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.

Contract No. DE-AC36-08GO28308

Updating Technical Screens for 

PV Interconnection

Preprint

Michael Coddington, Benjamin Kroposki, 

and Barry Mather

National Renewable Energy Laboratory

Abraham Ellis and Roger Hill

Sandia National Laboratories

Kevin Lynn

U.S. Department of Energy

Alvin Razon

SRA International, Inc.

Tom Key, Kristen Nicole, and Jeff Smith

Electric Power Research Institute

Presented at the 2012 IEEE Photovoltaic Specialists Conference

Austin, Texas

June 3–8, 2012

Conference Paper

NREL/CP-5500-54103

August 2012
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1 

Updating Technical Screens for PV Interconnection 

Michael Coddington1, Abraham Ellis2, Kevin Lynn3, Alvin Razon4, Tom Key5, Benjamin Kroposki1, Barry 

Mather1

, Roger Hill2, Kristen Nicole5, Jeff Smith5 

1

National Renewable Energy Laboratory, Golden, Colorado, 80401, USA 

2

Sandia National Laboratories, Albuquerque, New Mexico, 87123, USA 

3

U.S. Department of Energy, Washington, District of Columbia, 20585, USA 

4

SRA International, Inc., Fairfax, Virginia, 22033, USA 

5

Electric Power Research Institute, Palo Alto, California, 94304, USA 

Abstract — Solar photovoltaics (PV) is the dominant type of 

distributed generation (DG) technology interconnected to electric 

distribution systems in the United States, and deployment of PV 

systems continues to increase rapidly. Considering the rapid 

growth and widespread deployment of PV systems in United 

States electric distribution grids, it is important that 

interconnection procedures be as streamlined as possible to avoid 

unnecessary interconnection studies, costs, and delays. Because 

many PV interconnection applications involve high penetration 

scenarios, the process needs to allow for a sufficiently rigorous 

technical evaluation to identify and address possible system 

impacts. Existing interconnection procedures are designed to 

balance the need for efficiency and technical rigor for all DG. 

However, there is an implicit expectation that those procedures 

will be updated over time in order to remain relevant with 

respect to evolving standards, technology, and practical 

experience. Modifications to interconnection screens and 

procedures must focus on maintaining or improving safety and 

reliability, as well as accurately allocating costs and improving 

expediency of the interconnection process. This paper evaluates 

the origins and usefulness of the capacity penetration screen, 

offers potential short-term solutions which could effectively allow 

fast-track interconnection to many PV system applications, and 

considers longer-term solutions for increasing PV deployment 

levels in a safe and reliable manner while reducing or eliminating 

the emphasis on the penetration screen.

Index Terms — screens, interconnection, utility, electric 

utilities, public utility commissions, penetration, high 

penetration.

I. OVERVIEW AND PURPOSE

Solar photovoltaics (PV) is the dominant form of distributed 

generation (DG) technology interconnected to electric 

distribution systems in the United States, and deployment of 

PV systems continues to increase rapidly. Considering the 

rapid growth and widespread deployment of PV systems in

the United States today, it is important that interconnection 

procedures be as efficient as possible to avoid unnecessary 

interconnection costs and delays. 

Interconnection procedures vary depending on state or 

federal jurisdiction, and implementation practices vary by 

utility system. Most procedures allow for expedited 

interconnection without additional technical studies if the 

proposed interconnection passes a series of technical screens. 

If a proposed interconnection fails one or more of the screens, 

supplemental interconnection studies may be required before 

it can proceed to interconnection. 

Because many PV interconnection applications involve 

installations on distribution feeders with greater than 15% 

capacity penetration, the process needs to allow for a 

sufficiently rigorous technical evaluation to identify and 

address possible system impacts. There is an implicit 

expectation that those procedures will be updated over time in 

order to remain relevant with respect to evolving standards, 

technology, and practical experience. Modifications to 

interconnection screens and procedures must focus on 

maintaining or improving safety and reliability, as well as 

accurately allocating costs and improving expediency of the 

interconnection process.

The purpose of this paper is to evaluate the origins and 

usefulness of the capacity penetration screen, offer short-term 

solutions that could effectively allow fast-track 

interconnection to many PV system applications, and consider 

longer-term solutions for increasing PV deployment levels in 

a safe and reliable manner while reducing or eliminating the 

emphasis on the penetration screen. 

