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

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

Technical Report

NREL/TP-7A40-66056

December 2018

Best Practices for Operation and 

Maintenance of Photovoltaic and 

Energy Storage Systems; 3rd Edition

National Renewable Energy Laboratory, 

Sandia National Laboratory, SunSpec Alliance, 

and the SunShot National Laboratory Multiyear Partnership 

(SuNLaMP) PV O&M Best Practices Working Group
NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

This report is available at no cost from the National Renewable Energy

Laboratory (NREL) at www.nrel.gov/publications.

Contract No. DE-AC36-08GO28308

National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, CO 80401

303-275-3000 • www.nrel.gov

Technical Report

NREL/TP-7A40-66056

December 2018

Best Practices for Operation and 

Maintenance of Photovoltaic and Energy 

Storage Systems; 3rd Edition

National Renewable Energy Laboratory, 

Sandia National Laboratory, SunSpec Alliance, 

and the SunShot National Laboratory Multiyear Partnership 

(SuNLaMP) PV O&M Best Practices Working Group

Suggested Citation 

National Renewable Energy Laboratory, Sandia National Laboratory, SunSpec Alliance, and 

the SunShot National Laboratory Multiyear Partnership (SuNLaMP) PV O&M Best Practices 

Working Group. 2018. Best Practices for Operation and Maintenance of Photovoltaic and 

Energy Storage Systems; 3rd Edition. Golden, CO: National Renewable Energy Laboratory. 

NREL/TP-7A40-66056. https://www.nrel.gov/docs/fy19osti/66056.pdf.
NOTICE

This work was authored by the National Renewable Energy Laboratory, operated by Alliance for Sustainable 

Energy, LLC, for the U.S. Department of Energy (DOE) under Contract No. DE-AC36-08GO28308. Funding 

provided by the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy Solar Energy 

Technologies Office and SuNLaMP Agreement 32315.The views expressed herein do not necessarily represent 

the views of the DOE or the U.S. Government.

This report is available at no cost from the National Renewable 

Energy Laboratory (NREL) at www.nrel.gov/publications.

U.S. Department of Energy (DOE) reports produced after 1991 

and a growing number of pre-1991 documents are available 

free via www.OSTI.gov.

Cover Photos by Dennis Schroeder: (clockwise, left to right) NREL 51934, NREL 45897, NREL 42160, NREL 45891, NREL 48097, 

NREL 46526.

NREL prints on paper that contains recycled content.
iii

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Acknowledgments

The National Renewable Energy Laboratory (NREL), Sandia National Laboratories (SNL), 

SunSpec Alliance, and Roger Hill were supported by the U.S. Department of Energy (DOE)

Solar Energy Technologies Office (SETO) under Agreement 32315 in the production of this 

report. The authors would like to thank the following working group contributors to this report.

Working Group Coordinator

Dylan Tansy, SunSpec Alliance

Support Team

Ammar Qusaibaty, SETO

Andy Walker, NREL

Eric Lockhart, NREL

Travis Lowder, NREL 

Kari Burman, NREL, ret.

Geoff Klise, SNL

Roger Hill, consultant

Tom Tansy, SunSpec Alliance

Tim Keating, SunSpec Alliance

Olga Lavrova, SNL

Anil Pochiraju, SunSpec Alliance

Jessie Deot, SunSpec Alliance

Bob Fox, SunSpec Alliance

Chuck Kurnik, NREL

Interviewees

Greg Sellers, Clean Power Finance

Jean Paul La Marche, Main Street Power

Dirk Michaels, K & L Gates

Rue Philips, True South

David Kenny, Sunrun 

Leigh Zanone, Meteocontrol

Paul Lanning, Lightbox Energy

Sarah Disch, Wells Fargo

Andrew Truitt, Distributed Resource Ventures

Marco Lopez, Alectris

Ross Biesemeyer, First Solar

Laks Sampath, Alectris 

Mark Berger, NextGrid Technologies
iv

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

2017 Working Group Roster

Eric Alderman, Airphrame

Carlos Alves, Nextera Energy Services

Rob Andrews, Queen's University

John Balfour, High Performance PV

Stephen Barkaski, FLS Energy

Jimmy Bergeron, SolarCity

Michael Bolen, Electric Power Research Institute 

Peter Bostock, VDE Americas

Alex Bradley, DuPont

Bill Brooks, Brooks Engineering

Paul Brucke, Brucke Engineering

Jon Budreski, Air Shark

Kari Burman, NREL

Joe Cain, Solar Energy Industries Assoc.(SEIA)

Nathan Charles, Enphase Energy

Daisy Chung, Solar Electric Power Assoc. (SEPA)

Joe Cunningham, Centrosolar

Jessie Deot, SunSpec

Skip Dise, Clean Power Research

Ron Drobeck, System Operations Live View 

(SOLV)

Nadav Enbar, Electric Power Research Institute

Cary Fukada, OpTerra Energy Services

Cyrille Godenot, Schneider Electric

Danya Golan, Solar Edge

Steve Hanawalt, Power Factors LLC

Chris Henderson, Ameresco

Martin Herzfeld, independent consultant

Roger Hill, consultant

Bill Hoffer, Sunergy Engineering Services

Rebekah Hren, Solar Energy International

Sandeep Jadhav, Mahindra Susten

Dirk Jordan, NREL 

Raymond Kaiser, Amzur Technologies

Joe Kastner, Radian Generation

Tim Keating, SunSpec

Jason Kechijian, SolBright

George Kelly, Sunset Technology, Inc.

Geoff Klise, SNL

Pramod Krishnani, Terraform Power

Bhushan Kunjeer, Enersaas

Sarah Kurtz, NREL

Paul Lanning, Lightbox Energy

Olga Lavrova, SNL

Richard Lawrence, Institute for Building Technology 

and Safety (IBTS)

Eric Lockhart, NREL

Mike Loeser, Strata Solar

Jaya Mallineni, Nexamp Inc.

Joseph McCabe, Renewable Energy Champion

Ryan McCauly, Tritium3

Dirk Michels, Ballard Spahr

Reegan Moen, SOLV

Jamie Mordarski, SMA America

Jesse Moses, Swinerton Renewable Energy

Matt Murphy, Borrego Solar

Sean Murphy, SolBright Renewable Energy, LLC

Eric Nessl, Strata Solar

Christina Nichols, DOE

Don Nista, Cypress Creek Renewables

Angelo Purpura, SOLV

Michael Rogerson, Solar Edge

AJ Rossman, Smart Resource

Mary Rottman, Rottman Associates

Laks Sampath, Alectris

Jadhav Sandeep, Mahindra Susten

Rudy Saporite, IBTS

Kenneth Sauer, DNVGL

Thomas Sauer, Exxergy

Ulrich KW Schwabe, SEGIS-AC awardees

Bill Shisler, NRG

Jeff Southard, Juniper Unmanned Inc.

Jeff Spies, North American Board of Certified Energy 

Professionals (NABCEP)

Kristy Straiton, American Society of Testing and 

Materials (ASTM)

Dylan Tansy, SunSpec

Tom Tansy, SunSpec

Abhay Tilwankar, Mahindra Susten

Ernest (Ernie) Tom, Salt River Project

Will Troppe, Power Factors LLC

Andrew Truitt, Dividend Finance

Andy Walker, NREL

Carter Wall, Franklin Beach Energy

John Williamson, Array Technologies

Gordon Woodcock, Taitem Engineering, PC

Leigh Zanone, 8minutenergy
v

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

2016 Working Group Roster

Eric Alderman, Airphrame

Carlos Alves, Nextera Energy Services

Rob Andrews, Heliolytics Inc. 

John Balfour, High Performance PV

Jimmy Bergeron, SolarCity

Michael Bolen, Electric Power Research 

Institute (EPRI)

Peter Bostock, VDE Americas

Alex Bradley, DuPont

Bill Brooks, Brooks Engineering

Paul Brucke, Brucke Engineering

Jon Budreski, Air Shark

Ben Compton, NextPhase Solar

Joe Cunningham, Centrosolar

Skip Dise, Clean Power Research

Ron Drobeck, SOLV

Nadav Enbar, EPRI

Cary Fukada, OpTerra Energy Services

Jeff Gilbert, Vigilant Energy Management

Danya Golan, SolarEdge

Shannon Grein, Empyrean Electric

Steve Hanawalt, Power Factors LLC

Chris Henderson, Ameresco

Martin Herzfeld, consultant

Roger Hill, consultant

Bill Hoffer, Sunergy Engineering Services PLLC

Rebekah Hren, Solar Energy International

Joe Kastner, Radian Generation

Jason Kechijian, SolBright

George Kelly, Sunset Technology, Inc.

Ken Kostok, Alectris

Pramod Krishnani, Terraform Power

Bhushan Kunjeer, SunEdison

Sarah Kurtz, NREL

Paul Lanning, Lightbox Energy 

Olga Lavrova, SNL

Richard Lawrence, National Accreditation Board 

for Certified Energy Professionals (NABCEP)

Mike Loeser, Strata Solar

Jaya Mallineni, Nexamp Inc.

Joseph McCabe, Renewable Energy Champion

Ryan McCauly, Tritium3

Scott McWilliams, Sematech

Dirk Michels, Ballard Spahr

Reegan Moen, Swinerton Renewable Energy

Jamie Mordarski, SMA America LLC

Jesse Moses, Swinerton Renewable Energy

Matt Murphy, Borrego Solar

Sean Murphy, SolBright Renewable Energy, LLC

Eric Nessl, Strata Solar

Christina Nichols, DOE

Don Nista, Cypress Creek Renewables

Rue Phillips, True South Renewables

Angelo Purpura, Swinerton Renewable Energy

Michael Rogerson, SolarEdge

AJ Rossman, Smart Resource

Mary Rottman, Rottman Associates

Laks Sampath, Alectris

Jadhav Sandeep, Mahindra Susten

Rudy Saporite, IBTS

Ulrich Schwabe, SEGIS-AC awardees

Bill Shisler, NRG 

Jeff Spies, NABCEP

Kristy Straiton, ASTM

Abhay Tilwankar, Mahindra Susten

Ernest Tom, Salt River Project

Will Troppe, Power Factors LLC

Andrew Truitt, Dividend Finance

Carter Wall, Franklin Beach Energy

David Walter, Hartford Steam Boiler

Gordon Woodcock, Taitem Engineering, PC

Leigh Zanone, Meteocontrol
vi

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List of Acronyms

AC alternating current

AMI advanced metering infrastructure

AMR automated meter reading

ANSI American National Standards Institute

ASNT American Society of Non-destructive Testing

ASTM

BLAST

American Society for Testing and Materials

Battery Lifetime Analysis and Simulation Tool

CAD computer-aided design

CT current transformer

DAS data acquisition system

DC

DOD

direct current

depth of discharge

DOE U.S. Department of Energy

EAM enterprise asset management

EPC engineering, procurement, and construction

EPDM ethylene propylene diene monomer

EPRI Electric Power Research Institute

ERP enterprise resource planning

EVA ethylene vinyl acetate

FEMP Federal Energy Management Program

FERC

GFI

GHI

Federal Energy Regulatory Commission

ground fault interruption

global horizontal insolation

GO generator owner

GOP generator operator

GSU generator step-up

IBTS Institute for Building Technology and Safety

IEC International Electrotechnical Commission

IECRE IEC Renewable Energy

IEEE Institute of Electrical and Electronics Engineers

IGBT insulated-gate bipolar transistor

IP Internet Protocol

IRR internal rate of return

IT information technology

I-V current voltage

KPI

kVAR

LC

key performance indicator

thousands of Volts-Amps Reactive

lithium carbon

LCOE

LFP

LLC

LMO

LTO

MC

levelized cost of energy

lithium iron phosphate

limited liability corporation

lithium manganese oxide

lithium titanate

multi-crystalline or multiple-connector
vii

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MFS maximum foreseeable loss

MLPE module-level power electronics

MPPT maximum power-point tracking

NABCEP

NCA

North American Board of Certified Energy Practitioners

Nickel cobalt aluminum

NCU Network Control Unit

NERC

NFPA

North American Electric Reliability Corporation

National Fire Protection Agency

NLE

NMC

normal loss expected

nickel-manganese-carbon

NREL National Renewable Energy Laboratory

OEM original equipment manufacturer

O&M operations & maintenance

OMC outside management control

OSHA Occupational Safety and Health Administration

PML probable maximum loss

POA plane of array

PPA power purchase agreement

PPE personal protective equipment

PR performance ratio

PV photovoltaics

PVC

PVPS

polyvinyl chloride

Photovoltaic Power Station

RCRA Resource Conservation and Recovery Act

REC renewable energy certificate

RMS root mean square

ROI return on investment

SAM System Advisor Model

SAPC Solar Access to Public Capital

SBS

SCADA

styrene butadiene styrene

Supervisory Control and Data Acquisition

SDO

sf

standards developing organization

square foot

STC

TOD

standard test condition

Time of Day

TPO thermoplastic polyolefin

UAV unmanned aerial vehicle

UL

UN

UPS

UV

VLA

VRLA

Underwriters Laboratories

United Nations

Uninterruptible Power Supply

ultraviolet

vented lead acid

valve regulated lead acid
viii

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Table of Contents

Acknowledgments ..................................................................................................................................... iii

Working Group Coordinator .................................................................................................................iii

Support Team ........................................................................................................................................iii

Interviewees...........................................................................................................................................iii

2017 Working Group Roster ................................................................................................................. iv

2016 Working Group Roster .................................................................................................................. v

List of Acronyms........................................................................................................................................ vi

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

1.1 Purpose.......................................................................................................................................... 1

1.2 Background—The PV O&M Working Group .............................................................................. 1

2 O&M and the Financing of PV Assets ................................................................................................ 3

3 Scope and Prerequisites for a Successful O&M Program ............................................................... 5

3.1 Scope of O&M Guide ................................................................................................................... 5

3.2 Prerequisites for a Successful O&M Program .............................................................................. 5

4 Definitions ............................................................................................................................................. 8

5 Dependencies on PV System Type, Site, and Environmental Condition...................................... 11

5.1 Electrical System......................................................................................................................... 11

5.2 Central, String, DC-Optimized, or Micro-Inverter Configuration .............................................. 12

5.3 Roof Maintenance Related to PV System ................................................................................... 15

5.4 Ballasted or Attached Rack ......................................................................................................... 19

5.5 Ground Mount............................................................................................................................. 20

5.6 Tracking Mounts......................................................................................................................... 23

5.7 Environmental Conditions........................................................................................................... 25

5.8 Site Access .................................................................................................................................. 31

5.9 Dependencies for PV Plus Storage Systems ............................................................................... 32

5.10 System and Site Considerations Checklist .................................................................................. 37

6 System Performance and O&M Plans .............................................................................................. 38

6.1 Planning for System Performance............................................................................................... 38

6.2 The PV O&M Plan...................................................................................................................... 45

6.3 Use of O&M Plan........................................................................................................................ 46

6.4 Document Management and Record Keeping............................................................................. 49

6.5 PV Plant Operations.................................................................................................................... 50

6.6 Preventive/Scheduled Maintenance ............................................................................................ 53

6.7 Corrective Maintenance .............................................................................................................. 55

6.8 PV Module Degradation Rate; Degradation in Energy Storage Capacity................................... 60

6.9 Example Work Statements.......................................................................................................... 61

6.10 End-of-Performance Period......................................................................................................... 61

6.11 Evaluation of O&M Plans........................................................................................................... 64

7 Health and Safety................................................................................................................................ 66

7.1 Energy Storage Safety Considerations........................................................................................ 67

8 O&M Provider Qualifications and Responsibilities......................................................................... 70

8.1 Qualifications of Plant Operators................................................................................................ 70

8.2 Qualifications of Service Providers............................................................................................. 70

8.3 Financial Solvency ...................................................................................................................... 71

8.4 Insurance ..................................................................................................................................... 71

8.5 Redundancy in Service Providers................................................................................................ 73

9 System Monitoring, Software Solutions, and Data Management.................................................. 74

9.1 DC Array Inspection ................................................................................................................... 74

9.2 Energy Storage System Inspection and Testing .......................................................................... 78
ix

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9.3 Instrumentation............................................................................................................................ 81

9.4 Data Presentation......................................................................................................................... 84

9.5 Quality of Monitoring Equipment............................................................................................... 85

9.6 Transparency of Measurement Protocols and Procedures........................................................... 85

9.7 Software Solutions ...................................................................................................................... 86

10 O&M Implementation Strategies ....................................................................................................... 91

10.1 O&M Contract and Performance Guarantee ............................................................................... 91

11 Estimating PV O&M Costs................................................................................................................. 93

12 PV O&M Cost Survey Information and Trends................................................................................ 97

References................................................................................................................................................. 98

Appendix A. System Performance Guarantee Example Calculation (Without Shade Correction). 103

Exhibit ................................................................................................................................................ 103

Appendix B. PV O&M Cost Model Preventive Maintenance Service Descriptions .......................... 107

Appendix C. PV O&M Cost Model Corrective Maintenance Service Descriptions........................... 116

Appendix D. PV O&M Scope of Work, Salary, and Qualifications ..................................................... 121

Appendix E. Examples of Scope of Work Documents........................................................................ 123

Example Performance Work Statement ............................................................................................. 126

Example Description of Maintenance Services for Commercial Rooftop Installations..................... 126

Example Description of Maintenance Services for Commercial Ground Mount Installations.......... 129

Example Description of Operations Services..................................................................................... 131

Appendix F. Using Model PV System Availability Terms for Contracted O&M................................ 137
x

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List of Figures

Figure 1. Two strings of batteries are recommended in design to allow O&M service of one string while 

the other string serves the purpose. Photo by Andy Walker, NREL ......................................... 7

Figure 2. Maintenance of wire management systems depend on plastic wire ties and grommets, which can 

break or pinch wires (left); exposure to sunlight; wind and weight of ice (center); and access 

by chewing rodents (right). Photos by Andy Walker, NREL.................................................. 12

Figure 3. A best practice is to run a slip sheet continuously under rack members to avoid direct contact 

with the roof membrane. In this photo, direct contact of the rack is cutting into the roof 

surface. Photo by Norm Crouse, Lightbox Energy................................................................. 18

Figure 4. Sheep, but not goats or cattle, can be employed for vegetation control. Photo by Eliza Hotchkiss, 

NREL...................................................................................................................................... 22

Figure 5. Drainage and storm-water run-off are difficult to improve after the PV array is installed, 

requiring diligence in design and construction of storm-water management systems. Photo 

by Andy Walker, NREL .......................................................................................................... 23

Figure 6. Although improving annual energy delivery, especially in summer, tracking mechanisms and 

controls require regular maintenance to be effective. Photo by Andy Walker, NREL............ 25

Figure 7. Module soiling can often be traced to a source, such as construction-site dust, resulting in about 

5% loss. Photo by Andy Walker, NREL ................................................................................. 28

Figure 8. Bird populations are a source of soiling, as well as nests that need to be removed and seeds that 

can sprout on arrays. Photo by Andy Walker, NREL.............................................................. 29

Figure 9. Snow is an environmental condition that both reduces performance and complicates provision of 

O&M services, but removal of snow off arrays is not recommended due to the potential for 

damage. Photo by Andy Walker, NREL ................................................................................. 30

Figure 10. It might be the responsibility of the O&M provider to respond and ensure that storm damage is 

rendered safe both in terms of electrical hazards and loose components following an extreme 

weather event such as this damage in St. Croix in 2017. Photo by Andy Walker, NREL ...... 31

Figure 11. Different definitions of Performance Ratio (as per IEC 61724) result if different values 

compared here for a sample of 2,200 PV systems. PR-1 is actual production divided by STC 

rating and normalized for insolation; PR-2 is actual production divided by PTC rating and 

normalized for insolation; and PR-3 is actual production divided by PTC rating normalized 

for insolation, ambient temperature, age of system, and balance of system efficiency. A 

value of PR-3 = 100% means the system is performing as expected. Figure by Andy Walker, 

NREL using data from oSPARC 2018.................................................................................... 41

Figure 12. Short-term test of PV Arrays on Carport of Degatau Federal Building and Courthouse, Puerto 

Rico, showing performance commensurate with calculated expected value, including that 

power is limited to 100 kW by the capacity of the inverter on this 125 kW DC system. This 

test was conducted over a 1-hour period that included sunny periods (points to the right) and 

passing clouds (points to the left side of the graph). Figure and photo by Andy Walker, 

NREL...................................................................................................................................... 42

Figure 13. The National Park Service budgets, ideally, $100,000 per year for O&M of this PV energy 

storage system (308 kW PV; 1,920 kWh battery) on Alcatraz Island. Photo by Andy Walker, 

NREL...................................................................................................................................... 54

Figure 14. Failure in materials and workmanship, such as encapsulant of this module, are often covered 

by product manufacturer’s warranty. Photo by Andy Walker, NREL .................................... 56

Figure 15. Snail trails in encapsulant are attributed to cracks in cells caused by flexure of the panel at the 

factory, shipping, or installation. The module would be covered by the performance warranty 

only if the cracks isolate fragments of the cell and reduce the output over time. Photo by 

Andy Walker, NREL ............................................................................................................... 57
xi

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Figure 16. Failure to follow product box handling and storage requirements can cause damage when 

moved and void a warranty. The umbrella symbol on this box indicates it should be kept dry 

and the box might fail when picked up with a forklift. Photo by Andy Walker, NREL ......... 59

Figure 17. Premature failure of a lead-acid battery caused by low state-of-charge for an extended period 

of time can be avoided only by periodic fully saturated charge of the battery. A battery can 

recover from amorphous sulfation; but, given time to crystalize, the degradation in capacity 

and efficiency is permanent and can cause swelling and breakage of the battery jar. Photo by 

Andy Walker, NREL ............................................................................................................... 63

Figure 18. Cracked or peeling backsheet leads to water infiltration and ribbon corrosion. Photo by Andy 

Walker, NREL ........................................................................................................................ 75

Figure 19. Manual inspection and testing requires opening NEMA-rated enclosures. The integrity of any 

enclosure seal must be restored after opening to avoid moisture damage as in this module 

junction box. Photo by Andy Walker, NREL.......................................................................... 76

Figure 20. High-resolution infrared aerial imaging can identify failed strings, modules, and cells within 

modules, as shown on this image. Image by Rob Andrews, Heliolytics Inc. ......................... 78

Figure 21. Infrared imaging exposes an imbalance of current through three parallel strings of batteries (the

string on top is cooler) and exposes the cause of the problem, which is a battery terminal 

connection that is badly corroded. Photo by Owen Roberts, NREL....................................... 80

Figure 22. Probability that the reserve account amount will be sufficient to cover costs in a given year as a 

function of the fraction of the total number of a type of component and the probability of 

failure of the type of component in that given year. Figure by Andy Walker, NREL ............ 94

Figure 23. Results of PV O&M cost model for 10-MW ground-mount PV system with tracking, central 

inverters, and pollen as an environmental condition. Figure by Andy Walker, NREL........... 96

Figure F-1. Model Availability Terms...................................................................................................... 140
xii

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List of Tables

Table 1. Cost of String, DC-Optimized, Central, and Micro-Inverter Replacement (Feldman et. al, 2018 13

Table 2. Service Costs for Different Types of Roofs

a (HomeAdvisor 2016; HomeAdvisor 2008)............ 16

Table 3. Representative PV Module Degradation Rates (Jordan and Kurtz 2012)..................................... 60

Table 4. Codes and Standards Related to Energy Storage System Maintenance (PNNL and Sandia 2016)

................................................................................................................................................ 68

Table A-1. Example of Annual Degradation included in tabulation of Availability and Performance Ratio

.............................................................................................................................................. 105

Table B-1. Service Descriptions for Preventive Maintenance Selections Available in the PV O&M Cost 

Model Tool........................................................................................................................... 107

Table C-1. Service Descriptions for Corrective Maintenance Selections Available in the PV O&M Cost 

Model ................................................................................................................................... 116

Table D-1. Qualifications and Loaded Labor Rates for PV O&M Service Providersa

............................. 121
1

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1 Introduction

The goal of this guide is to reduce the cost and improve the effectiveness of operations and 

maintenance (O&M) for photovoltaic (PV) systems and combined PV and energy storage 

systems. Reported O&M costs vary widely based on the requirements of the system and the 

nature of the O&M contract, but a more standardized approach to planning and delivering O&M 

has the potential to both decrease costs and make those costs more predictable over time. 

However, the bigger payoff for improved O&M is increased performance. Actuarial data indicate 

that comprehensive PV-only system O&M could improve the average performance ratio (PR, 

adjusted for age and temperature) of systems from 91.7 to at least 95%, which is a substantial 

increase in revenue and environmental benefits of a PV system (oSPARC 2018). Drivers to 

improve O&M include the following: increase efficiency and energy delivery (kWh/kW),

decrease downtime (hours/year), extend system lifetime (e.g., from 25 to 40 years for PV 

modules), reduce cost of O&M ($/kW/year), ensure safety and reduce risk, enhance appearance,

and meet requirements of financing and warranties.

