Proceedings

NREL/TP-550-48378

September 2010

High-Penetration Photovoltaic 

Standards and Codes Workshop 

Workshop Proceedings

M. Coddington, B. Kroposki, and T. Basso

National Renewable Energy Laboratory

K. Lynn

U.S. Department of Energy, Office of Energy Efficiency 

and Renewable Energy

C. Herig

Solar Electric Power Association

W. Bower

Sandia National Laboratories

Denver, Colorado

May 20, 2010
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

Proceedings

NREL/TP-550-48378

September 2010

High-Penetration Photovoltaic 

Standards and Codes Workshop 

Workshop Proceedings

M. Coddington, B. Kroposki, and T. Basso

National Renewable Energy Laboratory

K. Lynn

U.S. Department of Energy, Office of Energy Efficiency 

and Renewable Energy

C. Herig

Solar Electric Power Association

W. Bower

Sandia National Laboratories

Denver, Colorado

May 20, 2010

Prepared under Task No. PVC9.1110
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iii

Acknowledgements

Special thanks to our session moderators Kevin Lynn, DOE; Christy Herig, SEPA; Larry 

Sherwood, Solar ABCs; and Benjamin Kroposki, NREL; Ward Bower, Sandia National 

Laboratories; and all of the workshop speakers and participants who contributed their 

time, knowledge, and feedback at the High Penetration PV Standards and Codes 

Workshop.

We would like to extend our sincere appreciation to David Glickson and Connie 

Komomua who were instrumental in organizing and coordinating the workshop activities, 

and Don Gwinner who did an excellent job recording Q&A’s during the open panel 

discussions.

We would also like to like to thank Jessica Achtman and Michelle Allgauer from SEPA 

who flawlessly coordinated the logistical and operational aspects of SEPA’s 2010 Utility 

Solar Conference that preceded this workshop and were gracious enough to stick around 

afterwards and help register participants of the High Penetration PV Standards and Codes 

Workshop.
iv

Table of Contents

Acknowledgements...........................................................................................................iii

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

Workshop Agenda.............................................................................................................1

Workshop Presentations...................................................................................................3

Opening Remarks/Logistics ..........................................................................................3

Welcoming / Introductory Remarks ...............................................................................6

Session 1 – High Penetration PV Concerns ...............................................................14

Review of High Penetration PV Issues....................................................................14

Defining High Penetration–Multiple Definitions and Where to Apply Them ............21

Distribution System Impacts from PV on Utility Systems ........................................26

Session 1 Q&A: High-Penetration PV Concerns....................................................31

Session 2 – Gaps in Existing Standards and Codes...................................................36

Solar ABCs..............................................................................................................36

Systems Interconnection Standards and Codes-IEEE / Smart Grid .......................38

Technical Criteria for High Penetration-FERC/State Screens/Penetration Criteria.50

NIST Priority Action Plan Recommendations..........................................................57

Session 2 Q&A: Gaps in Existing Standards and Codes ........................................64

Session 3 – High Penetration PV Technical Solutions................................................67

PV Inverters with VAR Control, Low-Voltage Ride-Through, Dynamically Controlled 

Inverters, etc. ..........................................................................................................67

Energy Storage and PV Generation Integration-Utility and Manufacturers 

Perspectives............................................................................................................74

Monitoring, Information, and Control: Energy Management for Tomorrow's PV 

Technology..............................................................................................................80

Session 3 Q&A: High-Penetration PV Technical Solutions.....................................88

Session 4 – High Penetration PV Solutions: Modeling and Studies ...........................91

Modeling Tools, Existing and Future Needs / Modeling PV Systems .....................91

Anti-Islanding Assurance and Approach/ Review of Standards Focused on Island 

Systems ................................................................................................................101

Distribution Impact Studies / Review of IEEE P1547.7 .........................................106

Session 4 Q&A: High-Penetration PV Solutions-Modeling and Studies................114

Moving Forward with HPPV Standards and Codes / Discussion of Future Workshops, 

Webinars & Standards Activities...................................................................................116

Appendix - List of Attendees .........................................................................................117
1

Introduction

Effectively interconnecting high-level penetration of photovoltaic (PV) systems requires 

careful technical attention to ensuring compatibility with electric power systems. Standards, 

codes, and implementation have been cited as major impediments to widespread use of PV 

within electric power systems. 

On May 20, 2010, in Denver, Colorado, the National Renewable Energy Laboratory, in 

conjunction with the U.S. Department of Energy (DOE) Office of Energy Efficiency and 

Renewable Energy (EERE), held a workshop to examine the key technical issues and barriers 

associated with high PV penetration levels with an emphasis on codes and standards. This 

workshop included building upon results of the High Penetration of Photovoltaic (PV) Systems 

into the Distribution Grid workshop held in Ontario California on February 24-25, 2009, and 

upon the stimulating presentations of the diverse stakeholder presentations. 

Fourteen speakers spoke to the audience of over 100 participants from utility, industry, and 

government organizations. While the focus of the presentations covered a wide spectrum of 

topics, there was significant focus on how to minimize the negative impacts of PV deployment 

and how high penetration may support the electric distribution system. Additionally, there was 

significant discussion on future inverters that would be capable of staying online during grid 

anomalies while maintaining grid safety and reliability. 

Discussions included multiple definitions of high penetration, enhanced monitoring and control 

opportunities, and the new IEEE P1547.8 Draft Recommended Practice for Establishing 

Methods and Procedures that Provide Supplemental Support for Implementation Strategies for 

Expanded Use of IEEE Standard 1547 that may focus on resolution of many concerns of highpenetration PV deployment. Copies of each presentation, as well as notes on the question and 

answer intervals, are included in these workshop proceedings. 

The meeting concluded with general consensus that additional meetings, webinars and 

conference calls would be desirable. There was overwhelming agreement that developing new 

standards and codes for high-penetration PV deployment is an extremely important goal for

utilities, industry, and government. 

Workshop Agenda

The workshop was comprised of four sessions, with three panelists presenting within each 

session. Audience members were asked to hold questions and comments until the Open Panel 

Discussion following the presentations. Questions and comments were to be focused toward 

the need for and development of new standards and codes related to high penetration 

photovoltaic system deployment. 
2 
3 

Fourteen presentations are included in this document, followed by a question and answer 

transcription (Q&A Transcripts) which captures many of the discussion topics and main points. 

Workshop Presentations 

Opening Remarks/Logistics 

Michael Coddington, National Renewable Energy Laboratory (NREL) 

Michael Coddington is a Senior Engineer with the National Renewable Energy Laboratory in 

Golden Colorado, and came to NREL after working 20 years in the electric utility industry. 

Michael worked in many areas of the utility industry including electric distribution design and 

planning, system planning, operations, power quality and service investigation, and key 

account management. He also spent much of his time focusing on rate and tariff design, 

contract administration, system planning, secondary network engineering, electric metering, 

customer information services, and advanced metering infrastructure. 
4

His work at NREL focuses on the integration of DG systems to the grid, with a focus on 

standards and codes. He has authored or collaborated on several technical papers focusing on 

interconnection to the grid with an emphasis on the customer and utility side of the Meter.

Michael received his degree in electrical engineering from Colorado State University and is 

also a licensed master electrician and licensed electrical contractor in the State of Colorado.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Opening Remarks & Logistics

Michael Coddington, NREL

HPPV Workshop Logistics

• Breaks & Lunch

• Moderators

– Kevin Lynn, DOE SETP

– Ben Kroposki, NREL

– Christy Herig, SEPA

– Larry Sherwood, Solar ABCs

• Four Sessions – 3-4 speakers each

– Q&A during Open Panel Discussion

2
5

HPPV Workshop Logistics

• Focus on HPPV Standards and Codes 

• Capturing the Discussion 

– Emails and feedback welcome

– michael.coddington@nrel.gov

• Results and Presentations to be Published

• Future Workshops Possible – Please Comment

3
6

Welcoming / Introductory Remarks 

Kevin Lynn, U.S. Department of Energy (DOE)

Kevin Lynn works for the Department of Energy in the Solar Energy Technologies Program 

and is the lead for the Systems Integration subprogram. Kevin manages the work in grid 

integration, testing and evaluation, and codes and standards. Previously Kevin worked as a 

support services contractor at the Department of Energy (DOE) in the Solar Energy 

Technologies Program (SETP). There he provided leadership for the Systems Integration 

subprogram and the Solar America Board for Codes and Standards, a body of experts receiving 

funding from DOE to address codes and standards issues. Mr. Lynn has provided leadership in 

programs requiring technical assistance such as the Solar America Cities program, the Solar 

America Showcases program, and the Government Solar Installation Program. Before working 

for Sentech, Mr. Lynn was a Senior Research Engineer at the Florida Solar Energy Center 

(FSEC) working in a faculty position from 1998 to 2007. In 2005 Kevin was the principal 

investigator on the Southeast Regional Experiment Station, a project with the Department of 

Energy focused on photovoltaic system research. 
7

Energy Efficiency & Renewable Energy eere.energy.gov

2

Solar Program Budget 

Sub-Elements

Photovoltaics (PV)

Concentrating Solar 

Power (CSP)

DOE

SETP

Market Transformation

System Integration

Distributed Generation 

- on-site or near point of use -

Centralized Generation 

- large users or utilities -

Energy Efficiency & Renewable Energy eere.energy.gov

3

The goal of the Systems Integration 

sub-program is to address

– inverter cost reduction

– other technical barriers to achieving 

10-20% market penetration of solar 

technologies by 2030

Systems Integration Sub- Program Goal

Residential System Targets *

$0.00

$0.03

$0.06

$0.09

$0.12

$0.15

$0.18

2009 Benchmark 2015 2030

LCOE (2009$/kWh)

O&M 

Overhead, Regulatory & Other 

Installation Labor 

Other Materials 

Inverter 

Module 
8

Energy Efficiency & Renewable Energy eere.energy.gov

4

• The Systems Integration Area is organized into the following:

• System Technology Development 

– Developing technologies for allowing PV systems to integrate into 

distribution systems at high penetrations and Smart grids (Solar Energy 

Grid Integration Systems – SEGIS)

• System Level Technical Modeling and Analysis

– Developing technical models for high penetration analysis

• System Level Lab and Field Testing 

– Lab and field testing of high penetration scenarios

• Solar Resource Characterization and Forecasting

– Radiometry

– Forecasting

– Resource Characterization and Modeling

• Systems Integration Codes and Standards 

– Updating standards and codes to address high penetration solar

• Testing, Evaluation, and Reliability

Areas of Activity

Energy Efficiency & Renewable Energy eere.energy.gov

5

Solar Capacity Growth in 10% and 

20% Scenarios

Slide 5
9

Energy Efficiency & Renewable Energy eere.energy.gov

6

• Completed Renewable Systems 

Interconnection Study in 2008

• 15 reports (over 1000 pages) 

discussing issues and research needs 

for implementing high penetration 

solar

Systems Integration Planning

Developed multi-year program 

plan for Renewable Systems 

Integration based on RSI Study

• Currently codes and standards in the 

United States are developed around 

passive participation in the electric 

power system.

• As higher levels of PV systems are 

integrated into the electric power 

system, they will need to play an 

active role in the operations on the 

grid.

• Codes and standards will need to be 

adjusted to account for this fact and 

regulatory agencies will need to be 

aware of these changes.

Energy Efficiency & Renewable Energy eere.energy.gov

7

• High Penetration Workshop in Ontario, CA

– February 2009

– “There was general agreement that standards for inverter 

operation and performance (e.g., IEEE 1547) need to be revised 

and developed to enable ancillary services such as local voltage 

regulation. These changes in standards are expected to be nearto mid-term activities, depending on the availability of technical 

evidence to support changes.”

• Solar Energy Grid Integration Systems – Energy Storage

– June 2009

– Development of Standards was a major requirement in the 

development of smart grid capability with energy storage

Finding from High Penetration 

Workshops
10

Energy Efficiency & Renewable Energy eere.energy.gov

8

The Hawaii utilities (HECO, MECO, HELCO) are proposing to limit the 

total amount of distributed generation to 5% of the peak capacity. 

HECO is resetting the frequency cut-off from 59.3 to 57 Hz.

Island 

Grid

Net System Load 

at Peak (MW)

Existing DG 

(MW)

Existing 

Distribution 

Level 

Penetration 

Proposed Action

Oahu 1,200 40.1 3.3%

Allow DG to 60MW; conduct further 

study over course of year to confirm 

ability to accommodate more.

Hawaii 194.6 9.1 4.7%

Defer additional variable DG 

interconnection requests including 

standard interconnection agreement 

and NEM requests, until appropriate 

mitigation measures are identified and 

employed. Defer bi-lateral PPA 

negotiations.

Maui 199.9 5.8 2.9% Same as Hawaii (above)

Lanai 4.70 2.1 43.7% Defer additional DG interconnections

Molokai 5.95 0.3 5.0% Defer additional DG interconnections

System and Integration Issues

Energy Efficiency & Renewable Energy eere.energy.gov

9

Technology Development

Solar Energy Grid Integration Systems (SEGIS)

• Program Scope: Develop highly 

integrated, advanced inverters/controllers 

either with built-in energy management 

functions (including management of 

energy storage) or capable of interfacing 

with energy management and energy 

storage systems to achieve fully gridinteractive PV distribution systems.

• Impact: DOE involvement provides the 

necessary funding to create new 

technologies compatible with the Smart 

Grid.

• Collaborations: Industry, EPRI, NIST, 

OE, Universities

• Research Category: Advanced 

Component Development and Prototypes

• TRL Level: 6

Year Budget

1) Scoping $4.7M

2) Product Development $21M

3) Deployment TBD
11

Energy Efficiency & Renewable Energy eere.energy.gov

10

Dashboard Status

Contractual

Technical

Financial (LCOE)

Financial (Health)

Management

FSEC/Satcon: Solar Energy Grid 

Integration System

Description: Creation of a 100 kW 

inverter that enhances yield, safety 

and allows for utility control.

Innovative Aspect: Uses a string level 

DC/DC converter, allows for utility VAR 

control, and allows for storage and DC 

loads 

Goal: Commercial and Utility market 

LCOE targets.

TRL Level: 6

Justification: Lower LCOE costs and 

greater.

Company status: 23 MW being deployed 

in China. $62M in revenue in 2008.

Budget status: $1.5M DOE committed to 

date, $1.2M in Stage 2

Jobs: 50+ Mostly R&D and Project 

Development

Energy Efficiency & Renewable Energy eere.energy.gov

11

Issue: Command and Control

• PV inverter provide power at unity 

power factor and are designed to 

disconnect from grid very quickly on any 

grid disturbance

• Voltage regulation may be effected 

because of PV systems operating at 

unity power factor of conventional 

generation’s ability to handle the ramp 

rates of PV at large scales.

• Utilities would like to be able to send 

signals that allow PV to provide 

regulation and off of unity power factor

System and Integration Issues

SETP Work to address issue 

• Solar Energy Grid Integration FOA

• Funding several inverter manufacturers 

to develop advanced communications 

and control for PV systems

The figure above shows the voltage profile along 

the length of a distribution circuit. 

When a DER is added at the end of the circuit 

the voltage at the end increase to a value 

outside of the normal voltage range.

DG

Normal 

voltage 

range w/o DER

voltage with DER

DER
12

Energy Efficiency & Renewable Energy eere.energy.gov

12

Issue: Solar Resource Variability

• Variability and uncertainty of solar 

generation (particularly PV) may make 

power systems operations more difficult 

and could increase cost

• Utilities are extracting variability of 

smaller systems to larger systems

• There is a concern about the ability of 

conventional generation’s ability to 

handle the ramp rates of PV at large 

scales.

