Interconnecting PV on New York 

City’s Secondary Network 

Distribution System 

K. Anderson, M. Coddington, K. Burman, 

S. Hayter, B. Kroposki, and A. Watson 

Technical Report 

NREL/TP-7A2-46902 

November 2009 
 

 

Technical Report Interconnecting PV on New York NREL/ TP-7A2-46902 City’s Secondary Network November 2009 

Distribution System 

K. Anderson, M. Coddington, K. Burman, 

S. Hayter, B. Kroposki, and A. Watson 

Prepared under Task No. PVC9.92GA 

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

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

Office of Energy Efficiency and Renewable Energy 

Operated by the Alliance for Sustainable Energy, LLC 

Contract No. DE-AC36-08-GO28308 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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Report Contents 

1.0 Photovoltaic Deployment Analysis for New York City
 

2.0 A Briefing for Policy Makers on Connecting PV to a Network Grid 

3.0 Technical Review of Concerns and Solutions to PV Interconnection in New York City
 

4.0 Utility Application Process Review
 

5.0 Conclusion
 

6.0 Glossary
 

ES-i 
 

 

 

 

Executive Summary
 

The U.S. Department of Energy (DOE) has teamed with cities across the country through the 

Solar America Cities (SAC) partnership program to help reduce barriers and accelerate 

implementation of solar energy. The New York City SAC team is a partnership between the City 

University of New York (CUNY), the New York City Mayor’s Office of Long-term Planning 

and Sustainability, and the New York City Economic Development Corporation (NYCEDC).The 

New York City SAC team is working with DOE’s National Renewable Energy Laboratory 

(NREL) and Con Edison, the local utility, to develop a roadmap for photovoltaic (PV) 

installations in the five boroughs. The city set a goal to increase its installed PV capacity from 

1.1 MW in 2005 to 8.1 MW by 2015 (the maximum allowed in 2005). A key barrier to reaching 

this goal, however, is the complexity of the interconnection process with the local utility. Unique 

challenges are associated with connecting distributed PV systems to secondary network 

distribution systems (simplified to “networks” in this report). 

Although most areas of the country use simpler radial distribution systems to distribute 

electricity, larger metropolitan areas like New York City typically use networks to increase 

reliability in large load centers. Unlike the radial distribution system, where each customer 

receives power through a single line, a network uses a grid of interconnected lines to deliver 

power to each customer through several parallel circuits and sources. This redundancy improves 

reliability, but it also requires more complicated coordination and protection schemes that can be 

disrupted by energy exported from distributed PV systems. Currently, Con Edison studies each 

potential PV system in New York City to evaluate the system’s impact on the network, but this is 

time consuming for utility engineers and may delay the customer’s project or add cost for larger 

installations. City leaders would like to streamline this process to facilitate faster, simpler, and 

less expensive distributed PV system interconnections. 

The DOE/NREL Four-Part Study 

To assess ways to improve the interconnection process, NREL conducted a four-part study with 

support from DOE. The NREL team then compiled the final reports from each study into this 

report. In Section 1—PV Deployment Analysis for New York City—we analyze the technical 

potential for rooftop PV systems in the city. This analysis evaluates potential PV power 

production in ten Con Edison networks of various locations and building densities (ranging from 

high density apartments to lower density single family homes). Next, we compare the potential 

power production to network loads to determine where and when PV generation is most likely to 

exceed network load and disrupt network protection schemes. The results of this analysis may 

assist Con Edison in evaluating future PV interconnection applications and in planning future 

network protection system upgrades. This analysis may also assist other utilities interconnecting 

PV systems to networks by defining a method for assessing the technical potential of PV in the 

network and its impact on network loads. 

Section 2—A Briefing for Policy Makers on Connecting PV to a Network Grid—presents an 

overview intended for nontechnical stakeholders. This section describes the issues associated 

with interconnecting PV systems to networks, along with possible solutions. 

ES-ii 
 

 

Section 3—Technical Review of Concerns and Solutions to PV Interconnection in New York 

City—summarizes common concerns of utility engineers and network experts about 

interconnecting PV systems to secondary networks. This section also contains detailed 

descriptions of nine solutions, including advantages and disadvantages, potential impacts, and 

road maps for deployment. 

Section 4—Utility Application Process Review—looks at utility interconnection application 

processes across the country and identifies administrative best practices for efficient PV 

interconnection. 

Summary of Findings 

Section 1 finds that if PV systems were fully deployed to cover all suitable roof space in New 

York City, PV generation could exceed network load in six of the ten networks. Figure ES-1 

shows an example of network load and predicted PV generation in one network. The figure 

illustrates that PV generation exceeds network load in the spring months, resulting in energy 

exported to the network and possible disruption of network protection equipment. 

450
 

400
 

350
 

300
 

250
 

200
 

150
 

100
 

50
 

0
 

MW

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05 

Load PV Generation 

Figure ES-1. PV generation and network load 

Table ES-1gives results for all ten networks. The fourth column shows the annual maximum 

percent of network load met by PV-generated electricity (called “PV generation” in this report) 

under full PV deployment. A value greater than 100 means that PV generation surpasses network 

load, resulting in a net export of electricity from the network. Although PV generation can 

significantly exceed network loads at times (by as much as two times in the Maspeth network, 

for example), its contribution to the network’s overall energy requirements is much lower 

because energy generation is limited to daylight hours. In general, the networks with the highest 

amount of rooftop space per person export the most electricity. Generally, these networks serve 

the outer boroughs, where there are more single-family homes and office buildings with fewer 

stories. 

ES-iii 
 

 

 

 

 

 

 

 

 

 

 

Table ES-1. Network Analysis Results 

Network Name Location 

Total PV Size 

(MW AC) 

Percent of Load 

Met by PV (Annual 

Maximum; %)a 

Energy 

Penetration 

(%)b 

Bay Ridge Brooklyn 96.20 104.22 14.73 

Borough Hall Brooklyn 58.08 44.52 6.42 

Central Bronx Bronx 75.25 112.21 17.18 

Cooper Manhattan 25.73 27.17 3.76 

Flushing Queens 223.17 163.35 18.80 

Fox Hill Staten Island 97.51 142.26 18.94 

Herald Manhattan 1.29 4.31 0.45 

Maspeth Queens 188.61 203.72 26.70 

Southeast Bronx Bronx 115.85 157.65 16.41 

Sutton Manhattan 1.85 3.04 0.40 

a

Percent of load met by PV (annual maximum) = PV power generation/load × 100%, for annual maximum hour

b

Energy penetration = annual PV energy generation/annual energy consumption × 100% 

The amount of energy exported varies by time of year, day of week, and time of day. Exporting 

is highest during the spring months because PV generation is above average and loads are low. 

PV generation peaks in the spring because the PV array tilt angle (equal to the site’s latitude) 

best matches the medium sun angle that occurs in the spring and fall. The fall and winter months 

experience less (although still significant) exporting, and the summer months export little 

electricity because network loads are higher. More electricity is exported on weekends than on 

weekdays, particularly in industrial networks where loads drop when businesses close on the 

weekends. 

Over the course of a day, exporting is most likely to occur between 9:00 a.m. and 1:00 p.m., 

peaking at 11:00 a.m. PV generation is highest at midday, when the sun is directly over the 

south-facing arrays. The low midday load also contributes to high exporting. In general, the PV 

arrays reduce load significantly for about 8 hours in the morning and afternoon, but have no 

effect on nighttime loads. Because the peak load occurs in the evening in most networks, the PV 

systems reduce peak load in only three of the ten networks. In the others, the utility’s required 

generating capacity remains the same. 

ES-iv 
 

 

 

 

 

 

 

 

Because many PV arrays in the New York area are flat-mounted, we conducted additional 

analysis to evaluate how the results would change for flat-mounted PV arrays. We found that 

total annual PV power generation decreases, with production in the summer remaining about the 

same, spring and fall production dropping somewhat, and winter production falling significantly. 

The annual maximum percent of load met by PV changes very little (although the day on which 

it occurred shifts from early to late spring). Total net exporting hours are significantly reduced, 

with exporting completely eliminated in all months except May. 

This analysis evaluated the effects of full PV deployment, with all suitable roof space covered in 

PV arrays. Although it is unlikely that full PV deployment will ever be realized, some effects on 

network systems are seen even at low deployment levels. 

Section 2 describes the technical concerns associated with interconnecting distributed PV to 

network systems. Power exported from individual systems can disrupt protection and 

coordination schemes essential to the reliable operation of the network. At higher deployments, 

distributed PV systems can present challenges for load forecasting and power system planning, 

increase potential for unintentional islands, and cause power quality problems like voltage 

flicker. We end Section 2 by briefly summarizing potential solutions for these issues. 

Section 3 looks at nine solutions in more detail. We find that the most common way to prevent 

disruption to networks from distributed PV systems is to ensure that they do not export power to 

the network. This can be achieved by sizing systems so that they never produce more power than 

is consumed at the site or by adding hardware (reverse power relays [RPRs], minimum import 

relays [MIRs], or dynamically controlled inverters [DCIs]) that prevents power from exporting. 

DCIs show the most promise because they reduce PV output without taking the PV system 

offline altogether and do not require manual resets, which reduces lost output for the system 

owner. DCI costs, which are minimal compared to RPR and MIR technologies, would not be 

cost-prohibitive for smaller systems. In the future, smart grid technologies will facilitate 

interconnection of exporting PV systems through better communication and control of network 

protection equipment and PV systems. 

In Section 4, we review the administrative interconnection processes of utilities across the 

country and identify ways to streamline the distributed generation application process. This 

review suggests that making application documents available online and using an online tracking 

system (where homeowners and contractors can look up their application status) reduces wait 

time. In addition, compiling a qualified equipment list and a qualified contractor list makes 

information on acceptable equipment and trusted contractors readily available, decreasing review 

time. Finally, training and outreach programs for both contractors and homeowners help to 

improve the quality of the applications submitted. 

Future Research 

To increase understanding of the effects of distributed PV systems on networks, we recommend 

further research in the following areas: 

•	 Identify system-level impacts of high PV penetration in networks: Although the 

effects of individual PV system connections to networks have been comprehensively 

ES-v 
 

 

examined, little is known about how the entire system is affected at high penetrations of 

PV. 

•	 Identify maximum penetration levels in network systems: PV penetration levels of 

20% to 30% are generally considered to be the maximum level allowable in radial 

distribution systems before changes to the system are necessary. The maximum allowable 

penetration level on a network system, however, is unclear. Additional research is 

necessary for establishing maximum acceptable penetration levels in both area and spot 

networks. 

•	 Improve modeling of distributed generation in network systems: Current modeling 

solutions do not adequately address the system impacts of distributed generation in 

network systems. Additional research and development should be directed at improving 

modeling solutions for network systems. 

•	 Develop smart grid technologies: Future smart grid technologies may offer intelligent 

monitoring and control of PV systems that will allow better integration into network 

systems. Research and development of smart grid technologies, with a particular focus on 

their applicability in network systems, should continue. 

ES-vi 
 

1.0 Photovoltaic Deployment Analysis for New York City 

This study evaluated the technical potential of rooftop photovoltaics (PV) in ten New 

York City networks. To determine the maximum technical PV potential for each network, 

analysts from the U.S. Department of Energy’s (DOE) National Renewable Energy 

Laboratory (NREL) assessed suitable roof space and estimated the power that could be 

produced if all suitable space were covered with PV arrays. PV power levels were then 

compared to actual hourly load levels in each network. The results of the study, 

presented in this section, are intended to help New York City and its utility, Con Edison, 

plan for increased PV deployment on the city’s secondary network distribution system by 

showing where and when PV-generated electricity (called “PV generation” in this report) 

is most likely to exceed network load and disrupt network protection schemes. The 

results may assist Con Edison in evaluating future PV interconnection applications and 

planning future network protection system upgrades. This study might also help other 

utilities that are interconnecting PV systems to networks by defining a method for 

assessing the technical potential of PV in the network and its impact on network loads. 

1-1
 
 

 

 

Contents 

1.1 Introduction............................................................................................................................3
 

1.2 Methodology..........................................................................................................................3
 

1.2.1 Analyzing the Building Type Composition of Each Network Area.......................... 4
 

1.2.2 Analyzing the Suitable Roof Space in Each Building Type Category ...................... 5
 

1.2.3 Calculating the Suitable Roof Space and Maximum Capacity of PV in Each 

Network Area...................................................................................................................... 7
 

1.2.4 Calculating PV Power Production ............................................................................. 8
 

1.2.5 Comparing PV Electricity Production to Network Loads ......................................... 9
 

1.3 Results....................................................................................................................................9
 

1.3.1 Percent of Network Area Covered by PV................................................................ 10
 

1.3.2 Total PV Size ........................................................................................................... 10
 

1.3.3 Percent of Load Met by PV (Annual Maximum) .................................................... 10
 

1.3.4 Capacity Penetration ................................................................................................ 10
 

1.3.5 Energy Penetration................................................................................................... 11
 

1.3.6 Network Load and PV Generation under Full PV Deployment .............................. 11
 

1.3.7 Maximum Export Day under Full PV Deployment................................................. 16
 

1.3.8 8760-Hour Load-Duration Curve ............................................................................ 19
 

1.3.9 8760-Hour Load-Duration Curve, Top 100 Hours .................................................. 23
 

1.3.10 Exported Energy .................................................................................................... 27
 

1.4 Discussion............................................................................................................................34
 

1.5 Sources of Error ...................................................................................................................35
 

1.6 Conclusion ...........................................................................................................................35
 

Appendix 1-A: Network PV Deployment Percentage and PV Capacity Calculations ......... 37
 

1.A.1 Bay Ridge........................................................................................................................37
 

1.A.2 Borough Hall....................................................................................................................38
 

1.A.3 Central Bronx...................................................................................................................40
 

1.A.4 Cooper Square.................................................................................................................41
 

1.A.5 Flushing............................................................................................................................42
 

1.A.6 Fox Hills...........................................................................................................................42
 

1.A.7 Herald Square..................................................................................................................43
 

1.A.8 Maspeth............................................................................................................................44
 

1.A.9 Southeast Bronx ...............................................................................................................45
 

1.A.10 Sutton .............................................................................................................................46
 

Appendix 1-B: PV Generation for Flat-Mounted Arrays....................................................... 47
 

Appendix 1-C: Individual Building Analysis ........................................................................... 54
 

1.C.1 Primary School.................................................................................................................54
 

1.C.2 Mid-Rise Apartment Building..........................................................................................56
 

1.C.3 Stand-Alone Retail Store..................................................................................................57
 

1.C.4 Warehouse Building.........................................................................................................58
 

1.C.5 Conclusion........................................................................................................................59
 

1-2
 
 

 

 

 

 

 

1.1 Introduction 

Although most areas of the country use simpler radial distribution systems to distribute 

electricity, larger metropolitan areas like New York City typically use more complicated 

secondary network distribution systems (referred to as “networks” in this report) to 

increase reliability in large load centers. Unlike the radial distribution system, where each 

customer receives power through a single line, a network uses a grid of interconnected 

lines to deliver power to each customer through several parallel circuits and sources. 

This redundancy improves reliability, but also requires protective devices called 

“network protectors” (NPs) that prevent power from back-feeding from one transformer 

through another. Network protector operation can be disrupted by energy exported to the 

network from distributed generation. At current levels of distributed PV deployment, PV 

generation is so small compared to network loads that any electricity exported to the 

network is consumed by nearby loads. At higher levels of deployment, however, PV 

could generate enough electricity to back-feed through network protectors, potentially 

causing these devices to open unnecessarily, which would reduce network reliability. 

To assess PV generation at high deployment levels and the effect it might have on the 

network, an NREL team conducted a study to evaluate the technical potential of rooftop 

PV in ten New York City networks. We selected the particular networks to study because 

they represent a cross section of all of New York City’s 62 networks. 

We determined the maximum technical PV potential for each network by assessing 

suitable roof space and estimating the power that could be produced if all suitable space 

were covered with PV arrays. Next, we compared the PV generation levels to actual 

hourly load levels in each network. We found that if PV systems were fully deployed to 

cover all suitable roof space in New York City, PV generation could exceed network load 

in six of the ten networks. This would be most likely to occur at midday during spring 

weekends in the lower density outer boroughs. 

It is important to note that we performed this analysis at the macro level, comparing total 

loads and total PV generation across entire networks. Although this allowed us to 

estimate net energy exported from the network as a whole, network protectors operate 

within the network and will respond to more localized energy exporting. To predict the 

effects of exporting PV energy on individual network protectors, a more detailed study at 

the individual building level is required. 

1.2 Methodology 

With support from DOE, the NREL team analyzed ten Con Edison networks to determine 

the maximum technical PV deployment possible in each network area. We used NREL’s 

In My Backyard (IMBY) tool to estimate the amount of roof space suitable for PV arrays 

in each network area.1 Based on the suitable area and an average PV power density, we 

determined the total capacity of rooftop PV. Based on this capacity and on site weather 

1

For more information on IMBY, see http://www.nrel.gov/eis/imby/. 

1-3
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

data, we calculated hourly PV production, then compared these data to actual hourly load 

levels in each network. Finally, we analyzed the data in more depth to determine in which 

hours PV generation exceeded network load, and by how much. The subsections that 

follow outline the analysis steps in detail. 

1.2.1 Analyzing the Building Type Composition of Each Network Area 

Because the percentage of total network area available for PV varies by building type and 

density, we examined satellite images to determine the building composition of each 

network. Some areas were homogenous, with similar building types and densities across 

much of the network. In other networks, building types varied significantly. In 

nonhomogenous networks, we broke down the total built area into categories by building 

type, building density, and, for the warehouses, availability of rooftop space (see Table 1­

1). We estimated roof-space availability based on visible rooftop obstructions. The blue 

areas on the rooftops in the example images in Table 1-1 represent potential PV arrays 

for the selected block. 

Table 1-1. Building Categories 

Building 

Category 

LowDensity 

Residential 

Description 

Includes widely spaced single-family 

homes (generally found on the outskirts 

of the outer boroughs), as well as 

widely spaced high-rise apartment 

buildings. Less than 50% of the total 

land area is occupied by buildings. 

Example Image 

HighDensity 

Residential 

Includes closely spaced or attached 

single-family homes, multifamily units, 

and apartment buildings. More than 

50% of the total land area is occupied 

by buildings. 

LowDensity 

Warehouse 

(Poor 

Availability) 

Includes large, low commercial 

buildings with wide expanses of roof 

space. Less than 50% of the total land 

area is occupied by buildings, and less 

than 20% of the roof space is available 

for PV. 

1-4
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LowDensity 

Warehouse 

(Good 

Availability) 

Includes large, low commercial 

buildings with wide expanses of roof 

space. Less than 50% of the total land 

area is occupied by buildings, and more 

than 20% of the roof space is available 

for PV. 

HighDensity 

Warehouse 

(Poor 

Availability) 

Includes large, low commercial 

buildings with wide expanses of roof 

space. More than 50% of the total land 

area is occupied by buildings, and less 

than 20% of the roof space is available 

for PV. 

HighDensity 

Warehouse 

(Good 

Availability) 

Includes large, low commercial 

buildings with wide expanses of roof 

space. More than 50% of the total land 

area is occupied by buildings, and more 

than 20% of the roof space is available 

for PV. 

High- Includes closely spaced high-rise 

Density buildings, found mainly in Manhattan. 

High-Rise 

For example, in analyzing the satellite imagery of the Bay Ridge network, we found that 

the area is made up of 80% high-density residential buildings; 4% low-density warehouse 

(poor availability) buildings; 5% low-density warehouse (good availability) buildings; 

5% high-density warehouse (poor availability) buildings; and 6% high-density warehouse 

(good availability) buildings. 

These percentages represent the percent of the total network area (%TNA) attributed to 

each building category. Appendix 1-A contains details of building categories in each 

network area. We estimate that the building composition percentages are ±2% accurate. 

1.2.2 Analyzing the Suitable Roof Space in Each Building Type Category 

We used IMBY to perform a detailed analysis of 10% of the area in each building 

category in each network to estimate the amount of roof space suitable for PV in that 

1-5
 
 

 

 

 

 

 

 

 

 

sample area.2 Roofs were covered to the maximum extent practical, taking into 

consideration the following factors: 

• Rooftop obstructions preventing PV placement 

• Shading by rooftop obstructions, parapets, nearby buildings, or trees 

• Walkway space required around obstructions and PV panels for access and safety 

•	 Roof aspect—east, south, and west-facing roofs were covered; north-facing roofs 

were avoided. 

Visible rooftop maintenance conditions were evaluated as well (see Appendix 1-A), but 

we included rooftop space regardless of condition to assess the maximum amount of 

available space. 

Using IMBY, we estimated the suitable space on each rooftop in the sample area 

(accurate to within ±10%). Next, we summed the suitable areas on each rooftop to 

calculate the total suitable space in the sample area and compared this value to the size of 

the entire sample area. This allowed us to estimate the PV deployment percentage 

(PVD%): the percentage of the sample area that could be covered in PV arrays (see 

Equation 1-1). That percentage was assumed to be equal to the percentage calculated for 

its sample area. We estimate that this is 5% to 15% accurate, depending on the size of the 

sample area (larger sample areas including many buildings are more accurate) and the 

variation in the building category (less varied categories are more accurate). 

PV deployment percentage (PVD%)Sample Area A= 

× ∑

Sample area A

area Array area array area array N ( , ,... ) 1 2 (1-1) 100% 

For example, if a 1,000-m2 sample area contained five buildings, and the IMBY analysis 

found that each had 10 m2 of suitable roof space, the PVD% would be 

PVD% = (10+10+10+10+10)/1000 × 100% = 5%. 

Appendix 1-A contains PVD% details in each building category for each network. 

2 IMBY estimates the size of a polygon drawn on a Google map satellite image. Based on this size and an 

average power density, it then estimates electricity production using the PVWatts performance model (for 

more information on PVWatts, see http://www.nrel.gov/rredc/pvwatts/). IMBY is typically used to estimate 

the size and potential electricity production of a PV array or wind turbine at an individual home or 

business. In this study, we used it to estimate the size of PV arrays over a large area. 

1-6
 
 

 

 

 

 

1.2.3 Calculating the Suitable Roof Space and Maximum Capacity of PV in 

Each Network Area 

To estimate the overall network PV deployment percentage, we multiplied the PVD% 

figures calculated in each building category (see Section 1.2.2) by the corresponding 

%TNA figures (see Section 1.2.1 and Equation 1-2). 

PV deployment percentage (PVD%)network = 

[(PVD%1) × (%TNA1) + (PVD%2) × (%TNA2) +... + (1-2) (PVD%n) × (%TNAn)]/100 

For example, the PVD% and %TNA for each building category in the network (see Table 

1-2) can be multiplied as follows to calculate the network PVD%: 

PVD% Network = [10 × 50 + 5 × 20 + 15 × 30] / 100 = 10.5%. 

This number represents the maximum percentage of the total network area that could be 

covered in PV arrays, assuming that all suitable roof space was used. 

Table 1-2. PVD% and %TNA for Sample Network Building Categories 

Building Category PVD% %TNA 

High-Density Residential 

High-Density Warehouse (Poor 

Availability) 

10 

5 

50 

20 

High-Density Warehouse (Good 

Availability) 15 30 

To calculate the total area of the PV arrays in a network at full PV deployment, we 

multiplied the size of the total network area by the network PVD%. Using the resulting 

value, we applied a power density of 0.1 kW DC/m2 to calculate the total capacity (in 

kilowatts) of PV in the network (see Equation 1-3). In reality, this power density will 

vary by ±15%, depending on individual module characteristics. 

PV capacity network = total network area × PVD% × 0.1 kW DC/m

2 (1-3) 

For example, if a network had an area of 10 km2 (10,000,000 m2) and a PVD% of 10.5%, 

the network’s PV capacity would be 

PV capacity = 10,000,000 m2 × 0.105 × 0.1 kW DC/m2 = 105 MW DC. 

The AC capacity is calculated by multiplying by a DC-to-AC derate factor of 0.77. For 

the example given here, the AC capacity would be 105 × 0.77 = 81 MW AC. 

1-7
 
 

 

 

 

 

 

 

 

 

1.2.4 Calculating PV Power Production 

We used IMBY’s solar estimator to model the PV power on an hourly basis for 2005 

annual data. IMBY made use of Perez Satellite Solar Resource Data (satellite-derived, 

high-resolution data from visible channel images from geostationary satellites)3 and 

PVWatts (as the PV performance model) to estimate hourly AC power production for a 

crystalline silicon PV system. Using the 2005 Perez weather data from New York City, 

the solar estimator calculated the solar radiation incident on the PV array and the PV cell 

temperature for each hour of the year. The DC power for each hour was calculated from 

the PV system DC rating and the incident solar radiation, and then corrected for the PV 

cell temperature. The AC power for each hour was calculated by multiplying the DC 

power by the overall DC-to-AC derate factor and adjusting for inverter efficiency as a 

function of load. The PV power production estimate is accurate to within 10% to 12%.4 

We made the following assumptions in calculating power generated from the PV arrays: 

•	 The overall DC-to-AC derate factor was 0.77. This is the standard derate factor 

assumed in PVWatts. It accounts for losses from the components of the PV 

system, including inverter and transformer, mismatch, diodes and connections, 

DC wiring, AC wiring, soiling, system availability, shading, sun-tracking, and 

age. 

•	 All PV arrays were assumed to be fixed (not tracking the sun). Sun-tracking 

arrays could generate between 25% and 40% more electricity. 

•	 The PV array tilt angle was equal to the site’s latitude (40.8° N). This 

normally maximizes annual energy production. Increasing the tilt angle favors 

energy production in the winter; decreasing the tilt angle favors energy production 

in the summer. A tilt angle equal to the site’s latitude will favor energy production 

in the spring and fall. In this case, because Con Edison sees its minimum loads in 

spring and fall, maximizing PV production for spring and fall allowed us to 

analyze maximum energy exporting. Because many New York area PV systems 

are flat-mounted, we also analyzed one network with a PV array tilt angle equal to 

zero (flat-mounted). Appendix 1-B contains this analysis for comparison. 

•	 The PV array azimuth angle was 180° (south-facing). This normally maximizes 

energy production. 

•	 The installed nominal operating temperature was 45°C. This is the PVWatts 

default. 

•	 The power degradation resulting from temperature was 0.5%/°C. This is the 

PVWatts default. 

•	 The angle-of-incidence (reflection) losses for a glass PV module cover were 

calculated as presented by King and colleagues.5 

3 Perez R.; Ineichen, P; Moore, K.; Kmiecik, M.; Chain, C., George, R.; Vignola, F. “A New Operational
 

Satellite-to-Irradiance Model.” Solar Energy; Vol. 73 (5), 2002; 307–317.
 4 See http://www.nrel.gov/rredc/pvwatts/interpreting_results.html.
 5 King, D; Kratochvil, J; Boyson, W. “Field Experience with a New Performance Characterization
 

Procedure for Photovoltaic Arrays.” Presented at the Second World Conference and Exhibition on 

Photovoltaic Solar Energy Conversion, July 6–10, 1998.
 

1-8
 
 

 

 

 

 

 

 

 

 

 

 

 

1.2.5 Comparing PV Electricity Production to Network Loads 

We compared the predicted PV production under full PV deployment to actual 2005 Con 

Edison network loads. The next section gives the results of this comparison. 

1.3 Results 

PV generation under full PV deployment was compared to network loads for the ten 

network areas. The results for each network are presented in Table 1-3 and in the graphs 

that follow. We discuss these results in more detail in Section 1.4. 