1.1 Purpose

This guide encourages adoption of best practices to reduce the cost of O&M and improve the 

performance of fielded systems, but it also enhances financing of new projects by making cost 

more predictable and mitigating performance risk. This guide also includes technical 

improvement opportunities in the design of systems and in specification of equipment because 

high-quality system deployment improves lifetime project performance and energy production 

while reducing, or at least optimizing, costs to deliver an O&M program. This guide provides 

recommendations that increase the effectiveness of O&M services; reduce O&M costs, improve 

solar asset transparency for investors and rating agencies; provide an industry framework for 

quality management; and reduce transaction costs.

Most of the content of this guide relates to utility-scale or larger distributed generation PV 

systems, and also to portfolios or fleets of systems, but some sections are equally applicable to 

smaller distributed-generation or residential systems. The reader is referred to the Table of 

Contents to help find content applicable to system by size, type, and market sector.

1.2 Background—The PV O&M Working Group

This is the 3rd edition of this guide. The 2nd edition is available at 

https://www.nrel.gov/docs/fy17osti/67553.pdf, which was a successful publication with an 

audience of almost 12,000 readers. The1st edition was an “interim” version issued in 2015, which 

is available at http://www.nrel.gov/docs/fy15osti/63235.pdf. These guides were developed by 

facilitated working groups, the membership of which is listed in the front matter. The Solar 

Access to Public Capital (SAPC) Working Group was convened in 2014 to open capital market 

investment in the solar asset class and consisted of solar developers, financiers and capital 

managers, law firms, rating agencies, accounting and engineering firms, and other stakeholders 

engaged in solar asset deployment. In 2016, a subset of the SAPC Working Group was merged 

with Sandia National Laboratories’ Technical O&M Working Group to unify efforts by the U.S. 

Department of Energy (DOE) to improve O&M practices, data standards, and costs. This 

combined body—the PV O&M Working Group—is administrated by the National Renewable 
2

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Energy Laboratory (NREL), Sandia National Laboratories, SunSpec Alliance, and Roger Hill, 

and it is supported by the DOE SunShot Initiative (SuNLaMP program). 

Other products of the PV O&M Working Group that support and inform this guide include two 

actuarial databases (the Open System Performance and Reliability Clearinghouse (oSPARC, 

2018) performance database and the PV Reliability Operation and Maintenance database of 

failure and reliability data) and the PV O&M Cost Model (initially a spreadsheet model; now an 

online tool to estimate annual O&M costs called Asset Performance Suite at 

http://APsuite.SunSpec.org).

1.2.1 Updates to the 3rd Edition

This edition includes the integration of O&M considerations for systems that combine PV and 

energy storage. The storage-related additions to the 3rd edition are integrated throughout the 

document. The scope of the types of battery technologies and the battery use cases considered 

are detailed in Section 3; system dependencies specific to storage are listed in Section 5; O&M 

and end-of-performance period issues are addressed in Section 6; safety in Section 7; controls 

and monitoring considerations in Section 9; and cost estimate guidance is presented in Section 

11. 

Other updates to the guide include the following:

• Expanded and created new section on health and safety considerations 

• Developed the discussion on selecting and implementing software solutions in the 

context of the full life cycle of PV-only and PV plus storage systems

• Presented model PV system availability terms for contracted O&M

• Described a scorecard methodology to evaluate an O&M program

• Added O&M actions to prepare for and recover from extreme weather events, such as 

hurricanes.
3

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2 O&M and the Financing of PV Assets

An effective O&M program enhances the likelihood that a system will perform at or above its 

projected production rate and cost over time. Therefore, it reinforces confidence in the long-term 

performance and revenue capacity of an asset. Historically, O&M practices and approaches have 

not been standardized, and instead, they were implemented in various proprietary methods. This

approach can increase the cost to projects and portfolios, as well as raise the perception of risk 

from investors. Specific recommendations from the PV O&M Working Group to reduce 

variations in O&M practices include:

• Define performance metrics uniformly. A system characterized by a “Guarantee” to 

deliver 1,000 MWh/year would be difficult to compare and bundle with another that has a 

“Key Performance Indicator” to be operational 90% of the time. Investors need 

performance metrics and evaluation methods to be the same across a bundle of assets.

• Refer to specified standards. Practices and delivery of O&M services differ, and investors 

need to know that an existing system has been maintained according to standard 

definitions and criteria.

• Make cost estimates uniform and predictable. Differences in types of systems as well as

geographic location and climate conditions can confound securitization. Investors want to 

know how much it will cost to perform required O&M and secure the performance of the 

investment. Cost estimates must be uniform and predictable so that they can be bundled, 

yet they should reflect the factors that cause O&M costs to vary from site to site.

Many investors are more interested in reducing risk than maximizing internal rate of return 

(IRR). Investors would prefer 100% certainty of achieving a 5% IRR over a 50% certainty of 

achieving a 10% IRR, even though the two are of statistically equivalent value. Investors will 

first make an investment decision based on mitigating performance risk with effective O&M;

and then the financing rates are finally determined mainly through competition from other 

financiers (e.g., competing banks). Standardization of O&M practices will facilitate investor 

analyses of risk factors and can reduce the time and cost to perform due diligence. Risk reduced 

by effective O&M will enable more banks to qualify more projects, and that will eventually 

increase competition and reduce borrowing costs.

Although PV systems may have different origins, they can be pooled together in portfolios—and 

thus, be financed more efficiently—if they adhere to clear, industry-accepted business and 

technical guidelines regarding O&M. Industry groups important to this effort include the 

Institute for Building Technology and Safety (IBTS), SunSpec Alliance, and North American 

Board of Certified Energy Practitioners (NABCEP). National and international standardsdeveloping organizations (SDOs) important to this effort include the American National 

Standards Institute (ANSI), Institute of Electrical and Electronics Engineers (IEEE), 

International Electrotechnical Commission (IEC), and ASTM International (formerly known as 

the American Society for Testing and Materials [ASTM]).

Two SDOs—the ASTM and IEC—are coordinating directly with NREL and Sandia National 

Laboratories to develop O&M standards, with drafts being made available to working group 

members. These standards are primarily technical in nature and focus on life cycle management, 

design for O&M guidelines, and detailed maintenance processes and procedures. Representatives 

from ASTM and IEC were involved in developing these best practices. This document is offered 
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as what is referred to in the standards-making process as “research” to be considered as the IEC 

and ASTM committees develop the language of the standards. The IECRE, which is the 

Renewable Energy IEC system for certification to standards, will receive this guide for 

consideration of recommendations. It will serve as input to PV industry certification and 

compliance approaches and practices.

Combining PV with storage brings additional financial considerations. Battery energy storage 

can resolve technical barriers to grid integration of PV and increase total penetration and market 

for PV. Storage can add to the value propositions that PV projects can access and improve the 

value of PV but also can increase overall costs and add complexity to weigh against the benefits.

Benefits of integration of storage include: shift when PV generation is used, which has an array 

of potential benefits such as savings on time-of-use and demand charge reductions; avoid net 

metering where not allowed by technical constraints or utility policy; increasing the resilience of 

facilities by keeping systems energized during grid outages; and potentially monetizing other 

grid benefits such as power factor correction, frequency regulation and voltage support. 

Monetizing and combining all the different value propositions of combining solar and storage is 

an ongoing area of research and business model innovation, and will increase the market for PV 

and the need for financing. The more interactive nature of battery dispatch (charge/discharge) 

increases the “operations” part of O&M considerably.
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3 Scope and Prerequisites for a Successful O&M 

Program

3.1 Scope of O&M Guide

The services covered in this guide include asset management, monitoring, operations, preventive 

maintenance, corrective or condition-based maintenance (repair), and end of performance period 

(disposition).

This guide addresses dependencies due to system type, such as micro-, string-, or central

inverter; ground versus roof-mounted PV; attached versus ballasted mount; and tracking versus 

fixed mount. The guide also addresses dependencies based on site conditions including sources 

of soiling, bird populations, snow, pollen, and high temperatures. Energy storage systems are 

discussed in the context of dependencies, including relevant technologies, system topologies, and 

approaches to energy storage management systems.

This guide provides information on the delivery of O&M services, including qualifications of 

service providers, contractual relations, and performance guarantees related to O&M.

3.1.1 PV Scope

This document covers a wide scope of PV size classes: residential rooftop (typically less than 10 

kW); commercial and industrial rooftops and shade structures such as carport (10 kW to 1,000 

kW); and utility-scale ground-mounted systems (often greater than 1,000 kW).

3.1.2 Energy Storage Scope

This guide focuses on electrochemical batteries and does not cover other energy storage 

technologies such as pumped hydro or compressed air energy storage. Within batteries, the focus 

will be on lead-acid and lithium-ion chemistries, with some limited discussion of flow batteries.

This selection is based on current market penetration and forecasted future market growth for 

batteries in combination with PV systems.

3.2 Prerequisites for a Successful O&M Program

Borrowing from classroom grades, where “A” is best, it is possible to bring a PV system earning 

a “D” grade up to a “C” or “B” with effective O&M. However, it is not possible to earn an “A” 

unless O&M was a consideration in the design of a system. Also, O&M might not be able to save 

a failing system if the problems are intrinsic to the design or products used. O&M issues should 

be considered in design, engineering, and construction in order to:

• Select low- or no-maintenance alternatives when available (for example plastic wire ties 

would require replacement whereas coated metal ones may not);

• Track the performance of fielded equipment and identify and specify the ones that have 

low failure rates, and which have the best OEM warranty service; standardize on 

preferred products to avoid mis-match of parts and expertise in a fleet;

• Make use of network-connected inverters for remote testing, software configurations 

and/or updates, and remote resets

• Provide required access to and clearance around equipment for maintenance (EPRI 2010)
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• Provide elevated pads to prevent flooding of ground-mounted equipment and provide 

permanent storm-water management system that is integrated with surrounding 

properties.

• Enable third-party inspection and commissioning of original EPC installations to spot 

operation problems before acceptance (EPRI 2010)

• Conform to the evaluation and quality-assurance protocol detailed in the SAPC PV 

System Installation Best Practices Guide (applicable to residential systems only)

(Keating, Walker, and Ardani 2015).

• Build PV and storage systems to relevant standards, such as IEEE 937: Recommended 

Practice for Installation and Maintenance of Lead-Acid Batteries for Photovoltaic (PV) 

Systems (IEEE 2007).

• Apply IEC 62446: Grid Connected Photovoltaic Systems-Minimum Requirements for 

System Documentation, Commissioning Tests, and Inspections (IEC 2009), which 

requires documentation of the system, array testing, and whole-system performance test1

(applicable to commercial, industrial, and utility-scale systems). Commissioning is the 

link between the engineering, procurement, and construction (EPC) contractor and the 

operator. In addition to the above-mentioned safeguards, commissioning is now 

recommended to be a two-part process: The first part is done when the system starts 

operation, and the second is performed after one year of operation. Full acceptance of the 

system comes after the second step. Third-party verification of a plant can help ensure 

that best practices are applied throughout the life cycle of a plant. Such verification could 

include concept, site selection, design, equipment selections, installation, commissioning,

final commissioning, PV system performance reporting, annual certification, certification 

for transfer of ownership or for refinancing, O&M practices, and/or end-of-performance

period.

Based on inspections of PV systems damaged in hurricanes, the following are prerequisites to 

address in the design and installation of a system in the areas vulnerable to hurricanes prior to 

O&M tenure:

• Through-bolting is preferred to self-tapping screws. Self-tapping screws are more likely 

to pull out, and due to the hardened threads and lack of galvanized coating on the threads,

they get weaker over time due to corrosion.

• Through-bolting is preferred to clamps in rack hardware. Clamps may have the specified 

strength in the proper orientation when forces are applied in the proper direction, but 

relative movement, rotation, or vibration of rack parts in a storm can cause them to 

release. An entire row of modules can fail if one module is lost, and they are held by Tshaped clamps that hold two modules at one point.

• Stainless-steel boxes with thick rubber gaskets and multiple closure attachments stay 

intact and exclude moisture more effectively than those with only handle-actuated 

attachments (specify NEMA 6 rating).

• Mastheads can break off or leak in a storm and must be sealed with foam packing 

provided for that purpose to avoid water infiltration and keep insects out.

• Drainage from boxes and conduit runs must be provided in the case of water infiltration.

 1 Other commissioning guides are also available.
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For battery storage systems, two parallel strings of batteries are recommended so that one may be 

taken out of service for maintenance while the other string provides at least some storage for 

continued operations. Design of a battery facility should consider easy access to each cell for 

service and also for replacement of individual units without disassembling the whole battery 

plant. The design should also include features to support battery O&M such as safety systems 

and on-site storage of battery materials and supplies that is compliant with all safety and code 

requirements.

Figure 1. Two strings of batteries are recommended in design to allow O&M service of one string 

while the other string serves the purpose. Photo by Andy Walker, NREL
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4 Definitions

For the purposes of this document, key terms are defined below.

Asset management is a systematic process of planning, operating, maintaining, upgrading, and 

replacing or disposing of assets effectively with minimum risk and at the expected levels of 

service over the assets’ life cycles. It therefore contains all of the services that would fall under 

O&M but also includes business services operations, such as billings and collections from power 

purchase agreements (PPAs) and lease-based systems (DOT 1999). Asset management involves 

planning and budgeting for O&M, administration, billing, accounting, tax preparation and filing,

hiring subcontractors, enforcement of warranties, management of budget and reserves, insurance 

policies, renewable energy certificate (REC) certification and trading, performance reporting,

plant supervision, quality control, as-built plant documentation, ongoing environmental 

compliance, and compliance with any other regulatory or utility requirements.

Asset owner holds title to the PV system or portfolio of systems and may be an individual, a 

corporation, or, most commonly, a special-purpose corporation, such as a limited liability 

corporation (LLC), formed just to implement and operate the PV project.

PV operations includes the following five areas: 

1. Administration of operations: Ensures effective implementation and control of O&M 

services including curation of as-built drawings, equipment inventories, owners and 

operating manuals, and warranties. Curation involves not only keeping an archive but 

also selecting what to keep, pursuing missing documents, preserving documents, keeping 

them up to date, and, finally, archiving documents. Administration includes keeping 

records of performance and O&M measures, preparing scopes of work and selection 

criteria for service providers, contracting with suppliers and service providers, paying 

invoices, preparing budget, and securing funding and contingency plans for O&M 

services. Administration also includes compliance with regulations by the government or 

authorities having jurisdiction and mandatory guidelines issued by utilities.

2. Conducting operations: Ensures efficient, safe, and reliable process operations 

including making decisions about maintenance actions based on cost/benefit analysis.

This includes serving as a point of contact for personnel regarding operation of the PV 

system; coordinating with others regarding system operation; preparing power and energy 

forecasts; scheduling maintenance operations; listing spare parts inventory (either instock onsite or in suppliers’ consignment stocks); and inspecting work and approving 

invoices. Meanwhile, operations include any day-to-day operation of the system to 

maximize power delivery, assess performance and trends, operate the grid interface,

manage curtailments, or adjust settings such as power factor or other ancillary services. 

Operations activities related to utility interaction or distribution-system 

integration/control are of increasing importance as individual plants get larger and the 

penetration of PV systems get more concentrated.

3. Directions for the performance of work: Specifies the rules and provisions to ensure 

that maintenance is performed safely and efficiently, including the formalization and 

enforcement of safety policy [including training for direct current (DC) and alternating 
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current (AC)] safety, rooftop safety, minimum staffing requirements, arc flash, and lockout/tag-out); work hours; site access, laydown areas and parking; and any other 

stipulations under which work is performed. This includes confirming and enforcing 

qualifications of service providers, as well as compliance with any environmental or 

facility-level policies regarding the handling of controlled materials (e.g., solvents, weed 

killer, insecticide).

4. Monitoring: Maintains monitoring system and analysis of resulting data to remain 

informed on system status, metering for revenue, alarms, diagnostics, and security 

monitoring. Includes comparing results of system monitoring to benchmark expectation 

and providing reports to facility stakeholders. This includes periodically preparing reports 

as required by O&M contract or as required by the system owner, including reports of 

plant performance, key performance indicators, problems and alarms, and maintenance 

services performed. Site security is performed both locally and with remote monitoring 

(e.g., cameras, intruder alarms) to protect against theft and vandalism.

5. Operator knowledge, protocols, documentation: Ensures that operator knowledge, 

training, and performance will support safe and reliable plant operation. Information such 

as electrical drawings, part specifications, manuals, performance information, and records 

must be deliberately maintained and properly filed/catalogued.

PV maintenance includes the following four types of maintenance procedures: 

1. Administration of maintenance: This overlaps with “administration of operations” and 

ensures effective implementation, control, and documentation of maintenance services

and results. Administration includes establishing budgets and securing funds for 

preventive maintenance; establishing reserves or lines of credit for corrective 

maintenance; planning services to avoid conflict with system operation or operations at

the customer site; correspondence with customers; selection and contracting with service 

suppliers and equipment manufacturers; record keeping; enforcement of warranties; 

providing feedback to designers of new systems; and reporting on system performance 

and the efficacy of the O&M program.

2. Preventive maintenance: Scheduling and frequency of preventive maintenance is set by 

the operations function and is influenced by a number of factors, such as equipment type, 

environmental conditions at the site (e.g., marine, snow, pollen, humidity, dust, wildlife), 

and warranty terms. Scheduled maintenance is often carried out at intervals to conform to 

the manufacturers’ recommendations, as required by the equipment warranties. 

3. Corrective maintenance: Required to repair damage or replace failed components. It is 

possible to perform some corrective maintenance such as inverter resets or 

communications resets remotely. Also, less urgent corrective maintenance tasks can be 

combined with scheduled, preventive maintenance tasks.

4. Condition-based maintenance: Condition-based maintenance is the practice of using 

real-time information from data loggers to schedule preventive measures such as cleaning 

or to head off corrective maintenance problems by anticipating failures or catching them 

early. Because the measures triggered by condition are the same as preventive and 

corrective measures, they are not listed separately. Rather, condition-based maintenance 
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affects when these measures occur, with the promise of lowering the frequency of 

preventive measures and reducing the impacts and costs of corrective measures.

End-of-performance period disposition: Specifying the options for the parties in an offtake 

contract (such as a PPA) at the end of the performance period or at the end of the projected life 

of a host-owned system, the alternatives are the following: to continue the performance contract 

for an extended term, including continued O&M; purchase of the system by the site or others 

(often at “fair market value”) involving a new O&M provider; or removal of the system and 

restoration of the site.
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5 Dependencies on PV System Type, Site, and 

Environmental Condition

It is useful to consider how O&M requirements and attendant costs depend on the type of system 

and components, some details of the site, and climate and other environmental conditions such as 

agricultural area versus urban setting.

5.1 Electrical System

If micro-inverters are not used, the PV system will have both AC and DC components. The DC 

system determines system power capacity and energy production, whereas the inverter and the 

AC system has the greatest impact on system reliability. There can be several single points of 

failure in the AC system—for example, the central inverter, or the generator step-up (GSU) 

transformer. Central-inverter considerations are discussed in the next section.

O&M measures and cost depend on the wire management system employed. Preventive 

maintenance entails making sure wires are secure and protected. Corrective maintenance entails 

finding and repairing ground faults, such as wire scaping against a module frame; and arc-faults 

that may be caused by a broken wire or loose connection. Wire management may be classified 

in three categories: open air; direct bury; or conduit/cable tray.

• Module-to-module and module-to-combiner wires are often in open air. These are most 

subject to damage, but it is easy to locate their problems and repair them.

• Direct bury of conductors is a lower first cost than installing conduit and pulling 

conductors. Failure risk of direct-bury conductors is usually low, and failures are 

typically caused by rodents chewing on them. Proper compaction of the soil is a best

practice for reducing this problem. However, if the direct-bury conductor fails, it may be 

difficult to locate the fault, and the conductor must be dug up to find and fix the problem.

This can be very expensive. Not only does the conductor need to be dug up, but there are 

likely other buried infrastructure in the vicinity, making the dig-up process very slow.

Direct bury is chosen in many cases, driven by capital-cost considerations.

• O&M will be minimal for conductors in conduit or lay-in trays, which are designed as an 

integral part of the rack and wiring system.

Maintenance must be provided to ensure that the wire management system continues to protect 

the wires from physical damage. O&M problems will be exacerbated if:

• Wires, plastic wire ties, or grommets/bushings are exposed to sunlight. Even products 

listed for direct ultraviolet (UV) exposure will show degradation over the long life of a 

PV system and require eventual replacement.

• Movement or rubbing against modules, rack parts, or other wires due to wind or thermal 

expansion/contraction are allowed. This will require more frequent inspection, testing, 

and replacement. Movement of ballasted rack systems on a roof can cause damage to 

conduit or wires, and even ground -mounted parts can experience movement over a long 

period of time. A design that accommodates such movement and thermal 

expansion/contraction will require less corrective maintenance.

• Wire ties pinch wires too tightly. This will eventually deform the insulation. Faults may 

occur anywhere that wires are held tightly between metal parts.
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• Wires are pulled too tight or do not have strain relief. This will require more frequent 

maintenance. Wires exposed where there is weight from accumulated ice, or where 

module leads do not come in the right length for the installation, will require frequent 

testing and repair.

• Exposure to animals, such as squirrels, requires measures to deny the animals access to 

the wiring and to repair any sections where the insulation has been chewed.

• Large bundles of wires do not allow wires at the center of the bundle to cool as they 

would in open air, leading to early degradation of the insulation and potential fault.

Figure 2. Maintenance of wire management systems depend on plastic wire ties and grommets,

which can break or pinch wires (left); exposure to sunlight; wind and weight of ice (center); and 

access by chewing rodents (right). Photos by Andy Walker, NREL

GSU transformers are common in utility-scale PV plants, and the failure risk has been low 

historically. In the past, transformers were overbuilt and have a reputation for being very 

reliable. However, as design engineers now have access to computer-aided design (CAD) tools, 

they are able to meet requirements without overdesigning. If the GSU fails, it can idle the plant 

for months. GSUs are very expensive and have a very long lead time. Also, they are large and 

heavy, and the logistics associated with delivery are complicated. Delivery of GSUs may include 

a crane and require special permits for transport on roads and interstates.2 

The risk of GSU transformer failure may be mitigated during the design phase by dividing the 

plant into multiple arrays, each with its own GSU transformer. It is critical to follow the 

manufacturer’s recommendations for a preventive maintenance program. It may also be possible 

to work with local utilities to pool resources for better access to replacement units. At the 

minimum, the responsible party should have a fully formed reaction plan in place. Some 

operators keep a spare GSU on-site to reduce down-time associated with this critical component.

5.2 Central, String, DC-Optimized, or Micro-Inverter Configuration

O&M depends on the topology of the inverter system: micro-inverters on each module, string 

inverters on series strings of modules, DC-optimized inverters that combine elements of both 

topologies, or larger central inverters. The cost per watt of capacity is much higher for a micro-

 2 Accessed August 2016. http://community.energycentral.com/community/t-d/managing-risk-transformer-failures
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inverter and string inverter than it is for a central inverter. The different types of inverters have 

different failure and replacement profiles and different effects on production.

Table 1. Cost of String, DC-Optimized, Central, and Micro-Inverter Replacement 

(Feldman et al. 2018

Inverter Types 20-Year Replacement Cost ($/W)

String Inverter $0.25 (estimated as 2x factory price)

DC Optimizer/Inverter $25

Central Inverter $0.14 (2x factory price)

Micro-Inverter $0.40

Inverter reliability continues to increase for all types of inverters, with 10-year warranties now 

commonly available and 20-year extended warranties/service plans also gaining prevalence.

However, a sound O&M plan should account for inverter failure because it is one of the most 

frequent causes of PV system performance loss (EPRI 2010). The best preventive maintenance 

for the inverters would be to perform the manufacturer’s required maintenance—to include, but 

not limit to, re-torqueing current-carrying conductor fasteners (screw lugs on terminal blocks)

and thermal imaging of electrical connections and components. Inverter air filters will take in 

grass and dust during mowing, high winds, or dusty conditions, and the O&M plan should 

establish a timeframe when the grass-cutting is done and schedule a preventive filter 

swap/cleaning to follow such dusty conditions. A technician will be dispatched faster to service a 

central inverter (see Appendix C for corrective maintenance choices for both string and central 

inverters), whereas failures of micro-inverters, and to a lesser extent string inverters, can be 

delayed until a scheduled visit because their impact on the performance of a large plant is 

incremental.

