Michael Coddington, Barry Mather, 

and Benjamin Kroposki 

National Renewable Energy 

Laboratory 

Kevin Lynn and Alvin Razon 

U.S. Department of Energy 

Abraham Ellis and Roger Hill 

Sandia National Laboratories 

Tom Key, Kristen Nicole, and 

Jeff Smith 

Electric Power Research Institute 

Updating 

Interconnection Screens 

for PV System 

Integration
Updating Interconnection 

Screens for PV System 

Integration 

Michael Coddington, Barry Mather, and

Benjamin Kroposki

National Renewable Energy Laboratory

Kevin Lynn and Alvin Razon

U.S. Department of Energy

Abraham Ellis and Roger Hill

Sandia National Laboratories

Tom Key, Kristen Nicole, and Jeff Smith

Electric Power Research Institute

Prepared under Task No. SS12.1310

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. 

Technical Paper

NREL/TP-5500-54063

February 2012

Contract No. DE-AC36-08GO28308
NOTICE

This report was prepared as an account of work sponsored by an agency of the United States 

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responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

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Reference herein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States government or any agency thereof. The views 

and opinions of authors expressed herein do not necessarily state or reflect those of the United 

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Acknowledgements 

The National Renewable Energy Laboratory (NREL) would like to acknowledge co-authors 

Kevin Lynn, U.S. Department of Energy (DOE); Alvin Razon, SRA International Inc. 

(contractor−DOE); Abraham Ellis and Roger Hill, Sandia National Laboratories; and Tom 

Key, Kristen Nicole, and Jeff Smith, Electric Power Research Institute for their expert 

contributions to this paper. 

Additionally, the authors would like to thank the following reviewers for their comments on 

various drafts: 

Josh Hambrick and Thomas Basso, NREL; Michael Sheehan, Interstate Renewable 

Energy Council; Jason Keys and Kevin Fox, Keys and Fox, LLP; Tom Bialek, 

William Torre, Jose Carranza, and Ali Yari, San Diego Gas and Electric; Chase Sun, 

Jonathan Sykes, John Carruthers, Matthew Helig, Michael Jensen, Joan Dellavalle, 

and Harjeet Gill, Pacific Gas and Electric; Russell Neal, Brandon Tolentino, Roger 

Salas, Robert Yinger, and Leanne Swanson, Southern California Edison; David 

Brown and Gilbert Angeja, Sacramento Municipal Utility District; Daniel Adamson, 

Solar Energy Industries Association; Rachel Peterson, Jaclyn Marks, and the 

technical staff at California Public Utility Commission. 

Finally, we thank Connie Komomua, NREL, for her editing support. 
v

Contents

1 Overview and Purpose.......................................................................................................................................1

2 Interconnection Procedures..............................................................................................................................1

3 The 15% Penetration Threshold........................................................................................................................2

3.1 Unintentional Islanding .............................................................................................................................3

3.2 Voltage Control..........................................................................................................................................4

3.3 Protection Coordination............................................................................................................................5

4 Upgrading the 15% Screen.................................................................................................................................5

5 Short-Term Solutions.........................................................................................................................................6

5.1 Base Screen on Minimum Daytime Load ..................................................................................................6

5.2 Apply Supplementary Screens...................................................................................................................9

5.3 Utility Identified Zones of Penetration Levels....................................................................................... 12

6 Mid-Term and Long-Term Solutions .............................................................................................................. 13

6.1 Develop Higher Accuracy Screening Metrics and Formulas.................................................................. 13

6.2 Upgrade Distribution Circuit Design for PV-Hosting Applications........................................................ 14

6.3 Deploy Inverters with Advanced Functions........................................................................................... 15

7 Conclusion and Next Steps............................................................................................................................. 16
1

1 Overview and Purpose

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. In states such as California, Hawaii, and New Jersey 

alone, the number of new PV interconnection applications is in the thousands each year. 

Considering the rapid growth and widespread deployment of PV systems embedded 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. 

Since 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.

The purpose of this paper is to evaluate the origins and usefulness of the capacity 

penetration screen, offer short-term solutions which 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. Short-term and longer-term alternatives 

approaches are offered as examples; however, specific modifications to screening 

procedures should be discussed with stakeholders and must ultimately be adopted by state 

and federal regulatory bodies.