• Utilities could impose limitations on 

ramp rates and curtail PV system output 

System and Integration Issues

High Variability of PV output for a 14MW plant

Preliminary Plant Layout of SunPower 

210MW PV Plant

≈ 5 km

Energy Efficiency & Renewable Energy eere.energy.gov

13

Issue: Impact of Solar on the Grid

• There is a lack of good steady-state and 

dynamic models for PV inverters for 

studies of high penetration

• Distributed PV (generation) not 

accounted for in distribution modeling 

packages

• This hampers utilities ability to conduct 

impact studies quickly

System and Integration Issues

SETP Work to address issue 

• Funding several projects through High 

Penetration FOA to address modeling

• NREL and Sandia working to develop 

inverter models for the variety of 

modeling applications

PV 

Array 

Model

Inverter 

Model

Network 

Model 

(impleme

nted in 

PSS/E or 

PSLF)

Reactive 

Power or 

Voltage 

Regulator 

Model

Solar 

Irradiance

DC Voltage

DC 

Current

Desired 

Q-Axis Current

D- and 

Q-Axis 

Current

D- and 

Q-Axis 

Voltage

Simplified model

Detailed model

Integrated into power 

system model
13

Energy Efficiency & Renewable Energy eere.energy.gov

14

High Penetration Solar 

Deployment

Areas of Activity

• Topic 1: Improved Modeling Tools 

Development

• Topic 2: Field Verification of HighPenetration Levels of PV into the 

Distribution Grid

• Topic 3: Modular Power Architecture

• Topic 4: Demonstration of PV and 

Energy Storage for Smart Grids

Awardees

• Arizona Public Service Company

• Commonwealth Edison Company

• Florida State University

• National Renewable Energy 

Laboratory

• Sacramento Municipal Utility District

• University of California San Diego

• Virginia Polytechnic Institute and 

State University

Energy Efficiency & Renewable Energy eere.energy.gov

15

High Penetration Award

NREL/Southern California Edison

SCE MW scale rooftop installation

Description: SCE is installing 500MW of 

commercial rooftop PV systems on the 

distribution systems over the next 5 

years.

Innovative Aspect: Very high penetration 

of PV on distribution system that is 

owned by the utility.

Goal: To monitor systems and develop 

models of high penetration systems on 

the distribution system.

TRL Level: 7

Justification: Answer questions and 

develop solutions to high penetration 

of solar on the distribution system.

Company status: One of the largest 

utilities (IOU) in California

Budget status: $3.6M DOE over 5 years; 

Year 1

Jobs: 50 Project Development

Dashboard Status*

Contractual

Technical

Financial (LCOE)

Financial (Health)

Management

*Just Starting this Year
14

Energy Efficiency & Renewable Energy eere.energy.gov

16

Thank You

Contact Information:

Kevin Lynn

Department of Energy

Phone: (202) 586-1044

Email: Kevin.Lynn@ee.doe.gov

Session 1 – High Penetration PV Concerns

Review of High Penetration PV Issues

Thomas Key, Electric Power Research Institute 

Tom Key has over 30 years experience in energy related R&D with the U.S. Navy, Sandia 

National Laboratory, and EPRI. He currently manages EPRI’s program to enable integration of 

distributed renewable resources. Tom is a Fellow of the IEEE and a nationally recognized 

leader in power system compatibility research, integration of distributed and renewable energy 

resources, application energy storage and power electronic technologies.
15

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

It’s Time to Change the Rules

Thomas Key, EPRI

Review of High Penetration PV Issues

2

• Role of distributed PV in voltage regulation, 

steady state and dynamic? 

• Best response to abnormal grid voltage, setting 

trip limits?

• Responsibility to prevent unintended islanding? 

• Coordination with existing protection systems?

• Is PV a negative load or a grid asset...adapting to 

changing conditions?

• To use central or distributed control and 

communication?
16

We have been working on these

issues for a while...

3

Codes and Standards

• NEC Article 690, PV 

System Installations, 1984

• IEEE 929 - for Utility Interface of PV Systems, 1988

• IEEE 1001 –Recommended 

Practice for Grid 

“Integration”, 1989 

• IEEE 1547 and UL 1749 –

Std Interconnection, 2003

• FERC Standards Connection

Tom Key, Sandia Lab, July 1987

• IEEE 2030, New Standard for High Penetration Integration with 

Distribution Grid, 20XX

Voltage Response/Ride Thru Test

4

Early Inverter 

Test Results 

Sandia Lab

1982-83
17

German MV Grid Code – Ride Thru

5

Utility Voltage Correction Test

6

Early Inverter 

Test Results 

Sandia Lab

1982-83

Advanced PWM inverter, very clever 

controls designer – both fundamental and 

harmonic reactive power compensation
18

Voltage Regulation

7

VARs Generated

Capacitive

Inductive

System 

Voltage

V1 V2 V3

V4

Q1

Q4

Q2 Q3

Utility-Defined Location Dependant Response
19

Dynamic Interactions Multiple DER

9

EPRI-ORNL

Testing 2004

Peak Load on Feeder in kVA

Aggregate DR rating on Feeder in kVA Penetration FactorTotal feeder load =

sc

sc

System kVA

Aggregate kVA of DR on Feeder Contribtution Ratio =

Significance Factors

• Connection Point

• Relative Size

• Feeder Loading 

• Aggregate Total kVA

• Penetration Levels

Local 

EPS 1

Local 

EPS 2

Area EPS

PV Load

PCC PCC

Load

Point of DR 

Connection

Local 

EPS 1

Local 

EPS 2

Starting point with IEEE 1547
20

Make a plan to change the rules

11

% of Generation ≤ 2% ≤ 10% ≤ 30% 100%

Grid Penetration 

Scenarios 

 I. Low-numbers and 

level of PV with 

relatively stiff grid 

connection

 II. Moderate-level of 

PV with relatively 

soft grid connection

III. High-level of PV with 

capacity of grid less 

than the load demand 

 IV. PV operates 

part time as an 

island or microgrid

PV Impact and its 

Role in the Grid

Very low, not 

significant to grid 

operation

Non critical, can 

affect distribution 

voltage near PV

Critical to power 

delivery and meeting 

demand 

Primary power 

source for stand 

alone operation

Interconnection 

and Integration 

Objectives

Non interference, 

good citizen and 

compatible

Manage any local 

distribution impacts

Engage PV for system 

operations and control

Rely on PV for 

stability and 

regulation

Rules/Standard 

Operating 

Procedures

IEEE 1547-2003 

current practice 

radial feeders

Modified 1547, add 

network and 

penetration limits

New rules include 

operation and grid 

support requirement

Standalone rules 

that are system 

dependent

Main Concerns 

with-respect-to 

system dynamic 

grid impacts 

- Voltage and 

current trip limits,

- Response to 

faults 

- Synchronization

- Interfere with 

regulation,

- Recovery times,

- Islanding

- Coordination.

- Availability 

- Regulation provided -

Ramping response

- Interactions of 

machine controls

- Availability

- Load following

- Voltage control

- Normal and 

reserve capacity

......Transitions On- and Off-Grid......

Are we ready to do this thing?

12

Tom Key

865-218-8082

tkey@epri.com

“Completing the 

Circuit”
21

Defining High Penetration–Multiple Definitions and Where to Apply Them

Phil Barker, NOVA

Phil Barker has worked as a consulting engineer in the electric power industry for 24 years 

working for Power Technologies, Incorporated, EPRI’s Power Electronics Applications 

Center, and as the leader of Nova Energy Specialists, a consulting firm he founded.

Phil has extensive experience analyzing the impacts of high penetration distributed generation 

on power systems, considering factors such as voltage regulation, grounding compatibility, 

power system losses, stability, overcurrent protection, power quality and reliability. Phil has 

also assisted several states in the development of first generation distributed generation 

interconnection requirements.

Phil is a member of ASES, a Senior Member of IEEE and was a participant in the development 

of IEEE 1547. He received his B.S. and M.S. degrees in Electrical Engineering from Clarkson 

University, and is the author of 31 technical papers and articles.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Defining High Penetration PV – Multiple Definitions and Where to Apply Them

Presented by: 

Phil Barker 

Founder and Principal Engineer 

Nova Energy Specialists, LLC

www.novaenergyspecialists.com

pbarker@nycap.rr.com

(518) 346-9770
22

How Should We Define Penetration?

• Over what total area 

do we measure PV 

penetration?

• What specific power 

system “levels” are 

considered?

• What types of 

measures of 

penetration are 

useful?

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC 2

Subtransmission System

PV

PV

Bulk Transmission System

Alternate 

Feeds

Bulk 

Bulk Gen.

Gen. Bulk 

Gen.

Customer A Customer B

Adjacent 

Distribution 

Substations

Primary Feeder

Distribution 

Substation & 

adjacent 

feeders

Bulk Generation 

System

Shared 

Secondary

Dedicated 

Customer Secondary

Recloser

Traditional Penetration Measures

• PV connected as a percent of peak load

• PV energy as a percent of power system energy 

consumed

• PV connected as a percent of generation 

capacity

3

The above traditional measures of penetration, while useful in certain 

ways, don’t necessarily provide the information we need to identify 

locations where specific power system impacts are problematic. 

Additional penetration measures are needed to generally define the 

ability of the power system to handle a specific level of PV at specific 

sites and/or sections of the system.

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC
23

Some Limitations of Traditional 

Peak Load PV Penetration Measures

• Power system impedance and regulator settings vary greatly 

from site to site, so “peak load to PV power ratios” don’t 

necessarily tell us how much the voltage regulation will be 

influenced by PV on the circuit

• Peak load to PV generation ratios don’t provide a good 

indication of grounding compatibility or the risk of ground 

fault overvoltage during light load conditions

• Peak load to PV generation ratios don’t provide a good 

indication of the risk of islanding during light load conditions

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC 4

Key Areas of Focus for Distribution 

and Subtransmission Impact Studies

• Voltage Regulation 

(steady state conditions, fluctuating conditions [flicker], tap changer 

cycling issues, reverse power flow issues)

• Fault Currents and Protection Coordination

(impact on fault levels, device coordination, interrupting ratings, 

ground fault current detection desensitization)

• Ground Fault Overvoltages 

(this is important especially for non-effectively grounded DG, of which 

PV devices are often configured that way)

• Islanding

(important especially in complex situations with multiple DG present 

or with fast reclosing present and no live-line reclose blocking)

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC 5
24

• Check using raw 

feed point 

impedance

• Check with line drop 

compensation and 

regulator settings

• Results: 

 ∆V < 1% change then 

voltage issues not likely

 ∆V > 1% change then 

more detailed study 

and mitigation may be 

needed

Estimating Voltage Influence Due 

to DG at Feed Point Impedance

6

V I (X Sin(θ ) RCos(θ )) ∆ ≈ DG +

Point of 

Connection (POC)

Vinfinite source

X R IDG

θ Vsource

DG

IDG

∆V

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

Power system 

equivalent impedance

Some Useful Penetration Ratios for 

Engineering Analysis

• Minimum Load to Generation Ratio

(this is the annual minimum load on the relevant power system section 

divided by the aggregate DG capacity on the power system section)

• Stiffness Factor (the available utility fault current divided by DG 

rated output current in the affected area) 

• Fault Ratio Factor 

(available utility fault current divided by DG fault contribution in the 

affected area) 

• Ground Source Impedance Ratio (ratio of zero 

sequence impedance of DG ground source relative to utility ground source 

impedance)

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC 7

Note: all ratios above are based on the aggregate DG sources on the system area of interest where appropriate
25

Type of 

Ratio

What is it useful for? (Note: these ratios are intended for distribution and 

subtransmission system impacts of DG listed below, and not 

necessarily the overall bulk system stability impacts) 

Suggested Penetration Level Ratios(1)

Very Low 

Penetration

(Very low probability

of any issues)

Moderate 

Penetration (Low to minor probability

of issues)

Higher

Penetration(5)

(Increased probability

of serious issues. 

Minimum 

Load to 

Generation 

Ratio(2)

• Ground fault overvoltage 

analysis (use ratios shown when DG is 

not effectively grounded)

• Islanding analysis (use ratios 2/3 of 

those shown)

>10

Synchronous Gen.

10 to 5

Synchronous Gen.

Less than 5

Synchronous Gen.

>6 

Inverters(4) 

6 to 3

Inverters 

Less than 3 

Inverters 

Fault Ratio 

Factor

(I

SCUtility/ISCDG)

• Overcurrent device coordination

• Overcurrent device ratings >100 100 to 20 Less than 

20

Stiffness 

Factor 

(I

UitliltySC/IRatedDG)

• Voltage Regulation

(this ratio is a good indicator of voltage 

influence. Wind/PV have higher ratios 

due to their fluctuations. Besides this 

ratio, may need to check for current 

reversal at upstream regulator devices.)

>100 

PV/Wind

100 to 50

PV/Wind

Less than 50 

PV/Wind

> 50 

Steady Source

50 to 25

Steady Source

Less than 25 

Steady Source

Ground Source 

Impedance 

Ratio(3)

• Ground fault desensitization

• Overcurrent device coordination 

and ratings

>100 100 to 20 Less than 

20

8

Notes: 

1. Ratios are meant as guides for radial 4-wire multigrounded neutral distribution system DG applications and are calculated based on aggregate DG on relevant power system sections

2. “Minimum load” is the lowest annual load on the line section of interest (up to the nearest applicable protective device). Power factor of load is assumed to be 0.9 inductive.

3. Useful when DG or it’s interface transformer provides a ground source contribution. Must include effect of step-up transformer if present.

4. Inverters are weaker sources than rotating machines therefore a smaller ratio is allowable

5. If DG application falls in this “higher penetration” category it means some system upgrades/adjustments are likely needed to avoid power system issues.

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC

Ratios and Their Uses

Concluding Remarks & Caveats

• Ratios we have discussed are only guides for establishing 

when distribution and subtransmission system effects of DG 

become “significant” to the point of requiring more detailed 

studies and/or potential mitigation options.

• They must be applied by knowledgeable engineers that 

understand the context of the situation and the exceptions 

where the ratios don’t work

• It requires a lot more than just these slides here to do this 

topic justice. We have omitted a lot of details due to the short 

presentation format so this is just meant as a brief illustration 

of these issues.

NREL Workshop on High Penetration PV: Defining High Penetration PV – Multiple Definitions and Where to Apply Them Phil Barker, Nova Energy Specialists, LLC 9
26

Distribution System Impacts from PV on Utility Systems

Russ Neal, Southern California Edison 

Russell Neal is a Strategic Program Manager for Southern California Edison, specializing in

Smart Grid with an emphasis on distribution systems.

His experience includes five years as an officer in the surface nuclear Navy, seventeen years at 

Southern California Edison’s San Onofre Nuclear Generating Station, and twelve years in the 

Transmission and Distribution Business Unit including service in distribution apparatus 

engineering, and as Manager of Distribution System Engineering. Russell holds a BSEE from 

the U.S. Naval Academy, an MSEE from the University of Idaho, and an MBA from Azusa 

Pacific University. He is a registered Professional Engineer in both Electrical and Nuclear 

Engineering in the State of California.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Distribution System Impacts from PV on Utility Systems

Russ Neal, Southern California Edison
27

PG&E

SCE

• Serve a population of about 14 million people 

in a 50,000-square-mile service area within 

central, coastal and Southern California

• 5 million electric meters

• 12,000 circuit miles of transmission lines and 

more than 111,500 circuit miles of 

distribution lines

• 5,000 MW of generating capacity from 

interests in nuclear, hydroelectric, and fossilfueled power plants

• Award-winning energy efficiency & DR 

customer programs

• Industry leader in renewable energy, electric 

transportation, Smart Grid and smart 

metering

SDG&E

LADWP

Southern California Edison

An Edison International Company

Presentation Content

• PV System Impacts on Electric Distribution

• Utility Concerns and Potential Problems with 

High Penetration

• What are we Doing to Address this Issue?