Additional O&M measures related to inverters include the following:

• The decision to replace or repair an inverter is based on inverter size, type, 

manufacturer’s ability and availability for timely repairs, and associated costs.

Replacement is preferred over repair when it becomes difficult to source repair parts and 

desired new features trigger an upgrade. However, upgrading may lead to other concerns 

such as not being able to get the correct replacement size, footprint, and electrical conduit 

and wiring configuration. Include in any upgrade remote monitoring to confirm the 

inverter status, reset the inverter, and remotely diagnose problems.

• In remote locations, stock component replacements onsite, especially for equipment 

commonly in need of repair, such as driver boards, if the manufacturer support or 

warranty is not available. Store replacement micro-inverters and power optimizers onsite.

5.2.1 Central Inverter

Central inverters involve much more DC wiring to deliver the PV energy from a very large 

distributed array to the location of the central inverters. Electricians working on energized DC 

circuits (combiner box and array) must have the training and personal protective equipment as 

required per National Fire Protection Agency (NFPA) 70E (NFPA 2012) and Occupational 

Safety and Health Administration (OSHA) standards (including but not limited to arc-rated 
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clothing, insulation gloves, face shield, and other personal protective equipment [PPE] as 

required for the level of voltage and arc-flash potential being worked on). The gloves with liners 

and leather protectors are sometimes unwieldy, so complex tasks are difficult, and tasks take 

longer to perform. The cost of a technician that has training and PPE to work on live DC circuits 

in one case (a campus in Denver CO with several PV systems totaling 8 MW) is $128/hour 

versus $70/hour for a journeyman electrician who could maintain ordinary AC circuits. Other 

items, such as disconnects, are also more expensive in a DC version than AC version. An arc 

fault is more persistent in DC wiring than in AC wiring. The additional DC wiring of a centralinverter configuration might require more repair than the corresponding AC wiring of a microinverter or string-inverter configuration. Large central inverters become a single point of 

failure—if the inverter is down, either intentionally for maintenance or unintentionally, the entire 

associated electrical production is lost, not just a portion. Monitoring using only a few central 

inverters is less complicated than multiple micro- and string inverters, and it involves less energy 

consumption by the monitoring system itself. Advanced features such as non-unity power factor 

(sourcing kVAR), curtailment of output power, low-voltage ride-through, and low-frequency 

ride-through are easier to implement in central inverters, and such controls will add more to the 

“per-watt” cost of micro- and string inverters. For central inverters, numerous subsystem repairs

to the inverter are supported (control cards, driver cards, components such as an insulated-gate 

bipolar transistor [IGBT] matrix and capacitors), assuming that each is repaired independently, in 

contrast to micro- and string inverters, which require replacement of the entire unit.

5.2.2 String Inverters, Micro-Inverters, and DC-Optimized Inverters

Micro-inverters and string inverters shut down automatically as required by IEEE 1547 upon loss 

of AC connection, and only the strings of modules connected to the string inverter remain 

energized. The wiring from the string inverters to the central AC switchgear becomes deenergized, which is the important advantage of string inverters with an impact on O&M costs

because it is simpler and less expensive to work on de-energized, conventional, AC wiring than 

it is to work on energized DC wiring. Micro- and string inverters avoid the need for an additional 

control circuit and hardware required for rapid shutdown (NEC 690.12) and avoid the need for 

arc-flash protection when working on the connecting AC wiring. Power optimizers work similar 

to micro-inverters but shut down the DC power coming from the power optimizers to the 

inverters. Each power optimizer will output only 1 V, meaning that the string connecting the 

modules to the inverter is also de-energized. Regarding corrective maintenance, manufacturers of

string inverters vary but can take up to about one month to send in new warranty inverters for 

replacement. The customer should go to the site and take a photo of the dead string inverter and 

then call the company to ship the replacement materials authorization, which is a long process 

when compared to replacing failed components of a central inverter with spares on hand.

However, replacement of string inverters is quicker and easier than repair of central inverters and 

can be accomplished by an electrician rather than an inverter specialist. Annual production can 

be improved over that of a central inverter by keeping string inverters in stock for replacement 

and to rotate this stock as inverters fail—an approach that is not feasible for central inverters.

With string inverters, fewer arrays are impacted with one inverter failure. Even though it is 

unlikely that all the string inverters will be down at the same time, there is a corresponding 

probability that, at any given time, at least some string inverters will be down and in need of 

service or replacement (called “whack-a-mole” by service providers). Micro-inverter 

manufacturers have developed a sophisticated data platform that maps location and can monitor 
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performance and also pushes out software upgrades on a module-by-module level—much more 

detailed information than data from a central inverter. Power optimizers also offer the ability to 

see module-level data through mapping module locations and, in many cases, can remotely offer 

the same troubleshooting capabilities of onsite current-voltage (I-V) sweeps. The selection of

string inverters assumes replacement or swap as the most common corrective action, rather than 

replacing failed parts as in a central inverter.

5.3 Roof Maintenance Related to PV System

O&M measures related to the roof for rooftop systems include finding and fixing roof leaks and 

any maintenance related to the rack attachments or effects of ballast on the roof. Rather than only 

the roof membrane, a “roof system” includes membrane, cover-board, insulation, air and vapor 

barriers, and the roof deck. O&M considerations provide preventative maintenance for the roof 

and avoid damage to any of these roof-system components as the PV system is being serviced.

Roofs under warranty require annual preventive roof maintenance to maintain the roof warranty.

It is a best practice for the PV O&M provider to meet with the roof maintenance provider to 

make sure both teams understand their roles and responsibilities and respect the needs of the 

other. Failure to provide maintenance of a roof system may result in roof-system failure, thereby 

necessitating PV system removal for roof repair/replacement, which is bad for the prospects of 

the PV system. By meeting, the roof maintenance provider can share particular areas of concern 

with the PV O&M team and vice versa. This kind of collaboration can minimize contentious 

finger pointing when problems arise. Scope and cost of maintenance for rooftop systems are 

affected by several factors, as discussed below.

Complexity: It costs more to perform repairs on a roof with a complex layout, such as multiple 

sections or multiple ridges in different orientations. 

Slope or pitch: It is more difficult, requires more safety equipment and training, and costs more 

to perform repairs on a steep roof than a low-slope roof. Slopes greater than 3-4:12 pitch 

(vertical to horizontal, about 18 degrees; some companies use 14 degrees as the low-slope/steep 

slope criterion) require a higher standard for fall protection (29 CFR 1926.500)—warning lines 

alone are not allowed, guardrails must have toeboards, etc.—and contractors charge more for 

pitches above 7:12 because of the difficulty and special equipment required and because the 

company pays higher insurance costs. See OSHA 1926.501(b)(10) for low-slope roof 

requirements and 1926.501(b)(11) for steep roofs. A ballasted, rather than attached, system may 

be used on flat and low-slope roofs but not sloped roofs.

Condition: If the roof and decking are damaged, any repairs or replacement costs will be 

additional scope and cost. This could occur if a water leak has damaged the underlying roof 

deck. Often, water damage is not noticed until after the roofer has removed shingles and looked 

at the deck.

Scale: The size of the roof—and more specifically, the areas under the PV system requiring 

maintenance associated with the solar energy system—affects the per-unit cost. With a high cost 

of mobilizing equipment and labor to the site, leaks in small roof areas (e.g., residential) will be 

very expensive to fix on a per-square-foot basis. Roofers talk in units of “squares,” and one 

square equals 100 square feet (sf).
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Type of roof: The costs per square foot for the different roof types in Table 2 are based on a 

scale of 1,200 sf repair/replacement, typical of commercial-scale rooftop PV. Membrane flatroof applications include a fully adhered thermoplastic polyolefin (TPO) membrane roof, 

ethylene propylene diene monomer (EPDM), or polyvinyl chloride (PVC). For ballasted systems, 

there is a sacrificial slip sheet between the bottom of the ballast pan and the roof membrane. Cost 

to repair or replace a membrane roof is about $70/m2 ($7/sf: $2/sf roofing material, supplies, and 

equipment; $5/sf labor). Built-up asphalt roofs and other modified-bituminous roofs may cost on 

the order of $100/m2 ($10/sf to repair). Asphalt shingles are perhaps the least expensive roofing, 

and, thus, also less expensive to maintain. Maintenance costs are on the order of $60/m2 ($6/sf, 

of which $1.50/sf is for materials) of affected roofing area plus mobilization costs. Composite 

shingles use better materials and may cost on the order of $70/m2 ($7/sf to repair damaged areas;

$2.50/sf for materials). Wood shingles may cost $200/m2 ($19/sf) for repair or replacement. Slate 

roofing repair may cost on the order of $130/m2 ($120/sf; materials $10/sf). A metal roof can 

accommodate solar very easily, and it would be difficult to attribute any O&M cost with the 

attachments to the metal seams, except for inspections. However, if problems occur with metal 

roofing, they may cost on the order of $430/m2 ($40/sf to repair; $15/sf for materials). Concrete 

tile is common on Spanish colonial-style homes and may cost on the order of $650/m2 ($60/sf)

on area requiring repair or replacement ($5/sf for materials) (HomeAdvisor 2016; HomeAdvisor 

2018).

Table 2. Service Costs for Different Types of Roofsa (HomeAdvisor 2016; HomeAdvisor 2008)

Roofing Type Repair Materials 

($/m2)

Repair Labor (h/m2)

Thermoplastic Polyolefin (TPO) $20.00 1.0

Ethylene Propylene Diene Monomer 

(EPDM)

$20.00 1.0

PolyVinyl Chloride (PVC) $20.00 1.0

Built-up, Bituminous $15.00 1.5

Styrene-Butadiene-Styrene (SBS) $20.00 1.0

Asphalt Shingle $15.00 1.0

Composite Shingle $25.00 1.0

Wood Shingle $40.00 2.0

Slate $50.00 1.0

Metal Roof $50.00 0.5

Tile $50.00 1.0

a Large variations can exist based on size, site access, location, and labor markets.

The use of manufacturer-specific materials is required for the flashing to PVC, TPO, and other 

membrane-type roofs. The flashing must bond chemically with the field membrane, and all 

materials and adhesives must be compatible. Bituminous and modified bitumen roofs use coneshaped metal flashings, and the skirt of the flashing is sealed with a torch-down bitumen 
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capsheet, with an EPDM collar sealing the flashing to the post. The cost of repairing flashing can 

be on the order of $100 per flashing of a roof stanchion or conduit penetration and as much as 

$500 for larger objects such as the pedestal supporting a roof-mounted inverter, combiner box, or 

switchgear.

Overburden waiver: An overburden waiver, often required to maintain a roof warranty, 

includes an agreement to remove the PV system should the roofing company need access to do 

any roof work. If required, the cost of removing and re-installing a PV array is high and also 

entails lost production.

Roof warranty issues: Roofing contractors often guarantee the work they do, which is 

frequently between 5 and 10 years for their workmanship. This will typically cover leakage or 

total failure but not wear-and-tear or damage associated with the PV system. Some roofing 

manufacturers offer 25-year warranties, but those typically apply to commercial projects and 

require certain installation procedures. PV systems can be installed on many different types of 

roofs. However, installation of a PV system can increase a roof’s potential for leaks and damage 

due to increased rooftop foot traffic and additional attachments to and through the roof 

membrane. Thus, measures need to be taken to continue a warranty and ensure long-term 

performance of the roof under the PV system. The following scope of work is recommended for 

the roofing company that has the warranty or service contract on the roof, or failing that, then 

another roofing company certified by the roof manufacturer:

• Roofing company should specify the procedures to follow and provide information 

required and forms to fill out to officially notify roofing company and manufacturer of 

roof problems related to a PV system and plan for repairs.

• Review the repair plan to ensure that it is appropriate for the existing type of roof, 

compatibility of materials, stresses, expansion/contraction, membrane puncture, 

insulation compression, and recommended repair/replace practices. Identify the 

conditions required to maintain the roof warranty or recommendations for the quality of 

the installation, such as thickness and material properties of slip sheets, as well as

including the selection of cleaning agents and any other future O&M impacts.

• Inspect the condition of the roof prior to repair work. Provide details of any repairs or 

reinforcements required.

• Inspect the final condition of the roof upon completion and acceptance of the repairs. To 

reduce the potential for leaks and to provide a more durable platform under all types of 

PV systems, the roof manufacturer will specify requirements and recommendations. For 

ballasted rack PV systems, this would include a sacrificial layer (membrane) of minimum 

thickness under the feet of the ballasted rack system (Figure 3); walkway system 

comprising a walkway pad or pavers around the blocks of the PV arrays; requirements to 

remove PV components to investigate a leak or make a repair; requirements that the 

system be rendered safe (de-energized) for roof work; and other requirements considered 

necessary by the roofing company or roof materials manufacturer. New flashings or other 

alterations to the roof must follow all technical standards and details provided by the 

manufacturer.
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Figure 3. A best practice is to run a slip sheet continuously under rack members to avoid direct 

contact with the roof membrane. In this photo, direct contact of the rack is cutting into the roof 

surface. Photo by Norm Crouse, Lightbox Energy

Snow and ice removal: Snow is rarely removed from PV systems because it is not cost effective 

and damage may occur to the PV modules and wiring. Snow may slide off of arrays tilted more 

than approximately 30 degrees but will remain on lower tilts until it melts. The electrical

configuration of the array can also affect losses due to snow, with horizontal strings of modules 

or micro-inverters suffering less loss in a partially covered array. If snow is not removed, annual 

production is reduced by about 3% on average and up to 15% in very snowy climates (e.g., 

Truckee, California). However, it is sometimes necessary to remove snow to avoid limits on roof 

weight loading. For light snow, a turbofan or brushes and squeegees may do less damage than 

shovels and rakes, but extreme care is required to avoid damage. Snow is sometimes removed 

from the roof or ground in front of the array to provide clearance for snow to slide off of the PV 

array. Cost for snow removal is about $50 to $75 per hour for labor, or about $0.50/sf of array 

area.

Removal of ice dams: Ice dams should be removed to allow the roof to drain properly. Snow 

over the ice dam can be removed with a rake or shovel, and the ice dam can be removed using 

chemical ice melters or a de-icing cable. The cost is $70 for labor per ice-dam location, and 

materials include a $50 rake and ice-melting supplies. Extreme care must be taken not to damage 

the roof membrane, the PV modules, or connecting wiring.

Removal of debris: Debris that has collected such as leaves should be removed to allow water 

drainage and to prevent material for vegetation growth and nesting on the roof. Cost for removal 

of debris is often included in the estimated cleaning cost but is a cost in addition to cleaning the 

surface of the PV modules themselves.
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5.4 Ballasted or Attached Rack

PV arrays may be attached to the roof deck or structure or they may be ballasted, which means 

held in place by added weight. Ballasted systems can only be used with flat or low-slope roofs 

(as specified by supplier but not more than 5 degrees; 1:12 pitch). To reduce wind loads, 

ballasted systems can only be used if solar collectors are at a low tilt angle—usually a 10-degree 

tilt and limited to no more than 20 degrees (one dual-orientation ballasted system has a southfacing panel tilt angle of 25 degrees and north-facing of 15 degrees). Such a low tilt angle is a 

minor penalty on annual energy delivery depending on latitude but allows more kilowatts per 

square foot of roof area and delivers more in summer when utility rates are higher.

Roofing material: Maintenance of a ballasted PV system is affected by the type of roofing 

material. Coal tar pitch, styrene-butadiene-styrene (SBS) modified bitumen, or other soft 

materials may be damaged by the pressure of a ballasted system, although suppliers of those 

roofs have introduced products and methods to accommodate ballasted PV. Fully adhered TPO 

membrane roof, EPDM, or PVC-type roofs are protected by a slip sheet of material between the 

ballast foot and the roof membrane.

Compressible insulation: Maintenance issues may arise on roofs that have compressible 

insulation, and some measure may be needed to avoid membrane damage and ponding of water.

Ponding of water in depressions under the added weight of a ballasted PV system can deform 

and stretch the membrane, accumulate dirt, and increase abrasion—in turn, requiring more 

maintenance to avoid leaks in the membrane. To avoid this, in design, the insulation should be 

polyisocyanurate (polyiso) board stock as base layer, with a more rigid backer-board to serve as 

an underlayment for the membrane, such as 15.8-mm (5/8-in.) gypsum cover board; otherwise,

special protective layers may be required to avoid compression of insulation and membrane 

damage.

Wear on roof membrane: The manufacturer will specify requirements including the thickness 

of slip sheets between the ballast feet and the roof membrane. Even with this sacrificial layer, or 

where the layer is not present, movement causes wear of the membrane, and maintenance will be 

required to maintain the integrity of the membrane. Two best practices are recommended: (1) a 

continuous slip-sheet roll running underneath the entire racking rail (as compared to slip sheets 

placed individually under contact points; and (2) during O&M, make sure these slip sheets are 

still in place under racking contact points. The slip sheets can sometimes work themselves loose 

over time.

Roof deflection: Typically, an attached system will add less than 3 pounds per square foot of 

solar collector area, whereas a ballasted system will add 3 to 8 pounds per square foot depending 

on the tilt angle and wind loading. The weight of ballast materials varies from the edges to the 

middle of the racking system, depending on the load to be resisted; thus, ballast weight is not 

necessarily distributed uniformly across the array. Edges of structures have greater wind loads 

than the center of the roof; thus, it has more ballast weight. The added weight of a ballasted 

system can cause deck deflection, resulting in increased ponding of water. In that case, there may

be measures to improve drainage.

Wind damage: To use a ballasted rack solution, advanced wind-loading evaluations have to be 

performed above the general requirements of ASCE-07. Wind loading is usually the determining 
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consideration on whether a ballasted system is feasible (i.e., in areas susceptible to high wind,

the ballast weight required could be excessive and so an anchored system would be better).

Product-specific design can aid in the placement of a ballasted array to avoid strong wind areas. 

Extreme snow loads and ballasted racks: Snow loads are a variable load consideration 

common to both attached and ballasted systems. Extremely heavy snow loads may exceed the 

rating (often 240 kg/m2 or 50 lbs/ft2) for low-slope ballasted rack hardware and may cause 

damage to the rack and modules.

Maintenance of proper roof drainage: The position of the PV rack and ballast materials must 

be arranged so that they do not disrupt drainage or result in accumulation of small debris.

Ballasted racks have many obstructions (numerous ballast feet laid on the roof) unlike attached 

systems, which sit up taller on stanchions. Thus, ballasted racks take more effort to keep the roof 

clear of debris and ensure that these obstructions do not impede drainage.

Migration of connections on roof: Unattached, ballasted components can move over time. The 

design should accommodate this movement in the conduit to the stationary interconnection. But

eventually, cumulative movement will require a revision to the conduit to avoid stresses. For 

large commercial rooftop PV systems, this cost may be on the order of $1,000 ($400 materials) 

and occur every 5 years.

5.5 Ground Mount

Ground mount avoids the roof maintenance issues listed above but introduces ground 

maintenance issues, including:

• Vegetation management (e.g., mowing, trimming, tree removal, herbicides), which is

often estimated as a cost per acre of site area.

• Snow removal, which can involve removal from the array itself, clearing access roads 

and alleys, and removal where snow accumulates as it slides off an array. If snow is 

removed from the array, care should be taken to ensure that the modules are not 

mechanically damaged by the removal techniques. In the case of single-axis trackers, 

significant damage can occur if snow is not cleared from between tracker rows because

the modules can come into contact with snow banks when the tracking mechanism is at 

its extreme east or west positions.

• Cleaning requirements, which increase for ground-mounted arrays because they are 

closer to the source of airborne dirt and pollen.

Just as equipment O&M issues should be considered in the design phase, the long-term 

maintenance of the ground cover and drainage should be considered in the design, civil 

engineering, and construction phases of ground-mounted systems to reduce O&M risks and 

costs. In climates with high rainfall, for example, grass cutting and vegetation control costs can 

equal or exceed equipment O&M costs (Brehaut 2015; Huff 2013).

5.5.1 Design

Initial design considerations that can significantly impact O&M costs for ground-mounted 

systems include ensuring that panels are mounted with sufficient and relatively uniform 

clearance from the ground, racking is spaced widely enough to allow access for efficiently sized 
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mowing, and equipment is cleaned to protect panels from damage from such equipment (EPRI 

2010; Brehaut 2015). During site selection, it is important to consider vegetation growing on 

adjacent properties—consider how tall the trees will be in 20 years and if this will cause shading 

of the system.

In an informal survey and series of interviews conducted by NREL with more than 30 members 

of the PV industry, several respondents cited significant problems with panels mounted too close 

to the ground to allow access under the panels by an arm of a mower, causing significant costs 

for more labor-intensive vegetation management approaches.

Initial design considerations also include establishing proper drainage to avoid or accommodate 

flooding and to control erosion, which can undermine equipment pads and racking. Several 

NREL survey respondents cited increasingly unpredictable and extreme weather conditions that 

impacted operations and pointed to the need to design for more extreme climatic conditions.

5.5.2 Ground Cover

Upfront investment in developing ground-cover solutions tailored to each site’s climate and soil 

conditions and establishing such solutions in the initial year or two of operation can ensure 

longer-term viability and lower the risks of shading, erosion, and excessive weed and vegetation 

abatement costs during the operations phase (Hernandez et al. 2014).

Applying gravel as a ground cover was widely identified by NREL survey respondents as 

expensive and problematic because it creates uneven work surfaces, changes runoff coefficients, 

and does not provide a long-term weed abatement solution. Gravel applications were described 

as requiring either regular application of herbicides, which can be restricted by local regulations, 

or mechanical weed control, which can kick up rocks and damage modules.

In general, NREL survey respondents saw low-growth, vegetative ground cover as ideal for 

ongoing maintenance, although many cited challenges in re-establishing vegetation following 

construction. Successful solutions included:

• Replanting with low-growth species selected by a horticulturalist or other expert based on 

site soil and climate conditions, including bent grass, white clover, and buffalo grass 

combined with blue grama (ESCO Associates Inc., forthcoming)

• Replanting with pollinator-friendly or other habitat-supporting ground cover in 

coordination with local agricultural extension services or other partners

• Preserving existing, sometimes native, vegetation through minimizing grading, which can 

reduce weed infestations.

Some survey respondents, as well as an NREL study of revegetation applications at a utilityscale PV site in Colorado, report greater success with broadcasting seeds and raking them into 

the soil, or drill seeding, than with hydro-seeding to re-establish vegetative cover in more arid 

areas (ESCO Associates Inc., forthcoming).

5.5.3 Vegetation Management

Chemical vegetation abatement may be more efficient and at times less costly, particularly in 

arid areas. However, several NREL industry survey respondents cited problems with soil 
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stabilization after herbicides eliminated vegetation; the added risk to, and safety requirements of, 

those handling the chemicals; and, most often, local or state regulations that restrict herbicide 

use. In addition, chemical vegetation abatement can conflict with public expectations of 

environmental stewardship from the solar industry.

In arid areas, mowing may be unnecessary with proper soil stabilization. For areas where 

mowing is required, there is the added risk of projectiles damaging modules.

Some companies in Germany and a growing number of utility-scale PV systems in North 

Carolina and Hawaii are working with local ranchers and farmers to use sheep grazing for 

vegetation management (Figure 4). Goats are not a good option because they jump up onto the 

array, and cattle are large powerful animals that damage the array by scratching against it. Those 

with experience in this area report greater success when forage needs are taken into consideration 

in the design phase and determining the re-seeding mix. Grazing considerations can include 

slightly higher ground clearance and conduit to protect wiring (Huff 2013).

Figure 4. Sheep, but not goats or cattle, can be employed for vegetation control. Photo by Eliza 

Hotchkiss, NREL

5.5.4 Erosion Control

Grading prior to PV system construction exposes soil that is extremely susceptible to runoff and 

erosion due to rainfall. Civil engineers may design for “sheet flow” of storm water. But, in fact,

once a small rill starts to form, it collects more water and grows into a large gully. The rill and 

gully erosion that occurs under such conditions can endanger the stability of the PV rack 

foundations and fences, expose buried conductors, and damage access roads and inverter pads. 

Thus, a best practice is to design specific pathways for storm-water runoff that include checkdams throughout the site that feed into channels lined with rock (rip rap) and that have the 
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channels terminate in splash pads and integrated into the site storm-water management system, 

such as a retaining basin. Runoff and erosion can be reduced by stabilizing the aggregates at the 

soil surface with soil conditioners. Such soil conditioners are polymers that are sprayed on the 

dry soil surface before the rainy season. There are several types of polymer soil conditioners, but 

they all have a high molecular weight and complicated molecular shapes that bond with soil and 

act as a cementing material that stabilizes the soil against the force of raindrops, as well as 

preventing pores in the soil from clogging with clay. The type and amount of polymer applied 

depends on the soil type and conditions at the site. Reapplication is required if treated soil is 

disturbed or the appearance of rills shows the need for reapplication. Once the long-term ground

cover (described above) is established, reapplication of the polymer should not be necessary.