2 Interconnection Procedures

Interconnection procedures vary depending on state or federal jurisdiction, and 

implementation practices vary by utility system. In May 2005, the Federal Energy 

Regulatory Commission (FERC) adopted small generator interconnection procedures for 

distributed energy resources up to 20 megawatts in capacity. The FERC document titled 

Small Generator Interconnection Procedures (SGIP) applies to facilities that fall under 

federal jurisdiction, those that participate in and interconnect with wholesale market 

transactions with “facilities that are already subject to the transmission provider’s Open 

Access Transmission Tariff (OATT) at the time the interconnection request is made.”1 The 

FERC SGIP was also intended to be a “model rule” for consideration by state public utility 

commissions who commonly regulate distribution level interconnection procedures. 

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. These supplemental studies may only 

add a few weeks or months to the interconnection approval process, but they have a 

 1 FERC Order 2006 Paragraph 5, Page 4 http://www.ferc.gov/eventcalendar/files/20050512110357-order2006.pdf.
2

significant impact on the time, cost, and uncertainty of the proposed project. And for many 

utilities and PV developers, the potential impacts from PV are not clearly understood and 

the supplemental studies are not well defined.

3 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 where 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 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, 

protection miscoordination, and other potentially negative impacts are negligible if the 

combined DG generation on a line section is always less than the minimum load. 

There are three commonly used measures to describe penetration levels: instantaneous, 

energy, and capacity. Instantaneous penetration2 is defined as the output power of total DG 

on a circuit divided by the circuit load at any particular instance in time. This value will 

change over time depending on the load conditions and power output from DG. Energy 

penetration is the ratio of energy generated on a circuit divided by energy consumed by 

load over a specific period of time (typically one year). Capacity penetration is defined as 

the nameplate capacity of the combined DG on a circuit divided by the peak annual load on 

that circuit. The capacity penetration threshold is expressed in terms of peak load, as 

opposed to the intended metric (minimum load) because peak load data is tracked and 

accessible to utilities. 

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, defined as the ratio of total DG capacity to the peak load, and determines whether 

penetration level is less than 15% of the line-section peak load. This 15% threshold applies 

to radial distribution circuits, which is the most common type of distribution circuit with 

interconnected PV systems. For typical distribution circuits in the United States, minimum 

load is approximately 30% of peak load.3 The actual ratio varies widely depending on many 

factors such as the type of load served. Based on this generalization, the 15% penetration 

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

screening purposes.

 2 Load data is often tracked in intervals of 15 or 30 minutes by utilities, so the “instantaneous” is actually more discrete in nature. 3 This is considered a rule of thumb for electric distribution engineers and is based on observation that the minimum load is, on 

average, approximately 30% of the peak annual load.
3

No

No

No

No

No

No

No

No

No

Approve Interconnection

Initial Screening

For connection to load side of spot network: DG is inverterbased, aggregated DG capacity is <5% of peak load & <50 kW

For connection to a radial circuit: Aggregated DG capacity is 

<15% of annual peak load on line section

Aggregated DG contribution to max. short circuit current 

is <10% at primary voltage nearest change of ownership

For interconnection to single-phase neutral of 240V service: 

Resulting imbalance < 20% of service transformer rating 

For connections to a single-phase shared secondary: 

Aggregated DG capacity < 20kW

For interconnection to transmission side of substation in stabilitylimited areas: Agg. transm. connected DG capacity <10 MW

DG can be interconnected without the need for construction of 

facilities on the Transmission Provider’s system.

Go to Supplemental Study 

Procedure

DG can be connected consistent 

w/ standards (safety, reliably, etc)

Yes or N/A

Yes or N/A

Yes

Yes

Yes

Yes

Yes or N/A

Yes

No

Aggregated DG does not cause protective device to exceed 

87.5% of short circuit interrupting capability

DG interface is compatible with type of primary 

distribution line (e.g., 3-wire or 4-wire)

Yes or N/A

Yes or N/A

Figure 1 – FERC SGIP initial review screens summarized

Originally, the purpose of the 15% screen was to identify situations where the amount of DG 

penetration may be large enough to sustain an unintentional island, a condition deemed 

hazardous to utility personnel and possibly damaging to loads. The threshold was also 

intended as a “catch all” rule to eliminate other possible problems related to voltage control 

and system protection. There is considerable debate on whether or not more efficient and 

appropriate screening criteria can be used, especially in light of the fact that that this screen,

more than any other, triggers the need for additional studies. In addition, PV systems have 

unique technical characteristics that, if taken into account, could lead to a more efficient and 

effective screening procedure. The following sections discuss these PV characteristics and 

how the current 15% screen does not always take them into account.