3
28

Impacts

• Seasonal, Daily, Minute Solar Power Fluctuating

• PV Inverter – Grid Interactions

• Low Capacity Factor < 20% 

• Inaccurate forecasting 

• No storage

• Reverse Power Flow

Identified Issues Relative Priority Identified Issues Relative Priority

Voltage Control High Equipment Specs High

Protection High Interconnection 

Handbook Medium

System Operations High Rule 21 and WDAT Medium

Power Quality High IEEE 1547/ UL 1741 Medium

Monitoring and 

Control Medium Application Review High

Feeder Loading 

Criteria High Clarification of Responsibilities High

Transmission 

Impact Medium Integration with Tariffs Medium

Feeder Design Medium Coordination with 

Other Initiatives Medium

Planning Models Medium

Concerns
29

What we are Doing

• Inverter Specifications

– DIFG (EPRI)

– IEEE 1547.8

– Inverter testing

• ISGD AVVC project

• DMS/ALCS Project

• NREL Testing

– On SPVP impacted circuits

– Will include inverter trials as well

• Other studies

Inverter Modes

• Normal Mode

– Conservation Voltage

– Supply/Draw VARs to 

regulate local voltage

– “Qmax Available”

• Emergency Mode

– Supply max available 

VARs to support 

transmission 
30

Identified Issues With Renewable 

Integration – Operations

• Voltage control

– Multiple sources on a distribution feeder

– Intermittency

• Protection

– Overall circuit protection coordination

– Potential reverse power flow

– Coordination with inverters

• System operation

– Switching impacts resulting from large levels of DER generation

• Don’t want to limit system operations during emergency and clearances

– Interoperability of multiple inverters from various manufacturers

• Power quality

– Potential harmonic issues

• Monitoring and control

– As the aggregate capacity increases, additional monitoring and control may be desired

Identified Issues – Planning and 

Engineering

• Feeder loading criteria and forecasting

– How much generation can be installed on a distribution feeder

– Load forecasting needs to consider multiple generation sources

• Feeder design

– Future feeder design may need to consider large levels of DER 

generation

• Planning models

– Models should be adjusted to reflect actual system operation with 

high levels of DER generation
31

Identified Issues – Tariffs and Standards

• Equipment specifications and standards

– Ensure equipment such as inverters are compatible with 

SCE system operation

• Interconnection handbook

– Address multiple solar DER installations on distribution 

circuits and aggregate generation impacts

• Rule 21 and WDAT

– Address aggregate generation from multiple sites

Session 1 Q&A: High-Penetration PV Concerns

Note: This is not an exact transcription of the discussion during the Q&A session and is meant to be 

representative of the discussion during the session.

Audience Questions/Panel Answers 

Q. Any problems with PV systems with high-resistance ground? Any red flags or issues?

A. In looking at commercial systems there are a lot of configurations. Often see delta to 

grounded Y or Grounded Y / Grounded Y distribution transformer. Embedded in the 

inverter is an isolation transformer (center point it not grounded) therefore, the inverter 

does not looking like an effective grounded source. Need to pay careful attention to 

effectively grounding the system.

Q. Voltage regulation (VR) is the #1 issue with high penetration. What are solutions to 

mitigate the problem?

A. Some utilities regulate voltage on distribution circuits with switch capacitors operating 

on voltage; no VAR-type control. Often times there are no load tap changers (LTCs) in our 

substations where there may be high-penetrations PV installed. New inverters may be 

available to help mediate voltage regulation. There have not been issues yet, but we have a 

pilot program using thyristor technology on distribution system to help stabilize voltage 

fluctuations.
32

A. Close to putting in static VAR compensator, but have not done it yet. Important things 

to look at:

• Rapid changes, like voltage flicker are more rapid than the voltage regulation (VR) 

equipment is designed to operate at (time delay of 20-30 s); not meant for rapid 

changes. Tap changer cycling is a big issue and can be a problem. Back off on the line 

drop compensation; this is a cheap fix. If you reduce more sensitive, you're degrading 

VR for the customer. There is a tradeoff.

• Slower steady-state issues. If DG source exporting lots of VARS, then distribution 

system could back off on providing VARS.

Q. Problem transitioning from steady-state to moving. What solutions for flicker?

A. One of the speakers made their own curve for PV, similar to GE flicker curve in IEEE 

519, but not as sensitive. GE is based on rectangular shape, but PV is more sinusoidal 

shaped. Little more variation with PV and still don’t see anything especially for PV, 

smoother. There has not yet seen a problem on any feeder that have been studied. Flicker 

has not been the problem. More issues/problems pertain to LTC cycling and ground-fault 

overvoltages. 

Q. Would the utility let you open up UL1741 or IEEE 1547 constraints to allow inverter 

support VAR capability? Dynamic voltage compensation.

A. Nothing being done on a commercial product (at distribution level). GE has made 

adjustments with large wind turbines to meet FERC 661-A requirements at the 

transmission level. 

Q. Is the PUC letting us invest in grid-interactive inverters?

A. Dynamic voltage compensation is not a PUC issue.

A. X/R ratio on system is much greater than 1 typically. More reactance than resistance. A 

little VAR support coming from inverter goes a long way to deal with voltage problems. 

Very little loss to the inverter and could be very useful.

Q. Control voltage on feeder by backing off on the tap settings in the substation? Does this 

include any controller communication between substation and the end of the feeder?

A. There are a variety of ways to regulate voltage, LTC control or supplementary VR banktype control. These have a line drop compensator built into them. It is set for ideal 

regulation for that particular feeder. You can back off the line settings, thus reducing the 

sensitivity and the LTC cycling. However, you may need to increase the voltage set-point 

at the substation.

Q. With knowing what’s going on at the end of the feeder, have you considered developing 

communication? Automation?
33

A. Smart Grid means making power system more compatible for distributed generation 

(DG) if communication is better. But don't get carried away, don't make grid too 

complicated.

Q. Can we put in some simple communication and make basic changes? (He wants to take it a 

step further with communication.)

A. The technology exists today off the shelf, but it doesn’t solve all the problems, just on 

the margin.

Q. Emphasizing penetration issues, subdivide into local (voltage) and interconnection-wide 

(frequency) issues. Use reactive power to control voltage locally. Grid power balance is wider 

issue. In addition to looking at storage to mitigate PV variability, we should look at loads. 

When you start to balance the power system at a higher level, you get benefits of aggregation 

and cloud passing things don’t become an issue. Morning rise and evening drop are more of an 

issue. It can be counterproductive to balance at local area to try to govern voltage. Reactive 

power is much more efficient way to do it.

GE does market a grid-interactive inverter (based on wind turbine technology) to do such a 

thing, but it’s hard to market because of IEEE 1547 requirements. Early drafts of IEEE 1547 

allowed for grid interaction, but in the end some utilities did not want this capability included. 

The Commission has adopted IEEE 1547 and can’t deviate from 1547. It is a Catch 22. 

Choices that were made 10 years are becoming counterproductive.

A. Western Wind Solar Integration Study (WWSIS) coming out very soon. Good point 

regarding area storage with inverter. Results from WWSIS show you can control for 

geographical diversity. Diversity of approaches to mitigate problems. Codes and standards 

(C&S) trying to address 1547 problems and a new standard IEEE 1547.8 should address 

voltage regulation and other advanced functions. Cal ISO has system above 20 MW with 

variability generation control variability.

A. Storage is not cheap. Watts costs more than VARs. If you add capacity to feeder, 

putting storage at substation, good concept in addition to using electric vehicles with 

batteries and integrating them at distribution end.

Q. In deployment of large rooftop systems, have you seen systems kicking on or off due to 

cloud interaction between different systems? Systems fighting one another?

A. We will have 5 MW in by end of May, another 40 MW (utility owned) by end of year. 

Another 50 MW IPP contracts, so we are early in the process and have not seen integration 

issues.

A. Worst case is that we have 2 MW on a 10-MW circuit. No operational problems yet.
34

A. In general, you don't have active control going on. Inverter are set to trip off on utility 

issues. There is not reactive power control and the current systems can’t fight with each 

other.

A. Need to engage the folks in Germany, who have tremendous amount of experience in 

these issues. They have 1000s of MW of PV. Numerous studies on clouds passing effects 

on distribution system. U.S. deals with things more loosely, less regulation. Germany has 

ride-through standards. We don’t need to blaze new territory on these issues; Germany has 

done much, and we can learn from them.

Q. We should have looked further into the future when drafting 1547 so we wouldn't have to 

be dealing with some of these problems. We need to look at three things now: 

• Reactive support from two directions, not just top down; up to transmission grid from 

distribution system. When we need reactive support, it would be much more efficient to 

supply this support from both the distribution and transmission side, instead of top 

down as we do now. 

• Fault-induced-delay voltage recovery. Get more capacity out of our grid. Consider this 

when we develop new standards. Follow the Volt/VAR schedule.

• Conservation voltage reduction. Optimizing appliances to better efficiencies and more 

situations. We need to work with appliance manufacturers.

A. Regarding the voltage collapse issue, a little storage goes a long way.

Q. Variability issue. SunEdison has 24 systems in a specific area. On a very cloudy day, in 

terms of variability, the aggregate takes care of system variability. Variability of less than 5% 

for aggregate system, when single system has shown variability of 50%. Presentation of the 

data will be made during PV Specialists Conference in Hawaii.

A. You’re generalizing. System leveling has an impact at the circuit level. The distribution 

system constraints are not going to benefit from geographical dispersion. 

A. I take into account how dispersed are the PV on the feeder in my studies. If they are 

dispersed over several miles, it helps a lot. It’s better than having 1 MW located on top of a 

building or something like that.

Q. Speak about investing in distribution management system (DMS).

A. DMS is in the very early stages in development. We asked for everything under the sky: 

integrate DG, regulate PV, etc., in talks with several potential suppliers. Another question 

is to minimize bandwidth burden on communications systems to have closed-loop control 

over the system like larger plants. Schedule of behavior or different modes of operation 

preloaded in DG asset. Don’t want high bandwidth for these operations. Not investing large 

broadband. Use Internet? What if these things start to fight each other? Has anyone done 

any full-scale modeling? Trying to regulate voltage from various autonomous inverters? 

Build in some kind of delay, some randomness. 
35

Q. Look at what happened in computer industry. Rapid changes in technology; may cause 

problems?

A. Doesn’t see the regulatory space changing. Regulators are letting utilities do more 

research; this is positive. Utilities are getting more funds for research to advance the 

technology.

A. Hawaii is our test lab for new ideas. Utilities have put up cases for owning assets. Filing 

rate case for owning PV systems. Other utilities have put cases together for owning. Once 

the utility starts to own the asset, this will change the rules significantly. SEPA is starting 

to study how to file a rate case.

Q. Delayed voltage recovery after fault. Points out another issue of standards interaction and 

what would work best. Ride-through needs to be required. There was a study of whole 

western grid (8 years ago) where GE modeled the system with 20% of the inverters being UL 

1741 complaint and the system was shown to have issues with stability. With ride-through 

capability, it withstood disturbance. UL 1741 compliance is blocking inverters with this 

capability from market. We need to modernize the grid.

A. Doesn’t make sense to use 1741 for installing batteries. We need IEEE to write a new 

standard, ties it back to new functionality in IEEE 1547.8.

A. An option is to have grid inverters with multimodes. UL1741 or IEEE 1547 or gridinteractive modes. Wind ride-through disturbance is requirement now. Compound 

problem with not allow wind to remain on line during some fault. UL 1741 trips the 

inverter. Include VAR support. 

A. PV has been somewhat more successful than expected; needs of bulk system vs 

distributed system. IEEE 1547 has accelerated the success of PV. Need to revisit the 

whole grid PV interaction issue.

Q. What are ways to mitigating problems. Different modes that inverters can behave

differetly. Inverter modes Volt/VARs control. In my modeling, I have not run into any 

problems with inverters fighting each other. It does not take much VARs support to help with 

voltage regulation.

A. We were surprised by how fast PV came on and can support the grid. 

Q. Reinforcing these points. Regulatory is a real mess. What is the standard that we should 

certify our equipment to? Need a standard for inverter compliance.

A. IEEE is working on a new standards IEEE 1547.8 that will include testing to new 

functionality. That can eventually be integrated with UL 1741 to certify products. 
36

Q. Can you use of inverters for frequency regulation?

A. Four-quadrant device, why not make it follow a Watt/Frequency schedule to help 

stabilize the power grid? This could also apply to refrigerators, electric car chargers. Lots 

of unexplored territory. We have just barely taken our first steps toward this line.

Q. Defending 1547.4, which has intentional grid-supported capability, but when do you want a 

grid device interactive? These are exciting times, we now have a 20-MW storage device that is 

1547-compliant and meets LVTR requirement.

Session 2 – Gaps in Existing Standards and Codes

Solar ABCs

Larry Sherwood, Solar ABCs 

Larry Sherwood is President of Sherwood Associates, a renewable energy consulting firm. Mr. 

Sherwood has nearly 30 years of experience in the renewable energy field. He is Project 

Administrator for the Solar America Board for Codes and Standards, Executive Director of the 

Small Wind Certification Council, author of the annual IREC Report, U.S. Solar Market 

Trends, and Editor of the IREC Small Wind Newsletter. Previously, Mr. Sherwood served as 

Executive Director of the American Solar Energy Society. He is a graduate of Dartmouth 

College and lives in a PV-powered home in Boulder, Colorado.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Gaps in Existing Codes and Standards

Larry Sherwood
37

Solar America Board for Codes 

and Standards (Solar ABCs)

2

The Solar America Board for Codes and Standards (Solar 

ABCs) is a collaborative effort among experts to formally 

gather and prioritize input from the broad spectrum of solar 

photovoltaic stakeholders including policy makers, 

manufacturers, installers, and consumers resulting in 

coordinated recommendations to codes and standards 

making bodies for existing and new solar technologies. The 

U.S. Department of Energy funds Solar ABCs as part of its 

commitment to facilitate widespread adoption of safe, 

reliable, and cost-effective solar energy technologies.

Introduction to Solar ABCs

3

• Solar ABCs works with National Laboratories, Federal 

agencies, private industry, academic researchers, and 

public officials

• Many Solar ABCs members serve on the major solar 

energy-related standards and codes-making panels

• The Solar ABCs actively solicits and uses input from the 

whole spectrum of solar energy stakeholders

• The Solar ABCs perform targeted research leading to 

publication of peer-reviewed Study Reports and White 

Papers.
38

2010 Gap Analysis

4

• Highest priority topics:

– PV Flammability Research (increase in scope for existing activity)

– Ground Fault Protection Improvements to Prevent Fires

– Standards for PV and Storage

– Connection of PV to the Smart Grid

– Guidelines for Utility Inspections

• High Priority but defer until research or work at national labs is 

complete

– Inverter Qualification Standard

– Standards for Power Conditioning and DC-DC Converters

– Standards for Installation and Operation

– Standards for High Penetration Solar

Systems Interconnection Standards and Codes-IEEE / Smart Grid

Tom Basso, NREL 

Tom Basso is the NREL Principal Investigator for Smart Grid Interconnection and 

Interoperability Standards, and the Renewable Systems Impacts areas for DOE Office of 

Electricity, and the Principal Investigator for the NREL Codes and Standards area for the Solar 

Energy Technology Program. Tom is Vice Chairman of IEEE SCC21 which sponsors IEEE 

1547 interconnection and IEEE 2030 smart grid interoperability standards development. Tom 

is the US Technical Advisory Group Chair and Technical Advisor for the IEC TC8 Electrical 

Systems group. Tom received his B.E. Engineering Science, SUNY at Stony Brook and his 

M.S. in Engineering Thermodynamics and Applied Analysis at the State University of New 

York at Stony Brook.
39

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Systems Interconnection Standards and Codes: 

IEEE 1547 and P2030; Tom Basso, NREL 

Content

• Background 

the grid; 

DER interconnection; 

standards and applying standards. 

• IEEE 1547 and P2030 Standards 

• Closing Remarks 

2
40

3

Traditional Electric Grid in the USA

3

SmartGrid: Interoperability & DER Interconnection 

Distribution 

System 

Communications and Information Technology 

Information Flow, Data Management, 

Monitor & Control

Substations

DE Resources 

Interconnection

Bulk Power

Combined Heat

& Power

Load Management

sensors

sensors

(Also, larger DER 

on transmission)

sensors

sensors

Systems Approach 

• Interconnection & Interfaces 

• Technical Standards 

• Advanced Technologies 

• Systems Integration 

Transmission System

EV

Recip. 