Figure 5. Drainage and storm-water run-off are difficult to improve after the PV array is installed, 

requiring diligence in design and construction of storm-water management systems. Photo by 

Andy Walker, NREL

5.6 Tracking Mounts

The complexity of tracking systems requires more maintenance—not only on the load-bearing 

moving parts of the array but also for the associated system for actuators and controls. The 

additional costs of the tracking system are weighed against the performance gains it is expected 

to provide. Depending on system design and location, there are settings where tracking mounts 

may be able to make O&M less expensive per unit of energy as a result of the increased 

production.

Types of trackers include:
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• Single-axis, dual-axis: Single-axis trackers can rotate on a single axis while dual-axis 

trackers can move across dual axes of rotation. Both tracker types have several different 

sub-categories for their chosen axis of rotation, a mechanism for their rotation, and 

specific tracking capabilities. Each sub-category of tracking approach results in differing 

performance expectations and associated O&M costs.

• Centralized, decentralized: The decision between centralized and decentralized tracking 

has important bearing on array layout and O&M costs, particularly as a result of O&M

personnel access issues that can arise from centralized configurations. Decentralized 

designs can also facilitate more efficient land use.

Additional considerations for tracking systems include:

• Electrical: Check electrical connections and enclosure for tracking motor/controller; 

check grounding braids for wear

• Controls: Inspect and calibrate anemometer; replace cup-wheel; inspect inclinometer; 

inspect limit switch; replace tracking-controller power-supply fan filter; inspect/test 

tracking controller

• Rack and actuator: Check drive-shaft torque and visually inspect gearbox lubrication; 

inspect module table; grease screw jack; inspect screw jack; lubricate slew-gear; check 

slew-gear torque and inspect wear; grease universal joint (zerk fitting); inspect universal 

joint; lubricate tracker-mounting bearings/gimbals; repair/replace tracker drive shaft; 

replace hydraulic cylinder; replace tracker drive bearing; replace tracker motor controller; 

replace tracker mount bearing; replace/upgrade tracker control software

• Monitoring: Adjust availability calculations for tracking issues— original equipment 

manufacturers (OEMs) may have remote tracking platforms that support optimizing 

preventive maintenance scheduling

• Battery replacement: Replace during the life of the trackers even if only used as a 

backup, depending on technology type and function.
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Figure 6. Although improving annual energy delivery, especially in summer, tracking mechanisms 

and controls require regular maintenance to be effective. Photo by Andy Walker, NREL

5.7 Environmental Conditions

Many environmental conditions can affect O&M, and many are outside human control. Soiling 

can be addressed by the O&M contractor through cleaning and possibly during the site-selection 

process. That is to say, if two potential sites are being evaluated, and the only difference is that 

one has a source of soiling and the other does not, choose the site with no soiling problem. Other 

environmental conditions can affect O&M but are outside human control. Examples include:

• Humidity (this may be addressed by installing dehumidifiers in shelters that contain 

sensitive equipment)

• Hot climate, extreme temperatures

• High wind, possibility of hurricane or tornado 

• Hail (PV module breakage)

• Salt air, marine environment (corrosion, soiling)

• High insolation (high temperatures and UV degradation)

• Heavy snowfall (damage to array, lost production)

• Flooding (high rainfall; water intrusion into enclosures).

5.7.1 Cleaning

Soiling reduces the energy output of the PV array and can lead to localized hot-spot failures if 

the soiling is uneven. Efforts should be taken to reduce uneven soiling, for example, from bird 

droppings. Care must be taken with array cleaning to avoid damaging the components. Follow 

the PV module manufacturer’s recommendations with any array cleaning. Clean PV modules 

with plain demineralized water and mild detergent recommended by the manufacturer. An 
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economical method is with a bucket of water, strip cleaner, and squeegee (often on opposite 

sides of the same tool), using overlapping vertical strokes in the same way window glass is 

cleaned on commercial buildings. Do not use high-pressure water, brushes, or any types of 

solvents, abrasives, or harsh detergents. Robotic cleaning systems are available for large systems, 

and many of these require that the design of the system accommodate the movement of the 

robotic cleaning system.

Cleaning may be on a defined interval or “condition based,” and the impact of soiling can be 

measured by instruments to trigger a cleaning (e.g., a sensor with and without a shutter of soiled 

glass). In either case, the benefits of cleaning may be hard to calculate. For example, an 

instrument may indicate that the array is dirty, which would trigger a cleaning, but there may be 

a heavy rain the next day that would clean the array for free. In the case of uniform soiling, a 

local, site-specific cost-benefit analysis should be performed to determine whether routine 

cleaning of the array is warranted. The frequency determined may be seasonal, depending on 

local rainfall and dust characteristics. The optimal cleaning interval is affected by several 

parameters:

• Cost of cleaning: usually a fixed fee to mobilize a cleaning crew and then a per-unit-area 

cost for labor and materials ($/m2)

• The rate at which soil accumulates on the array, expressed as a power loss in %/day, 

%/month, or %/year

• Capacity factor for the location: the better the solar resource is, the higher the reward for 

cleaning

• Value of the delivered power ($/kWh): the higher the value of the power, the higher the 

reward for cleaning

• PV module efficiency: the lower the efficiency, the more area (m2) of array needs to be 

cleaned for the same benefit.

It is tempting to combine these parameters to calculate a cleaning interval that justifies the 

cleaning expense. However, because dirt begins to accumulate again as soon as a system is 

cleaned and because of rain, a simulation is required to account for time-series effects. Using 

such a simulation, Naeem (2014) found that for a system in Mesa, Arizona, with an annual 

soiling loss of 1.91%, a single annual cleaning would reduce the loss to 1.52%/year (-20%), two 

annual cleanings to 1.32%/year (-31%), and three annual cleanings to 1.20%/year (-37%).

Including the effects of soil accumulation and rain in an hourly simulation can also account for 

the effects of soiling changes throughout the day, with losses due to soiling in the morning and 

evening being about twice that in the middle of the day because of high incident angle (the 

shadow cast by each dirt particle grows longer with increasing incident angle).

Most rely on rain to keep the array clean; no cleaning regimen is employed. Heavy rains result in 

a nearly complete cleaning effect, whereas light rains clean much less effectively and can even 

increase soiling if dust then sticks to sparse water droplets. Naeem (2014) did a comprehensive 

study based on empirical data for both soiling rates and cleaning costs and concluded that 

cleaning is not cost-effective for residential, commercial, nor utility-scale plants. He found that 

cleaning costs varied from $0.25/m2 for large systems to $1/m2 for single residential systems,

and water consumption was around 1 liter/m2 of system area.
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However, where special conditions (listed below) occur, cleaning will be required on a schedule 

that depends on the source and nature of the soiling. Annual soiling losses are reported in a range 

from 4.3% to 7.5%, with many studies confirming losses around 6%/year. However, annual 

values are confounded by the rain cycle, and it is more helpful to look at how soil accumulates 

daily, in between heavy rains. Studies report about 0.05% reduction in output per day due to 

soiling. Naeem (2014) provides a good analysis of cleaning and survey of the literature and 

reports daily soiling rates of 0.061%/day and a range from 0.057% to -0.085%/day from his own 

experiments. He recounts a study of 186 systems reporting 0.051%/day and another reporting a 

range of 0.04% to 0.07%/day. In an area with heavy agricultural activity, 0.36%/day is reported 

and contrasted to a rate of 0.01%/day in a desert area void of agricultural, construction, or 

industrial activity. Large bird populations may result in losses accumulating as high as 0.5%/day,

and dust storms in places such as India have reported losses accumulating around 1.5%/day.

Soiling and resulting cleaning regimen depend on local sources of dirt. A sample swabbed from 

the PV module surface can be taken to an analytical laboratory to ascertain its origin. Some 

sources of soiling may be eliminated or reduced at the source (e.g., birds, factories, construction 

sites), whereas others will be corrected only by cleaning. Sources of soiling that may indicate the 

need for prevention or a cleaning regimen include:

• Agricultural dust: Cleaning can be scheduled following plowing. In parts of the world 

without active soil conservation, persistent dust can require frequent cleaning.

• Construction dust: Cleaning can be scheduled after completion of nearby construction.

Encourage the construction manager to implement dust suppression.

• Pollen: Schedule cleaning after the end of pollen season.

• Bird populations: Reduce open cracks between panels where birds can build nests; use 

plastic bird slides to change flat surfaces to steep-sloped surfaces; use bird netting to 

seal areas under the panels down to the roof completely around the array; install bird 

spikes along the top edge of the array to prevent roosting; use plastic owl or falcon with 

swivel head to scare off birds; schedule rooftop services and removal of nests according 

to nesting season timing. Live birds (falcons) have also been used to scare away other 

birds. Birds are creatures of habit, and their behaviors can be changed over time to avoid 

your roof.

• Diesel soot: Present in cities and concentrations such as at bus depots and may require 

frequent cleaning.

• Industrial sources: Processes such as cooking or manufacturing can be sources of array 

soiling. This can be identified by testing samples of the dirt. As an example, a filter added 

to a fryer can reduce oil in kitchen exhaust air.
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Figure 7. Module soiling can often be traced to a source, such as construction-site dust, resulting 

in about 5% loss. Photo by Andy Walker, NREL
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Figure 8. Bird populations are a source of soiling, as well as nests that need to be removed and 

seeds that can sprout on arrays. Photo by Andy Walker, NREL

5.7.2 Snow Removal

Snow accumulation on a PV array can reduce annual average performance by 0%–2% in 

southern states, 2%–4% in arid states such as Colorado, and 10%–16% in places with heavy 

snowfall such as Michigan, Wisconsin, and Maine (Ryberg and Freeman 2017). Design of array 

can increase or decrease snow accumulation (Figure 9). During design of the system, the 

necessary clearance between the bottom of the array and the ground or roof is determined to 

avoid wind-driven drifts and allow snow to slide off. Snow generally slides off steep arrays (e.g., 

30-degree tilt) but does not slide off low-sloped arrays (<20-degree tilt). Snow removal is 

generally not recommended because it may damage the modules, but it is sometimes required to 

reduce snow weight on a roof or to remove ice dams. The weight of snow has been known to 

completely crush PV modules and racks in rare instances. Snow removal is by powerful turbofan, not shovel or other mechanical means. Snow removal to provide access (i.e., roads, 

walkways) is generally required.
30

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Figure 9. Snow is an environmental condition that both reduces performance and complicates 

provision of O&M services, but removal of snow off arrays is not recommended due to the 

potential for damage. Photo by Andy Walker, NREL

5.7.3 Extreme Weather Conditions: Hurricanes and Tornadoes

PV is installed in locations where extreme weather conditions may occur, such as hurricanes in 

the Caribbean, storms along the eastern U.S. coast, and tornadoes in Texas and Oklahoma. PV 

systems should be designed and installed with such possibilities in mind, and measures should 

have been incorporated such as two-column racks (rather than post-strut), thick or non-glass 

covers, rigid backsheets, and through-bolted clamps. The designer should specify PV modules 

with high ratings for both uplift and down-force pressure. Some of these installation measures 

could be retrofit as part of making a system more resilient to extreme weather. Some practical 

O&M considerations include:

• Carefully inspect and re-torque all fasteners. Many systems have fasteners that are loose 

or missing, but the structure has not been tested by high winds—in preparation for a 

storm, carefully inspect and torque every fastener in the system. Sophisticated fastener 

systems are available with anti-vibration locking features.

• Re-install any weak or broken wire ties. Add additional wire ties.

• Supplement or replace clamp-type connections with through-bolt solutions that can 

withstand a lot of vibration.

• Remove any objects that could become airborne and damage the array (foreign objects).

Remove any broken tree branches, abandoned antenna stands, or such objects that serve 

no purpose and could be liberated in a storm.
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• Make sure cabinets and electrical boxes are properly latched with gasket intact and in

place. Consider strapping doors closed on cabinets with less than NEMA 6 rating [see 

https://www.nema.org/Products/Documents/nema-enclosure-types.pdf].

• Leave the instrumentation in place to record the increasing storm conditions; however,

anemometry and data backhaul antennas do not generally survive the worst storms, so 

consider taking these items down before a storm if you cannot afford to replace them 

after the storm.

Following a catastrophic weather event, personnel with the required training, certification, 

and protective equipment would:

• Render the system in a safe condition by disconnecting circuits that have sustained 

damage. Ground faults and arc faults might occur in damaged sections of the array, so 

disconnect damaged arrays at the module level.

• Perform inspection for both structure and electrical condition. Document any damage, 

prepare scopes of work and budgets for repairs, execute repairs quickly to ensure safe 

conditions and restore performance.

• Consider reinforcing or replacing components that failed with a stronger, properly 

engineered version. Replace any bent components.

• Secure PV modules and other items that have been liberated from the rack. Ensure that 

remaining rack sections are secure; if not, disassemble and secure.

• After making required rack and electrical repairs, re-commission the entire system before 

bringing it into service.

Figure 10. It might be the responsibility of the O&M provider to respond and ensure that storm 

damage is rendered safe both in terms of electrical hazards and loose components following an 

extreme weather event such as this damage in St. Croix in 2017. Photo by Andy Walker, NREL

5.8 Site Access

Utility-scale sites frequently have access roads through the array. These are installed during civil 

construction to facilitate array construction services. Because these sites can be several acres, 

driving access is needed. Roads must also accommodate emergency vehicles such as fire trucks. 

The roads may be built to accommodate cranes, and crane access may be needed during O&M 

services. Roads are placed in natural breaks, such as the end of several strings or the end of an 
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array-tracking mechanism. To ensure an accessible site, these roads must be maintained 

periodically (EUCI 2016).

Site security is another issue to consider. If the site is in a rural area, perhaps a fence and locks 

on the enclosures and shelters is all that is needed. In a more populated area, cameras or 

occasional visits by a security guard may be warranted.

5.9 Dependencies for PV Plus Storage Systems

This section details additional system dependencies to consider when integrating PV and energy 

storage systems. After discussion of commonly used topologies for PV plus storage system 

designs, the subsections follow the same progression as those in the preceding PV-only section. 

As with PV-only systems, there is detail on operations in Section 6 and health and safety 

considerations in Section 7. O&M considerations for energy storage depend on battery type, use

case, and other parameters.

5.9.1 Battery Type

There are several types of batteries, each with their own characteristics, including:

• Lead acid

o Vented lead acid (VLA)

o Valve regulated lead acid (VRLA)

• Lithium-ion

o Lithium iron phosphate (LFP)

o Lithium nickel manganese cobalt oxide (NMC)

o Lithium nickel cobalt aluminum oxide (NCA)

o Lithium manganese oxide (LMO)

o Lithium titanate (LTO) 

o Lithium carbon (LC)

• Nickel cadmium.

In order to discuss applications of batteries to different use cases, it is important to clarify key 

terms that describe their performance and capacity. A battery can provide a maximum amount of 

power (kW), and it can store a certain amount of energy (kWh). Batteries are generally rated in 

units of amp-hours, which, when multiplied by cell voltage (V), is energy storage capacity in 

units of kilowatt-hours. Energy storage systems are also rated by power delivery capacity in units 

of kilowatts. The power rating is important to determine the rate at which power can be delivered 

and will vary according to the application and relevant load profiles. The energy rating is also 

important to determine how long the battery can be discharged and how to program the energy 

management system. For example, a 10 kW/100 kWh battery can provide power at a rate of 

10 kW and stores 100 kWh, so one could discharge the battery at 10 kW (the maximum power) 

for 10 hours.
33

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Battery replacement intervals also present a special challenge when planning O&M expenditures 

because how long a battery may last in service depends on how the battery is treated.

Replacement interval is no longer than “shelf life” or “float life” but is significantly less 

depending on how long the battery has spent at low states of charge, the magnitude of the 

charge/discharge rates applied, how effective service such as equalization of charge and 

maintenance of electrolyte has been (for lead acid), and the average and extreme temperatures 

that the battery has been exposed to. Batteries start to lose capacity (effective kilowatt-hours of 

storage) as soon as the battery is installed, so, to determine a battery replacement interval, we 

have to specify how much storage is required at a minimum. For example, a telecommunications 

application might specify that a battery be replaced when a test reveals that it has 70% of its 

initial capacity.

5.9.2 Battery Use Cases 

The use cases for batteries in the guide include PV systems. Some of these use cases are more 

typically applied to standalone battery systems, such as utility-scale frequency regulation or 

substation- or feeder-level solutions that are implemented by the utilities themselves (Lazard 

2016), or commercial or industrial grid-connected batteries that do not have complementary PV 

systems.

Frequency regulation: Electricity storage has the capability to very quickly source or absorb 

energy to provide primary frequency regulation services. The value of frequency regulation 

depends on the needs of the electric utility. 

Time of use (arbitrage): Storage applications that seek to shift usage of PV-generated electricity 

from times of PV generation to later times, especially peak usage times when power demand 

(kW) is at a premium price.

Ramp-rate controls: Ramp-rate controls using batteries are a good thing in grid-connected 

applications and a necessity for small grids such as an island or village power system. A growing 

number of jurisdictions are issuing regulations to stage ramp-up of solar power in the morning, 

ramp-down in the evening, and manage PV fluctuation throughout the day. Such controlled rates

of change allow that ramping up conventional generators in a small grid (10–25 min) will be 

needed as the PV share of generation increases in general.

Peak shaving: Includes demand charge reduction in the commercial and industrial sector and,

more generally, applications that manage peak loads.

Resiliency: Defined as applications that seek to provide extended energy services during system 

outages. An example is a home system that is outfitted with a separate critical loads panel that 

allows the combination of rooftop PV and storage to power critical loads for a period of time.

Micro-grid (islanded and grid-connected): Refers to bundles of loads that are electrically 

connected to distributed energy resources, such as PV generation and storage. These combined 

generation and storage systems can be “islanded” in remote or isolated areas or grid-tied with the 

ability to operate both with interaction with the grid or disconnect from the grid to maintain 

operations separately as needed (e.g., in the event of a grid outage).
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5.9.3 PV Plus Storage System Topologies

Topologies for PV plus storage systems are typically determined by a combination of regulatory 

constraints and technical inputs paired with anticipated system behavior and associated system 

efficiency and cost. For example, in some settings, investment tax credit considerations may 

encourage designs that prioritize charging batteries with solar-PV-generated electricity. On the 

customer usage side, whether the power use is coincident with PV generation will be a key 

consideration.

5.9.3.1 Important O&M Considerations in System Design

There are a number of important considerations that go into system design and influence O&M, 

both in terms of ongoing costs and system performance, and that influences topline power 

production (translating into revenue or avoided costs, depending on context).

Designing systems to minimize losses is central to performance and costs relating to optimizing 

system size for a given set of power needs. The first step in minimizing efficiency losses through 

effective system topology design and equipment selection is to evaluate expected typical system 

behavior. This analysis would include activities such as assessing the relevant load profile(s), 

comparing that to the solar resource for the location, and considering the rate and duration of 

power needs. A system that is well designed for its application will optimize the usage of the 

battery, potentially decreasing frequency of corrective actions, such as needing to replace 

batteries that are failing prematurely due to overuse and ideally extending battery life.

It is important to note that components have different efficiencies at different levels of 

utilization. Equipment efficiency changes as a function of environmental conditions such as 

temperature. Sizing considerations that flow from this analysis have an important bearing on 

O&M planning and execution. For example, a system that requires batteries to discharge deeply 

often may require more maintenance and will shorten the usable life of the batteries and alter the 

associated costs that must be set aside in reserve accounts.

5.9.3.2 AC-Coupled System

AC-coupled systems link the battery and the PV array on the AC bus. As a result, PV-generated 

electricity can typically serve loads directly with a single conversion, but for PV to charge the 

batteries, it needs to flow back through a bi-directional inverter to be converted to DC (resulting 

in an efficiency loss). For example, AC coupling is common in residential markets, and when 

batteries are retrofitted to existing systems, they are typically coupled on the AC side to avoid 

wiring replacements and potential violations of terms of ownership agreements (Ardani et al. 

2017).

5.9.3.3 DC-Coupled System

DC-coupled systems link the PV and the battery on the DC side of an inverter (typically still bidirectional to charge from the grid where permissible). A charge controller is needed to manage 

the voltage of the DC electricity coming from the PV that is used for battery charging. The 

charge controller is generally an efficient conversion, but nonetheless it represents an additional 

component that affects overall system efficiency. This configuration is sometimes classified as 

“AC/DC-coupled” when the battery can be charged from the grid in addition to the PV array. 
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Additional information about bi-directional inverters to complement the inverter discussion 

above follows this review of topologies.

5.9.3.4 Additional Topology Configurations and Settings

Diesel generator: In certain settings, particularly isolated micro-grids, a diesel generator can be 

paired with PV and energy storage systems. Typically, this design decision is made to provide 

energy when weather conditions are unfavorable to renewable generation, reduce the capital cost 

of the project (e.g., decreasing PV and or storage component sizing to shift costs toward ongoing 

fuel costs), or both.

DC loads: Some systems are designed to serve a DC load directly as the only load (e.g., an 

electric motor) or in addition to AC loads. This can be done by serving the DC loads by way of 

the charge controller, drawing on PV-generated electricity or the battery. 

Resiliency/backup power: Backup power applications are typically in DC-coupled topologies

with an automatic transfer switch and a critical loads panel.

5.9.4 Other Electrical System Information Related to Energy Storage

Charge controllers: DC-coupled systems will generally require a charge controller to protect the 

battery from overcharging. Any DC loads included in the system can also be served directly 

through the charge controller.

Air conditioning: Batteries may require active cooling depending on operating characteristics, 

enclosure design, and ambient temperature. If so, there will be auxiliary power usage for the air 

conditioning that can detract from the total energy delivered from the system to serve loads.

There are options for modeling this electricity demand from air conditioning systems to identify 

the optimal level of conditioning. For example, containerized batteries can leverage envelope and 

insulation modeling tools to narrow expectations of temperature variation and air conditioning 

needs to help guide O&M staff or provider system monitoring. See below for additional 

information about environmental conditions.

Maintaining battery temperature within a given range is often a requirement for battery 

warranties, so maintaining battery temperatures through appropriate conditioning can become an 

important ongoing operational concern. For example, lead-acid batteries tend to have warranties

that cap temperature tolerance at roughly 25-35°C, so conditioning solutions need to be selected 

and monitored on an ongoing basis. In addition to satisfying equipment warranty requirements, if 

batteries are kept at elevated temperatures, the rate of capacity degradation can increase 

meaningfully. The balance between warranties, conditioning costs, and capacity degradation 

needs to be identified at the system design stage and then monitored carefully and re-calibrated 

over time.

DC wiring: Best practices for handling DC wires are discussed earlier in this section. It is 

important to note that a DC-coupled PV and battery system can involve a larger DC-wired 

network than a standalone PV application.
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5.9.5 Inverter Considerations for Energy Storage Systems

This section supplements the inverter discussion above by discussing relevant considerations for 

bi-directional inverters. Bi-directional inverters allow the battery to charge and discharge, 

converting battery or PV-generated DC electricity to serve an AC load or converting grid power 

or onsite generator power back into DC to charge the battery. 

Combined PV and storage system topologies will generally require a bi-directional inverter, 

either as the primary inverter solution (DC-coupled) or in addition to the unidirectional PV 

inverters (AC-coupled). Bi-directional inverters are also integrating a growing number of 

different capabilities, particularly in grid-tied utility-scale settings and grid stability support 

services (use cases outside the scope of this document). 

The cost considerations of replacing inverters and maintaining reserve accounts are similar to 

central inverters discussed above. The calculus for the reserve account can be adapted based on

an estimation of the costs associated with not having the battery available, which depends on a 

given use case. For example, in settings where the battery serves a key role in demand charge 

reduction, downtime at an inopportune time could be exceedingly expensive. In other words, 

inverter selection should consider how system component failures can affect system operation as 

a whole and result in lost revenue.

5.9.6 Environmental Conditions for Energy Storage Systems

Though batteries will typically be in an enclosure, the containers or enclosures can still be 

influenced by environmental conditions in ways that can influence O&M decisions and costs. 

For example, many batteries will have recommended temperature ranges for optimal 

performance. Operating batteries outside those set ranges can result in capacity degradation,

shorter battery usable life, and possibly void product warranties, so ambient temperatures will 

generally influence O&M practices and costs even in conditioned enclosures. Battery 

manufacturers recommend the temperature and humidity levels which should be maintained in 

the battery enclosure. Additionally, as with inverters and their air intake, it is also important to 

keep battery vents clear. The vents will be important for cooling batteries and venting gases for 

certain battery types (i.e., hydrogen off gassing in certain lead-acid battery technologies). 