Table 1-3. Network Analysis Results 

Percent 

of 

Network 

Area Total PV Percent of 

Network Name 

(Borough) 

Covered 

by PV 

(%)a 

Size 

(MW 

AC)b 

Load Met by 

PV (Annual 

Maximum; %)c 

Capacity 

Penetration 

(%)d 

Energy 

Penetration 

(%)e 

Central Bronx (Bronx) 10.16 75.25 112.21 68.73 17.18 

Bay Ridge (Brooklyn) 10.12 96.20 104.22 48.87 14.73 

Borough Hall (Brooklyn) 9.60 58.08 44.52 23.52 6.42 

Southeast Bronx (Bronx) 8.66 115.85 157.65 57.69 16.41 

Cooper (Manhattan) 7.91 25.73 27.17 11.94 3.76 

Maspeth (Queens) 7.18 188.61 203.72 85.80 26.70 

Herald (Manhattan) 6.94 1.29 4.31 1.35 0.45 

Flushing (Queens) 5.64 223.17 163.35 58.67 18.80 

Sutton (Manhattan) 3.84 1.85 3.04 1.32 0.40 

Fox Hill (Staten Island) 2.99 97.51 142.26 53.18 18.94 a Percent of network area covered by PV: Calculated as shown in Section 1.2.3 

b Total PV size = size of PV array covering entire network × percent of network area covered by PV 

c Percent of load met by PV (annual maximum) = PV power generation/load × 100, for annual maximum 

hour (coincident). Coincident means the PV generation and load occur during the same hour.

d Capacity penetration = annual peak PV power generation/annual peak load × 100 (noncoincident). 

Noncoincident means the PV generation and load occur during different hours. 

e Energy penetration = annual PV energy generation/annual energy consumption × 100 

1-9 
 

 

 

 

 

 

1.3.1 Percent of Network Area Covered by PV 

The second column in Table 1-3 shows the percent of the total network land area that 

could be covered with PV arrays under full PV deployment (PVD%). This number is 

based on our analysis of the 10% sample area, and varies from 3% to 10%, depending on 

the density of buildings in the network area. The higher density networks have more 

buildings per square foot and therefore more rooftop space, which allows for larger 

amounts of PV per square foot. The lower density networks have fewer buildings per 

square foot and therefore a lower percentage of rooftop space available for PV arrays. For 

example, the high-density Bay Ridge, Borough Hall, Central Bronx, and Southeast Bronx 

networks have higher PVD%. The lower density Flushing, Fox Hill, and Maspeth 

networks have lower PVD%. Manhattan networks (Sutton, Herald, and Cooper) are an 

exception to this rule—even though they are high density, they tend to have low to 

medium PVD% because rooftop equipment and shading from neighboring high-rise 

buildings leave little space available for PV arrays. 

1.3.2 Total PV Size 

The third column in Table 1-3 shows the cumulative size of all PV systems in the 

network—in megawatts of alternating current power—under full PV deployment. This is 

the amount of power that could be produced by PV if all suitable rooftop space were 

covered (see Equation 1-4). 

Total PV size = size of PV array covering entire network × percent of (1-4) 

network area covered by PV 

1.3.3 Percent of Load Met by PV (Annual Maximum) 

The fourth column in Table 1-3 shows the maximum percent of network load supplied by 

PV-generated electricity, calculated as shown in Equation 1-5. It represents the one 

maximum hour during the year—in all other hours, the percentage will be lower. This 

hour is different for each network, but generally occurs at midday during the spring. A 

value greater than 100 shows that PV generation surpasses network load, meaning that 

there is a net export of electricity from the network. Note that these are coincident power 

generation and load values. 

Percent of load met by PV (Annual Maximum ) =
 

(1-5) 

×100 

 

Maximum hour PV power generation (kW ) 

Maximum hour load (kW ) 

1.3.4 Capacity Penetration 

The values in the fifth column in Table 1-3 are calculated by dividing the annual peak PV 

power generation (the PV generation during the 1 hour of the year when PV generation is 

at its highest) by the annual peak network load (the load during the 1 hour of the year 

when load is at its highest; see Equation 1-6). It is similar to “percent of load met by 

PV(annual maximum)” in that it is a measure of how much of the load is being generated 

1-10 

 
 
 

 

 

by PV. In this case, however, the generation and load values are noncoincident. Capacity 

penetration is a value commonly used by utilities in the peak hour report to evaluate the 

impact of distributed generation on network loads. 

Capacity penetration percentage =

)( 

)( ×

 

 Annual load peak 



kW 

Annual peak PV power generation kW (1-6) 

100 

1.3.5 Energy Penetration 

The last column in Table 1-3 shows the percent of annual network energy needs met by 

annual PV energy generation, calculated as shown in Equation 1-7. We see that even 

though PV energy production (in kilowatt-hours or megawatt-hours) may significantly 

surpass network loads in a single hour, it makes a much smaller contribution to total 

annual energy use. 

Energy penetration percentage =

(1-7) 

)( 

)( ×



 





Annual energy consumption kWh 

Annual PV energy generation kWh 100
 

We developed graphs to further illuminate the impact of PV generation in each network 

under full PV deployment. Each network has an associated graph that illustrates the 

following: 

• Network load and PV generation under full PV deployment 

• Maximum export day under full PV deployment 

• 8760-hour load-duration curve 

• 8760-hour load-duration curve, top 100 hours 

• Exported energy by month, day, and time. 

1.3.6 Network Load and PV Generation under Full PV Deployment 

Figures 1-1 through 1-10 chart the 2005 load and PV generation (under full deployment) 

for each network. They show how PV generation compares to loads over the course of 

the year, including how often PV generation surpasses load (if at all), and when. Because 

we were comparing PV generation to hourly loads (in megawatts), we used PV power 

generation (in megawatts) rather than energy generation (in megawatt-hours). 

From these graphs, we see that PV generation potential varies significantly between 

networks. In Herald and Sutton, for example, PV generation never approaches network 

load levels. In the Maspeth network, on the other hand, PV generation exceeds network 

loads throughout much of the year. In six of the ten evaluated networks, if PV arrays 

were fully deployed, they would sometimes generate more energy than the network could 

1-11
 
 

 

 

use. In general, the most likely areas to experience exporting are those with the highest 

amount of rooftop space per person. In areas of dense high-rise buildings (like 

Manhattan), where many people live or work under one roof, space available for PV 

arrays is small, and the energy they produce will be small compared to the load generated 

by all the people under that roof. In a residential area like Staten Island, however, people 

mainly live in single-family homes and office buildings tend to have only a few stories. 

Because there is a much larger amount of roof space per person, PV can generate a much 

higher percent of the minimum load. 

Figures 1-1 through 1-10 also show that, because the PV arrays are tilted at an angle 

equal to the site’s latitude (40.8° N), PV power output is greatest in the spring and fall. 

This tilt angle favors power production in the spring and fall because it best matches the 

medium sun angle that occurs during those seasons (halfway between the low winter sun 

and high summer sun). Note that this is different from energy production. Energy 

production (measured in megawatt hours) would peak in the summer months, when more 

daylight hours will result in more energy produced, even though less energy is produced 

per hour. MW

0 

50 

100 

150 

200 

250 

Jan-05 Apr-05 

Load 

Jun-05 Sep-05 Dec-05 

PV Generation 

Figure 1-1. Bay Ridge network load and maximum PV generation under full
 

PV deployment
 

1-12
 
MW

300

250

200

150

100

50

0

Jan‐05 Apr‐05 Jun‐05 Sep‐05 Dec‐05

Load PV Generation

Figure 1-2. Borough Hall network load and maximum PV generation under 

full PV deployment 

140

120

100

80

MW

60

40

20

0

Jan‐05 Apr‐05 Jun‐05 Sep‐05 Dec‐05

Load PV Generation

Figure 1-3. Central Bronx network load and maximum PV generation under 

full PV deployment 

300
 

250
 

200
 

MW

150

100

50

0

Jan‐05 Apr‐05 Jun‐05 Sep‐05 Dec‐05

Load PV Generation

Figure 1-4. Cooper network load and maximum PV generation under full PV 

deployment 

1-13 
 

 

 

500 

400 

300 

200 

100 

0 

Load PV Generation 

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05 

MW

Figure 1-5. Flushing network load and maximum PV generation under full PV 

deployment 

250
 

200
 

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05 

MW

150 

100 

50 

0 

Load PV Generation 

Figure 1-6. Fox Hill network load and maximum PV generation under full PV 

deployment 

120
 

100
 

80
 

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05 

MW

60 

40 

20 

0 

Load PV Generation 

Figure 1-7. Herald network load and maximum PV generation under full PV 

deployment 

1-14 
 

 

 

 

250 

200 

150 

100 

50 

0 

Load PV Generation 

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05 

MW

Figure 1-8. Maspeth network load and maximum PV generation under full PV 

deployment 

250
 

200
 

MW MW

150 

100 

50 

0 

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05 

Load PV Generation 

Figure 1-9. Southeast Bronx network load and maximum PV generation 

under full PV deployment 

200 

150 

100 

50 

0 

Jan-05 Apr-05 Jun-05 Sep-05 Dec-05
 

Load PV Generation
 

Figure 1-10. Sutton network load and maximum PV generation under full PV 

deployment 

1-15 
 

 

1.3.7 Maximum Export Day under Full PV Deployment 

Figures 1-11 through 1-20 offer a detailed look at the day during which the maximum 

export hour occurs (or, for nonexporting networks, the day when PV generation levels 

come closest to load levels). These graphs show the load and PV generation over 24 

hours and illustrate how PV generation reduces load, at what times of day the reduction 

occurs, and by how much. (Reduced load is equal to load minus PV generation.) When 

the reduced load dips below 0 MW, energy is exported to the network. We used hourly 

data to make these comparisons. 

From these graphs we see that PV generation can reduce load significantly in the morning 

and afternoon (between 7 a.m. and 4 p.m.), but it has no effect on evening loads. In 

general, PV generation results in a smooth dip in reduced load, but passing clouds can 

create abrupt decreases in PV generation, resulting in a more jagged curve (see Figure 1­

19). 

MW -20 

0 

20 

40 

60 

80 

100 

120 

0:00 4:00 8:00 0:00 

Load 

12:00 16:00 20:00 

Time 

Reduced Load PV Generation 

Figure 1-11. Bay Ridge maximum export day, March 26, 2005 

0 

20 

40 

60 

80 

100 

120 

140 

160 

MW 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Time 

Load Reduced Load PV Generation 

Figure 1-12. Borough Hall maximum export day, February 13, 2005 

1-16
 
 

 

 

MW

80 

60 

40 

20 

0 

-20 

Time 

Load Reduced Load PV Generation 

Figure 1-13. Central Bronx maximum export day, May 1, 2005 

0:00 4:00 8:00 12:00 16:00 20:00 0:00
 

0 

20 

40 

60 

80 

100 

120 

0:00 4:00 8:00 0:00 

MW 

Load 

Figure 1-14. Cooper maximum export day, April 10, 2005 

12:00 16:00 20:00 

Time 

Reduced Load PV Generation 

-100 

-50 

0 

50 

100 

150 

200 

250 

MW 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Time 

Load Reduced Load PV Generation 

Figure 1-15. Flushing maximum export day, April 9, 2005 

1-17
 
 

 

 

 

-40 

-20 

0 

20 

40 

60 

80 

100 

120 

MW 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Time 

Load Reduced Load PV Generation 

Figure 1-16. Fox Hill maximum export day, April 9, 2005 

0 

10 

20 

30 

40 

50 

60 

70 

80 

0:00 4:00 8:00 0:00 

MW 

12:00 16:00 20:00 

Time 

Load Reduced Load PV Generation 

Figure 1-17. Herald maximum export day, March 18, 2005 

-100 

-50 

0 

50 

100 

150 

200 

MW 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Time 

Load Reduced Load PV Generation 

Figure 1-18. Maspeth maximum export day, February 27, 2005 

1-18
 
 

 

MW

100 

80 

60 

40 

20 

0 

-20 

-40 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Load 

Time 

Reduced Load PV Generation 

Figure 1-19. Southeast Bronx maximum export day, November 13, 

2005 

70
 

60
 

50
 

MW

0 

10 

20 

30 

40 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Time 

Load Reduced Load PV Generation 

Figure 1-20. Sutton maximum export day, March 13, 2005 

1.3.8 8760-Hour Load-Duration Curve 

Figures 1-21 through 1-30 plot the 8760-hour load values over the course of the year, 

sorted in descending order, and the 8760-hour reduced-load (load minus PV generation) 

values, also sorted in descending order. The right side of the graphs show us how many 

hours per year PV energy exports to the grid under full deployment (export occurs when 

the reduced load line dips below 0 MW). Each figure also notes the percentage of full 

deployment and capacity of PV that would reduce net exporting hours to zero. 

1-19
 
MW

250 

200 

150 

100 

50 

0 

-50 

1 2,001 4,001 6,001 8,001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there is one hour net exporting. To reduce exported hours to zero, limit 

deployment to 95.96% of full deployment (92.31 MW).

Figure 1-21. Bay Ridge 8760-hour load-duration curve 

300
 

250
 

200
 

MW MW150 

100 

50 

0 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are 0 hours net exporting.

Figure 1-22. Borough Hall 8760-hour load-duration curve

120 

100 

80 

60 

40 

20 

0 

-20 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are 53 hours net exporting. To reduce exported hours to zero, limit 

deployment to 89.12% of full deployment (67.06 MW).

Figure 1-23. Central Bronx 8760-hour load-duration curve

1-20 
MW MW 

300 

250 

200 

150 

100 

50 

0 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are zero hours net exporting.

Figure 1-24. Cooper 8760-hour load-duration curve

500 

400 

300 

200 

100 

0 

-100 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are 313 hours net exporting. To reduce exported hours to zero, limit 

deployment to 61.22% of full deployment (136.62 MW). 

Figure 1-25. Flushing 8760-hour load-duration curve

250
 

200
 

150
 

MW

100 

50 

0 

-50 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are 406 hours net exporting. To reduce exported hours to zero, limit 

deployment to 70.29% of full deployment (68.54 MW).

Figure 1-26. Fox Hill 8760-hour load-duration curve

1-21 
MW MW

120 

100 

80 

60 

40 

20 

0 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are zero hours net exporting.

Figure 1-27. Herald 8760-hour load-duration curve

250 

200 

150 

100 

50 

0 

-50 

-100 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are 901 hours net exporting. To reduce exported hours to zero, limit 

deployment to 49.09% of full deployment (92.58 MW).

Figure 1-28. Maspeth 8760-hour load-duration curve

250
 

200
 

150
 

MW

100 

50 

0 

-50 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are 173 hours net exporting. To reduce exported hours to zero, limit 

deployment to 63.43% of full deployment (73.48 MW). 

Figure 1-29. Southeast Bronx 8760-hour load-duration curve

1-22 
MW

200 

150 

100 

50 

0 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 

Note: Under full deployment, there are zero hours net exporting. 

Figure 1-30. Sutton 8760-hour load-duration curve

1.3.9 8760-Hour Load-Duration Curve, Top 100 Hours

Figures 1-31 through 1-40 zoom in on the top 100 hours of the 8760-hour load-duration 

curve, allowing us to see if the PV generation reduces peak loads. (The reduced load line 

has a lower maximum load value than the load line if PV reduces peak loads.) Peak load 

reduction is beneficial because it would allow the utility to reduce overall generation 

capacity and relieve network equipment (e.g., substations, feeders, and transformers). 

The load-duration curves for the top 100 hours show that PV systems reduce peak load 

only slightly in most networks. Central Bronx sees the biggest reduction, at 4.68% of 

peak load. Bay Ridge and Borough Hall each see about a 1.75% reduction. In the 

remaining networks, peak load is reduced by less than 1%. This is because peak load 

occurs later in the day in most networks, when PV systems are not producing power. 

Even though the PV-generated electricity can significantly exceed network loads at times 

(as much as double the load in the Maspeth network), its contribution to the network’s 

overall energy requirements is much lower, because energy generation is limited to 

daylight hours. 

230
 

220
 

210
 

MW200 

190 

180 

170 

160 

1 11 21 31 41 51 61 71 81 91 101 

Sorted Hours 

Load Reduced Load 

Figure 1-31. Bay Ridge 8760-hour load-duration curve, top 100 hours

1-23 
 

 

 

280
 

MW

270 

260 

250 

240 

230 

220 

1 11 21 31 41 51 61 71 81 91 101 

Sorted Hours 

Load Reduced Load 

Figure 1-32. Borough Hall 8760-hour load-duration curve, top 100 hours 

125
 

120
 

115
 

1 11 21 31 41 51 61 71 81 91 101
 

MW

110 

105 

100 

95 

Sorted Hours 

Load Reduced Load 

Figure 1-33. Central Bronx 8760-hour load-duration curve, top 100 hours 

250
 

240
 

230
 

MW220 

210 

200 

190 

180 

1 11 21 31 41 51 61 71 81 91 101 

Sorted Hours 

Load Reduced Load 

Figure 1-34. Cooper 8760-hour load-duration curve, top 100 hours 

1-24
 
 

 

 

440 

420 

400 

MW

380

360 

340 

1 11 21 31 41 51 61 71 

Sorted Hours 

Load Reduced Load 

81 91 101 

Figure 1-35. Flushing 8760-hour load-duration curve, top 100 hours 

250 

200 

1 11 21 31 41 51 61 71 81 91 101
 

MW150 

100 

50 

0 

Sorted Hours 

Load Reduced Load 

Figure 1-36. Fox Hill 8760-hour load-duration curve, top 100 hours 

108
 

106
 

104
 

MW

102 

100 

98 

96 

1 11 21 31 41 51 61 71 81 91 101 

Sorted Hours 

Load Reduced Load 

Figure 1-37. Herald 8760-hour load-duration curve, top 100 hours 

1-25
 
 

 

 

250
 

240
 

230
 

MW

220

210 

200 

1 11 21 31 41 51 61 71 

Sorted Hours 

Load Reduced Load 

81 91 101 

Figure 1-38. Maspeth 8760-hour load-duration curve, top 100 hours 

225
 

220
 

215
 

1 11 21 31 41 51 61 71 81 91 101
 

MW210 

205 

200 

195 

190 

Sorted Hours 

Load Reduced Load 

Figure 1-39. Southeast Bronx 8760-hour load-duration curve, top 100 hours 

160
 

155
 

1 11 21 31 41 51 61 71 81 91 101
 

MW150 

145 

140 

135 

Sorted Hours 

Load Reduced Load 

Figure 1-40. Sutton 8760-hour load-duration curve, top 100 hours 

1-26
 
 

 

 

 

 

 

 

1.3.10 Exported Energy 

Figures 1-41 through 1-76 give more detail on when energy is exported to the grid. They 

show which times of the day, days of the week, and months of the year are most likely to 

experience exporting energy. The graphs show this information in two ways—the amount 

of energy exported per year (in megawatt-hours) and the number of hours per year during 

which energy is exported. Note that we include these graphs only for the six networks 

that export energy. 

Figures 1-41 through 1-52 show energy exported by month. These graphs show that the 

most likely time of year for PV energy exporting to the grid is the spring (March–May). 

This can be attributed to good PV generation (almost as high as the peak summer energy 

generation) and low loads. The fall and winter months experience less (although still 

significant exporting), and the summer months see little exporting because of higher 

network loads. 

0 

0.5 

1 

1.5 

2 

2.5 

3 

3.5 

4 

4.5 

January

February

March

April

May

June

July

August

September

October

November

December 

MWh 

0 

0.2 

0.4 

0.6 

0.8 

1 

1.2 

January

February

March

April

May

June

July

August

September

October

November

December 

Number of Hours 

Figure 1-41. Bay Ridge amount of Figure 1-42. Bay Ridge number of hours 

energy exported by month of energy exported by month 

1-27 
 

 

 

 

 

15 

20 

25 

30 

35 

40 

45 

MWh MWh MWh 

Figure 1-45. Flushing amount of energy Figure 1-46. Flushing number of hours 

exported by month of energy exported by month 

14 

Figure 1-43. Central Bronx amount of Figure 1-44. Central Bronx number of 

energy exported by month hours of energy exported by month 

45 14

10
 

5
 

0
 

15
 

30
 25
 20
 

35
 

45
 40
 

0
 

5
 10
 15
 

30
 25
 20
 

35
 40
 

January

February

March

April

May

June

July

August

September

October

November

December 

January

February

March

April

May

June

July

August

September

October

November

January

February

March

April

May

June

July

August

September

October

November

December December 

January

February

March

April

May

June

July

August

September

October

November

Number of Hours Number of Hours Number of Hours 

0
 

2
 

4
 

6
 

8
 

10
 

12
 

0
 

2
 

4
 

6
 

8
 

10
 

12
 

2
 

4
 

6
 

8
 

10
 

12
 

January

February

March

April

May

June

July

August

September

October

November

January

February

March

April

May

June

July

August

September

October

November

14 

0
 

Figure 1-47. Fox Hill amount of energy 

exported by month 

Figure 1-48. Fox Hill number of hours of 

energy exported by month 

1-28 

December December December 

0 

5 

10 
 

 

 

 

Figure 1-49. Maspeth amount of energy 

exported by month 

Figure 1-50. Maspeth number of hours 

of energy exported by month 

0 

1000 

2000 

3000 

4000 

5000 

6000 

7000 

January

February

March

April

May

June

July

August

September

October

November

December 

MWh 

0 

20 

40 

60 

80 

100 

120 

140 

January

February

March

April

May

June

July

August

September

October

November

December 

Number of Hours 

0 

100 

200 

300 

400 

500 

600 

700 

800 

January

February

March

April

May

June

July

August

September

October

November

December 

MWh 

0 

10 

20 

30 

40 

50 

60 

70 

January

February

March

April

May

June

July

August

September

October

November

December 

Number of Hours 

Figure 1-51. Southeast Bronx amount of Figure 1-52. Southeast Bronx number of 

energy exported by month hours of energy exported by month 

Figures 1-53 through 1-64 show that Saturdays and Sundays are the most common days 

of the week for energy to export to the grid. In the more industrial networks like 

Southeast Bronx and Central Bronx, the increase in export on the weekends is significant 

(at least twice the weekday export level). In the more residential networks like Fox Hill 

and Flushing, the increase is less significant. This is likely because the residential loads 

are fairly consistent over the course of the week, but industrial loads drop on the 

weekends when businesses close. 

1-29
 
 

 

 

 

 

 

0 

0.5 

1 

1.5 

2 

2.5 

3 

3.5 

4 

4.5 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

MWh 

0 

0.2 

0.4 

0.6 

0.8 

1 

1.2 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

Number of Hours 

Figure 1-53. Bay Ridge amount of Figure 1-54. Bay Ridge number of hours 

energy exported by day of energy exported by day 

0

10

20

30

40

50

60

70

80

90

100 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

MWh 

0 

5 

10 

15 

20 

25 

30 

35 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

Number of Hours 

Figure 1-55. Central Bronx amount of Figure 1-56. Central Bronx number of 

energy exported by day hours of energy exported by day 

0 

200 

400 

600 

800 

1000 

1200 

1400 

1600 

1800 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

MWh 

0 

10 

20 

30 

40 

50 

60 

70 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

Number of Hours 

Figure 1-57. Flushing amount of energy Figure 1-58. Flushing number of hours 

exported by day of energy exported by day 

1-30 
 

 

 

 

 

 

0 

100 

200 

300 

400 

500 

600 

700 

800 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

MWh 

Figure 1-61. Maspeth amount of energy 

exported by day 

1000 

900 

800 

700 

600 

500 

400 

300 

200 

100 

0 

Figure 1-59. Fox Hill amount of energy 

exported by day 

MWh MWh 

Saturday 

Number of Hours 

Sunday Sunday

Monday Monday

Tuesday

Wednesday Wednesday

Thursday Thursday

Friday Friday

Tuesday

0 

10 

20 

30 

40 

50 

60 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

Saturday 

0 

20 

40 

60 

80 

100 

120 

140 

160 

180 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

Number of Hours 

Figure 1-60. Fox Hill number of hours of 

energy exported by day 

Saturday 

0 

10 

20 

30 

40 

50 

60 

70 

80 

90 

Sunday

Monday

Tuesday

Wednesday

Thursday

Friday

Saturday 

Number of Hours 

Figure 1-63. Southeast Bronx amount of 

energy exported by day 

7000 

6000 

5000 

4000 

3000 

2000 

1000 

0 

Figure 1-64. Southeast Bronx number of 

hours of energy exported by day 

Figure 1-62. Maspeth number of hours 

of energy exported by day 

1-31
 
 

 

 

 

 

 

 

 

 

Figures 1-65 through 1-76 show that over the course of a day, exporting is most likely to 

occur between 9:00 a.m. and 1:00 p.m. (although it can start as early as 8:00 a.m. and go 

as late as 3:00 p.m.), peaking at 11:00 a.m. This is because PV generation is highest at 

midday, when the sun is directly over the south-facing arrays. The low midday load also 

contributes to high exporting. 

4.5
 

4
 1.2 Number of Hours

8:00 10:00 12:00 14:00
 

3.5
 

3
 1
 

0.8
 

0.6
 

0.4
 

0.2
 

MWh 2.5 

2 

1.5 

1 

0.5 

0 0 

8:00 10:00 12:00 14:00 

Time of Day Time of Day 

Figure 1-65. Bay Ridge amount of Figure 1-66. Bay Ridge number of hours 

energy exported by time of day of energy exported by time of day 

0 

10 

20 

30 

40 

50 

60 

70 

80 

8:00 10:00 12:00 14:00 

MWh 

Time of Day 

0 

5 

10 

15 

20 

25 

8:00 10:00 12:00 14:00 

Number of Hours 

Time of Day 

Figure 1-67. Central Bronx amount of Figure 1-68. Central Bronx number of 

energy exported by time of day hours of energy exported by time of day 

1-32
 
 

 

 

 

 

 

 

 

 

 

 

 

2500 80

2000 

ours 

1500

MWh 

of H

1000 

ber 

500 

Num

0 

8:00 10:00 12:00 14:00 

Time of Day 

Figure 1-69. Flushing amount of energy 

70 

60 

50 

40 

30 

20 

10 

0 

8:00 10:00 12:00 14:00 

Time of Day 

Figure 1-70. Flushing number of hours 

exported by time of day of energy exported by time of day 

MWh MWh 

1400
 

1200
 

1000
 

800
 

600
 

400
 

200
 

0
 

7:00 9:00 11:00 13:00 15:00 

Time of Day 

Figure 1-71. Fox Hill amount of energy 

exported by time of day 

8000
 

7000
 

6000
 

5000
 

4000
 

3000
 

2000
 

1000
 

0
 

7:00 9:00 11:00 13:00 15:00 

Time of Day 

Figure 1-73. Maspeth amount of energy 

exported by time of day 

120 

80 

100

Hours 

60

of 

40

mber 

20

Nu

0 

7:00 9:00 11:00 13:00 15:00 

Time of Day 

Figure 1-72. Fox Hill number of hours of 

energy exported by time of day 

Number of Hours 

180 

160 

140 

120 

100 

80 

60 

40 

20 

0 

7:00 9:00 11:00 13:00 15:00 

Time of Day 

Figure 1-74. Maspeth number of hours 

of energy exported by time of day 

1-33 
 

 

 

 

 

 

 

 

 

0 

100 

200 

300 

400 

500 

600 

700 

7:00 9:00 11:00 13:00 15:00 

MWh 

Time of Day 

0 

5 

10 

15 

20 

25 

30 

35 

40 

45 

50 

Number of Hours 

Time of Day 

Figure 1-75. Southeast Bronx amount of Figure 1-76. Southeast Bronx number of 

energy exported by time of day hours of energy exported by time of day 

1.4 Discussion 

We can also use the results of this analysis to determine the size of PV array that would 

generate a given percentage of the network load. Table 1-4 shows the PV array size that 

would generate 20%, 50%, or 100% of the network load during the year’s annual 

maximum export hour. Because these PV array sizes are based on the maximum export 

hour, the percentage of network load generated by the PV array during all other hours 

will be lower. 

