowest 

decile, as indicated by the arrow on the right. A linear regression of the 10th decile loads, 

extrapolated to 2023, resulted in a load level of 73.2 GW. General Electric data, used for other 

analysis outside of this study, gave a similar projection of 74.1 GW for 2023.

Figure 3. Lighter load duration analysis curves
12

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2.6.2 Redispatch for Increased Solar and Lighter Load

The U.S. WECC load was reduced with uniform scaling of system loads to 73 GW. Because the 

high-mix, light-load case, even before this load reduction, had displaced most of the fossil-fueled

generation available for redispatch or decommitment, most of the reduction in generation was 

accomplished by reducing the hydro generation in the Northwest. This resulted in significant 

south-to-north flows, a condition that today is relatively unusual in the West.

The commitment (operating MW rating) and dispatch (MW production) of renewable and other 

resources for the final lighter load case is shown in Figure 4. Nuclear units are included in 

“steam”.

Figure 4. Lighter load final commitment and dispatch 

Although power exchange among regions is a significant element in overall system stability, it is 

not the same thing as dispatch. To show the relative magnitude of the regional exchanges 

compared to dispatch, a second plot, which includes imports (negative being export) for this 

condition, is shown in Figure 5. Massive export from the Southwest and some import to the 

Northwest are consequences of the combination of high solar production in the South, high wind 

everywhere, and load in the lowest 10th decile for spring daytime conditions.
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Figure 5. Lighter load final dispatch with imports 

The regional penetration of solar and wind are shown in Figure 6 for the lighter load case.
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Figure 6. Lighter load wind and solar (PV plus CSP) penetration 

2.7 Transmission Improvements

Several updates to the transmission topology were made to the two final retirement power flow 

cases.

2.7.1 Pacific DC Intertie Upgrade

The Pacific DC Intertie (PDCI) was upgraded at the Oregon end. This upgrade increases the 

line’s capability for north-to-south flow. The capability remains the same for south-to-north 

transfer, at 3,100 MW. The longer term plan is for the upgrade to raise the north-to-south limit to 

3,800 MW. We used that limit in this work. At present, only a portion of the increase from 3,100

MW to 3,800 MW is allowed for operation.

For the heavy summer case, we increased transfer to this future 3,800-MW limit. For the lighter 

load case, the transfer is south-to-north. In both cases, we have not altered the HVDC dynamic 

model; instead, we added positive and negative loads at the rectifier and inverter, respectively, to 

capture the increased transfer. An estimate of the incremental losses is included (i.e., the 

incremental power coming out of the HVDC “addition” is less than that going in.) 
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2.7.2 Improvements to Accommodate Increased Solar Production

Many other local reinforcements were carried forward from WWSIS-3 and WWSIS-3A. These 

were additions to the light spring base that allowed the two retirement cases for this study to 

avoid severe overloads or local voltage problems. To accommodate the higher level of solar 

generation, many 230-kV line and 230-/500-kV transformer additions were made.

These transmission improvements were made in the narrow context of relieving local thermal 

and voltage problems, and they were emphatically not the result of a larger transmission 

expansion planning exercise. Clearly, such detailed planning would be necessary as actual solar 

projects are proposed. Improvements included:

• Added segments of 230 kV, 345 kV, and 500 kV

• Added transformers of 230/500 kV 

• Additional reactive compensation.

In all cases, new circuit elements were added in parallel with existing circuits (e.g., in several 

locations, single circuits have been converted to double circuits). No new routes were created, 

although wider rights-of-way might be required. The transmission additions are shown in Table 

4. The two highlighted circuits were needed for the heavy summer cases (after the other lines 

were added for the lighter load case). New transformers are shown in Table 5. Reactive 

compensation additions are shown in Table 6 and Table 7. Note that these compensation 

additions are in the Nevada desert, where a considerable amount of solar was added.

Realistically, the amount of solar added in that region would require a more comprehensive 

transmission expansion plan rather than the piecewise stopgap approach used here. We made 

enough improvements to avoid creating localized stability problems that would compromise the 

larger picture results of the study.
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Table 4. Transmission Additions
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Table 5. Transformer Additions

Table 6. Capacitor Additions

Table 7. Heavy Summer Synchronous Condenser Additions 

Eleven CSP units and one combined-cycle plant (Blythe) needed to have power system 

stabilizers added to alleviate damping problems in the retirement cases as well.

2.8 Heavy Summer Retirement Case 

The heavy summer case includes the PDCI upgrade, the transmission improvements, and the unit 

retirements. The regional commitment and dispatch are shown in Figure 7. The imports and 

dispatch are shown in Figure 8. Under these conditions, there is still substantial export from the 

Southwest. The Northwest is also exporting to California, a typical condition for heavy summer 

loads.
18

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Figure 7. Final commitment and dispatch for heavy summary retirement case

Figure 8. Final dispatch with imports for heavy summer retirement case 
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2.9 Replacement of CSP with PV (CSP-to-PV) Sensitivity Case

The light spring base case includes approximately 900 MW of CSP plants. The new lighter load 

case has approximately 10 GW; however, since the development of these cases, the market for 

CSP in the western United States has largely disappeared. Many proposed CSP projects have 

been canceled or converted to utility-scale PV projects. For this study, all the CSP plants in the 

original light spring case were retained. All other CSP plants were converted to utility-scale PV,

with the plant MW rating retained in the conversion. The net result was that 78 plants totaling 

approximately 7.6 GW dispatch were converted from CSP to utility-scale PV, retaining the same 

power production.

Table 8. Dispatch of CSP-to-PV Sensitivity Case
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3 CSP Model Validation

The dynamic models of the CSP plants added for this investigation are based on the 

characteristics of actual CSP plants operating in the Western Interconnection. Validation of those 

models are presented here.

WECC/NERC rules dictate that the dynamic performance of stability models for operating 

power plants be periodically validated. The resulting validated models are documented and 

provided to WECC. The project team obtained field-test reports for two operating CSP plants in 

the Western Interconnection:

• Genesis Plant (by GE Energy Consulting)

• Mohave Plant (by Kestrel).

Both are in the Mohave Desert.

The approach used for model validation here was to implement the parameters from the field 

tests in a single plant model for all CSP plants in the study cases. The validation then repeated, as 

possible, the field tests used for the commercial reports.

Plant models have standard components for the generators, excitation systems, and the one 

turbine governor as follows:

• NextEra Genesis 1 Plant 

o Genrou

o Esac7b

o Pss2b

o Ieeeg1.

• Mojave Plant 

o Genrou

o Esst4b

o Pss2a.

The representation in these tests had some additional refinements. For example, the Genesis unit 

in the WECC model did not have the rating. This test model was updated to available data for the 

physical plant.

3.1 Exciter Model Validation Testing

These tests gave the same stimulus, but there is no record of the condition or short-circuit 

strength of the Western grid when the tests were performed. So, for example, a voltage reference 

step test should exhibit the same general speed and dynamic performance, but the magnitude of 

the response will vary with grid operating condition. This difference was observed in these tests.
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Figure 9 shows the field measurement and simulated response of the Genesis exciter and voltage 

regulator model. As required, the simulation model does a good but not perfect job of capturing 

the response to step tests.

Figure 9. Excitation test of Genesis CSP plant

In Figure 10, the same voltage reference step test is applied to the Genesis plant in a study 

database. The performances are very close, but the VAR swing is less in our test. The power 

bump is slightly smaller, too. The behavior is consistent with a weaker grid, which in turn is 

consistent with expectations of a future system with fewer synchronous machines and more 

inverter-based resources. This means that relatively fewer VARs are needed to move the voltage.
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Figure 10. Simulation validation of exciter model(s)

The behavior of the Mohave plant was also checked, with similar results.

3.2 Governor Model Validation Testing

Figure 11 shows the governor test on the Genesis plant. Note that no governor tests were

performed on the Mohave plant because the steam turbine is operated with steam valves wide 

open, and therefore it provides no governing behavior. This control, or lack thereof, is important 

for this study, and it is discussed at length later.

As with the exciter test, the governor model produced a good match to the physical field tests.

For a 10-MW reference step, the speed of the turbine response was approximately 0.7

MW/second. The speed of response plays a key role in frequency control, and it is examined 

later.

The simulation model in the study database, shown in Figure 12, produced a good match, as 

expected.
23

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Figure 11. Governor test of Genesis CSP plant

Figure 12. Simulation validation of governor models
24

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In summary, the models from the commercial validation tests were implemented in the study 

models. The performance of these updated models is consistent with the field tests and model 

validation for the conditions in the study model.

The performance of the generic governor model used across the system representation for new 

plants is very similar to the one available from field tests for system-wide frequency events. The 

models used for the investigations of this study provide a good baseline of realizable, validated 

performance.

3.3 Load Model Validation

The dynamic behavior of loads, and now of load equivalents with lots of embedded solar 

photovoltaics, has been shown in our earlier Western Wind and Solar Integration study work to 

have a significant impact on bulk system performance. Since the behavior of the loads is known 

to have an important impact on stability simulation results under some conditions, having 

validation of the model behavior (compared to observed actual behavior) will contribute to

confidence in the overall study findings. There is a relative paucity of field validation of the load 

models, so an effort to validate the dynamic behavior of the modeled load was made.

We obtained some high-resolution measurements of load behavior at a low-voltage load node in 

the system. Then we identified a few significant frequency events in the Western Interconnection

that corresponded to times when we had data. It was our hope that we could show a comparison 

of a composite load with measured data for validation.

Figure 13 shows measured frequency for an actual event on the left and the active power at the 

measured load node on the right. The frequency signature is characteristic of events in the West, 

and it is of the variety specifically targeted by the NERC BAL-003-1 frequency response 

obligation (FRO). The active power signal for the same time shows no observable response to 

the frequency event. This is surprising and at odds with accepted wisdom about composite load 

dynamics. Another event shows similar insensitivity to frequency for this load node.

Figure 13. Load data March 30, 2012, 10–11 a.m.

-30000

-20000

-10000

0

10000

4:03:22 PM 4:04:05 PM 4:04:48 PM 4:05:31 PM 4:06:14 PM

Real Power

59.8

59.9

60

60.1

4:03:22 PM 4:04:05 PM 4:04:48 PM 4:05:31 PM 4:06:14 PM

Frequency
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A second look at the measured data was made to see if there was useful information in the lowamplitude, continuous variation in load and frequency at the bus. A linear regression of the data 

shows a very high sensitivity to frequency: on the order of 10 to1, which is many times as great 

as conventional modeling assumes. Although the regression shows a steep slope, the scatter of 

the data makes the regression of questionable usefulness. A second set of data showed similar 

lack of observable dynamic response with frequency and questionable correlation of load and 

frequency.

In short, this exercise produced no meaningful insights into the load dynamic sensitivity to 

frequency. This is a small sample, so broad conclusions are not warranted. Nevertheless, this 

reinforces the need for the industry to give further attention to load modeling, including doing a 

better job of capturing the effects of short-term frequency excursions.

The study continued to use the present state-of-the-art WECC composite load model with 

embedded PV, as shown in Figure 14. The details of the behavior of the Western Interconnection 

node from this exercise are shown in Figure 15. The event has both voltage and frequency 

swings. The behavior of the load model shows a significant reduction in power during the swing, 

at least some of which is attributable to frequency.

Figure 14. Composite load model with embedded PV
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Figure 15. Dynamic behavior of composite load model for a selected bus

In summary, we regard the load mode validation exercise to be inconclusive, and we have 

proceeded with the best available load modeling using the WECC composite load model (WECC 

2012).
27

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4 System Characterization

In this section, several key elements of the various study databases are compared. The intent is to 

provide quantitative reference to how system characteristics change with the addition of large 

amounts of solar and wind generation.

In most of the results presented in these sections, the four lighter load conditions discussed above

are used.

4.1 System Inertia

As wind and solar generation displace other, mostly thermal resources, the total inertia on the 

system tends to drop. As noted in earlier work (Miller et al. 2014a), this drop in inertia is often 

incorrectly used as a shorthand for a spectrum of frequency control problems that can accompany 

this displacement. Nevertheless, having the system get “lighter” does affect the dynamics of 

frequency.

Figure 16 presents the four related measures for the four spring cases (the original light spring 

base case; the light spring high-mix case; the new lighter load retirement case with new CSP; and 

the sensitivity case, in which most of the possible CSP comes in as utility-scale PV.

In the top left of the figure, the inertia of the system, given in units of MW-sec is provided. This 

is the megavolt ampere (MVA) rating times the H inertia constant of every synchronous machine 

that is committed. The purple arrow highlights the fact that from the original planning case to the 

PV sensitivity case, the system inertia declines by approximately one-third (32.9%). The trace on 

the top right is the total MVA of the synchronous generation running (committed). It drops a 

similar amount, which means that the average inertia constant, shown in the lower left, changes 

very little. That is, the “system” inertia constant stays approximately 3.7–3.8 MW-sec/MVA.

This last observation means that the mix of synchronous generation that remains committed has 

approximately the same individual inertial characteristics as those being decommitted to make 

room for the solar. Finally, the trace on the lower right reflects the fact that the load has dropped 

from the earlier cases to the lighter load cases for this study. The amount of inertia per unit of 

load drops 20%, which in a sense normalizes the reduction in inertia resulting from the added 

inverter-based renewables. CSP is synchronous, so the change between the third and fourth cases 

in each plot is solely caused by the loss of inertia from converting new CSP to PV.
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Figure 16. Spring: Western Interconnection system inertia

Figure 17 shows the change in inertia for the four regions. As wind and solar are added, from the 

spring base case to the high-mix case, the biggest change is in the Northeast, where the green 

arrow highlights the fact that coal was mostly on the margin and displaced by the added wind 

and solar. Then, as load dropped, relatively little fossil-fueled generation was left that could be 

dispatched down or decommitted; and hydro in the Northwest was substantially reduced, as 

highlighted by the red arrow. Finally, the CSP that changed to PV was mostly in the Southwest, 

highlighted by the purple arrow, with some in California as well.
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Figure 17. Spring: regional impact on inertia

4.2 Short-Circuit Strength

Grid strength is a concern with inverter-based variable renewables (CIGRE 2016.) The shortcircuit strength of individual nodes is one metric of system strength. In this set of evaluations, we 

examine what is happening to short-circuit strength (measured in MVA) at every bus of 230 kV 

and more.

We are primarily concerned in this investigation with changes in short-circuit strength and with 

locations that are weak relative to the inverter-based generation that the node hosts. Three factors 

enter the picture:

1. The decommitment of synchronous generation displaced by wind and solar reduces shortcircuit strength.

2. The addition of new transmission (as described mainly in Section 2.7.2) increases shortcircuit strength.

3. The addition of CSP generation increases short-circuit strength.

In the following figures, we looked at short-circuit strength for each of the four lighter load 

cases. Further, we looked at changes using the lighter load case as a reference. For example, we:

1. Calculated short-circuit strength MVA for all buses 230 kV and more for the four lighter

load cases

2. Plotted these quantities, sorting from high to low for the lighter load (labeled SC MVA 

LL) case
30

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3. Calculated the change in short-circuit strength going from the lighter load (SC MVA LL) 

case to the other cases (and plotted from high to low for the PV sensitivity case)

4. Calculated the percentage change in short-circuit strength going from the lighter load

case to the lighter load PV sensitivity case (using the following formula):

A total of 2,056 buses were considered. Figure 18 gives the absolute short-circuit strength for the 

four cases. The points are each for the same bus, with the lighter load case buses (in grey;

difficult to see) sorted from highest to lowest short-circuit strength. Very few buses have very 

high strength, and many are in the range from 20,000 MVA to a few thousand. The relative 

change, which is shown in the other case by the colors above or below the curve and then again 

in the lower curve, only shows the change (delta) from the lighter load case. There are some 

interesting trends to observe. The lighter load case tends to be stiffer than the PV sensitivity case 

(grey lines in the lower plot). This is as expected because everything between the two cases is the 

same except for the inverter PV being substituted for synchronous CSP. The high-mix case tends 

to be stiffer (orange, below the line), but there are many exceptions (above the line) where added 

transmission or added CSP have stiffened the system even though the load and other generation 

has dropped. 