II. THE 15% PENETRATION THRESHOLD

In 1999, before the FERC SGIP was established, the 

California Public Utilities Commission (CPUC) issued an 

order instituting a rulemaking to address interconnection 

standards for devices to the electric grid in California. The 

order resulted in the reform of CPUC Rule 21, which 

identified screens that allowed low-impact generators to be 

interconnected relatively quickly and made the review process 

more efficient for small, low-impact generation at low 

penetration levels. During the reformation of CPUC Rule 21, 

a 15% threshold was established to identify situations in 

which the amount of DG capacity on a line section exceeds 

15% of the line section annual peak load. The 15% threshold 

was then adopted in the FERC SGIP and is used by most 

states as a model for developing their interconnection 

procedures. Under most applicable interconnection screening 
2

procedures, penetration levels higher than 15% of peak load 

trigger the need for supplemental studies.

The 15% threshold is based on a rationale that unintentional

islanding, voltage deviations, and other potentially negative 

impacts are negligible if the combined DG generation on a 

line section is always less than the minimum load. 

Capacity penetration, or simply “penetration,” is defined as 

the nameplate capacity of the combined DG on a circuit 

divided by the annual peak load on that circuit. The 

penetration threshold is expressed in terms of peak load 

because utilities track peak load information. 

Figure 1 summarizes the FERC SGIP initial review process, 

from which many states have adopted the same or a similar set 

of screens. The first screen examines total penetration by 

capacity and determines whether penetration level is less than 

15% of the line-section peak load. For typical distribution 

circuits in the United States, minimum load is approximately 

30% of peak load. Based on this generalization, the 15% 

penetration level (one half of the 30%) was selected as a 

conservative penetration level for general screening purposes.

Originally, the purpose of the 15% screen was intended as a 

“catch all” rule to eliminate potential problems related to 

voltage rise and system protection. The following sections 

discuss these PV characteristics and how the current 15% 

screen does not always take them into account.

Fig. 1. FERC SGIP initial review screens summarized.

A. Unintentional Islanding

Risks from unintentional islanding conditions include 

unacceptable voltage and frequency levels, transient overvoltage conditions, equipment damage, and operational safety 

concerns. Grid-connected PV inverters have unintentionalislanding features built into the controls and are required to be 

“certified” for the intended use, meaning that they must have 

UL 1741 certification and meet IEEE 1547 requirements. 

B. Voltage Control

A major concern with high penetration of PV on 

distribution feeders is high steady-state voltage. When power 

is injected into the electric power system that normally serves 

load, the voltage at that location may increase. The impact of

PV on steady-state voltage is generally lessened as the 

distance to the substation is decreased. 

Figure 2 illustrates the possible impact of PV on steadystate voltage. If PV power injected into the circuit is high 

enough, the voltage will increase, potentially pushing voltage 

above normal operational conditions. 

Similar to steady-state voltage issues, if the PV system is 

located further from the distribution substation, PV output 

variability can result in significant voltage variability. Possible 

consequences are poor voltage regulation and increased 

cycling and stress on voltage control equipment. 

C. Protection Coordination

A PV inverter’s contribution to fault current is limited by 

design and is not as likely to cause protection problems1

III. UPGRADING THE 15% SCREEN

as 

rotating machines. However, coordination and grounding 

compatibility impacts may still arise, and there are screens to 

check for those possibilities. In some PV inverter installations, 

an effectively grounded neutral is required to reduce the 

potential for transient overvoltage during unbalanced system 

faults. Multiple ground sources can increase ground current 

contribution and affect the sensitivity of ground current 

protection functions at the substation. 

During review of PV interconnection requests in locations

with a high level of PV deployment, the 15% interconnection 

screen often triggers the need for supplemental studies. In 

many cases, even when PV penetration is substantially above 

15%, the supplemental review does not identify any necessary 

system upgrades. There are many circuits across the United 

States and Europe with PV penetration levels well above 15% 

where system performance, safety, and reliability have not 

been materially affected.2

 1 Keller, J., Kroposki, B. (2010). Understanding Fault Characteristics of 

Inverter-Based Distributed Energy Resources. NREL Report No. TP-550-

46698. http://www.nrel.gov/docs/fy10osti/46698.pdf. 2 M. Braun et al. “Is the Grid Ready to Accept Large Scale PV Deployment? -

State of the Art, Progress and Future Prospects,” Submitted to Progress in 

PV, to be published in 2012.
3

Fig. 2. Example of voltage rise problem for a high penetration scenario.