Table 1-4. PV Array Sizes to Generate Percentage of Network Load during Maximum
 

Export Hour
 

Network 

Maximum PV Size 

Based on Available 

Roof Space (MW 

AC) 

PV Array Size to Generate Percentage of 

Network Load (MW AC) 

20% 50% 100% 

Bay Ridge 96.20 18.46 46.15 92.31 

Borough Hall 58.08 26.09 65.23 130.46 

Central Bronx 75.25 13.41 33.53 67.06 

Cooper 25.73 18.94 47.35 94.71 

Flushing 223.17 27.32 68.31 136.62 

Fox Hill 97.51 13.71 34.27 68.54 

Herald 1.29 5.98 14.95 29.90 

Maspeth 188.61 18.52 46.29 92.58 

Southeast Bronx 115.85 14.70 36.74 73.48 

Sutton 1.85 12.15 30.37 60.75 

Even though we evaluated only ten networks in this study, the results can be used to 

estimate PV generation in other networks in the New York area. An estimate of the 

percent of the network area that could be covered by PV arrays can be drawn from a 

similar network. In general, a dense area of buildings with fewer stories (such as in 

1-34 
 

 

 

 

 

 

Brooklyn or the Bronx) will have the highest percent coverage, around 8% to 10%. A 

dense area of taller buildings (like Manhattan) will have a lower percent coverage, around 

4% to 8%. Tall buildings tend to shade neighboring roof space and typically have a 

higher percentage of their own rooftops occupied by rooftop equipment (and therefore 

unavailable for PV). Lower density areas (such as in Staten Island and Queens) will also 

have lower percent coverages, between 3% and 7%, because there is less rooftop space 

per square foot of land area. Lower density areas also tend to have buildings with fewer 

stories and more trees, making rooftops in these areas more susceptible to shading. 

If the size of the network area (in square meters) is known, we can estimate PV 

generation from Equation 1-8: 

PV Power (kW AC) =

Area of Network (m

2

) × Percent of Network Area Covered by PV	 (1-8) 

× 0.1 kW DC / m

2 × 0.77 kW AC / kW DC 

This equation assumes a DC-to-AC derate factor of 0.77 and a power density of 0.1 kW 

DC/m2

. The percent of network area covered by PV can be estimated by comparing the 

building density and composition of the network area to the networks evaluated in this 

study, and using a corresponding percentage from the second column in Table 1-3. 

1.5 Sources of Error 

There are two main sources of error in this analysis: 

•	 Sample area estimate: We estimated the PV array size for each sample area by 

drawing arrays on rooftops in a satellite image. Because of limits in the satellite 

image resolution, these drawings are only an estimate of the maximum PV array 

size possible, accurate to within 10%. Further, IMBY estimates the rating of each 

array based on the rule of thumb that the DC rating of the system in kilowatts is 

one-tenth the area of the array in square meters. This estimate is accurate to 

within 15%. 

•	 Extrapolation of sample area to network area: Although we chose the sample 

areas to represent particular building categories within a given network area as 

closely as possible, there is variation within each building category, and the 

sample areas are not likely to be an exact match. The sample areas are estimated 

to be accurate within 5% and 15%, depending on the size of the sample area 

(larger sample areas including many buildings are more accurate) and the 

variation in the building category (less varied categories are more accurate). 

1.6 Conclusion 

In this analysis, the NREL team evaluated ten New York area networks to determine the 

maximum PV deployment possible in each network. Electricity generation from those PV 

systems was then compared to the network load. We found that under full PV 

1-35
 
 

 

deployment, PV generation would sometimes exceed network load and export to the grid 

in six of the ten networks. The networks with the highest amount of rooftop space per 

person experienced the most exporting. These were generally lower density networks in 

the outer boroughs, made up of more single-family homes and office buildings with 

fewer stories. The amount of energy exported varied by time of year, day of week, and 

time of day. Exporting was highest during the spring months, but also significant in fall 

and winter. Weekends experienced greater exporting than weekdays, particularly in 

industrial networks. On days that exporting occurred, it was consistently highest at 11:00 

a.m. 

1-36
 
 

 

 

 

Appendix 1-A: Network PV Deployment Percentage and PV 

Capacity Calculations 

In this appendix, we present more detail on how we calculated network PV deployment 

percentages and total PV capacities. To represent the varied building types and rooftop 

availability, we first divided each network into different building categories. Then we 

chose 10% of the area for each building category, for detailed evaluation of PV 

deployment potential. Next, we evaluated rooftops in each sample area using NREL’s In 

My Backyard (IMBY) tool to estimate the maximum PV deployment percentage 

(PVD%) in each building category. 

By multiplying each building category’s PVD% by the percent of total network area 

(%TNA) it represents, and summing across all five building categories, we calculated an 

overall network PVD%. We then multiplied the overall network PVD% by the network 

area and a power density of 0.1 kW DC/m2 to calculate the total capacity of PV in the 

network. 

For each network, we give results for current roof conditions (in which some rooftops are 

avoided because of poor maintenance) and well-maintained conditions (in which no 

rooftops are avoided because of poor maintenance). Note that the PV generation 

presented in the main body of the report assumes well-maintained conditions. 

Sections 1.A.1 through 1.A.10 describe each network. 

1.A.1 Bay Ridge 

The Bay Ridge network is located in Brooklyn. It is of particular interest in the PV 

deployment analysis because the warehouses in its Sunset Park neighborhood, along the 

New York Upper Bay between 20th and 60th Streets, have large expanses of available 

roof space. 

Our analysis of satellite images showed that the network consists of two distinct types of 

neighborhoods: residential and warehouse. Although the residential neighborhoods are 

very similar to one another, generally consisting of brownstones with comparable rooftop 

areas, maintenance conditions, and shading, the warehouses are not as homogenous. The 

size and density of buildings vary, along with the state of their rooftops. Some rooftops 

have many obstructions that make PV panels impractical. Others appear to be in poor 

repair. 

To represent the varied building types and rooftop availability, we divided the network 

into different building categories. Table 1-A-1 presents the %TNA and PVD% for each 

building category, along with the resulting overall network PVD% and total network PV 

capacity. 

1-37
 
 

 

 

 

 

 

 

 

 

 

 

 

 

Table 1-A-1. Bay Ridge PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Building 

Category Sample Area %TNA Current WellRooftop Maintained 

Conditions Conditions 

High-Density 

Residential 

Bounded by 3rd Avenue on 

the west, Fort Hamilton 

Parkway on the east, 61st 

Street on the south, and 

53rd Street on the north 

80.04 9.83 10.08 

Low-Density 

Warehouse 

(Poor 

Availability) 

Bounded by the Upper New 

York Bay on the west, 1st 

Avenue on the east, 56th 

Street on the south, and 

54th Street on the north 

3.72 2.14 4.50 

Low-Density 

Warehouse 

(Good 

Availability) 

Bounded by the Upper New 

York Bay on the west, 2nd 

Avenue on the east, 63rd 

Street on the south, and 

58th Street on the north 

4.91 8.17 8.17 

High-Density 

Warehouse 

(Poor 

Availability) 

Bounded by 2nd Avenue on 

the west, 3rd Avenue on the 

east, 37th Street on the 

south, and 33rd Street on 

the north 

4.98 6.69 10.00 

High-Density 

Warehouse 

(Good 

Availability) 

Bounded by the Upper New 

York Bay on the west, 3rd 

Avenue on the east, 22nd 

Street on the south, and 

19th Street on the north 

6.35 15.51 15.51 

Overall PV Deployment Percentage 9.67 10.12 

Total Capacity (kW DC) 119,383 124,932 

Total Capacity (kW AC) 91,925 96,198 

Based on the number of installations in each sample area, we estimate full deployment at 

approximately 36,000 individual installations. 

1.A.2 Borough Hall 

The Borough Hall network is found at the north end of Brooklyn, neighboring the Bay 

Ridge network. Our analysis of satellite images showed that the network consists of three 

distinct types of neighborhoods: residential, warehouse, and high-rise. Within these three 

neighborhoods, the residential and warehouse areas can be further broken down by 

1-38
 
 

 

 

 

 

density and rooftop availability. Table 1-A-2 presents the %TNA and PVD% for each 

building category, along with the resulting overall network PVD% and total network PV 

capacity. 

Because the building types and densities in the Borough Hall network are very similar to 

those in Bay Ridge, we applied the PV deployment percentages calculated for the Bay 

Ridge network to the five equivalent Borough Hall categories. PV deployment 

percentages for the remaining two categories, low-density residential and high-rise 

buildings, have been drawn from similar neighborhoods in the Central Bronx and Herald 

networks, respectively. 

Table 1-A-2. Borough Hall PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Building Category Sample Area %TNA Current WellRooftop Maintained 

Conditions Conditions 

Low-Density Residential See Table 1-A-3 7.07 5.07 5.32 

High-Density 

Residential See Table 1-A-1 37.75 9.83 10.08 

Low-Density 

Warehouse (Poor 

Availability) 

See Table 1-A-1 3.26 2.14 4.50 

Low-Density 

Warehouse (Good) 

Availability 

See Table 1-A-1 16.95 8.17 8.17 

High-Density 

Warehouse (Poor 

Availability) 

See Table 1-A-1 18.88 6.69 10.00 

High-Density 

Warehouse (Good 

Availability) 

See Table 1-A-1 10.30 15.51 15.51 

High-Density High-Rise See Table 1-A-7 5.78 6.94 6.94 

Overall PV Deployment Percentage 8.79 9.60 

Total Capacity (kW DC) 69,029 75,423 

Total Capacity (kW AC) 53,152 58,076 

We estimate full deployment at approximately 12,000 individual installations. 

1-39
 
 

 

 

 

 

 

 

 

 

 

 

 

 

1.A.3 Central Bronx 

The Central Bronx network is of particular interest in the PV deployment analysis 

because the warehouses in the network’s Hunt’s Point neighborhood (along the Bronx 

River east of the Sheridan Expressway) are thought to be prime locations for large PV 

systems. 

Our analysis of satellite images showed that the network consists of two distinct types of 

neighborhoods: residential and warehouse. The residential neighborhoods can be further 

divided into areas of high-density and low-density buildings. The warehouse areas can be 

grouped by building density and the availability of their rooftops. Table 1-A-3 presents 

the %TNA and PVD% for each building category, along with the resulting overall 

network PVD% and total network PV capacity. 

Table 1-A-3. Central Bronx PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Building 

Category Sample Area %TNA Current WellRooftop Maintained 

Conditions Conditions 

Low-Density 

Residential 

High-Density 

Residential 

Low-Density 

Warehouse 

(Poor 

Availability) 

Low-Density 

Warehouse 

(Good 

Availability) 

High-Density 

Warehouse 

(Poor 

Availability) 

Bounded by Trinity Avenue 

on the west, Tinton Avenue 

on the east, E 163rd Street 

on the south, and E 165th 

Street on the north 

Bounded by Prospect 

Avenue and Westchester 

Avenue on the west, 

Southern Boulevard on the 

east and south, and E 163rd 

Street on the north 

Bounded by Halleck Street 

on the west, Avenue F on 

the east, Food Center Drive 

on the south, and the Bronx 

River on the north 

Bounded by Halleck Street 

on the west, Food Center 

Drive on the north and east, 

and the Bronx River on the 

south 

Bounded by Tiffany Street 

on the west, Manida Street 

on the east, Oak Point 

Avenue on the south, and 

Randall Avenue on the 

north 

6.40 5.07 5.32 

52.82 11.91 12.16 

17.57 2.84 5.30 

14.69 7.75 7.75 

5.74 6.30 11.43 

1-40
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

High-Density 

Warehouse 

(Good 

Availability) 

Bounded by Worthen Street 

on the west, Tiffany Street 

on the east, Oak Point 

Avenue on the south, and 

Truxton Street on the north 

2.80 22.87 23.84 

Overall PV Deployment Percentage 9.25 10.16 

Total Capacity (kW DC) 89,046 97,722 

Total Capacity (kW AC) 68,565 75,246 

We estimate full deployment at approximately 15,000 individual installations. 

1.A.4 Cooper Square 

The Cooper Square network is located in Manhattan’s East Village. Our analysis of 

satellite images shows that it is largely made up of high-density residences and 

businesses, with lower density buildings near the East River. Rooftops are in fairly good 

condition, although some need maintenance. There are few trees shading rooftops, but 

there are significant areas of shading resulting from the height of nearby buildings. There 

are no warehouses in this network. Table 1-A-4 presents the %TNA and PVD% for each 

building category, along with the resulting overall network PVD% and total network PV 

capacity. 

Table 1-A-4. Cooper Square PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Building 

Category Sample Area %TNA Current WellRooftop Maintained 

Conditions Conditions 

Low-Density 

Residential 

Bounded by Pitt Street on 

the west, Columbia Street 

on the east, Grand Street on 

the south, and Stanton 

Street on the north 

27.61 4.33 4.58 

High-Density 

Residential/ 

Business 

Bounded by Bowery on the 

west, Clinton Street on the 

east, Delancey Street on the 

south, and E Houston Street 

on the north 

72.39 8.93 9.18 

Overall PV Deployment Percentage 7.66 7.91 

Total Capacity (kW DC) 32,363 33,418 

Total Capacity (kW AC) 24,919 25,732 

We estimate full deployment at approximately 7,000 individual installations. 

1-41
 
 

 

 

 

 

 

 

1.A.5 Flushing 

The Flushing network is located in Queens. Our analysis of satellite images shows that it 

is a residential area, consisting mainly of single-family homes. There are several large 

parks and golf courses, and the New York Mets’ Citi Field (and its associated parking 

lots) is located here as well. With the exception of these open spaces, the building density 

is fairly uniform. Rooftops are generally well-maintained, with a fair amount of shading 

from the area’s many trees. Because the network density and building types are uniform, 

we evaluated the built area of the network in one sample area. Table 1-A-5 presents the 

%TNA and PVD% for each building category, along with the resulting overall network 

PVD% and total network PV capacity. 

Table 1-A-5. Flushing PV Deployment Percentage and PV Capacity Calculations 

Building 

Category 

Built Area 

Sample Area 

Bounded by Whitestone 

Expressway on the west, 

Clearview Expressway on 

the east, 35th Avenue on 

the south, and 26th Avenue 

on the north 

%TNA 

79.72 

PVD% 

Current 

Rooftop 

Conditions 

WellMaintained 

Conditions 

6.83 7.08 

Open Space Not applicable 20.28 0 0 

Overall PV Deployment Percentage 5.44 5.64 

Total Capacity (kW DC) 279,601 289,835 

Total Capacity (kW AC) 215,293 223,173 

We estimate full deployment at approximately 65,000 individual installations. 

1.A.6 Fox Hills 

The Fox Hills network is located on Staten Island. Our analysis of satellite images shows 

that it is a residential area, consisting mainly of single-family homes. There are several 

large parks and golf courses, with open space making up 31% of the network area. There 

are small pockets of wooded areas with more widely spaced homes, and a few blocks of 

denser high-rise buildings, but overall building density is uniform. Rooftops are wellmaintained, but there is a significant amount of shading from the area’s many trees. 

Because the network density and building types are uniform, we evaluated the built area 

of the network in one sample area. Table 1-A-6 presents the %TNA and PVD% for each 

building category, along with the resulting overall network PVD% and total network PV 

capacity. 

1-42
 
 

 

 

 

 

 

 

 

 

Table 1-A-6. Fox Hills PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Building 

Category Sample Area %TNA Current WellRooftop Maintained 

Conditions Conditions 

Built Area 

Bounded by Todt Hill Road 

on the west, Seaside 

Boulevard on the east, 

Midland Avenue on the 

south, and Seaview Avenue 

on the north 

68.76 4.10 4.35 

Open Space Not applicable 31.24 0 0 

Overall PV Deployment Percentage 2.82 2.99 

Total Capacity (kW DC) 119,435 126,635 

Total Capacity (kW AC) 91,965 97,509 

We estimate full deployment at approximately 40,000 individual installations. 

1.A.7 Herald Square 

The Herald Square network is located in the center of Manhattan. Our analysis of satellite 

images shows that it is made up solely of high-density high-rise buildings. Rooftops are 

in good condition, and even though some are covered with rooftop equipment, large 

spaces are also available for PV. There is some shading from the tall buildings nearby. 

The small size of this network (11 square blocks) allowed us to evaluate 100% of the 

network area (instead of the 10% sample we completed for larger networks). Table 1-A-7 

presents the overall network PVD% and total network PV capacity. 

Table 1-A-7. Herald Square PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Current Rooftop 

Conditions 

Well-Maintained 

Conditions 

Overall PV Deployment Percentage 6.69 6.94 

Total Capacity (kW DC) 1,612 1,673 

Total Capacity (kW AC) 1,242 1,288 

We estimate full deployment at approximately 60 individual installations. 

1-43
 
 

 

 

 

 

 

 

 

 

 

 

1.A.8 Maspeth 

The Maspeth network is located on the west side of Queens. Our analysis of satellite 

images shows that it is mainly a high-density residential area, made up of closely spaced 

single-family homes and attached brownstones. There are also small pockets of lower 

density residential areas, and some warehouse buildings. In general, the rooftops appear 

to be in good repair, although there is some room for maintenance. There is little shading 

from trees or other buildings. Open space (mainly cemeteries) makes up a large section of 

the network as well. Table 1-A-8 presents the %TNA and PVD% for each building 

category, along with the resulting overall network PVD% and total network PV capacity. 

Availability on warehouse building rooftops is uniform throughout the network, so they 

are not separated into good and poor availability categories. 

Table 1-A-8: Maspeth PV Deployment Percentage and PV Capacity Calculations 

Building 

Category 

Low-Density 

Residential 

Sample Area 

Bounded by Ascan Avenue 

on the west, Puritan Avenue 

on the east, Kessel Street 

on the south, and Greenway 

N on the north 

%TNA 

2.45 

PVD% 

Current 

Rooftop 

Conditions 

WellMaintained 

Conditions 

3.44 3.44 

High-Density 

Residential 

Bounded by 69th Street on 

the west, Queens Boulevard 

on the east, the Long Island 

Expressway on the south, 

and 51st Avenue on the 

north 

56.68 9.40 9.65 

Low-Density 

Warehouse 

Bounded by Highway 278 

on the west, 50th Street on 

the east, 55th Avenue on 

the south, and 54th Road on 

the north 

2.97 5.91 6.91 

High-Density 

Warehouse 

Bounded by 47th and 48th 

Streets on the west, Rust 

Street on the east, Grand 

Avenue on the south, and 

Maspeth Avenue on the 

north 

10.28 12.83 13.83 

Open Space Not applicable 27.62 0 0 

Overall PV Deployment Percentage 6.91 7.18 

Total Capacity (kW DC) 235,596 244,947 

Total Capacity (kW AC) 181,409 188,610 

We estimate full deployment at approximately 40,000 individual installations. 

1-44 
 

 

 

 

 

 

 

 

 

 

 

1.A.9 Southeast Bronx 

Our analysis of satellite images shows that the Southeast Bronx network is mainly a 

residential area of high-density single-family homes, but there are also some lower 

density apartment buildings, a few warehouse buildings, and some small areas of 

parkland. In general, the residential area rooftops appear to be in good repair, although 

there is some room for maintenance. There is little shading from trees or other buildings. 

Table 1-A-9 presents the %TNA and PVD% for each building category, along with the 

resulting overall network PVD% and total network PV capacity. For the warehouse areas, 

we drew estimates of PV deployment from similar areas in the neighboring Central 

Bronx network. 

Table 1-A-9. Southeast Bronx PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Building 

Category Sample Area %TNA Current WellRooftop Maintained 

Conditions Conditions 

Low-Density 

Residential 

Bounded by Unionport Road 

on the west, Purdy Street 

and Olmstead Avenue on 

the east, St. Raymond 

Avenue and Starling 

Avenue on the south, and 

Tremont Avenue on the 

north 

11.51 6.13 6.13 

High-Density 

Residential 

Bounded by the Hutchinson 

River Parkway on the west, 

the Bruckner Expressway 

on the east, E Tremont 

Avenue on the south, and 

Westchester Avenue on the 

north 

78.94 8.06 8.31 

Low-Density 

Warehouse 

See Table 1-A-3 2.52 7.75 7.75 

High-Density 

Warehouse 

See Table 1-A-3 5.26 22.87 22.87 

Open Space Not applicable 1.77 0 0 

Overall PV Deployment Percentage 8.47 8.66 

Total Capacity (kW DC) 147,025 150,452 

Total Capacity (kW AC) 113,209 115,848 

We estimate full deployment at approximately 40,000 individual installations. 

1-45 
 

 

 

 

 

1.A.10 Sutton 

The Sutton network is located on the east side of midtown Manhattan. Our analysis of 

satellite images shows that it contains primarily large high-rise buildings and a few 

brownstones. The building density is high. Rooftops are in good condition, but most are 

covered with rooftop equipment, leaving little room for PV. There is significant shading 

from the tall buildings nearby. 

Because the network density and building types are fairly uniform, we did not divide this 

network into building categories. Instead, we selected one sample area for detailed 

evaluation of PV deployment potential. Table 1-A-10 presents the overall network 

PVD% and total network PV capacity. 

Table 1-A-10. Sutton PV Deployment Percentage and PV Capacity Calculations 

PVD% 

Sample Area %TNA Current WellRooftop 

Conditions 

Maintained 

Conditions 

Bounded by 55th Street on the 

north, 54th Street on the south, 

5th Avenue on the west, and 

the East River on the east 

100 3.59 3.84 

Overall PV Deployment Percentage 3.59 3.84 

Total Power (kW DC) 2,244 2,400 

Total Power (kW AC) 1,728 1,848 

We estimate full deployment at approximately 400 individual installations. 

1-46
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appendix 1-B: PV Generation for Flat-Mounted Arrays 

Our analysis assumed that all PV arrays were tilted at 40.8°N (equal to the latitude of the 

site). This maximizes annual energy production and favors energy production in the 

spring and fall. Because Con Edison sees its minimum loads in spring and fall, 

maximizing PV production for spring and fall gives us maximum energy exporting. 

Many PV arrays in the New York Area, however, are flat-mounted. As a result, we 

conducted additional analysis for one network (Central Bronx) to show how results can 

be expected to change for flat-mounted PV arrays. 

As shown in Table 1-B-1, the percent of network area covered by PV and total PV size 

remain the same. Changing the angle of the PV arrays, though, affects the annual 

maximum percent of load met by PV, the capacity penetration, and the energy 

penetration. 

Table 1-B-1. Comparison of 0° and 40.8° PV Array Tilt Angles, Central Bronx Network 

PV Array Tilt 

Angle 

Percent of 

Network 

Area 

Covered by 

PV (%)a 

Total PV 

Size 

(MW AC)b 

Percent of 

Load Met by 

PV (Annual 

Maximum; %)c 

Capacity 

Penetration 

(%)d 

Energy 

Penetration 

(%)e 

40.8° Tilt 10.16 75.25 112.21 68.73 17.18 

0° Tilt 10.16 75.25 110.28 55.48 14.46 a Percent of network area covered by PV: Calculated as shown in Section 1.2.3 

b Total PV size = size of PV array covering entire network × percent of network area covered by PV 

c Percent of load met by PV (annual maximum) = PV power generation/load × 100, for annual maximum 

hour (coincident)

d Capacity penetration = annual peak PV power generation/annual peak load × 100 (noncoincident) 

e Energy penetration = annual PV energy generation/annual energy consumption × 100 

The annual maximum percent of load met by PV changes very little. The day on which it 

occurs shifts toward the summer (from May 1 to May 29), because a flat-mounted array 

will produce the most energy around the summer solstice when the sun is highest in the 

sky. This is helpful in mid-summer, when New York sees its highest annual loads. But 

near-maximum amounts of energy are also produced in late spring, when New York 

experiences its lowest annual loads. The annual maximum percent of load met by PV, 

then, is not reduced much for a flat-mounted array. 

The capacity penetration and energy penetration show more significant reductions (about 

19% and 16%, respectively). Capacity penetration is calculated by dividing the annual 

peak PV power generation by the annual peak network load (noncoincident). Although 

the annual peak network load has not changed, the annual peak PV power generation is 

reduced at a 0° tilt angle. (Optimum tilt angles for the New York area vary between 25.8° 

and 55.8°, depending on the season in which you want maximum PV generation.) Lower 

1-47
 
angles are better for summer generation, medium angles for spring and fall, and higher 

angles for winter production. A 0° tilt angle is not optimum at any time of year. Energy 

penetration is calculated by dividing annual PV generation by annual energy 

consumption. Again, although energy consumption has not changed, the annual PV 

generation is reduced at this tilt angle. These lower values indicate that less energy will 

be exported over the course of the year. The effect of changing the PV array tilt angle is 

further shown in the graphs that follow. 

Figure 1-B-1 shows how the PV generation curve changes when the tilt angle is adjusted 

to 0°. PV generation remains about the same in the summer (albeit with a slight 

decrease), but is reduced more in the spring and fall and significantly reduced in the 

winter. This is because a flat-mounted PV array will see the most direct sunlight during 

the summer, when the sun is highest in the sky. As the sun moves lower in the sky during 

the spring and fall, and reaches its lowest point in winter, the PV array will receive much 

less direct sunlight. Although it seems surprising that summer generation also decreases, 

this is explained by the tilt angle. An optimum tilt angle for summer production is about 

15° less than latitude, or 25.8°. Because the 0° tilt is further from the optimum summer 

angle than the 40.8° tilt, summer production is slightly reduced. 

120

100

80

60

40

20

0

Jan‐05 Apr‐05 Jun‐05 Sep‐05 Dec‐05

Load PV Generation 40.8° Tilt PV Generation 0° Tilt

Figure 1-B-1. Central Bronx network load and PV generation under full deployment: 

Comparison of 40.8° and 0° tilt angles

MW

1-48 
 

 

 

Figures 1-B-2 and 1-B-3 show the maximum export days under full PV deployment for 

40.8° and 0° tilt angles. The jagged shape of the 0° tilt angle curve, which is caused by 

partly cloudy conditions, demonstrates the intermittent nature of PV power. At a 40.8° 

degree tilt, the maximum export day occurs closer to the spring solstice (on May 1). At a 

0° degree tilt, the maximum export day is May 29, closer to the summer solstice. In both 

cases, the load is reduced by about the same amount. 

80 

60 

0:00 4:00 8:00 12:00 16:00 20:00 0:00
 

MW

40 

20 

0 

-20 

Time 

Load Reduced Load PV Generation 

Figure 1-B-2. Maximum export day under full PV deployment: 40.8° tilt angle (May 1) 

70
 

60
 

50
 

40
 

MW

30 

20 

10 

0 

-10 

0:00 4:00 8:00 12:00 16:00 20:00 0:00 

Time 

Load Reduced Load PV Generation 

Figure 1-B-3. Maximum export day under full PV deployment: 0° tilt angle (May 29) 

1-49
 
Figures 1-B-4 and 1-B-5 compare the load-duration curves for 40.8° and 0° tilt angles. 

The full 8760-hour curve shows that changing the tilt angle from 40.8° and 0° results in 

43 fewer net exporting hours. Therefore, a slightly higher percentage of full deployment 

can be reached before a net export of energy occurs. The curve of the top 100 hours 

shows that PV arrays tilted at 40.8° and 0° produce equal reductions in peak load. 

120 

100 

80 

MW

60 

40 

20 

0 

-20 

1 2001 4001 6001 8001 

Sorted Hours 

Load Reduced Load 40.8° Tilt Reduced Load 0° Tilt 

Note: Under full deployment, at 0° tilt, there are 10 hours net exporting. To reduce exported hours to zero, 

limit deployment to 90.8% of full deployment (68.23 MW). At 40° tilt, there are 53 hours net exporting. 