3.1 Unintentional Islanding

Risks from unintentional islanding conditions include unacceptable voltage and frequency 

levels, transient over-voltage conditions, equipment damage, and operational safety 

concerns. Grid-connected PV inverters have anti-islanding features built into the controls, 

and are required to be “certified” for the intended use, meaning that they must have UL 

17414 certification and meet IEEE 1547 grid compatibility requirements. The possibility of

 4 Information on UL 1741 can be found at http://ulstandardsinfonet.ul.com/scopes/1741.html.
4

PV inverters unintentionally islanding is very low because UL 1741-listed inverters use 

anti-islanding algorithms that detect and drop off line within two seconds after an island is 

formed.

Unintended islanding remains a particular concern when PV and synchronous generators, 

such as diesel generators or other DG without anti-islanding features, are connected onto 

the same line section. These machines may mimic normal grid conditions, causing the PV 

inverters to stay online. 

Another significant utility concern is that the unintentional islanding test in UL 1741 is 

conducted on only a single inverter at a time. For this reason, some argue that multiple 

inverters could interfere with each other in such a way as to increase the chances that an 

unintentional island not be detected. While it is not possible to reduce the risk to zero, the 

reality is that the risk is extremely low, considering all the factors that need to be 

concurrently present. The most compelling substantiation is that incidents of unintentional 

islanding are extremely rare in actual field experience despite numerous examples of high 

penetration scenarios that exist. While a complete discussion of anti-islanding techniques is 

outside the scope of this paper, there are some simple concepts that can be incorporated in 

screening procedures to assess the risk of unintentional islanding.5

3.2 Voltage Control

A major concern and most commonly reported problem associated with high penetration of 

PV on distribution feeders is high steady-state voltage. When power is injected into a part of 

the electric power system that normally serves load the voltage at that location tends to 

increase. With higher penetration, higher voltages are expected along a feeder. The voltage 

effect depends on the feeder characteristics (voltage rating, conductor size, conductor 

material, overhead or underground) and location of PV along the feeder. Because feeders 

are often designed to be higher ampacity (thus lower impedance), thus “stiffer6”, near the 

substation, and because the substation will often contain voltage control equipment, the 

impact from PV on steady-state voltage is generally lessened as the distance to the 

substation is decreased. Conversely, as PV systems are located longer distances from the 

substation, the stiffness often decreases and the potential for high voltages becomes greater 

(especially during periods of light load such as weekend days). 

Figure 2 illustrates the possible impact of PV on steady-state voltage. On a circuit with no 

DG present (red line) the voltage along the feeder decreases as distance from the substation 

increases. If PV power injected into the circuit (blue line) is high enough, the voltage will 

increase, potentially taking the voltage above normal operational conditions (5% above 

nominal). PV located close to the substation can also affect steady-state voltage regulation 

by “masking” part of the load and thus interfering with load-controlled voltage regulation 

equipment. In either case, the net result is that high penetration would make it more 

challenging to maintain acceptable voltage regulation. It should be kept in mind that 15% 

penetration threshold, by itself, is not a good indicator of when steady-state high voltage are 

likely to occur. 

 5 S. Gonzalez, M. R, A. Fresquez, M. Montoya, and N. Opell, "Multi-Inverter Utility Interconnection Evaluations", Proc, 37th IEEE 

PVSC, 2010. 6 A “stiff” location on a feeder would typically have a lower than average impedance and larger conductor capable of serving many 

megawatts of power to utility customers.
5

Figure 2 – Example of voltage rise problem for a high penetration scenario 

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 (line regulators and switched capacitor banks) leading to more 

frequent and costly maintenance. A series of case studies on high penetration circuits is 

being developed and is planned for publication in 2012.7

3.3 Protection Coordination

A PV inverter’s contribution to fault current is limited and not as likely to cause protection 

problems8 as rotating machines; however, screening procedures routinely check for 

coordination and grounding compatibility. 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. 