Figure 18. Spring: impact on short-circuit strength
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These results are for the entire system. Much of the CSP of interest is in Southern California 

Edison (SCE) zone, so we looked more carefully at SCE buses. There is a lot of new solar, and 

we added a significant amount of 230kV transmission to accommodate it. Figure 19 plots the 

changes for the SCE buses of 230 kV and more. The balloons highlight some interesting points

that are consistent with those raised earlier. The trends reinforce but do not point to specific 

buses to be studied. Short-circuit strength is a location-specific metric, and individual nodes 

become important. Many buses in Figure 18 have very small short-circuit MVA change. We are 

interested in locations that experience substantial change so that we can look for significant 

stability effects associated with the difference. Figure 20 shows the geographic distribution of 

buses that experience a substantial (more than 10%) drop in short-circuit strength when the CSP 

is converted to PV. Not surprisingly, a number of nodes show very large drops (the deeper 

colors).

The locations in this figure that are the weakest, which have the biggest difference between CSP 

and utility-scale PV and have relatively large amounts of new solar generation, are candidates for 

closer investigation. Results of this investigation are presented in Section 10.

Figure 19. Short-circuit strength detail in SCE Zone
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Figure 20. Changes in short-circuit strength from lighter load to lighter load PV-to-CSP case

4.3 Simultaneous Nonsynchronous Penetration: General Discussion

SNSP is a metric of the degree to which the grid depends on power that is delivered through 

inverters (and not synchronous machines).

It was originally introduced by EirGrid, the grid operator for Ireland (O’Sullivan, Rogers, and

Kennedy 2011), and it is presently a key metric there in limiting the instantaneous penetration of 

inverter-based resources (i.e., wind plus HVDC). EirGrid calculates SNSP using the dispatch of 

resources. It is basically the total generation from wind and HVDC divided by the total 

generation from all resources. Today, EirGrid limits SNSP based on transient stability 

limitations. Having started with a limit of <50%, they have been meeting their objective of 

raising that limit by 5% per year, reaching a limit of 60% today. Today, wind power is curtailed 

to adhere to the limit. They have a goal of raising that limit to 75% by 2020 (EirGrid 2015).

EirGrid’s long-term (2030) goal is to be able to accommodate 100% instantaneous penetration.
33

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EirGrid pioneered the use of SNSP as metric of system behavior and a quantitative limitation on 

system operation. EirGrid limits system operation based on a maximum allowable SNSP, has 

been stepping up in 5% increments over the past few years towards the 75% target. SNSP is a 

piece of the puzzle in understanding system performance with high penetrations of inverterbased resources. It is a systemic metric for which we are trying to understand the implications for 

the Western Interconnection and other U.S. grids. The work reported here builds on the SNSP 

investigation of WWSIS-3. Figure 21 shows the SNSP and the contributing elements for the 

lighter load case. The SNSP is 58%, which puts it squarely in the range considered the present 

limit by EirGrid. The genesis of the EirGrid SNSP limit is primarily transient stability. Hence, 

use of actual generation levels, i.e., dispatch, is a rational metric.

EirGrid applies the SNSP metric at the systemic level (i.e., all of the Irish grid); however, the 

Western Interconnection is much larger, both geographically and in terms of total rating. Figure 

22 shows the SNSP and contributing elements from the four regions (of Figure 1). The 

Northwest has an SNSP of 77% in the lighter load case because there are large amounts of wind 

generation in the region, and we have decommitted hydro (as discussed earlier) to rebalance the 

system at the lighter load condition.

Other concerns, particularly with respect to inverter stability, are arguably more tied to the 

ratings of equipment relative to the total system. Figure 23 shows the SNSP metric calculated

based on the rating of the operating equipment rather than the dispatch (or production). The high 

level (84%) in the Northeast was examined in WWSIS-3.

Figure 21. Lighter load simultaneous nonsynchronous penetration for system based on 

generation (dispatch)
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Figure 22. Lighter load regional simultaneous nonsynchronous penetration based on generation 

(dispatch)
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Figure 23. Lighter load simultaneous nonsynchronous penetration based on capacity (generator 

rating)

4.3.1 Simultaneous Nonsynchronous Penetration: Effect of CSP to PV

Conversion on Lighter Load Results

The sensitivity case in which new CSP is replaced with utility-scale PV has a substantial effect 

on the SNSP in the Southwest, particularly in Arizona. Figure 24 illustrates the impact on the 

entire system, with the approximate 10-GW conversion of CSP to PV causing the system-wide 

SNSP to rise from 58% to 67%.

The regional effect is more pronounced, as shown in Figure 25, where the SNSP in the 

Southwest rises from 28% (Figure 22) to 57%. The split between inverter and synchronous 

generators is shown in even finer granularity on Figure 26. Some of the smaller areas, such as 

New Mexico, have relatively high levels of inverters (red portion of bar). But as Figure 27

shows, the Southwest region is dominated by Arizona. The relative performance of Arizona 

between the two conditions is examined in some detail in Section 10.
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Figure 24. Contribution of CSP to reducing simultaneous nonsynchronous penetration
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Figure 25. Simultaneous nonsynchronous penetration for CSP-to-PV sensitivity
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Figure 26. Lighter load CSP-to-PV case distribution of inverter-based resources 

Figure 27. Lighter load CSP-to PV case changes in resources in the Southwest
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5 System Transient Stability Performance 

5.1 Overview

Transient stability is one of the limiting dynamic phenomena in the Western Interconnection. In 

preceding WWSIS, we provided background discussion of the technical basics of Transient 

Stability (Miller et al. 2014a, Section 1.1.3]

5.1.1 Transient Stability Visualization

Here we present a simple visual model intended to help understand the basic problem of transient 

stability in interconnected systems, that we have used in previous Western Wind and Solar 

Integration studies (Miller et al 2014a).

In addition to maintaining the balance between electricity generation and electricity demand, 

power system operators must ensure that the grid can successfully transition from normal operation 

(e.g., all transmission lines and generating units are in service), through a disturbance (e.g., an 

abrupt outage of a major transmission line or large generator), and into a new stable operating 

condition in the 10–20 seconds immediately following a disturbance. The ability to make this 

successful transition is called transient stability. 

Figure 28 shows an updated visualization of the problem originally presented in Elgerd (1971) to 

include wind and PV. The round masses (inertias) represent generators, with the tension on the 

various springy lines representing power transfer. The board at the top represents the simplified 

idea of an infinite bus—a real, finite power system is floating. The level at which it is floating is a 

proxy for frequency, which must stay close to 60 Hz. The hands represent wind and PV. They put 

tension (inject power) on the system, but they are all control and not weight. The mission of these 

devices, unless taught to do otherwise, is to pull uniformly, regardless of whether the node to which 

they are connected is moving or not. 

The scissors represent a disturbance, which might cut a line or disconnect a generator. The rubbery 

mass-spring system bounces around. If the event is too severe or some of the lines are stretched 

too taught (too much loading), more lines will break. It is easy to imagine a cascading failure in 

which each successive break leads to another failure. A substantial part of system planning is aimed 

at avoiding such unacceptable consequences.
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Figure 28. Visualization of transient stability with synchronous generators and wind power plants

U.S. interconnections have a long history of constraints because of transient stability limitations 

that vary depending on system characteristics such as electricity demand (e.g., peak summer load), 

the power flowing on the transmission system (e.g., heavy flows on critical paths), and the location 

of the generating plants in operation (e.g., remote from population centers). Transient stability can 

be both systemic and local. The primary performance criteria follow NERC and regional reliability 

entity standards.

5.1.2 Previous Transient Stability Work: Western Wind Solar Integration Study: 

Phase 3 and Phase 3A

In WWSIS-3a, we conducted extensive experiments on the transient stability in eastern 

Wyoming, which has a very high level of exported power generated by inverter-based resources 

in the study cases. In that work, we found that the exporting system tended to have good stability 

limits and high levels of export were achievable, potentially higher than could be achieved with 

export from synchronous generation. We also found evidence that the system, when pushed to 

transient stability failure, tended to lose synchronism faster and with less warning (i.e., the 

system stability performance looks good until the system is very close to the limit).

In that investigation, more emphasis was placed on understanding the local behavior driving the 

stress and instability. After diving into the details of the characteristics of the system instability, 

the investigation turned to potential system adjustments and control features of wind turbine 

generators as means to reestablish stability.

Note that the current study is an investigation to increase understanding about how highly 

stressed systems with high levels of wind and solar generation and low levels of synchronous 

generation behave in the system nearer the bulk of the system load and with emphasis on solar 

generation rather than wind generation.

As noted earlier, the industry has limited experience with large, geographically diverse grids in 

which solar and wind generation have displaced most of the synchronous generation.
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5.2 Regional Transient Stability Impacts of Required Transmission 

Changes

The addition of new transmission elements to accommodate the steady-state thermal and voltage 

requirements was described in Section 2.7. These transmission changes will alter the transient 

stability of the system as well. In this section, we present investigations of the impact of these 

transmission changes on the system transient stability. 

5.2.1 Heavy Summer Pacific DC Intertie Event Case: Initial Investigation

The disruption of flow on the PDCI is a severe transient stability event. In past WWSIS studies, 

a simplified version of the event was run in which the HVDC terminal is blocked, but none of 

the other remedial action schemes are engaged. The intent was to examine the differences caused 

by the changes from the addition of solar and wind resources rather than to evaluate exactly 

whether the case is stable or not.

In this study, we continued that investigation. As noted, for this study we upgraded the PDCI 

capability to align with its planned future capability. Figure 29 shows the heavy summer highmix case and the new heavy summer retirements case. As in earlier studies, the high-mix case is 

unstable without the remedial action scheme, with a loss of synchronism and system separation 

occurring at approximately 5 seconds. By comparison, the new heavy summer case with 

retirements and added transmission for the new solar power plants is stable. The key path flows 

for the successful new case are shown in Figure 30.

This result was something of a surprise because the transmission and generation additions were 

mostly rather remote from the California-Oregon Interface (COI) stress points mostly affected by 

the PDCI event. This surprising result led to into a more detailed investigation, which is reported 

next.

On a final note for this section, the PDCI event for the lighter load case is relatively 

uninteresting. As noted earlier, because there is substantial excess of generation in the southern 

half of the system, the PDCI is operating from south to north, exporting power from the Los 

Angeles basin. When the DC is blocked, the system tolerates the extra power in the South 

without major stress on the systems.
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Figure 29. Frequency Pacific DC Intertie result
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Figure 30. California-Oregon Interface Pacific DC Intertie event: key path flows

5.2.2 Investigation of Transmission Additions Impact on Transient Stability for 

Pacific DC Intertie Event

The first test performed to try to understand the change in stability for the new heavy summer 

case with increased solar was to check the impact of the PDCI upgrade on the heavy summer 

high-mix base case. The case with only higher PDCI power was, as expected, considerably less 

stable, since the disturbance is bigger and the transmission hadn’t changed. We expected that the 

addition of the other transmission, which was needed for the new heavy summer case, would 

improve the performance of the original heavy summer high-mix case. Again, however,

somewhat counter to our expectations, the case with more transmission is less stable, as shown in 

Figure 31. Note that both cases are unstable, but the added transmission (mostly in Southern

California and Arizona) results in the system separating faster, i.e., it is less stable.
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Figure 31. Pacific DC Intertie disturbance performance degraded by transmission additions

Closer investigation of the flows, reactive power balances, and voltage profiles throughout the 

system provided some insights. Some key path flows are shown in Figure 32. We also tested a 

long sequence of intermediate steps, adding pieces of the total transmission additions (from 

Table 4). Each successive stiffening of the system in the desert resulted in somewhat worse 

performance for this specific event. We concluded that strengthening the grid to the south, and in 

particular the Arizona and Southern California region, results in the swing stress on the COI and 

Northern California being slightly faster and more acute.
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Figure 32. Path flow comparisons for PDCI disturbance showing performance degraded by 

transmission additions

5.2.3 California-Oregon Interface Event

For further investigation, we designed a test case that stresses the system electrically closer to the 

reinforcements. A COI event was created in which we trip all three 500 kV lines across the COI 

border. The case was created so that power from the Northwest that would have crossed into 

California on the COI needs to loop around toward the east and across the Colorado River 

interfaces to the south. The comparison of performance shown in Figure 33 is for the heavy 

summer high-mix condition with and without the new transmission added. Again, both cases fail, 

but the case with new transmission holds on longer. It is more stable. The separation occurs 

farther south for this event, nearer to reinforcements. This result is as expected because the 

reinforcements tend to support the part of California starved for power by the trip of the COI.

The overall observation for the COI event is that the added transmission in Southern California 

and the Mohave Desert improves performance for events that depend on that path. 
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Figure 33. California-Oregon Intertie event stability test details 

5.2.4 Overall Observations on Transient Stability Impact of Transmission 

Additions

Additional transmission, necessary to avoid local voltage and thermal problems that accompany 

the significant build-out of solar in Arizona and California, impacts the transient stability of the 

bulk power system. The impacts might be positive or negative, depending on the event. The 

differences in performance are not dramatic; the most observable changes in the stability 

behavior tend to be variations in the timing of instability, advancing or retarding separations by a 

second or so. 

Good but well-established system planning practice will need to accompany the build-out of 

transmission and the addition of solar power plants, as it would for any other major system 

changes. There is no obvious change in practice required based on this narrow investigation.
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6 Frequency Performance

6.1 Frequency Response Overview

6.1.1 Frequency Response Visualization

The need to manage grid frequency has been addressed in several of the studies that preceded

this work. Here we present a brief tutorial and visualization of frequency response that is adapted 

from earlier reports.

To reliably operate a large interconnected electric grid, such as the Western Interconnection, 

requires a constant balancing of electricity generation with electricity demand. Electricity must 

be generated at the same instant it is used, so operating procedures have developed to forecast 

electricity demand, schedule electric generators to meet that demand, and ensure sufficient 

generating reserves are available to respond to forecast errors and system disturbances. The 

measure of success in this balancing act is frequency. In North America, that means maintaining 

system frequency at or very close to 60 Hz, as shown in Figure 34.

However, disturbances do occur, including large ones (e.g., abrupt outage of a large generator or 

a major transmission line) that affect overall system frequency. For example, a transmission line 

outage might disconnect a large industrial customer. As a result, the total electricity generation 

exceeds the total electricity demand and frequency rises. Because operators, in general, have 

more control over generation than demand, they can execute a generation reduction to regain the 

balance, and return system frequency to near 60 Hz.

A potentially more significant problem is the loss of a large generating plant. As a result of this 

type of disturbance, the total electricity demand exceeds the total electricity generated and 

frequency drops as shown in Figure 35. In general, an electric grid is designed and operated to 

withstand the loss of the single largest generator; however, the loss of multiple generators or 

plants might cause the frequency to drop significantly, such that protective devices act to 

disconnect customers to preserve the bulk of the system. It is a serious reliability failure when 

operators lose the ability to supply all the electricity needed to meet demand.
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Figure 34. Balance analogy for frequency stability

Figure 35. Electricity demand exceeds electricity generation and frequency drops

An example of system frequency in response to a large generation trip is shown in Figure 36.