Generator 

Photovoltaics

Micro 

Turbine

Storage 

Fuel Cell 

4
41

DER Interconnection 

Distributed Energy 

Resources

Interconnection 

Technologies

Electric Power 

Systems

Fuel Cell PV

Microturbine Wind

Generator

Inverter 

Switchgear, 

Relays, & 

Controls

Functions

• Power Conversion

• Power Conditioning

• Power Quality

• Protection

• DER and Load Control

• Ancillary Services

• Communications

• Metering

Microgrids

Energy 

Storage

Loads

Local Loads

Load Management 

Utility 

System

PHEV - V2G

5

Standards & Conformity Assessment 

 Safeguards against hazards 

 Fosters quality design and 

manufacture 

 Increases competitiveness in 

industry 

 Creates and expands markets 

 Facilitates Trade and 

Commerce 

 Assurance is provided when 

products meet quality 

standards, then users need not 

be concerned with redundant 

testing or evaluation of the 

product 

 Accelerates engineering 

advances & implementation, 

interoperability, and installation 

 Assists increased quality and 

reliability achievement 

 Simplifies compliance to needs, 

permitting, & rules 

 Promotes advanced 

communications; software 

platforms interchangeability 

 Enables enhanced DE systems 

and grid intelligence 

 Lower cost and quicker 

deployment for projects. 6
42

Standards, Testing, and Conformance: 

Putting the Pieces Together (STAC)TM

Testing & 

Certification Implementation: 

Rules & Agreements

Standards

Technical 

Conformance programs:

established by stakeholders; 

satisfy mandates; quality; 

recognized/accepted; not 

stagnant. 

Controlled/quality: processes, 

facilities, equipment personnel. 

Lab accreditation. 

Manufacturer quality. Test @ 

cradle-to-grave. 

Consensus driven. 

Defined scope & 

purpose. 

Proven/validated. 

Maintained/updated. 

Goals/purposes. 

Which standards & programs? 

Authority having jurisdiction. 

Dispute resolution. 

7

7

8

IEEE 1547 Interconnection Standards Use: 

UL 1741*

Interconnection 

Equipment 

• 1547.1 Tests 

• Construction

• Protection 

against risks of injury 

to persons

• Rating, Marking

• Specific DR Tests for 

various technologies

IEEE 1547.1

Interconnection 

System Testing 

• O/U Voltage 

and Frequency

• Synchronization

• EMI

• Surge Withstand

• DC injection

• Harmonics

• Islanding

• Reconnection 

IEEE 1547

Interconnection 

System and Test 

Requirements 

• Voltage Regulation

• Grounding

• Disconnects

• Monitoring

• Islanding

• etc. 

* UL 1741 supplements and is to be 

used in conjunction with 1547 and 

1547.1

NEC 

Article 690 PV 

Systems; 

Article 705: 

interconnection 

systems (shall 

be suitable per 

intended use 

per UL1741) 

PJM Interconnection, Inc. 

Small Generator 

Interconnection Standards 

FERC approved 

(0-to<10MW and 10-to-20 MW; 

incorporate 1547 and 1547.1) 

Federal, Regional, State and Local Authorities/Jurisdictions . 
43

PJM* Interconnect, Inc. 

Small Generator Interconnection Standards

1547 Std technical requirements 

1547 based test requirements

 Design Test (may be pre-certified)

 Production Test

 Installation Evaluation

 Commissioning Test

 Periodic Testing (per PJM 

tariff requirements) 

PJM SCADA option available 

Other Requirements

 e.g. PJM EPS owner voltage regulation 

 e.g., PJM EPS metering

 e.g. other National / local codes 

Summary Overview (Gen ≤ 10 MW, and, 10-20MW)

Purpose for adopting PJM-wide 

technical standards based on 

1547: 

• Limit barriers to 

interconnection

• Provide transparency 

• Allow for pre-certification and 

other means to expedite 

interconnection process 

*PJM is a regional 

transmission organization with 

over 140 GW load; 165 GW 

generating capacity 9

• Energy Policy Act (2005) Cites and Requires Consideration of 

IEEE 1547 Standards and Best Practices for Interconnection. 

• Energy Independence and Security Act (2007) Established NIST 

as Lead to Coordinate Framework and Roadmap for Smart Grid 

Interoperability Standards and Protocols. 

Federal 2009 ARRA: 

Smart Grid projects & 

DER high penetration. 10
44

• Energy Storage Systems, e.g., extend for storage system 

specific requirements 

• Distribution Grid Management Initiatives, e.g., extensions 

of 1547 series and/or P2030 series, including two-way 

communications 

• Voltage Regulation, Grid Support, etc., e.g., develop 

specifications in P1547.x and/or P2030-series. 

• Management of DER in Planned Islands 

• Static and Mobile Electric Storage, including both small 

and large electric storage facilities.

• Plug-in Electric Vehicles. 

1547 & P2030 Standards Development Considerations 

for NIST standards framework 

11

1547- 2008 Standard for Interconnecting Distributed Resources 

with Electric Power Systems

1547.1 - 2005 Conformance Test Procedures for Equipment 

Interconnecting DR with EPS 

1547.2 - 2008 Application Guide for IEEE 1547 Standard for 

Interconnection of DR with EPS

1547.3 - 2007 Guide for Monitoring, Information Exchange and 

Control of DR

Current 1547 Projects

P1547.4 Guide for Design, Operation, & Integration 

of Distributed Resource Island Systems with EPS

P1547.6 Recommended Practice for Interconnecting 

DR With EPS Distribution Secondary Networks

P1547.5 Guidelines for Interconnection of EPS >10 

MVA to the Power Transmission Grid 

Microgrids

IEEE 1547 Interconnection Standards

http://grouper.ieee.org/groups/scc21/index.html

P1547.7 Draft Guide to Conducting Distribution 

Impact Studies for DR Interconnection

P1547.8 (new) 

Extend use of 1547, 

e.g. grid support, energy 

storage, ride-thru, etc. 

12
45

... 

4.0 Interconnection Technical 

Specifications and Requirements: 

. General Requirements 

. Response to Area EPS 

Abnormal Conditions

. Power Quality

. Islanding 

5.0 Test Specifications and 

Requirements: 

. Design Test 

. Production Tests 

. Interconnection Installation

Evaluation 

. Commissioning Tests 

. Periodic Interconnection 

Tests 

ANSI/IEEE Standard 1547 

13

• A Technical Standard - Functional Requirements 

For: the interconnection itself and 

• the interconnection test 

• Technology neutral, e.g., does not specify 

particular equipment nor type 

• A single (whole) document of mandatory, 

uniform, universal, requirements. 

•Should be sufficient for most installations. 

•Requirements apply at point of common coupling 

(unless otherwise stated). 

IEEE 1547 

IS:

IEEE 1547 

Is NOT:

• a design handbook 

• an application guide

• an interconnection agreement 

• prescriptive, e.g., does not address 

DR self-protection, nor planning, 

designing, operating, or maintaining 

the Area EPS.

14
46

IEEE Std 1547.1 (2005) 

... Standard for Conformance Test Procedures ...specifies the type, 

production, and commissioning tests that shall be performed to demonstrate 

that interconnection functions and equipment of a distributed resource (DR) 

conform to IEEE Std 1547. 

Figure 1. Boundaries between the interconnection system, the EPS and the DR. 

Energy 

Conversion

(Inverter , 

Converter)

Generator

(Induction, 

Synchronous)

Area EPS

or 

Local EPS

System Control

(Output Levels, Start/Stop, etc.)

Electrical Protection

(abnormal protection)

Steady-State Control

(V, I, W, VAR, pf)

Distributed 

Resource

(DR)

(Internal Combustion, 

Photovoltaics, Wind, Fuel Cell, 

Turbine, Storage, etc.)

Interconnection System (ICS)

Ancillary Equipment 

15

P1547.4 (Planned DER Islands) IEEE ballot: Apr-May 2010 

Substation

Island 

Forms

lateral

Recloser 

Opens

feeder

DG 3

DG 1

PV DG 2

Inverter 

Source 1

PV 

Inverter 

Source 3

PV 

Inverter 

Source 2

Conventional 

Rotating DG

Conventional 

Rotating DG

Conventional 

Rotating DG

Substation

Island 

Forms

lateral

Recloser 

Opens

feeder

DG 3

DG 1

PV DG 2

Inverter 

Source 1

PV 

Inverter 

Source 3

PV 

Inverter 

Source 2

Conventional 

Rotating DG

Conventional 

Rotating DG

Conventional 

Rotating DG

E.g., DER (generation and energy storage) technologies are 

integrated with all others including the grid technologies to form 

Micro-grids (planned islands; includes – load management, 

voltage & VAR control, active participation, etc.) 

16
47

P1547.7 Guide to Conducting Impact Studies 

• Describes criteria, scope, and extent for engineering 

studies of the impact of DR on distribution system. 

• Methodology for performing engineering studies. 

• Study scope and extent described as functions of 

identifiable characteristics of: 

- the distributed resource, 

- the area electric power system, and 

- the interconnection. 

• Criteria described for determining the necessity of 

impact mitigation. 

• Guide allows a described methodology for: 

- When impact studies are appropriate, 

- What data is required, 

- How studies are performed, and 

- How the study results are evaluated. 17

P1547.8 Recommend Practice to Extend Use of 1547

• Need for P1547.8 is to address industry driven 

recommendations and NIST smart grid 

standards framework recommendations (e.g., 

NIST priority action plans). 

• Example considerations include: low voltage 

ride thru; volt-ampere reactive support; grid 

support; two-way communications and control; 

advanced/interactive grid-DR operations; highpenetration/multiple interconnections; interactive 

inverters; energy storage; electric vehicles; etc. 

18
48

Photovoltaic systems

Central Generating

Station

Step-Up 

Transformer

Distribution

Substation

Receiving

Station

Distribution

Substation

Distribution

Substation

Commercial

Industrial Commercial

Gas 

Turbine

Diesel

Engine

Cogeneration

Cogeneration

Turbine

Fuel 

cell

Microturbine

Wind Power

Residential

Storage

1 - Power System Infrastructure

The Smart Grid - the Integration of: Power, & 

Communications and Information Technologies 

Control Center

Operators,

Planners & Engineers

2 - Communications & Information Infrastructure

19

Draft Guide for Smart Grid Interoperability of Energy 

Technology & Information Technology Operation with the 

Electric Power System (EPS) &End-Use Applications & Loads 

• Provides guidelines in understanding and defining smart grid 

interoperability of the EPS with end-use applications and loads 

• Focus on integration of energy technology and information and 

communications technology 

• Achieve seamless operation for electric generation, delivery, and 

end-use benefits to permit two way power flow with communication 

and control

• Address interconnection and intra-facing frameworks 

and strategies with design definitions

• Expand knowledge in grid architectural designs and operation to 

promote a more reliable and flexible electric power system. 

IEEE Std P2030 – Smart Grid Interoperability

20
49

Closing Remarks 

• IEEE 1547 and IEEE P2030 Standards development 

facilitate high penetration of distributed energy resources . 

• IEEE P1547.4 (micro-grids/planned islands) discusses 

advanced DER and distribution system operations. 

• IEEE P1547.7 is a guide to conducting DER impacts study

• IEEE P1547.8 establishes recommended practices to 

extend 1547 use (such as voltage regulation, ride-through, 

grid support, etc.) 

------------------- ----------------------------------------- -----------------

Next P2030 and P1547 series meetings 

• P2030 Meeting May 25 – 28 

• P1547.7 Meeting August 10 – 11 

• P1547.8 Meeting August 12 – 13 21

Contact Information (background slides follow) 

• Dick DeBlasio, NREL Technology Manager 

NREL Distributed Energy & Electricity Reliability (DEER) Program 

IEEE Board of Governors, IEEE Standards Board Liaison to DOE; 

Chair IEEE SCC21, 1547 and P2030; 

email: Dick.DeBlasio@nrel.gov voice: (303) 275 – 4333 

• Thomas Basso* NREL

Vice Chair IEEE SCC21 & Sect’y 

P1547.2.3.4.6 .7 

email: thomas.basso@nrel.gov

voice: (303) 275 - 3753 * NREL DEER Distribution & Interconnection R&D

NREL http://www.nrel.gov

1617 Cole Blvd. MS-5202 Golden, CO 80401-3393 

• IEEE SCC21 -- IEEE Standards Coordinating Committee 21 on Fuel Cells, 

Photovoltaics, Dispersed Generation, & Energy Storage 

http://grouper.ieee.org/groups/scc21/

• IEEE Std 1547TM series of standards 

http://grouper.ieee.org/groups/scc21/dr_shared/ 

• IEEE Std P2030TM series of standards 

http://grouper.ieee.org/groups/scc21/P2030/ 

• Ben Kroposki* NREL 

Sec’ty 1547.1 & Chair P1547.4 

email: benjamin.kroposki@nrel.gov

voice: (303) 275 – 2979 

22
50

Technical Criteria for High Penetration-FERC / State Screens / Penetration 

Criteria

Michael Sheehan, Interstate Renewable Energy Center 

Michael Sheehan is an Interstate Renewable Energy Council representative working on state 

level rulemaking and workshops. He is also the Vice President of Utility Development for an 

energy efficiency company which provides utility-grade electronic voltage regulators. Michael 

has worked for three electric utility companies during his career, with a focus on 

interconnection, distribution reliability, transmission and distribution Planning, energy 

efficiency, and optimization measures. Michael was an original member of the IEEE 1547 

working group, is a registered Professional Engineer in the state of Washington, and a graduate 

of the Illinois Institute of Technology.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

FERC SGIP 15% Line Section Criteria

Michael T. Sheehan, P.E. IREC
51

Background FERC SGIP

• 10 kW Inverter Process

• Fast Track Process no larger than 2 MW

• Study Process no larger than 20 MW

• ANOPR, NOPR, Rule

• www.ferc.gov/industries/electric/indus-act/small-gen.asp

FERC SGIP Screens

• Section 2.2.1.1-10

• 10 screens

• 15 % rule on line section

• Line Section: That portion of the utility’s 

Distribution System connected to a Customer 

bounded by automatic sectionalizing devices or 

the end of the distribution line. 
52

FERC SGIP Subject Matter 

Experts (SMEs)

• IEEE P1547.6 Draft Recommended Practice For 

Interconnecting Distributed Resources With 

Electric Power Systems Distribution Secondary 

Networks 

• IEEE P1547.7 Draft Guide to Conducting 

Distribution Impact Studies for Distributed 

Resource Interconnection

• DOE designated SMEs

FERC SGIP Results

• Questionnaire request sent to 157 Subject 

Matter Experts (SME)

• 37 SMEs Completed Questionnaire

• 12 from IEEE 1547.6 Working Group

• 32 from IEEE P1547.7 Working Group 

• 5 Solar ABCs/DOE invites
53

FERC SGIP Results – Who completed the 

questionnaire?

Utility – Transmission

Utility – Distribution

Utility – Renewable

Utility – Policy

Engineering firm

Consultant

Regulatory

Manufacturer

Other

0

2

4

6

8

10

12

14

16

18

CA NJ NY NM TX AZ CT FL MA MI CO GA HI LA NC DE KY NH NV OH OR PA RI SC TN VA

FERC SGIP Results – Who completed the 

questionnaire?