These observations offer some indication that the existing 

15% screen is conservative and is not an accurate method of 

determining the hosting capability of a particular feeder. The 

following short-term, mid-term, and long-term approaches 

may be considered as possible steps to improve 

interconnection procedures for distribution-connected PV 

systems.

IV. SHORT-TERM SOLUTIONS

Inverter-based PV has unique technical characteristics that 

reduce the impacts on grid operations. Unlike other DG 

resources, the output pattern of PV is strictly diurnal (active in 

daytime). The grid-PV interface is an electronic inverter with 

adjustable settings and short-circuit current much lower than 

synchronous generators of the same output rating. PV 

inverters are designed to comply with IEEE 1547 standards 

and UL-1741 certification without the need for external 

protection or controls. By taking into account these technical 

characteristics, it is possible to refine screening procedures to 

be more efficient and effective, substantially reducing 

interconnection process time and effort for PV deployment 

without compromising the safety and reliability of the 

interconnected distribution system. Several possible 

approaches could be undertaken in the short term to improve 

screening procedures for distribution-connected PV systems.

There are three conceptual examples discussed in this 

section. The first approach is to include a PV-specific 

screening criterion that utilizes the minimum daytime load. 

The second approach is to apply additional screens to identify 

possible technical issues, regardless of penetration level. The 

third approach is to increase the penetration levels by 

identifying zones of higher penetration based on the utility 

distribution feeder configuration and location of substations.

A. Base Screen on Minimum Daytime Load

The fact that PV generation has a strictly daytime pattern is 

significant considering that voltage impacts tend to be greater 

during periods of highest instantaneous penetration. By the 

time PV systems are producing a substantial amount of power, 

loads are well above their nightly lows on most feeders. A

new screen may set a threshold at minimum daytime load, 

during the period between 10:00 a.m. and 2:00 p.m. A simple 

modification of the SGIP screening criteria to implement this 

PV-specific screening criterion is depicted in Fig. 3. If actual 

historical data is available, load data in areas of interest could 

be analyzed to establish factors that relate minimum daytime 

load levels to peak load levels. Some utilities already use 

minimum daytime load as a screening criterion and have 

determined these load levels for their service territory. Figure 

4 illustrates an example circuit where the annual minimum 

daytime load is significantly higher than the minimum 24-

hour load. Figure 5 shows the comparative ratios of minimum 

load to peak load, and minimum daytime load to peak load, 

for 500 residential and commercial feeders in a southwest 

U.S. city. The figure shows the percentage of the feeders that

have a minimum to peak load ratio between zero and 20%, 

20% and 30%, 30% and 40%, and 40% and 50% based on 

minimum daytime load (10 a.m. to 2 p.m.) and minimum 24-

hour load.

Many utilities have access to feeder minimum and peak 

load data via Supervisory Control and Data Acquisition 

(SCADA) systems. Minimum daytime load can also be 

estimated based on standard load profiles for various customer 

classes that many utilities maintain and update on an annual 

basis.3

 3 See

http://www.sce.com/AboutSCE/Regulatory/loadprofiles/2011loadprofiles.

htm.

Load variability and circuit segment switching must be 

+5%

+5%

-5%

-5%
4

considered by utility planning engineers when determining 

minimum daytime load of sections of feeders.

Fig. 3. Modified SGIP screens to address PV interconnection 

based on minimum daytime load.

Fig. 4. This load profile indicates that minimum daytime load is 

significantly higher than absolute minimum load.

Fig. 5. Ratio of minimum load to peak load for daytime minimum 

load (10 a.m. to 2 p.m.) and 24-hour minimum load.

B. Apply Supplementary Screens

Applying supplementary screens to identify possible 

technical issues, regardless of penetration level, focuses on 

utilizing more comprehensive analyses as part of the initial 

review in order to eliminate the possibility of voltage 

regulation issues and the creation of unintentional islands. An 

example of this concept is shown in Fig. 6. 

Fig. 6. Modified SGIP screens to address PV interconnections 

regardless of penetration level.
5

Fig. 7. An example area with zoned penetration limits.

California Rule 21 Supplemental Review Guideline 

contains several simple procedures that can be incorporated 

into the review screen for PV systems. 4

C. Utility Identified Zones of Penetration Levels

Similarly for antiislanding, Rule 21 Supplemental Review Guide contains a 

simple screen that can be applied as part of the initial review.