The system is operating normally, with a frequency of 60 Hz, up to 1 second. At that time, a 

large generating unit is abruptly lost. Load now exceeds generation, so the frequency drops. The 

speed of the initial decline is related to the number of conventional synchronous generators on 

the system. More generators mean more inertia, which retards the initial rate of frequency 

decline, the rate of change of frequency (ROCOF); however, the slowing and eventual reversal 

of the frequency decline is emphatically not caused by inertia but rather various resources 

providing arresting power. The resources that respond to the declining frequency by increasing 

generation or reducing load before the frequency nadir are the source of arresting power. They 

Electricity

Generation

Electricity

Demand

Frequency

60 Hz

59.5 Hz 60.5 Hz

Electricity

Generation

Electricity

Demand

Frequency

60 Hz

59.5 Hz 60.5 Hz
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“catch” the system on the way down. In this example, at approximately 10 seconds, the 

frequency nadir or minimum is reached. Only resources that have acted during the time before 

the nadir are relevant to this performance. Frequency nadir is one measure of a system’s 

frequency stability—it must be above the highest level of underfrequency load shedding. At that 

point in time, the generators with governor controls have begun to act to increase power output,

and thus the system frequency begins to recover. By approximately 60 seconds, the system 

frequency has settled to somewhat below the normal operating frequency of 60 Hz. A metric of 

frequency stability is based on the change in frequency between the nadir and this settling 

frequency and the change in power in this interval. Measurements are averaged over a defined 

period following the nadir, as indicated with the brackets, and the ratio of change in power to 

change in frequency is calculated. This is called frequency response and is formally defined by 

NERC (2012a). After 60 seconds, even more generators begin to increase their power output,

and the frequency returns to normal within approximately 10 minutes. This section of the report 

focuses on system frequency behavior in the first 60 seconds.

Figure 36. System frequency in response to a large generation trip

There is general concern regarding the degradation of frequency response in North America 

during the past two decades. The decline is caused by various factors, such as the withdrawal of 

primary or governor response shortly after an event, the lack of in-service governors on 

conventional generation, and the unknown and changing nature of load frequency characteristics. 

Large penetrations of inverter-based, or nonsynchronous, generation technologies further 

complicate this issue. Without special operation or controls, wind and solar power plants do not 

inherently participate in the regulation of grid frequency. By contrast, synchronous machines 
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always contribute to system inertia, and some fraction of the synchronous generation in operation 

at any point has governor controls enabled. When wind and solar (especially PV) generation 

displaces conventional synchronous generation, the mix of the remaining synchronous generators 

changes. All these factors have the potential to adversely impact overall frequency response.

Therefore, one of the primary objectives of this investigation is to evaluate and better understand 

the impact of high-penetration solar power on system-wide frequency response to large generator 

outages in the first minute after the outage occurs and to examine the differences in behavior 

between synchronous concentrating solar power plants and inverter-based utility-scale PV plants.

6.1.2 Frequency Response Obligation

The Western Interconnection FRO is given in Table 9 and throughout the report as 

840 MW/0.1 Hz. Part of the NERC BAL-003-1 standard sets the obligation includes periodic 

update of the Western Interconnection FRO (NERC 2012b). Consequently, this is only a 

reference point, not a static and absolute statement of obligation. The other FROs in the table are 

estimates based on the heavy summer base case initial conditions using the generation and load 

from that condition as an approximation for the peak generation and load levels dictated by the 

standard. These figures are for reference only. FRO is assigned to each balancing authority in 

proportion its size relative to the entire interconnection. This calculation is only an 

approximation, and it should not be used to determine whether any balancing authority is in 

compliance.

Later, when the frequency response is calculated and compared to the FRO, the Western 

Interconnection totals always include the contribution of resources in Canada and Mexico. Only 

U.S. resources are included in the regional and area levels. 

There is also a locational aspect of FRO. NERC standard BAL-003-1 does not stipulate that the 

balancing authorities need to meet their FRO with their own resources (NERC 2012b). A formal 

contractual arrangement is required. This is still relatively new ground for the industry. 

Throughout this report and investigation, the results are reported based on how regions and areas 

meet the estimated FROs. This is not a statement that balancing authorities need to do it all 

themselves; rather these are metrics on how much the regions and entities contribute.

Table 9. Western Interconnection Frequency Response Obligation and Approximate Regional and 

Area Frequency Response Obligations

The frequency response performances of the interconnection and the individual entities are given 

by the ratio of the change in power resulting from a disturbance-induced change in frequency.

For this metric, the frequency change is assumed to be uniform across the interconnection. In the 

work presented here, the only power change measured and included in the calculations is that of 
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the turbine power of the responsive generation. Load response is not considered in the 

calculation of frequency response. This study focuses on system-wide frequency response. 

Measuring the frequency at a single node in the grid following a disturbance can be confusing 

and misleading. In the study, an MVA weighted sum of synchronous machine speeds is 

calculated and used as a composite frequency

6.1.3 Palo Verde Reference Event 

The design basis event in WECC for the NERC Western Interconnection FRO is the 

simultaneous trip of two Palo Verde Nuclear Generating Station units for a total loss of 

approximately 2,750 MW. That event is used throughout this investigation of frequency 

performance.

6.2 Impacts of CSP and Load Condition on Dispatch

The changes from the light spring high-mix case to the new lighter load case are substantial: the 

system load is much lower; several plants have been retired; and several plants that provide

primary frequency response (PFR), especially in the Northwest, have been decommitted.

The following figures show the impact on frequency response of those changes. With lower load 

and fewer responsive resources, the 2,750-MW event is relatively larger for the system. As 

expected, the system frequency excursion shown in Figure 37 is more severe for the new lighter 

load case (red trace) compared to the light spring high-mix case (blue). Figure 38 shows the 

reduction in contribution by generation in the Northwest in the top left trace. The added CSP 

shows up in the California and Southwest blocks because the CSP is included in these 

summations, but for this comparison the CSP units are not contributing to PFR (their governors 

are in baseload mode, reflecting their operation without underfrequency response). Figure 39

shows further details, including the five areas with most of the CSP. The primary frequency 

response (as shown by the change in mechanical power to the turbine-generators with active 

governors – Pmech) in the lighter load case (red trace) for those areas is somewhat greater, 

reflecting the deeper frequency excursion and reduced contribution to frequency response from 

the Northwest. This provides a useful baseline for the next exercise, in which we enable the 

governors on the new CSP plants.

The main point of this comparison is to emphasize that having additional generation dispatch 

from solar in conjunction with lower load can push frequency-responsive generation out of the 

system commitment, resulting in degraded frequency response. The performance of both cases 

meets performance criteria. A further discussion of the frequency response relative to the FRO is 

provided in Section 9. 
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Figure 37. Light spring compared to lighter load frequency (no contribution from CSP)
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Figure 38. Light spring compared to lighter load regional primary frequency response (no 

contribution from CSP)
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Figure 39. Light spring compared to lighter load regional primary frequency response in areas 

with significant CSP capacity (no contribution from CSP)

6.3 CSP Governor and Inertia Contributions

The addition of synchronous CSP generation provides system inertia, and it can provide 

governor response. Again, the lighter load case is more interesting because the system has less 

inertia and less committed generation, but the event size remains the same.

6.3.1 Lighter Load

Figure 40 shows three cases that illustrate two separate points. The red trace corresponds to the 

red in the lighter load case in the preceding three figures—that is, the CSP units are online 

contributing inertia, but there is no governor response. In the blue trace, we have enabled the 

governors (per the model discussion in Section 3.2). As expected, both the frequency nadir and 

the settling frequency improve. The green trace is for the CSP-to-PV sensitivity case. This is 

interesting because the only significant difference between this and the red case is the inertia of 

the CSP machines. As expected, the frequency drop is faster, and the nadir occurs sooner and is 

approximately 1 mHz deeper. We look more closely at this next.
55

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Figure 40. Impact of CSP governors and inertia on frequency for Lighter Load case

6.3.2 Inertia impact on Rate of Change of Frequency 

Figure 41 shows the first 2.5 seconds of the system frequency decline. (This is the same 

information as that shown in Figure 40 but magnified.) The initial ROCOF with the CSP units 

not contributing to system inertia is greater, with the green trace dropping faster. As expected, 

the blue and red traces are initially coincident because the CSP governors (blue trace) have little 

to no impact during the first 0.5 second. The ROCOF numbers in the figure callouts are based on 

the change in the first 0.5 second. 
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Figure 41. Inertia impact on initial rate of change of frequency

6.4 Locational Aspects of Inertia and Frequency Response

A locational aspect of the change in inertia occurs that impacts the frequency behavior between 

the CSP cases and the CSP converted to PV case. Figure 17 shows the changes in system inertia 

by region. Note that in that figure, the change between these two cases (lower right-hand side) is 

the most dramatic. The new CSP is in relatively close electrical proximity to the Palo Verde 

Nuclear Generating Station. That means that the added inertia “sees” the disturbance relatively 

quickly after the generation trips. 

Figure 42 plots the frequencies of the four regions. This sheds some interesting light on the 

locational aspects of frequency. The ROCOF for all these traces, summarized in Table 10, is 

calculated as the change in frequency during two periods: for the first 0.1 second and then for 0.5 

second of the event.

Because the disturbance occurs in the Southwest (where the Palo Verde Nuclear Generating 

Station is located), the initial frequency decline there occurs much sooner, and the ROCOF is 

approximately three times the system ROCOF. Further, the difference between the green trace

(no CSP inertia) and the red trace in the Southwest is most noticeable. The aggregate frequency 

(and ROCOF) in Figure 41 rather masks this locational factor. It is also interesting to note that 

the more remote parts of the system respond later in the case. That means that the ROCOF
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calculated during the first 0.1 second is actually lower for the more remote parts of the system 

compared to the ROCOF calculated during the first 0.5 second. For context, the Irish system is 

concerned with the system-wide ROCOF exceeding 2 Hz per second (Eirgrid 2015); the Electric 

Reliability Council of Texas might see system-wide ROCOF reaching as high as 0.5 Hz in the 

near future (ERCOT 2010).

This raises some interesting questions, mainly: Do we care that the ROCOF is higher? In these 

cases, the system frequency response is improved by the contribution of the CSP governors. The 

impact of inertia on frequency response and on the frequency nadir is quite small in this case.

Those two metrics have the greatest reliability and economic impact. In later sections we 

examine the control and robustness implications of the locational aspects of frequency with 

attention to options to mitigate frequency problems.

Figure 42. Locational aspects of rate of change of frequency impacts
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Table 10. Lighter Load Initial Rate of Change of Frequency

6.4.1 Locational Aspects of Primary Frequency Response

Results show that, as expected, the frequency tends to drop fastest in locations close to the point 

of the initiating unbalance. To look further into frequency response and dependence on location 

of the initiating event, a learning exercise with an event of similar size to the Palo Verde event 

was tried in the Northwest. The idea is to examine what difference the location of the event 

makes. This locational aspect is a potential concern, since if it were to be shown that the location 

of the initiating event has a substantial impact on primary frequency response, then operation and 

control strategies will need to take this impact into consideration.

The simulated event is a fiction created for this test. We did not identify a reasonable event that 

would cause an approximate 3,000-MW loss of generation in the Northwest. Instead, we added 

load in the Northwest that resulted in a similar settling frequency. A bit more load was added 

(3,000 MW) compared to the 2,750-MW loss with tripping the two Palo Verde units to get the 

same settling frequency, as shown in Figure 43.
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Figure 43. Comparison: loss of two Palo Verde units (approximately 2,750 MW) compared to 3,000 

MW load increase in the Northwest
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Figure 44. Primary frequency response: loss of two Palo Verde units compared to 3,000 MW load 

increase in the Northwest

Although the system-wide frequency response is broadly similar, the reasons why the Northwest 

required approximately 250 MW more load to get the same settling frequency as the Palo Verde 

generation loss in the Southwest are not immediately obvious. The aggregate regional governor 

responses between the two cases, shown in Figure 44, are similar and settle at almost the same 

level. This leaves loads and losses as the possible source of the difference.

The load model, described in Section 3.3, results in behavior that has a substantial dependence 

on voltage. The voltages in the Northwest are depressed by the Northwest event, as shown in 

Figure 45. The insert in the figure shows that the voltages for the Palo Verde event are largely 

unchanged. The depressed voltage results in load relief, making the event somewhat less severe 

for frequency response. This is consistent with other results shown from earlier WWSIS studies:

the voltage impact on load is a significant consideration for frequency events, and it is often 

more important than the frequency sensitivity of the load model. Voltage response to big 

disturbances has a substantial locational dependence, and as such the location of an initiating

frequency event will have some locational dependence from the load response.
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Figure 45. Voltage: loss of two Palo Verde units compared to 3,000 MW load increase in the 

Northwest

Another locational aspect is the ROCOF. As shown in Figure 42, proximity to the event is 

important. Figure 46 shows details of the regional frequencies for the two cases. The locational

aspects dominate for approximately 2 seconds. Note, for example, how different the two events 

“look” in the Northwest and in the Southwest. Even though these are events of approximately the 

same magnitude, from a frequency perspective they look very different during the first 2 

seconds. This represents an acute challenge for triggering control actions that are sensitive to 

initial frequency or ROCOF. This is an important point for system control and for frequency 

response design, which will be explored in more detail in Section 7.4.
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Figure 46. Initial regional frequency decline: loss of two Palo Verde units compared to 3,000 MW 

load increase in the Northwest

In summary of the locational aspects of frequency, in this section we have shown:

• Location has a significant impact on initial transient and measured frequency.

• Voltage impact on loads has a significant impact.

• Decisions based on local frequency to meet system-wide performance objectives should

not be made too fast.

This last point will be examined further in Section 7. 

6.5 Heavy Summer 

6.5.1 Impact of Retirements and DC Upgrade

Figure 47 shows three traces. The blue trace is for the heavy summer high-mix case. The red 

trace shows the isolated impact of the PDCI upgrade on the high-mix case—the impact is 

minimal. The green trace is for the new heavy summer retirement case. The redispatch for this 

condition results in slightly better performance for the Palo Verde event, but the difference is 

small. Basically, the frequency response under heavy load conditions for this system is not very 

interesting. It might become so in a future with even higher levels of solar. For example, if solar 

continues to grow such that instantaneous solar penetration levels under high load levels are 

high, frequency response and some of the locational issues identified for the lighter load 

condition will likely be more challenging.
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Figure 47. Heavy summer: impact of retirements and DC upgrade

6.5.2 Heavy Summer Impact of CSP Governors

The heavy summer cases have more generation committed to handle the higher loads. With more 

responsive units committed and higher inertia, the loss of Palo Verde is a relatively smaller 

event. The difference in performance when the CSP governors are turned on for the heavy 

summer retirement case is shown in Figure 48. Again, the CSP governors make a significant 

contribution to the system frequency response. 
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Figure 48. Heavy summer retirement case: impact of CSP governors

6.5.3 Localized Damping Concerns

During the development of the heavy summer retirement case, the dispatch of CSP generation 

was increased (per Table 1). Some locations in the desert areas are host to clusters of new CSP 

plants. One of the areas with several new plants in the study case is in western Nevada, with 

essentially radial transmission connection southward to the more fully developed grid to the 

north and east of Los Angeles. These plant sites were selected in WWSIS-2, based mainly on 

solar resource and location, and they are not individual proposed or actual plants. Nevertheless, 

they have realistic factors in their siting. The total dispatch from the multiple plants in the area 

identified in the right-hand side of Figure 49 was such that the plants in the area developed acute 

damping problems, as shown in the swings of the figure. This occurred even though the 

transmission had been strengthened sufficiently to avoid thermal problems in the study case. The 

poor damping was mitigated by the addition of power system stabilizers and reduction of exciter 

gains on the oscillating plants. Although these are not real plants, the incident is representative of 

a risk that is always present with radially connected synchronous plants. These damping 

problems can normally be remedied with appropriate control tuning, power system stabilizers, 

and other means. Because PV plants do not have moving parts, the risk of this type of instability 

is low with utility-scale PV.
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Figure 49. Illustration of local damping risk with CSP on long radial interconnection

6.6 North-South Separation Disturbance

Earlier work, particularly the frequency response investigation of WWSIS-3, showed that there is 

a tendency for a disproportionate amount of the system’s frequency response to come from the 

Northwest under some high wind and solar dispatch conditions. That work did not identify any 

strong concerns about this shift in the location of responsive resources for the cases investigated.