4 Upgrading the 15% Screen

During review of PV interconnection requests in regions 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.9

 7 NREL case studies on high penetration distribution circuits to be published 2012. 8 Keller, J., Kroposki, B. (2010). Understanding Fault Characteristics of Inverter-Based Distributed Energy Resources. NREL Report No. 

TP-550-46698. 9 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.

+5%

+5%

-5%

-5%
6

These observations offer some indication that the existing 15% screen is conservative and 

is not an accurate method of determining the hosting capability (ability to add more PV 

without system upgrades) 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.

5 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 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 instead of 

the absolute minimum load. The second approach is to apply additional screens to identify 

possible technical issues, regardless of penetration level. Finally, 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.

5.1 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. Therefore, it makes sense to consider minimum daytime 

load as a technical screening criterion. For example, a screen may set a threshold at 

minimum daytime load, where daytime is defined as 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 Figure 3. If the PV system passes the additional screen it 

passes the penetration screen. 
7

No

No

No

No

No

No

No

No

No

Approve Interconnection

Initial Screening

For connection to load side of spot network: DG is inverterbased, aggregated DG capacity is <5% of peak load & <50 kW

For connection to a radial circuit: Aggregated DG capacity is 

<15% of annual peak load on line section

Aggregated DG contribution to max. short circuit current 

is <10% at primary voltage nearest change of ownership

For interconnection to single-phase neutral of 240V service: 

Resulting imbalance < 20% of service transformer rating 

For connections to a single-phase shared secondary: 

Aggregated DG capacity < 20kW

For interconnection to transmission side of substation in stabilitylimited areas: Agg. transm. connected DG capacity <10 MW

DG can be interconnected without the need for construction of 

facilities on the Transmission Provider’s system.

Go to Supplemental Study 

Procedure

DG can be connected consistent 

w/ standards (safety, reliably, etc)

Yes or N/A

Yes or N/A

Yes

Yes

Yes

Yes

Yes or N/A

Yes

No

Aggregated DG does not cause protective device to exceed 

87.5% of short circuit interrupting capability

DG interface is compatible with type of primary 

distribution line (e.g., 3-wire or 4-wire)

Yes or N/A

Yes or N/A

• Is the proposed generator PV, and

• All other DG in the feeder PV, and

• Penetration level < minimum daytime load? No

Yes

Figure 3 – Modified SGIP screens to address PV interconnection based on 

minimum daytime load

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 which have a minimum to peak load ratio between zero 

and 20%, 20%-30%, 30%-40%, and 40%-50% based on minimum daytime load (10 a. m. -

2 p.m.) and minimum 24-hour load. 

It may be difficult to establish minimum daytime load unless reliable historical data is 

available; however, most utilities now have access to feeder minimum load and feeder peak 

load data via Supervisory Control and Data Acquisition (SCADA) systems. If SCADA data is 

unavailable, minimum daytime load can be estimated based on standard load profiles for 

various customer classes that many utilities maintain and update on an annual basis.10 It 

 10 See http://www.sce.com/AboutSCE/Regulatory/loadprofiles/2011loadprofiles.htm. 
8

should	 be	 noted	 that	 historical	minimum	loads	are	 no	guarantee	of	 future	minimum	load	

levels,	which	creates	some	uncertainty	and	need	for	better	communication	between	DG	and	

the	utility	operations	and	control,	especially	when	DG	is	in	the	megawatt	scale.	And	sections	

of	 distribution	 circuits	 are	 frequently	 switched	 onto	 adjacent	 circuits,	 which	 adds	 to	 the	

uncertainty	of	minimum	and	peak	load	values,	and	there	are	times	when	large	loads	may	be	

offline.	 Load	 variability	 and	 circuit	 segment	 switching	 must	 be	 considered	 by	 utility	

planning	engineers	when	determining	minimum	daytime	load	of	sections	of	feeders.