To reduce exported hours to zero, limit deployment to 89.12% of full deployment (67.06 MW).

Figure 1-B-4. 8760-hour load-duration curve: Comparison of 0° and 40.8° tilt angles

125
 

120
 

115
 

MW

110 

105 

100 

95 

1 11 21 31 41 51 61 71 81 91 101 

Sorted Hours 

Load Reduced Load 40.8° Reduced Load 0° 

Figure 1-B-5. Top-100-hour load-duration curve: Comparison of 0° and 40.8° tilt angles

1-50 
 

 

 

 

Figures 1-B-6 through 1-B-11 give more details on how much net energy is exported to 

the grid and when, for PV arrays at 40.8° and 0° tilt angles. 

Figures 1-B-6 and 1-B-7 show that reducing the tilt angle from 40.8° to 0° significantly 

reduces net exporting energy at all times of day, with the greatest reductions seen 

between 10 a.m. and 1 p.m.. 

80
 

70
 

60
 

9:00 10:00 11:00 12:00 13:00
 

MWh 50 

40 

30 

20 

10 

0 

Time of Day 

40.8° Tilt 0° Tilt 

Figure 1-B-6. Amount of energy exported by time of day: Comparison of 40.8° and 0° tilt 

angles 

0 

5 

10 

15 

20 

25 

9:00 10:00 11:00 12:00 13:00 

Number of Hours 

Time of Day 

40.8° Tilt 0° Tilt 

Figure 1-B-7. Number of hours of energy exported by time of day: Comparison of 40.8° and 

0° tilt angles 

1-51
 
 

 

 

Figures 1-B-8 and 1-B-9 show that reducing the tilt angle from 40.8° to 0° significantly 

reduces net exporting energy throughout the week. 

0 

20 

40 

60 

80 

100 

MWh 

40.8° Tilt 0° Tilt 

Figure 1-B-8. Amount of energy exported by day of week: Comparison of 40.8° and 0° tilt 

angles 

0 

5 

10 

15 

20 

25 

30 

35 

Number of Hours 

40.8° Tilt 0° Tilt 

Figure 1-B-9. Number of hours of energy exported by day of week: Comparison of 40.8° 

and 0° tilt angles 

1-52
 
 

 

 

Figures 1-B-10 and 1-B-11 show that reducing the tilt angle from 40.8° to 0° significantly 

reduces the amount of energy exported and the number of hours of energy exported 

throughout the year. It also changes the monthly distribution of exporting energy. PV 

arrays tilted at 40.8° have two peaks (a higher one in spring and a lower one in fall). PV 

arrays tilted at 0° show one peak in late spring/early summer. 

0 

10 

20 

30 

40 

50 

MWh 

40.8° Tilt 0° Tilt 

Figure 1-B-10. Amount of energy exported by month: Comparison of 40.8° and 0° tilt 

angles 

0 

2 

4 

6 

8 

10 

12 

14 

Number of Hours 

40.8° Tilt 0° Tilt 

Figure 1-B-11. Number of hours of energy exported by month: Comparison of 40.8° and 0° 

tilt angles 

1-53
 
 

 

 

Appendix 1-C: Individual Building Analysis
 

We carried out the New York City PV deployment analysis at the macro level, comparing 

total loads and total PV generation across entire networks. This results in an estimate of 

net energy exported from the network, but utility operations require a more detailed 

understanding of energy exported at the individual building level. 

To paint a better picture of which building types are most likely (or least likely) to export 

energy, we analyzed four types of buildings. Con Edison furnished four specific buildings 

in the New York area for this analysis: a primary school, a mid-rise apartment building, a 

stand-alone retail store, and a warehouse building. We used IMBY to estimate hourly 

annual PV generation for each building. 

As in the overall network analysis, the rooftops were covered to the maximum extent 

possible. We estimated the load of each building based on NREL’s benchmark buildings, 

which represent new commercial buildings meeting minimum ASHRAE 90.1-2004 

standards. We used DOE’s EnergyPlus whole-building annual simulation software to 

estimate load for each building type considered.6 Building size and climate zone were 

taken into account. 

The analysis for each building type is described in the following sections. 

1.C.1 Primary School 

As shown in Figure 1-C-1, rooftop equipment on the school limits the space available for 

PV. The maximum PV system size would be 9 kW. PV generation would be insignificant 

compared to the load (see Figure 1-C-2), and energy would never export to the grid. 

Figure 1-C-1. School PV system 

6 For more information on EnergyPlus, see http://apps1.eere.energy.gov/buildings/energyplus/. 

1-54
 
 

 

300 

250 

200 

150 

100 

50 

0 

PV Generation Load 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

KW

Figure 1-C-2. School load and PV generation (space limited by rooftop equipment) 

If rooftop equipment did not limit space available for PV, the entire roof could be 

covered with a 46-kW PV system, and PV generation would exceed loads at times—most 

commonly on the weekends (see Figure 1-C-3). 

300
 

250
 

200
 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

KW

150 

100 

50 

0 

PV Generation Load 

Figure 1-C-3. School load and PV generation (space not limited by rooftop equipment) 

1-55
 
 

 

1.C.2 Mid-Rise Apartment Building 

Here, almost all roof space is available for PV, with room for a 64-kW system (see Figure 

1-C-4). Although loads exceed PV generation most of the time, energy would be 

exported for 154 hours during the year (see Figure 1-C-5). 

Figure 1-C-4. Apartment PV system 

200 

150 

100 

50 

0 

PV Generation Load 

Figure 1-C-5. Apartment load and PV generation 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

KW

1-56
 
 

 

1.C.3 Stand-Alone Retail Store 

About half of the roof space on this retail store is available for PV, with room for a 567­

kW system as shown in Figure 1-C-6. PV generation would exceed load during all 

months of the year, most significantly in spring, fall, and winter (see Figure 1-C-7). 

Figure 1-C-6. Retail store PV system 

600 

500 

400 

300 

200 

100 

0 

PV Generation Load 

Figure 1-C-7. Retail store load and PV generation 

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

KW

1-57
 
 

1.C.4 Warehouse Building 

All the roof space on this warehouse is available for PV, with room for a 118-kW system 

as shown in Figure 1-C-8. PV generation would significantly exceed load throughout the 

year (see Figure 1-C-9). 

0 

20 

40 

60 

80 

100 

120 

Jan 

Figure 1-C-8. Warehouse PV system 

Figure 1-C-9. Warehouse load and PV generation 

PV Generation Load 

Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

KW

1-58
 
 

 

1.C.5 Conclusion 

Our analysis of these four buildings identifies the energy-exporting potential of the 

individual buildings studied, but it is insufficient for drawing conclusions about the 

energy-exporting potential of the broader building types. We recommend further analysis 

to identify whether certain building types are likely to export (or not export) energy. This 

information would assist Con Edison in evaluating interconnection applications for these 

building types. 

1-59
 
2.0 A Briefing for Policy Makers on Connecting PV to a
 

Network Grid 

This section is designed to educate urban planners and policy makers on the technical 

issues utilities face when interconnecting distributed photovoltaic (PV) systems to 

networks. The main technical concerns— network protector operation and cycling, 

load forecasting and planning, fault currents, reactive power requirements, harmonics, 

voltage flicker, voltage sag, and unintentional islands— are described, along with 

possible solutions. 

2-1
 
Contents
 

2.1 Introduction............................................................................................................................3
 

2.2 Technical Concerns and Solutions.........................................................................................3
 

2.2.1 Network Protector Operation and Cycling ................................................................ 3
 

2.2.2 Load Forecasting and Planning Challenges............................................................... 5
 

2.2.3 Increased Fault Currents ............................................................................................ 5
 

2.2.4 Increased Reactive Power Requirements................................................................... 6
 

2.2.5 Increased Harmonics.................................................................................................. 6
 

2.2.6 Voltage Flicker........................................................................................................... 7
 

2.2.7 Voltage Sag................................................................................................................ 7
 

2.2.8 Impacts of Other Distributed Generation Systems on PV ......................................... 7
 

2.2.9 Unintentional Islands ................................................................................................. 8
 

2.3 Bibliography ..........................................................................................................................9
 

2-2
 
 

 

 

2.1 Introduction 

Traditionally, energy is generated at large, centralized power plants. These power plants 

are connected to the transmission system, which carries energy over long distances and at 

high voltages from power plants to substations. From the substations, electricity moves 

on to individual customers through the distribution system, which operates over shorter 

distances and at lower voltages. Although most power is connected to the transmission 

system, small customer-sited generators can be connected to the distribution system 

(called “distributed generation”). Today, this includes a growing number of PV systems. 

There are two main types of electrical distribution systems: radial and network. Most 

areas of the United States use simpler radial distribution systems to distribute electricity, 

but larger metropolitan areas like New York City typically use more complicated 

networks to increase reliability in large load centers. Unlike the radial distribution 

system, where each customer receives power through a single feeder and single 

transformer, a network delivers power to each customer through several parallel feeders 

and transformers. This redundancy improves reliability because the loss of a single line or 

transformer will not interrupt the power supply. 

Networks use coordination and protection schemes that are based on the assumption that 

power flows in one direction—from the utility substation to the customer. With 

traditional power plants, this is true. When power sources like PV are connected to the 

distribution system at the customer’s site, however, power can flow in the opposite 

direction—from the customer toward the utility substation. This can disrupt network 

protection schemes and threaten network reliability. 

Although there are risks inherent in interconnecting PV systems to networks, there are 

benefits as well. Demand in New York City is increasing, and PV-generated electricity 

can help meet this demand and possibly reduce the capital costs associated with new 

conventional power plants. There is also the possibility for distributed PV systems to 

reduce distribution system requirements (if load forecasting and planning challenges are 

addressed) because they are located at the load. This is particularly important in New 

York City, where the distribution system is entirely underground. The existing system is 

costly to maintain, and space for new equipment is limited. 

This briefing summarizes the main technical concerns associated with connecting 

distributed PV systems to networks and presents possible solutions to alleviate these 

problems. 

2.2 Technical Concerns and Solutions 

2.2.1 Network Protector Operation and Cycling 

Networks are designed for power flow in one direction (from the utility’s substation to 

the customer). Power flow in the reverse direction (called “reverse power flow”) is 

indicative of an upstream supply feeder fault. Network protectors are designed to sense 

reverse power flow and physically disconnect the faulted supply feeder. This immediately 

isolates the fault, prevents equipment damage, and allows technicians to quickly repair 

2-3
 
 

 

 

 

 

and restore service. Network protectors are critical to maintaining robust network 

reliability. 

Network-connected PV systems can upset this standard network protection scheme. 

When a PV system connected to the network at a customer’s home or business generates 

more power than the customer can use, for example, the excess power is fed back into the 

network and produces reverse power flow. This causes network protectors to open 

unnecessarily and leads to wear on the equipment. 

Network protectors are also responsible for reconnecting the faulted section once the fault 

has been cleared. They do this by sensing when power flow is in the correct direction 

(from the utility toward the customer). But when the network protector opens, the 

direction of the load flow changes. If the open network protector senses that power is 

flowing in the correct direction, it closes. When the network protector closes, the load 

flows will change again and the PV power could cause the network protector to open 

again. Repeated opening and closing of the network protector can eventually cause 

network protector failure. 

2.2.1.1 Solutions 

The simplest way to prevent unnecessary network protector operation is to ensure that PV 

systems do not export energy to the network, thus never producing reverse power flow. 

This can be accomplished in several ways. First, the customer can be required to maintain 

a minimum load at all times, to make sure that they are always drawing power from the 

network. Second, a minimum import relay (MIR) can be installed to trip the PV system 

offline if the customer load drops below a predetermined level. Third, a reverse power 

relay (RPR) can be installed. Similar to an MIR, an RPR trips the PV system offline if the 

customer load drops to zero or if the PV system begins to export power. Fourth, a 

dynamically controlled inverter (DCI) can monitor the load and curtail PV system output 

if the customer load drops below a predetermined level. 

If PV systems are allowed to export to the network, a short-term solution is adjusting 

network protector settings to be less sensitive to reverse power flow. The network 

protectors can be set in a time-delayed mode, where they do not open immediately for 

low levels of reverse power (instead, they might wait two and a half minutes, and then 

open if the power is still flowing in the reverse direction). They can also be set to an 

insensitive mode where they do not trip at all for low levels of reverse power. In both 

cases, though, they still trip immediately for high levels of reverse power. Although an 

insensitive mode setting would necessitate fewer network protector operations, it could 

also result in network protectors not opening when they need to, leading to equipment 

damage, additional restoration time, and overall reduced system reliability at high PV 

penetrations. 

At high PV penetration levels, utilities will need the ability to monitor, exchange 

information with, and control network protectors and PV systems. This will allow them 

to adjust network protector settings to allow reverse power, or to curtail PV production at 

times to reduce reverse power flow. These functions could be part of future smart grid 

technologies, but are not available in current utility systems. 

2-4
 
 

 

 

 

 

2.2.2 Load Forecasting and Planning Challenges 

When PV systems supply part of a customer’s energy needs, the load profile seen by the 

network changes. The difference between minimum and maximum load increases as 

daytime loads drop and nighttime loads remain the same. The variability of the load also 

increases because PV production is highly weather-dependent, and can drop off suddenly 

when clouds pass over. At low levels of penetration, these changes are not noticeable at 

the network level, but at high penetrations the utility will need to adjust generation from 

conventional power sources to meet these new load profiles. Conventional sources will 

have to be more flexible to quickly pick up the load when PV production drops off. Some 

conventional generation sources must be operated at a minimum load, and cannot be 

stopped and started quickly (i.e., coal-fired power plants). More flexible sources (natural 

gas) tend to be more expensive. The additional flexibility required to accommodate high 

PV penetrations can lead to higher generation costs. 

2.2.2.1 Solutions 

Utility operators can cope with load forecasting and planning challenges in a number of 

ways. The first solution should be to integrate renewable energy supply into the planning 

process and consider it during energy growth forecasting. Variable renewable generation 

should be viewed as a part of the load, and the variability should be characterized to 

ensure that the conventional generation portfolio has enough flexibility to cope with 

increased variability. This will allow for realistic plans for conventional generation and 

reasonable estimates of system operating costs. 

As the penetration of renewable generation increases, conventional generation may no 

longer be flexible enough to handle the variability of renewable generation, and 

additional flexibility may be too expensive. In this case, variability can be reduced by 

controlling or shifting loads, using energy storage, and curtailing renewable generation 

sources. 

Adjustments to the siting of renewable generation might also be able to reduce 

variability. Spreading renewable generation over a larger area can reduce the impact of 

passing clouds (although for a region as small as New York City, this may not be an 

effective strategy). Varying the orientation of PV panels (so some face east, some south, 

some west) will disperse maximum power production across the day (rather than 

concentrating it at midday if all were facing south), producing a more even load profile. 

2.2.3 Increased Fault Currents 

Network protective equipment (breakers and fuses) and substation equipment is designed 

to withstand a certain level of fault current. Adding additional sources of energy, like a 

PV system, can increase the level of available fault current beyond the equipment ratings, 

to the point where network protective devices will fail to protect the system from fault 

currents. This can result in catastrophic equipment failures that can threaten public safety. 

Additional sources of supply can also change the direction of fault current flows or add 

new flows, disrupting the coordination of protective devices. 

2-5
 
 

 

 

2.2.3.1 Solutions 

Compared to other distributed generation sources, PV systems generate very little fault 

current. Because they are inverter-based, they typically can generate only twice the rated 

current for a short time. Synchronous generators, on the other hand, typically generate six 

to ten times their normal rating in fault current. Furthermore, PV systems are required by 

IEEE standards (see Bibliography) to drop offline quickly (within 0.16 seconds, or 6 

cycles) in the event of a fault, which limits the amount of time in which they can inject 

any fault current. For these reasons, PV systems are not expected to contribute 

significantly to fault currents. 

If increased fault current levels remain a concern, they can be mitigated by upgrading 

distribution system equipment to accommodate higher operation at fault levels (an 

expensive solution) or using fault mitigation controls1 to disconnect a PV system if it 

begins to supply current to a fault condition. Concerns about the coordination of 

protective devices can be addressed through utility short-circuit studies, which would 

determine if the PV system could potentially disrupt coordination. If the potential exists, 

the utility could modify the coordination scheme. Another solution is to set the PV 

inverters to monitor high-current conditions and automatically scale back their current 

when a spike in current over time is detected. Although they are not currently available, 

future smart grid systems will allow better coordination of relaying and protection 

schemes through communication with the PV system. 

2.2.4 Increased Reactive Power Requirements 

Electrical power is made up of real power (measured in watts) and reactive power 

(measured in volt-ampere reactive [VAR]). Most loads use both real and reactive power. 

IEEE standards (see Bibliography), however, require PV system inverters to produce 

only real power. This means other power generators will have to supply a higher 

percentage of reactive power. 

2.2.4.1 Solutions 

Capacitors can be installed to supply reactive power to inductive loads. They can be 

installed at the customer’s site, or utilities can install them at feeders or substations. As 

the PV penetration increases, PV inverters may need to supply VARs. 

2.2.5 Increased Harmonics 

PV systems could reduce power quality by inducing harmonic distortion in the system, 

which could adversely affect operation of motors and electronics. Harmonics also cause 

undesirable heating in transformers and cables. This can cause circuit-breaker tripping, 

overvoltage problems, incandescent light blinking, and computer malfunctions. 

2.2.5.1 Solutions 

The inverters used in modern PV systems are required to meet minimum power quality 

standards and do not induce harmonic distortion. Future PV inverters might have the 

1 Fault current mitigation would be defined by the utility on a case by case basis but generally requires that 

the protection interrupt the fault current contribution within half a cycle. 

2-6
 
 

 

 

capability to actually improve the harmonics at the load by actively canceling load 

harmonics. 

2.2.6 Voltage Flicker 

Voltage flicker can occur when PV system output increases or decreases (in response to 

passing clouds, for example) faster than the remaining generators can compensate. This 

leads to voltage excursions that can become noticeable to customers as light flicker or 

variable motor speed performance. These variations can also wear down equipment that 

attempts to hold the voltage at a constant level. 

2.2.6.1 Solutions 

Voltage flicker can be reduced by adding storage systems that compensate for the 

variations in PV system output. Storage (like batteries) can be added to PV systems or to 

utility substations. PV systems can also be spatially distributed to reduce the impact of 

passing clouds. Although this might not be an effective solution for customer-sited 

generation, spatial distribution could be a consideration in utility-owned systems. 

Another solution would be to integrate cloud forecasting into future smart grid utility 

control systems, allowing the utility to predict PV output dips and to use voltage 

regulation methods to lessen the effects. 

2.2.7 Voltage Sag 

Current interconnection standards require PV systems to disconnect from the grid during 

grid faults. The sudden loss of PV generation can lead to unacceptably low voltages in 

parts of the system and subsequent increases in apparent load to the utility. This is less of 

a concern in secondary networks, which have numerous sources of power, although it 

could become more significant at very high PV penetration levels. 

2.2.7.1 Solutions 

In the short term, voltage sag issues can be mitigated by using energy storage systems 

and ensuring that utilities have adequate backup energy generation capacity that can be 

brought online quickly to make up the lost voltage while PV systems are offline. A better 

long-term solution is to allow PV systems to stay online during voltage sags caused by 

temporary faults, and to help restore the voltage after the fault is cleared. This is known 

as “fault ride-through capability.” Adding this capability will require changes to existing 

interconnection standards for distributed generation and to current anti-islanding 

protection schemes. 

2.2.8 Impacts of Other Distribution System-Connected Equipment on PV 

Other distribution system-connected equipment, such as lighting ballasts, arc welding 

equipment, synchronous generators, or induction generators, could induce harmonics, 

high voltage, reduced voltage, and variations in frequency, noise, or surges in the local 

distribution system. These events could force the PV system to drop offline. The loss of 

the PV systems in the area could further exacerbate the voltage level and quality of the 

local distribution system. 

2-7
 
 

 

 

 

 

 

 

2.2.8.1 Solutions 

A utility power quality expert can monitor power quality to determine if any of these 

issues exist. These aberrations might not be significant enough to cause any adverse 

operating condition for a PV system or the electric utility secondary network. If they are 

significant, though, operators must locate the source of the harmonics, abnormal voltages, 

and variations in frequency and eliminate the problem. 

A second solution, similar to the solution for voltage sag, is to allow inverters to stay 

online through temporary aberrations like bumps or voltage dips. Again, this will require 

alternative methods of unintentional island protection and is unlikely to be implemented 

in the near future. 

2.2.9 Unintentional Islands 

Unintentional islands (which can be established when a network protector opens and 

isolates a section of the power system with an energy source) pose a threat to proper 

utility system operation for a number of reasons: 

1.	 The upstream utility system might attempt to reclose into the island under
 

unsuitable conditions, which can damage switchgear, power generation 

equipment, and customer loads.
 

2.	 An unintentional island can increase public exposure to unsafe, energized downed 

conductors. 

3.	 Line crews working on power restoration following storms or other events may 

encounter unintentional energized islands, making their job more hazardous and 

slowing down the power restoration process. 

4.	 Unintentional islands do not usually have their generators set up with the proper 

controls to maintain adequate voltage and frequency conditions to the customer 

loads. 

5.	 Unintentional islands can increase the likelihood of dangerous spikes or surges in 

the system. 

Because of the dangers of unintentional islands, the IEEE 1547-2008 standard (see 

Bibliography) and utility interconnection guidelines require PV systems connecting to the 

network to have anti-islanding protection. Inverters are set to disconnect in the event that 

the network voltage or frequency goes outside of predefined limits. As a result, 

unintentional islands are not currently considered a significant concern at lower levels of 

PV penetration. Under high penetration levels, though, current anti-islanding techniques 

may not adequately detect island formation and disable it within a suitable amount of 

time. Furthermore, current anti-islanding techniques require PV systems to drop offline 

during temporary faults, contributing to voltage drop problems. Alternative anti-islanding 

protection methods that allow PV systems to stay connected during temporary faults are 

needed. 

2-8
 
 

 

 

 

 

 

2.2.9.1 Solutions 

A power line carrier communications (PLCC) system could replace current anti-islanding 

techniques. A PLCC would send out a constant signal from the utility to PV systems (and 

other DG systems) on the actual utility distribution conductors. As long as the utilitysupplied signal is present, the PV system knows that the network is operating nominally, 

and stays connected. If the utility service is disconnected, the PLCC signal is lost at the 

PV system’s end of the line, and the PV system will disconnect resulting in the PV 

system disconnecting in order to prevent an unintentional island. A PLCC system would 

allow voltage and frequency trip settings to be widened to better accommodate system 

variations and allow PV systems to stay connected during temporary faults or for lowvoltage ride through. Implementing PLCC will require development of a rugged, lowcost PLCC transmitter and a low-cost (and preferably noninvasive) means of ensuring 

reliable signal availability at all end points. 

A second solution is to integrate PV inverters into utility supervisory control and data 

acquisition (SCADA) systems or advanced metering infrastructure (AMI) systems. 

Inverters could be tied into utility communications systems, which would issue a 

disconnect command to inverters in sections of the utility system isolated from the utility. 

And although they are not currently available, future smart grid systems should be 

designed to allow this type of control and through communication with the PV system. 

2.3 Bibliography 

Achilles, S.; Schramm, S.; Bebic, J. Transmission System Performance Analysis for 

High-Penetration Photovoltaics. NREL/SR-581-42300. Golden, CO: National 

Renewable Energy Laboratory (NREL), 2008. 

Bebic, J. Power System Planning: Emerging Practices Suitable for Evaluating the Impact 

of High-Penetration Photovoltaics. NREL/SR-581-42297. Golden, CO: NREL, 2008. 

Behnke, M.; Erdman, W.; Horgan, S.; Dawson, D.; Feero, W.; Soudi, F.; Smith, D.; 

Whitaker, C.; Kroposki, B. Secondary Network Distribution Systems Background and 

Issues Related to the Interconnection of Distributed Resources. NREL/TP-560-38079. 

Golden, CO: NREL, 2005. 

Coddington, M.; Kroposki, B.; Basso, T.; Lynn, K.; Sammon, D.; Vaziri, M.; Yohn, T. 

Photovoltaic Systems Interconnected onto Secondary Network Distribution Systems— 

Success Stories. NREL/TP-550-45061. Golden, CO: NREL, 2009. 

Edison Electric Institute (EEI). Edison Electric Institute Distributed Resources Task 

Force Interconnection Study. Washington: EEI, June 2000. 

IEEE. The Authoritative Dictionary of IEEE Standards Terms. IEEE 100, Seventh 

Edition. New York City: IEEE, 2000. 

2-9
 
 

 

IEEE. Standard Conformance Test Procedures for Equipment Interconnecting 

Distributed Resources with Electric Power Systems. IEEE Std, 1547.1-2005. New York 

City: IEEE, 2005. 

http://ieeexplore.ieee.org/xpl/standardstoc.jsp?isnumber=32033&isYear=. Accessed 

October 3, 2009. 

IEEE. Application Guide for IEEE Standard 1547, IEEE Standard for Interconnecting 

Distributed Resources with Electric Power Systems. IEEE P1547.2-2008. New York 

City: IEEE, 2009. http://ieeexplore.ieee.org/servlet/opac?punumber=4816076. Accessed 

October 3, 2009. 

IEEE. Standard for Interconnecting Distributed Resources with Electric Power Systems. 

IEEE Std. 1547-2003. New York City: IEEE, 2003. 

http://grouper.ieee.org/groups/scc21/1547/1547_index.html. Accessed October 3, 2009. 

Liu, E.; Bebic, J. Distribution System Voltage Performance Analysis for HighPenetration Photovoltaics. NREL/SR-581-42298. Golden, CO: NREL, 2008. 

McGranaghan, M.; Ortmeyer, T.; Crudele, D.; Key, T.; Smith, J.; Barker, P. Renewable 

Systems Interconnection Study: Advanced Grid Planning and Operations. SAND2008-

0944 P. Albuquerque, NM: Sandia National Laboratories (SNL), 2008. 

Underwriters Laboratories, Inc. (UL). Inverters, Converters, Controllers and 

Interconnection System Equipment for Use with Distributed Energy Resources. UL 1741. 

Northbrook, IL: UL, 2007. http://ulstandardsinfonet.ul.com/scopes/1741.html. Accessed 

October 3, 2009. 

Whitaker, C.; Newmiller, J.; Ropp, M.; Norris, B. Renewable Systems Interconnection 

Study: Distributed Photovoltaic Systems Design and Technology Requirements. 

SAND2008-0946 P. Albuquerque, NM: SNL, 2008. 

2-10
 
3.0 Technical Review of Concerns and Solutions to PV 

Interconnection in New York City 

This section describes solutions to concerns commonly expressed by utility network engineers 

and industry experts when interconnecting photovoltaic (PV) systems onto secondary networks. 

Nine solutions are described in detail, including advantages and disadvantages, potential impacts, 

and road maps for deployment. We suggest the following solutions: maintaining minimum loads, 

minimum import relays, reverse power relays, dynamically controlled inverters, load flow 

studies, supervisory control and data acquisition (SCADA) system/inverter integration, energy 

storage devices, advanced protective schemes, and PV array orientation variations. 