In which state or states has the bulk of your 

recent renewable related interconnection work 

been focused? (up to 8 states)
54

15 % Line Section

8

0.00

5.00

10.00

15.00

20.00

25.00

1/1/20092/1/20093/1/20094/1/20095/1/2009

6/1/2009

7/1/20098/1/20099/1/2009

10/1/200911/1/200912/1/2009

Mw

McAuliffe Substation Load Profile

Jan 1 - Dec 31 2009

Minimum Load 5.7 MW

Peak 23 MW

Weekly Load Profile

11

0.00

2.00

4.00

6.00

8.00

10.00

12.00

6/26/20096/26/20096/26/20096/26/20096/26/20096/27/20096/27/20096/27/20096/27/20096/27/20096/28/20096/28/20096/28/20096/28/20096/28/20096/29/20096/29/20096/29/20096/29/20096/29/20096/30/20096/30/20096/30/20096/30/2009

7/1/20097/1/20097/1/20097/1/20097/1/20097/2/20097/2/20097/2/20097/2/20097/2/2009

Mw

McAuliffe Substation Weekly Load Profile

June 26 to July 2, 2009
55

Daily Load Profile

12

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

6/28/20096/28/20096/28/20096/28/20096/28/20096/28/20096/28/2009

6/28/20096/28/20096/28/2009

6/28/20096/28/20096/28/20096/28/20096/28/20096/28/20096/28/20096/28/20096/28/20096/28/20096/28/2009

6/28/20096/28/20096/28/2009

Mw

McAuliffe Substation Daily Load Profile

June 28, 2009

10:00 AM 3:00 PM

FERC SGIP Results - #2: DG capacity vs. line 

section peak load (max 15%)

YES

NO

Not able to answer

Do you support 

updating this 

screen?
56

In Summary – Selected 

Considerations 

• Three Stake holders meeting scheduled

November 2009; February 2010,

April 2010

• Draft Report – April 30th, 2010

• Comments – May 17th , 2010 

• Consensus – June 15th, 2010

• Final report – July 31, 2010

Feedback 

Michael Sheehan, PE

IREC

206.232.2493

climberlow@hotmail.com
57

NIST Priority Action Plan Recommendations

Al Hefner, National Institute of Standards and Technology 

Allen Hefner is a member of the National Institute of Standards and Technology Smart Grid 

Team and is NIST’s Project Leader for Power Devices and Thermal Measurements. He is 

currently focused on interconnection standards and power electronics technologies needed for 

high penetration of clean energy sources, energy storage, and plug-in vehicles. He is Chairman 

of the Interagency Advanced Power Group, Electrical Systems Working Group where he leads 

program coordination and information exchange among different federal government agencies 

in the area of electrical power conditioning. Dr. Hefner is an IEEE Fellow and has received a 

number of NIST and US Department of Commerce awards as well as a US Department of 

Energy Award for contributions to High-megawatt Power Conditioning System Technology 

for Clean Energy Systems.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Coordination and Acceleration of 

Smart Grid Interoperability Standards

Al Hefner
58

High Penetration of Renewables and PEVs 

2

• Power Conditioning Systems (PCS) convert to/from 60 Hz AC for 

interconnection of renewable energy, electric storage, and PEVs

• “Smart Grid Interconnection Standards” required for devices to be 

utility controlled operational asset and enable high penetration:

• Dispatchable real and reactive power 

• Acceptable ramp-rates to mitigate renewable intermittency 

• Accommodate faults faster, without cascading area-wide events

• Voltage/frequency control and utility controlled islanding

PCS PCS PCS

Energy Storage

(FERC top 4 priority)

Plug-in Vehicle to Grid

(Million in US by 2015)

Renewable/Clean Energy

(20% by 2020 )

Communication

Power Smart Grid

NIST’s Role in Smart Grid

3

Energy Independence and Security Act 

(2007) 

In cooperation with the DoE, 

NEMA, IEEE, GWAC, and other 

stakeholders, NIST has “primary 

responsibility to coordinate 

development of a framework 

that includes protocols and 

model standards for information 

management to achieve 

interoperability of smart grid 

devices and systems...”
59

Government Roles in Smart Grid

4

Public Utility Commissions

Federal

State

Federal

Energy

Regulatory

Commission

NIST’s Three Phase Plan

5

 NIST role

PHASE 1

Identify an initial set of 

existing consensus 

standards and develop 

a roadmap to fill gaps

2009 January 2010

PHASE 2

Establish Smart Grid 

Interoperability Panel (SGIP) 

public-private forum with 

governance for ongoing efforts

NIST Interoperability

Framework 1.0 Draft

Released Sept 2009

Smart Grid 

Interoperability Panel 

established Nov 2009

PHASE 3

Conformity Framework 

(includes Testing and 

Certification)

NIST Interoperability

Framework 1.0 

Released Jan 2010

Summer 2009 workshops
60

NIST Framework and Roadmap

6

http://www.nist.gov/smartgrid/

Conceptual Reference 

Model

• Revised version January 2010

• Smart Grid Vision / Model

• 75 key standards identified

– IEC, IEEE, ...

• 16 Priority Action Plans to 

fill gaps:

– One completed 

– Another added (wind plant 

communication)

• Cyber security strategy

– Companion document 

NISTIR 7628

International Standards are Vital

7

International 

77%

US Domestic 

13%

US Government 

10%

Source of Standards in NIST Roadmap

International Coordination

• Bilateral interactions

– China, Japan, Korea, India, Brazil, 

France, Germany, Ireland...

• US-EU Energy Council activities

– Smart Grids-Electric Vehicles

– Public workshop, USG-European 

Commission

• Coordination with International 

Standards Organizations:

– NIST Liaison to IEC-SG3

– SGIP international participation
61

Smart Grid Interoperability Panel

8

• Public-private partnership, 

started in Nov. 2009

• Over 550 organizations, 

over 1700 representatives

• Supports NIST in 

coordinating smart grid 

standards

• Governing Board elected

• SGIP Chair elected

• Committees established, 

SGIP meetings ongoing

• Electronic collaboration 

tools, newsletters / 

communications

• Project management office

• Open, transparent process

• International 

participation welcome

Smart Grid Interoperability Panel and Governing Board Smart Grid Interoperability Panel and Governing Board

SGIPGB

Products (IKB)

SGIP

One Organization,

One Vote

(Over 450; over 1500 persons 

participating including from 

international organizations)

One Organization,

One Vote

(Over 450; over 1500 persons 

participating including from 

international organizations)

Working 

Groups (DEWG, PAP, Other)

Smart Grid 

Identified 

Standards

Use Cases

Requirements

Standards

Descriptions

Priority

Action 

Plans

At large

Members (3)

Ex Officio

(non-voting)

Members

Ex Officio

-

Stakeholder 

Category

Members (22)

including 

utilities, 

suppliers, IT 

developers

Stakeholder 

Category

Members (22)

including 

utilities, 

suppliers, IT 

developers

Standing 

Committees

(Architecture, 

Conformance and 

Security)

Conceptual Model

Smart Grid Interoperability Panel and Governing Board Smart Grid Interoperability Panel and Governing Board

SGIPGB

Products (IKB)

SGIP

One Organization,

One Vote

(Over 450; over 1500 persons 

participating including from 

international organizations)

One Organization,

One Vote

(Over 450; over 1500 persons 

participating including from 

international organizations)

Working 

Groups (DEWG, PAP, Other)

Smart Grid 

Identified 

Standards

Use Cases

Requirements

Standards

Descriptions

Priority

Action 

Plans

At large

Members (3)

Ex Officio

(non-voting)

Members

Ex Officio

-

Stakeholder 

Category

Members (22)

including 

utilities, 

suppliers, IT 

developers

Stakeholder 

Category

Members (22)

including 

utilities, 

suppliers, IT 

developers

Standing 

Committees

(Architecture, 

Conformance and 

Security)

Conceptual Model

http://www.nist.gov/smartgrid/

(Over 550; over 1700 persons 

participating including from 

international organizations)

Priority Action Plans

9

Priority Action Plans

Smart meter upgradeability standard 

(PAP 00, completed by NEMA in 2009)

Standard meter data profiles (PAP 05)

Develop common specification for price 

and product definition (PAP 03)

Develop common scheduling 

communication for energy transactions 

(PAP 04)

Standard demand response signals (PAP 

09)

Customer energy use information (PAP10)

Energy storage interconnection guidelines 

(PAP 07)

Interoperability standards to support plugin electric vehicles (PAP 11)

Wind Communication Standards (PAP 16)

Priority Action Plans

Guidelines for use of IP protocol suite in 

the Smart Grid (PAP 01)

Guidelines for the use of wireless 

communications (PAP 02) 

Harmonize power line carrier standards 

for appliance communications in home 

(PAP15)

Develop common information model 

(CIM) for distribution grid management 

(PAP 08)

DNP3 Mapping to IEC 61850 Objects 

(PAP12)

Transmission and distribution power 

systems model mapping (PAP 14)

Harmonization of IEEE C37.118 with 

IEC 61850 and Precision Time 

Synchronization (PAP 13)
62

PAP 7: Smart Grid ES-DER Standards

10

SG Standards Need

• Interconnection and object model standards needed for:

– DER grid operational interface with dispatchable: VAR, V, F, etc.

– support for energy storage devices (ES), including PEV

– and hybrid generation-storage systems (ES-DER) 

PAP Major Objectives

• Revised and updated consistent guidelines and standards:

– Involve broad set of Stakeholders: SDOs, utilities, vendor, etc.

– Scoping Document to determine priorities and timeline for 

standards development for spectrum of applications 

– IEEE 1547 revisions for urgent applications

– Consistent object models for DER, ES, ES-DER in IEC 61850-7-420

– UL, NEC-NFPA70, SAE guidelines for safe, reliable implementation

PAP 7: Task Interactions

11

a) 

b)

c)

d

e)

Task 0:

Scoping Document

Prioritized timeline for 

ES-DER standards 

Task 1: 

Use Cases

Define requirements 

for different scenarios

Task 4: Develop and Harmonize Object Models

IEC61850-7-420 : Expanded to include 

multifunctional ES-DER operational Interface; 

harmonized with SEP, CIM, MultiSpeak

Task 5: Safe and Reliable 

Implementation

UL, NEC-NFPA70, SAE, 

CSA and IEC

Task 3: Unified interconnection method with 

multifunctional operational interface for range 

of storage and generation/storage.

IEEE 1547.8 PAR (a) Operational interface

(b) Storage without gen

(c) PV with storage

(d) Wind with storage

(e) PEV as storage

Task 2: IEEE 1547.4 for island applications 

and IEEE 1547.6 for secondary networks

PAPs 
63

Conclusion

• US energy strategy requires high penetration of

– renewable and clean electricity generators

– energy storage to mitigate intermittency and for grid stability

– plug-in electric vehicles for fuel diversity and grid storage 

• Power Conditioning Systems (PCS) interface DERs to grid

• Existing DER interconnection standards 

– do not take advantage of PCS value for grid operations

– may lead to stability problems for high penetration

• Smart Grid provides opportunity for change:

– communications to utilize DER as utility controlled asset

– coordination of standards for interoperability 

12

Contact Information

13

George Arnold

National Coordinator for Smart Grid Interoperability

george.arnold@nist.gov

David Wollman Dean Prochaska

david.wollman@nist.gov dean.prochaska@nist.gov

Al Hefner 

(NIST liaison to IEC SG3, NIST Lead for PAP 7 and PAP 16)

Allen.hefner@nist.gov

NIST Smart Grid Website: 

http://www.nist.gov/smartgrid/

NIST SGIP Collaborative Twiki site: 

http://collaborate.nist.gov/twiki-sggrid/bin/view/SmartGrid/
64

Session 2 Q&A: Gaps in Existing Standards and Codes

Audience Questions/Panel Answers

Note: This is not an exact transcription of the discussion during the Q&A session and is meant 

to be representative of the discussion during the session.

Q. 1547 didn’t worry much about NOPRs. Do we need to now?

A. Don’t want regulatory lag, barriers to new technologies. Need to move at a higher level, 

find common ground for everyone. FERC/NARUC should work together, have a joint 

hearing. Uniform standards would be great, but won’t happen; each state will do its own 

thing. It would be great to have no regulatory lag.

A. Standards dig into technical rationale that others can vet. Get engineering details in 

B&W for others. FERC and PUC roles are important, but I don’t want them to drive 

engineering. 

Q. Where do we go from here, for near term, for long term? Wise to set up roadmap effort to 

see what is possible near term, next 2 years, in next 10 years?

A. NIST scoping document identifies use cases and applications for storage and generators, 

and combinations, and to develop roadmap with timelines based on needs for utilities to be 

prepared when technology becomes commercially viable. Standards need to support a 

variety of solutions. The scoping document is an ongoing thing; need further input.

Q. General question about FERC and NARUC getting together. Can they also develop 

business case guidelines? If we supply VARS, we might get paid for it, that would be nice. 

Big generators already get paid for supplying VARS in some parts of the U.S. If we had a 

reliable business case for what VARS are worth and how much we get paid for them, this 

would help to move things along. DOE thinks that is in FERC’s scope. FERC thinks that it’s a 

local market issue and it’s outside their scope. It looks like it’s up to the state regulatory bodies 

to make these decisions. Who is dealing with market issues?? Folks making installation need 

to understand business case.

A. VAR tariff is a problem. FERC role is not going to help make a business case. VARS at 

different ends of the feeder have different value. Turf battles in regulatory world; they 

change people every 3 or 4 years. Detailed business cases are beyond our current scope.

Q. We’re looking for quick fixes, fast application solutions. Standards are slow. In the 

implementation phase, we need to find a better way. Why don’t we go in with a case on 

technical basis and with exceptions and argue it at FERC level? Industry needs to do this, no 

one else will do this for us.

A. FERC does rule making at federal level and at transmission level. PUCs are important 

too, at the distribution level. Legislation at the distribution level.
65

A. Too complicated to get quick fixes. Industry needs to get to Washington or go to the 

PUC.

Q. Is PV tied to storage? Ramp rates need to be controlled at the point of interconnection? 

Trade off between system-level approaches and at project level?

A. The initial EPRI roadmap identified gaps in standards. We need to narrow this list 

down. We organized it by priority. We looked at FERC’s priorities: storage was high 

priority. Issues on ramping, intermittency, variability, we are trying to deal with 

unpredictability, intermittancy. Can storage be used for more predictable variability, like 

diurnal? Trying to be consistent across all DER applications. Don’t want to have to 

change standards if something new comes out.

Q. 1547 series basically looks at static interconnection (yes or no decision). Can we add in 

dynamic capabilities, allowing interconnection, but only if they are willing to be part of 

ongoing real-time operation, maybe with managing VARS settings?

A. Certain tariffs would help to determine this. A device that supports 1547 today can be 

turned on or off, can be configured through communication.

A. PJM has implemented 1547 in their interconnection requirements; they require voltage 

regulation on larger systems. DG proponents and the utility need to sit down and figure it 

out. Quick fix is to get a friendly system integrator and friendly utility and make it work. 

Needs to be done on case-by-case basis (because not every utility has large interconnection 

group).

A. In Australia, regulators have looked ahead and let utilities know how they want them to 

move, good signals. We have reactionary framework here. It’s a different model; how do 

we change the paradigm?

Q. Any discussion to pursuing standards from applications or technology priority point of 

view? Do some issues hold up everything? Voltage ride-through, difference between how 

Europe does things and how we do it.

A. The standards need to be itemized to allow FERC or PUCs to select certain classes. 

Individually implemented, rather than waiting for another standard. We do have a 

prioritization process.

A. SolarABCs is supposed to listen to industry to bring back messages to SDOs. 

A. IREC is funded by DOE and cannot advocate for one particular technology, cannot 

favor one industry over another. For all renewable energy and best practices. We capture 

best practice in interconnection and net metering, for example. 

Q. Utilities feel like they are constrained by regulators by 1547. 1547 is non-prescriptive 

basically for islanding, it gives 3-4 possible solutions. UL 1741 does concentrate on one 
66

solution (active anti-islanding). How can we make sure that test standards by independent test 

labs will conform to all solutions, rather than becoming prescriptive?

A. Looking back, write back for an interpretation of UL 1741 to prove you have a viable 

anti-islanding scheme. Looking forward, get involved. PUC meetings are open. FERC 

process: ANOPR, NOPR, rulemaking....so there are multiple pathways to get into process. 

But it is slow.

A. SGIP is another pathway, which supports NIST. Need to make recommendations on 

standards that are ready for use.

Q. A roadmap question follow up. Could SolarABCs take a look at it?

A. We can look at that.

Q. Who in the audience worked on 1547? (Quite a few people in audience raised their hands). 

There is support for NIST and what they are doing. NIST and IEEE are well coordinated. If 

you want to work on IEEE standards, contact Tom Basso, to get involved.
67

Session 3 – High Penetration PV Technical Solutions

PV Inverters with VAR Control, Low-Voltage Ride-Through, Dynamically 

Controlled Inverters, etc. 