All the cases in that work were limited to individual, usually design basis N-1, events. In this 

section, we exam a broader question of location. The Western Interconnection has on rare 

occasion separated, breaking into two or more parts (Aggarwal et al. 1997).

Historically, there have been separation remedial action schemes in the West that are designed to 

create a more orderly division between the North and South under extreme disturbance 

conditions. One of the intents of these schemes is to create large electrical islands that have a 

better chance of reaching a viable equilibrium post-disturbance. To look at the impact of the 

added variable renewables in this context, we created a North-South separation test event. In 

these cases, the system is split along the interface shown in Figure 50. The reader is cautioned 

that this is a simulation experiment, and it is not intended to replicate any specific, known 

separation or the actions of a specific remedial action scheme. Rather, we are interested in 
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examining the relative impact of having the location and amount of frequency response 

generation differ between scenarios.

Figure 50. Illustrative North-South separation

6.6.1 Heavy Summer North-South Separation

The North-South separation disturbance under heavy summer load conditions, as modeled, is a 

severe event, resulting in system failure for all the cases tested. The difference in performance 

between the high-mix and the new retirement case is minimal. Figure 51 shows frequencies of 

the four regions. Note that, as expected, the two regions in the North, which are initially 

exporting to the South, experience a rise in frequency. The two regions in the South have a 

frequency drop. The two regions in the South remain connected as the frequency drops below 

59.5 Hz approximately 1 second after the event starts. At this point, the simulation is not very 

meaningful because underfrequency load shedding, which is not modeled here, would begin to 

act. It is possible, although by no means ensured, that the southern island could reach a stable 

equilibrium. The system stress is such that the Southwest and California also exhibit voltage and 

flow dynamics that are indicative of separation. Flows on key lines are shown in Figure 52. The 

separation occurs approximately 0.8 second after the event (time 1.8 seconds in plots), with 

voltages in Southern California (shown in Figure 53) showing characteristics of separation. Note

that relatively small differences in unit commitment can determine whether the system breaks up 

or not. Although the specific details of this simulation are not especially meaningful (e.g., we do 
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not have protective relaying modeled in sufficient detail to capture how the system would really 

unravel), the difference is notable. For this condition, the bulk system dynamics are highly 

sensitive to initial conditions, which can create a substantively different outcome.

From a planning perspective, this result suggests (and reinforces earlier results) that the

performance of the remedial action scheme and other protective schemes needs to be carefully 

checked, and possibly updated, to address changes in system dynamics that are likely to occur 

with high levels of variable renewables in the West.

Figure 51. Heavy summer: regional frequencies for North-South system separation

No UFLS 

modeled
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Figure 52. Heavy summer retirement case: North-South separation—key path flows
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Figure 53. Heavy summer retirement case: North-South separation—selected bus voltages

6.6.2 Impact of PV Compared to CSP on Separation Dynamics

To test the effect of synchronous compared to inverter-based solar, we tried the CSP-to-PV 

sensitivity case for the heavy summer system as well. The system with PV also separated and 

failed in California. Note that the behavior was noticeably different. Figure 54 shows the reactive 

power output of the generators in the remaining southern half of the system. The case with PV 

fails a few hundred milliseconds later, and the reactive swings as the system separates look 

noticeably different.

The case reinforces that changes in generator technology will have some impact on the dynamics 

of the system under extreme conditions.
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Figure 54. CSP compared to PV separation dynamics

6.6.3 Spring Lighter Load North-South Separation

In all the lighter load cases, the southern portion of the system exports excess generation to the 

North. This operating condition is radically different from the heavy summer case, and it has 

little resemblance to operating conditions observed in the West today.

Because the South has excess generation, the regional frequency swings following the NorthSouth separation, as shown in Figure 55, are reversed. The frequency dip in the Northwest and 

Northeast is well handled by the responsive generation there, and the overfrequency in the South 

is also moderate. This suggests that, at least under conditions of high solar production, the 

separation of the Western Interconnection might be easier to tolerate.

Fail
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Figure 55. Lighter load spring case: North-South separation
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7 Fast Frequency Response and Enhanced PV

Response

In this chapter, we examine new technology options for managing frequency, including those 

based on solar generation. Some aspects of the results are also applicable to a wider spectrum of 

inverter-based resources, particularly battery and other energy storage technologies.

7.1 Fast Frequency Response Discussion

Section 6.1 presented a discussion of frequency response and accompanying metrics of 

performance. It introduced the concept of arresting power. Historically, the early (pre-nadir) part 

of PFR from synchronous machine governors represented the vast majority of the arresting 

power.

Traditional systems relied on “spin,” of which a portion was fast enough to provide sufficient 

arresting power to avoid underfrequency load-shedding. As inertias have dropped, ROCOF has 

become steeper/greater, and the need for speed has increased (NERC 2012a). The traditional 

sources of PFR have become rarer, at least under some operating conditions with high

penetrations of variable renewable generation.

These factors, combined with the possibility for fast-acting resources enabled by power 

electronics, creates an opportunity to reward the provision of arresting power by a new product:

fast frequency response (FFR). In this construct, the sole benefit of FFR is to improve the 

frequency nadir—and avoid underfrequency load-shedding by delivering arresting power, i.e.,

injecting power in the time before the frequency nadir. Different technologies might provide 

other benefits beyond this narrow impact, but those aspects are not germane to this discussion.

The economic benefit of not depending solely on PFR can be significant, especially as ROCOF

increases and inertia decreases. Generation that might be required solely to provide PFR and 

inertia might otherwise be economically decommitted. The options are increased, with success 

now being a function of three parameters: inertia, PFR, and FFR. 

The Electric Reliability Council of Texas has led the industry in describing and quantifying the

relationship between the three (Matevosyan 2015.). Many technologies have the potential to 

provide FFR (Miller et al. 2017).

7.2 Concepts for Transient Fast Frequency Response from PV

7.2.1 Solar PV Components and Fast Frequency Response

PV has the potential for FFR capability to be designed into it. This is particularly true for utilityscale PV. In this section, we provide a detailed discussion of the fundamental concepts that allow 

PV to provide FFR.

The two most basic components of PV for the provision of AC power are common to all 

applications in power ratings ranging from a fraction of a watt to utility-scale projects 

approaching (or even exceeding) a gigawatt. The first component is a collection of 

photosensitive semiconductor cells that when subjected to photons of appropriate wavelength, 

produce energetic electrons that will flow, when allowed to do so—that is, they produce direct 
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voltage and current. The product of this DC voltage and current is power, which must be 

converted to 60-Hz AC power by the second component, the power inverters. PV installations 

consist of one or more of these modules, normally connected in parallel. For projects of utilityscale, AC collector systems resemble those of a wind power plant, with a supervisory control 

providing an intelligent interface between the grid and the plant.

For this discussion of possible FFR, a few physical elements of PV are critical:

1. DC power rating: Individual photocells typically have voltage ratings on the order of 2 V 

and current ratings very roughly proportional to the area of the cell. The details of 

voltage, rating, sensitive wavelength, temperature sensitivity, etc., vary with different cell 

designs and materials, and they are not particularly important here. The DC rating of the 

collection of cells (i.e., a “panel”) dedicated to a specific inverter is important. The DC 

rating (for this discussion) is the maximum DC power that can be produced under 

conditions of maximum insolation (sunlight energy intensity at the panel). DC rating is 

independent of the inverter.

2. AC power rating: The inverter serves the function of converting the DC power to AC.

The cost of the inverter is dominated by the AC current rating, although the rating is 

typically given in kVA at nominal AC voltage. The key point is that there is no 

fundamental requirement that the rating of the inverter “match” the DC rating of the 

panel. In practice, this has significant implications for FFR, as will be discussed below.

3. Tracking: The orientation of the panel relative to the sun dictates how much of the 

available insolation energy is converted. In general, PV installations can be fixed, singleaxis trackers, or dual-axis trackers. Tracking installations physically orient the panels so 

that they capture more energy during the course of a daily solar transit. For a given day 

and DC rating, the DC power available from the three types of tracking (for similar DC 

ratings) are conceptually shown in Figure 56.
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Figure 56. Illustration of DC power impact of tracking

4. Time of year: Shorter days and lower incidence angle affect the energy production. This 

seasonal variation has some importance, relative to the inverter rating, as will be 

discussed later.

5. Maximum power point tracking (MPPT) control: One of the functions of the inverter is to 

maintain the best DC voltage for the present condition by MPPT control. With MPPT the 

solar PV maintains the minimum of the maximum available DC power; maximum AC 

power, i.e., the inverter power limit; and power set point, i.e., a curtailment. The MPPT is 

normally a slower closed-loop control than the inverter current control loop and the 

supervisory voltage control loop. To maintain control stability between these controls, 

their speed of response is typically separated by an order of magnitude. Consequently, the 

MPPT control has a time constant on the order of a second.

6. Supervisory control: For utility-scale, transmission-connected PV installations (i.e., those 

that are most likely to be able to provide FFR), there is typically supervisory control that 

has many of the same functions as a wind power plant supervisory control. The 

supervisory control will accept curtailment (and other) instructions from the host utility 

and communicate them to the individual inverters for implementation. As in wind power

plants, there are latencies in control and communications paths that limit how fast the 

supervisory control can transfer commands to the individual inverters. Again, similar to

wind power plants, the industry has not yet been required to drive these latencies to very 

low levels.

7.2.2 Curtailment, Overload, and Fast Frequency Response

Unlike wind, no inherent energy storage is available via kinetics (i.e., the rotating mass).

Therefore, if a PV resource is to deliver any fast boost in power output, the inverter must be 

operating at an AC power transfer level that is less than the available DC power from the PV 

panel at that point in time (Kroposki et al. 2017). Under conditions when the AC inverter (and 

balance of plant) is not the limiting condition, this requires that the power production be curtailed 
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to a level less than the available power. This is a nearly perfect analog to the precurtailment of 

the wind power necessary to provide sustained FFR or PFR (Milligan et al. 2015).

The steady-state and short-term overload rating of the PV inverter can play an important role 

here. Although it is natural to think of the rating of the inverter in terms of kW, or kVA, the 

physical reality is that the rating is dominated by the current-carrying capability of the 

semiconductor valves. A simple illustration of the concept is shown in Figure 57. This figure is 

greatly simplified, but it captures the predominant character of the inverters not only for PV but 

also for Type 4 wind turbines and essentially all inverter-based energy storage devices. The 

figure is for a four-quadrant device: power can come in from the grid on the left hemisphere,

which is only meaningful for energy storage and loads, and go out to the grid on the right; and it 

can provide reactive power to the grid (northern hemisphere) or consume it (southern 

hemisphere). A key point is that P (active power) and Q (reactive power) are controlled 

independently if the device is not at its limit. But when the combination of P and Q demand 

drives the operating point against the circle, the control must decide which takes priority. The 

issue is further complicated by the reality that these limits are actually current limits—the figure 

as labeled is meaningful for nominal terminal voltage. But when the voltage rises, the circles get 

bigger; and when it sags, the circles shrink. Finally, the outer circle, which represents overload 

capability, is a function of design and time. Depending on the inverter design, this overload 

capability might be very small and very short, i.e., a few percentage points of overload for 

fractions of seconds. But other designs might have more capability, either because of more 

robust design for other considerations or as a deliberate incremental capability for short-term 

overload.

Figure 57. Inverter rating concept

Overall, this trade-off between active and reactive current capability and system voltage can be 

important for FFR. Two, not mutually exclusive, options exist: 

1. Give active power priority over reactive power. This especially makes sense if the 

inverter is operating underexcited (i.e., consuming reactive power). It will raise the 

voltage, allowing more power to be delivered for a given current. Conversely, when the 
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inverter is supplying reactive power, reducing the VARs to make room for active power 

will decrease the voltage, increasing the current necessary to deliver the same active 

power. It will be systemically dependent, and it is possible that the voltage reduction will 

negate the benefit or create other systemic problems. These considerations are situational 

and will tend to be greater in weak grid situations.

2. Drive the inverter into the overload range. This must be done carefully and with 

knowledge of the design capability of the inverter. Considerations such as ambient 

temperature and predisturbance valve junction temperature might be important if 

squeezing out every bit of power is important.

These points only make sense if the inverter is limiting the delivery of active power. The inverter 

cannot cause the PV panel to make more power than the maximum allowed by the instantaneous 

insolation.

The interplay between these two options—the system requirements and the available DC 

power—can be rather confusing. Phasor diagrams help illuminate the relationships. Figure 58

shows the current for a normal operating condition (blue dot) in which the current limits of the 

inverter are not active. The blue phasor, shows active current (Ip) being injected to the grid at a 

level of DC power (insolation), given by the vertical dotted blue line. The reactive current, Iq, in 

this quadrant is being injected into the grid to support voltage (presumably in response to 

required closed-loop voltage regulation). As long as the total current, Itotal, is within the rating 

circle, the active and reactive injections are independently controllable.

Figure 58. PV current phasor for normal operation
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As available DC power increases, the operation moves toward the steady-state current limit. In 

Figure 59, the DC power is assumed to have increased to the green vertical dashed line, whereas

the reactive current requirement remains the same. This new operating point, the green dot, 

represents operation at the steady-state current limits of the inverter. If the system reactive power 

demands (for Iq) and the available DC power (Ip at this voltage) together exceed the current rating, 

then the inverter must establish which function takes priority. If reactive support takes priority, 

which is typically the case up to the power factor required by interconnection requirements, then 

active power will be limited. Alternatively, reactive current can be reduced to make room for active 

current injection.

Figure 59. Normal operation at steady-state current limits

Giving priority to active power for high levels of insolation results in a reduction of reactive 

current injection. In the limit, the inverter could go to unity power factor without exceeding the 

steady-state current rating of the inverter.

Taking advantage of possible short-term overload rating of the inverter is illustrated by moving 

to the dashed circle in the phasor diagrams. The short-time overload rating circle can be time-, 

temperature-, and operating history-dependent. The two concepts, giving P priority and using 

short-term overload capability, can work together to provide control options for achieving FFR.

Care is required in assigning these priorities. The stability work of WWSIS-3A showed that 

giving Q priority in weak exporting systems improves transient stability.

These current-rating and DC power relationships raise an interesting new option for FFR, as 

discussed in the next section. 

7.2.3 Inverter and Panel Rating

Historically, the biggest cost component in PV systems was the semiconductor panel. Further, 

until recently, the overall cost of PV energy was considerably higher than from competing 
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generation resources. Consequently, the economics of PV design tended to strike a balance 

between using the absolute least-expensive components for the rest of the system (i.e., the 

balance-of-plant), including the inverter, and making sure that every unit of energy that the 

panels might produce would be delivered to the user (meter). Therefore, inverters were 

commonly rated to meet the maximum DC power of the panel. Further, the inverters were 

assumed to operate at unity power factor, thereby eliminating any extra current rating (and cost) 

associated with the delivery of reactive power.

Recently, two important changes have developed: the cost of panels has dropped precipitously, 

making the relative cost of inverters in the overall system much larger, and grid authorities are 

demanding (through grid codes, etc.) that PV provide voltage support and have reactive power 

capability (FERC 2005).