3-1
 
Contents
 

3.1 Introduction........................................................................................................................... 3
 

3.1.1 Organization of This Section ..................................................................................... 9
 

3.2 Solutions ............................................................................................................................. 10
 

3.2.1 ML—Maintain Minimum Load............................................................................... 10
 

3.2.2 MIR—Minimum Import Relay................................................................................ 11
 

3.2.3 RPR—Reverse Power Relay.................................................................................... 15
 

3.2.4 DCI—Dynamically Controlled Inverter .................................................................. 18
 

3.2.5 LF—Load Flow Studies........................................................................................... 21
 

3.2.6 SCADA—Integrate Inverters with Communication Capabilities............................ 24
 

3.2.7 ES—Energy Storage ................................................................................................ 27
 

3.2.8 PRO—Advanced Protective Schemes ..................................................................... 31
 

3.2.9 OR—PV Array Orientation ..................................................................................... 34
 

3-2
 
 

 

3.1 Introduction 

In this section, intended for utility network engineers and industry experts, we focus on potential 

technical problems (called “concerns”) that might arise when interconnecting PV systems onto 

secondary networks. Table 3-1 presents the concerns along with relevant solutions for each. The 

table lists the concerns in order of importance, loosely based on the most common issues 

described by utility network engineers and industry experts. 

Each solution given in Table 3-1 is abbreviated, and Table 3-2 is the abbreviation key. Following 

Table 3-2, we examine each of the top nine solutions in detail, looking at the concerns it 

addresses, its effectiveness at various PV penetration levels, its advantages and disadvantages, its 

impacts, its financial considerations, and any associated smart grid issues. At the end of each 

solution discussion, we suggest a road map for deployment. 

Note that, to date, PV deployment on secondary networks has been quite limited. As a result, 

many of the topics discussed in this section will need to be revisited to determine the validity of 

the concerns and the appropriateness of the solutions. 

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Table 3-1. Concerns and Solutions for Interconnecting PV with Secondary Distribution Networks 

Concern Explanation Solution 

Network Protector 

Operation and Cyclinga 

Power System Planning— 

Generation Dispatch Impact 

Power System Planning— 

Load Profile Change 

Increased Fault Currentb 

Fault Current Coordination 

Issuesa 

Voltage Risec 

Increased Volt-Ampere 

Reactive (VAR) 

Requirements 

Increased Harmonics 

Voltage Flicker 

Exporting PV systems produce reverse 

power flow, which might cause network 

protectors to operate and cycle. 

Variability in PV generation might require 

increased flexibility from conventional 

generation. 

PV generation might change the load profile 

seen by the utility, impacting the scheduling 

of conventional generation. 

PV systems add additional sources of 

energy to the network, and might increase 

the level of available fault current beyond 

the equipment ratings. 

PV systems add additional sources of 

energy that can change the direction of fault 

current flows or add new flows, disrupting 

the coordination of protective devices. 

Reverse power flow from exporting PV 

systems can cause voltage levels to rise 

above the maximum voltage limit. 

PV system inverters produce only real 

power, so other power generators will have 

to supply a higher percentage of reactive 

power (VAR). 

PV systems could induce harmonic 

distortion in the system. Harmonics could 

adversely affect operation of motors and 

electronics and cause undesirable heating 

in transformers and cables. 

When PV system output increases or 

decreases (in response to passing clouds, 

for example) faster than the remaining 

generators can compensate, voltage flicker 

can occur. This may result in light flicker, 

variable motor speed performance, and 

wear on equipment. 

MIC, DCI, LF, SCADA 

(exporting systems) 

ML, MIR, RPR, DCI, LF, 

SCADA (nonexporting 

systems) 

GF, LC, SIT, OR 

OR, FOR
 

FCM
 

MIC, PRO
 

ES
 

CAP
 

PQ, MIC
 

DIS, ES, WEA (exporting 

systems) 

ES, WEA (nonexporting 

systems) 

3-4
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Voltage Drop Resulting 

from Sudden PV Lossa 

The sudden loss of PV generation can lead 

to unacceptably low voltages in parts of the 

ES, VR, LVRT 

system and subsequent increases in 

apparent load to the utility. 

Voltage Drop Caused by Interconnection standards require PV LVRT, VR 

Trips on Distribution 

Systema 

systems to disconnect from the grid during 

grid faults. Loss of PV generation may lead 

to unacceptably low voltages. 

Sudden PV Loss Due to Customer equipment and other distributed PQM, INV 

Inverter Tolerance Limits generators could induce harmonics or 

variations in voltage and frequency that 

push power outside inverter tolerances, 

forcing PV systems to drop offline. The loss 

of the PV systems could lead to 

unacceptably low voltages. 

Subtransmission Problemsa PV currents may feed from the distribution PRO, LIM, INS 

system back up into the subtransmission 

system, causing ground fault overvoltage, 

interference with sectionalizing switching 

schemes, and overcurrent protection 

coordination issues on the subtransmission 

system 

Unintentional Islandsa, d When a network protector opens and PLC, SCADA 

isolates a section of the power system with 

a PV energy source, an unintentional island 

might form. This endangers utility and 

customer equipment and personnel. a This is only a concern at higher PV penetration levels. At this time, high PV penetration levels for secondary
 

networks are not well defined. In this report, we consider high penetration to be above 5%.

b Fault current contribution from inverter-based systems is not considered significant.
 c Extremely unlikely with most small to medium PV systems. Very unlikely on any secondary network.
 d Underwriters Laboratories (UL)-approved inverters have an anti-islanding function per IEEE 1547-2003 [IEEE.
 

Standard for Interconnecting Distributed Resources with Electric Power Systems. IEEE Std. 1547-2003. 2003.
 

http://grouper.ieee.org/groups/scc21/1547/1547_index.html. Accessed October 3, 2009.]
 

3-5
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 3-2. Solution Key for Table 3-1 

Abbreviation 

ML 

Definition 

Minimum load 

Explanation 

A minimum load is maintained at all 

times. 

MIR Minimum import relay A relay is set to trip PV offline if customer 

load drops below a predetermined level. 

RPR Reverse power relay A relay is set to trip PV offline if customer 

load drops to zero or if the PV system 

begins to export power. 

DCI Dynamically controlled inverter A DCI monitors the load and curtails PV 

system output if customer load drops 

below a predetermined level. 

LF Load flow study The utility runs a load flow study to 

determine if there is any potential impact 

to the coordination of protective devices. 

If a potential exists, the utility can modify 

the coordination scheme in most cases. 

Load flow calculation for network systems 

is highly complex. 

SCADA Supervisory control and data 

acquisition 

PV inverters are integrated into utility 

SCADA systems and/or advanced 

metering infrastructure (AMI) systems. 

The SCADA system controls inverters via 

an available communications channel. 

ES Energy storage Energy storage (most likely batteries) is 

added at the PV site or the utility 

substation to control fluctuations in PV 

system output. The cost is significant, but 

the storage could decrease ramp rates, 

reduce flicker, and help manage voltage 

levels. 

PRO Advanced protection Advanced protective schemes—such as 

directional overcurrent trip, blocking, and 

high-speed transfer trip(s)—are used to 

take equipment offline in the event of a 

fault. 

OR Orientation The orientation of some PV panels is 

changed to shift timing of power 

generation. 

MIC Monitoring information exchange 

and control 

Utility monitoring, information exchange, 

and control allow curtailment of PV 

generation. 

GF Generation flexibility The utility modifies the balance of 

generation portfolio to maintain flexibility, 

allowing the system to cope with 

3-6
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

increased variability. 

LC Load control The utility uses load control, load shifting, 

energy storage, and curtailment of PV 

generation to manage a flexibility 

shortage or voltage excursions. 

SIT Siting Utilities, states, and cities evaluate 

alternative siting options of PV systems to 

reduce impacts on generation dispatch. 

FOR Load forecasting The utility includes PV generation in the 

energy growth forecast (integrated 

resource plan) and plans for sufficient 

flexibility in generation portfolio. 

CAP Capacitor Capacitors are installed on customer PV 

systems to maintain a power factor (PF) 

of 90% or better (PV inverters currently 

produce only real power). A utility might 

also install feeder-level capacitors or 

substation-sited capacitor banks to 

maintain proper PF and VARs. 

PQ Power quality standards Power quality issues are addressed by 

IEEE 1547-2003 and inverters must meet 

the UL 1741 standard.1 These standards 

require distributed generation (including 

PV) to maintain minimum power quality. 

WEA Weather forecasting Tracking of weather patterns, especially 

cloud cover, is integrated into utility 

dispatch operations to ensure that 

adequate spinning reserve or 

dispatchable load is available. 

DIS Spatial distribution Distributed resources (including PV) are 

spatially distributed so that cloud cover 

does not affect the system quickly.a 

VR Voltage regulation The utility uses load tap changers or 

other regulator devices to raise or lower 

feeder voltage to keep it within normal 

limits. 

LVRT Low-voltage ride-through Inverters with ride-through capability 

allow the PV system to maintain 

operation during times when voltage sags 

below normal operating range or when 

there are temporary voltage drops caused 

by faults. PV systems stay online during 

minor system disturbances and support 

1 See UL 1741. [Underwriters Laboratories Inc. Standard for Inverters, Converters, Controllers and Interconnection 

System Equipment for Use with Distributed Energy Resources. UL Std. No. 1741, 1st Edition. 1999. 

http://ulstandardsinfonet.ul.com/scopes/1741.html. Accessed October 28, 2009.] 

3-7
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

voltage, rather than dropping off in bulk 

(causing a larger disturbance). Some 

existing inverters have the ability to ride 

through voltage irregularities, but current 

U.S. standards2 call for the inverters to 

drop offline and remain offline for 5 

minutes once normal voltage returns. 

PQM Power quality monitoring Power quality monitoring devices are 

installed at the source of power quality 

problems. The utility works with the owner 

of problematic systems to bring that 

system into conformance as governed by 

the rules of the utility. 

INV Inverter tolerance The inverter operates outside of the 

normally allowed voltage parameters. 

Many inverters on the market today can 

be programmed or adjusted to tolerate 

aberrations in voltage, frequency, and 

harmonics. Future standards (UL and 

IEEE) could allow for wider tolerances or 

for adjustments. 

LIM Limit penetration PV capacity is limited to a safely defined 

penetration limit. This requires tracking 

the total PV deployment level and 

comparing that number to the known 

system peak demand load. 

INS Insulation Insulation coordination and 

surge/lightning arresters are increased on 

all cables and devices to handle ground 

fault overvoltages. This is applicable if 

system studies indicate that voltage 

levels could reach a level that could 

damage distribution equipment. b 

PLC Power line carrier 

communications 

PLC communications (PLCC) tests the 

continuity of the line by injecting a lowfrequency signal (typically 5 kHz or lower) 

onto the network to verify the presence of 

utility sources. Inverters “listen” for the 

signal and drop offline in the event of loss 

of signal (indicating loss of utility power). 

This prevents unintentional islanding. 

FCM Fault current mitigation Fault current mitigation equipment is 

installed at the generator. Fault mitigation 

requirements are defined by the utility on 

2 See IEEE 1547-2003, 4.2.3 Table 1 [IEEE. Standard for Interconnecting Distributed Resources with Electric 

Power Systems. IEEE Std. 1547-2003. 2003. http://grouper.ieee.org/groups/scc21/1547/1547_index.html. Accessed 

October 3, 2009.] 

3-8
 
 

 

 

 

 

 

 

 

 

 

 

a case-by-case basis but generally 

require that the protection interrupt the 

fault current contribution within half a 

cycle. Examples of FCM include DC links, 

fast acting fuses, or series reactors. a Spatial distribution opportunities within New York City are limited for customer-owned PV systems. Utility-owned
 

PV systems may be located with reasonable spatial distribution.

b This is highly unlikely for secondary network systems similar to those in New York City.
 

3.1.1 Organization of This Section 

Each solution is further described in this section with the following components: 

•	 Description: Offers information on how the solution might apply to one or more
 

concerns.
 

•	 Discussion: Elaborates further on the main description if necessary. 

•	 Concerns Addressed: Lists which concerns (identified in Table 3-1) are addressed by 

this solution. 

•	 Ranking of Solutions: Ranks how well the solution addresses the concern. The ranking 

applies to both area and spot networks, unless otherwise stated. This ranking is 

subjective, and is based on the experience of National Renewable Energy Laboratory 

(NREL) staff and from information gleaned from other publications on this subject: 

o	 Good—considered an acceptable or preferred approach to address specific 

concerns. 

o	 Poor—considered an unacceptable solution for the concern being addressed. The 

technology may have been deployed in some manner and shown to be either 

unsuccessful or having significant shortcomings. 

o	 Untested—not likely to have been applied on PV systems on secondary networks. 

•	 Penetration Level: Discusses the appropriateness of the solution at low, medium, or high 

penetration levels. The level of penetration of PV systems on an electric distribution 

system is expressed as a percentage of peak PV generation power divided by the peak 

demand load for that system. 

•	 Advantages: Presents some of the potential advantages of the solution to both PV system 

owners and the utility. 

•	 Disadvantages: Presents some of the known or perceived disadvantages of the solution 

to both PV system owners and the utility. 

•	 Financial Considerations: Covers financial issues, positive or negative, for both the PV 

system owner or installer and the utility. 

•	 Impact of Solution: Examines the anticipated impact of this solution (may be based on 

historical experience). 

•	 Location of Solution: Briefly describes where the solution might be physically located. 

3-9
 
 

 

 

 

 

•	 Smart Grid Issues: Describes how the solution would integrate with smart grid 

technology. Much of the discussion is hypothetical because the smart grid has not been 

fully defined or deployed. 

•	 Road Map: Lists potential steps or issues to address in the future. 

•	 Remarks: Serves as an area for additional comments. 

We have also included graphs and examples where they help to illustrate the solution. 

3.2 Solutions 

3.2.1 ML—Maintain Minimum Load 

Description: ML is a means to forecast that net customer load (including PV generation) will be 

greater than a specific minimum load. The expected power output of the PV system is compared 

to historical and projected customer loads, and the PV system is sized to ensure a minimum load 

is maintained at all times. All non-PV customer-sited distributed generation must also be 

included in the analysis. 

Concerns Addressed: Network protector operation and cycling 

Ranking of Solution: Network protector operation and cycling—good 

Penetration Level: This is an appropriate solution for all levels of penetration. 

Advantages: 

•	 Relatively simple to estimate level of minimum load based on load data and type 

•	 Good solution for PV systems that must remain nonexporting 

•	 Can be validated by real-time monitoring 

•	 Applicable to both area and spot networks 

•	 Using ML might eliminate requirements for other protective relays like RPR, MIR, or 

DCI in situations where load is consistent and PV system peak output is less than half of 

the minimum daytime load. 

•	 Can be used in conjunction with RPR, MIR, or DCI to prevent a system from exporting. 

•	 The most appropriate solution for installations with minimum loads that are significantly 

greater than the output of the PV system. 

Disadvantages: If the minimum daytime load at a facility is low (e.g., on weekends and 

holidays), the PV system size may have to be reduced in order to maintain a nonexporting 

system. 

Financial Considerations: 

For PV system installer/owner 

3-10
 
 

 

 

 

•	 Analysis cost (e.g., system monitoring) 

•	 May be no equipment costs (unless ongoing monitoring is required or another
 

technology—such as RPR, MIR, or DCI—is used in conjunction with ML)
 

•	 Cost of review of design and load data by the utility. 

For the utility 

•	 Significant internal coordination required among engineering, planning, operations, 

billing, and other departments 

•	 May incur costs if the utility is to monitor or inspect the system at regular intervals. The 

cost of monitoring (via SCADA/smart grid system) may be recoverable in the rate base if 

approved by the Public Service Commission (PSC). 

Impact of Solution: ML has no impacts other than a reduced daytime load for the customer with 

the PV system. 

Location of Solution: This solution affects only the size of the PV system. No additional 

hardware is required. 

Smart Grid Issues: Monitoring the status of minimum load during PV production hours via 

SCADA/smart grid might be beneficial for verifying the power generated and the load consumed 

at the site. 

Road Map: ML can be calculated and the PV system sized based on historical and forecasted 

loads. An annual review of all ML systems might be worthwhile, though, in case loads drop 

significantly below historical or forecast levels. If loads are smaller than allowed for in the PV 

system design, the PV system owner might need to take steps to eliminate export (if required) or 

to reduce power production capability. 

ML is a good solution for any spot network. It might also be a good approach for area networks 

where power exporting is not desired or allowed. ML may not require any system upgrades or 

hardware additions. To track annual loads for verification, however, the utility might require an 

interval or production meter. 

Remarks: ML is based on limited PV system size and larger historical or projected site loads. 

ML has been implemented with several PV systems on networks with successful results. One 

very significant drawback to relying on ML alone is the nature of loads in any location. For 

example, buildings of any type can see large increases or decreases in load over time, and 

additional PV equipment might be installed on the buildings. ML relies on historical or forecast 

data, which may not be an accurate prediction of future data. 

3.2.2 MIR—Minimum Import Relay

Description: Similar to an RPR, an MIR is designed to trip a circuit breaker (or perhaps control 

a DCI) when the customer’s load drops below a predefined level. The MIR monitors the input at 

the point of common coupling (PCC) and issues a signal if customer’s load drops below a preset 

threshold. Good solution for ensuring that the customer load does not approach zero and power is 

always being drawn from the network. 

3-11
 
 

 

Concerns Addressed: Network protector operation and cycling 

Ranking of Solution: Network protector operation and cycling—good for spot networks. For 

area networks, an RPR should be considered instead of an MIR if zero customer load is 

acceptable. 

Penetration Level: MIR is an appropriate solution for spot networks at all levels of penetration. 

For area networks, they may be used at any level of penetration, but it is unlikely that MIRs 

would be necessary to prevent disruptions of network protector operations at low penetration 

levels. At higher levels of penetration, the MIR solution will be a valuable method to ensure that 

network protectors remain closed. 

Advantages: 

•	 Technology exists today and is proven. 

•	 Prevents customer’s load from dropping below a specified threshold. 

•	 Can be monitored by customer’s energy management system (EMS) or utility-owned 

SCADA systems. 

•	 Can be used in concert with other solutions (e.g., ML, RPR, and DCI). 

Disadvantages: 

•	 For smaller PV systems, MIR installation can be a significant percentage of overall 

system cost. 

•	 Customer’s loads must consume all power produced or risk an MIR lockout. 

•	 Most MIRs must be reset manually. If not monitored, this could result in the PV system 

being offline for an extended period of time. 

•	 Utility must review and accept calculations of settings for the level of current/power 

appropriate for each customer site. This could be time consuming and costly. 

Financial Considerations: 

For the PV system installer/owner 

•	 Typically in the range of $10,000 installed (traditionally paid by installer). 

•	 Varying prices based on existing equipment configuration, integration constraints, size of 

PV system, size of MIR equipment, and service characteristics. 

•	 Cost of review of design and load data by the utility. 

For the utility 

•	 May be a cost to the utility for testing, monitoring, or ongoing evaluation of the
 

equipment.
 

3-12
 
 

 

 

 

 

 

 

 

 

Impact of Solution: 

For area networks, an MIR should eliminate any power flow onto the network, greatly reducing 

the likelihood of network protectors operating and cycling. At significant levels of penetration, 

reduced system loads from the presence of PV systems (and other distributed generation 

systems) could cause MIRs to operate frequently. This will result in PV systems going offline for 

extended periods. 

For spot networks, an MIR will eliminate the PV system contribution before the customer’s load 

drops too low. It is a good solution for spot networks, which require a minimum load to be 

present at all times to keep the network protectors closed. 

Location of Solution: MIR monitoring sensors are located near the main utility meter equipment 

just downstream of the main disconnect (the PCC). This placement allows the utility to measure 

the service load. The MIR relay, typically located within a few feet of the monitoring sensors, 

controls a circuit breaker or contactor that ties onto the PV system branch circuit. 

Smart Grid Issues: 

•	 At higher penetration levels, smart grid controls might need to be incorporated into 

MIRs. 

•	 Using SCADA to monitor larger PV MIR systems3 would be beneficial as a means of 

verifying operation and determining the relay’s status. The utility would also be able to 

gain control of the MIR in the event of a significant network failure that would require 

remote operation of the MIR. Monitoring of smaller systems might not be required, 

although monitoring might have benefits to the utility and the system owner. 

•	 Larger PV systems with MIR technology might have an option for utility control in case 

of severe problems on the network, but a highly secure communication link would be 

necessary. 

•	 If AMI technology progresses sufficiently in the future, so that all customers have twoway communications in place, both the PV system owner and the utility might benefit 

from monitoring the status of all PV systems. 

Road Map: 

•	 MIR equipment, like RPR equipment, is often installed as a retrofit after PV systems are 

installed. Although feasible as a retrofit, it is easier to install this technology on new 

buildings. 

•	 MIR equipment is a mature technology. The equipment is likely to evolve further and this 

solution will be employed for many years. 

3 IEEE 1547-2003 4.1.6 suggests monitoring provisions for systems of 250 kVA or larger. [IEEE. Standard for 

Interconnecting Distributed Resources with Electric Power Systems. IEEE Std. 1547-2003. 2003. 

http://grouper.ieee.org/groups/scc21/1547/1547_index.html. Accessed October 3, 2009.] 

3-13
 
•	 MIRs are a good choice when a PV system is not allowed to export power. Spot networks 

should always be fitted with an MIR, unless the minimum load can be shown to be 

significantly higher than the PV power produced. 

•	 MIR settings should be verified each year or when a significant load change occurs at the 

PV system location. 

•	 The utility might consider monitoring MIRs on its network systems using SCADA or 

smart grid MIC. Larger PV systems should be monitored, but smaller systems might also 

be considered for monitoring (depending on location specifics). 

•	 MIR is often financially practical to install, both from a cost perspective and from a 

technical perspective. Some facilities, though, will face significant challenges in 

retrofitting their electrical panels with this technology. 

Figure 3-1 illustrates one example of how an MIR might be applied. 

Figure 3-1. Schematic of a secondary network with MIR 

Remarks: The MIR is commonly deployed on PV system installations at commercial or 

industrial locations, but infrequently on residential systems. The MIR is an excellent solution 

that, when installed properly, ensures that the customer load is always taking power from the 

network transformers, which tends to keep network protectors in a normal closed position. Spot 13.2 kV 13.2 kV Feeder 1 Feeder 2 Feeder n 

120/208 Volt 

3-Phase Bus 

Spot/Area 

Network 

Con Edison 

± 

AC 

Disconnect 

NP

NP 

13.2 kV 

NP 

Minimum 

Import 

Relay 

Breaker 

Inverter 

Main 

Disconnect 

Utility 

Metering 

PV Array 

MIR 

Sensing 

Relay 

3-14
 
 

networks would be better served by an MIR than an RPR because the MIR is capable of ensuring 

minimum power flow to the customer. In addition, the MIR is a proven technology, trusted by 

many electric utilities and customers, and can be monitored and controlled remotely as smart 

grid technology takes on a greater role in electric utility operations. Note that coordination 

between the MIR, customer circuit breakers, and the network protector must be considered 

during system design. 

3.2.3 RPR—Reverse Power Relay

Description: An RPR is a special case of the MIR where the current is set at zero amps. It is 

designed to trip a circuit breaker (or perhaps control a DCI) when the customer’s load drops 

below the predefined limit of zero amps. The RPR monitors the input at the PCC and issues a 

signal if the input current from customer load drops below zero amps. 

Concerns Addressed: Network protector operation and cycling 

Ranking of Solution: Network protector operation and cycling—good for area networks. MIRs 

are preferred for spot networks. 

Penetration Level: RPRs are an appropriate solution for maintaining a nonexporting PV system 

at all levels of penetration. At very low levels of penetration, they may not be needed to prevent 

network operations in area networks. At higher levels of penetration, they will likely be a 

valuable tool for ensuring network protectors do not open. 

Advantages: 

•	 Prevents PV systems from exporting energy to the grid. 

•	 Technology exists today and is mature. Generally an acceptable solution for many 

utilities.
 

•	 Could be monitored by customer’s EMS and utility-owned SCADA/smart grid systems. 

Disadvantages: 

•	 Might still allow some network protectors to open as the customer load approaches zero 

(MIR or CIS solutions are a preferred choice because the PV system can be 

reduced/decoupled before the customer load reaches zero). 

•	 Cost, commensurate with the MIR, could be a significant percentage of cost for small PV 

systems (5 kW and below). 

•	 Customers must consume all power produced or risk the RPR lockout. 

•	 Most RPR circuit breakers must be reset manually and, if not monitored, could result in 

the PV system being offline for an extended time. This is a similar issue for MIR 

systems, and might pose a significant problem. 

Financial Considerations: 

For PV system installer/owner 

3-15
 
 

 

 

 

 

 

 

 

•	 Typically in the range of $10,000 installed (traditionally paid by installer). 

•	 Prices vary based on existing equipment configuration, integration constraints, size of PV 

system, and size of RPR equipment. 

•	 Cost of review of design and load data by the utility. 

For the utility 

•	 Utility can incur costs if the system is to be monitored or inspected on an ongoing basis. 

The utility cost of monitoring (via SCADA or smart grid system) could be recovered 

through the rate base if approved by the PSC. 

•	 If the installation labor and capital costs of the RPR are placed on the utility, those costs 

may be capitalized (if approved by the PSC) and could be recovered in one or more rate 

classes. 

Impact of Solution: 

An RPR eliminates power export from the customer PV system to an area network. This greatly 

reduces the likelihood of network protectors operating at low levels of penetration. At higher 

levels of penetration, network protectors are more likely to operate, owing to reduced network 

transformer loads from the aggregated effect of PV systems (and all distributed generation 

systems). 

For spot networks, network protectors may still open or cycle under network transformer lowload conditions because these networks require a minimum load to be present at all times to keep 

the network protectors closed. RPRs prevent power from flowing back to the utility. 

Location of Solution: The RPR is located on the customer side of the meter at the installation 

location. The RPR monitoring equipment (current transformers) is usually located near the main 

utility meter equipment or on the branch circuit that ties to the PV system. The relay controls a 

circuit breaker or contactor that connects to the PV system branch circuit. 

Smart Grid Issues: 

•	 Monitoring of larger RPR systems4 via SCADA or any hybrid system could be beneficial 

as a means of verifying operation, status of relay, and potential utility control of the RPR 

in the event of a significant network failure. 

•	 Smaller PV systems might have provisions to allow monitoring by a local device that 

would report back to the utility when needed. 

•	 Larger PV systems with RPR technology might also allow for utility control in case of 

severe problems on the network (per agreement by the utility and system owner). 

4 IEEE 1547-2003 4.1.6 Each DR unit over 250 kVA shall have provisions for monitoring. [IEEE. Standard for 

Interconnecting Distributed Resources with Electric Power Systems. IEEE Std. 1547-2003. 2003. 

http://grouper.ieee.org/groups/scc21/1547/1547_index.html. Accessed October 3, 2009.] 

3-16
 
 

Road Map: 

•	 Although RPRs are often installed as a retrofit system on PV systems, they are easiest to 

install where there is ample room or new construction. Some facilities will find installing 

RPRs difficult because of space constraints. 

•	 RPR technology is mature, and utilities have installed RPRs successfully. 

•	 As levels of penetration rise, RPRs may be required for systems of all sizes. Some PV 

proponents suggest that RPRs should not be required on PV systems smaller than 30 kW 

because small systems are unlikely to have significant impact on area networks. The 

requirement might have to be evaluated on a case-by-case basis. 

•	 RPRs are a good choice when exporting power is not expected or allowed on area 

networks. Spot network operators should consider using MIRs or DCIs to maintain 

minimum load and ensure that network protectors remain closed. 

•	 The utility might consider using SCADA/smart grid to monitor RPRs on its network 

systems. 

•	 RPR installations are often practical from both a cost perspective and a technical 

perspective. 

•	 For larger PV systems, utility monitoring (and perhaps supervisory control with 

agreement between the PV system owner and the utility) might be considered for both 

generation tracking and high-penetration controls. This would require the utility to 

upgrade its SCADA system or add other smart grid technologies, especially as 

penetration levels increase. The utility might ask that PV systems of all sizes be 

voluntarily monitored. The utility might also consider continuously monitoring PV 

systems using production meters. 