Ray Hudson, BEW 

Ray Hudson is a Principal Engineer at BEW Engineering in San Ramon, California where he 

leads the PV group. He has worked in the area of power electronics and renewable energy 

systems for over 20 years including inverter designs for wind and PV systems ranging in size 

from 10 kW to 5 MW. Before joining BEW, he was Vice President of Advanced Technology 

at Xantrex and prior to that he had management and engineering roles at Trace Technologies 

and Kenetech Windpower. He has Bachelors and Masters Degrees in Electrical Engineering 

from the University of Missouri – Columbia.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

PV Inverters with VAR Control, LVRT, and Dynamic Control

Ray Hudson – BEW Engineering
68

PV Inverter Overview

• Converts DC from PV Modules to AC into Utility Grid

• Implements Maximum Power Point Tracking

• Provides system monitoring

• Implements grid “Interactive” features

2

PV Utility Interactive Inverter Block Diagram

Present US PV Inverter Requirement Status

• Design to meet IEEE 1547

• Based on low penetration installations from 

California Rule 21 which is 15%

• Listed to UL-1741 (harmonized with IEEE 1547)

– Anti-Islanding

• Stop Operation if grid voltage goes away

– Tight over/under voltage and frequency trip settings

– Unity Power Factor

• AC voltage regulation not allowed

• Purpose is to get out of the way in fault condition 

and let existing utility protection scheme operate 

3
69

Utility Friendly Features • Operate like a traditional synchronous generator

• VAR Control 

– Non-Unity Power Factor

– Regulate PV plant voltage

• Low Voltage Ride Through

– Stay on-line during grid Voltage dip

– In contrast to Anti-Islanding

– Help improve system stability

• Dynamic Control

– Ramp rate and curtailment of real power

– Communication allows PV to be part of the utility system

• Purpose is to help with grid stability

• Will be required in the future for high penetration levels

4

European PV Has These Features

5

E.ON Netz Grid Code for High and Extra High Voltage

BDEW Technische Richtlinie Erzeugungsanlagen

am Mittelspannungsnetz

Journal Officiel de la Republique Francaise DEVE0808815A

Royal Decree RD 661/2007

Similar but not standardized

Other countries as well
70

German LVRT Example E.ON

6

• German Utility requirement for connecting 

distributed generation equipment to the 

transmission system

• Must remain operational above red line

German Example E.ON

7

• Requires ability to control power factor to 0.95 

leading or lagging to support voltage regulation

• Adjustments required to real power as a function of 

frequency

• Requirement to communicate with SCADA system

50MW Solar Plant in Germany with E.ON Features
71

Wind Has These Features

• First utility scale US 

windturbines did not

• Big windplants require it!

• Requirements standardized 

in FERC 661A

• Communications system for 

dynamic control included

• Generally more difficult to 

implement LVRT in a 

windturbine inverter 

compared to PV

8

FERC 661A • For windturbines - but only present standard and is 

applied to PV plants

• Requires LVRT

– 9 cycles down to zero Volts at high voltage side of 

windplant interconnection

– Follow recovery curve determined on a site by site 

basis based on the local grid characteristics and 

protection scheme

• Voltage control required

– 0.95 Leading PF to 0.95 Lagging PF

• Ruling negotiated between NERC and AWEA 

9
72

Proposed NERC LVRT Requirements

NERC PRC-024-1

Proposed – may be adopted in 2010

For single generators >20MW

Aggregate systems >75MW

10

Frequency Ride-Through Requirements Voltage Ride-Through Requirements

Dynamic Control

• Communications to PV inverters to control 

operational setpoints

– Real Power Limit

• Curtail production!?

• Ramp rates

– Reactive Power Level

• VARs

• Power Factor

• Voltage control

– Trip levels

• Over/Under Voltage

• Over/Under Frequency

• Operate like traditional power plants

11
73

Technical Challenges 

• Implementing VAR Control, LVRT, and Dynamic 

control is not highly technically challenging

• Most of the changes can be done in software

• Minor hardware changes

– Additional Sensors

– UPS for LVRT

– Minimal additional cost 

• Inverter will operate at higher current levels 

when off of unity power factor than at unity

– Impacts efficiency and reliability

12

Going Forward

• Confusing for inverter manufacturers and PV system 

developers

• Utility friendly features are required for large plants 

and high penetration levels

• Opportunity to leverage from Wind and European 

experience

• Standards need to be modified, accepted, and 

implemented

13
74

Energy Storage and PV Generation Integration-Utility and Manufacturers 

Perspectives

Charlie Vartanian, A123Systems 

Charlie Vartanian is Director of Grid Integration at A123 Systems, which is a manufacturer of 

advanced Lithium-ion batteries and systems. Charlie focuses on grid application development 

and market access advocacy to expand the useC of advanced storage technologies for grid 

benefit. Previously, he was Distributed Energy Resource Development Manager at Southern 

California Edison where he supported and participated in joint research studies with external 

entities working on advanced grid concepts. Other prior engagements include Southern 

California Edison Transmission Planning, Southern California Edison Field Engineering, 

California Energy Commission Staff, Enron Energy Services, and the U.S. Navy. Charlie 

received his MSEE from USC, and his BSEE from Cal Poly Pomona. Charlie is a licensed 

Professional Engineer in California, and is a member of IEEE.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Energy Storage and PV Generation Integration-Utility and 

Manufacturers Perspectives 

Charlie Vartanian, A123 Systems
75

DTE/A123 Smart Grid Storage

Courtesy, DTE 2

DTE/A123 Smart Grid Storage

3

Demonstration Item Side of the meter MPSC PV DOE CES

1. Frequency Regulation (DR-SOC dispatch, 

retransmit AGC from MISO) Utility X X

2.A VAR Support 

(local control, PF management) Customer X

2.B Voltage support

(local control, meet utility v-schedule) Utility X

3.A PV output shifting 

(Local control, Time of day) Customer X

3.B PV output leveling 

(local control ,ramp management) Utility / Customer X X

4. Demand response

4.A Grid support (DR-SOC dispatch, ‘N-1’) Utility X X

4.B Distribution circuit peak shaving 

(DR-SOC dispatch or schedule) Utility X X

4.C Customer peak shaving

(local control, demand charge mngt) Customer X

5. Islanding

5. Intentional (control schema TBD) Utility Excluded X
76

Challenges = Opportunities

• Voltage regulation

• Power flow control

• Preserving effectiveness of protection schemes

And Leverage New Assets to Extend Capability

– Transient mitigation

– Power quality

– Reliability

– Interphase balancing (hidden asset capacity degrader)

– Active filtering (hidden asset life degrader)

4

NEDO, Integration for Penetration

From, “NEDO Research Related to Large-scale PV-related Grid-connection Projects”, Nakama 5
77

NEDO, Avoiding Restriction on PV

From, “NEDO Research Related to Large-scale PV-related Grid-connection Projects”, Nakama 6

PV and Circuit Level Voltage, ref’s 

7

Technical discussion of the NEDO ‘Ota’ project

“STUDY ON THE OVER VOLTAGE PROBLEM AND BATTERY OPERATION

FOR GRID-CONNECTED RESIDENTIAL PV SYSTEMS”, 22nd European 

Photovoltaic Solar Energy Conference, 3-7 September 2007, Ueda, Y., et al

Technical characterization of the challenge

“Clustered PV Inverters in LV Networks: An Overview of Impacts and 

Comparison of Voltage Control Strategies”, IEEE Paper, Demirok, E., et al
78

Remove Unintended/Simple Std.’s Barriers

8

A123, Disruptive Technology Advances

9
79

A123, Disruptive Technology Advances

10

• 2MW 500kWh Modular Units

– Scalable to 200MW Arrays

– 20ms response

• High Cycle Life

– >8,000 full DoD, 

– >500K micro-cycles to 80% capacity 

• High Efficiency 

– 90% roundtrip

• Energy Storage Enabling New Possibilities for the Electric Grid 

FLEXIBLE: Can be used for frequency regulation, spinning reserve, black 

start, smart grid applications, and integration of renewable sources

A123, Scale to Accelerate Effectiveness

11
80

Monitoring, Information, and Control: Energy Management for 

Tomorrow's PV Technology

Brian Seal, Electric Power Research Institute 

Brian Seal is a Senior Project Manager at the Electric Power Research Institute, and is 

responsible for identifying and managing a range of projects that enable the utility industry to 

move forward with Smart Grid systems in a way that is both technically and economically 

sound. Brian’s research is centered on utility communication systems including distribution 

SCADA, Advanced Metering Infrastructure and In-Premise networks. Brian joined EPRI in 

2008 as part of a Smart Grid group. Prior to joining EPRI, Brian worked for Cellnet and Hunt 

and Schlumberger in the system architecting and product development areas. He is the holder 

of several patents related to advanced metering and utility communication systems. Brian 

received his Bachelors and Masters Degrees in electrical engineering from the Georgia 

Institute of Technology.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Monitoring, Information, and Control: Management for Tomorrow’s PV

Brian K. Seal
81

A Vision for Grid-Integrated Smart Inverters 

2

Communication-Connected Distributed Solar and Storage 

Systems as Beneficial Distribution System Assets 

Implementation Requires a Complete Solution

3
82

Collaborative Industry Project – June 2009

To identify a standards-based way that inverters could 

support a core set of grid-friendly functions 

350 individuals engaged, representing:

• 40 PV & Storage equipment providers

• 60 utilities

• 12 National labs and research organizations

• Engage a broad range of industry stakeholders 

• Select a beginning set of functions

• Identify appropriate standards (NIST aligned)

•Work together to define how each function will 

work 

• Map to standard communication protocols, 

DNP3, Smart Energy Profile, etc.

• Transfer to Standards Organizations









Project Approach & Activities
83

1. Connect / Disconnect from Grid

2. Output Power Management

3. Intelligent Volt-Var Control

4. Storage Management

5. Event/History Logging

6. Status Reporting /Reading

7. Time-sync

Functions Addressed in Phase 1 VARs Generated

Capacitive

Inductive

System 

Voltage

V1 V2 V3

V4

Q1

Q4

Q2 Q3

Volt/Var 

Mode 1 –

Normal 

Regulation

VARs Generated

Capacitive

Inductive

System 

Voltage

V1

V2

Q2

Q1

Volt/Var

Mode 2 –

Transmission 

VAR Support

Utility-Defined Curve Shapes

Simple 

Broadcast

Advanced Volt-Var Control
84

Time 

Power 

Watts

Vars

Reactive Intermittent Power Compensation

Circuit Impact Modeling

• Actual 12kV feeder

• 1800 customers

• ~10MW Peak load

• ~ 17 mi 3-phase primary

• ~ 115 mi 1-phase primary

• 20% PV penetration, 

customers randomly 

selected 

• Each with 4KW PV 

system

Substation

PV
85

Volt-Var Inverter Simulation Model

Residential Load

To Service 

Transformer

Var Control 

Algorithm

Meter

Residential PV

P, Q

P,Q

V

Q

Example PV and Customer Load Shape 

0

1

2

3

4

5

6

7

8

9

0 2 4 6 8 10 12 14 16 18 20 22

Hour

kW

Customer Load

Customer PV (-)
86

Baseline – No PV

Inverter Volt-Var Control

20% PV Penetration

Resulting Effect on Service Voltage

Alignment with IEC 61850-7-420

Contribution to NIST PAP 7 – Storage/PV

Use case sharing with OpenHAN 2.0

Planned DER Mapping to the Smart Energy Profile

Application contribution to the DNP3 TC

A live-application for NIST PAP12 – 61850 to DNP

Coordination planned with IEEE P1547-8 PAR

Coordination with Industry Activities
87

•Invite New Participants

•Review Completed Work

•Model / Simulate Behavior on Feeders 

(OpenDSS)

•Interoperability Laboratory Testing

•Field Test

•Evolve

•Repeat

Next Steps

Questions

Contact

Brian Seal

865-218-8181

bseal@epri.com
88

Session 3 Q&A: High-Penetration PV Technical Solutions

Audience Questions/Panel Answers

Note: This is not an exact transcription of the discussion during the Q&A session and is meant 

to be representative of the discussion during the session.

Q. Interested in VAR control graphic. Constant VARs or dynamic control depending on 

voltage? (Brian’s slide)

A. Not dynamic. The inverter configuration had the same kind of Volt/VAR characteristics. 

Q. Any interaction addressing ride-through? Large PV system like Wind FERC 661A. Is it a 

possible pressure point with someone like AWEA to make things happen?

A. Great question. Not aware of a similar activity. Great opportunity. Will pass that on to 

SEIA.

A. The Utility Wind Integration Group (UWIG) is good model. UWIG has started a solar 

integration subgroup. Expanding to look at solar integration issues. Workshops in Cedar 

Rapids in October; UWIG meeting in Portland.

A. So far UWIG has concentrated on variability of PV. Not a group for pushing standards. 

New group formed called Solar Grid Integration Group (SolarGIG) at SEPA.

Q. Take Wind experience on LVRT. 1547.4 San Francisco–take Wind experience with ridethrough and expand it to PV. There are answers. Does it need funding or research? 

A. There’s a bunch of research going on at NREL, Sandia, EPRI. Coordination is 

important. Need a forum to get feedback on access to and usability of research.

Q. If inverter is on customer side of meter is there a firewall issue. Google has all sorts of 

information on line, but there is all sorts of info on homes. How are we going to protect 

systems? Home area network type system vs. utility SCADA system?

A. Our working group has not been doing security work. Not obvious that PV would be on 

home area network. It’s alongside the demand response application. Don’t want someone 

to change signal going onto grid. If you solve the demand response residentially, then you 

solve it for renewable energy integration at the same time.

A. NERC Smart Grid task force. PV people open your horizons, start talking to NREC; 

they are the 800-pound gorilla you will run into. Looking at cyber security from the home 

to the bulk grid. There is a NERC report coming out soon. 

Q. NIST cyber security work addresses home area network to the utility. NIST Cyber Security 

work – addresses home area network to the utility. In addition, IEC 68150 is being expanded to 

include cyber security (run by Annabelle Lee, NIST).
89

Q. In the VAR vs, Voltage behavior, why dead band in middle? Why zig zag, not linear?

A. Great question. Currently there is not a standard setting or configuration.

Q. Power system difficult to communicate to regulatory people. The system can accommodate 

reverse power flow, will get opposite voltage gradient but there’s no reason why you can’t get 

10 MW of load to be able to handle 10 MW steady-state profile. To think you need storage to 

limit reverse power flow on feeder is unfortunate. One problem you can run into is at the 

feeder head voltage. Fix tap at substation and other feeder that don't have PV; a voltage 

regulator is a lot cheaper than storage. Solving feeder voltage problem with storage is 

overstated.

A. Only use storage if there is payback. You can use storage for voltage regulation.

Q. Cyber Security Working Group is a permanent group. NIST effort is closely coordinated 

with NERC.

Q. Could you speak further on comments that utilities don’t always adhere to IEEE standards 

them, especially behind the fence.

A. As long as you’re behind the fence, you don’t need to comply with 1547. Challenge 

comes in educating the design engineers. You don't have a UL. What do you have? The 

answer is it meets UL standard minus the chapter that describes anti-islanding.

A. Some big systems are operated behind the fence using European inverters mostly design 

to meet 1547 with the exception required by those sites. Sometimes the pushback comes 

from non-technical issues—e.g., conservative banks raise the idea of risk and they are not 

comfortable with it. Want to follow the proven standards.

A. Utility-owned out in the field, as on warehouse roofs. Most utilities need to meet 

exactly same interconnection standards. The utilities do have the latitude to put in 

something that’s not UL 1741 compliant, but it would require a study.

A. For non-standard projects for non-listed inverters, some utilities are accepting, some are 

not.

Q. From an inverter manufacturer perspective, where do we go to meet today’s standards and 

what do we do looking forward? Inverters can’t be developed overnight that has all the needed 

capabilities.

A. Talking to inverter vendors, they are interested in applications. Require VARs. Needs 

driven. Today’s need is voltage regulation.

A. AC current drives the cost. People are saying: we’ll buy your inverters, but they have to 

do this...Most vendors in Europe had to go through their own certification process and are 
90

looking to come to U.S. How do we coordinate this going forward? Demand will push it 

forward.

There are two kinds of demand markets for inverter manufacturers:

1. Distribution market: smaller systems with UL labels

2. Transmission: big systems with other features; can use non UL listed product and be 

OK with it. 

Q. There is a difference between interconnection requirement and the way the system operator 

decides to use the capability to manage the system. Europe (Ireland) requires that wind turbine 

be capable of frequency support on system and operates less than 100% power output. So you 

can have a positive response to frequency drops. This does not mean operators have to use it 

because of penetration levels.

Q. 1547 originally allowed for DG regulation voltage. Some believe the utility should not have 

any discretion. We have seen the request for utility not allowing inverters to be connected if 

it’s not on an approved list of inverters. Lots of uncertainty in this area.

A. 1547 is very important and the industry couldn’t have grown without it.

Q. PV has been very successful. Penetration has increased so much that we need to do more. 

Making exceptions to standards is not unusual. Just make your case to modify. PV is part of 

the DG community. There are ways to negotiate. IEEE 1547 can be extended but it must 

address reality of what you’re trying to do.

A. That’s what this forum is about. We need to look at what needs to be addressed and 

how to do it.