These factors drive different design decisions that are important for this discussion of FFR 

capability. Specifically, it is becoming common for the steady-state active power rating of the 

inverters to be less than the maximum DC power of the panels to which they are matched. The 

concept is illustrated in Figure 60. This concept presents an almost exact parallel to the “solar 

multiple” for CSP thermal plants (Jorgenson, Mehos, and Denholm 2014). That metric gives the 

ratio of the solar field rating to the power island rating.

Figure 60. DC power (different trackers) compared to AC inverter rating

The implication of this rating difference for the provision of FFR is potentially profound. If the 

underrated inverter is designed to have a degree of short-term overload and/or the inverter is 

given active power priority over reactive power delivery, then there is extra active power 

available for delivery to the grid. The concept is illustrated in Figure 61.
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Figure 61. Fast frequency response capability for reduced-rating PV inverters

This means that during any period in which the insolation exceeds the steady-state capability of 

the inverter, there will be essentially zero opportunity cost to the PV plant to provide FFR up to 

the short-time limit of the inverter and the instantaneous insolation. The owner of the PV will 

incur capital costs to have this capability. Further, this is new ground. There is not, at this 

writing, industry precedence for this approach.

7.2.4 Fast Frequency Response Control

The use of FFR, in the form of devices that can deliver a burst of arresting energy to the grid, is 

relatively new ground for the power industry. There is little experience in designing control 

systems to take the best advantage of these new technologies. In broad terms, there are two 

classes of controls: closed-loop controls and open-loop “triggered” controls.

Closed-loop controls are based on continuous measurements, usually of bus frequency, that are 

processed through transfer functions, resulting in continuously varying output, i.e., varying 

incremental active power injection. Open-loop controls are one way in character. That is, once 

certain criteria are met, the device “triggers” and provides a preprogrammed injection of active 

power. This can be as simple as a step up to an equipment (and insolation) maximum in response 

to frequency dropping below a triggering set point. This is a simple and seemingly attractive 

option. But substantial care is needed to avoid misbehavior, especially false triggers, i.e., having 

FFR actuated when it is not needed or wanted. Measuring frequency is conceptually simple, but 

in practice good measurements require at least a few cycles of fundamental frequency. So 

reliable triggering faster than approximately 50 ms based solely on local frequency 

measurements is difficult. Further, the locational aspects examined in Section 6.4 make the 

decision to trigger based on local frequency measurements difficult, and potentially unrobust. 
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In the following sections, we investigate some fundamental concepts aimed at improving 

understanding of the relationships between the timing, amplitude, and location of FFR for the 

purpose of improving frequency nadir.

7.3 Generalized Fast Frequency Response: Energy Impulse 

In this section, we consider a generalized FFR in which a pulse of energy is injected into the 

system to help arrest the frequency decline. Why “generalized” FFR? The natural assumption is 

that “faster is better,” i.e., the sooner into a frequency event that arresting power can be injected 

into the system, the better the outcome. But there are penalties for acting too fast (e.g., inability 

to confidently trigger using local frequency measurements).

In the following two sections, we explore questions of “what behaviors produce the best 

outcomes?” and “how does one make a fair comparison in the reliability value of resources with 

very different behavior characteristics in their abilities to maintain system security?” The

concepts and results present a broader framework for characterizing the quantitative impact on 

system security, particularly frequency nadir, for any resource that contributes arresting power.

The intent is to allow an “apples-to-apples” comparison between resources, so that 

compensation, via markets or other means, can:

• Reward the behavior that best meets the reliability need.

• Allow the broadest participation by resources that can contribute.

• Ensure that the right amount of resources is procured.

• Pay fairly for the benefits delivered.

In the following sequence, we present a construct for the evaluation of FFR. A sequence of tests

is conducted in which a 1,000-MW, 500-ms “block” of idealized FFR energy is injected at 

successive 0.5-second intervals (the total energy injected is therefore 500 MJ). The point of 

injection is in the middle of California at the Vincent 500-kV substation. The concept is 

illustrated on the heavy summer retirement case in Figure 62, with the baseline shown as the blue 

trace, and one perturbation. The baseline is our Western Interconnection case, subject to the 

design basis event (trip of the Palo Verde Nuclear Generating Station). The perturbation is the 

red trace, in which the energy pulse starts 3 seconds after the event starts and ends after another 

0.5 second (500 ms).
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Figure 62. Generic fast frequency response calibration simulations

The added FFR arresting energy improves the frequency nadir and delays the time at which the 

nadir occurs. This occurs, to differing degrees, for each interval up to the time of the nadir.

Obviously, FFR injections that occur after the nadir have no benefit. A composite of all the cases 

run in a sequence up to 10 seconds into the event is shown in Figure 63. The sequence of cases 

results in differing impact on the frequency nadir even though the arresting power and energy are 

the same for each perturbation.
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Figure 63. Sweep of fast frequency response impulses

The same exercise was done on the lighter load case, which is more limiting (i.e., has a lower 

frequency nadir). The results are qualitatively similar, which reinforces the generality of the 

approach. The change in nadir vs. the timing of the arresting energy pulse is shown in Figure 64.
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Figure 64. Nadir improvement compared to timing of arresting power injection

Note that injection of arresting energy later in the event has much higher efficacy at improving 

the nadir compared to injection that occurs immediately after the event starts. The efficacy 

reaches a relative maximum at about 5.5 seconds. This is because of the dynamic interaction of 

the FFR with the PFR. By allowing a more severe initial ROCOF, the PFR controls act more 

aggressively and produce better outcomes. The more aggressive response is because the speed 

governor, which is upstream in the control stream, sees a larger error sooner with higher 

ROCOF. The downstream turbine controls (e.g., the valve actuators on a steam turbine) “see” a 

larger signal sooner, and act—working through the relatively slower time constants of the 

turbines. In general, these “physical” time constants, those associated with moving valves, 

increase steam or fuel flow, are characteristics of the equipment and cannot changed by simple 

control adjustments.

The efficacy tends to roll off as the nadir approaches partly because there is less scope for 

improvement as the frequency approaches the nadir. In this case, injections up to a few seconds 

before the nadir (at about 8.0 seconds) are more effective. The authors have tested this approach 

on other systems and have found this trend. Broadly, we have seen that systems with frequency 

nadirs occurring several seconds after the event have the best efficacy approximately 1 second 
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before the frequency nadir. The behavior for a system with very fast nadirs will have different 

quantitative results. 

This might all seem rather convoluted, but the implications for most large systems are 

significant: very fast response is not necessary, and taking time to make good decisions about the

deployment of FFR is not only desirable from a robustness perspective but also more effectively

uses FFR resources with finite energy. 

7.4 Generalized Fast Frequency Response: Sustained Response

In this subsection, we look at the more common case of devices with sufficient rating to maintain 

power injection once initiated for the duration of the frequency event (i.e., at least until 

secondary frequency control kicks in).

Figure 65 shows the reference Palo Verde event (loss of approximately 2,750 MW) with two 

FFR injections. Both injections start 3 seconds into the event, and they are sustained, i.e., they 

continue to inject power for the duration of the simulations. The red trace is for 1,000 MW of 

FFR, and the blue is for 250 MW. An injection of 1,000 MW is sufficient to completely arrest 

the frequency decline and reverse it. Consequently, the frequency nadir occurs at the time of the 

FFR injection. From the perspective of understanding the efficacy of the FFR with time, this is 

too much power – that is, once the frequency decline is stopped by injection of the FFR, the time 

of the injection defines the nadir. Thus, the FFR has, in a sense, saturated. We look further at the 

amplitude later. But for 250 MW of FFR, the impact on the downward frequency trajectory is 

apparent, and the FFR clearly has a beneficial impact on the nadir.
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Figure 65. Sustained fast frequency response: two different amplitudes

Figure 66 shows the 250-MW FFR with a sweep similar to the impulse FFR in Figure 63. The 

sustained FFRs for each case are turned on 0.5-second intervals after the event begins.
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Figure 66. A 250-MW fast frequency response at Vincent 500 kV: varied trigger timing

Figure 67 shows the total results of this sweep (in blue), giving the impact on the nadir as a 

function of timing. This is an important result: the efficacy of the FFR is almost the same for 

deployments during the first 3 seconds of the event. That means that there is little systemic 

benefit in applying the FFR with undue haste. Waiting for good information with which to make 

the decision to “trigger” the FFR has a small performance penalty and might produce significant 

robustness benefits.

The second trace, in green, presents the same results except for the system where the CSP 

governors have been enabled. Note that the performance is similar. The overall curve is better 

(higher) because of the CSP governor contribution, but otherwise the impact is very similar. This 

is another significant result in that for a given operating condition, the beneficial contributions of 

multiple mitigations (in this case CSP governors plus FFR) are complementary and quite linear

(they add up). This is not to say that the impacts are linear or uniform across very different 

operating conditions.
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Figure 67. Timing and efficacy of 250-MW sustained fast frequency response

7.4.1 Linearity of Fast Frequency Response Impacts

In this section, we present a deeper look at the behavior observed between the two cases in 

Figure 65. In that figure, the large (1,000-MW) FFR reversed the frequency decline, and the 250-

MW significantly changed the trajectory and the nadir. In Figure 68, a sweep of FFR amplitudes 

is shown. Some caution is needed to read the figure. First, the amplitude of the FFR is decreasing 

from 1,000 MW from left to right, and, second, the spacing of the frequency steps is in two 

blocks, with steps of 250 MW down to 250 MW, then in steps of 50 MW down to -200 MW. For 

illumination, we have continued the exercise into the negative range. This would mean that extra 

power was withdrawn. Obviously, that is not something that would be intentional, but the 

exercise is interesting in that even down to zero and below the impact is relatively linear in the 

range from 250 MW to -200 MW. The “gain” of the system for the FFR injection now is given in 

the callout at 120 μHz/MW of FFR—i.e., 0.00012 Hz/MW, or, conversely, 830 MW, is required 

to improve the nadir by 0.1 Hz. This has similar units to that of FRO, but it is a measure of the 

efficacy of the FFR, not the PFR being measured for compliance with the FRO.

But as the FFR increases even further, the efficacy on improving the nadir declines. Between 250 

and 500 MW, the “gain” is approximately 15 μHz/MW of FFR. Further, the curve is flat down to 

500 MW. That means that any FFR greater than 500 MW immediately reverses the frequency 

Time of FFR Injection (after event initiated)
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decline, and the nadir is at the time of the injection. In the narrow context of arresting frequency 

and improving nadir, anything greater than 500 MW is wasted here. This gives an interesting 

perspective: the event is approximately 2,750 MW, but more than 500 MW of FFR produces no 

additional benefit for this specific operating condition. The FFR works as always with the PFR 

from the committed generation that has active governors and headroom to act. The FFR does not 

impact the system in isolation, and the combination of the FFR and the amount and speed of PFR 

dictates the MW level of this inflection point.

Note that as (1) system inertia drops, (2) PFR becomes slower or scarcer, and the (3) ROCOF

increases, this inflection point becomes a larger fraction of the size (in MW) of the event. The 

authors have observed this in smaller, lighter systems. In the limit—for example, as a system 

approaches no inertia—the breakpoint becomes equal to the size of the disturbance. That is, the 

FFR must fully, exactly, and quickly match the size of the disturbance to meet the frequency 

performance objective. The system under consideration in this study is far from that point.

Figure 68. Impact of sustained fast frequency response magnitude 

7.4.2 Locational Aspects of Fast Frequency Response

The results presented in Section 6.4 showed that the location of the disturbance on the system 

makes a difference in the system response, particularly during the first 1 to 2 seconds. Here we 

look at the locational aspect of the FFR.
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In Figure 69, there are five cases shown. They compare the performance for a single large FFR 

device, injecting arresting power at a single node (Vincent 500 kV) with the behavior of the 

system when FFR is provided by all the utility-scale PV throughout the West. The incremental 

MW from each utility-scale PV plant is made in proportion to its output for a total across the 

entire system equal to the amount from the single FFR device. In the figure, the red and blue 

traces represent the response to 250 MW of FRR, and the green and yellow traces represent

1,000 MW. The results for the pairs are essentially identical. That means that the primary 

benefits of the arresting power injection in terms of influencing the common-mode “system” 

frequency are not particularly location dependent. Although the location of the FFR injection 

might impact swing modes, having the injection spread geographically can result in the same 

overall performance benefit.

Figure 69. Distributed (at utility-scale PV plants) compared to single node fast frequency response 
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The FFR from utility-scale PV in these examples is assumed to be available by one of the 

techniques outlined in Section 7.2. But like the “generic” FFR at the central location (Vincent 

500 kV), these findings are not specific to FFR from PV. Rather, they apply equally to other 

resources than can provide FFR. That includes essentially any energy storage medium that uses 

inverter grid interface, such as:

• Battery systems

• Flywheel systems

• Variable-speed pumped hydro

• Ultracapacitors

• Advanced load controls.

7.4.3 Temporal Relationship Between Fast Frequency Response and Rate of 

Change of Frequency

In this section, we examine the question: Is there meaningful insight to be gained by looking at 

the temporal relationship between FFR and ROCOF? Starting with the sustained FFR analysis 

results presented earlier, we look at the impact of FFR on ROCOF.

Figure 70 shows the ROCOF corresponding to the frequency traces of Figure 66. (The plot is for 

a narrower window of time to allow clearer inspection of the period before the nadir.) This is an 

unusual plot because the ROCOF discussion is typically restricted to the initial ROCOF, i.e.,

how quickly the frequency starts to drop when the event initiates. That corresponds to the left 

end of these traces, which is approximately 0.18 Hz/s, as shown in Table 10. As the frequency 

drop is arrested, the ROCOF improves. Here the ROCOF calculation is for a 500-ms sliding 

window: i.e., ROCOF = -∆F/∆t where ∆t is 500 ms. (We opted to use a sign convention of 

positive meaning that the frequency is dropping.) The step in ROCOF corresponds to the effect 

of the FFR at that time on the frequency trajectory. The nadir is defined as ROCOF = 0.0, so all 

the frequency derivatives less than zero are after the nadir (single blue arrow at around 8 

seconds) and the frequency is recovering (as can be observed in Figure 66). A locus of points, 

each of which shows the ROCOF after FFR is injected at that time is sketched onto the figure 

(orange dotted line). The distance between the black trace and the orange trace is a metric of the 

efficacy of the FFR on improving ROCOF (i.e., moving in the positive direction). For example, 

the space between the two arrows is the change in ROCOF for 250 MW of FFR occurring at 6 

seconds. For FFR at 6 seconds, the ROCOF immediately following the injection improves about 

0.02Hz/sec. Overall, the efficacy in altering the ROCOF is similar to the change in frequency 

nadir shown in Figure 67.
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Figure 70. Fast frequency response impact on rate of change of frequency

In summary, the introduction of impulse and sustained FFR produces significant benefits on the

nadir. Sustained FFR also improves the frequency response. For this system, initiating FFR a few 

seconds into the frequency event produces most of the benefit. Because there are significant 

locational issues associated with measuring frequency and ROCOF, delaying FFR avoids 

locational issues that might result in unnecessary triggering. These findings are consistent with 

other work in the industry (Wilches-Bernal 2017).
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8 Enhanced Frequency Response from CSP

The cases presented throughout, especially those in Section 6.3, show a significant improvement 

in frequency response when CSP governors are enabled. Those cases were all using the governor 

models from the field validation (Section 3.2) on all the new CSP plants.

In this section, we explore the possibility of extracting even better frequency response from new 

CSP.