Batteries can also have specific requirements and stipulations such as being de-rated above a 

certain altitude (or voiding product warranties above a certain altitude) and safety mechanisms 

associated with seismic ratings.

5.9.7 Site Access for Energy Storage Systems

Ease of access considerations included in the PV-only section above apply to batteries as well. In 

addition, batteries will have their own siting and signage requirements that reflect the hazards 

associated with energy storage, such as ANSI Z535. Depending on battery type and usage, there 

may also be a need to keep the surrounding area clear to allow proper ventilation if outdoors. 

Ventilation and other health and safety concerns are covered in detail by a number of codes and 

standards that are listed in Section 7.
37

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5.10 System and Site Considerations Checklist

Site and system considerations include the following.

Was O&M a consideration in system design? Are the interests of EPC and O&M provider 

aligned?

Are conductors buried or placed in conduit? If direct-bury, is ground compacted to deter 

chewing rodents?

Is the preventative maintenance schedule for inverters followed? 

Is repair or replacement criteria for inverter based on availability, size, type, and cost? Do 

inverters have remote monitoring and control? 

Is the system compliant with the roof warranty? Is there an overburden waiver defining 

responsibilities for each party? Is a system in place for notifying the roofing company if roof 

problems arise related to a PV system? 

Does conduit design account for movement in rooftop ballasted systems? 

Are climate, extreme weather events, ecological conditions, and environmental regulations 

accounted for and budgeted into the O&M plan?

Does civil engineering design adequately provide for road access, drainage, and security?

Does panel spacing allow for vehicle access between rows?

Do panel cleaning methods follow manufacturer recommendations and cleaning schedule 

account for local conditions? Has a cost-benefit analysis been run to determine if regular 

cleaning is cost-justified?

Is the plant required to meet North American Electricity Reliability Corporation (NERC)

compliance for utility-scale plants? 
38

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6 System Performance and O&M Plans

The PV O&M plan should be considered within the context of the performance period required 

for a residential or commercial PV system to generate a sufficient return on investment (ROI). 

The PV O&M life cycle begins with planning and system design. The life cycle ends with 

provision for decommissioning or disposal of the system. The asset life (about 25 years) is 

considered the performance period even though ownership may change multiple times during 

that period. 

The cost of the monitoring program can range from minimal (e.g., checking the total electricity 

generated as reported by the inverter once per year) to exceeding $100,000/yr in high-accuracy 

monitoring equipment that is watched daily for signs of problems or needed cleaning. As 

discussed below and in the appendices, the monitoring program is chosen to align with the 

expected increased revenue because it would depend on the size of the system and the logistical 

details.

A system owner is likely to seek a performance contract where a specified performance 

indicator, such as MWh/year energy delivery, is guaranteed. Indicators that account for changes 

in weather, force majeure, and anticipated degradation are recommended, such as the PR, as 

described in Appendix A. Appendix F includes guidance on how to address general downtime 

outages that affect performance.

The scope of work for the performance contract is called a Performance Work Statement, with 

“performance” being quantified by indicators such as energy delivery or availability. Appendix E 

includes an example Performance Work Statement based on the key performance indicator of 

80% of system nameplate rating and corrected for balance-of-system efficiency and conditions.

6.1 Planning for System Performance

Many performance indicators have been proposed: select a type of key performance indicator 

(KPI) that minimizes cost but ensures optimal system performance under varying conditions.

Consideration of KPIs includes how they should be used, when they are or are not accurate, 

benefits of each, and pitfalls of using them for the wrong application. PV system performance is 

based on how much time is lost when a system is not available and on the performance of the 

system when it is available. A system may have an availability of 95%, but a performance ratio 

(weather adjusted) of 100%. The stakeholders will have a much better assessment of the system 

if they measure performance based on both metrics—downtime and energy delivery. KPIs are 

also important in the monitoring and guarantee sections of this guide.

6.1.1 PV Performance Indicators

People have much different needs and expectations regarding performance indicators depending 

on their perspective. Financiers and asset managers are interested in production and revenue 

regardless of the cause, so are satisfied with high level aggregated metrics. O&M service 

providers, on the other hand, want metrics that separate issues they can control from those they 

can’t control and that identify which issues are having the biggest impact on performance and 

return to service, and thus they need a more detailed “scorecard” with subsets of DC system 

health, inverter health, and grid interactions. Examples of KPIs include the following:
39

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1. “Availability” (or “uptime”) refers to the percentage of time that a condition is met—

usually that a component or system is operating. In contrast, IEC 61724 states that 

“energy availability” is a metric of energy throughput capability that quantifies the 

expected energy when the system is operating relative to the total expected energy, rather 

than the percent of time that a plant is available, which is the more traditional use of the 

term “availability” (IEC 1998). When defining availability as a contract term (see 

Appendix F), it is important to distinguish events that are “outside management control” 

(OMC). Operators should not be penalized for events that are OMC. Availability 

standards under development strive to remove from the calculation the lost energy 

production during the time of an OMC event.

However, there are many modified forms of defined availability, the details of which can 

be segmented, and which should be explicitly documented.

A. Is the availability affected by the grid interaction (grid down, power reduction, or 

planned shutdowns to avoid grid instabilities) or by the plant itself (shutdowns for 

planned O&M downtime due to malfunction)? IECRE’s implementation of IEC 

61724-3 suggests also reporting the energy availability with external causes

identified and OMC events excluded (IEC 1998).

B. The energy availability may be reported for the complete system or for “blocks” 

within systems. For example, a 2-MW plant may consist of four 500-kW 

“blocks,” and one may be down while the other three continue to operate. The 

energy availability may be reported either for the subsystems or for the entire 

system. Block availability is more appropriate than whole-system availability 

whenever the unaffected parts of a system can continue to operate unimpeded.

C. Availability can also be specific to the components or subsystems within a 

system. For example, there may be a KPI for one service provider to maintain a 

given availability for the tracking system and a separate KPI for another provider 

regarding uptime of the inverter. See Klise and Balfour (2015) for more detail. 

When availability is applied at the component level, it may make more sense to 

use the time-based availability, reporting, for example, the fraction of days per 

year that the component was available rather than attempting to identify the 

energy availability associated with that specific component.

D. An availability specification is currently being drafted by IEC (IEC 63019, 2018)

that further breaks down unavailability into various categories. Appendix F 

summarizes the key points. Some categories may be planned categories such as 

maintenance; others may be unplanned such as equipment failure, or unplanned 

but force majeure, such as weather or grid outage.

2. “Energy availability”: Because the availability of a PV system during times of darkness is 

not of much relevance to functionality, it is useful to define “energy availability,” which 

effectively provides an energy-weighted version of the time-derived availability metric.

For a PV system, IEC 61724-3 states that energy availability is a metric of energy 

throughput capability that quantifies the expected energy when the system is operating 

relative to the total expected energy (IEC 1998). The energy availability may be 

expressed as a percentage or a fraction. The system is viewed to be operating when the 

inverter(s) is peak-power tracking and feeding energy into the grid. If a system has 
40

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multiple inverters and only a fraction of the inverters are functioning, then the calculation 

of the “operating” expected energy is calculated only for the inverters that are operating.

If a system has string-level monitoring, then the “operating” expected energy may be 

calculated to reflect only the operating strings. Measurement of the energy availability 

requires knowledge of the weather data in addition to knowledge of when the inverters 

are operating; it is described in more detail in IEC 61724 (IEC 1998).

3. “Energy performance index”: The performance index is defined by IEC 61724-3 and may 

be used to complement the energy availability metric (IEC 1998). The performance index 

compares the energy that was produced by the plant with the energy that was expected 

for the plant based on the measured weather and irradiance, and a performance model 

agreed to by the stakeholder. The performance index may be defined to stand alone or to 

complement the energy availability metric by using the options:

A. “All-in energy performance index,” which is the ratio of the total electricity 

produced divided by the electricity that was expected including all hours and 

seasons of the year.

B. “In-service energy performance index,” which is the same ratio but excludes the 

electrical energy that was expected when the system was not operating. The inservice performance index is useful toward quantifying how well the plant 

functions when it is functioning and is best used to complement the energy 

availability metric. 

4. “Energy delivery” refers to the measured MWh/year energy delivery; adjusted energy 

guarantee is discussed in IEC 61724 (IEC 1998) and NREL report Analysis of 

Photovoltaic System Energy Performance Evaluation Method (Kurtz et al. 2013).

5. “Specific performance” refers to energy delivery divided by plant rated capacity, in units 

of kWh/kW/year. This is also referred to as “array output energy” in IEC 61724 (IEC 

1998).

6. “Performance ratio” is described in IEC 61724-1 (IEC 1998) or ASTM E2848 – 13 

Standard Test Method for Reporting Photovoltaic Non-Concentrator System Performance

(ASTM 2013). The latest version of IEC 61724-1 defines several ways to calculate 

various types of PRs. Variable definitions of PR can prevent direct comparisons in some 

cases. The “standard” definition of PR does not include a temperature correction. 

Recommendations are provided in the NREL report Weather-Corrected Performance 

Ratio (Dierauf et al. 2013) on how to avoid the variability of PR with weather conditions.

Appendix A presents an example of such a description of how PR is applied. Figure 11 

shows a comparison of different definitions of PR for 2,200 systems in California as 

measured over a period of 6 years, or less for the newer systems in the sample (oSPARC 

2018).

7. “Power performance index”: Measurement of the power performance index is described 

in IEC 61724-2 and is similar to the energy performance index except that it reflects the 

power output rather than the energy output (IEC 1998). A PR is not as relevant as a 

performance index. A PR of 0.8 may be fine for some locations but not for others. PR 

will usually be higher in the winter and lower in the summer. In contrast, a more 

consistent metric is the performance index, which compares the measured power or 
41

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energy to the expected power or energy—where expected power or energy is based on 

measured weather and irradiance and a performance model agreed to by the stakeholders.

Ideally, both the power performance index and the energy performance index are close to 

unity. Thus, the performance indices are more likely to deliver consistent metrics across 

times of the year, geographic locations, and times of weather anomalies. 

Figure 11. Different definitions of Performance Ratio (as per IEC 61724) result if different values 

compared here for a sample of 2,200 PV systems. PR-1 is actual production divided by STC rating 

and normalized for insolation; PR-2 is actual production divided by PTC rating and normalized for 

insolation; and PR-3 is actual production divided by PTC rating normalized for insolation, ambient 

temperature, age of system, and balance of system efficiency. A value of PR-3 = 100% means the 

system is performing as expected. Figure by Andy Walker, NREL using data from oSPARC 2018

8. Capacity test, or “short-term performance test”: The power delivered by the inverter 

(kW) is compared to the power of the PV system as calculated as a function of 

environmental conditions by the following equation:

PPssssssssss = PPSSSSSS

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(ηηBBBB ∗ dddddddd)

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1000WW

mm2 �

IIcc

⎝

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⎛

1 − δδ

⎝

⎛�TT aaaaaaaaaaaa + (NNNNNN − 20 )

�

800WW

mm2 �

IIcc� − 25 ⎠

⎞

⎠

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⎫

where:

Psolar = predicted average power output in kilowatts of the solar system, averaged over the 

duration of the test

PSTC = rated size in kilowatts, nameplate capacity; STC refers to standard test conditions

ηBOS = balance-of-system efficiency; typically 0.77 to 0.84 (NREL 2011) but stipulated 

based on published inverter efficiency and other system details 

degr = an age degradation factor that is 1.0 initially but degrades at 0.5% per year
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Ic = measured solar insolation in plane of array (W/m2), averaged over the duration of the 

test

δ = temperature coefficient of power (1/°C), which is usually on the order of 0.004 1/°C 

for silicon PV modules and may be less for other technologies

Tambient = ambient temperature (°C), averaged over the duration of the test 

NOCT = nominal operating cell temperature, which is a number found in the 

manufacturer’s literature and is often around 47°C

The ratio of measured average power to predicted average power is the performance index based 

on the short-term performance test. Notice that this is a “spot check” on instantaneous power 

performance and does not include availability (or downtime) in the metric. Figure 12 shows an 

example of such as short-term test performed as part of a system inspection.

Figure 12. Short-term test of PV Arrays on Carport of Degatau Federal Building and Courthouse, 

Puerto Rico, showing performance commensurate with calculated expected value, including that 

power is limited to 100 kW by the capacity of the inverter on this 125 kW DC system. This test was 

conducted over a 1-hour period that included sunny periods (points to the right) and passing 

clouds (points to the left side of the graph). Figure and photo by Andy Walker, NREL

O&M managers should consider how to allocate risk associated with inaccuracy of the 

calculation of PR or error in the implementation of the evaluation method. For example, dirt on a 

pyranometer will exaggerate PR. Thus, exclusions such as clipping (high AC/DC ratio), force 

majeure, specific representations made by the O&M provider, and underlying solar resource 

considerations should be specified in calculations and the evaluation method. The exclusions are 

also organized into an information model in IEC 63019 as categories of operation as a way to 

manage unavailability data for system assessment and availability calculations in Appendix F.

Note that a dirty irradiance sensor may be a maintenance issue, but clipping may be a model 

issue, and it is useful to distinguish between the two issues. The maintenance of instrumentation 

is very important. Current PV system performance standards development suggests that a model 

should be used in the calculation, and such a model may include simulation of issues such as

clipping. An example of such a performance model is the System Advisor Model (SAM)

program by NREL (https://sam.nrel.gov/), although there are many acceptable models available.
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6.1.2 Energy Storage Performance Indicators

Combined PV and energy storage systems draw on the performance indicators included above 

and add a set of additional battery and system-wide indicators. As in the preceding PV 

performance indicators section, this section lists a number of key performance indicators to 

consider tracking. The final set of indicators will depend on system design, user needs, metering,

and data analysis capacity.

6.1.2.1 Uptime/Availability

Uptime or availability measures the percentage of time the storage system is functioning or 

available. There are several different ways to measure this indicator, including: 

• Scheduled and unscheduled downtime: Scheduled or unscheduled downtime is a 

simple first approximation of whether uptime is meeting expectations. Scheduled and 

unscheduled downtime can be aggregated for customer reporting (e.g., for a system 

owner, both scheduled and unscheduled downtime will result in lost revenue, degraded

savings, and extended payback) or the scheduled maintenance can be excluded to focus 

the indicator on operations issues. This indicator can be framed in an absolute number of 

days, as a percentage of days of the year, or as a comparative measure such as year over 

year or facility vs. facility.

• Downtime relative to expectations: A ratio of observed downtime to expected 

downtime is an additional layer of analysis to consider. The expected downtime can be 

derived from existing data from a given site, derived from existing data from a 

comparable site, or modeled. Modeling expected downtime could include integrating 

information from the OEM for the battery, expected or actual data on battery 

performance [such as depth of discharge (DOD) covered below], and sources of failure 

mode distribution data.

Regardless of which availability metric is used for reporting or ongoing operations, it may also 

be useful to disaggregate downtime to support system optimization.

6.1.2.2 Cycling and Depth of Discharge

Battery longevity for lead-acid and lithium-ion batteries is a function primarily of DOD, number 

of cycles, time spent at each level of state charge, and operating temperature. Warranties will 

often have stipulations for usage to remain eligible for coverage.

Depth of discharge: DOD refers to the percentage of capacity that is used when a battery is 

discharged. A battery that is used once a day to shift PV-generated electricity that is discharged 

down to 65% of capacity has a DOD of 35%. DOD can be measured as an average percentage 

over time with a separate indicator for the variability in the reading and the deepest discharges 

the battery typically sees. The relationship between DOD and battery life is non-linear, so 

depending on the specifications for the battery and typical usage, there may be more or less value 

in increasing granularity of DOD data. Batteries will also have a minimum state of charge that 

the battery can sustain without damage, so monitoring systems and set points should be 

configured to avoid violating that constraint.

Cycles: A cycle is typically defined as each instance the battery is discharged and then 

recharged. There are several more complex approaches to counting cycles that can provide more 
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granular data on cycling behavior, and the ideal methodology for cycle counting will depend on 

the analytical needs for battery performance evaluation. Cycle depth and frequency will vary 

based on usage of the battery. For many time-of-use shifting applications, batteries will often 

cycle one time per day or less as they charge from PV and discharge at peak periods. In other use 

cases, such as frequency regulation, the number of cycles can be much greater and more variable, 

wherein the minimum number of cycles per year can vary from 250 to 10,000 (Akhil et al. 2013). 

Cycling indicators can be tracked as a total number, as a percentage as modeled, or as OEMadvised useful life for batteries. It may also be useful to note when the battery is only partially 

recharged during a cycle. Certain lead-acid technologies will also require a periodic equalization 

charge to ensure proper longevity.

Total longevity: To estimate how long a battery will last, it may be valuable to build a model of 

the system or develop expectations based on input from similar systems or battery OEMs. If 

battery life is modeled, inputs to the model would include load profile, irradiance data, system 

sizing, efficiency characteristics, and assumptions for degradation rates. Ideally, these inputs 

would be drawn from actual system measurements, but modeled assumptions for inputs can be 

developed as well. OEMs may also to be able to provide input on what expectations should be

for battery longevity under different use-case scenarios that can be used as a basis for modeling 

or as a means of validating outputs. The expected total longevity of a battery system can be 

continually revised throughout the battery’s life based on DOD, number of cycles, and battery 

age. Honing estimates of time until replacement has benefits for reserve account management 

and predictive maintenance scheduling.

6.1.2.3 Energy Availability/Capacity Degradation

Another key performance metric is capacity degradation of the batteries. It is important to 

monitor root causes of capacity degradation and carefully diagnose and respond to issues. There 

are a number of codes and standards that can guide this data collection and analysis.

There are several different approaches to assessing battery health, and they depend in large part 

on the type of battery and how they are used. For example, for lead-acid batteries, tracking 

voltage during charging and discharging cycles may be a valuable approach to comparing the 

relative health of strings within a battery bank. Comparing resistance across cells and between 

cells can also show signs of uneven degradation. For lithium-ion batteries, increases in battery 

resistance can point to reductions in battery capacity that stem from several types of 

electrochemical degradation within the battery (Neubauer 2014).

The ultimate goal of assessing battery health is to determine if the battery is degrading 

prematurely and, if so, whether the issues are being caused by charging or discharging 

approaches, temperature deviations from acceptable operating ranges, or typical loss from 

approaching the end of usable life (IEEE 1661) so adjustments can be made and reserve accounts 

can be adjusted based on revised useable life assumptions.

Temperature is an important input for understanding battery health and performance. 

Temperature readings can be valuable data points, and some battery instrumentation will track 

temperature deviations. Tools such as the Battery Lifetime Analysis and Simulation Tool 

(BLAST) or SAM can also be used to assess temperature behavior of batteries and estimate the 
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impact on degradation. It is important to contextualize readings with temperature at testing time.

For VRLA lead-acid battery testing, IEEE Standard 1188-2005 provides adjustments for testing 

being done outside ideal temperature conditions.

6.1.2.4 Energy Delivery

As with PV-only systems, energy delivery can also be included as a performance indicator for 

batteries. Throughput based on cycling and DOD is an important indicator for battery health and 

longevity, but energy delivery in kWh/year or MWh/year can also be tracked for financial and 

operational reporting.

6.2 The PV O&M Plan

An O&M Plan is recommended for all system sizes and types, but the plan for small residential 

systems might be very simple instructions on how to monitor system status and who to call if 

things go wrong. For larger utility or commercial scale systems a detailed PV O&M plan 

prepared by the owner, EPC firm, and/or the developer and accepted by the asset manager is the 

only long-term operations plan for a PV system. The motivations of the EPC and the long-term 

operator may be different and they may clash—the EPC is more concerned with getting through 

the installation workmanship warranty period, but the operator is more interested in protecting 

the value of the system and his or her contractual agreements for many years. The O&M 

manager retains in the plan archive all the initial planning, warranty, design, and other system 

specification documents and also revises the plan as the system is constructed, maintained, and 

modified over time. The O&M plan provides the specific measures to achieve the level of 

performance specified by the KPIs in the Performance Work Statement. 

An O&M plan can accommodate different system configurations by including all the 

descriptions and measures for systems and adding the terms “if applicable”—for example, 

“lubricate tracking ring gear, if applicable.” However, the scope of work and cost estimate for 

suppliers should itemize the measures to be performed based on system details affecting 

maintenance, such as the number and types of different inverters, fixed rack vs. tracker, rooftop 

vs. ground mount, and transformer vs. transformer-less system.

6.2.1 PV and Energy Storage O&M Plan Checklist

A documented PV O&M plan for a system or fleet of systems should include the following 

(depending on system size, complexity, and investment).

List of responsible-party contact information including site owner and offtaker of power, 

utility, local jurisdiction, local landowner, and emergency numbers.

System documentation including as-built drawings, specifications, site plans, photo records, 

special safety considerations, electrical single-line diagrams, schematics, drawings, installed 

components’ “cut sheets” and warranties (including warranties from system installer), 

performance estimates, insolation/shade studies (including a description of nominal 

conditions to make it easier to see malfunctions or deviations), operation manuals 

associated with any of the equipment (including emergency shutdown and normal operating 

procedures), and contracts for preventive maintenance, service, and other operations 

documents, including contacts for each, and specified response times and availability.
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Uphold manufacturers’ preventative-maintenance measures to preserve warranties and to 

optimize system energy delivery and the schedule for each. Include details such as cost and 

current supplier of each preventive-maintenance measure and special instructions such as 

hours that work is to be performed, access to site, and locations where vehicles may be 

parked and equipment staged.

Include descriptions of operational indicators, meters, and error messages; descriptions of 

any physical monitoring setup and procedures by which performance data are to be 

archived and reported; and procedures by which data are regularly examined for system 

diagnostics and analytics.

Keep an inventory of spare parts onsite or easily accessed by maintenance crew and 

implement a process for determining when other spare parts need to be ordered based on 

component failure history.

Clearly define availability and performance metrics and events outside of management 

control.

Implement focused training program for all O&M staff on processes relevant to each worker 

and the equipment they may be working on.

Implement chronological O&M log: work order and task tracking to include initial commission 

report, inspection reports, and ongoing O&M history.

Establish procedure for responding to alerts from monitoring diagnostics, error messages, or 

complaints from the building owner. Compile a troubleshooting guide for common problems.

List all equipment with make, model, and serial numbers and map of placement in system 

(to spot trends in manufacturing defects); for each piece, list a supplier of replacement part 

(vendor).

Determine criteria to decide whether to repair or replace a component; criteria to decide 

whether to “cannibalize” a string of modules to source replacement modules or to order new 

parts; and criteria to decide if an energy storage system with declining energy storage 

capacity should be replaced.

Establish procedures for re-acceptance testing following a repair.

Budget for O&M program including costs for monitoring and diagnostics, preventive 

maintenance, corrective maintenance, and minimum exposure (line of credit) if replacement 

of inverter or more expensive corrective maintenance is needed. 

Plan for degradation in performance of and periodic replacement of Energy Storage System 

but be prepared to revise the plan based on test results and actual battery system 

performance.

6.3 Use of O&M Plan

Following construction and commissioning, the O&M plan is the only surviving operational plan 

that contains the complete history of the plant in its archive. Therefore, it is critical to ensure that 

the O&M plan is well documented and safely archived.
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• Ensure, by establishing a well-organized directory, that a well-documented and 

maintained O&M plan is available for each system in the fleet, along with a preventive 

maintenance schedule

• Maintain a tracking log for customer-driven alerts for corrective maintenance and any 

measures taken on a system; include up-to-date document service histories for each 

installation

• Maintain the O&M plan in an online mobile work-order management system (there are 

dozens); use a ticketing system to record work

• Include decommissioning in the PV O&M plan and/or asset management.

6.3.1 O&M Plan for Residential/Small Commercial PV Systems

The residential and small commercial O&M focus is on fleet performance goals rather than 

individual systems; meeting performance warranties of individual systems to meet customer 

satisfaction goals should be balanced against cost and cash-flow optimization. These PV systems 

are typically simple, small, and geographically spread out over different metropolitan areas and 

states. The aim of the operations team is to minimize “truck rolls” and efficiently schedule any 

needed work.

6.3.1.1 O&M Plan Considerations for Residential and Small Commercial

System should be installed according to SAPC PV System Installation Best Practices Guide 

(http://www.nrel.gov/docs/fy15osti/63234.pdf).

Small commercial and residential onsite inspections are the responsibility of the contract 

offtaker (small commercial) or homeowner (residential). Often the small size precludes the 

use of automated monitoring (although developments, such as micro-inverter or power 

optimizer communications, are making automated and remote monitoring more feasible).