Q. Are inverters capable of increased VAR support today? Second, can you generate reactive 

power 24/7 with the inverter?

A. Yes, industry can make the jump. Pretty straightforward to modify equipment to meet 

needs. Second, a PV inverter is similar to a static VAR compensator...same topology. The 

question becomes, how do you get paid for these VARs?

Q. How many watts did you lose by implementing that strategy with that case?

A. Watts are always favored, and generate as many as you can. You’re not losing any real 

power production, not curtailing PV to do this.

Q. Not much incentive to buy VARs. Most utility are not allowed to recover cost of VARs 

they supply.

A. Can you contract with a party to supply VARs from inverters, thus reducing your capital 

investment of supply capacitors used in substation? 
91

A. Could be possible, but would need a guarantee for VAR delivery.

A. Had this conversation recently with PUC staffer. Said they’d be willing to take a look. 

Q. An inverter can be 95% efficient on its full rating power basis. We’re talking about 

operating the inverter at close to rated power, then adding VARs perpendicular to this as a 

vector so the increase of current is low. So the losses will be relatively small (99%+ efficient). 

You don’t need many VARs; might need only 20% of the magnitude of the real power to get 

the net effect. If inverter is run at night when no real power is being generated, it would 

become a very lossy device.

Q. Third-party owner of inverters and chargers should be compensated? How do you value 

VARs at many locations? Value is different from watts because it’s not uniform. It’s more 

conditional. The amount of money is very marginal. Do all these things as a condition of 

interconnecting. It’s being driven by two things: electric cars and PV.

Session 4 – High Penetration PV Solutions: Modeling and Studies

Modeling Tools, Existing and Future Needs / Modeling PV Systems

Abraham Ellis, Sandia National Laboratory 

Abraham Ellis has over 10 years experience in power system analysis and simulation for bulk 

system planning and operations, including the Transmission Operations Department at Public 

Service Company of New Mexico. Abraham is technical lead for renewable systems 

integration at Sandia National Laboratory coordinating various projects involving testing, 

modeling, simulation and analysis of solar and wind generation, power conversion technology 

and energy storage. He serves as Chairman of the WECC Renewable Energy Modeling Task 

Force and the IEEE Dynamic Performance of Wind Power Generation Working Group. He is 

actively involved in a number of activities related to renewable energy integration and 

modeling, under IEEE, NERC, UWIG, IEC and WECC. He is a Senior Member of IEEE and 

registered Professional Engineer in the state of New Mexico. Abraham obtained his Ph.D. and 

Masters Degrees from New Mexico State University in Electrical Engineering with a 

concentration in power systems.
92

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Modeling PV Systems in Bulk System Studies

Abraham Ellis, Sandia National Laboratories

aellis@sandia.gov

PV Systems Characteristics

• Different than conventional generators

– Collector system

– Converter interface

– Low short circuit current

– Zero inertia

– Non-dispatchable, variable

• Behavior “programmable”

– Trip thresholds

– Reactive power

– Active power 

2
93

Why Are Models Needed?

• Generator Interconnection Studies

• Grid Planning/Expansion Studies

• Evaluation of Future Scenarios

• Key questions addressed by simulation

– Does the system meet performance standards?

– How does the addition new equipment affect grid 

reliability or stability?

– What system upgrades are needed?

3

Type of Grid Planning Models

• Power flow

– Overloads, static voltage stability & control

• Dynamic

– Rotor angle stability, voltage recovery

• Short circuit

– Breaker duty, protection design/coordination

• Detailed, high-order

– Plant design, control interaction, harmonics, etc.

4

Conventional models OK for conventional CSP, but not PV
94

Desirable Characteristics of Models

5

• NERC Integration of Variable Generation Task Force (IVGTF) 

has identified the lack of industry-standard validated models 

as major barrier to renewable energy development

“Validated, generic, non-confidential, and standard power flow and 

stability (positive-sequence) models for variable generation technologies 

are needed. Such models should be readily and publicly available to power 

utilities and all other industry stakeholders. Model parameters should be 

provided by variable generation manufacturers and a common model 

validation standard across all technologies should be adopted. The NERC 

Planning Committee should undertake a review of the appropriate 

Modeling, Data and Analysis (MOD) Standards to ensure high levels of 

variable generation can be simulated.”

Source: NERC Special Report, Accommodating High Levels of Variable Generation,

http://www.nerc.com/files/IVGTF_Report_041609.pdf

WECC REMTF

• REMTF Charter

– Develop validated generic, non-proprietary, positivesequence power flow and dynamic simulation 

models for distributed and central-station solar and 

wind generation for large-scale simulations

– Issue guidelines, model documentation

– Coordinate with stakeholders groups

• Current Participants

– Sandia (lead), NREL, GE, Siemens, Satcon (program 

developers), SunPower, American Capital Energy, 

EPRI, NVEnergy, APS, SCE, PG&E, BEW, NPPT

6
95

• Need to model effects of distributed PV on bulk grid

• Implement as addition to WECC composite load model

Load Flow Model – Distributed PV

Residential

Commercial

Utility-scale PV

Transmission 

system

Distribution 

system

Unit Station 

Transformer

Pad/Pole 

Transformer

Transmission 

system

Unit Station 

Transformer (LTC)

~

DG Load

Model feeder impedance for dynamics

(e.g., WECC Composite Load Model)

Load Flow Model – Utility-Scale PV Plants

= . ... ... ... ... . ~= .

. ~

= .

. ~

= .

. ~

= .

. ~

= .

. ~

= .

. ~

= .

. ~

= .

. ~

Equivalent 

PV Feeder

Inverter

PV Array

Station 

transformer

Interconnection 

Line

Other PV plant 

Feeders

Medium Voltage 

PV Feeder

Station 

transformer

Interconnection 

Line

Equivalent PV 

Inverter 

Transformer

PV Inverter 

Transformer

Equivalent 

generator

~

Equivalencing

Req, Xeq, Beq

RTeq, XTeq

P level, Q limits & 

Q control mode 

Model interconnection line and station 

transformer explicitly, if they exist
96

1 4

2

3

5 9

7

6

SUB

8

PV Inverter

1 MW

+/-0.95 pf

PV Transformer

3 MVA

Z=6%, X/R=10

UG feeders

24 kV 

Inverter cluster

To utility 

Model station transformer and 

interconnection line explicitly, if they exist.

Example – 21 MW System

From To R X B n R n^2 X n^2

1 4 0.03682 0.00701 0.000000691 3 0.33136 0.06307 

2 4 0.02455 0.00467 0.000001036 3 0.22091 0.04205 

4 5 0.02455 0.00467 0.000001036 9 1.98816 0.37843 

3 5 0.02557 0.02116 0.000000235 3 0.23016 0.19042 

5 SUB 0.02557 0.02116 0.000000235 12 3.68251 3.04673 

6 8 0.03747 0.00868 0.000000561 3 0.33726 0.07809 

7 8 0.02455 0.00467 0.000001036 3 0.22091 0.04205 

8 9 0.02109 0.02501 0.000000199 6 0.75925 0.90025 

9 SUB 0.02109 0.02501 0.000000199 9 1.70831 2.02555 

RESULTS

Partial R sum 9.4788

Partial X sum 6.7666

N 21

Collector System Equivalent

(Same units as R, X & B data)

Req 0.021494 pu

Xeq 0.015344 pu

Beq 0.000005 pu

0.02843 j0.28430

0.00085 j0.00853 7

0.00597 j0.05970

= +

= +

+ = = MZ Z T

Teq

PV Transformer Equivalent

Collector System Equivalent on 100 MVA base, 24 kV

pu on 3 MVA base

pu on 100 MVA base

Q Q Pgen ( (PF)) MVAR

Pgen MW MW

min max tan cos 6.9

1 *21 21

1 = − = × =

= =

−

PV Generator Equivalent

Reactive control varies

Example – 21 MW System
97

Reactive Control Options

Reactive Power

S

Pad-mounted 

Transformer 

Equivalent

PV Generator 

Equivalent

Collector 

System 

Equivalent

Interconnection 

Line

POCC/POI Station 

Transformer(s)

Voltage Control

• Fixed PF/Var

• Volt/Var droop

• Closed Loop Voltage control

Reactive Power Capability of Inverters: What is the reactive power capability? What 

about partial power? Check spec sheet! Reactive Power

0.5 Prated

Prated

-0.5 Prated

0

PF = +/- 0.90 PF = +/- 0.95

Full capability at any 

operating point

Grid Voltage Monitoring 

Enabled – Unit Trips During 

L-L-L-G Fault

In this case the AC voltage drops 

instantaneously and triggers an 

“instantaneous AC under-voltage” 

trip. Inverter gating stops 

immediately and the AC contactor 

releases after a few cycles. The 

filter capacitor rings with the grid 

inductance for a short time.

Source: Colin Schauder, Satcon Technology 

Corporation - Transient Modeling for Inverter-Based 

Distributed Generation, March 2, 2010

Transient Behavior of PV Inverters
98

Grid Voltage 

Monitoring Disabled 

to Allow Ride-Through 

During L-L-L-G Fault

In this case the grid voltage 

monitoring has been disabled so 

the inverter keeps running (with 

limited 60 Hz current output).

Note the high frequency 

resonant discharge of the filter 

capacitor.

If the voltage drop is not so 

abrupt, then much less ringing 

occur.

Source: Colin Schauder, Satcon Technology Corporation - Transient Modeling for Inverter-Based Distributed Generation, March 

2, 2010

Transient Behavior of PV Inverters

Model Validation/Verification

• Laboratory testing is first step

• Also need to validate against field data

Source: Richard Bravo, SCE, 

3-phase solar inverter test 

procedures (Draft)

REMTF working with 

SCE/NREL inverter 

characterization project
99

Dynamic Models – Basic Specs

• Approximate aggregate dynamic response for entire PV plant

• Suitable for simulation of grid events

– 3-ph (up to 9 cycles) & 1-ph faults (up to 30 cycles) faults, frequency 

events, oscillatory events (up to 10 Hz bandwidth )

– Assume constant irradiance during electrical disturbance

• Model extension should handle irradiance input (user beware!)

– Protection module to mimic “LVRT” curve (piecewise linear)

• Numerically stable with time steps of 1⁄4 to 1⁄2 cycle

– Faster internal integration may be needed for some important controls

• Include existing and emerging control options & capabilities

– LVRT, Volt/Var control options, power control (ramp rate), behavior 

during/after fault, frequency support??

• Initializes from power flow without special scripts

Model Connectivity

PV Array 

Model

Inverter 

Model

Network Model 

(implemented in 

PSLF or PSS/E)

Reactive Power 

Control Model

Solar 

Irradiance

DC Voltage

DC 

Current

Desired 

Q-Axis 

Current

D- and Q-Axis 

Current

D- and Q-Axis 

Voltage

AC Bus Voltage

Initial PF

Grid Protection Model

Source: Mike Behnke, BEW Engineering – Proposal for Generic PV System Model, March 2, 2010
100

PV Array Model

0

0.2

0.4

0.6

0.8

1

1.2

1.4

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Array Current (pu)Array Power (pu)

Array Voltage (pu)

Increasing 

Irradiance

Increasing 

Irradiance

Increasing 

Irradiance

Source: Mike Behnke, BEW Engineering – Proposal for Generic PV System Model, March 2, 2010

Summary

• PV systems are different than conventional 

generation in key respects

– Low short circuit current, no inertia, collector system

– Inverter dynamic behavior can be “programmed”

• Need to make progress on PV system models to 

make solar “mainstream” 

• WECC REMTF working on model development 

and guidelines

– Goal is to meet NERC definition of adequate models

– Wide industry participation

18
101

Anti-Islanding Assurance and Approach/ Review of Standards Focused 

on Island Systems

Mike Ropp, South Dakota State University 

Michael Ropp was born in Rapid City, SD in 1967. He survived being the middle of three 

brothers and went on to earn a Bachelor's degree in Music from the University of NebraskaLincoln in 1991, playing low brass and low strings, and the Masters and Ph.D. in Electrical 

Engineering at the Georgia Institute of Technology.

Michael was a Professor of Electrical Engineering at South Dakota State University from 1999 

to 2010, and is now the founder and President of Northern Plains Power Technologies, an 

engineering services firm headquartered in Brookings, SD.

Michael’s experience is in photovoltaics; integration of distributed energy resources such as 

PV and electric vehicles into power systems; computer modeling of power systems; power 

electronics; and electric transportation. He currently lives in Brookings with his wife Susan, a 

molecular biologist, and twin children Thomas and Katherine, who continually make him 

realize how futile any attempts at prediction can be.

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Moving PV from negative load to distributed generation

Michael Ropp, N

P

P

T
102

Demands on PV inverters

• Today: negative load

– Basically a varying negative real power demand

– Voltage support—fixed or utility-controllable VAr supply

– At least neutral power quality impact

• Tomorrow: distributed generation (DG) asset

– Dynamic voltage support

– LVRT/LFRT

– System-level support functions

– Integration into EMS and ‘smart grid’ infrastructure

– Storage (either on-board or external)

– Microgrid mode?

2

N

P

P

T

Loss of mains (LoM) detection

• Inverters are required to have LoM detection 

for safety and historical reasons, and we’ll 

likely still need it in the “Smart Grid”.

3

PV

Load

To rest of system

PCC

“circuit 

interrupter”

N

P

P

T
103

PV and LoM

• Today’s anti-islanding relies on:

– Positive feedback;

– “Perturb-and-observe”, similar to impedance 

detection; and

– An assumption of a very strong grid source.

• Based on:

– Single-inverter case

– No other generation in the potential island

– “Negative load” philosophy

4

N

P

P

T

PVDG, and LoM

• Today’s anti-islanding is incompatible with high 

PV penetration or a DG philosophy

– Issues with multiple inverter case (?)

– Issues when multiple generator types present

– Incompatible with grid support functions

• Hard to distinguish between “trip” and “ride through” 

events

5

N

P

P

T
104

Today’s solution: transfer trip

Direct utility control over the inverter

Transfer trip is field-proven; utilities are 

comfortable with it

Can be very fast

Moderate to high cost 

 Point-to-point solution

Doesn’t guarantee islanding prevention unless 

every circuit interrupting device along the 

feeder is instrumented

6

N

P

P

T

Tomorrow’s LoM solutions

• One candidate: power line carrier 

communications (PLCC)

7

PV

Load

To rest of system

PCC

“circuit 

interrupter”

Rx Tx

 Works very well for islanding prevention

 Utilities have some comfort level with it

 Can be high cost—separate Tx for each feeder

 Lack of market adoption due to limited BW

 Can do little other than anti-islanding (BW again) N

P

P

T
105

Tomorrow’s LoM solutions

• Another candidate: methods based on 

synchrophasors

Can work well for

islanding detection

Can enable a host of 

additional advanced features

 Unproven (but this is changing)

 Cost uncertainty

 BW requirement uncertainty

8

N

P

P

T

Standards needs

• Standards writers are scrambling to keep up

• How much field adjustability?

• What should the LoM trip time be?

• From the system perspective, what feature set 

is desirable, and at what power or penetration 

levels?

• How to certify inverters with these features? 

(What should the tests look like?)

9

N

P

P

T
106

Thank you!

10

N

P

P

T

Distribution Impact Studies / Review of IEEE P1547.7

Robert Saint, National Rural Electric Cooperative Association 

Bob Saint has been with NRECA for over 9 years and his primary role is technical advisor for 

the transmission and distribution Engineering Committee and works with the System Planning 

Subcommittee. He has worked for rural electric co-ops, primarily distribution cooperatives for 

over 20 years in Colorado before coming to NRECA. Bob is also the Program Manager for the 

MultiSpeak Software Integration Initiative.