Figure 4 – This load profile indicates that minimum daytime load is significantly 

higher than absolute minimum load 

Annual	Peak	Load	

was	5.6	MW	at	5	p.m.

Annual	Minimum	load	

was	1.3	MW	at	5	a.m.,	

23%	of	annual	peak

Annual	Daytime	Minimum	

load	was	1.8	MW	at	10	a.m.,	

33%	of	annual	peak	load
9

Figure 5 – Ratio of minimum load to peak load for daytime minimum load 

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

5.2 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 Figure 6.
10

No

No

No

No

No

No

No

No

No

Approve Interconnection

Initial Screening

For connection to load side of spot network: DG is inverterbased, aggregated DG capacity is <5% of peak load & <50 kW

For connection to a radial circuit: Aggregated DG capacity is 

<15% of annual peak load on line section

Aggregated DG contribution to max. short circuit current 

is <10% at primary voltage nearest change of ownership

For interconnection to single-phase neutral of 240V service: 

Resulting imbalance < 20% of service transformer rating 

For connections to a single-phase shared secondary: 

Aggregated DG capacity < 20kW

For interconnection to transmission side of substation in stabilitylimited areas: Agg. transm. connected DG capacity <10 MW

DG can be interconnected without the need for construction of 

facilities on the Transmission Provider’s system.

Go to Supplemental Study 

Procedure

DG can be connected consistent 

w/ standards (safety, reliably, etc)

Yes or N/A

Yes or N/A

Yes

Yes

Yes

Yes

Yes or N/A

Yes

No

Aggregated DG does not cause protective device to exceed 

87.5% of short circuit interrupting capability

DG interface is compatible with type of primary 

distribution line (e.g., 3-wire or 4-wire)

Yes or N/A

Yes or N/A

• Is the proposed generator PV, and

• Passes the voltage regulation screen, and

• Passes the anti-islanding screen? No

Yes

Figure 6 – Modified SGIP screens to address PV interconnections regardless of 

penetration level

It is important that the additional screens are effective and relatively easy to apply with 

well-defined costs and timeline to complete the screens, established through a transparent 

and open process administered by a regulatory body that takes into account stakeholder 

input. For example, Hawaii’s revised Rule 14H11 has clear timelines for when an application 

must be deemed complete, examined through initial review, and processed through 

supplemental review. Further, the California Rule 21 Supplemental Review Guideline 

contains several simple procedures that can be incorporated into the initial review screen 

for PV systems.12 With respect to voltage regulation, a procedure similar to Figure 7 is 

recommended for consideration. Note that the 15% in this drawing refers to the peak 

export on the line section, which is different than the SGIP 15% screen. The 15% peak 

export implies an instantaneous penetration level greater than 100% for these systems with 

export levels less than 200kW.

 11 HPUC news release http://puc.hawaii.gov/news/pressreleases/2011/2011-11-

29%20PUC%20Press%20Release%20HECO%20Rule%2014h%20Approval.pdf/?searchterm=rule%2014h 12 http://www.energy.ca.gov/distgen/interconnection/model_rule.html.
11

BEGIN

Applicant peak 

export >200 kW?

Aggregate 

peak export >15% 

of line section 

peak load?

Yes

Applicant is 

exporting? Yes

No

No No

Voltage is 

controlled with line 

regulator or voltagecontrolled cap 

bank? 

Applicant 

capacity >500 kW? Yes

No No

Yes

Yes

Application presents potential 

voltage regulation concern. 

Review Application

Application does not present

a voltage regulation concern. 

Proceed to Next Issue

NOTE: This 15% refers to peak export on line 

section, which is different than the SGIP 15% 

screen. By definition, 15% peak export implies an 

instantaneous penetration level greater than 100%.

Figure 7 – Possible additional screening procedure for PV systems addressing 

voltage issues

Similarly for anti-islanding, Rule 21 Supplemental Review Guide contains a simple screen 

that can be applied as part of the initial review as seen in Figure 8. Application of the screen 

is more involved, but could be reasonably carried out as part of the Initial review since only 

a minimal amount of information is required. 
12

BEGIN

Applicant

Exporting?

Applicant is certified 

non-islanding? No

No

Aggregate 

DG >15% of line 

section peak 

load?

