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

Executive Summary: 

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-5D00-70782

July 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

Executive Summary: 

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-5D00-70782

July 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 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

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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. 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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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.................................................................................................................................... 1

Key Findings .......................................................................................................................................... 1

Grid Build-Out to Support Added Solar and Wind Changes Transient Stability.......................... 1

Primary Frequency Response from Concentrating Solar Power Helps Meet Frequency Response 

Obligation......................................................................................................................... 2

Fast Frequency Response from Solar Photovoltaics or Energy Storage Improves Frequency 

Nadir and Adds Margin Against Underfrequency Load-Shedding.................................. 3

Frequency Response from Concentrating Solar Power Can Substitute for Fast Frequency 

Response from Photovoltaics or Batteries........................................................................ 6

Available Dynamic Models Are Good, But They Have Some Limitations.................................. 9

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

They Are Not Decisive for the Conditions Studied ....................................................... 10

Executive Summary Closure ................................................................................................................ 11
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List of Figures

Figure ES-1. Contribution of concentrating solar power governors and inertia to frequency response ....... 3

Figure ES-2. Impact of fast frequency response timing on frequency nadir................................................. 4

Figure ES-3. The location of the event strongly affects the measured frequency during the first seconds. . 5

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

response.................................................................................................................................... 7

Figure ES-5. California’s frequency response declines during sunset if headroom is depleted. .................. 9

Figure ES-6. Transient stability of CSP compared to PV in a low-grid-strength location ......................... 11
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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 

Time of FFR Injection (after event initiated)

 

Time of FFR Injection (seconds after 2 PV unit trip initiated)
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2 seconds. Note, for example, how different the two events appear in the Northwest and 

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 
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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.
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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) 
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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 Hz 1

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” approximately 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
9

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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 
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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). 
11

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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.