Any inspection of fleets of small systems is usually on a representative sample rather than 

every system.

Performance guarantees should consider typical amounts of malfunction (e.g., one string 

fuse) and soiling to ensure insignificant corrections can be deferred and module cleaning 

and snow removal (by turbofan) is not provided. Treat extreme soiling situations as 

corrective maintenance.

A manual should be provided to the homeowner with contact information and description of 

operational indicators and procedures he/she can do, including clear documentation that 

states the customer is responsible for maintaining original insolation/shade study results by 

completing routine bush and shrub trimming.

6.3.2 O&M Plan for Larger Commercial and Industrial PV Systems

O&M focus for commercial and industrial PV is more on the performance of individual systems 

rather than fleets and meeting performance warranties. The investment and revenue of large 

systems justifies more detailed monitoring for anomalies in performance and increased 

communications and sensors to trigger condition-based or corrective maintenance services and 

alerts. Module cleaning, snow removal (i.e., for access to and in front of modules, only from 

modules themselves in unusual circumstances where required, such as excessive weight of 
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snow), and tree trimming, for example, should be included in the O&M plan and schedule of 

services and based on the plant environment (e.g., dusty) and financial and performance goals.

The PV O&M cost tool supports modeling of different regimes (see Appendix B). One of two 

reference modules could be cleaned to compare and evaluate the effect of cleaning; this 

information could be used to trigger a cleaning based on cost.

6.3.3 O&M Plan Considerations for Commercial and Industrial

Key considerations for an O&M plan for systems larger than 500 kW include the following.

Automated monitoring with diagnostics to push error alerts triggering corrective maintenance

Continually analyzing performance information to optimize condition-based O&M, such as 

cleaning, and long-term issues, such as reliability trends

Providing offtaker with manuals containing contact information and descriptions of their 

participation and responsibilities, self-inspection of the system, and what conditions 

necessitate the O&M provider to be notified of problems

Providing offtaker with a shelter onsite for workers to meet and look at plans if size warrants

6.3.4 O&M Plan Considerations for Energy Storage Systems

Key considerations for an O&M plan for systems that involve energy storage include the 

following.

Plan for a steady decline in capacity of the energy storage system, consider the storage 

requirements at the end of the battery life, and set criteria for when the capacity is 

insufficient and the battery will be replaced; plan for contingency that the battery will not last 

as long as the manufacturer claims—in field applications, batteries may only last half as long 

as manufacturer literature suggests.

Consider non-invasive monitoring of battery health; maintain good records so that decline in 

energy storage system capacity and efficiency are charted relative to as-new performance.

Ensure that charge control is specific to the type and configuration of battery installed and 

that charge rates are corrected for temperature and within the specified limits of the battery.

Provide for demand control (load control) to ensure that specified limits are observed for 

battery discharge rates and DOD—this may require that the load be curtailed to prevent low 

DOD (e.g., low voltage disconnect).

Provide for heating and cooling of battery enclosure to keep batteries within specified 

temperature limits and ensure that air flow is effective at removing heat from batteries.

Do not mix old cells of high impedance with new cells of low impedance in the same string, 

which would result in higher voltage and sulfation in the high impedance cells. Sulfation

further increases internal resistance, exacerbating the problem. Replacing failed cells with 

new batteries kills the remaining old batteries more quickly. Consider cannibalizing a string 

of cells with similar impedance and then installing new cells in a new string under separate 

charge control.
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Have a fund (i.e., reserve account, line of credit, sinking fund) to supply an eventual battery 

replacement. Battery maintenance costs increase as a battery plant ages, so have a 

strategy of when to replace batteries and how to do so in a phased way so that some 

service to the load can continue.

6.4 Document Management and Record Keeping

Documentation is essential to O&M services, and important records include the physical 

condition of a PV plant, current contracts for services, insurance policies, tax records, proof of 

ownership, compliance with regulations, warranties and the terms to keep warranties in effect,

records of past changes to the system, and records of past corrective maintenance services and 

the results of each. Before undertaking any maintenance service, the service provider must know 

what equipment was installed initially and any changes that have been made since. If not 

available, such records should be created (complete set of as-built drawings) at the cost of the 

asset owner. Some problems are difficult to diagnose and solve, so records of what has been 

attempted previously are often essential for eventually correcting the problem. Good record 

keeping of work orders and trouble tickets is required to ensure that each issue is ultimately 

resolved.

A document management system provides proper storage, access control, change control, and 

backup of essential data. A log should be kept of who has accessed the documents, who has 

taken them out, and what modifications were made, if any. Version control should be 

implemented so that people can see what document is currently in effect and can look at the 

history of the document.

6.4.1 Document Management Checklist

Considerations for managing documents in a structured document management system include 

the following.

Maintain list of responsible party contact information including site owner and offtaker of 

power, utility, local jurisdiction, local landowner, and emergency numbers.

Maintain list of all equipment with make, model, and serial numbers and map of placement 

in system.

Maintain all documents produced by the EPC, including as-built drawings (e.g., plant 

location, property boundaries, plant layout, electrical diagram), specifications, product data

sheets, and wiring diagrams.

Maintain operating manuals for inverters and other equipment.

Maintain documentation of health and safety issues and rules.

Maintain records and reports from commissioning, re-commissioning, and inspections.

Maintain past and current contracts with all service providers and suppliers’ names, start 

and end dates, scope of work, contract value and pricing, performance indicators and 

guarantees, and contract clauses.
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Maintain preventative maintenance and inspection records (proof that preventive 

maintenance required to keep warranties in effect has been completed), as well as 

corrective maintenance event logs [alarms (with date); status (problem flagged, cause 

identified; pending, action taken, confirmed that problem is solved); corrective action taken 

and date; who did the work with contact information].

Maintain an inventory of spare parts: stock count and location, names and part numbers,

date purchased.

Maintain all warranty documentation: warranty documents and claims made (affected 

equipment, claim description, occurrence date, correspondence with manufacturer/supplier).

Document environmental (weather) conditions: meteorological data (insolation in plane of 

array, temperature, other such as wind speed).

Document production data: AC active and reactive power at point of interconnection, power 

consumption of auxiliary systems and “house power,” power at other subsystems such as 

DC power into inverter, and other measurements as available.

6.5 PV Plant Operations

PV systems are often thought of as passive systems without much “operation” as a conventional 

fossil-fuel engine. However, operations programs that consisted largely of delivering solar power 

whenever it was available are becoming obsolete. PV system operations is a growing field 

because increasing PV penetration into the larger utility system and an emerging market for 

ancillary services (e.g., dispatch of storage, sourcing reactive power, curtailment of output) 

require more system interaction on an ongoing basis. Plant operations include forecasting output,

scheduling maintenance operations, creating a spare parts inventory (either in stock onsite or in 

supplier’s consignment stock), and inspecting work and approving invoices. Meanwhile, 

operations include any day-to-day operation of the system to maximize power delivery, assess 

performance and trends, operate grid interface, manage curtailments, or adjust settings such as 

power factor.

6.5.1 Forecasting PV Plant Output

Plant operations include forecasts of power and energy delivery hours and days in advance.

Suppliers of PV monitoring systems often also supply production forecasts based on proprietary 

or publicly available weather forecasts, satellite data, and statistical methods. In addition to these 

weather-based forecasts, the operator should impose any scheduled outages or maintenance 

services that affect the forecasted plant energy delivery. Forecasts are important for two 

applications:

• Allow PV systems to participate in markets that require advance (e.g., “day-ahead”) 

contracts to provide power. Such contracts come with an associated level of reliability 

and financial penalty for non-performance, so an accurate forecast is essential to 

participate in such day-ahead markets. 

• Allow for unit commitment and dispatch of conventional resources (e.g., diesel 

generator), which is essential in a micro-grid application or for a remote system (such as 

on an island out in the sea) and is desirable in mainland grid-integration efforts.
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Metrics associated with forecasting systems include:

• Forecast horizon: How far in advance the system predicts PV plant energy delivery.

Some provide a 2-week forecast, but the second week appears to be the astronomical (sun 

position) forecast, and only the first week appears to incorporate site-specific weather 

forecast.

• Time resolution: When using conventional weather forecasting techniques, hourly is 

considered state of the art. To get higher time resolution may require onsite sky 

observations. Image processing instruments to project cloud movement have been 

invented and demonstrated but are not yet in commercial use. Likewise, models to predict 

cloud formation based on thermodynamics and transport phenomenon in the atmosphere 

are in their infancy. 

• Update frequency: How often is the forecast updated? For example, one vendor updates 

its forecast every 4 hours.

• Accuracy: Accuracy of the forecast can be proven over time by taking the root mean 

square error (RMSE) of the production forecast compared to actual plant output and 

considering other factors such as if parts of the plant are dirty or out of service for 

maintenance.

6.5.2 Energy Management Control Approaches for PV Plus Storage Systems

Energy management (control) systems become a critical element of system economics when a 

battery is paired with solar PV. There are a number of different energy management approaches 

that are applied to PV plus storage systems. The selection for a given context will depend on 

constraints based on system design and topology, markets, and costs. In a residential setting for a 

system that is AC-coupled, the interconnection requirements and relevant regulations may 

preclude storing grid energy, and the algorithm may be as straightforward as pushing excess 

solar energy into the battery and then using the battery until it reaches minimum charge levels 

whenever the solar PV is not generating electricity. On the other hand, a micro-grid that has solar 

PV, a battery, and a diesel generator can have a much more complicated control algorithm and 

requirements on control solutions. If demand management is introduced as another option, the 

possibilities to optimize system performance and cost savings expand but so does the complexity 

of the supporting energy management and control systems.

6.5.2.1 Control Approaches

This subsection discusses some of the issues to consider in settings where there is flexibility in 

control approaches, such as the PV, battery, and diesel generator use case mentioned above. 

In residential grid-connected settings, the control algorithm decisions tend to be more narrowly 

bounded than in other use cases. The systems are fairly small, the customizations are limited, and 

the economics at play are more straightforward. As discussed above, the most common approach 

is to take advantage of the battery to maximize usage of the power that is being generated by the 

PV to minimize curtailment during the day. A modification of this approach, which is contingent 

on rate structures that include meaningful price changes during peak periods, is time-of-use 

shifting using the battery. This would again call for limiting curtailment during the day but then 

also discharging the battery to meet household loads during peak charge times. 
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In commercial or industrial settings, the control choices will be driven in large part by the rate 

structure and load profile. For example, demand charge management through a PV plus storage

system dictates the strategy for when to discharge the battery and when to charge it. In these 

situations, the control algorithm will be more complicated and likely call for some degree of 

forecasting and monitoring PV power, load profiles, and demand charges. The approach that 

comes from that modeling exercise will be custom to each individual commercial or industrial 

customer.

In utility settings of avoiding curtailment, model predictive control algorithms may be applied to 

take forecasts and wholesale market pricing into account. There are also settings where the 

battery can serve a ramp-rate control function in addition to the time-of-use shifting application, 

which has operational and control algorithm ramifications.

6.5.3 Inventory of Spare Parts

The O&M service provider is usually responsible for stocking spare parts, but the asset owner 

may also participate in spare-parts ownership and storage. Parties should agree on “bailment,” 

which is liability if the parts are stolen or damaged in storage, and the party providing storage 

should have insurance to mitigate such risk. Storage should provide for security (e.g., theft, 

vandalism), storage conditions (e.g., temperature, humidity, moisture), and organization (e.g., 

first in-first out, do not mix new and returned parts).

As part of the O&M manual and system documentation, the EPC contractor should have 

provided a spare-parts list with makes and model numbers, as well as recommended sources of 

such parts. Frequently used parts are called “consumables” and should always be stocked (e.g., 

fuses, filters, nuts, and bolts). The number of other spare parts in inventory depends on several 

factors: the reaction time required by the O&M contract, the allowable downtime, contractual 

commitments, and potential for liquidated damages. The higher the desired (or contractually 

required) availability for a plant, the more spare parts will have to be kept in inventory.

As discussed in more detail below regarding a cost estimate for a reserve account, the number of 

replacement parts to keep in inventory, n, depends on the total number of parts (of that 

component) in the system, N; the probability that a part will fail in a given year, P; and the 

desired reliability, R, according to the relationship n = N * R^P / (1 - P). The cost of maintaining 

this amount of inventory must be weighed against the time delay in obtaining parts not in the 

inventory and the consequences of down time. Experience with this equation indicates that it is 

prohibitively expensive to stock parts to maintain a desired reliability of greater than 

approximately 0.95. Experience in operating the plant (i.e., which parts fail, which failures result 

in lost production) will help fine-tune the inventory of spare parts.

Strategies to reduce the cost of maintaining an inventory of spare parts include:

• Maintaining regional clusters of systems surrounding a warehouse to share stock and 

reduce travel time; sharing spares for long-lead-time items such as inverters and 

transformers among multiple projects in a portfolio

• Standardizing certain makes and models to reduce diversity in stock

• Making arrangements with suppliers to guarantee availability or consignment stock with 

the manufacturer.
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6.5.4 Compliance with Regulatory Requirements

Large PV power plants (i.e., greater than 20 MW at the utility interconnection) that provide 

power into the bulk power system must comply with standards related to reliability and adequacy 

promulgated by authorities such as NERC and the Federal Energy Regulatory Commission 

(FERC). This requires that an operator trains and certifies personnel and demonstrates 

compliance with multiple requirements specified in standards. NERC and FERC regulations 

require that the operator establish and maintain a listing on the NERC compliance registry as a 

generator owner (GO) and generator operator (GOP) and provide and document such things as 

cybersecurity and critical infrastructure protection, emergency preparedness plans, reactive 

power and voltage control, services during and after disturbances, active power control,

harmonics, facility interconnection studies, and communications (voice and data link) between 

plants and grid operators. PV plant operations increase quite a bit and impose additional 

maintenance requirements if the plant operator is registered by NERC as a GOP. Most of the 

services and associated costs are associated with the systems and security that come regarding 

the documentation process. There is also a risk of incurring costs associated with not meeting the 

FERC/NERC requirements.

6.5.5 Operations Checklist

Operations considerations include the following.

Is system performance monitored and recorded? Are trends in performance examined 

continuously or regularly?

Does the monitoring supplier provide forecasting? At what horizon, time resolution, update 

frequency, and accuracy?

Are corrective maintenance response times specified in the contract?

Is module degradation rate specified?

Are all service contracts and insurance policies kept up to date?

Are all required operating permits, compliance documents, and licenses kept up to date?

6.6 Preventive/Scheduled Maintenance

Preventive maintenance maximizes system output, prevents more expensive failures from 

occurring, and maximizes the life of a PV and energy storage system. Preventive maintenance 

must be balanced by financial cost to the project. Therefore, the goal is to manage the optimum 

balance between cost of scheduled maintenance, yield, and cash flow through the life of the 

system. Preventive maintenance protocols depend on system size, design, complexity, and 

environment. A comprehensive list of these protocols is supported by the PV O&M cost model 

included in Appendix B.

The requirements for periodic maintenance for energy storage products should be identified by 

the OEM (IEEE 2010). In settings where predictive analytics maintenance is economical, 
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guidance should also be available from the manufacturer that identifies methodologies for 

assessing when a product may be approaching a failure mode.

As discussed briefly in Section 5, design aspects of storage systems will inform scheduled 

maintenance cost and benefit analysis. For example, in some systems, it is preferable to build the 

battery bank in multiple separate strings so that maintenance can be made on a single string 

without shutting down the full battery and all the storage-tied components. Data granularity also 

has a bearing on what preventive maintenance is deemed economical. For example, real-time 

cell-level data have the potential to identify and justify preventive maintenance that may not be 

visible at the battery string or battery bank level.

Figure 13. The National Park Service budgets, ideally, $100,000 per year for O&M of this PV energy 

storage system (308 kW PV; 1,920 kWh battery) on Alcatraz Island. Photo by Andy Walker, NREL

Figure 13 shows the PV energy storage system on Alcatraz Island. The National Park Service 

budgets ideally $90,000–$100,000/year for maintenance of this 1,920-kWh battery storage plant, 

including a monitoring contract for $30,000/year; battery testing for $5,000 three times/year; and 

PV array cleaning and maintenance for $15,000 twice per year. There are 480 cells in two strings 

of 240 cells each, and O&M staff feel that more parallel strings would ease maintenance 

scheduling. Battery replacement is planned on an 8-year cycle. Battery replacement provides an 

opportunity to revisit battery type, size, and voltage. Inverter replacement is planned on a 10-

year cycle and battery management system on a 7-year cycle (information from Jeff Obirek, 

National Park Service, provided for a tour March 2016).
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6.7 Corrective Maintenance

Lost revenue accrues while a system is down or when output is reduced. Repairs should be 

delayed only if there is an opportunity to do the repair more efficiently in the near future.

Response time for alerts or corrective action for the O&M function should be specified as part of 

the contract but typically will be 10 days or less for non-safety-related corrective maintenance 

service. For small residential systems, a fleet operator may make repairs only when enough work 

has accumulated to justify a truck roll to the area or at the next regularly scheduled 

preventive/inspection of a site. Appendix C contains service descriptions for corrective 

maintenance selections available in the PV O&M cost model. This cost model (described in 

Section 11) provides an estimated prediction of the corrective maintenance costs from year to 

year, but it is impossible to accurately predict when and where failures will specifically occur. 

The model has the ability to use fault and failure probabilities of specific components, if known.

Additional considerations include the following:

• The O&M plan should include how to perform corrective maintenance quickly in 

response to field failures, including how funds may be used from a reserve or line of 

credit.

• Response time and urgency of repair specified in the O&M plan should balance the cost 

of a “truck roll” with lost revenue. Consider system size, geographic location, spare-parts 

inventory, other scheduled maintenance, fleet performance requirements, and cost of 

response.

• Faults or conditions that introduce a safety problem should be addressed as soon as 

possible, even if the recovered revenue is small.

The O&M plan should include procedures for replacing batteries, including relevant safety 

requirements for handling and transporting batteries. Strategies for replacing batteries vary based 

on system topology and battery technology. For example, with VRLA lead-acid batteries,

replacing individual cells in a string may not be optimal if the system has been running for a 

period of time. The imbalance in the resistance between the new and older cells (even if 

functional relative to degradation expectations) can cause the new cells to degrade faster than 

scheduled.

6.7.1 Enforcement of Warranties

There is a distinction between “product warranties” and “performance warranties.” Product 

warranties cover materials and workmanship and protect a purchaser against failures due to 

manufacturing defects (Figures 14 and 15). Most solar panel manufacturers provide product 

warranties of 10–12 years, although some are as short as 5 years and one extends for 25 years. 

The performance warranty guarantees a certain power output that declines over time because the 

manufacturer knows that there will be some natural degradation in the performance, usually 

ending up at 80% of the initial rating after 25 years. PV modules are unique in that they carry 

very long-term performance warranties of 20 or 25 years (very few types of electrical equipment 

have such long warranties). The schedule of the decline in anticipated power output has an 

impact on the value of the warranty, with manufacturers offering a linear decline in the 

guaranteed output, claiming that they provide a benefit over those that reduce the guaranteed 

performance in a stair-step fashion. In the past, inverter warranties were only for a 1-year term,

but starting initially with European manufacturers, a 10-year warranty is now more the norm, 
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with some offering the longer term only along with a 10-year service contract. The EPC 

contractor may offer a shorter-term warranty (e.g., 1-year, 2-year) on the entire plant including 

civil works such as storm-water management.

Figure 14. Failure in materials and workmanship, such as encapsulant of this module, are often 

covered by product manufacturer’s warranty. Photo by Andy Walker, NREL
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Figure 15. Snail trails in encapsulant are attributed to cracks in cells caused by flexure of the 

panel at the factory, shipping, or installation. The module would be covered by the performance 

warranty only if the cracks isolate fragments of the cell and reduce the output over time. Photo by 

Andy Walker, NREL

Many financiers do not have faith in manufacturer’s warranties for the following reasons:

• A warranty may be voided by mishandling or not observing instructions or conditions of 

the warranty. For example, storing modules improperly onsite, such that the packaging is 

destroyed by rain, may void a warranty (Figure 16). Failure to provide adequate 

ventilation may void an inverter warranty. 

• Even reputable PV manufacturers with quality products have gone out of business.

• It is difficult to prove that a module is underperforming, and it might require an 

expensive standardized test of each module.

• The manufacturer’s warranty might cover replacement but not labor to remove, ship, and 

re-install an underperforming module. In marketing literature and proposals, the dealer 

may offer to cover these labor costs, but such language rarely makes it into the final 

contract because small local dealers are not in the position to incur such costs.

• The warranty often gives the manufacturer the option to “repair, replace, or supplement,” 

with “supplement” meaning to provide modules to make up the difference in lost power.

For example, if a system has 100 modules that are underperforming by 5%, the guarantor 
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could satisfy that by providing five additional modules to make up for the lost power, 

rather than replacing the 100 modules. However, increasing the plant size by five

modules to restore guaranteed power might not be possible due to lack of rack space or 

electrical infrastructure. Also, expanding the system “nameplate” capacity would 

generally trigger a new interconnect agreement and permitting, even though it would 

generate no more than the initial amount of power.

• Manufacturers often have the option of paying a cash-value equivalent to the lost 

capacity of underperforming modules, but as the price of modules declines, this might be 

less than originally paid for the modules. Given the complications described above, this 

option is often preferred by system owners unless there is a required level of performance 

that must be maintained.
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Figure 16. Failure to follow product box handling and storage requirements can cause damage 

when moved and void a warranty. The umbrella symbol on this box indicates it should be kept dry 

and the box might fail when picked up with a forklift. Photo by Andy Walker, NREL

Financiers take warranties into account in their financial prospectus only when offered by larger, 

more reputable, or more diversified companies with a sound credit rating. To hedge risk, 

warranty insurance is available from insurance companies, but adding the cost of such insurance 

to a project reduces the ROI or may make a competitive bid too high to get the contract. The cost 

of such insurance is lower for portfolios than for individual projects because risk is mitigated by 

a diverse collection of manufacturers—if one manufacturer goes out of business, it would affect 

only part of the portfolio (Ben Cook, NextPower Capital; Michael Bishop, ONGRID Solar; and 

Mike Borger, RECSolar, telephone conversation, September 23, 2016.).
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6.8 PV Module Degradation Rate; Degradation in Energy Storage 

Capacity

When comparing measured performance to predicted performance, it is important to consider the 

expected degradation in PV module output over time in the prediction. Prior to 2000, degradation 

rates exhibited considerable variability; currently, these rates are more uniform among types and 

manufactures and are often on the order of 0.5% per year (Jordan and Kurtz 2012). However, 

module degradation rates are only part of the story. As modules degrade, they do so at varying 

rates. This causes an induced circuit-level mismatch loss that should also be modeled. Some 

module-level power electronics (MLPE) solutions have the advantage of minimizing this added 

mismatch loss.

This is not to be confused with the failure rate of modules. PV module failures are rare, with a 

reported failure rate of 0.025%/year to 0.1%/year (Dhere 2005), depending on the source.

Measured and predicted performance can be compared using a module degradation value given 

by the manufacturer. If no value is available, one can assume a default value of 0.5% per year for 

new crystalline silicon products.

Degradation is calculated based on the age of the system at the time of evaluation. But for life

cycle cost analysis, a degradation factor of 0.94 provides an estimate of the degradation levelized 

over a 25-year lifetime with a 5% discount rate.

Module type does not have a large effect on raw O&M cost ($/year), but it has a tremendous 

effect on cost of O&M per kilowatt-hour delivered—especially late in the performance period 

when production is markedly decreased, failure rates are higher in the aged equipment, and 

inflation has increased the per-unit O&M costs. The impact of O&M costs on levelized cost of 

energy (LCOE) is much less with PV modules that have lower degradation rates.

Table 3. Representative PV Module Degradation Rates (Jordan and Kurtz 2012)

PV Module Type Degradation Rate per Year

(%/year)

Amorphous silicon (a-Si) 0.87

Monocrystalline silicon (sc-Si) 0.36

Multicrystalline silicon (mc-Si) 0.64

Cadmium telluride (CdTe) 0.40

Copper indium gallium diselenide (CIGS) 0.96

Concentrator 1.00

Degradation rates in batteries depend heavily on usage, temperature, and shelf life. OEMs will 

typically provide a chart that pairs anticipated cycling with DOD, which can be used to model 
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use-case-specific degradation rate expectations. That approach will produce an estimate that 

should be cross-referenced with actual data from the battery over time. Battery lifetime in field 

applications is often about half of that in manufacturers’ literature, most likely due to 

overheating and, for many PV applications, long periods at low state of charge. Energy storage 

systems used in PV applications are usually discharging their capacity and then waiting for the 

solar resource to recharge, in contrast to energy storage applications that can keep the batteries 

under optimal float voltage and maintain long battery life.