8.1 Concepts for Enhanced Frequency Response from CSP

The project team interviewed and obtained some documentation from a commercial supplier of 

CSP. In this section, we present some thoughts on how CSP steam systems might be created or 

modified to provide even better frequency response. The observations here should be taken as 

representative (of CSP steam turbines and boilers), not specific to a particular brand or in any 

way exclusive or exhaustive. 

CSP developers on the project review committee emphasized two points regarding provision of 

frequency response from CSP:

1. The fast dynamics (e.g., frequency response) of steam turbines is not significantly 

impacted by the source of heat (solar vs. fossil). The steam turbine does not care much 

whether the heat is from a solar field, a thermal storage mass, or a fossil boiler.

2. The market has not demanded and not placed a significant value on any level of dynamic 

response from CSP. Suppliers have not been motivated to improve dynamic performance

and development has been limited.

Some control basics for commercial power generation steam turbines:

• Primary frequency control is normally offered with a typical dynamic response of 

approximately 3%–5% of the turbine rating in 20–30 seconds. This response requires the 

valves to be active.

• Valves active is typically provided when the turbine is operating in the range from a low

of 40%–60% to a high of 90% loading.

• Outside of this loading range, turbine operation is with valves wide open. In this case, the 

response is too slow to be of use in the stability time frame.

• Boiler-follow means that the turbine output is determined by the boiler. Steam flow is 

constant, unless the heat supply is changed (e.g., additional waste heat going into heat 

recovery steam generator.

• Load-following is similar to boiler-follow, except the boiler set point is being adjusted to 

change the fuel delivered to the boiler. The steam supply changes much later. This is too 

slow to have any contribution to PFR.

• Units can be designed to allow PFR throughout a wider power range.

The relationship between the steam and load dispatch is shown in a greatly simplified fashion in 

Figure 71. When the valves open to admit more steam—for example, in response to the governor 
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asking for more power—the main steam pressure drops. Coincident with this, the boiler control 

increases the fuel or heat supply to help raise the steam pressure back to, and beyond, the initial

point. The time constants of this boiler step are much slower, on the order of several tens of 

seconds, and standard stability models, including those used here, do not capture any impact on 

the main steam pressure. The differences between the boiler and heat-recovery steam generator 

designs can be substantial, with some systems having much more steam inventory than others.

Consequently, controls that might improve the steam behavior cannot be captured in standard 

stability models for steam turbine governors.

Figure 71. CSP frequency control and steam balance

Some options are available to increase steam turbine dynamic performance. They involve 

dynamic control of the steam of the entire turbine system. One option, in addition to the highpressure steam valve opening, is that the unit master load control will close the steam bleedings 

connected to the low-pressure heaters and feed water tank. This diverts steam to intermediatepressure and low-pressure turbines. This also requires control of condensate to the feed water 

tanks and other steps.

The point is that the turbine can sustain higher output for a period of time (minutes) at the 

expense of efficiency. This arrangement also presents the theoretical possibility to use thermal 

storage to give the steam pressure a transient “bump” for increased power during a frequency 

event.

In the case of thermal storage that might be provided with a CSP system, the storage will make it 

possible to sustain the increased output. The speed with which the storage might augment the 

heat supply to the boiler is unknown. It is possible that the physical location of the thermal 

storage could substantively affect how quickly the storage can help.
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8.2 CSP Governor Response Compared to Inverter-Based Fast 

Frequency Response

In earlier results, we showed that the CSP governor response produces significant frequency 

response benefits. In this section, we compare the CSP to the inverter-based FFR.

For these discussions, we consider the response of the steam turbine to be PFR. To date, the 

industry has considered FFR to be from “other” resources, e.g., inverter-based generation and 

fast load control.

In Figure 72, we show an “equivalence” between the CSP governor and FFR. The reference case 

(black trace) is without FFR or CSP governor contribution. The blue trace is for the CSP 

governors enabled with no FFR. The green trace is for 250 MW of FFR without CSP governors.

The CSP governors produce a somewhat better frequency nadir (in line with the arrow and 

dotted line) than the 250 MW of FFR. The red trace is for both, showing that the impacts are 

additive.

Figure 72. CSP governor compared to fast frequency response: impact on frequency

The response of the CSP units is shown in Figure 73, with the FFR associated with the green 

trace in Figure 72 superimposed. The CSP units collectively start to respond before this FFR, and

they have reached approximately 325 MW of output by the time of the frequency nadir. When 
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viewed this way, the CSP has delivered somewhat more arresting energy (the area under the 

curves) by the time of the nadir. The better frequency nadir is consistent with the increased 

amount of energy delivered, and the CSP can be regarded as “worth” approximately 300 MW of 

FFR.

Figure 73. CSP governor compared to fast frequency response: power response

The addition of CSP governors contributes to the overall frequency response of the system.

Because all the existing governors providing PFR have fixed, linear droops, the other units 

contribute less because of the smaller frequency excursion. A geographic representation of the 

governor responses is shown in Figure 74. The dots are plants with active governors. The 

warmer the color, the bigger the frequency response contribution of that unit. Comparing the

results with (left) and without (right) CSP governors shows that other units work less when the 

CSP contributed. Figure 75 shows the difference between the plots and the incremental duty 

reduction on the other responsive generation caused by the contribution of the CSP. One unit in 

California has a very responsive governor, which is shown in red in the figure by the an

approximate 5-MW change.
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Figure 74. Synchronous units with governor

Figure 75. Delta of governor response
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8.3 Fast Valving and Enhanced CSP Response Results

To date, industry consideration of FFR has been for controllable, usually inverter-based, 

resources (PV, batteries, etc.). So far in this study we have used an open-loop triggering 

mechanism with inverter-based FFR. In earlier work (WWSIS-3 and 3A), we also showed

performance of closed-loop FFR (e.g., synthetic inertia for wind turbine generators).

But triggering mechanical valving in steam turbines by similar open-loop logic is possible. There 

is precedent for the use of fast-valving controls to combat synchronous overspeeds—it has been 

used selectively in thermal plants in the United States to manage transient stability problems

(Pasternak and Bhatt 1988).

Here we assume a frequency or special protection scheme based on triggering fast valving of the 

new CSP plants. In these cases, we trigger a fast-valving event to open the turbine valves. A 5% 

increase in power reference is injected to the control immediately (100 ms) after the event. We 

have made no other changes to the dynamic model. This is a relatively crude proxy for a 

triggered control that does not depend solely on machine speed to actuate. The triggering is very 

fast (100 ms) because the experiment was intended to give an upper bound on the benefits (for 

this model).

Figure 76 shows the incremental improvement of the fast valving on all the new CSP (green 

trace). The mechanical power from the CSP units is shown in Figure 77. An extra 132 MW of 

response is enabled by the fast valving. In this figure, note that the initial PGEN = 7,589 MW on 

a MWCAP = 10,211 MW for new CSP. This extra power is less than the 5% requested; that is, 

132 MW/10,211 MW is 1.3% rather than 510 MW.
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Figure 76. Frequency with CSP fast valving

Figure 77. All CSP response with fast valving
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To look closer, the performance of a single unit is shown in Figure 78. For this unit, the dispatch 

is 64 MW on a unit with capability of 94 MW. A 5% response on this base is 4.7 MW, so this 

unit exhibits the expected behavior. Closer inspection of other units shows that many of the CSP 

units are dispatched at or above 95% of rating, so a 5% step from fast valving cannot result in 

that increase in output. This lack of headroom is important, which is examined further in Section 

9.3 and Section 9.4. 

Figure 78. Fast valving on a single CSP unit

8.3.1 Frequency Response Comparison of CSP Fast Valving to Fast Frequency 

Response from PV

The total frequency response of the system for four cases is summarized in Table 11.

Table 11. Frequency Response: CSP Fast Valving Compared to Fast Frequency Response from PV
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From this table, and the result presented above, the overall benefit of CSP governors on nadir is

similar to approximately 300 MW of FFR. This benefit increases to approximately 415 MW with 

fast valving. This is approximately 3%–4% (3 MW–4 MW FFR equivalency per 100 MW of

CSP rating).

In summary, we find that enhanced steam turbine response is judged possible by designers of 

steam turbines interviewed for this project. The improvements are not unique to solar steam.

Sustained (or better) steam pressure by control is possible. There is some possibility that the use 

of thermal storage might be advantageous. Although the faster valving produces significant 

improvements, the ability to trigger very fast is debatable and at odds with the locational results.

Practical benefits are probably less than we have shown in these illustrations. These results are, 

in our opinion, purely illustrative. A detailed and fully validated dynamic model is needed to do 

quantitative analysis and benefits comparison.
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9 Sunset Net Load Ramp and Frequency Response

So far in this study we have focused on conditions of relatively high instantaneous penetrations

of solar and wind power. We have looked for a variety of stability concerns that might arise 

under those conditions and opportunities to use solar generation to mitigate those concerns and 

improve overall system performance.

One challenge that has surfaced for systems with high levels of solar is managing the system as 

the sun sets and there is a common-mode drop in the solar generation. As the solar power drops, 

there are potential issues with exhausting other resources. Thus, this class of concern is not about

high instantaneous penetration but rather what might happen shortly afterward, when the sun 

sets.

We will look closely at California for insight, but the issues are more general, and the findings

apply to other parts of the West and to other systems around the world that have or might have 

high levels of solar generation. 

9.1 Discussion: California Duck Curve

One version of the California “duck curve” (CAISO 2016a) is shown in Figure 79. The net load 

curve, in red, represents the demand that needs to be served by resources controlled by CAISO—

that is, it is the system load net of nominally non-dispatchable wind and solar generation.

“Nominally” because CAISO generally has the ability to dispatch utility-scale wind and solar 

downward but has essentially no capability to dispatch (or even “see”) distributed generation,

mainly distributed PV. There are two aspects of this net load curve that are important. First, there 

is low net load through midday, when there is heavy insolation, and high production from the 

solar generation. Second, when the sun sets, the net load grows rapidly, from the combination of 

lost solar generation and natural evening load rise. Together, these represent an operating 

challenge. , because backing down and decommitting enough synchronous resources to allow the 

system to absorb the full output of the wind and solar is challenging because resources that can 

ramp up quickly later as the sunsets are needed. To keep resources available for the evening load 

rise, some must be kept operating at low or minimum power during the middle of the day when 

there is substantial solar generation. This presents a risk of over-generation. It is this evening net 

load ramp that is the motivation for CAISO’s pursuit of new ramping products.

The two main study cases, lighter load and heavy summer, have characteristics that allow us to 

investigate the sunset operating condition. The lighter load case is a reasonable proxy for 

operation during the low net load condition that precedes the start of sunset. This is noted in the

left callout on the figure, which we added to CAISO’s drawing.
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Figure 79. CAISO duck curve

9.2 Depletion of Headroom

In the time frames that are the focus of this study, one of the most pressing concerns that 

accompany sunset from high solar, light load conditions is frequency response. During sunset, 

the system needs to fill in the rise of net load by (1) dispatching up committed generation that 

has headroom and (2) committing or starting additional resources.

In this section, we present an exercise aimed at improving understanding of the relationship 

between this net load following and the depletion of generation headroom that accompanies the 

upward dispatch. To that end, we take the extreme case of looking at what happens if all the 

decrease in solar generation is followed by resources that are already committed in California.

The case starts with the lighter load condition, which is a reasonable proxy for the high solar, 

light load condition before the sun starts to set. The utility solar generation across the Western 

Interconnection, both PV and CSP, is ramped down uniformly (in proportion to the plant 

loading) to approximate the effect of dropping insolation that accompanies sunset. The 

committed gas-fired thermal generation, including combined-cycle steam, in California only is 

dispatched upward, with the dispatch on generation outside of California left fixed. Noncombined-cycle steam in California is also left unchanged. This continues until these units are 

effectively out of headroom and cannot increase output farther. At that point, the California 
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hydro with headroom is dispatched upward. The distinction might be important because when 

modeling hydro we assume that there is sufficient water (and headroom) to allow this upward 

dispatch. A much closer look at the hydrology would be needed to confirm this. As noted earlier 

in this work, and in earlier WWSIS work, the contribution of California hydro to meeting the 

CAISO FRO is significant under these study conditions. Closer inspection of the actual 

capability and performance of these hydro plants is warranted.

In Figure 80, a profile of the California dispatch/production(orange) and commitment (blue, i.e.,

unit MW rating) for the initial lighter load condition is shown on the left. On the right, the 

dispatch and commitment for this test is shown at the end of a 4,000-MW reduction in utility 

solar across the system. Notice that the gas headroom is completely depleted and that the hydro 

headroom is greatly reduced. PV and CSP have dropped. (Note that it has dropped outside of 

California as well, so the differences in this figure do not add up: solar drop is not equal to gas 

and hydro increase.)

Figure 80. California headroom - before and after reduction of 4,000 MW of utility-scale solar 

generation due to sunset

The steady depletion of headroom from the responsive generation in California results in 

progressively worse frequency performance. In Figure 81, the system frequency is shown for 16 

successive cases, each with 250 MW less solar production than the preceding case. Each trace 

includes the amount of reduced utility-scale solar generation due to the sun setting. After 1,250 

MW of reduced utility-scale solar generation due to the sun setting, the gas-fired generation 

headroom is exhausted (the first 5 cases, as highlighted by the upper purple arrow in the figure), 

as the notation in the figure points out. From then on, the hydro follows, with progressive 

depletion of headroom (the remaining cases, as indicated by the lower purple arrow in the 

figure). As expected, the overall frequency performance degrades. By the end of the sequence, 

the margin above the underfrequency load-shedding at 59.5Hz is small, and the case is 

marginally compliant with the WECC stability criteria.

As the sequence of cases progresses, California contributes less toward arresting and restoring 

the system frequency. This is reflected as a drop in California frequency response (as defined by 

BAL-003-1). The declining California frequency response is shown in Figure 82. After 
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approximately 1,000 MW in reduced utility-scale solar generation due to the sun setting, the 

contribution of in-state generation to the California FRO drops below the target amount that was 

calculated for this study. (Per the discussion in Section 6.1.2, note that the actual figure is 

changed yearly and will likely be somewhat different.) The drop in frequency response with 

headroom is relatively linear. The orange trend line shows a loss of approximately 4.5 MW/0.1

Hz of frequency response for each 100 MW of headroom depletion.

Figure 81. Frequency response to Palo Verde event during sunset
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Figure 82. California frequency response during sunset

The impact on the overall system is similar but less dramatic. In Figure 83, the decline of

frequency response for all the Western Interconnection is shown. At the systemic level, the 

interconnection drops below the target FRO after a 3,000-MW reduction in utility-scale solar 

generation due to the sun setting. This provides something of an upper bound for the system.

Because CAISO (and all balancing authorities) have the option to procure frequency response 

services from outside, the fact that California stopped meeting its FRO with in-state generation is 

not necessarily a failure. CAISO already has mechanisms in place to procure frequency response 

from outside the state. So, from a practical perspective, the point in the sunset sequence at which 

violations of FRO occur is likely between 1,000 MW and 3,000 MW of reduced utility-scale 

solar generation due to the sun setting.
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Figure 83. System-wide frequency response during sunset

9.3 Lighter Load Low Frequency Response Sunset Sensitivity 

Investigation

The results presented in the previous section are directionally and qualitatively consistent with 

operating experience, but CAISO expressed concern that the results are overly optimistic relative 

to current and near-term future performance.