Figure 3-2 illustrates one example of how an RPR might be applied. 

3-17
 
 

Figure 3-2. Schematic of a secondary network with RPR 132 kV 

120/208 Volt 

3-Phase Bus 

Area Network 

Con Edison 

± 

AC 

Disconnect 

. 

Reverse 

Power 

Relay 

Breaker 

Inverter 

Main 

Disconnect 

Utility 

Metering 

PV Array 

RPR 

Sensing 

Relay 

132 kV

132 kV 

Feeder 1

Feeder 2

Feeder n 

NP

NP

NP 

Remarks: RPRs are a proven technology, trusted by many electric utilities and customers, and 

they can be monitored remotely using smart grid technology. RPRs are often deployed on PV 

system installations in commercial or industrial settings, but rarely on residential systems (an 

RPR is not typically a financially viable option for a smaller PV system). RPRs are considered 

costly for smaller PV systems (<30 kW), and usually considered economical for medium to large 

PV systems. 

3.2.4 DCI—Dynamically Controlled Inverter

Description: A DCI is an electronic-based control system that monitors the load and curtails PV 

system output if the customer load drops below a predetermined level. DCIs would typically be 

integrated into the inverter, and have monitoring and control components that are external to the 

inverter. The major advantage of DCIs is the PV system is signaled to reduce output, instead of 

being dropped to zero power output as the RPR and MIR options require. DCIs are an emerging 

technology. 

Concerns Addressed: Network protector operation and cycling 

Ranking of Solution: Network protector operation and cycling—good 

3-18
 
 

 

 

 

 

 

Penetration Level: DCIs are an appropriate solution for low, medium, and higher levels of 

penetration. At very low penetration levels, DCIs would be unnecessary to prevent network 

protector from opening within an area network. At higher levels of penetration, DCIs are likely 

to be a valuable tool to ensure that network protectors do not open. Smart grid controllability 

might need to be incorporated into DCIs at higher penetration levels. DCIs would be a good 

solution on spot networks regardless of overall network penetration levels. 

Advantages: 

•	 Prevents PV systems from exporting, or from exporting under certain conditions, thus 

eliminating detrimental power flow onto the grid. 

•	 Might be applied as a means to ensure minimum import requirements. 

•	 Can be monitored by customer’s EMS and utility-owned SCADA systems. 

Disadvantages: 

•	 Emerging technology. Successfully demonstrated in actual deployment, but not
 

extensively field tested.
 

•	 Loss of generation for some PV system owners when the DCI reduces system power 

output. 

•	 Only a few inverter manufacturers offer DCIs.5 

•	 DCI operation could preclude PV system owners’ awareness of reduced system output. 

Financial Considerations: 

For PV system installer/owner 

•	 DCIs can be integrated into inverters for minimal additional cost. 

•	 Costs are likely to drop as inverter manufacturers look at making this a standard option 

for inverters. 

•	 DCIs will result in loss of generation for PV system owners when the DCI reduces 

system power output. This loss will reduce the amount of energy produced annually, 

which will impair the economic performance of the system and extend payback periods. 

New tariffs might compensate PV system owners for curtailed operations, similar to 

existing demand response provisions. 

•	 Customer will incur a cost for the review of the design and load data by the utility. 

For the utility 

•	 Utility can incur costs if the system is to be monitored or inspected on an ongoing basis. 

The utility cost of monitoring (via SCADA or smart grid system) could be recovered 

through the rate base if approved by the PSC. 

5 At the time of this report, DCIs are not a commonly available option for all inverters. They are available 

commercially only on larger (>100 kW) inverters. 

3-19
 
 

 

 

 

 

 

Impact of Solution: 

For area networks, a DCI can be set to eliminate all power flow onto an area network, greatly 

reducing the likelihood of network protector operations. An MIR would still be required to 

ensure network protectors do not operate. In high-penetration scenarios, the DCI could be 

monitored and potentially controlled by the utility smart grid system. That control could 

significantly reduce system problems when high levels of distributed generation negatively affect 

the distribution system. 

For spot networks, because network protectors will open if their load drops below the minimum 

power threshold, DCIs would have to be programmed to prevent power from flowing back to the 

utility. Network protectors might still open or cycle under low-load conditions, but are far less 

likely to do so if the DCI assists by lowering PV system power production. 

Location of Solution: A DCI would always be located on the customer side of the meter. DCI 

monitoring equipment would likely be located near the main disconnect, and most DCI 

electronics would be located within the inverter itself. 

Smart Grid Issues: 

•	 Monitoring of DCI systems via SCADA/smart grid would be beneficial as a means of 

verifying operation and status of output. Monitoring would also allow for emergency 

control of the DCI if the network suffered a significant failure that required remote 

inverter operation. 

•	 Monitoring provisions should be installed on larger PV systems that include DCIs.6 This 

gives the utility the option to track the PV system’s performance. 

•	 Smaller PV systems with DCIs could also have an option for utility control in case of 

problems on the network. 

Road Map: 

•	 In comparison to RPRs or MIRs, which are protection systems, DCIs could be
 

significantly easier to install in existing facilities. DCIs are worth consideration, 

particularly because they can be set to provide nonexporting functions.
 

•	 DCIs should be combined with an MIR in a spot network to ensure that network 

protectors remain in service. As a design philosophy, control and protection functions 

need to remain separate. 

•	 DCIs have been installed in PV systems, though none to date in New York City. 

•	 DCIs can be considered an option for PV systems of all sizes for both spot networks and 

area networks with higher levels of penetration. 

•	 The utility might consider using SCADA to monitor DCIs on its network systems. 

6 IEEE 1547-2003 4.1.6 Monitoring Provisions [IEEE. Standard for Interconnecting Distributed Resources with 

Electric Power Systems. IEEE Std. 1547-2003. 2003. http://grouper.ieee.org/groups/scc21/1547/1547_index.html. 

Accessed October 3, 2009.] 

3-20
 
 

•	 DCIs are feasible to install, both from a cost perspective and a technical perspective. Not 

all manufacturers offer DCI at this time, however. 

•	 For medium to large PV systems, utility monitoring and control should be considered for 

both generation tracking and for high-penetration controls. This might require upgrading 

the utility SCADA system or putting other smart grid technology in place. 

Figure 3-3 illustrates one example of how a DCI might be applied. 13.2 kV 13.2 kV Feeder 1 Feeder 2

Feeder n 

120/208 Volt 

3-Phase Bus 

Spot/Area 

Network 

Con Edison 

± 

AC 

Disconnect 

NP

NP 

13.2 kV 

NP 

Device 

Breaker 

Dynamically 

Controlled 

Inverter 

Main 

Disconnect 

Utility 

Metering 

PV Array 

LoadSensing 

CTs/PTs 

Figure 3-3. Schematic of a secondary network with DCI 

Remarks: DCIs work well for ensuring that a PV system does not export power onto either an 

area or spot network. Because the output of the PV system would vary depending on the 

incoming utility power, the systems are ideal when the load status changes. 

3.2.5 LF—Load Flow Studies 

Description: A utility load flow study evaluates the effects of a proposed PV system—and other 

distributed generation systems—on a secondary network. In such studies, analysts use software 

tools to help the utility engineers understand if the proposed system would cause any reliability 

problems and whether any facilities would need to be upgraded. The studies, which are typically 

quite detailed, can be time-consuming and expensive. Where appropriate, both the utility and the 

PV system owner would prefer a simplified approach. 

3-21
 
 

 

 

 

Concerns Addressed: Network protector operation and cycling 

Ranking of Solution: Network protector operation and cycling—good 

Penetration Level: Load flow studies are appropriate at all levels of network penetration. 

Because of the nature of secondary networks and their sensitivity to the direction of current flow, 

load flow studies are useful even when there are relatively few PV systems on a network. As 

penetration levels increase, concerns that PV systems will disrupt network operations grow, and 

load flow studies might need to be completed on all PV system installations. 

Advantages: 

•	 The utility engineers have the expertise to conduct load flow studies using computer 

models. 

•	 Load flow studies allow engineers to evaluate potential PV systems at a specific location 

and design solutions appropriate for that system. 

Disadvantages: 

•	 A load flow study is a time-consuming process that can delay a project. 

•	 Modeling tools for distributed generation systems are under development, but tools 

currently available are limited. 

•	 It may be difficult to discern which potential installations require a load flow study. 

•	 Secondary networks and load flow characteristics will change over time. As a 

consequence, recommendations that come from load flow studies might need to be 

reevaluated in the future. 

Financial Considerations: 

For the PV system installer/owner 

•	 The cost of a load flow study is borne by the PV system owner up to cost limits set by the 

public utility commission. Costs may range from $500 to $5,000, and possibly more for 

more complicated systems. 

•	 The study could indicate that specific relaying equipment, DCIs, or additional equipment 

is required, and these costs can be significant. 

•	 Subsequent load flow studies could be required as the network changes and as PV
 

systems are added.
 

For the utility 

•	 After the cost limit set by the public utility commission is reached, further costs are borne 

by the utility. 

•	 Analysts completing load flow studies can become overwhelmed during periods where 

there are large numbers of applications. 

3-22
 
 

 

 

•	 Results do not necessarily mitigate future network problems. Network changes may 

require the utility to run new load flow studies at their own cost. 

Impact of Solution: 

•	 A load flow study can uncover potential problems in a particular area and will help the 

engineers make reasoned recommendations. 

•	 A load flow study can be time-consuming, which can have some impact on application 

processing. 

•	 These studies are unlikely to be necessary for small- to medium-sized PV systems. 

•	 The results of the study might indicate that special control equipment would be required 

(RPRs, MIRs, DCIs, or smart grid monitoring/controls). This equipment, if required, 

could have significant financial implications on the PV installer or owner. 

Smart Grid Issues: Load flow studies help determine which PV systems can be sited using 

autonomous control and which systems might need external monitoring, information exchange, 

and control. Some network systems might require more smart grid solutions than others. 

Road Map: 

•	 A load flow study is not required for proposed nonexporting PV systems. 

•	 As the number of studies of potential PV system installations increases over time, it 

should become clear that some PV systems do not need a load flow study. Need for 

studies may depend on PV capacity, penetration levels, location, and type of PV system. 

•	 PV systems and other distributed generation equipment can be monitored using a 

database and mapping system. Data from this monitoring can then be incorporated into 

load flow studies of future PV systems. 

•	 If a Web-based application process were available, it would be useful to consider a 

preliminary load factor study set of criteria for applicants. This might help them 

understand the constraints in their area based on their proposed design. In addition, PV 

system designers could find the resulting design parameters useful during their design 

process. 

Remarks: 

•	 Load flow studies are often critically important for any electric utility evaluating 

distributed generation systems. 

•	 Numerous software packages are available for conducting load flow studies, although 

none assess the impacts of distributed generation on a three-phase networked system. 

•	 Future software releases could reduce the time and cost of load flow studies, which 

would benefit customers and the utility. 

•	 Lessons learned from studies of current PV systems could reduce the number, time, and 

cost of future load flow studies, which would benefit customers and the utility. 

3-23
 
 

 

3.2.6 SCADA—Integrate Inverters with Communication Capabilities

Description: SCADA and AMI systems could be configured, along with communication 

systems, to use inverter technology for monitoring and controlling PV systems. This would allow 

a utility to monitor the PV system’s output, which in turn would enable curtailment or power 

diversion to, for example, a local storage system, load bank, or microgrid in the event of a grid 

problem. 

Concerns Addressed: 

•	 Unintentional islands 

•	 Network protector operation and cycling 

Ranking of Solution: 

•	 Unintentional islands—untested 

•	 Network protector operation and cycling—untested 

Penetration Level: This is an appropriate solution for all levels of penetration. 

Advantages: 

•	 Integrating PV system inverters into SCADA or AMI systems could allow for continuous 

monitoring of PV system performance. AMI systems could collect data for geographical 

areas and report back to SCADA. 

•	 If coupled with two-way communications technology, AMI systems could be used for 

communicating with PV systems when those systems were required to curtail power 

output. 

•	 SCADA monitoring of PV inverters would allow for real-time monitoring by system 

operators responsible for dispatching generation resources. Real-time monitoring in many 

SCADA systems results in data that are updated every 1 to 5 seconds. 

•	 Continuous monitoring of PV systems would be an important tool for understanding PV 

system performance and the ramp rates that would be associated with various weather 

phenomena. 

•	 Understanding the overall power output of blocks of PV systems would allow for a 

significantly improved understanding of the benefits of PV on the utility networks. 

Disadvantages: 

•	 Utility systems are not in place to monitor real-time customer-side information. 

•	 AMI systems, which are currently designed for billing customers, are often slow and are 

not designed for fast data collection. 

•	 There may be data collection limitations on the number of PV systems that could be 

monitored via AMI. 

3-24
 
 

•	 SCADA system monitoring would not be practical for monitoring each individual PV 

system (especially residential systems). Using intermediary systems (e.g., grid agents and 

smart grid platforms) to accumulate data for blocks of PV systems would be necessary 

for managing the large amounts of data. This would negate the possibility of real-time 

monitoring. 

•	 Costs to implement and maintain these systems would be high. 

Financial Considerations: 

For the PV system installer/owner 

•	 AMI monitoring of a PV system is more expensive for the PV system owner because the 

inverter manufacturer adds costs for specific monitoring points or for smart grid 

communications capabilities (e.g., via Zigbee, Bluetooth, WAN, and IEEE 802.11x, 

among others). 

•	 To maintain grid reliability, PV systems might be asked to curtail operations for any 

reason. These curtailments would reduce the amount of energy produced annually, which 

would impair the economic performance of the system and extend payback periods. New 

tariffs might compensate PV system owners for curtailed operations, similar to existing 

demand response provisions. 

For the utility 

•	 High cost to implement and maintain. 

•	 Significant investment (likely in the billions of dollars) will be required as part of an 

overall smart grid investment. These investments will need to be paid both by the PV 

system owners and the ratepayers as a group, as well as other stakeholders. This may be 

considered part of an overall smart grid system investment that is paid for by all 

ratepayers. Investments would likely be needed with either SCADA or AMI system 

upgrades/additions as well. 

Impact of Solution: 

•	 Network operators will be able to track bulk PV system performance for specific areas 

within a network. 

•	 Utilities would have the ability to monitor PV systems and notify owners if their PV 

systems cease to operate or sustain significant change in expected performance. If the 

utility is relying on PV system availability for operations and planning, SCADA systems 

would allow the utility to implement compliance measures, including penalties for 

nonperforming or underperforming systems. This may not be economically feasible or 

practical for monitoring smaller systems. 

•	 SCADA, AMI, or smart grid systems could monitor the difference in load and power 

production and, through additional communications, could notify the system operator of a 

problem or send a control signal to the inverter to curtail operation. 

3-25
 
 

 

 

 

•	 Understanding overall PV system performance would allow the utility and distribution, 

transmission, and generation operators to better utilize the resource and to plan for future 

load growth. 

•	 When the utility engineers know the characteristics of PV systems on their networks, they 

can design more accurate and timely tariffs. 

•	 Understanding the measured profile of all PV systems in an area might help researchers 

establish the benefits of, for example, PV systems and battery storage. 

Location of Solution: 

•	 SCADA systems have both software and hardware components and are integrated with 

communications systems. SCADA equipment for monitoring PV systems would be 

located on the distribution system on a secondary network. 

•	 AMI systems include utility revenue meters and one or more communications platforms. 

The communications platforms can be completely separate from the utility distribution 

system, or they can use the electric distribution systems via a power line carrier system. 

Smart Grid Issues: 

•	 SCADA integration may be impractical without additional communication systems or an 

intermediary (e.g., grid agent system) that could transfer bulk PV system information 

gathered in pockets of the network. 

•	 Security and cyber security are of concern. 

•	 AMI systems typically monitor utility revenue meters and report back to a central meter 

collection computer via PLC, radio signal, fiber optic system, or a combination of these. 

Some AMI systems have the capability to both monitor and issue commands to external 

devices (e.g., air conditioners or thermostats). PV systems with AMI would need to be 

monitored and commanded with the help of smart grid devices (such as grid agents) that 

have the ability to minimize the data movement in any direction. This would prevent the 

AMI system from being overwhelmed by large amounts of data. 

•	 AMI systems that rely on slower reporting technology or those with unidirectional 

information exchange (from meter to utility) would likely have limited usefulness in 

monitoring PV systems (other than collecting production data). To be effective, an AMI 

system must have a low-latency communications backbone and the capability to monitor 

and control external devices. 

Road Map: AMI systems should be chosen and deployed with several considerations, including 

•	 Overall cost to install meters and communications 

•	 Overall cost to read meters 

•	 Quality of AMI system and track record with other utilities 

•	 Adaptability to new technology (can the AMI devices integrate new devices?) 

•	 Speed of data retrieval and speed of commands to meters (if available) 

3-26
 
 

• Ability to integrate distributed generation into their platform.
 

Figure 3-4 illustrates one example of how a SCADA/AMI system might be applied.
 13.2 kV 13.2 kV Feeder 1 Feeder 2 Feeder n 

120/208 Volt 

3-Phase Bus 

Spot/Area 

Network 

Con Edison 

± 

AC 

Disconnect 

NP

NP 

13.2 kV 

NP 

Device 

Breaker 

Inverter/ 

Charger 

Main 

Disconnect 

AMI 

Metering/ 

SCADA 

Interface 

PV Array 

LoadSensing 

CTs/PTs 

Battery 

Bank 

AMI/SCADA 

Monitoring and 

Control of Inverter 

Figure 3-4. Schematic of a secondary network with SCADA or AMI interface to inverter (batteries 

optional) 

Remarks: The utility will decide whether to add monitoring and control of PV systems—via 

AMI communications and control technologies—to its operations. SCADA system integration 

would likely be focused on bulk PV systems reporting to an intermediate control device. 

Inverter manufacturers need to design inverters capable of interfacing with external systems. 

These inverters will need to have standardized outputs for monitoring power, energy, and status, 

along with inputs for control of chargers and curtailment. 

3.2.7 ES—Energy Storage 

Description: PV systems can be operated with batteries connected to the inverter. The batteries 

would be charged during periods when the power is not needed on the grid, and would be 

available to move that power back onto the grid when it is needed. Batteries could also be used 

as a backup system for a customer’s home or business, or for other critical loads (streetlights, 

emergency radios, life safety apparatus, and emergency loads). Batteries could also be used to 

improve ramp rates of PV systems. 

3-27
 
 

 

 

 

 

 

 

 

 

Concerns Addressed: 

•	 Voltage rise 

•	 Voltage flicker 

•	 Voltage drop resulting from sudden PV loss. 

Note: PV system batteries might address other concerns because they have the potential to keep a 

PV system from exporting. They can also allow a PV system to shift its power output to periods 

that are most beneficial to the utility system (e.g., shifting power to peak demand times). 

Ranking of Solution: 

•	 Voltage rise—good. Voltage rise could occur when PV systems export power to the 

network. Batteries could prevent exporting by storing excess power rather than sending it 

back to the network. 

•	 Voltage flicker—good. Flicker could occur when many PV systems drop offline because 

of sudden cloud cover. Batteries could maintain inverter power output in the event of 

sudden loss of DC power from the PV arrays. 

•	 Voltage drop resulting from sudden PV loss—poor. Once a feeder or network drops 

offline, and then is restored, the inverters—with or without batteries—must remain 

offline (once normal voltage and frequency are restored) for a period up to 5 minutes.7 

Penetration Level: ES is an appropriate solution for medium to high levels of penetration. 

Advantages: 

•	 Even small amounts of battery storage can smooth out and reduce the ramp rate of PV 

systems dropping out with cloud cover. Just one automotive-sized battery could improve 

system ramp performance. 

•	 Larger storage systems might allow for shifting energy production to grid peak times. 

•	 Customers could run inverters and batteries to lower their peak demands, potentially 

lowering monthly electric costs. 

•	 Storage systems could be used to allow customers to operate in stand-alone mode during 

outages. 

•	 For PV systems that are required to be nonexporting, batteries might store extra energy 

instead of cutting back production or installing a smaller PV system. 

Disadvantages: 

•	 Batteries are expensive and experience losses associated with charging and discharging. 

•	 Lead-acid batteries require significant maintenance. 

7 Per IEEE 1547-2003 4.2.6 [IEEE. Standard for Interconnecting Distributed Resources with Electric Power 

Systems. IEEE Std. 1547-2003. 2003. http://grouper.ieee.org/groups/scc21/1547/1547_index.html. Accessed 

October 3, 2009.] 

3-28
 
 

•	 Storage of batteries can be difficult. 

•	 Concerns about explosive gas and corrosive acids are significant. 

•	 Batteries have a limited life expectancy. 

Financial Considerations: 

For the PV system installer/owner 

•	 Inverters that also charge batteries typically cost more than standard inverters. 

•	 Battery storage containers, cables, monitors, and venting all add to the balance of system 

cost. 

•	 Batteries can reduce peak demand for commercial and industrial customers who pay a 

demand and energy component on their electric utility bill, with potential savings on 

monthly utility bills. 

•	 Battery systems last only a few years under normal conditions and replacing them adds 

substantial costs to the PV system. 

For the utility 

•	 Battery systems integrated with PV could flatten system demands, lowering costs and 

potentially lowering requirements for generation reserves (at higher levels of integration). 

•	 If significant levels of PV system penetration were attained in areas where the grid is 

congested, PV systems with batteries could be used to reduce grid congestion. This has 

the potential of reducing outages, deferring capital improvements, and lowering service 

calls. 

Impact of Solution: 

For area networks, PV systems with battery storage could flatten the load profile, which would 

benefit the utility. In addition, storage could be used to ensure that PV systems stay in a 

nonexporting mode. 

For spot networks, storage could be a viable option to keep PV systems nonexporting (batteries 

could charge when notified by an MIR). Batteries would also allow for an overall larger system, 

especially if customer load is unpredictable and minimum customer demand load is low. 

Location of Solution: Battery systems integrated with PV systems would typically be installed 

within a few feet of the PV system inverter. 

3-29
 
 

Smart Grid Issues: 

•	 Battery systems could be monitored and possibly dispatched manually or automatically 

when needed. 

•	 Sufficient quantities of battery storage on PV systems could have a positive impact on 

reserve requirements. 

Road Map: 

•	 Battery systems could be deployed in PV systems today because the inverter and battery 

technologies exist. 

•	 Depending on system need, peak-reducing battery systems would need to be dispatched 

based on a predefined schedule or through SCADA/AMI systems. 

•	 Smart grid equipment could be deployed that would charge batteries if there is 

insufficient load on the network. Conversely, batteries could be discharged during peak 

times. 

Figure 3-5 illustrates one example of how batteries might be applied. 13.2 kV 13.2 kV Feeder 1 Feeder 2

Feeder n 

120/208 Volt 

3-Phase Bus 

Spot/Area 

Network 

Con Edison 

AC 

Disconnect 

NP

NP 

13.2 kV 

NP 

Device 

Breaker 

Inverter/ 

Charger 

Main 

Disconnect 

Utility 

Metering 

PV Array 

LoadSensing 

CTs/PTs 

Battery 

Bank 

Load Sensors 

Control Battery 

Charge/Discharge 

± 

Figure 3-5. Hypothetical design of a secondary network with MIR and battery technology 

3-30
 
 

 

Remarks: 

•	 For grid-connected PV systems, batteries are currently very expensive. Adding one or 

two batteries, though, could improve overall system performance. 

•	 Batteries might also be available for emergency systems, traffic lights, and emergency 

radios, among other applications. 

•	 Battery power might also support smart grid components in the event of an outage by 

keeping information moving even if utility power is absent. 

•	 Using battery systems to perform multiple tasks will increase the value of the battery, 

thus improving the economics. 

3.2.8 PRO—Advanced Protective Schemes 

Description: Advanced protective schemes8 allow the customer to ensure proper operation of 

circuit breakers and other protective equipment during instances of equipment failures (when 

fault currents are present). Some PRO already exist and are in place for distributed generation 

systems; others are under development. 

Concerns Addressed: Fault current coordination issues 

Ranking of Solution: Fault current coordination issues—untested 

Penetration Level: PRO is an appropriate solution for low and medium levels of penetration. 

The equipment might need to incorporate smart grid controllability, especially at higher 

penetration levels. 

Advantages: 

•	 Although the technology exists today, much more development can be done to make 

these schemes technically and financially feasible (for customers and for the utility). 

•	 PRO technologies can be monitored by utility-owned SCADA systems. 

Disadvantages: 

•	 Systems might cost more to install, for both the customer and the utility. 

•	 In the case of transfer trip schemes, or other similar schemes in which protective devices 

communicate with other systems, there may be significant distances between the 

monitored equipment and the controlled equipment. Communications could be unreliable 

and might require upgrades. 

•	 Protective schemes might need to be evaluated and changed as the network changes (e.g., 

as new PV systems or new loads or both are added). 

8 Includes directional overcurrent tripping, blocking, and high speed transfer trip (HSTT), among others. 

3-31
 
 

 

 

 

 

 

 

 

Financial Considerations: 

For the PV system installer/owner 

•	 High Speed Transfer Trip (HSTT) might require system modification and new or
 

additional control equipment, which would increase PV system installation costs.
 

•	 The PV system could be forced offline and not produce energy on occasion, causing loss 

of energy production and revenue. 

•	 Cost of review of design and load data by the utility. 

For the utility 

•	 The utility incurs costs when the protective scheme equipment is monitored or inspected 

on regular intervals. Those costs are justified only if recovered through approval of the 

PSC. 

•	 If the installation and material costs of the advanced protective schemes are paid by the 

utility, those costs may be capitalized, if approved by the PSC. 

Impact of Solutions: 

Advanced protective schemes might prevent fault current from being injected into the system in 

the event of a fault. PV system fault current contribution is not considered problematic, however, 

because of the behavior of the inverters. Therefore, installing these advanced protective schemes 

for PV systems might have little effect on networks other than, perhaps, to add more equipment 

that requires maintenance, inspection, and adjustment. 

In addition, HSTT schemes may drop PV systems offline unnecessarily if not carefully installed 

and maintained. 

Location of Solution: 

•	 These devices reside on the distribution system and components can be installed at the 

substations, on the feeders, at network protectors, or at a customer’s service equipment or 

inverter location. 

•	 Some solutions will require components that are located at various points on the
 

distribution system, which will necessitate communications links among multiple
 

components. 

Smart Grid Issues: 

•	 Special protective devices might be monitored and or controlled by smart grid 

technology. 

•	 Smart grid-enabled devices might be programmed to change characteristics based on the 

status of the network during specific times of the day or particular seasons of the year. 

3-32
 
 

 

•	 Smart grid communications systems would likely be an important component in 

monitoring, operating, coordinating, programming, and maintaining protective
 

equipment.
 

Road Map: 

•	 The utility will continue to study fault current contribution from inverters and determine 

if they are a threat to the protective schemes. 

•	 If load flow studies conclude that advanced protective schemes are needed, and worth the 

financial expenditures, a list of viable schemes would be developed. 

•	 Viable protective schemes should be rolled out for PV systems over a specific size or at a 

specific penetration threshold. 

Figure 3-6 illustrates one example of how an HSTT scheme might be applied. 

Note: Signal to trip breaker can be initiated by, for example, network protectors or substation relays. 

Figure 3-6. Schematic of a secondary network with transfer trip protective scheme 

Remarks: Addition of new distributed generation systems on a network, as well as load changes, 

will affect advanced protective schemes. 

.

132 kV

. 

120/208 Volt 

3-Phase Bus 

Spot/Area 

Network 

Con Edison 

± 

AC 

Disconnect 

. 