6.9 Example Work Statements

A contract to implement an O&M plan or part of an O&M plan should include a complete list of 

obligations under the contract. Examples of commercial-system work statements are detailed in 

Appendix E; the statements contain a maintenance “Schedule of Services” typically found as an 

addendum to an O&M contract comprising a fixed contract fee, with provision for an added 

time-and-materials cost adder for non-warranty corrective maintenance. Schedules are included 

for commercial rooftop and ground-mount systems. Appendix F outlines the foundation for 

developing language that can be utilized in model equipment availability terms typically 

included in an O&M services agreement for a PV system and between a plant owner, operator, 

and O&M services provider.

6.10 End-of-Performance Period

The economic prospectus for a PV project contemplates an initial investment followed by a long 

performance period. Life cycle cost standards specify a maximum of 25 years for electrical 

equipment (10 CFR 436), but there is evidence that PV systems could last longer and some 

industry guidance suggests a 40-year analysis period (EISA 2007). Asset owners and managers 

will have several options at the end of the performance period depending on the contractual 

commitments to the landowner and regulatory requirements of the authority having jurisdiction. 

These options include:

• Refurbishing the system and extending its life (e.g., 25 years to 40 years)

• Extending the term of the performance contract or PPA

• Selling the system at fair market value

• Removing the system and restoring the site to an earlier condition or other use.

The rate at which PV systems are being installed today will be equal to the rate of system 

disposition in 25 years or so. Relevant U.S. law here is codified under the U.S. Resource 

Conservation and Recovery Act (RCRA) governing non-hazardous waste (Subtitle D) and 

hazardous waste (Subtitle C). These laws assign responsibility to the generator of waste, 

although some PV manufacturers also practice extended producer responsibility (e.g., 

http://www.firstsolar.com/Modules/Recycling). Today’s manufacturer may in 25 years become a 

recycler, or rather, a re-processor of PV modules and other components. Components should be 

designed for recyclability and to control toxic materials. Current best practices are to minimize 

hazardous materials and/or design for recyclability and control of such materials (IRENA 2016).

Such foresight in recyclability and management of substances may affect the eventual cost and 

benefits of end-of-life PV waste management. During project permitting, decommissioning plans 

may include site-restoration requirements and financial mechanisms to deal with recycling or 
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proper disposal of waste. Such planning would likely consider the value of recovered copper, 

aluminum, and steel, which can be substantial.

Demonstration projects at SolarWorld and commercial-scale recycling operations at First Solar 

have shown that 84% to 90% by weight of a PV module can be recycled (Larsen 2009).

If a system transfers ownership, it is important to consider how warranties are handled. Often,

manufacturers or EPCs will not honor the warranty if the original purchaser no longer owns the 

equipment. However, many manufacturers have a process for transferring the warranty to the 

new owner. Such a process typically consists of paperwork, a small fee, and a finalization period 

(usually 30 days) after the equipment sale. This service must be planned along with the rest of 

the ownership transfer process.

6.10.1 Battery Failure Patterns

As discussed above, batteries lose capacity and efficiency over time and with “throughput” or 

energy in and out of the battery. Manufacturing literature might cite a “cycle life” and often as a 

function of DOD. For lead-acid batteries, time spent at a low state of charge leads to 

irreversibility in the reaction and damage to the battery. This is cited as an advantage of battery 

material systems other than lead acid that can accommodate a deep discharge for long time 

periods.

Lifetimes of 1,000 or 2,000 cycles for lead-acid batteries are typical, with 10,000 cycles being 

the goal for research in new materials systems such as Lithium-ion. There is a gradual reduction 

in capacity over time beginning before the battery is even installed and increasing with use. So 

“lifetime” implies some criteria as to when the battery needs to be replaced. For applications 

where reliability is important, a cell whose capacity had fallen to 80% after 1,000 cycles would 

probably be slated for replacement, but in many applications, the battery could continue working 

until perhaps 2,000 cycles when its effective capacity will have fallen to 60% of its initial 

capacity or longer, as long as the user can live with the reduced capacity and as long as 

variability in the status of individual cells does not lead to physical or catastrophic failure. Figure 

17 shows now not only the electrical performance but also the physical condition of the battery 

can affect the need for replacement. Actual capacity of a battery can be measured by a 

charge/discharge test, but this requires that operation of the battery be interrupted for the 

duration of the test. An alternative measure of cycle life is based on the internal 

resistance/impedance of the cell. In this case, the cycle life is defined as the number of cycles 

that the battery can perform before its internal resistance increases by a specified amount, such as 

1.3 times the initial value. When battery systems are specified, it is usual to specify the required 

capacity at the end of life rather than its capacity when new.
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Figure 17. Premature failure of a lead-acid battery caused by low state-of-charge for an extended 

period of time can be avoided only by periodic fully saturated charge of the battery. A battery can 

recover from amorphous sulfation; but, given time to crystalize, the degradation in capacity and 

efficiency is permanent and can cause swelling and breakage of the battery jar. Photo by Andy 

Walker, NREL

6.10.2 Battery Recycling and Reuse

In combined PV and storage systems, the above end-of-life considerations apply, but batteries 

also bring their own end-of-life issues. It can be expected that batteries will be replaced two or 

more times during the typical life of the PV system they are anchored to. End-of-life disposition 

activities and options for batteries depend on the technology employed. In all cases the supplier 

or a community-based waste management solution takes the battery back for recycling. Consult 

with the supplier regarding disposal before purchasing a battery and for large battery purchases 

require a guarantee or bond that the spent batteries will be recycled. This subsection provides a 

brief background on lithium-ion and lead-acid end-of-life issues and associated recycling 

industries.

6.10.2.1 Lead Acid

Recycling lead-acid batteries in combined PV and storage settings benefit from widespread 

usage of lead-acid batteries in other industries, such as automobiles, and regulations on their 

disposition in many settings because lead is toxic. The regulation and the battery market size led 

to the development of a healthy recycling industry. Lead-acid batteries are also composed of 

roughly 65% heavy metals that support the economic case. Recovered lead can cost less than 

mined lead as a result (Gies 2015).
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6.10.2.2 Lithium Ion

Lithium-ion batteries are less regulated for end-of-life issues, and the batteries themselves are 

more complicated to recycle than lead-acid batteries. While lead-acid car batteries have more 

natural touch points for recycling markets, lithium-ion batteries are dispersed into a number of 

different products in different shapes and sizes, further complicating market development (Gies 

2015).

As the market for lithium-ion grows, in particular through electric vehicle market growth, there 

may be more of a push to ensure products are recycled and reused (Gaines and Nelson 2010). It 

is also possible that economics will drive greater recycling (e.g., increased costs of new materials 

for battery manufacturing).

6.11Evaluation of O&M Plans

Evaluation of an existing/ongoing O&M plan involves:

• Assembling a qualified team to conduct the assessment; scheduling and organizing team 

meetings and at least one site visit. The team designates a team lead and functional O&M 

leads for each area such as site, operations, and maintenance. 

• Planning the steps to go through, logistical issues, and selection of an “assessment 

database,” a web tool, spreadsheets, or databases to manage the information.

Conducting the assessment includes:

• Reviewing documents and procedures prior to a site visit

• Visiting the site to collect information and observe site conditions

• Interviewing personnel at in-person meetings, on the phone, or in a webinar—most 

assessors deem closed in-person meetings as most effective for candid review

• Entering data into the assessment tool (web tool, spreadsheets, or database). The 

operations lead will collect and enter information regarding each area. An example of 

what each topic lead will be looking at includes:

o Operations lead collects information regarding shift turnover procedures, security 

and clearances for staff to site and computer systems, frequency and content of 

shift meetings, control room procedures and performance, operator rounds,

condition and performance of operations equipment such as monitoring and 

control systems, effectiveness of record keeping.

o Maintenance topic lead will enter information regarding work management; 

inspections; frequency and content of crew briefings; confirmation of training 

requirements, certifications, and personal-protective equipment (PPE) for such 

things and arc-flash protection, lock-out/tag-out, and general safety; maintenance 

support; presence and condition of labels and signage; orderly site and 

housekeeping issues; and condition of tools and equipment.

• Comprehensively analyzing performance of the attribute ratings and comments, including 

data review and identification of strengths and improvement items

• Briefing client, site management and O&M team, first-line supervisors, and others as 

deemed necessary about the strengths and improvement items with supporting 
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information. Plant staff are present to ask questions and clarify any of the information.

The briefing should conclude with a discussion to confirm that plant staff understand all 

of the recommendations resulting from the assessment.

• Delivering written report after the briefing and incorporating any clarifying information 

derived from the briefing. The report should include information about the assessment 

team and the overall scope of the assessment, an overall summary of the plant’s assessed 

performance, strengths, and recommendations for improvement including a means to 

confirm that the improvement has been implemented. The report should also include 

references where site staff can find relevant guidance. As an appendix, the final report 

may also include the database of ratings and observations.

The Electric Power Research Institute (EPRI) promulgates guidelines and a web-based tool for 

conducting comprehensive O&M assessments of power plant performance, which can be adapted 

for use with PV systems (Buck 2018). Use of such a standardized approach provides a means 

whereby the policy, process, and execution of O&M plans and execution are assessed in a 

uniform way and more independent of individual reviewer’s opinions.
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7 Health and Safety

The asset owner is ultimately responsible for safety related to a PV system and must meet that 

responsibility through the specific requirements of O&M service contracts and mitigate risk 

through accident and liability insurance. O&M of battery systems involves important 

considerations related to environmental and safety requirements. Batteries often involve 

materials, such as the acid and lead found in lead-acid batteries that present not only immediate 

hazards to personnel but also careful custody over the life of the battery, concluding in full 

recycling of a worn-out battery.

In the United States, OSHA (www.osha.gov) promulgates regulations related to workplace 

safety. PV health and safety issues include affect those involved in construction or electrical 

maintenance work, vegetation control, and PV systems. Roof fall protection, electrocution, arcflash protection, lock-out/tag-out, and dehydration and heat stress are of special importance to 

workers providing maintenance of PV systems. It is important to recognize that health and safety 

issues are relevant to all personnel and work locations, even office workers (e.g., ergonomics, 

safe work environment). All workers must have at least basic training in safety and at least an 

orientation to hazards specific to each system.

O&M services are usually done by small teams of workers, and it is cost-prohibitive to have a 

dedicated health and safety professional with each team for each site visit. As a result, the O&M 

contractor depends on a strong safety culture, along with well-trained workers. Health and safety 

is usually considered an indirect cost, and it falls into the overhead cost category. It consists 

mainly of training, inspection, and auditing functions, with typical services that may include:

• Periodic inspection of personal protective equipment

• “Ride-alongs” to watch workers perform their jobs, capitalizing on teachable moments

• Site inspections to ensure that measures such as dead fronts on electrical panels and other 

guards are in place.

Because PV systems only produce power from sunrise to sunset, O&M teams have a plant 

shutdown every night. Many O&M contractors do their work at night, only working on deenergized systems. Although nighttime work introduces its own risks, these are lower than risks 

present when equipment is energized. Working at night assumes that problems have been 

identified with certainty and that the work being done is likely to solve the problem (EUCI 

2016).

PPE is required for all jobs depending on the hazards. It is important to understand that providing 

the equipment is not enough—the user of the equipment has to be trained and, in most cases,

certified in its use, and the condition of the equipment has to be continuously assessed and the 

equipment replaced if need be. PPE often encountered in PV system maintenance includes the 

following (which is not all-inclusive and depends on particular circumstances):

• General: Most sites will require at all times a helmet, safety glasses, safety vest, and work 

boots (steel-toed preferred).

• Lock-out/tag-out: Locks and tags are shaped to fit onto the types of switches and breakers 

in the system and the procedure of locking out circuits so that someone unaware does not 

energize a circuit that someone else is working on.
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• Fall protection: Working at elevated heights requires fall protection, which may include 

personal fall arrest systems and guardrails around openings and edges of roofs.

• Arc-flash protection: Face shield, helmet, gloves, and apron suited for the amount of arcflash energy that is calculated based on details of the circuit being worked on.

Storage systems in PV plus storage settings call for many overlapping safety standards and

precautions, particularly those that apply to working on DC wiring, and bring a set of 

technology-specific new considerations. Many storage systems will be built to various standards 

for safety, but there is an ongoing O&M role in keeping facilities to standard. 

7.1 Energy Storage Safety Considerations

General battery safety rules include: remove any jewelry before handling batteries; wear 

protective clothing, especially safety glasses, apron, and gloves; use proper insulated tools; 

disconnect batteries from power source while working around batteries; wash hands after 

handling batteries; provide warning label areas where batteries are charging; ensure proper 

venting of battery enclosure; keep open flames and sparks away from batteries; no smoking near 

batteries; have baking soda or neutralizing agent accessible to neutralize acid spills; do not water 

batteries before equalizing; and do not measure current (amps) across terminals, voltage only.

Follow any additional manufacturer’s safety instructions. There are many codes and standards 

relating to safety of stationary energy storage at the local, national, and international levels by 

UL, NFPA (NEC, 70E), ANSI, CSA, and IEC, among others. Standards involve markings and 

ratings, use and safety instructions, casing, physical strength, vibration/impact/drop, 

flammability/explosion, temperature, venting, pressurization, leakage, short circuit, overcharge, 

over-discharge, voltage reversal, and environmental limits such as temperature, altitude, and 

humidity (http://www.mpoweruk.com/testing.htm).

Table 5 provides a non-exhaustive list of codes, standards, and regulations that support health 

and safety at energy storage installations. Lithium-ion standards lag those for the more 

established lead-acid technologies, though standards for several different settings are under 

development, such as IEC 62897 (Rosewater 2015). In addition to the above, the U.S. 

Department of Transportation, Federal Aviation Authority, International Air Transport 

Association (IATA), International Maritime Organization, or United Nations (UN) regulations 

may need to be referenced when battery systems are being replaced (IEEE 2010). 

Table 5 is drawn from the Energy Storage System Guide for Compliance with Safety Codes

(PNNL and Sandia 2006) and highlights many of the relevant codes and standards.
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Table 4. Codes and Standards Related to Energy Storage System Maintenance

(PNNL and Sandia 2016)

A more exhaustive list of relevant codes and standards is available in Inventory of Safety-Related 

Codes and Standards for Energy Storage Systems (PNNL 2014). Some individual states will 

make available listings of relevant national, state, and local codes, standards, and regulations, 

such as California’s Safety Best Practices for the Installation of Energy Storage.

The Energy Storage System Safety Working Group is led by Sandia National Laboratories, and 

Pacific Northwest National Laboratory seeks to “foster confidence in the safety and reliability of 

energy storage systems” and is a valuable repository of the latest developments in codes and 

standards.

3

Diligent documentation of battery system information that is pertinent to safety is critical. One 

format is proposed in “Suggested Template for Energy Storage System Review and Approval” in 

Section 5.1 of Energy Storage System Guide for Compliance with Safety Codes and Standards

and includes site details, battery technology information, equipment and interconnection details, 

ventilation and thermal management, and fire protection (PNNL and Sandia 2016).

 3 More information available at http://www.sandia.gov/ess/publications/EnergyStorage_safetyroadmap_2017.pdf. 
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7.1.1 Health and Safety Checklist

Considerations for health and safety include the following.

Meet with “first responders” such as fire marshal, local fire department, first-aid providers, 

and police to familiarize them with access and shutoffs and make them aware of the plant 

purpose and location.

Control access to site and brief visitors and workers on safety procedures.

Identify hazards unique to the site and system and plan work to reduce risks associated with 

these and all hazards.

Use a company health and safety manual, which establishes appropriate rules and 

procedures concerning reporting of health and safety problems, injuries, unsafe conditions, 

risk assessment, and first aid and emergency response. Verify that this satisfies all laws and 

regulations regarding workplace safety; the manual should provide a complete list of 

personnel training requirements and certifications.

Designate a health and safety coordinator or point of contact for questions or complaints.

Have an entity with the authority to periodically inspect and stop work to verify that safety 

measures are in place and observed.

Ensure that all site personnel are equipped with complete PPE for the task, including fall 

protection from roofs and arc-flash protection for working on live circuits. Ensure that all 

personnel have met the training and certification requirements of NFPA 70E for being a 

qualified worker.

Verify that areas with hazards have clear and evident signage identifying the hazard to 

authorized or unauthorized visitors and that visitors are kept away from hazards by

enclosures and barriers.

Ensure that site supervisor (if applicable) has a minimum of an OSHA 30 certification and all 

site personnel have an OSHA 10 certification.

Maintain an OSHA total case incident rate of 5.00 or less or similar rate based on a 

substantially equivalent, accepted measure used to report workplace injuries.
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8 O&M Provider Qualifications and Responsibilities

PV O&M personnel, service category, scope of work, salary, and qualifications for the following 

roles are detailed in Appendix D: administrator/management, designer, cleaner, tree trimmer,

pest control, roofer, structural engineer, mechanic, master electrician, journeyman electrician,

network/information technology (IT) specialist, inspector, inverter specialist, PV module/array 

specialist, and utilities locator. These roles are defined in the PV O&M cost model for work 

calculations but can be customized by the user for different pay rates, roles, and local work 

conditions and context.

8.1 Qualifications of Plant Operators

Solar plant operators require monitored data to analyze and identify the root cause of 

performance issues observed by the operator. It is critical to identify the root cause of failure to 

reduce maintenance costs when dispatching service providers.

There are two ways to identify root causes of failures and performance problems:

• Qualified personnel who understand the specific plant design, with the necessary 

experience to identify anomalies (i.e., NERC-certified operators, experienced in power 

plant operations/generation, remote monitoring, remote data analysis)

• A software and/or asset management system infrastructure that is able to define the 

specific plant hierarchy that can then automatically identify anomalies, conduct rootcause analysis, and suggest remedies long before the need to dispatch a service provider.

8.2 Qualifications of Service Providers

Every service provider—from the person that mows the grass to the master electrician—requires

some sort of qualifications. Examples are listed in Appendix D for most types of service 

providers. Most electricians work on AC building systems, and most electricians are unfamiliar 

and untrained to deal with DC-based PV systems.

These electrical qualifications are essential, but each O&M service category has required 

qualifications. For example, certifications to apply herbicides and insecticides may be required 

for those removing weeds and infestations, as listed in Appendix D for each job category. 

8.2.1 Service Provider Qualification Checklist

Considerations for service provider qualifications include the following.

Licensed electrical contractor

NABCEP PV installer certified and/or UL PV system installation certified

Experience with and on power generation systems

Experience with medium-voltage DC electrical systems

Experience and working knowledge of NFPA 70E

Familiarity with sections of the National Electric Code specific to PV (section 690/691)

ASNT certified for planning and conducting thermal imaging (American Society for Nondestructive Testing)

Internal equipment calibration and tracking program
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Met NERC compliance for utility-scale systems

Audited financial statements available

Bank and/or supplier references and access to letters of credit, surety bonds, etc. and credit 

rating

Track record of performance

8.3 Financial Solvency

Contractors should provide documentation that communicates the financial solvency of the 

O&M service provider. The purpose of references is to determine if the contractor is in financial 

distress. Financial distress of the installation contractor or O&M service provider could have a 

negative impact on the level of system quality and the timeliness and quality of delivered O&M 

services.

These references should be made available to financing sources upon request. Sample 

documentation includes: 

• Audited financial statements 

• Bank references [Data Universal Number System (DUNS)]

• Supplier references

• Bond ability/bank letter of credit

• Credit rating matrix

• Track record.

8.4 Insurance

A good O&M contract and good insurance coverage are the two keys to mitigate any financial 

risk. O&M program best practices can have a positive impact on reducing insurance losses, thus 

reducing premiums paid for insurance. An insurance engineer and underwriter should be 

engaged to evaluate a facility (or the design for a yet-built system), including the O&M program, 

to quantify loss potential and estimate insurance coverage and costs. This review also provides a 

better understanding of risks that might impact the performance of a PV plant. Insurance 

products that may be of interest to the owner (which are different than coverages that an O&M 

provider should have at a minimum) are outlined by EPRI (2015).

The three categories of insurance are “Property,” “Liability,” and “Business Interruption” 

insurance. Property Insurance protects against loss damage to land, buildings and equipment and 

is often combined with Casualty Insurance that protects businesses from injuries and crimes. 

These policies are often the expanded to offer coverages for equipment not on the premises; 

liability for the cost of harm caused to others; and perhaps for major equipment failure. What is 

included and excluded from policy offerings should be carefully evaluated.

A relatively new offering is Energy Production Insurance, also known as a “Solar Revenue Put,” 

which pays the difference if a solar power plant fails to reach an agreed-upon output, perhaps 

80% to 95% of expected output. Such insurance allows projects to get 10% or 15% more debt 

financing (lower debt coverage ratio, less equity financing) and at lower interest rates because it 

reduces risk and guarantees the project cash flow necessary to meet the requirements of lenders.

A performance assessment is conducted to set expected output and put a price on the risk to 
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establish the insurance premium to be paid, but the cost of the premium is often exceeded by the 

savings in financing cost and the ability to get financing for more projects.

“Weather Transfer Risk” is a financial instrument that pays according to a “collar” on 

production. For example, if the production is less than 50% of the expected production range 

(P50 meaning that 50% of the years have more production), then the insurance company pays a 

proportional amount and if the production is greater than P60 the customer pays a premium to 

the company. As the name implies this instrument might refer to irradiance only, not equipment 

performance.

An insurance company might offer a “O&M Cost Cap” where a customer pays a premium, say 

every 6 months, and the policy pays out if O&M cost exceed the specified dollar amount during 

the covered time period. 

Liability and risks should be mitigated through contracts that clearly articulate the insurance 

requirements to O&M service providers. Concepts related to insurance include:

• Normal loss expected (NLE), which determines the dollar amount of the deductible for an 

item that can be expected to occur, such as inverter replacement, without an insurance 

claim.

• Probable maximum loss (PML), which determines the premium paid on a portfolio over 

time. As far as insurance premiums are concerned, a rate of $0.001 (total insurable value, 

the reported value of physical assets + annual business income, is offered as a cost 

benchmark (from David Walter, The Hartford Steam Boiler Inspection and Insurance 

Company, by working group correspondence June 7, 2016).

• Maximum foreseeable loss (MFS), which sets dollar limits on coverage and represents 

the worst-case loss scenario.

Confirm that the contracting company maintains current and appropriate business insurances.

8.4.1 Insurance Checklist

For small commercial or residential PV systems the home-owners insurance extends property 

and liability coverage to the PV array. Regardless of system size utilities may require specified 

levels of insurance coverage. For stand-alone utility or distributed-generation PV systems 

insurance considerations include the following.

Property insurance: coverage commensurate with value of buildings, equipment, or 

improvements to a property; might also cover against other risks if included or unless 

excluded.

Commercial general liability insurance: in a form covering all actions by owner or contractors, 

written on an occurrence basis, including coverage for products and completed operations, 

independent contractors, premises and operations, personal injury, broad form property 

damage, and blanket contractual liability: Large utility scale systems may have coverage limits 

of $30 million, to cover against liability of a wildfire, for example. Smaller rooftops ground 

mount systems may carry $1,000,000 per occurrence, $2,000,000 aggregate; covers 

negligence claims, settlements, and legal costs
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Inland insurance or marine insurance: insures against loss of equipment not on the property 

premises. Inland insurance is often covered under property insurance policy. 

Workmen's compensation: $1,000,000 each accident, each employee, policy limit

Professional liability insurance: insures against errors and omissions often required by board of 

directors

Commercial vehicle insurance: insurance for owned and rented vehicles or personal vehicles 

used on company business

Warranty insurance: equipment warranty issued by manufacturer but backed up by an 

insurance company in the event that the manufacturer company goes out of business. Many 

insurance companies do not offer warranty insurance but rather cover such risk under property 

insurance.

Business interruption insurance covers lost revenue due to downtime caused by covered 

event—this can be important in PPAs where revenue is essential for debt service and O&M 

expenditures 

“Energy production insurance” or “solar revenue put” insures against production less than 

specified, which can improve access to debt financing and reduce debt interest rate

Insurance claims: made by the asset owner or a representative of the owner such as asset 

manager or O&M service provider. The procedure for making claims described in the 

insurance policy should be followed to the letter, keeping copies of all submittals and 

correspondence with the insurance company. The insurance company (claims adjuster) will 

need to be provided access to the site to assess damage and to collect information needed to 

process the claim.

8.5 Redundancy in Service Providers

Investor confidence is increased if a “hot backup” service provider is available. This second 

service provider would be paid a fee to be available and to have the capability (products and 

training) to perform O&M on the system if a current O&M service provider fails to perform.