Bob is chairman of the IEEE P1547.7 and IEEE PES Distributed Resources Integration 

Working Group. Bob is a member of the GridWise Architecture Council and on the Governing 

Board of the NIST Smart Grid Interoperability Panel. He is a Professional Engineer in Texas 

and Virginia and a senior member of IEEE. Bob graduated from Wichita State University with 

a BS in Electrical Engineering.
107

High Penetration Photovoltaics Workshop

May 20, 2010

Denver, Colorado

Distribution Impact Studies/Review of IEEE P1547.7

Bob Saint

1547- 2008 Standard for Interconnecting Distributed Resources 

with Electric Power Systems

1547.1 - 2005 Conformance Test Procedures for Equipment 

Interconnecting DR with EPS 

1547.2 - 2008 Application Guide for IEEE 1547 Standard for 

Interconnection of DR with EPS

1547.3 - 2007 Guide for Monitoring, Information Exchange and 

Control of DR

Current 1547 Projects

P1547.4 Guide for Design, Operation, & Integration 

of Distributed Resource Island Systems with EPS

P1547.6 Recommended Practice for Interconnecting 

DR With EPS Distribution Secondary Networks

P1547.5 Guidelines for Interconnection of EPS >10 

MVA to the Power Transmission Grid 

Microgrids

IEEE 1547 Interconnection Standards

http://grouper.ieee.org/groups/scc21/index.html

P1547.7 Draft Guide to Conducting Distribution 

Impact Studies for DR Interconnection

P1547.8 (new) 

Extension of 1547, 

e.g. grid support, energy 

storage, ride-thru, etc. 
108

P1547.7 - Scope

This guide describes criteria, scope, and extent 

for engineering studies of the impact on area 

electric power systems of a distributed 

resource or aggregate distributed resource 

interconnected to an area electric power 

distribution system.

3

P1547.7 - Purpose

The creation of IEEE Std 1547 “Standard for Interconnecting 

Distributed Resources with Electric Power Systems” has led to 

the increased adoption of distributed resources (DR) 

throughout distribution systems. This document describes a 

methodology for performing engineering studies of the 

potential impact of a distributed resource interconnected to 

an area electric power distribution system. Study scope and 

extent are described as functions of identifiable 

characteristics of the distributed resource, the area electric 

power system, and the interconnection. Criteria are described 

for determining the necessity of impact mitigation.

4
109

P1547.7 – Purpose (cont.)

Establishment of this guide allows distributed resource 

owners, interconnection contractors, area electric 

distribution power system owners and operators, 

and regulatory bodies to have a described 

methodology for when distribution system impact 

studies are appropriate, what data is required, how

they are performed, and how the study results are 

evaluated. In the absence of such guidelines, the 

necessity and extent of DR interconnection impact 

studies has been widely and inconsistently defined 

and applied.

5

P1547.7 - Outline

1. Overview

1.1 Scope

1.2 Purpose

1.3 Intended Audience

1.4 Limitations

1.5 Document Structure

2. References

3. Definitions, acronyms and abbreviations

3.1 Definitions

3.2 Acronyms and abbreviations

6
110

P1547.7 – Outline (cont.)

4. General Considerations 

4.1 Potential System Impacts of DR

4.2 Classes of impact studies

4.3 Classes of tools for studying impacts

4.4 Reliability Perspectives Related to EPS and 

DR

4.5 DR owner perspective 

7

P1547.7 – Outline (cont.)

5. Assessment Methodology 

5.1 Assessment Sequence

5.2 Assessment Information

5.3 Preliminary Review

5.4 Routine Distribution Study

5.5 Special System Impact Study

8
111

P1547.7 – Outline (cont.)

6. Data Requirements 

6.1 Proposed distributed resource

6.2 Existing and planned area EPS 

6.3 Proposed interconnection equipment and 

system integration

6.4 Specialty Studies

6.5 General considerations

9

P1547.7 – Outline (cont.)

7. Operating and Configuration Considerations 

7.1 DR Considerations

7.2 Area EPS Considerations

8. Preliminary Review 

8.1 Study Types and Tools

8.2 Technical Issues

10
112

P1547.7 – Outline (cont.)

9. Routine Distribution Studies 

9.1 Study Types and Tools

9.2 Technical Issues

10. Special System Impact Studies 

10.1 Study Types and Tools

10.2 Technical Issues

11

P1547.7 – Outline (cont.)

11. Using the results of impact studies 

11.1 Mitigation of system protection concerns

11.2 Mitigation of steady-state performance 

concerns

11.3 Mitigation of power quality concerns

11.4 Mitigation of system stability concerns

12
113

P1547.7 – Next Meeting

August 10-11, 2010 – San Francisco, CA

http://grouper.ieee.org/groups/scc21/1547.7/15

47.7_index.html 

13

Contact Me

Bob Saint 

Principal Distribution Engineer, Energy & 

Environmental Policy 

National Rural Electric Cooperative 

Association (NRECA) 

Phone: (703) 907-5863 

Email: robert.saint@nreca.coop 

14
114

Session 4 Q&A: High-Penetration PV Solutions-Modeling and Studies

Audience Questions/Panel Answers

Note: This is not an exact transcription of the discussion during the Q&A session and is meant 

to be representative of the discussion during the session.

Q. Our utility uses 20-cycle reclosing. 2-sec IEEE standard interferes with the reclosers 

(which are about 1.5 sec). How are inverters affected?

A. Most inverters usually trip off at less than 2 sec.

A. The IEEE trip was meant to be “a short time,” not exactly 2 seconds.

A. 1547 has recloser coordination requirement.

A. Third requirement: Don’t cause overvoltage on feeder. Blowing off arresters in ground 

fault unless you get off very quickly. Need time-coordinated transfer trip.

A. With very low or high voltage, trip time should be lower than 2 seconds.

Q. We’re struggling with modeling of basic PV system, whether to allow it to interconnect. 

What about real-time monitoring and determining when you need to go into different modes 

for different situations?

A. Our models today are pretty simple. Need to get more sophisticated with models and 

tools.

A. We need to be able to model at many different scales. Tough problem.

Q. Rule 21 has been the most-used document over the last 10 years. Regarding the screens, 

what’s been working in CA? Need feedback.

A. We do have people from CA on P1547.7 project. If it passes the screens, what do we do 

next? That’s what we’re concentrating on.

A. Single line to ground fault and voltage excursions. Don’t permit interconnections 

without ground bank or voltage protection. Do we need high-speed modeling to figure out 

mode selection? Figuring out whether you’re approaching voltage collapse...

Q. When PV can be installed by anybody, we may not know how much PV is on the grid. 

Losing control, messing up modeling.

A. Yes, modeling is a complicated issue. The grid is robust. Uncertainty in modeling is 

accepted; we are conservative. Sensitivity studies, “what if I get it wrong?”
115

A. Wake-up call to utilities. They need to know who is connecting PV to the system! Make 

it easy to know/find out.

A. Scenario to get in our heads. We think of orderly progression to add PV to grid (not 

much guerilla solar). But let’s say it changes, with people throwing on lots of PV. Then 

what?

A. Bulk system-level model. But there is a need for modeling for day-to-day distribution 

simulation. DOE is supporting this work.

Q. Data intensity vs. value out. Massive data requirements. Use geographic models.

A. Commercial modeling developers would like someone to come up with models that 

they can plug into their application.

A. Working at NREL to develop validated models that software companies can pick up 

and put in their packages.

A. Utilities want to know what variability could do at the local level. E.g., How cloudy is 

cloudy?

A. Not just models. Need whole new modeling tool. Quasi-steady-state (QSS), for 

example. Not available now. Write our own code to make QSS dynamic simulation 

around commercial software.

A. Variability of load flows. Packages don’t offer that capability, but OpenDS (EPRI) 

does. First used for wind, now being applied to PV. 

A. Transmission planning. Resistance to adopting new models. Resistance to using new 

software. If planners are not use to something, they don’t like it. It’s difficult. Make it 

easy to translate databases from one platform to another.

A. Simulating cloud shadowing connected to GIS data. Need to simulate the patterns. 

Important if we really want to get idea.

Q. Evaluating advanced module on CymeDist. Does time analysis. Single- and 3-phase. Don’t 

need to be a programmer to enter the data.

Q. What features do we want to add to our models? Leads to chaos quickly. What are our 

objectives? What is the purpose of the study? Modeling is an art. 
116

Moving Forward with HPPV Standards and Codes / 

Discussion of Future Workshops, Webinars & Standards 

Activities 

Kevin Lynn, DOE 

During the closing remarks, there was a discussion of the new IEEE P1547.8 Draft 

Recommended Practice for Establishing Methods and Procedures that Provide Supplemental 

Support for Implementation Strategies for Expanded Use of IEEE Standard 1547 that may 

focus on resolution of many concerns of high-penetration PV deployment.

Kevin Lynn posed several questions to the audience: First step in addressing codes and 

standards (C&S) for HPPV. Do more workshops? Like this, or something else? Different 

format? Should we just focus on C&S? Just 1547? What are action items coming out of this 

workshop?

Audience Responses:

• Great session. We need a session with focal point, timeline, dates, what can/can’t be 

done, reality.

• Issues are interrelated. Difficult to talk about in isolation.

• Consensus on issues. 1547.8 being a priority for moving forward. Address the issue 

where there is consensus.

• Some presentations on bulk power efficiency and reliability and what HPPV can have, 

voltage reduction, what voltage should we target.

• Learn from experience good and bad from Europe, Germany and Spain. Some 

interaction with them? They are farther down the road than we are. Let’s not reinvent 

the wheel or repeat their mistakes.

• New PVPS Task 14, April 2010, High Penetration, IEA member countries. Just getting 

kicked off. Next meeting is in December 2010 in Denver.

• Face-to-face is better than Webinars.

• NREC, Intergeneration Task Force (IGTF), bulk generation. Discuss how this fits with 

our work.

The meeting concluded with general consensus that additional meetings, webinars and 

conference calls would be desirable. There was overwhelming agreement that developing new 

standards and codes for high-penetration PV deployment is an extremely important goal for 

utilities, industry, and government. 
117

Appendix - List of Attendees

Andrykowski, Rory National Renewable Energy Laboratory (NREL)

Asgeirsson, Hawk DTE Energy

Atkinson, Suzanne Navarro Research and Engineering/ Golden Field Office

Atmaram, Gobind Florida Solar Energy Center (FSEC)

Bank, Jason NREL

Barker, Philip Nova Energy Specialists

Bassett, David PPL Electric Utilities

Basso, Thomas NREL

Beach, Joe Colorado School of Mines

Behr, Andy Hisco

Bordine, Andrew Consumers Energy

Borgmeyer, Kevin Alliant Energy

Bower, Ward Sandia National Laboratories

Bravo, Richard Southern California Edison

Brooks, Bill Brooks Engineering

Burman, Kari NREL

Buttz, Diana Equinox Solar

Carlson, Eric SolarCity

Chakraborty,Sudipta NREL

Christensen, Ken Advanced Energy

Cisco, Dinah Salt River Project

Cleveland, Frances Xanthus Consulting International

Coddington, Michael NREL

Collins, Forrest juwi solar Inc.

Darie, Silviu EDSA Micro Corporation

Davari, Asad West Virginia University, Institute of Technology

DeBlasio, Dick NREL

Deline, Chris NREL

Ellis, Abraham Sandia National Laboratories

Enbar, Nadav EPRI

Everett, Jeff Schneider Electric

Faruque, Omar Center for Advanced Power Systems , FSU

Forrester, Dan juwi solar Inc.

German, Jeff Satcon Technology

Gilliam, Rick SunEdison

Grant, Mike Duke Energy

Gupta, Smita Itron Inc.

Gwinner, Don NREL

Hambrick, Joshua NREL

Hamm, Julia Solar Electric Power Association (SEPA)
118

Hampton, Tonja National Science Foundation

Handy, Mark KenJiva Energy Systems

Hefner, Al National Institute of Standards and Technology (NIST)

Herig, Christy SEPA

Heskin, Daryl Renewable Technologies, Inc.

Holmes, Darell Southern California Edison

Hudson, Raymond BEW Engineering

Huque, Aminul EPRI

Johnson, Lars SunPower Corporation

Johnson, Walter University of California, San Diego

Kalejs, Juris American Capital Energy

Keller, Jamie NREL

Key, Tom EPRI

Kobusch, Andrew Navarro Research & Engineering

Krauze, Richard Renewable Energy Advisor

Kroposki, Ben NREL

Kueck, John Oak Ridge National Laboratory

Kulick, John Siemens Corporation

Kushner, Linda Progress Energy

Kuszmaul, Scott Sandia National Laboratories

Lenox, Carl SunPower Corporation

Lew, Debra NREL

Liang, Nathan Hawaiian Electric Company

Lubkeman, David KEMA, Inc.

Lynn, Kevin U.S. Department of Energy (DOE)

Mander, Art Tri-State G&T

Manjrekar, Madhav Siemens Corporate Research

Mather, Barry NREL

McDonnell, Chad Denver Investments Wealth Management

McNutt, Peter NREL

McPhail, Keith GST

Meeker, Rick FSU Center for Advanced Power Systems

Mensah, Adje Petra Solar

Metzger, Thomas Navarro Research & Engineering, Inc.

Mignogna, Richard Colorado PUC

Miklos,Todd Advanced Energy Industries Inc. - Solar Inverters

Muller, Matthew NREL

Nasr, Elie SMA

Neal, Russell Southern California Edison

Nichols, David Altairnano

Nicole, Kristen Sentech

Novachek, Frank Xcel Energy

Nowicki, Genevieve Solar Power Partners
119

Nuesken, Sven Navarro Research & Engineering

Nugent, Patricia Dow Chemical

OBrien, Kathleen GE Global Research

Ong, Sean NREL

Orwig, Kirsten NREL

Palomino, Ernie Salt River Project

Pardington, Chris Xcel Energy

Paylan, Andy Semikron, USA, Inc.

Payne, Jim DOE

Perez, Rudy Southern California Edison

Pisklak, Stephen Dow Chemical

Plank, William juwi solar Inc.

Raffaelle, Ryne NREL

Reedy, Robert FSEC/University of Central Florida

Rever, Bill BP Solar

Rice, Brent NREL

Roesch, Jeff Advanced Energy Industries Inc.

Ropp, Michael Northern Plains Power Technologies

Saint, Robert National Rural Electric Cooperative Association

Sanchez, Manuel Public Service Company of New Mexico

Schmitt, Bob SMA America

Scholl, Kent Xcel Energy

Seal, Brian EPRI

Sedghisigarchi, Kourosh West Virginia University Institute of Technology

Sheaffer, Paul Resource Dynamics Corporation

Sheehan, Michael Interstate Renewable Energy Center (IREC)

Sherwood, Larry Solar America Board for Codes & Standards (Solar ABCs)

Small, Forrest Navigant Consulting

Stafford, Byron NREL

Starrs, Tom SunPower Corporation

Suryanarayanan, Sid Colorado School of Mines

Tatsumi, Haruhiko SANYO North America Corporation

Taylor, Mike SEPA

Thomas, Holly DOE

Toe, Sylvester Georgia Power Company

Tuttle, Julie NREL

Van Geet, Otto NREL

Vartanian, Charles A123 Systems

Walker, Michael ArgusON

Walling, Reigh GE Energy

Washom, Byron University of California San Diego, Strategic Energy Initiative

Welch, Robert KEMA, Inc.

Williams, Lucius Tennessee Valley Authority
120

Worrell , Lynn Xcel Energy

Yohn, Thomas Xcel Energy
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4. TITLE AND SUBTITLE

High-Penetration Photovoltaic Standardes and Codes Workshop:

Workshop Proceedings

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

5b. GRANT NUMBER

5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S)

M. Coddington, B. Kroposki, T. Basso: NREL

K. Lynn: Department of Energy, EERE

C. Herig: Solar Electric Power Association

W. Bower: Sandia National Laboratories

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NREL/TP-550-48378

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14. ABSTRACT (Maximum 200 Words)

Effectively interconnecting high-level penetration of photovoltaic (PV) systems requires careful technical attention to 

ensuring compatibility with electric power systems. Standards, codes, and implementation have been cited as major 

impediments to widespread use of PV within electric power systems. On May 20, 2010, in Denver, Colorado, the 

National Renewable Energy Laboratory, in conjunction with the U.S. Department of Energy (DOE) Office of Energy 

Efficiency and Renewable Energy (EERE), held a workshop to examine the key technical issues and barriers 

associated with high PV penetration levels with an emphasis on codes and standards. This workshop included 

building upon results of the High Penetration of Photovoltaic (PV) Systems into the Distribution Grid workshop held in 

Ontario California on February 24-25, 2009, and upon the stimulating presentations of the diverse stakeholder 

presentations.

15. SUBJECT TERMS

HPPV; photovoltaic; electric power systems; EPS; DOE; NREL; high-penetration photovoltaics; standards; codes 

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