Device 

Breaker 

Dynamically 

Controlled 

Inverter 

Main 

Disconnect 

Utility 

Metering 

PV Array 

LoadSensing 

CTs/PTs 

Substation 132 kV

132 kV 

Feeder 1

Feeder 2

Feeder n 

NP

NPNP 

3-33
 
 

 

 

 

 

 

 

 

3.2.9 OR—PV Array Orientation 

Description: PV panels can be oriented at different tilt angles (horizontal, vertical, or an angle in 

between) and different azimuths (facing east, south, west, or an angle in between). They can be 

fixed, or they can track the sun across the sky in one or two axes. Variations in tilt angle, 

azimuth, and tracking affect daily and seasonal output. 

Discussion: Tilt angle affects the PV system power production over the course of the year. 

Mounting systems with a tilt angle equal to the site’s latitude maximizes spring and fall power 

production. Increasing the tilt angle to a more vertical position increases production during the 

winter months, and decreasing the tilt angle to a more horizontal position increases production 

during the summer months (often the most desirable). 

Azimuth affects the PV system power production over the course of a day. South-facing systems 

produce the most power at midday. East-facing systems have better morning production, and 

west-facing systems have better afternoon production. Tracking systems have fairly steady 

production during all daylight hours. Tracking systems are more expensive than fixed systems, 

however, because they have higher installation and maintenance costs. 

PV systems are usually designed to minimize the cost per kilowatt-hour of energy by 

maximizing annual energy production while minimizing installation and maintenance costs. A 

PV array can also be designed to maximize power output during certain hours of the day and 

months of the year, but this may increase the cost per kilowatt-hour of energy. 

Concerns Addressed: 

•	 Power system planning—load profile change 

•	 Power system planning—generation dispatch impact 

Ranking of Solution: 

•	 Load profile changes—good at low penetration, untested at high penetration. These 

changes might help match the PV system power output to the load profile, but can shift 

the output only during daylight hours. Because customers will change their tilt and 

azimuth only with an incentive from the utility or if paid the higher market price of 

peaking power, we do not know whether this solution will be cost-effective in terms of 

overall grid performance. 

•	 Generation scheduling flexibility—untested. Modifying the power output hours will have 

limited effects on daytime power output from PV systems. 

Penetration Level: This solution could be incorporated in some PV systems (some PV arrays 

will have limited adjustability), and could have some impact at all levels of penetration. 

Advantages: 

• Several online tools can be used to determine the power output profile of a PV system 

based on tilt and azimuth. Models such as IMBY9 can inform the utility and the PV 

9 For more information on the IMBY (In My Backyard) tool, see http://www.nrel.gov/eis/imby/. 

3-34
 
 

 

system owner about the implications on system performance. Figures 3-7 through 3-11 

show an example of one system. 

•	 These angles can be adjusted in many cases to best fit the needs of the utility based on the 

average daily load profile. 

Disadvantages: 

•	 Adjusting tilt and azimuth of a PV array may be possible for some PV systems, but at a 

cost of reduced annual PV system energy production and increased balance of system 

cost. 

•	 Some systems do not have flexibility on the tilt and/or azimuth setting and must conform 

to the environment in which they are placed. Building-integrated PV (BIPV) systems 

generally have little flexibility with regard to panel orientation. 

Financial Considerations: 

For the PV system installer/owner 

•	 Many PV arrays can be adjusted to required or desired tilt and/or azimuth angles. The 

cost can be minimal or significant, depending on the situation. Each PV array must be 

evaluated for panel orientation flexibility. 

•	 Overall energy production will vary depending on the chosen angles. Loss of annual 

energy production might reduce the financial benefits of the PV system unless utility 

incentives were available. 

•	 Cost of review of design and load data by the utility. 

For the utility 

•	 Overall annual energy output might be lowered depending on the tilt and azimuth of the 

panels. If the utility adopts requirements for the PV system load shape, the utility might 

need to offer financial incentives to the PV system owner. 

•	 Time-of-day or time-of-year rates could cause PV system owners to adjust their systems 

to maximize their financial position, which could in turn create shifted load profiles. In 

this case, the utility might need to readjust its system resource mix. 

•	 Flattening of combined PV production output could be useful when committing 

generation reserves. 

•	 Cost of committing generation reserves might increase as PV system generation profiles 

change. 

•	 Time-of-day or time-of-year rates for PV systems might have a significant effect on the 

PV array orientation design, which may or may not benefit the utility. 

3-35
 
 

 

 

 

Impact of Solution: 

•	 Adjusting panel orientation—tilt, azimuth, or both—will change the PV energy 

production. Doing so can help shape the load profile of the customer and the secondary 

network. 

•	 Panels may be oriented to produce more power during summer months or they may be 

oriented to generate more power during spring and fall. 

•	 Panel orientation optimization can be encouraged by offering customers incentives to 

contribute power and energy during specific times of the day and/or specific months of 

the year. 

Location of Solution: This solution would be sited at the PV array. 

Smart Grid Issues: A smart grid system, capable of monitoring PV system power output, could 

be employed to track the system performance on one system or for an entire network. 

Examples: A model of a 4.2-MW (DC) PV system, located in Manhattan, was evaluated based 

on a summer-peaking tilt angle (0° flat) as well as a spring-fall peaking tilt angle (~45°). 

Additionally, the system was evaluated for morning-peaking azimuth angle (90°) and an 

evening-peaking azimuth angle (270°). Figures 3-7 through 3-11 illustrate the results. 

•	 Figure 3-7 is an example of an array installed tilted 41° with an azimuth of 180° 

(southern orientation for optimal annual production).
 

•	 Figure 3-8 is an example of an array installed tilted 41° with an azimuth of 90° (easterly 

orientation for enhanced morning power production). 

•	 Figure 3-9 is an example of an array installed tilted 41° toward the south with an azimuth 

of 270° (westerly orientation for enhanced afternoon power production). 

•	 Figure 3-10 is an example of an array installed with 0° tilt (flat array installation) for 

maximized power production during summer months. 

•	 Figure 3-11 is an example of an array installed with 45° tilt (toward due south) for 

maximized power production during spring and fall months. 

3-36
 
 

 

 

Figure 3-7. IMBY/PVWatts results for 41° tilt and 180° azimuth (typical system profile for flat panel 

installation) 

Figure 3-8. IMBY/PVWatts results for 41° tilt and 90° azimuth (panels adjusted for morning peak) 

Figure 3-9. IMBY/PVWatts results for 41° tilt and 270° azimuth (panels adjusted for afternoon peak) 

3-37
 
 

 

 

 

 

Figure 3-10. IMBY/PVWatts annual hourly PV simulation profile for 0° tilt (note the peak in 

spring/summer) 

Figure 3-11. IMBY/PVWatts annual hourly PV simulation profile for a south-facing array with a 45° 

tilt (note higher output in spring and fall months) 

Road Map: 

•	 Future PV system installations might be considered for modified panel orientation by 

offering PV system owners incentives to increase power production during specific times 

of the day and the year. 

•	 Financial models will need to be developed and tariffs evaluated in order to encourage 

PV system owners (with incentives) to orient their arrays in a manner that best meets the 

generation needs of the utility. 

Remarks: 

•	 PV systems that track the sun will produce the most power and energy over the course of 

a year, but tracking systems for rooftop design are expensive and may not be practical. 

Most rooftop systems are designed and installed with a fixed tilt and azimuth, and can 

often be installed with the panels oriented for greater power production during time 

intervals chosen by the system installer or with input from the utility. 

3-38
 
•	 Networks with low penetration potential would not see a significant change in their load 

profile based on PV system installations, and modifications to panel orientation would 

have little effect. The utility may choose, however, to work with PV system owners to 

modify panel design orientation regardless of their location. 

3-39
 
 

4.0 Utility Application Process Review
 

As applications for distributed generation systems (like photovoltaic [PV] installations) 

increase nationwide, public utilities are facing mounting delays in the application 

process. This section describes surveys conducted on the interconnection processes of 

U.S. utilities that are connecting distributed generation systems to networks. It also 

identifies ways in which utilities could streamline the application process. 

Recommendations from this review include making application documentation available 

on the utility’s Web site; establishing an online tracking system to inform the 

contractor/homeowner about the status of an application; creating qualified equipment 

and contractor lists; removing application fees; and offering training and outreach 

programs to contractors and homeowners. 

4-1
 
 

Contents 

4.1 Overview............................................................................................................................... 3
 

4.1.1 Application Distribution Process ............................................................................... 3
 

4.1.2 Tracking System Requirements ................................................................................. 3
 

4.1.3 General Application Review Process......................................................................... 4
 

4.1.4 Requirements for a Full Utility Engineering Study ................................................... 4
 

4.1.5 Inspection and Verification Test Requirements......................................................... 4
 

4.1.6 Outreach Education Program and Training ............................................................... 5
 

4.2 New York State Application Process.................................................................................... 5
 

4.2.1 Discussion of Proposed Application Process............................................................. 6
 

4.3 Summary of Recommended Practices .................................................................................. 7
 

Appendix 4-A: List of Questions on Application Process.......................................................... 8
 

Appendix 4-B: Web-Site Survey ................................................................................................ 9
 

Appendix 4-C: Verification Test Requirements (National Grid) .............................................
 

4-2
 
 

4.1 Overview 

To heighten the efficiency of the application process for distributed generation systems 

like PV, the New York Solar America City Program partnered with the U.S. Department 

of Energy’s (DOE) National Renewable Energy Laboratory (NREL) to conduct a survey 

of public utilities around the country. The survey—conducted for New York City’s 

utility, Con Edison—explored ways to streamline the application process without 

sacrificing the quality of PV system installations. The NREL team conducted phone 

interviews with various utility companies to discuss their application review process. The 

six utilities surveyed by phone were Seattle City Light, Xcel Energy, Pacific Gas & 

Electric (PG&E), Sacramento Municipal Utility District (SMUD), National Grid, and 

Public Service Enterprise Group (PSEG). The survey questions (contained in Appendix 

4-A) focused on the following areas of the review process: 

• Application distribution process (Web-based or mail) 

• Tracking system requirements 

• General application review process 

• Requirements for a full utility engineering study 

• Inspection and/or verification requirements 

• Outreach education program and training. 

We also reviewed ten utility Web sites, and the Excel spreadsheet in Appendix 4-B gives 

additional information we gleaned from these reviews. 

In the subsections that follow, we briefly summarize the interviews for each area of the 

survey. 

4.1.1 Application Distribution Process 

We learned that, for the most part, applications are distributed via the utility’s Web site. 

At the time of the interviews and the Web site review, SMUD was the only utility with 

mail-in applications. As of June 8, 2009, however, SMUD’s applications became 

available online. The applications are generally categorized by the size of the distributed 

generation system rather than the type. All six utilities surveyed indicated that most 

applications are for residential installations sized at <10 kW. 

4.1.2 Tracking System Requirements 

Xcel Energy was the only utility company surveyed that tracked applications online. 

Xcel’s application process is done entirely through the Web, e-mail, and fax. The 

applications are all online and can be filed by either the homeowner or the contractor 

installing the system. Once the application is approved, the applicant receives an e-mail 

outlining the next step in the application process. All the steps in the application review 

process are dated and tracked in Xcel’s online database. Other utilities we interviewed 

designate a representative as an applicant’s point of contact. 

4-3
 
 

 

 

 

4.1.3 General Application Review Process 

Once the applicant fills out the application, it is sent—along with a one-line diagram and 

a list of equipment—to the utility for review. If the application is for a single-phase 

system sized below 15 to 30 kW, there is no major review. For large, three-phase, 480-V 

systems, though, the application process requires review and approval by a licensed 

electrical professional engineer. Both Xcel Energy and PG&E reported that about 90% of 

all their net energy metering (NEM) projects are sized below 10 kW. In the majority of 

utilities surveyed, applications for small PV systems (<10 kW) are reviewed by the 

“office specialist” and the one-line drawings are generally reviewed by an engineer. 

Applications using equipment from an approved list (certified by a qualified independent 

testing laboratory) will move through the system more quickly. Certified equipment lists 

are located on the New York State Web site at http://www.dps.state.ny.us/distgen.htm 

and the Go Solar California Web site at 

http://www.gosolarcalifornia.ca.gov/equipment/index.html. The California state Web site 

also has a list of certified contractors at 

http://www.gosolarcalifornia.ca.gov/retailers/search-new.php. To be listed on this Web 

site, California requires that the contractor have a C10 (EE license) or a C45 (solar 

license). Contractors must also supply references along with a minimum of five PV 

systems they have installed previously. 

Once the application is approved, the utility company or the city electrical inspection 

(permitting) office schedules an inspection of the PV system. After the inspection is 

signed off, the interconnection can take place with the installation of an advanced net 

meter. Some utilities, including SMUD and Xcel, are then required to send out the 

rebates within 30 days. 

4.1.4 Requirements for a Full Utility Engineering Study 

We found that utilities typically approve PV systems without a full utility engineering 

study when the aggregate generation is below 10 to 50 kW on a single-phase branch of a 

distribution circuit, or if the aggregate generation is below 150 kW on a single threephase distribution feeder. 

4.1.5 Inspection and Verification Test Requirements 

In general, the utilities surveyed require that a qualified individual perform a verification 

test on the initial parallel operation of a generating system. Qualified individuals include 

professional engineers or certified technicians and licensed electricians with experience 

in testing protective equipment. The test requires removing power to the inverter, and 

then visually checking the inverter to ensure it is not producing energy. Voltage may be 

removed by one of the following methods, as approved by the utility: 1) opening the AC 

disconnect (if present); 2) opening the main disconnect; 3) opening the circuit breaker 

tied to the inverter output; or 4) removing the fuse tied to the inverter output. More 

formal test plans for complex systems are determined on a case-by-case basis. 

The utility usually reserves the right to witness verification testing or to require written 

certification that the testing was successfully performed. Xcel Energy requires only that 

the city electrical permit be issued before it places a net meter on the system. Xcel does 

not inspect any of its systems, relying solely on the city’s permitting process. 

4-4
 
 

 

 

 

 

 

 

4.1.6 Outreach and Education Programs and Training 

Our review of the ten utility Web sites indicated that many of the utilities have posted 

documentation online, including a wide range of educational resources for contractors, 

homeowners, and design professionals. SMUD and National Grid indicated that they hold 

advanced training sessions for contractors once or twice a year. They hire a company to 

present advanced design and installation workshops. They also hold a workshop four 

times a year called “PV for Homeowners.” Our utility Web site review also showed that 

many utilities have an FAQ section to help their customers with common problems. 

4.2 New York State Application Process 

The New York State Standardized Interconnection Requirements (SIRs) and the 

application process for new distributed generators of 2 MW or less were updated in 

February 2009 by the New York State Public Service Commission.1 There are two 

distinct application processes—one for distributed generation systems of 25 kW or less 

and an additional process for systems >25 kW and <2 MW. 

Using the updated application standard requirements and the information from our 

survey, we constructed a detailed outline of recommended practices. Table 4-1 reviews 

the application process and recommends practices that might help streamline the process. 

We discuss these recommendations in Section 4.2.1, referencing the processes from the 

utilities surveyed. 

Table 4-1. Recommended Practices 

New York State Application Process (<25 kW) Recommended Practice 

Step 1: Initial communication from the potential	 Customer makes initial contact through an online 

applicant	 tracking system. Customer inquiry takes place 

primarily through documentation on the utility’s 

Web site. 

Step 2: Utility review of the inquiry to determine Customer files formal application online. The 

project’s nature utility’s online tracking system contains links to all 

documents, which include 

1. Letter of authorization from the customer 

2. Standard one-page application form 

3. One-line diagram with manufacturer model 

number 

4. Verification test (see Appendix 4-C) to 

ensure that SIRs are met. 

Step 3: Applicant files formal application Utility’s office specialist conducts a review of the 

application. Engineering group reviews the oneline diagram. 

Step 4: PV system installed	 The local inspection authority that handles the 

permits should inspect the PV system. 

1 New York State Public Service Commission, New York State Standardized Interconnection Requirements 

and Application Process for New Distributed Generators 2 MW or Less Connected in Parallel with Utility 

Distribution System, February 2009. http://www.dps.state.ny.us/Final_SIR_02-12-09_Clean.pdf. Accessed 

October 8, 2009. 

4-5
 
 

 

 

 

 

 

New York State Application Process (<25 kW) Recommended Practice 

Step 5: Applicant’s system tested in accordance with 

the SIR. Verification testing must be performed at least 

once every four years. 

Step 6: Final acceptance and company cost 

reconciliation 

The utility should reserve the right to witness 

verification testing or require written certification 

that the testing was successfully performed. 

Rebates and incentives are handled under the 

state solar incentive program, separately from the 

utility’s interconnection process. 

4.2.1 Discussion of Proposed Application Process 

Step 1: We recommend implementing an online tracking system similar to the one 

Frontier Associates2 developed for Xcel Energy. The user-friendly tracking system 

allows all the application steps to be done online, and all forms are available on the Web 

site. Customers can follow their applications through the entire process, and e-mail 

messages update the customer on the next step. According to the New York SIRs, the 

utility Web site is required to give applicants with systems 25 kW and below the ability 

to submit their application for interconnection via the Web. The Web-based application 

process must include the ability to attach associated documentation or drawings 

associated with each project. 

Step 2: The main part of the application is submitted in this step. A complete application 

package consists of a signed letter of authorization by the customer (the customer can 

scan or fax the signed document, or use the electronic signature feature available in some 

programs). The completed standard application should be submitted with a one-line 

diagram, and the drawing should contain the manufacturer’s model number for the PV 

panels and inverter. The equipment must be Underwriters Laboratories (UL)-certified, 

and should also be listed as standard equipment on the list on New York State’s Web site. 

If the application design meets the SIRs, the application is approved and the tracking 

system sends out an e-mail message that indicates approval and date of approval. Note 

that the utility can require the installer to carry out a verification test procedure. 

Step 3: The utility’s nontechnical person should be responsible for reviewing the 

application to ensure that all the forms are filled out and that the equipment specified in 

the design is on the certified equipment list. An engineer should review the one-line 

diagram. The nontechnical preliminary review of the application and design should help 

reduce the engineer’s review time. 

Step 4: The system is installed and tested. Inverter-based systems are allowed to 

interconnect to the utility system for no more than two hours for verification testing. The 

utility can either dispatch a witness to the verification test or simply request written 

certification that the system was installed and tested in compliance with the SIRs. 

2 Frontier Associates LLC. http://www.frontierassoc.com/about.html. Accessed September 15, 2009. 

4-6
 
 

 

 

 

Step 5: According to the New York SIRs, the single-phase inverters and inverter systems 

rated 25 kW and below must be verified on initial parallel operation and then once every 

four years. The homeowner must interrupt the utility source and verify that the equipment 

automatically disconnects and does not reconnect for at least 5 minutes after the utility 

source is reconnected. The owner should maintain the log and results from testing for 

inspection by the utility. National Grid provided an example of a verification test (see 

Appendix 4-C). 

Step 6: Once the interconnection has been verified, the utility should finalize acceptance 

and do its company cost reconciliation promptly. Rebates and incentives should be 

handled under the state solar incentive program and separate from the utility’s 

interconnection process. Currently, the New York State Energy Research and 

Development Authority (NYSERDA) handles the rebates. 

4.3 Summary of Recommended Practices 

As detailed earlier in this section, the survey brought to light some recommended 

practices that might help speed up the application process: 

•	 Make applications documentation available on the utility’s Web site. 

•	 Institute an online tracking system to inform customers about the status of their 

applications. 

•	 Post a qualified equipment list for PV modules and inverters. 

•	 Post a qualified contractor list and make sure that contractors meet the
 

certification requirements that qualify them to be on the list. 

•	 Offer training and outreach programs for both contractors and homeowners. 

These help to build awareness of the application process and should improve the 

quality of the applications submitted. 

4-7
 
 

 

 

Appendix 4-A: List of Questions on Application Process 

Here is a list of general interconnection questions for utilities approving PV systems. 

1.	 Does your company install distributed generation systems by size and type? Are 

there different processes for PV installations versus other distributed generation 

installations? 

2.	 How long does it take an application for PV installation to move through your 

system today compared to when you were first approving new systems? If the 

process is faster, what do you attribute that to? 

3.	 Does your company have all documents (applications, procedures, guidelines) 

available online? Is this a change from your first installations? 

4.	 What types of PV systems are approved without any full utility engineering 

studies? How is this different from a few years ago? 

5.	 Does your company inspect all systems that are installed? If you do an inspection, 

what does it consist of? What test do you run on an installation or is it just a 

visual check? 

6.	 If some systems are not inspected, is this because of the experience you have had 

with other installations? 

7.	 What equipment has a fast-track process? 

8.	 What procedures have been streamlined since PV systems were first being 

installed? If they were streamlined, how?
 

9.	 Have these streamlined processes been successful? Have they 

A. Reduced the time to install a system? 

B. Reduced the cost to the customer and/or your utility? 

C. Improved time spent by the utility engineers? 

D. Revised the processes more than once? 

10. Does your company have an online tracking process in place? If not, how does a 

customer determine the status of their installation? 

11. Do you have outreach education for your communities? Do you mainly target 

installers/developers or customers? 

4-8
 
Appendix 4-B: Web-Site Survey 

4-9
 
 

Utility 

Sempra includes 

San Diego Gas & Electric (SDG&E) and 

Southern California Gas Company 

Pacific Gas & Electric (PG&E) Xcel Energy Sacramento Municipal

 Utility District (SMUD) Seattle City Light (SCL) 

Web Site http://www.sdge.com/business/netMetering.shtml http://www.pge.com/myhome/saveenergymoney/solaren 

ergy/ 

http://www.xcelenergy.com/XLWEB/CDA/0,3080,1-1-

2_735_25709-23075-2_424_756-0,00.html 

http://www.smud.org/community-environment/solar/ http://www.seattle.gov/light/Conserve/cgen/ 

Location California California Colorado California Washington State 

Point of Contact Ken Parks 

San Diego Gas & Electric 

8316 Century Park Ct, CP52F 

San Diego, CA 92123-1582 

kparks@semprautilities.com 

Phone: 858-636-5581 

Mark O'Leary 

Net Energy Metering (NEM) Supervising Project 

Manager 

PG&E, Generation Interconnection Services 

245 Market Street, Room 776 

San Francisco, CA 94105 

Phone: 415-972-5265 

Fax: 415-973-3064 

Pam Newell 

Phone: 507-457-1249 

pamela.j.newell@xcelenergy.com 

Hector Ortiz 

Energy Specialist II 

Residential/Commercial Solar PV 

Phone: 916-732-6882 

Jack Brautigam 

Renewables Program Manager 

Seattle City Light 

700 Fifth Avenue, Suite 3200 

P.O. Box 34023 

Seattle, WA 98124-4023 

Phone: 206-684-3954 

jack.brautigam@seattle.gov 

State Tiers <10 kW. <10 kW. <10 kW. <10 kW <300 kW. 

10 kW–10 MW. 10 kW–10 MW. 10 kW–2 MW. 10 kW–10 MW. 300 kW–2 MW. 

Utility Tiers <30 kW. <30 kW. 0.5–10 kW. None specified. <100 kW. 

30 kW–1 MW. 30 kW–1 MW. 10 kW–100 kW. >100 kW. 

100 kW–1 MW. 

PV System Connection Requirements: Utility Tier 1 

Size Limit <30 kW. <30 kW. 0.5–10 kW. None specified. <100 kW. 

Application Fee None. None. None. None. $100 

Application Three pages. Requires name and contact info for owner 

and contractor, along with description of solar panels, 

inverter/controller, disconnect, and any other customer 

generation system. 

Eight-page combined application and interconnection 

agreement. Requires contact information for owner and 

contractor, insurance information, rate selection, and a 

description of the generating facility (including solar 

panels, inverters, and disconnects). 

Online application requires contact info for owner and 

contractor, along with description of system including 

PV panel manufacturer and model, nameplate capacity, 

azimuth/orientation, tilt angle, tracking system, singleor three-phase electrical service, and inverter 

manufacturer and model. 

Ten-page application requires contact information and 

generating system information. Available online but 

must be submitted by mail. 

Six-page combined application and interconnection 

agreement requires contact information and generating 

system information. Separate two-page application for 

electric service required to request a production meter if 

applying for the Washington State Renewable Energy 

Production Incentive. SCL electrical service 

representatives available to visit customer's property to 

review submitted forms and system design. 

Interconnection Agreement Eight pages. Agreement must be signed. Agreement 

summarizes generating facility, interconnection and 

design requirements, metering and billing, 

disconnection, interruption or reduction of deliveries, 

access to premises, indemnity and liability, and 

insurance. 

Included in application. Fifteen pages. Requires a signed agreement that outlines 

the terms for connecting the PV installation to the utility 

grid. 

Two agreements: Electrical Interconnection Agreement 

and Net Metering Agreement. 

Included in application. 

Electrical Diagram One-line diagram (one page). The general arrangement 

and relationship of the system components and the make 

and model of each component must be shown. 

One-line diagram (one page). Diagram must show the 

installation of the generating facility. Must include the 

electrical rating and operating voltages of the significant 

electrical components, the general location of the 

customer's loads relative to the generating facility, and 

the interconnection with PG&E's distribution system. A 

description of each component, including manufacturer 

name, model number, and rating, is also required. 

A one-page installation diagram must show the 

arrangement of system components. 

One-line electrical diagram (one page). One-line electrical diagram (one page). 

Description of Materials Requires bill of materials with item description, vendor, 

part number, and quantity. 

Included in electrical diagram. Requires serial numbers of the PV panels and inverters 

to verify that the equipment is new. 

Included in application and electrical diagram. Inverter specification sheet required, also with 

production meter socket installation. 

AC Disconnect A visible, open, lockable disconnect must be installed 

adjacent to electric service panel. Brand name and model 

number must be given to the utility. 

Requires a description and location of visible, lockable 

AC disconnect switch if present. Switch is required only 

for inverter-based interconnections having a transformerrated meter or noninverter- based generators. 

An AC disconnect is not required for <10 kW. Not specified. Requires a UL-approved safety disconnect switch. This 

requirement may be waived if interconnection equipment 

physically disconnects generating equipment supply 

internally, and applicant agrees that service may be 

disconnected entirely if generating equipment must be 

disconnected for any reason. 

4-10
Utility 

Sempra includes 

San Diego Gas & Electric (SDG&E) and 

Southern California Gas Company 

Pacific Gas & Electric (PG&E) Xcel Energy Sacramento Municipal

 Utility District (SMUD) Seattle City Light (SCL) 

City Permits & Inspections Permitting agency must notify utility that PV system is 

approved. 

Requires final signed copy of building permit for PV 

system. 

Requires documentation of all necessary 

town/municipal/county inspections. 

Provide final signed building permit. Requires electrical permit. Other permits may be 

required by the city. 

Utility Inspections SDG&E completes utility inspection. Not specified. Not specified. Not specified. SCL performs final inspection to ensure meter socket 

and meter location are acceptable. Production meter 

installed after this inspection. 

Additional Fees None. Fee to install bidirectional meter for customers that don't 

currently have one is $228. 

None. None. If applying for Washington State Renewable Energy 

Production Incentive, $47 for production meter. 

Insurance Requires information on any existing insurance 

coverage. 

Requires information on any existing insurance coverage Requires proof of $300,000 minimum liability 

insurance. 

Not specified. No additional insurance required. 

Incentives & Rebates Applicants apply for rebates through the state's 

California Solar Initiative program: 

http://www.gosolarcalifornia.ca.gov/csi/apply.html. 

Applicants apply for rebates through the California Solar 

Initiative state program, separate from the utility. 

Utility provides acknowledgment letter and customer 

contract for signature. Summarizes the system 

specifications and provides documentation of the 

estimated rebate and renewable energy credit (REC) 

payment. 

Self-installers applying for a rebate must turn in a 

reservation/payment form, signed disclaimer, and system 

drawing or roof photo showing proposed module layout. 