Based on discussions with CAISO, a sensitivity case was developed that reflects a condition that 

is more stressful. The commitment and dispatch of the system has the potential to have 

considerably less headroom and frequency response than the lighter load case. CAISO suggested 

that a case with less wind, lower hydro, and more PV at higher production be examined. This 

moves closer to the situation faced by CAISO now or in the near future. This is not an effort to 

replicate all the upgrades to the dynamic data set that have been instituted since this project was 

started; rather, it is a sensitivity case aimed at gaining additional insight. The changes to the load 

flow in California from the lighter load to the case with lighter load and low frequency response

were:

• Convert new wind to PV plants (with capacity of approximately 910 MW and dispatch at

340 MW).
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• Decommit some wind, with an approximate target of 6 GW in California (per current 

American Wind Energy Association figures) (American Wind Energy Association 2017).

• Hydro units that were dispatched at < 20 MW were decommitted, and PV units are 

dispatched up (total of 144 units; capacity of approximately 3,200 MW and dispatch of 

approximately 1,030 MW).

• Wind is dispatched down by approximately 1,650 MW, reflecting a lower wind condition 

that could occur under these system conditions

• PV is dispatched up, reflecting a higher insolation condition that could occur under these 

system conditions

The before and after California dispatch and commitment are shown in Figure 84. A comparison 

of the case details is given in Table 12.

Figure 84. Lighter load compared to California low frequency response case: commitment and 

dispatch
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Table 12. Lighter Load Low Frequency Response CSP Scenario

As with the previous sequence, the gas-fired generation is dispatched up first, followed by the 

California hydro. The hydro runs out of headroom after approximately a 3,200-MW reduction in 

utility-scale solar generation due to the sun setting, so the sweep is halted there. The right-hand 

side of Figure 85 shows the final dispatch at this point. A similar sweep of system frequency is 

shown in Figure 86. Notations in this figure are the same as in Figure 81. The frequency 

excursions are more severe, and the final case barely avoids underfrequency load-shedding. The 

changes in the system operating profile for this case makes California’s frequency response 

substantially worse. The frequency response for this new case is shown in Figure 87 (green trace) 

along with the results shown from Figure 82 (blue trace). Even before the sunset starts, in this 

new sensitivity case California is not meeting its estimated FRO. The decline with depleted 

headroom is similar, although the rate at which the frequency response degrades with lost 

headroom is a little greater. This reflects the reduced number of units providing frequency 

response in the case. Nevertheless, it is interesting to see how linear the behavior is. This means 

that a variety of mitigation measures might be deployed, with a reasonable expectation that they 

would be additive in their benefits. 
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The impact on all the interconnection’s frequency response is shown in Figure 88. The whole

West drops below its Western Interconnection FRO after about a 1,000-MW reduction in utilityscale solar generation due to the sun setting.

Figure 85. Lighter load low frequency response: dispatch at beginning and “end” of sunset

Figure 86. Lighter load low frequency response CSP sunset scenario
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Figure 87. Sunset impact on California frequency response: low frequency response case
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Figure 88. Sunset impact on WECC frequency response: low frequency response case

Frequency response is a key metric of system performance, but it is not the only one. The 

magnitude of the frequency nadir is also important. They are, of course, closely related. In Figure 

89, the system frequency nadir is plotted for both cases. The more rapid drop in nadir with 

depletion of the thermal headroom (i.e., to the left of the vertical blue line) is indicative of the 

faster response of the gas turbines (and corresponding penalty with depletion of their capabilities 

to regulate frequency as they are dispatched upward). The fact that the frequency nadir is a about 

59.53Hz, or 30mHz above UFLS, at the point in the sequence when the interconnection FR is at 

the interconnection FRO of 840 MW/0.1Hz, shows NERC’s intended relationship between FRO 

and avoiding UFLS. The standard (NERC 2012b) includes adjustments for real-life complexities 

such as initially low frequency, that aren’t captured in traditional stability simulations.
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Figure 89. Sunset impact on frequency nadir: low frequency response case

9.3.1 Effect of Enabling CSP Governors During Sunset

Figure 87 shows that California was initially out of compliance for the lighter load with low 

frequency response case. This means that the motivation for adding CSP governors is high. A 

comparison set of cases for the low frequency response sensitivity was run with all CSP 

governors enabled. The benefit to California is substantial, initially adding 150 MW/0.1 Hz of

frequency response to California, as shown in Figure 90. California can meet its frequency 

response for up to 1,500-MW reduction in utility-scale solar generation due to the sun setting.

As this new sweep starts, the frequency response (purple trace) initially increases, which is 

counter to expectations. Closer inspection of the frequency nadirs, shown in Figure 91, shows 

that the nadirs improve (red arrow) as the sun sets and the other generation loses headroom.
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Figure 90. Lighter load low frequency response during sunset with CSP governors on

This result can be understood by looking at the response of the CSP plants with the governors on.

In Figure 92, governor response (P mechanical) of the CSP plants for selected cases in the sunset 

sweep are shown. As the sun sets, the CSP dispatch drops. This frees up headroom on the plant.

The action of enabling the governors means that this model expects there to be sufficient steam 

(per the discussion above in Section 8) to increase plant output, at least temporarily. A closer 

look at a single plant, in Figure 93, makes the trade-off between headroom and frequency 

response clearer. For this 200-MW plant, an increase in headroom results in a better response 

from the plant. In the traces, increasing the headroom from about 6 MW (blue trace) to about 17

MW (red trace) increases the frequency response from about 6 MW to about 13 MW. This figure 

also makes it clear that having more than about 10% headroom (green trace) produces no 

incremental frequency response for the system, although the transient swing, peaking at about 15 

seconds, is a bit higher and helps the frequency dynamics. As has been observed in our earlier 

work: too much headroom on an individual unit (of any type or fuel) produces no frequency 

response benefit (for systems above underfrequency load-shedding frequency thresholds) when 

standard proportional (i.e., 5% droop) controls are used.
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Figure 91. Nadirs with enabled CSP governors
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Figure 92. CSP governor response with headroom increase
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Figure 93. Details of one CSP governor response as sun sets

However, if other controls are added to take advantage of the additional headroom, the system 

can benefit. In Figure 94, a pair of cases run at a 1,500-MW reduction in utility-scale solar 

generation due to the sun setting is shown, along with the initial, presunset case (blue trace). The 

red trace (like the blue trace) is for the response of only the governors. It is substantially better

because the incremental power delivered in the red case, with more headroom, is about 600 MW.

By adding fast valving (as discussed above in Section 8.3), the performance (green trace) is 

further improved, by another 350 MW. The callout added to the legend on the right-hand side of 

the figure shows the California and system frequency response for the three cases. The benefits 

of the CSP headroom are substantial. Remember that much of the CSP is outside of California, 

so the benefits accrue to all of the West (and to the Southwest).

The actual frequency that goes with these three cases is shown in Figure 95. This figure shows 

that, from the perspective of improving the frequency nadir, the fast valving during sunset, when 

there is more headroom, is “worth” about a 1,500-MW reduction in utility-scale solar generation 

due to the sun setting.
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Figure 94. Sunset with CSP governors plus fast valving
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Figure 95. Fast valving during sunset

Better dynamic response is effectively a postponement of sunset in the sense that it provides a

frequency response benefit like retaining headroom. The benefits of fast valving are shown with 

the red annotations in Figure 96. The red dot represents the improvement for this single fastvalving case. The red dotted line has the same slope as the frequency response trend of the purple 

and green lines. Those lines give the approximate relationship between sunset (declining 

headroom) and frequency response. We have shown that the relationship is quite linear, so the 

red dotted line is an extrapolation of the benefit with fast valving. In this construct, the fast 

valving is “worth” about a 1,700-MW reduction in utility-scale solar generation due to the sun 

setting. This is a nontrivial contribution to California’s duck curve. But whether such capability 

is possible returns us to question of whether control and/or thermal storage can be used to extract 

better—i.e., faster and more sustained—frequency response from CSP.
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Figure 96. CSP fast-valving benefit during sunset

9.3.2 Governor: Headroom, Frequency Response, and Storage

This sequence of results raises some interesting economic and technical questions. The results 

show significant frequency response benefit from CSP if dispatched with some (approximately 

5%–10%) headroom. In simple terms, this is consistent with other variable renewable work done 

earlier. That is, for wind and PV there are benefits to holding back some power (i.e., curtailing) 

to provide frequency response. 

But unlike wind and PV, there are options for storing, rather than spilling, the curtailed power 

(i.e., thermal storage) (Mehos et al. 2016). Although out of scope, some questions arise:

• Does it make economic sense to do so?

• Does it make economic sense to consider an optimization of power island (MWe) rating 

compared to solar field (MWt) rating compared to thermal storage (MWhrt) rating?

These economic questions cannot be answered with stability tools, but it is possible to provide 

some stability limit guidance, which would be essential to framing and evaluating the economic 

benefit that might be realized by using thermal storage to improve frequency performance.
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9.4 Implications for CSP Thermal Storage

Figure 97 illustrates the trade-off in dispatch as the sun sets. On the left, the figure shows the 

dispatch of the PV and CSP dropping across the system in a relatively uniform fashion. The 

orange boxes suggest the loss in production. On the right, the first block of bars shows the 

dispatch and commitment of the committed, dispatchable generation in California going into 

sunset. The second block shows the dispatch, with the change required to follow the sunset 

highlighted with the dotted lines and the up arrows. The point of the illustration is to show that if 

the dispatch of CSP could be sustained by drawing on thermal storage, it would effectively be a 

postponement of sunset. By continuing to dispatch, headroom on other frequency response 

resources is maintained, plus CSP continues to run and provide frequency response. The concept 

is illustrated by the orange locus sketched in Figure 98. In short, the thermal storage would offer 

an additional mechanism to ensure that the system has adequate dynamic range to meet its FRO. 

Figure 97. Thermal dispatch during sunset

Sunsets across interconnection Thermal generation dispatch in CA increases

Before sunset During sunset
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Figure 98. Fast frequency response and storage impact on frequency response during sunset

9.5 Synopsis of Sunset Investigation

Several key summary points can be made based on the relatively complex discussion of this

chapter:

• Sunset from the high solar condition can deplete headroom, causing problems in meeting 

FRO.

• This frequency response concern is during sunset, so it is not necessarily the high 

penetration condition but the condition that follows that is most concerning.

• Too much load following (by dispatch) without committing (starting) new resources (or 

obtaining frequency response from outside) will result in FRO violations.

• These cases show that it is possible for California to be short of frequency response; the 

new case showed the California short even before sunset starts.

• Thermal storage is effectively a postponement of sunset. Continuing to dispatch by 

drawing on the stored energy maintains the headroom on other frequency response 

resources and allows CSP to continue to run and provide frequency response.
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• Better dynamic response, such as that provided by fast valving, is also effectively a 

postponement of sunset in the sense that it provides a frequency response benefit such as

retaining headroom.

Some caution is needed in reviewing these results:

• WECC and the western utilities and operators are continuing to upgrade the WECC 

model. Increased fidelity modeling might show that these results are optimistic and that 

the available frequency response, especially in California, is more limited than these 

results indicate.

• The cases presented here are illustrative and are not a substitute for detailed planning 

studies.
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10Local Weak Grid and Regional High Simultaneous 

Nonsynchronous Penetration 

10.1Introduction

10.1.1 Weak Grid Visualization 

One of the most challenging operating conditions for inverter-based generation is in a so-called 

weak grid. But what is a weak grid? Analytical descriptions have long been available (Tande and 

Olav 2000), but the question is one of relative size: Is the inverter-based generation relatively 

small or relatively large compared to the host grid? Here we present, again, a simple 

visualization intended to illustrate the concept (from WWSIS-3A) (Miller, Leonardi, and 

D’Aquila 2015). 

Historically, wind power plants were relatively small compared to the grid. A 1-MW wind 

turbine connected to a 20-GW system has no more ability to move that system than a lap dog, 

even a badly behaved one, can bend a palm tree (Figure 99); however, as wind power plants 

became larger and are connected to smaller and more remote portions of the grid, they exert 

more influence. A 200-MW wind power plant connected to a 300-MW subsystem can now 

impact system response to a disturbance similar to the way in which an elephant can bend or 

break a palm tree unless it is trained not to (Figure 100).

It is this latter condition of high local concentration of solar, and the possible difference between 

supply by synchronous generation (i.e., CSP) or inverter-based generation (i.e., utility-scale PV) 

that is the focus of this section of the report.

Figure 99. Small wind power plant relative to

the electric grid

Figure 100. Large wind power plant relative 

to the electric grid

10.1.2 Investigation of Short-Circuit Strength on Weak and High-Change Buses

Section 4.2 showed the characterization and sorting of nodes in the system by short-circuit level 

and change in short-circuit strength caused by switching from CSP to utility-scale PV. In Figure 

1 Ton
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20, buses with large changes were shown. From among these three locations, we selected

additional scenarios for more detailed analyses. The two buses with the largest short-circuit 

MVA change are:

• Gila Bend 230 kV (Arizona):

o A reduction of 48% in short-circuit MVA occurs when CSP is converted to PV.

o Eight CSP units are connected.

o The total MVA from CSP/PV is 1,128 MVA.

o The short-circuit ratio (SCR) is 3.7.

• Eagle Eye 230 kV (Arizona):

o A reduction of 56% in short-circuit MVA occurs when CSP is converted to PV.

o Eight CSP units and 1 PV are connected.

o The total MVA from CSP/PV is 1,584 MVA.

o The SCR is 2.44.

And a third, E-W-WILD 230 kV (SCE), has similarly low system strength.

With the addition of inverter-based generation, SCR is a well-established measure of system 

strength relative to the rating of HVDC or other individual inverter-based resources, such as a 

single wind or PV site. Inverter-based generation operating with a low SCR can have control 

stability issues.

10.2Investigation of Low Short-Circuit Strength at Solar Power Plants

The large-scale system disturbances examined in Section 5.2 show modest impacts of the added 

solar and transmission. Most of the big changes to the system are in Southern California and 

Arizona, and they have the potential to alter the system dynamics considerably on a local basis.

The short-circuit screening and SNSP characterization presented in Section 4 gives a foundation 

for more detailed inspection of specific locations in the system. In this section, two locations are 

examined.

10.2.1 Gila Bend

The simulated solar development at Gila Bend is extensive, with a cluster of projects in this 

study totaling more than 1 GW. The development has a largely radial 230-kV connection to the 

500-kV backbone that runs across the southern edge of California. The 500-kV corridor is a key 

element in supply to Southern California, and generation connected to it has the potential to 

impact system security.

As noted, the Gila Bend 230-kV bus experiences a nearly 50% reduction in short-circuit strength 

when PV is substituted for CSP. Further, the radial double-circuit 230-kV path up to Gila River 

is very heavily loaded in this case. 

When the system is subjected to a fault, cleared in primary time by the removal of one of the two 

Gila Bend 230/500-kV transformers, the cluster of generation at Gila Bend needs to maintain 
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synchronism through the remaining transformer. A plot of the voltage and the power flowing 

through the remaining circuit is shown in Figure 101. The behaviors are characteristic of radially 

connected synchronous and inverter-based generation. The synchronous CSP machines

accelerate substantially during the fault, and they exert substantial incremental power into the 

grid as the synchronising torque of the grid pulls the machines back. The higher power flow and 

accompanying reactive stress results in some delay in the recovery of the voltage, as can be 

observed in the blue voltage trace. Subsequent oscillations are also characteristic of synchronous 

machines. Normally, power system stabilizers, which are mandatory in WECC, would be tuned 

to give better damping than this case exhibits. The behavior of the PV is, in comparison, 

relatively simple. There is no acceleration and no energy accumulated in the PV system during 

the load rejection. Consequently, the inverter controls act quickly to return the system to its 

predisturbance condition. The voltage immediately folllowing clearing of the fault is relatively 

high. This is partly because of the model and partly a real consequence of the reactive power 

balance during recovery of the inverter. The stability model is a bit pessimistic in regard to postswitching overvoltages because the numerical stability constraints of the model result in 

understating the speed with which the control suppresses reactive current injection on fault 

clearing. Overall, the performance of both systems is acceptable and meets WECC and NERC 

stability criteria.