Other DG in

circuit are synchronous

generators?

Application presents a 

potential islanding concern.

Review Application

Application does not present 

an islanding concern.

Proceed to Next Issue

Applicant is a 

synchronous 

generator?

Aggregate DG

>15% of line section 

peak load

All other DG are

non-exporting?

Yes

Yes

No

No

No

Peak Export >10% 

of line section peak 

load?

Yes

Yes

Yes

No

Yes

Yes

Yes

No

No

NOTE: This 10% refers to peak 

export on line section, which 

implies an instantaneous 

penetration greater than 100%.

Figure 8 – Possible supplemental screening procedure for PV systems addressing 

unintentional islanding issues

5.3 Utility Identified Zones of Penetration Levels 

One concept for increasing penetration criteria is to identify zones where higher 

penetration is acceptable. These zones would be identified by utilities through a 

transparent and open process administered by a regulatory body that takes into account 

stakeholder input, and should not exclude PV interconnection outside the zones as shown in 

Figure 9. 

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 is an example area displaying zones that allow for greater 

penetration and those that require further study. These zones would change over time as 

new installations of DG come online. One shortcoming of this conceptual drawing is the 

difficulty presented in measuring load, thus penetration, and how adjacent zones will affect 

one another. Implementing this would likely be labor-intensive, and require greater utility 

staffing levels. The California Energy Commission recently published a report that proposes 
13

several criteria for identifying project areas requiring minimal detailed studies.13 The 

report discusses a modeled system in which a wholesale PV project might have acceptable 

impact if connected in one location in a circuit, but may have significant impacts requiring 

mitigation or upgrades if connected in another location.

Figure 9 – An example area with zoned penetration limits

6 Mid-Term and Long-Term Solutions 

While short-term solutions may be applied in a one-year or less time frame, there are more 

promising solutions to be considered that will take longer to develop and implement. Midterm 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. 

6.1 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 are functions of 

multiple distribution and PV system characteristics. For example, from previous highpenetration PV integration case study data, it is known that a PV system’s nameplate 

 13 http://www.energy.ca.gov/2011publications/CEC-200-2011-014/CEC-200-2011-014.pdf
14

capacity, circuit impedance, and distance from the distribution substation are key indicators 

of the expected voltage impacts of the PV system interconnection. A more reliable voltage 

impact metric can be formulated through extensive distribution system modeling using 

verified models that incorporate both the PV system nameplate capacity and the location of 

the interconnection on the distribution system. Other circuit characteristics and 

parameters, such as circuit voltage, conductor sizing, voltage regulation scheme, and the 

required service voltage range can also be considered in the development of a more reliable 

PV voltage impact metric. A sensitivity analysis for each considered circuit characteristic 

would then be performed and only the characteristics that largely determine the system 

impacts due to PV interconnection would be included in the final PV impact metric in order 

to simplify the calculation of the metric as much as possible.

The proposed PV impact metrics are more difficult to calculate than the current penetration 

metric (15%) but are still calculated based on available distribution circuit and PV system 

parameters. The developed PV impact metrics is a set of formulas that indicate whether the 

impacts of an individual PV interconnection exceed a given range agreed by the utilities and 

regulators similar to the PV penetration metric currently under use. Since PV impact 

metrics are developed for each interconnection concern and each metric takes into account 

a number of system characteristics and parameters, the resulting PV interconnection 

screening process allows more safe and compatible PV system to be interconnected without 

a supplemental interconnection study.

6.2 Upgrade Distribution Circuit Design for PV-Hosting Applications

Upgrading existing distribution feeders with larger-sized (thus lower impedance) 

conductors, installing voltage regulation devices, and increasing operating voltages (e.g. 

from 4kV to 13.2kV), 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 as well as maintaining voltage levels, but there are 

financial impacts associated with these approaches. 

New circuits designed and built in areas where there is significant PV development should 

be evaluated for increased conductor size and installation of voltage regulators. Existing 

distribution circuits can also be upgraded, but the process is often more complicated. The 

cost of such upgrades might be shared between utilities and PV developers, but that policy 

issue is not discussed in detail in this paper. Costs may range from a few thousand dollars 

for modifying controls for bi-directional voltage regulators, for example, to hundreds of 

thousands of dollars for replacing several miles of smaller conductors with larger 

conductors. 