Another concept for increasing penetration criteria is to 

identify zones where higher penetration is acceptable. These 

zones would likely be located in areas closer to substations or 

with low-impedance conductors, thus having a lower 

potential for voltage abnormalities or protective system 

miscoordination. Figure 7 is an example area displaying 

zones that allow for greater penetration and those that require 

further study. 

V. MID-TERM AND LONG-TERM SOLUTIONS

While short-term solutions might be applied in 12 to 18 

months, there are more promising solutions to be considered 

 4 http://www.energy.ca.gov/distgen/interconnection/model_rule.html.

that will take longer to develop and implement. Mid-term 

solutions, for this paper, might be those that happen in the 

one-to-five-year range, while long-term solutions are likely 

those beyond the five-year horizon. 

A. Develop Higher Accuracy Screening Metrics and 

Formulas

PV penetration metrics alone are insufficient indicators of 

the expected distribution system level impacts from PV 

interconnection. One potential solution is to develop more 

accurate screening metrics that can be used in a revised 

screening process. An interconnection impact metric for each 

PV interconnection concern, e.g., voltage effects, 

unintentional islanding, and protection coordination, could be 

developed. These metrics would be functions of multiple 

distribution and PV system characteristics. 

B. Upgrade Distribution Circuit Design for PV-Hosting 

Applications 

Upgrading existing distribution feeders with larger-sized 

(and thus lower-impedance) conductors, installing voltage 
6

regulation devices, and increasing operating voltages (e.g., from 4 kV to 13.2 kV), are ways to maintain acceptable 

voltage levels and increase the PV hosting capacity of a 

feeder. Larger conductors and higher operating voltages 

allow greater levels of power delivery to loads while

maintaining voltage levels, but there are significant costs

associated with these approaches. 

C. Deploy Inverters with Advanced Functions

Future investments and application of new technologies are 

expected to significantly increase PV hosting capability. 

Although it will take time to widely implement, a new 

generation of inverters is available with advanced functions 

designed to interact with and support the grid. Advanced 

communication and control will enable the future distribution 

systems to better coordinate settings and limits of switch, 

protection, and voltage control devices as conditions change. 

Relative to many other devices connected to utility 

distribution systems, PV inverters are highly capable in terms 

of responsiveness, controllability, processing capability, and 

memory. Advanced inverters and controllers will provide 

real-time reactive power compensation, real power 

curtailment, watt-voltage, and watt-frequency management, 

etc. Configurable autonomous actions can support the grid 

during abnormal voltage or frequency conditions. 

VI. CONCLUSION AND NEXT STEPS

There is an implicit expectation that existing 

interconnection procedures will evolve over time to reflect 

changes in standards, technology, and practical experience. 

Modifications to interconnection screens and procedures must 

have a focus on maintaining or improving safety and 

reliability, as well as reducing costs and improving 

expediency of the interconnection process. 

Three short-term approaches have been presented for 

consideration. The first approach uses PV-specific screening 

criteria that would utilize minimum daytime load for a circuit 

rather than absolute minimum load or a percentage of peak 

load. The second approach uses additional screens to evaluate 

potential voltage or unintentional island problems, regardless 

of penetration levels. The third approach would increase 

penetration levels in specific areas or zones based on 

substation location, circuit design, and existing DG. These 

three conceptual approaches may be considered as solution 

frameworks for increasing levels of PV deployment.

Mid-term and long-term solutions require close cooperation 

between all PV stakeholders. These solutions will ultimately

produce straightforward approaches to understand how much 

PV can be deployed on a circuit, and at what locations, while 

maintaining a focus on safety, reliability, and cost. 

ACKNOWLEDGEMENT

This work was supported by the U.S. Department of 

Energy under Contract No. DE-AC36-08-GO28308 with the 

National Renewable Energy Laboratory.

0.9

0.925

0.95

0.975

1.000

1.025

1.05

0 4 8 12 16 20

Hour

Voltage

Baseline – No PV

20% PV

20% PV w/ volt-var control

Fig. 8. Feeder voltage response with advanced VAr control5

 5 Smith, J., Sunderman, W. Dugan, R., Seal, B., “Smart Inverter Volt/VAr Control Functions for High Penetration of PV on Distribution Systems,” 2011 Power 

Systems Conference and Exposition, Phoenix, Arizona, March 2011.

.