Figure 101. Gila Bend disturbance: CSP compared to PV dynamics 
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To further stress this system, we tried a more severe fault with a three-phase fault and with a

stuck breaker at the Gila 230-kV bus. Again, we tripped the 230/500-kV transformer. The case is 

more severe, and we expected to have a stability failure. The CSP plant swings are more acute, 

and although the case is stable, the voltage recovery swing does not meet WECC criteria for a 

stuck breaker (Class C) event (WECC 2003). Had the power export been higher, or the 

disturbance longer, the CSP machine would have lost synchronism after the fault was cleared.

Figure 102. Gila Bend disturbance: CSP compared to PV stuck breaker case

10.2.2 Eagle Eye

The Eagle Eye 230-kV bus in the Mohave Desert has the lowest short-circuit level of the high 

solar buses screened. The solar PV at that node results in an SCR before the fault of 2.44. This is 

near the lower end of short-circuit strengths generally considered acceptable without detailed 

consideration of control stability and potential mitigation measures (discussed more later).

A test with fault and clearing of one of the lines out of Eagle Eye was run. The results were quite 

like the tests shown in the previous subsection for the Gila Bend event, even though the SCR is 

considerably lower (2.44 here compared to 3.7 for Gila Bend).

Because SCR is one of the key metrics for concern about inverter-based generation instability, a 

further test was devised in which the grid was degraded by removal of one of the 230-kV lines 

providing egress for the power from the solar power plants. In this case, the SCR before the fault 
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is 2. In Figure 103, a comparison of these two cases, with the system degraded, is shown. The 

voltages in the upper set of axes show the CSP in blue and the utility-scale PV in red. The power 

swings of the local solar power plants are shown in the next two sets, with the CSP synchronous 

machines swings in the middle and the PV power on the bottom. The swing of the synchronous 

CSP machines is somewhat greater. Both cases meet WECC criteria.

Figure 103. Eagle Eye fault: CSP compared to utility-scale PV
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Figure 104. Eagle Eye fault: with initially lower short-circuit ratio

10.2.3 Discussion of Mechanisms of Weak Grid Inverter Instability

The cases involving Eagle Eye had the lowest SCR found by the screening for this study system.

These SCR levels are not extremely low, and the authors have encountered systems in which 

inverter-based generation has been proposed for much lower system strengths. Nevertheless, for 

the solar-rich region of Southern California and Arizona, the necessity to provide adequate 

thermal capability with new transmission seems to have resulted in avoiding unduly low system 

strength.

It is worth examining the physical mechanisms by which inverter-based generation can become 

unstable. Here we provide a synopsis of three distinct (in)stability mechanisms:

1. Fast voltage collapse. Analysis of this phenomenon requires adequate modeling of the 

inverter (and plant) voltage regulator and accompanying active and reactive power 

controls. This problem is suitable for phasor analysis. (Taylor 1994) Great care is needed 

with generic models, and it is possible that some aspects of the generic models might not 

be adequate.

2. Fast regulator stability. Analysis of this phenomenon requires adequate representation of 

phase-locked loops and other synchronizing mechanisms employed by individual original 
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equipment manufacturers. These are not in standard PV models. Getting the details right 

in the models is tricky, and they vary by original equipment manufacturer. The problem 

is generally tractable using the phasor analysis structure present in transient stability 

programs, but it requires care and usually cooperation with the equipment supplier.

Generic stability models might give optimistic results, showing good performance when 

the application behaves poorly in low SCR situations. The minimum system strength 

specified by the converter supplier can provide guidance for when different models and 

tools are required.

3. Very fast firing instability. This phenomenon is not detectable or possible to model with 

phasor analysis (i.e., positive sequence/stability program). Like many other 

nonfundamental frequency phenomena (e.g., subsynchronous resonance), this risk needs 

to be addressed as a system specification issue. Composite SCR and other methods are 

suitable for risk screening. For applications that are flagged, equipment-specific 

electromagnetic transient, three phase point-on-wave (EMT) modeling is required.

Generic EMT models are mostly useless for analysis of this behavior because controls 

and equipment structures employed by individual original equipment manufacturers vary 

and are generally proprietary.

For the low short-circuit conditions being approached in the Eagle Eye (and Gila Bend) 

examination, it is possible for solar PV regulators that have not been tuned for low short-circuit 

levels to misbehave. In Figure 105, an approximately 9-Hz weak grid instability is shown. This 

event is a simulation replicating a measurement from an actual field event (the device trips at 

approximately 0.6 second). This behavior (of the second type in the listing above) can occur 

when regulator gains are too high for the strength of the system. This can occur from improper 

application and is mainly a risk when the system is degraded (as we tried in the recent case 

presented). 
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Figure 105. Measured utility-scale PV inverter instability

10.2.4 Experiments with Deliberately Induced PV Regulator Instability

For this investigation, we further experimented with the PV plant model at Eagle Eye based on 

the behavior shown above. Specifically, we pushed the PV model toward control settings that:

1. Might be found in a very stiff system 

2. We know can cause regulator stability problems in weak systems.

Again, for the Eagle Eye three-phase fault on the SCR degraded case (with a line-out), the SCR 

before the fault is 2. The results are shown in Figure 106. Notice that voltage after the fault clears 

has a rapid oscillation. This 13-Hz instability is representative of the behavior shown in Figure 

105. The slower oscillations observable before the event are also characteristic of a weak grid

and voltage regulator instability.
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Figure 106. PV voltage regulator induced instability

10.3Key Observations on Low Levels of Synchronous Generation

Some summary comments on the weak grid instability investigation follow.

Overall, the stability of the solar power plants that were flagged by our short-circuit level 

screening to be the most vulnerable to weak grid instabilities demonstrated satisfactory 

performance. For the cases tests, both CSP and utility-scale PV plants meet WECC criteria for 

primary cleared faults.

It is possible for either type of plant to have stability problems. The backup clearing faults of 

longer duration caused a voltage swing violation for the CSP plant in one case. Even longer 

faults would cause the synchronous generators of the CSP plants to trip on loss of synchronism.

We were able to roughly capture voltage regulator instability in the PV plant by using settings 

that should be applied only in a much stronger grid. On this later point, the simulations are 

illustrative only. In practice, the modeling of PV and all positive sequence analysis are highly 

suspect at these frequencies (9 Hz, 13 Hz). Definitive analysis is impossible with these tools.

Further, default generic stability models are not particularly well suited to capturing this risk.

They tend to be optimistic in that voltage support and current control can appear more stable.

This is a concern that requires attention to equipment specifications provided by the 

manufacturers and that might require other analytical tools to fully evaluate. However, we have 

not seen practical cases where weak grid instability cannot be fixed by control tuning. This does 

not mean this is always true, but it also means do not panic and do not assume that minimum 

synchronous generation levels will necessarily be limiting. Emerging good practice will dictate 
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that applications of inverter-based resources that can feed into very weak systems must be 

analyzed with tools and models that are more sophisticated than generic stability models allow.
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11Key Findings and Conclusions

This investigation shows that the integration of large amounts of solar power in the western 

system, for the conditions studied, does not present any obviously intractable challenges. We 

find that frequency response can be aided significantly by frequency sensitive controls on CSP 

and PV solar. Anticipated weak grid stability problems were not substantial.

This is relatively new ground for the industry, and this investigation is not a substitute for 

detailed planning, but the risks illustrated can be analyzed and mitigated. Tools, data, and the 

current state-of-the-art interconnection and bulk power system stability studies, if used following 

good system engineering practice as the system is built out, will ensure continued reliability of 

the power system.

11.1Key Findings

11.1.1 Changes in Frequency and Transient Stability Resulting from Solar and 

Wind Build-Out

Transmission added in solar-rich areas to avoid thermal and voltage violations, plus changes in 

dispatch and commitment, have some effect on transient stability. The impacts are mixed, with 

some improvements and decreases. No stability violations (noncompliance with WECC criteria) 

were found for the primary clearing cases tested. Voltage swing violations were observed for a 

backup cleared fault with a large cluster of CSP plants. As noted, good planning practices need

to be observed. Path ratings and remedial actions schemes might need to be revisited.

System-wide inertia dropped up to 27%–32% from earlier light load planning cases with less 

wind and solar generation. The lower system inertia did not present any significant stability or 

frequency response challenges.

We did not observe systemic issues related to frequency and transient stability as a result of the 

solar and wind build-out. That is, the overall behavior was similar in character to the present 

system. The system seems to tolerate nondesign basis north-south separation better.

So, for example, for the conditions tested, moving to SNSP on the order of 70% on a systemwide or regional level was not a clear indicator of degraded transient stability. Transient stability 

issues seemed to be rather localized.

11.1.2 Primary Frequency Response from CSP

PFR from CSP benefits frequency response, improves the system nadir, and helps the system 

(and regions thereof, such as California) meet the FRO. 

For comparison with FFR from PV, in these cases, the benefit of frequency response from CSP is 

approximately equivalent to 3% of FFR from inverter/switched resources. That means, for 

example, that for each 100MW of CSP providing PFR, the equivalent of 3 MW of FFR is 

provided at that time. In this system, with approximately 10 GW of CSP, PFR on all the units 

would provide the same benefit for FRO as 300 MW of inverter-based FFR. Batteries or utilityscale PV, as discussed in Section 7.2, have potential to provide FFR. Obtaining FFR from these 

inverter-based resources will have accompanying costs, which might include costs of 

curtailment. The timing of available PFR or FFR will vary by resource. Both the amount (i.e., the 
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number of hours per year that the service is available) and the timing (i.e., what hours the service 

is available) will be different by resource. Consequently, the overall (or annualized) economic 

value of the various alternatives derive from overall operational impact (i.e., over the full 8,760 

hours of a year).

Fast-valving-type open-loop controls on CSP might increase this benefit to approximately 4.5%.

Concepts were presented in the work for such controls, which would need further engineering 

design to ensure feasibility.

Thermal storage should help the sustainability of PFR and might help the speed of response.

Again, more detailed design is required.

11.1.3 Fast Frequency Response

Provision of FFR by utility-scale PV or other inverter-based resources, such as energy storage 

devices, can improve the system frequency nadir and add margin against underfrequency loadshedding. 

Responding quickly after the disturbance produces improved performance (in terms of improved 

nadir). But a response of 1–2 seconds produces most of the benefit. Faster response produces 

only marginally better performance, and it introduces robustness concerns. Specifically, local 

differences in frequency during disturbances suggest that triggering FFR should be no faster than 

0.5 sec.

For energy-limited FFR (e.g., synthetic inertia from wind), the best efficacy is for FFR a few 

seconds into the event.

For systemic events, the location of the FFR resources is not very important. The impact of the 

amount of FFR is quite linear for moderate amplitude actions, but it declines in efficacy with 

large power levels.

FFR from PV, as modeled, is sustainable and therefore also improves frequency response. 

Transient overload of inverters, and/or possible reversion to active power preference might 

provide free FFR. Otherwise FFR from PV requires advanced curtailment.

Simulations here show mechanisms by which the relative efficacy of FFR compared to PFR can 

be determined. Market mechanisms for FFR will need to recognize that it is possible to compare 

the two and that the relative benefit depends on the system operating condition.

11.1.4 Dynamic Models

CSP thermal plant models have good correlation to field tests.

CSP models lack the modeling detail needed for dynamic testing of thermal energy storage 

dynamic impacts. Approximations showed significant promise, but more detailed modeling 

efforts are required for definitive quantitative results.

Utility-scale PV models might be optimistic for weak grid conditions. In particular, generic 

models might not accurately capture fast voltage and fast regulator stability concerns under 
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short-circuit conditions below equipment specifications. Generic models might show good 

performance when the application behaves poorly in low SCR situations. The minimum system 

strength specified by the converter supplier can provide guidance for when different models and 

tools are required.

Displacing fossil-fueled generation by renewables increases dependence on hydro and makes 

modeling fidelity more important.

11.1.5 Stability Implications of CSP Compared to PV

Short-circuit levels in solar-rich areas tended to increase because of added transmission, which 

offsets effects of decommitting synchronous generation. The SCR levels from this work are not 

extremely low, and the authors have encountered systems in which inverter-based generation has 

been proposed for much lower system strengths. For the solar-rich regions of Southern California 

and Arizona, the necessity to provide adequate thermal capability with new transmission seems 

to have resulted in avoiding unduly low system strength.

System strength declines as PV is substituted for CSP. 

The lowest grid strength here (i.e., SCR of slightly more than 2.0) is where inverters for stiffer 

grids might misbehave. Stress tests in simulations showed instability like that observed in the 

field; however, instabilities are outside the accuracy of these positive sequence tools. More 

sophisticated analysis is required for evaluation and mitigation. The behavior of inverter-based 

generation is specific to individual equipment designs. In low-grid-strength applications, 

guidance from the manufactures, by specification or direct inquiry, is needed. Analysis with 

more detailed, proprietary simulation tools, including nonfundamental frequency screening tools 

and EMT time simulations, might be needed.

Transient stability of solar exporting areas generally showed better transient stability with PV 

compared to CSP. No transient stability issues that resulted in violation of WECC criteria were 

observed for primary fault clearing regardless of the type of solar generation.

The range of tests performed here did not show evidence of any widespread concerns about weak 

grid, high SNSP, or low short-circuit levels for the predominantly utility-scale PV case. These 

cases do not provide observable motivation to prefer synchronous CSP over inverter PV 

regarding system transient and voltage stability.

11.1.6 Economic Implications of CSP Compared to PV

This investigation was limited to system stability, and it is not an economic study. Nevertheless, 

the stability constraints of the Western Interconnection must be respected, and they have a 

substantive impact on the variable cost of operation. The various options presented in this study, 

including especially mechanisms to meet the FROs and changes in transfer limits, can be 

included in production cost simulations as boundary conditions. For example, use of thermal 

energy storage in CSP plants to maintain headroom and add frequency response would provide 

an additional operations option that will reduce the variable cost of operation. This savings could 

be quantified in a properly configured production study.
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11.2Future Work

This work illuminates a few areas for which further study, analysis using different tools, and the

development of new tools would move forward the industry’s understanding of grid operations

with low levels of synchronous generation. Such understanding might alter the planning 

landscape for CSP.

11.2.1 Western Interconnection Analysis

Further investigations of different network topologies with even lower levels of synchronous 

generation (e.g., Southern California) would be of interest. Both the system assumptions and 

economic operation of a very high variable renewables scenario in the West (and particularly

California) need more investigation. Combined production simulation and transient stability 

work (i.e., so-called round-trip analysis) is needed more than ever.

11.2.2 Protection and Relaying Investigation

Analyses of system stability using fundamental frequency, positive sequence analysis, including 

those presented in this report, generally assume that protective relaying and protection (e.g.,

circuit breakers) will continue to perform as presently modeled. For example, the faults used in 

this study were assumed to be of a “standard” four-cycle duration. The fault clearing times used 

in stability studies are usually conservative approximations of actual protection system behavior. 

This behavior is based on the level and character of short-circuit currents, which are substantially 

different and less well known from inverter-based generation. Whether these assumptions are 

still valid in systems with predominantly inverter-based generation warrants further 

investigation.

11.2.3 Load Modeling

Load behavior continues to have a substantive impact on system frequency performance and 

transient stability. Although significant effort has been devoted in recent years, including the 

introduction of the composite load model, there is still much to be done. The industry would 

benefit from (1) better loads models, with good field validation and (2) better methods to 

meaningfully address the planning and operations uncertainty that accompanies the inevitable 

inaccuracies of load modeling.
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