Contractors/installers applying for a rebate must supply 

the items listed for self-installers applying for a rebate, 

as well as a copy of the contractor/customer contract, 

contractor's contract attachment exhibit A, shade 

analysis/report, rebate calculation, and system 

certification. 

Before an incentive check can be issued, a renewable 

energy cost recovery certification form and an annual 

incentive payment application must be completed. 

Additional Requirements Signs must be installed on the AC disconnect and on the 

customer's electric service panel. These indicate that 

customer has a secondary power source and identifies 

the utility disconnect. 

A copy of a recent electric bill for the project site is 

required to verify that the customer has an account at the 

project site. 

A copy of the invoice is required to show actual 

installation costs. 

Inspections are done on all applications. None. 

Recommended Equipment or Installers Does not recommend specific contractors or equipment 

suppliers. Makes available a "Consumers Guide to PV," 

which contains recommended questions to ask a 

potential PV installer. 

Does not recommend specific contractors or equipment 

suppliers. Suggests using www.findsolar.com to find an 

installer. 

Does not recommend installers, but recommends using 

the yellow pages, Colorado Solar Energy Industries 

Association, Find Solar, or North American Board of 

Certified Energy Practitioners to find one. Provides link 

to California Energy Commission's Web site for list of 

eligible equipment. 

Does not recommend specific equipment. Provides a list 

of contractors who have agreed to install equipment 

according to SMUD specifications. These contractors 

must be C10 (EE license) or C46 (Solar license) and 

have installed at least five solar projects. 

Does not recommend installers or specific equipment. 

Provides guide on questions to ask when interviewing 

potential installers. 

Web Site Ease of Use Residential PV connection information is not 

immediately obvious online. "Going Green" link on 

home page does not lead to solar program. User must go 

through "Environment" link. Requires five links total 

from utility home page. Once found, Web site clearly 

describes process for interconnection and required 

documents. 

Residential PV connection information is not 

immediately obvious online. Home page features several 

links to energy efficiency programs, but you must go 

through an "Environment" link, which takes you to 

"What you can do" to find solar program information. 

Requires seven links total from utility home page. Once 

found, Web site gives clear list of required application 

components and application process time line. 

Easy to find Residential PV connection information. 

Clear link to "Renewable Energy" under residential 

menu on home page. Requires two links total from home 

page. Process is clearly outlined. Online application can 

only be submitted online (i.e. it cannot be printed out 

and sent in). 

Residential PV connection information is easy to find 

(two clicks from homepage under Community & 

Environment/Solar), but very little information is 

provided on Web site. There is general information 

about PV systems and a list of recommended installers, 

but no application or description of process for 

connecting. No contact person is given for more 

information. 

Residential PV connection information is not 

immediately obvious. Found under Residential/ 

Customer Generation. Requires two links total from 

home page. Once found, Web site clearly outlines 

interconnection process and provides all required 

documents. 

Additional PV System Connection Requirements: Utility Tier 2 

Tier 30 kW–1 MW. 30 kW–1 MW. 10 kW–100 kW. Not applicable (no tiers). >100 kW. 

Application Fee None. $800 None. Not applicable. Information on tier 2 systems unavailable online. 

Additional Application Forms & Agreements More extensive 12-page application. More extensive 12-page main application. SO_REC contract: Agreement regarding energy 

production from PV system and the sale of the 

associated Renewable Energy Credits (RECs) to utility. 

Not applicable. Information on tier 2 systems unavailable online. 

Supplemental application: Provides alternating current 

disconnect information and notifies PG&E of potential 

access issues. 

Security Fund declaration (required for SO_REC 

contract). 

Interconnection Agreement (now separate from main 

application). 

Small Generator Interconnection Agreement. 

4-11
 

Utility 

Sempra includes 

San Diego Gas & Electric (SDG&E) and 

Southern California Gas Company 

Pacific Gas & Electric (PG&E) Xcel Energy Sacramento Municipal

 Utility District (SMUD) Seattle City Light (SCL) 

Net Energy Metering Agreement Form. Sale of Electricity Letter (third party developers only). 

Third Party Authorization (required only if a third party--

usually the contractor-- handles the application process) 

Additional System Information Site plans and diagrams showing the physical 

relationship of the significant electrical components. 

Site plans and diagrams showing the physical 

relationship of the significant electrical components. 

Site Diagram. Not applicable. Information on tier 2 systems unavailable online. 

Transformer information (if used). Transformer information (if used). 

Transfer switch description (if used). Transfer switch description (if used). 

Protective relay description/ diagrams (if used). Protective relay description/ diagrams (if used). 

Additional Insurance Information None. Declarations page of home owner insurance. Proof of insurance and indication that Xcel Energy is 

listed as co-insured 

Not applicable. Information on tier 2 systems unavailable online. 

Additional inspections None specified. PG&E will conduct inspection. None specified. Not applicable. Information on tier 2 systems unavailable online. 

4-12
 

Utility 

NSTAR Entergy Con Edison Public Service 

Enterprise Group (PSE&G) 

Web Site http://www.nstar.com/business/interconnections/ http://www.entergyneworleans.com/your_home/net_metering.aspx http://apps.coned.com/dg/applications/applications.asp http://www.pseg.com/customer/solar/process1.jsp 

Location Boston, Massachusetts Arkansas, Louisiana, Mississippi & Texas New York New Jersey 

Point of Contact Jan Gudell 

Program Manager 

Phone: 781-441-8366 

Fax: 781-441-8721 

jan.gudell@nstar.com 

Joe Feraci 

Senior Engineer 

Phone: 781-441-8196 

Fax: 781-441-8721 

joseph.feraci@nstar.com 

Entergy New Orleans, Inc. 

Customer Relations, Net Metering 

P.O. Box 61000/LMAG-44 

New Orleans, LA 70161-1000 

1-800-368-3749 

Margarett Jolly 

DG Ombudsman 

jollym@coned.com 

212-460-3328 

Don Cooke 

Distribution Team Leader, New Business 

PSE&G Electric Delivery Asset Management 

80 Park Plaza, T12 

Newark, NJ 07102 

Phone: 973-430-7419 

Mobile: 973-390-7026 

Fax: 973-621-8410 

Donald.Cooke@pseg.com 

State Tiers <10 kW one-phase or <25 kW three-phase. <25 kW residential, <100 kW commercial. <15 kW. <100 kW. 

>10 kW one-phase or >25 kW three-phase 15 kW–2 MW. >100 kW–2 MW. 

Utility Tiers <10 kW one-phase or <25 kW three-phase. <25 kW residential, <100 kW commercial. <10 kW with net metering or <15 kW without net 

metering. 

<10 kW single-phase or <25 kW three-phase. 

>10 kW one-phase or >25 kW three-phase. No other tiers. 15 kW–2 MW. 

2 MW–20 MW. 

PV System Connection Requirements: Utility Tier 1 

Size Limit <10 kW one-phase or <25 kW three-phase. <25 kW residential, <100 kW commercial. <10 kW with net metering or <15 kW with no net 

metering. 

<100 kW. 

Application Fee None. None A $350 fee is refunded to net metering customers unless 

applied to transformer. 

$10 per installed kilowatt up to a maximum fee of 

$2,500 per application. 

Application Six-page combined application and interconnection 

agreement. Requires contact information, generating 

facility information, and inverter UL1741 listing 

information. 

Four-page application requires contact information and 

generating facility information. 

One-page application. Additional addendum application 

(five pages) required for configurations that do not 

qualify for net metering. Must attach protection 

schematics and generator control description to 

addendum application. 

Three page application requires contact information, 

system information, and contractor information. 

Interconnection Agreement Included in application. Six-page interconnection agreement. Six-page New York State Public Service Commission 

Standardized Interconnection Agreement. Requires copies of project design documents; project 

operation and maintenance plan, including warranty 

documents; and all documents/agreements between 

applicant and solar developer. 

Electrical Diagram Not specified. One-line electrical diagram One-line electrical drawing. Wiring and schematic 

drawings sealed by a licensed professional engineer in 

New York State. 

Project design documents including one-line electrical 

diagram. 

Description of Materials Not required. Not required. List of all interconnection devices; must provide specs 

for this equipment upon utility request. 

Copies of the manufacturer's specification sheets for the 

equipment comprising the project. 

AC Disconnect NSTAR may require an external disconnect switch. AC disconnect required. External disconnect switch required. All generating equipment must be capable of being 

isolated from PSE&G system by means of an external, 

manual, visible, gang-operated, load breaker (except for 

systems of <10 kW). 

4-13
Utility 

NSTAR Entergy Con Edison Public Service 

Enterprise Group (PSE&G) 

City Permits & Inspections Inspection required Inspection required. Not specified. Electric inspection required. 

Utility Inspections NSTAR may perform inspection and witness test. Although Entergy is not required to perform an 

inspection, the company reserves the right to do so. 

Owner will verify load break disconnect switch 

operation once per year, and maintain a log of these 

operations for inspection by connecting utility. 

PSE&G completes a wiring inspection of all 

installations. 

Additional Fees None. Meter installation costs $50. Up to $350 if dedicated transformer is required. None. 

Insurance No insurance required. Not specified. No insurance required. Not specified. 

Incentives & Rebates No information given. No information provided. Information supplied for more than 11 incentive 

programs. 

New Jersey solar loan program. 

Additional Requirements None. A relay system drawing is required. Installation test plan. If not tested, requires total system 

and individual equipment product literature. 

Installation test plan. If not tested, requires total system 

and individual equipment product literature. 

List of proposed relay functions with a table of their 

planned settings and the intended purpose of each 

function. 

Descriptions of all protection devices and accessories, 

and protection design drawings. 

Expected power factor of proposed generator and plan 

for maintaining adequate power factor within SIR limits. 

Method of dynamic control for regulation of VARs and 

power output of the generating unit. 

Operating instructions for parallel operation detailing 

normal and emergency start-up and shut-down 

procedures. 

Discussion of intended modes of operation of the 

generation plant. 

Recommended Equipment or Installers Does not recommend equipment or installers. Does not recommend equipment or installers. It is recommended that inverter equipment be selected 

from the “Certified Equipment” list maintained by the 

New York Public Service Commission. No installers 

recommended. 

Provides a link to installers and equipment 

manufacturers on NJ's Clean Energy Program website. 

Web Site Ease of Use Difficult to find information. Residential PV connection 

information is listed under "business/interconnections." 

Once found, interconnection process is clearly outlined 

and all application documents are available on Web site. 

Easy to find information. Requires one link from home 

page to "myhome/net metering." Although information 

is limited, it appears that all required documents are 

available on the Web site. No connection time line is 

provided. 

Residential PV connection information not immediately 

obvious. Found under "business center/distributed 

generation" link on home page. Requires one link from 

home page. Once found, extensive information is 

available, although figuring out which processes and 

incentives apply to which systems is somewhat 

confusing. 

Easy to find information. Requires two links from home 

page. All required documents are available on the Web 

site. No connection time line given. 

Additional PV System Connection Requirements: Utility Tier 2 

Tier >10 kW one-phase or >25 kW three-phase. Not applicable (only one tier). 15 kW–2 MW. >100 kW–2 MW. 

Application Fee $3/kW (minimum $300, maximum $2500). Not applicable. $350, nonrefundable. $500 

Additional Application Forms & Agreements More extensive seven-page application and thirteen-page 

interconnection agreement. 

Not applicable. Two-page main application and five-page addendum 

application. Must attach protection schematics and 

generator control description to addendum application. 

Three-page application including size of unit as 

percentage of facility normal load and peak load and 

plan for excess power. 

Qualified facility (QF) certificate from Federal Energy 

Regulatory Commission (FERC). 

Must reimburse utility for the cost of the preliminary 

review, Coordinated Electric System Interconnection 

Review (CESIR), any required modifications to utility 

system, administration, metering, and verification 

testing. 

4-14
 

 

 

 

 

 

 

 

 

 

 

Utility 

NSTAR Entergy Con Edison Public Service 

Enterprise Group (PSE&G) 

Additional System Information Electrical one-line diagram. Not applicable. Written verification test procedure. If exporting and selling excess DG capacity outside of 

the Local Distribution Circuit, need to file aplication and 

secure permission from Pennsylvania-New JerseyMaryland (PKM) Interconnection High Voltage 

Transmission System. 

Physical location map. Electrical studies as requested by the utility for 300 

Relay protection scheme. kW–2 MW systems. 

Copy of user manual for each distributed generation 

device. 

Certified test reports for protection devices. 

Exterior lockable disconnect switch required. 

Additional Insurance Information $500,000 to $5,000,000 general liability insurance Not applicable. None required. None specified. 

required, depending on size of system. Insurance 

certificate required to show NSTAR as the insured. 

Additional inspections NSTAR will witness initial inspection and start-up Not applicable. Verification test must be performed by qualified None specified. 

testing; periodic testing of protective functions. individual; utility reserves right to witness verification 

testing or require written certification that testing was 

successfully performed. 

4-15
Appendix 4-C: Verification Test Requirements (National 

Grid) 

4-16 
4-17
 

 

 

 

 

 

 

 

5.0 Conclusion
 

To help accelerate the widespread implementation of solar energy in the United States, the U.S. 

Department of Energy (DOE) has teamed with cities around the country through its Solar 

America Cities (SAC) partnership program. New York City’s team is working with DOE’s 

National Renewable Energy Laboratory (NREL) and the city’s utility, Con Edison, to develop a 

roadmap for photovoltaic (PV) installations in the five boroughs. City leaders set a goal to 

increase the installed PV capacity in New York City from 1.1 MW in 2005 to 8.1 MW by 2015 

(the maximum allowed in 2005). The complexity of the interconnection process with the local 

utility, though, presents unique challenges that must be addressed if the city’s goals are to be 

met. 

Although most areas of the country use simpler radial distribution systems—where each 

customer receives power through a single line—to distribute electricity, larger metropolitan areas 

typically use secondary network distribution systems (simplified to “networks” in this report) to 

increase reliability in large load centers. Networks deliver power to each customer through 

several parallel circuits and sources, and although this redundancy does improve reliability, it 

also requires more complicated coordination and protection schemes. These schemes can be 

unintentionally disrupted by energy exported from distributed PV systems. Today, Con Edison 

evaluates the network impact of each proposed PV system in New York City, but this is time 

consuming for utility engineers and may delay the customer’s project or add cost for larger 

installations. The city’s leaders would like to streamline this process to facilitate faster, simpler, 

and less expensive PV system interconnections. 

With support from DOE, NREL conducted a four-part study to assess ways to improve the 

interconnection process. We then compiled the final reports from each study into this report, 

which is intended not only to document our work in New York City, but also to assist other 

utilities that are interconnecting distributed PV systems to their networks. 

5.1 A Brief Summary of Each Report Section 

In Section 1, we analyze the technical potential for rooftop PV system in ten Con Edison 

networks. The study spans various boroughs of New York City and different building densities, 

ranging from high-density apartments to lower density single family homes. Next, we compare 

the potential power production to network loads to determine where and when PV generation is 

most likely to exceed network load and disrupt network protection schemes. The results of this 

analysis may assist Con Edison in evaluating future PV interconnection applications and in 

planning future network protection system upgrades. 

Section 2 is an overview intended for nontechnical stakeholders. Here we describe the issues 

associated with interconnecting PV systems to networks and present possible solutions. At 

higher deployments, for example, distributed PV systems can disrupt network protection, 

complicate load forecasting and power system planning, increase the potential for unintentional 

islands, and cause power quality problems like voltage flicker. Section 2 ends with a brief 

summary of potential solutions for these issues. 

5-1
 
 

 

 

 

 

 

 

 

In Section 3, we summarize common concerns of utility engineers and network experts about 

interconnecting PV systems to secondary networks. This section also contains detailed 

descriptions of nine solutions, including advantages and disadvantages, potential impacts, and 

road maps for deployment. 

Section 4 describes our review of the administrative interconnection processes of utilities across 

the country and identifies ways to streamline the distributed generation application process. A 

list of administrative best practices for efficient PV interconnection is included in this section. 

5.2 Future Research 

To build on what we learned in this four-part study and gain a better understanding of the effects 

of distributed PV systems on networks, we recommend additional research in the following 

areas: 

•	 Identify system-level impacts of high PV penetration in networks: Although the 

effects of individual PV system connections to networks have been comprehensively 

examined, we currently know little about how the entire system is affected at high 

penetrations of PV. 

•	 Identify maximum penetration levels in network systems: PV penetration levels of 

20% to 30% are generally considered to be the maximum allowable level in radial 

distribution systems before changes to the system are necessary. The maximum allowable 

penetration level on a network system, however, is unclear. Additional research is crucial 

for establishing maximum acceptable penetration levels in networks. 

•	 Improve modeling of distributed generation in network systems: Current modeling 

solutions do not adequately address the system impacts of distributed generation in 

network systems. Further research and development should be directed at improving 

modeling solutions for network systems. 

•	 Develop smart grid technologies: Smart grid technologies, which are currently in their 

infancy, could potentially offer intelligent monitoring and control of PV systems, 

allowing for better integration into network systems. Research and development of smart 

grid technologies, with a particular focus on their applicability in network systems, 

should continue. 

5-2
 
 

6.0 Glossary
 

Area network: A type of secondary network distribution system that is typically used in larger 

metropolitan areas. It can serve hundreds to thousands of electric customers of all types and sizes 

(e.g., residential, commercial, and industrial). Area networks are also known as street networks 

or grid networks. Area networks have two or more feeders and two or more transformers 

networked together (see Figure 6-1), to provide redundancy. Typical area networks can include 

as few as 10 transformers to more than 1,000 transformers, and be served by 3 to 35 distinct 

electric distribution feeders. Some area networks can serve up to several square miles. Area 

networks are designed to serve all network customer loads, during a peak-demand day, with one 

to two feeders out of service. And many networks could operate with additional feeders out of 

service during times of nonpeak demand. 

M 

Utility Substation 

Customer Site 

Primary Feeder 

Network Protector 

M Utility Meter 

3-Phase Network 

Transformer 

Legend 

Secondary Grid 

Customer load 

Substation Breaker 

Fuse 

Breaker 

Figure 6-1. A typical area network 

6-1 
 

 

 

 

 

Circuit breaker (“breaker”): A device designed to open the circuit automatically on a 

predetermined overload of current. It is typically manually reset to the closed position. A circuit 

breaker is usually intended to operate infrequently, although some types are suitable for frequent 

operation. 

Cycling: The undesirable cyclical opening and closing of a network protector because of 

external (load) conditions. Left unchecked, cycling can eventually lead to failure of the network 

protector. 

Reverse power flow from exporting photovoltaic (PV) systems can cause cycling. The network 

protector opens initially when it senses reverse power. Once it has opened, the load flow 

changes direction, and the open network protector may sense this as a “re-close” condition. 

When the network protector closes, the load flows will again change direction and could once 

again cause the network protector to open. This could lead to repeated opening and closing of the 

network protector, eventually causing it to fail. 

Electrical distribution system: The system that carries electricity from the substations to the 

individual customers. The two main types of electrical distribution systems are radial and 

network. 

Electrical transmission system: The system that carries electricity from the power plants to the 

substations. The transmission system operates over longer distances and at higher voltages than 

the distribution system. 

Fault current: The current that results from the accidental connection between an energized and 

a grounded or other conductive element. Faults can be caused by a range of events, including 

lighting strikes, overhead lines breaking in storms, and workers digging through cables. Fault 

currents can be very large and the distribution system must be designed to withstand these 

currents and to disconnect the faulted section quickly, allowing the rest of the system to continue 

operating with a minimum of disturbance. Because PV systems add an additional source of 

energy to the network, they can increase the amount of fault current in the network. Increased 

fault current caused by individual PV systems is generally very small, but it could exceed 

equipment ratings at high PV penetrations. 

Feeder: The circuit that carries electricity from the electrical substation to the customers. A 

feeder typically supports several hundred to several thousand electric utility customers. 

Fuse: An overcurrent protective device that detects faults and opens the circuit by melting a wire 

component. 

Grid network: See area network. 

Harmonic distortion: The change in the waveform of the supply voltage from the ideal 

sinusoidal waveform. Harmonics cause undesirable heating in transformers and cables, which 

can lead to circuit breaker tripping, overvoltage problems, incandescent light blinking, and 

computer malfunctions. 

6-2
 
 

 

 

 

 

Islanding: A condition in which a portion of the utility system that contains both load and 

distributed resources remains energized while isolated from the rest of the utility system. 

Meter: The device that measures and records electricity consumption. 

Net metering: A practice that enables customers to use their own generation to offset their 

consumption over a billing period by allowing their electric meters to run backward when they 

generate electricity that exceeds their demand. This offset means that customers receive retail 

prices for the excess electricity they generate. Without net metering, a second meter is usually 

installed to measure the electricity that flows back to the provider, with the provider purchasing 

the power at a rate much lower than the retail rate. 

Network: See secondary network distribution system. 

Network protector (NP): Special protective devices used in secondary network distribution 

systems (networks), but not in radial distribution systems. Networks were originally designed for 

one-way current flow from the electric utility to the consumer, and NPs are usually set to prevent 

current from flowing back toward the utility. NPs, which consist of a relay and breaker pair, are 

installed on the low-voltage side of each network transformer. When they sense reverse current 

flow, they open to prevent current from flowing back through the transformer from its lowvoltage side to its high-voltage side. This prevents current flow in the event of a faulted or deenergized circuit, and allows the network to maintain uninterrupted service to utility customers 

even if a piece of equipment fails. 

Because NPs are set to prevent reverse current flow, net metering is often difficult to implement 

in systems with NPs. Most NPs, though, can be programmed to allow reverse current, even by up 

to half the power rating of the transformer. 

Pumping: The rapid, uncontrolled, unintentional, and intolerable repetitive opening and closing 

of a network protector, normally because of a failure in the network protector control circuitry. 

If not detected and corrected, pumping will quickly lead to failure of the network protector. 

Radial distribution system: The most common design used by electric utilities. Radial 

distribution systems are the least expensive to plan, construct, and maintain. They generally 

consist of an electrical substation (typically at medium voltage in the 15-kV class); a feeder 

(which may be a few miles to a few dozen miles in length); and a transformer that converts the 

15-kV voltage to a utilization level (120/240, 120/208 or 277/480; see Figure 6-2.) Several 

hundred to several thousand electric utility customers are typically on a feeder, and anywhere 

from 1 to 20 customers are served by a single transformer. Although radial distribution systems 

are simpler and less expensive than their network counterparts, they are also the least reliable 

because of the radial nature of the design. If any part of the system experiences a failure, some 

customers will be without power until a repair is completed. An auto-loop distribution system is 

a special type of radial distribution system that is differentiated by having two feeders that tie to 

a customer load. The auto-loop system automatically senses the loss of one source of voltage and 

quickly and automatically switches the load to the second feeder. This type of system increases 

reliability by keeping outages to a few seconds (or faster), but requires two sets of utility 

6-3
 
 

 

equipment at one location (which can add thousands to hundreds of thousands of dollars to an 

installation). 

Feeder 2 

Utility Substation Feeder 1

Closed Switch 

Primary Feeder 

Transformer 

Legend 

Secondary Circuit 

Customer Load 

Substation Breaker 

Open Switch 

Note: Any transformer/customer load can be served by either feeder, depending on the switch positions. 

Figure 6-2. A typical radial distribution system 

Reactive power: Represents the alternating exchange of stored energy (inductive or capacitive) 

between two areas. Unlike real power, it does not deliver energy to a load, but it is necessary for 

the operation of induction motors. 

Relay: A switch that opens and closes electrical contacts to control another device. In the case 

of an NP, a relay controls the circuit breaker. 

Secondary network distribution system (“network”): The most sophisticated type of 

distribution system used by larger electric utility companies. Networks bring electricity to 

customers in areas where there are large concentrations of load and where greater reliability 

6-4
 
 

 

(than that of a radial system) is needed. A network is designed so that each load receives its 

power and energy from several parallel circuits and sources. This is achieved using a grid of 

interconnected primary and secondary lines to serve the connected loads. Engineers design 

networks with redundant transformers and redundant feeders, which is a distinguishing 

characteristic of a network. Redundant feeders and transformers can be taken out of service 

without affecting customers. Network feeders, transformers, and NPs can be taken out of service 

for maintenance or to add new equipment. Other reasons to take them out of service include 

equipment failures that result in a feeder or transformer outage, and significant drops in load on 

the network. Because there are multiple sources of power, “n,” network engineers often design 

the networks to operate at “n-1” or “n-2” contingency mode. The n-1 indicates that the network 

will be fully functional with one less feeder in service, and n-2 indicates that the network will be 

fully functional with two less feeders in service. 

The two types of secondary network distribution systems are spot networks and grid networks. 

Spot network: A type of secondary network distribution system that is frequently used to serve 

a single customer. Spot networks will have two or more feeders and two or more transformers 

networked together at an electric consumer’s site (see Figure 6-3). Electric consumers who are 

served by spot networks are typically located in very large buildings with major electric loads. 

Utility Substation Feeder 1 

Customer 

Feeder 2Feeder 3 

M 

Primary Feeder 

Network Protector 

Utility Meter 

3-Phase Network 

Transformer 

Legend 

Secondary Bus 

Substation Breaker 

Fuse 

Breaker 

M 

To other Network 

Transformers 

Figure 6-3. A typical spot network 

6-5
 
 

 

 

Street network: See area network. 

Substation: A group of switches, circuit breakers, buses, and transformers that switch power 

circuits and transform power from one voltage to another or from one system to another. A 

substation connects the electrical transmission system and the distribution system, and 

transforms the power from high to low (or the reverse) using transformers. Electricity may flow 

through several substations between the power plant and the consumer, and the voltage may be 

changed in several steps. 

Transformer: A device that raises or lowers voltage and current levels in a circuit. 

VAR: Volt-ampere-reactive, the unit of reactive power. 

6-6
 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

REPORT DOCUMENTATION PAGE Form Approved 

OMB No. 0704-0188 

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources,

gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this

collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents 

should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a 

currently valid OMB control number. 

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION. 

1. REPORT DATE (DD-MM-YYYY) 

December 2009 

2. REPORT TYPE 

Technical Report 

3. DATES COVERED (From - To) 

4. TITLE AND SUBTITLE 

Interconnecting PV on New York City's Secondary Network 

Distribution System 

5a. CONTRACT NUMBER 

DE-AC36-08-GO28308 

5b. GRANT NUMBER 

5c. PROGRAM ELEMENT NUMBER 

6. AUTHOR(S) 

K. Anderson, M. Coddington, K. Burman, S. Hayter, B. Kroposki, 

and A. Watson 

5d. PROJECT NUMBER 

NREL/TP-7A2-46902 

5e. TASK NUMBER 

PVC9.92GA 

5f. WORK UNIT NUMBER 

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES) 

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 

8. PERFORMING ORGANIZATION 

REPORT NUMBER 

NREL/TP-7A2-46902 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES) 10. SPONSOR/MONITOR'S ACRONYM(S) 

NREL 

11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER 

12. DISTRIBUTION AVAILABILITY STATEMENT 

National Technical Information Service 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

13. SUPPLEMENTARY NOTES 

14. ABSTRACT (Maximum 200 Words) 

This study describes technical assistance provided by NREL to help New York City and Con Edison improve the 

interconnection of distributed PV systems on a secondary network distribution system. 

15. SUBJECT TERMS 

Photovoltaic (PV) Interconnection; secondary network distribution system; New York City; Con Edison; utility 

networks 

16. SECURITY CLASSIFICATION OF: 17. LIMITATION 

OF ABSTRACT 

UL 

18. NUMBER 

OF PAGES 

19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified 

c. THIS PAGE 

Unclassified 19b. TELEPHONE NUMBER (Include area code) 

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18 

F1147-E(10/2008)