Capital expenditures by utilities are constrained by the availability of financial resources 

and limited by regulatory agencies and financial organizations. If greater expenditures are 

encouraged, then regulated utilities will need approval from utility commissions and by the 

organizations that have financial oversight over the utilities. Investor-owned utilities have 

specific revenue to capital investment requirements necessary to maintain stock ratings, 

and this could be a significant issue when considering upgrading distribution circuits. 

Investor-owned utilities often issue stock to raise money for capital expenditure programs 

that include new and rebuilt distribution circuits. Other types of utilities, such as 

cooperatives and municipal-owned utilities have other difficulties in paying for upgrades.
15

6.3 Deploy Inverters with Advanced Functions 

Today, the challenge involves integrating PV into the existing electrical distribution systems 

that were not designed for significant reverse power. Inverter grid support functions are 

either unavailable or unused. Future investments and application of new technologies are 

expected to significantly increase PV hosting capability. Although it will take time to 

implement, a new generation of inverters is available with advanced functions designed to 

interact and support the grid. Enabling these functions will involve setting up, 

programming, reacting to grid condition signals, and potentially implementing two-way 

communications with distribution system operators. Also evolving is a smart grid with 

more automated distribution equipment and the ability to process information fed into both 

a central distribution management system and dispersed management systems that will 

manage accordingly. 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. Together, advanced inverter functions and 

distribution automation are expected to significantly increase the PV hosting capability of 

the existing infrastructure. 

Relative to 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. Configurable 

autonomous actions can support the grid during abnormal voltage or frequency conditions. 

Previous studies have shown that advanced inverters can mitigate voltage-related issues 

and potentially increase the hosting capacity of solar PV by as much as 100%.14 This point is 

further illustrated in Figure 10, where the feeder voltage response is shown to improve 

with the use of advanced volt-VAr control.

Figure 10 – Feeder voltage response with advanced VAr control15

 14 Braun, M., Stetz, T., Bründlinger, R., Mayr, C., Ogimoto, K., Hatta, H., Kobayashi, H., Kroposki, B., Mather, B., Coddington, M., 

Lynn, K., Graditi, G., Woyte, A. and MacGill, I. (2011), Is the distribution grid ready to accept large-scale photovoltaic 

deployment? State of the art, progress, and future prospects. Progress in Photovoltaics: Research and Applications. 

doi: 10.1002/pip.1204. 15 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.

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
16

Other functions, such as voltage and frequency ride-through, short-term or dynamic AC 

voltage support, inverter response to active anti-islanding, and arc-fault detection and 

mitigation, can increase reliability and safety. 

Taking advantage of advanced inverter functions, along with other opportunities for 

demand management, will require communication and control and, consequently, 

opportunities will evolve with a smarter distribution system. For PV inverters there will be 

potential to perform a large number of grid-supportive functions. The value of this 

functionality depends on the degree in which a grid operator can integrate PV functions 

with other distribution equipment. 

Interconnection standards must be defined and developed before these advanced inverters 

are deployed in larger numbers on electric distribution systems. IEEE P1547.816 is the 

standard recommended practice under development that will help define how these 

advanced inverters will be integrated into an electric distribution system. Completion of 

this standard will pave the way for a future interconnection standard which will supplant 

IEEE 1547.

17

7 Conclusion and Next Steps

Thousands of applications are submitted in the United States each year for PV installations 

and many states have aggressive renewable portfolio standards that encourage these 

installations. Therefore, it is critical that interconnection procedures be as streamlined as 

possible to avoid unnecessary interconnection studies, costs, and delays. 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 

suggests utilizing 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 is to apply 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 regulatory agencies, 

electric utilities, national laboratories, DOE, EPRI, equipment manufacturers, and PV 

developers. These solutions 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. Modeling, observation, testing, failure analysis, success 

analysis, and technology development is attainable through mutual cooperation and a focus 

on success.

 16 For additional information see http://grouper.ieee.org/groups/scc21/1547.8/1547.8_index.html. 17 For additional information see http://grouper.ieee.org/groups/scc21/1547/1547_index.html.