This second company could be hired to perform capacity and energy tests and provide a check on 

the decisions of the current O&M service provider.
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9 System Monitoring, Software Solutions, and Data 

Management

The three main areas of best practices for system monitoring are the following: data presentation, 

quality of monitoring equipment, and transparency of measurement protocols and procedures. 

The approach to monitoring and associated cost depends on the revenue associated with the 

performance of the asset. IEC 61724 classifies monitoring systems (A, B, C); the O&M related 

to monitoring depends on the system class (IEC 1998).

Data are valuable, and it should be established who owns the monitoring data and who will have 

access to the data and for what purpose. Data analysis is a powerful tool for understanding PV 

system performance, but it is fundamentally limited by the quality of sensors and models being 

used, in addition to the condition of the array.

The objective of monitoring is to provide enough information to accomplish an “energy balance” 

accounting for the amount of solar resource available and the losses in each energy conversion 

process up to delivery at the point of interconnection. Advanced operation of a PV plant such as 

modulating output or power factor can confound the drawing of conclusions from monitored 

data. A monitoring system should account for clipping of output due to high DC-to-AC ratio, 

interconnect limits, and called-for curtailment or any other reason.

9.1 DC Array Inspection

Because of the inherent inaccuracies of data monitoring alone, it is common to implement a 

secondary check of the DC array to detect string- and module-level faults through periodic 

inspection and testing. The two main methodologies used for these inspections are manual 

electrical testing and aerial thermal-imaging inspections.

9.1.1 Manual Electrical Testing

Manual electrical testing such as open-circuit voltage, operating current, or field I-V curve 

tracing is used as a method to detect faults in the DC system that the monitoring system is not 

able to detect. The accuracy of testing equipment is limited by the combined accuracy of 

irradiance, temperature, and electrical sensors, and in the case of I-V tracing, it is limited to 

around 5% for standard field units. This testing reveals only defects that are currently causing 

significant module failure, and it will not detect hot-spot defects that are not currently causing 

significant electrical degradation of the module. However, these signatures can be important for 

understanding underlying module-quality issues, in addition to allowing early detection of 

possible fire risks. Figure 18 shows a module that shows physical damage and compromised 

electrical insulation even though the module continues to perform electrically. 
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Figure 18. Cracked or peeling backsheet leads to water infiltration and ribbon corrosion. Photo by 

Andy Walker, NREL

Manual testing is performed over several days or weeks to test a large array, and the 

meteorological conditions will vary over this time, making it difficult to spot relative differences 

in the array and requiring significant documentation to ensure that measurements are 

comparable. Because this testing must be performed inside the isolated combiner while the 

system is operational, arc-flash PPE is required for all testing—which can limit the speed of 

effective inspections and can pose a potential safety risk to operators. It should be noted that for 

some combiner topologies, the arc-flash hazard may be too high according to NFPA 70E, and 

electrical testing on live circuits in the combiner box may not be possible or may require portions 

of the array to be de-energized prior to measurement (NFPA 2012). Manual inspection and 

testing requires that inverter wiring enclosures, re-combiner boxes, combiner boxes, and 

eventually module junction boxes be opened to access the circuits; it is important to note that 

these must be properly re-sealed (gasket, screw-torque) to maintain the original NEMA rating for 

the type of enclosure (Figure 19).
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Figure 19. Manual inspection and testing requires opening NEMA-rated enclosures. The integrity 

of any enclosure seal must be restored after opening to avoid moisture damage as in this module 

junction box. Photo by Andy Walker, NREL

9.1.2 Aerial Thermal Imaging

Aerial thermal imaging inspections refer to the collection and processing of image data collected 

by aerial sensors with the goal of detecting string, module, and sub-module faults in the array.

By detecting thermal variations between modules, any critical defect that is causing a reduction 

in module efficiency can be detected, in addition to the proactive detection of hot spots and 

potential fire risks (Figure 20). These inspections can be performed instead of manual electrical 

testing as part of annual preventative maintenance and can also be used for system 

commissioning, end-of-warranty inspections, and infrared inspection of AC substation.

Aerial thermal imaging can be performed using manned survey aircraft or unmanned aerial 

vehicles (UAVs). The quality of the assessment depends largely on the imaging and postprocessing systems that are used. These systems should have the following characteristics

(according to Rob Andrews of Heliolytics Inc. in a 2016 communique called “DC Assessment 

Proposed Best Practice” provided in a review of this Best Practices document.)

• Thermal detector sensitivity of <0.02°C and frame integration time of <2 ms

• Thermal wavelength imager ground resolution of 19 cm/pixel or better; visible 

wavelength imager ground resolution of 3 cm/pixel or better
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• Irradiance at a minimum of 600 W/m2 with an irradiance deviation of <100 W/m2 and a 

temperature deviation of <5°C during inspections

The resulting imagery should be processed by a validated processing routine to correctly identify 

module defects and their specific location in the field. These defects should be identified to the 

module level, and labelling should be provided to allow field technicians to quickly identify and 

remediate module-level issues. When properly applied, remote imaging inspections can 

proactively detect the following classes of array faults: 

• Module faults: Hot spots, diode failures, full module failures, junction-box heating, 

cracked modules, ethylene vinyl acetate (EVA) fogging, yellowing, antireflective coating 

degradation, acute soiling (bird droppings, debris, vegetation), and other module-level 

defects

• String and system faults: Fuse failures, inverter failures, module-connector failures, 

reverse-polarity wiring, major maximum power-point tracking (MPPT) faults

• Racking and balance of system: Major racking shifts, systemic shading, major erosion.

The use of proper post-processing tools is critical to accurately detect and classify module faults. 

Post-processing tools should be validated against ground data, allowing a properly validated tool 

to identify the exact location and probable cause of all thermal faults in an array.

For inspections without validated post-processing routines, it is important to note that many of 

the problems described above cannot be diagnosed with aerial inspections. The inspection simply 

points out symptoms and the rough location of the problem. Further troubleshooting on the 

ground is required (EUCI 2016). 

Alternatively, if the system is metered at the string level, and robust data analytics or data review 

is in place, then module faults that are affecting string output can be identified with a robust 

remote monitoring system. However, cell-level hot spots generally will not significantly affect 

module performance and cannot be detected by data analytics alone. 
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Figure 20. High-resolution infrared aerial imaging can identify failed strings, modules, and cells 

within modules, as shown on this image. Image by Rob Andrews, Heliolytics Inc.

9.2 Energy Storage System Inspection and Testing

Before a battery plant is installed, qualification testing can ensure that the specified battery can 

perform in the application and environmental conditions, and the O&M provider will have to 

adapt procedures to that particular battery type and configuration. After installation, state-ofhealth testing is required to ascertain what the actual, and declining, capacity is over time and to 

diagnose problems that require corrective maintenance or replacement of cells or complete 

battery systems.

9.2.1 Battery Qualification Tests

The O&M required of a battery, including expected replacement, depends a lot on the 

application. For those purchasing many battery systems, it makes sense to do qualification 

testing to make sure the battery will work in the application. Qualification testing includes:

• Physical tests: Dimensional accuracy, static and dynamic mechanical stresses, and 

puncture resistance.

• Environmental tests: Extreme environmental conditions are likely to be encountered by 

the battery over its lifetime, most notably temperature. The manufacturers’ published 

temperature limits on batteries are often exceeded by climate conditions in actual 

applications.

• Cycle life: Number of charge/discharge cycles a battery completes before its capacity 

falls below 80% of its initial rated capacity. These tests are expensive because they take a 

long time to run, ruin the battery under test, and require a statistically significant number 

of cells be tested. Thus, the only test data most practitioners have access to are performed 

by the manufacturers and published in the product literature. Temperature, 
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charge/discharge rates (amps), and the DOD each have a major influence on the cycle life 

of the cells. Independent tests specific to the application are recommended for those 

purchasing many batteries in order to create realistic reliability and lifetime expectations.

Warranty claims may be reduced or voided by temperatures or operating conditions 

beyond battery specifications (http://www.mpoweruk.com/testing.htm).

9.2.2 State-of-Health Testing

A complete rendering of the state of health of a battery would require tests of capacity, internal 

resistance, self-discharge, charge acceptance, discharge capabilities, the mobility of electrolyte,

and cycle counting. Such testing is beyond the capability of most battery system operators and 

internal resistance/impedance is often used as a proxy indicator of internal conditions affecting 

battery capacity, heat generated during charge/discharge, and build-up of sulfates in lead-acid 

batteries.

9.2.3 Test Conditions

Test conditions must be specified so that estimates of capacity (kWh) and cycle life are 

repeatable and can be compared to the manufacturers’ specifications or to other batteries.

Conditions to specify include:

• Definition of cycle life and range of test (e.g., to 80% of initial rated capacity)

• DOD (e.g., to 40% of capacity with each cycle)

• Rate of discharge: current in amps or percent of capacity per hour; rates are sometimes 

expressed as capacity divided by a number of hours; a discharge rate of C/10 for a 1,000 

amp-hour battery would be (1,000 amp-hours/10 hours) = 100 amps

• Rate of charging: current in amps or percent of capacity per hour

• Temperature: battery performance is heavily dependent upon temperature; even small 

deviations from reference conditions (77°F) have significant effects on capacity, 

efficiency, and lifetime.

9.2.4 Non-Invasive Testing

State-of-charge testing required discharging the battery. Other tests might require that a battery 

be disconnected from its circuit. Some parameters of interest such as state-of-charge do not have 

any direct way of measuring (to cite an aging example: density of electrolyte is a proxy for stateof-charge in flooded lead-acid batteries). For these reasons, such tests are often not conducted 

and non-invasive approaches to ascertain battery status and health are needed, such as impedance 

and voltage.

9.2.4.1 Internal Resistance/Impedance

Comparing measured value of cell resistance to initial value provides an indication of any 

deterioration in battery performance. Impedance is calculated by measuring the current that 

results from a small AC voltage of known frequency applied across the terminals of the cell and 

can be carried out while the battery is under load to continuously monitor battery performance.

Cell impedance is the applied voltage divided by the resulting current. This test detects other cell 

defects in the internal circuitry such as short or open circuits.
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9.2.4.2 Voltage Measurements

Voltage measurements are available without interrupting battery operation, but in order to be 

meaningful, voltage measurements must be mathematically adjusted for voltage level, 

temperature, discharge rate, and the age of the cell.

Both impedance and voltage measurements depend not only on measurement conditions but also 

on the history of the batteries. Still, for an arrangement of batteries all at the same condition, 

differences in voltage over time or over position within the arrangement are important indicators 

of battery performance and the need for maintenance or replacement. Good record keeping is 

needed to track trends over time.

9.2.4.3 Infrared Imaging of Battery Systems

Similar to the use of infrared imaging in spotting problems in PV arrays, combiner boxes, and 

switchgear, infrared imaging can expose the location and effects of problems in battery systems.

Individual battery cells with high internal resistance appear hotter than neighboring cells, battery 

post connections that are loose or corroded appear hotter, and imbalance of current between 

strings can be seen by a temperature difference. Batteries not passing current at all would appear 

cooler (see Figure 21).

Figure 21. Infrared imaging exposes an imbalance of current through three parallel strings of

batteries (the string on top is cooler) and exposes the cause of the problem, which is a battery 

terminal connection that is badly corroded. Photo by Owen Roberts, NREL
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9.2.5 Energy Storage System Testing Checklist

Considerations for energy storage system testing include the following.

If cost-justified by a large purchase, consider qualification testing of battery systems.

Include test conditions in specifications for battery O&M diagnostics and testing.

Consider non-invasive test techniques, such as impedance and voltage testing, to continuously 

or frequently monitor battery performance.

Keep records of initial and subsequent test results to see how parameters, such as internal 

resistance, change over time.

9.3 Instrumentation

Requirements vary depending on the performance measurement model used, the required 

accuracy, and other considerations—and not just whether the system size is above or below a 

certain system size. For instance, a fleet of 5,000 residential systems may rely on satellite and 

local weather data. A fleet of 50- to 100-kW commercial systems may have requirements to 

accurately measure irradiance, module temperature, and weather at each site. We describe 

recommended guidelines, but the requirements should actually be based on an accuracy level 

required by the subject system or fleet of systems.

It is important to understand that for any system there exists an underlying uncertainty in the 

calculation of system performance from measured data. Some studies have shown that the 

combined effects of system measurement and modeling errors can range from 5%–10% 

(Thevenard 2010; Cameron, Boyson, and Riley 2008; Freeman et al. 2014). 

Some examples of the sources of these errors are as follows:

• Meteorological data measurement 

Onsite environmental sensors that measure irradiance and temperature for systems 

>100 kW. For large plants, adding an extra irradiance sensor for each ~2 MW would help 

discern irregularities caused by cloud movement over the array. Radio communicationbased weather sensor (such as a Deno Watts weather station) would help to avoid the 

wiring for the weather stations.

• Irradiance—plane of array (POA)

IEC 61724 Class A pyranometer uncertainty: ±3% (IEC 1998)

POA model uncertainty if using Global Horizontal Insolation (GHI): 2%–5%

If there is more than one orientation of the PV array (e.g., part fixed and part tracking), 

then a separate pyranometer would be required for each orientation (in the POA), and 

each pyranometer must be properly assigned to that portion of the system for calculation 

of PR.
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The pyranometer must be kept clean to provide an actual measurement of the solar 

resource. Condition of the onsite pyranometer and data acquisition system (DAS) must be 

checked frequently (daily) to ensure proper operation and to avoid loss of data.

Irradiance measurements should be recorded at a minimum interval of 1 hour, and 15-

minute or 1-minute data are often specified.

• Satellite-based irradiance measurement

Services are available that take data from satellites and process them with models to 

create an estimate of ground-level irradiance at a site. Although less accurate than a wellmaintained and calibrated onsite pyranometer, satellite measurements can be more 

accurate than an onsite pyranometer that is dirty, out of calibration, or installed 

incorrectly.

• Temperature-module back sheet

A back-of-module temperature sensor with an uncertainty of ±1°C and an ambient 

temperature sensor with an uncertainty of ±1°C (IEC 1998).

Intra-array temperature variation: 2–5°C (variations greater than this can obscure the 

cause of images based on temperature).

Firmly affix the temperature sensor with thermal conduction adhesive in the middle of a 

cell, in the middle of the module, and in the middle of the array. Arrays with sections of 

different orientation or mounting conditions would require multiple temperature 

measurements.

• Measurement of system electrical performance

Combiner-level data generally come from current transformers (CTs) measuring current 

from combiner-box home runs measured at the inverter. Monitoring at the string level is 

also available (instrumented combiner box).

IEC 61869 Class 1 CT uncertainty is 1%.

Inverter-direct monitoring (no external AC meter) with an uncertainty of ±5% for 

systems <100 kW. For modular plants, adding an external AC meter for each inverter 

500 kW and greater would help to give visibility to the production of each inverter 

(necessary if the inverter does not include direct monitoring and providing an 

independent check and redundancy if it does).

Measurements at the inverter also include instantaneous power (AC), cumulative energy 

delivery (kWh), inverter alarms, inverter control settings, input (DC) current and voltage,

and any other information available from the inverter data interface such as inverter 

temperature. If the inverter does not report temperature, then it is recommended to add a 

temperature sensor to the inverter enclosure to identify overheating.
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Energy meter: There is often a separate high-accuracy “revenue-grade” AC meter for 

energy-revenue invoicing or independent measurement of performance for a performance 

guarantee or other purpose. Specified accuracy is sometimes required for plants where 

third-party financing is involved or where solar RECs generate revenue. This should be a 

high-accuracy, high-reliability meter with accuracy within ±0.5% and with 

communications that are compatible with both the online monitoring system and a 

separate automatic meter reading (AMR) service or advanced metering infrastructure 

(AMI) at the site. The meter should report at a minimum cumulative energy delivery, but 

may also include advanced “smart-meter” functions such as power-outage notification 

and power-quality monitoring.

• Model errors

Measured performance is meaningful only when compared to a model of expected 

performance. The accuracy of the model is affected by:

o Wire length affecting losses between combiner and measurement CTs

o Actual power rating of modules

o Actual module mismatch 

o Shading

o Soiling

o Degradation.

The following can act to increase the uncertainty in system measurement and modeling:

o Failure to re-calibrate instruments per manufacturer instructions. Most 

pyranometers must be re-calibrated every 2 years.

o Failure to clean pyranometers on a regular basis. Pyranometers should be 

mounted in such a way as to allow regular access by service personnel.

o Detachment or poor adhesion of module temperature sensors to modules. The 

adhesive should allow good thermal conductivity between the module backsheet 

and temperature sensor.

o Poor temperature sensor placement. The module temperature sensor should be 

placed away from inverter exhaust, disconnected modules (those used for soiling 

measurement only), and the edges of roads that will be more acutely affected by 

wind. Temperature variation from a module at the edge of a road to a module in 

the center of an array can be as high as 5°C due to wind effects. 

o Poor documentation of system as-builts. It is important to understand the power 

capacity connected to any monitored section of the array.

o Unreliable Data Backhaul. A dedicated or shared network connection such as a 

cellular, satellite, or dedicated broadband backhaul is required to retrieve the data 

from a monitoring system. In remote areas where utility-scale projects may be 

located, a satellite data connection may be necessary. It is often not reliable to use 

the offtaker’s network to backhaul monitored data, and in many cases, that is not 

possible due to security reasons. It is important to perform automated or manual 

quality checks frequently on the data to detect failed or dirty sensors. All raw data 

should be archived and backed up automatically and regularly. Onsite data storage 

helps to prevent loss of data when the communication link is down.
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9.4 Data Presentation

Good reporting is essential to obtain value from monitoring data. In the field of PV plant 

operations, operations quality is determined by (1) the ratio of the amount of energy harvested to 

the potential amount of energy available for a particular plant and (2) plant equipment 

availability over time. Given this definition, keeping the plant up and running at its peak 

operating point requires accurate performance measurements, the ability to easily pinpoint 

issues, and prompt cost-effective repair of defects. Active plant monitoring is essential, and the 

quality of the monitoring system itself is fundamental to the overall quality of the plant.

Reports should include the following information:

• Site name, location, size of PV plant, other reference information

• Insolation (onsite or satellite data, plane of array, kWh/m2), temperature (ambient, 

module)

• Real power and energy delivery (kW, kWh) 

• Peak power delivery (kW)

• Other advanced meter data such as reactive power (kVAR)

• Estimate of power that should have been produced and PR

• Time-based availability; energy-based availability

• Inverter efficiency, balance-of-system efficiency

• Measurement of soiling, if any.

Additional considerations:

• An internet-accessible portal should be available at any time with: 

o Downloadable raw data 

o Charts and tables to interpret data (dashboard or user interface configured to 

specific user).

• Daily feeds of previous day, month-to-date, and year-to-date production values should be 

developed and stored.

• Data should include insolation in the POA; energy delivery (kWh); PR (kWh 

delivered/kWh expected); and specific yield (kWh/kW), as well as any alarms or other 

performance indicators. Alarms should convey all the information in the alarm format of 

the manufacturer so that operators can act on the error message.

• Data format should be compatible with standards (“open platform,” IEC 61724, and 

SunSpec Alliance) for aggregation into larger data platforms. Data format should be 

clearly documented.

• O&M plans should be built to notify actionable personnel on critical production or safety 

issues as soon as possible and within 5 days for issues that affect production but not 

safety, depending on what the anomaly is and considering lost revenue and safety issues.

Fire alarms and intrusion detection alarms should be pushed out immediately to on-call 

personnel.

• Complete loss of production and non-communication should be reported on a daily basis

(immediate reporting of such issues is a source of false alarms- communications might be 

quickly restored).
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• Systems producing lower-than-forecasted energy correlated to local weather/insolation 

conditions should be reported on a weekly or monthly basis. Using intervals smaller than 

a week increases the possibility of false positives and usually does not provide business 

value.

• Reliable data backup and storage should be provided. A best practice is for data loggers 

to store 6 months of data and to backup data to cloud storage. A reliable method to 

“backhaul” the data is required. Most connect to the internet via DSL, but be aware that 

many site owners will not allow the solar monitoring system to use the site network. This 

may require a separate internet connection and often requires cellular or satellite backhaul 

of the data to an operations center or user website.

9.5 Quality of Monitoring Equipment

Use open standards for information and data communication throughout the plant, fleet, and 

enterprise. Ensure that the monitoring system addresses the following:

• Transparency of measurement protocols and procedures 

• Ability to audit measurement protocols and procedures

• Ability to maintain hardware and software by a variety of service providers, including 

calibration and servicing requirements

• Ability of systems to share information with stakeholders

• Ability to ensure “operational continuity” (backup and restore)

• Support of third-party access for custom application development

• Security of software and applications

• Ability to have entire monitoring system on an uninterruptible power supply.

In this document, we do not pick a standard to be used to calculate and report system 

performance. However, there should be an effort to at least collect and maintain data that can be 

used to report PV system performance as specified in the most common standards for the 

industry, regardless of how it is reported by any operator or for any plant. This procedure will 

allow system performance to be reported according to any of these standards if the need arises.

9.6 Transparency of Measurement Protocols and Procedures

The benefits of adopting open standards for information and communication are wellestablished. As it relates to the quality of the solar monitoring system, open standards are applied 

at four levels:

1. Device communication and plant sensor readings

2. Data collection and storage at the plant

3. Information transmission from the plant to the information data store

4. Information access to the data store from applications.

High-quality monitoring systems can be built with proprietary methods that encourage lock-in to 

a single vendor. But a standard information model used across all four levels ensures high 

fidelity and eliminates poor or inconsistent mappings from one model to another. A standard 

information model allows systems to be compared to one another, independent of the monitoring 
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vendor. The SunSpec Alliance standard information models—combined with standard transport 

protocols such as Modbus, Ethernet, and WiFi—are recommended, with support information 

models, as defined in IEC 61850 (IEC 2003) and/or Smart Energy Profile 2.0. SunSpec standards

are harmonized with both of these technologies. Sandia National Laboratories has developed an 

open-source data-filtering and analysis platform, “Pecos” (https://github.com/sandialabs/pecos), 

that can be used to provide insight into PV system data quality and roll up raw data into energy 

tests, such as those outlined by IEC 61724 (IEC 1998).

Data quality is an issue that should be addressed. Recent work in standards recognizes that data 

collection anomalies do occur, such as missing data or highly inaccurate instrument readings for 

a period of time. Quality checks should be established to quickly screen data so that they do not 

skew reported results and so that repairs can be made in a short time. Sandia National 

Laboratories, perhaps among others, is working on a set of data-handling techniques that will be 

open to the industry once released. It is also worth noting that some requirements may include 

third-party certification of data collection, calculation, and reporting. Proper application and 

maintenance of instrumentation should also be mentioned because it can be vital to accurate 

readings.

9.7 Software Solutions

Software solutions can both decrease costs and improve revenue optimization, depending on the 

setting and organizational priorities. Software solutions can also reduce risk and uncertainty 

(e.g., automating compliance processes to avoid missing dates and receiving fines). While the 

full life cycle of PV or PV plus storage systems is touched upon throughout this guide, it is 

particularly important to consider when selecting and implementing software solutions that are 

influenced by upstream activities, such as generating leads for prospective clients, and in turn 

also influence downstream processes, such as financing ownership changes and end-of-life 

deposition.

The suite of software tools is changing rapidly, and business models and processes vary greatly 

across fleets. Each asset or O&M manager will have a custom solution reflecting the business 

model and level of vertical integration, markets it is active in, stage of development, and 

technical capacity to bring solutions in-house, among others. On the software side, there is a 

spectrum from service providers with narrow expertise to vertically integrated companies that 

offer integrated products for multiple parts of the business and a blend of companies offering 

software as a service and software packages to implement through licensing arrangements. This 

section lays out emerging practices for selecting and integrating software solutions into O&M.

The ultimate goal that this section drives toward is identifying and implementing an appropriate 

solution for asset management or O&M plans, which would include functions such as:

• Document archive for complete plant documentation upkeep and reference 

• Performance monitoring dashboard with actual performance compared to expected 

performance for the day, month, year

• Customer/plant interaction tracking logs

• System/portfolio analysis

• Budget tracking
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• Trouble ticket or incident tracking

• Mobile work-order flow management and documentation systems.

Though many of those activities are executed entirely within the O&M function, the underlying 

inputs and outputs touch other aspects of the business. The following sections seek to take that 

broader organizational perspective in approaching appropriate software solutions. The four

subsections below cover assessing the need, selecting appropriate solutions, integrating new 

software, and using decision support software. This discussion is relevant for vertically 

integrated operations with O&M in-house and for identifying third-party service providers.

9.7.1 Assessing Need

It is important to identify functional requirements of the software before evaluating specific 

options and trade-offs between different approaches. It is analogous to needing to establish 

criteria for hiring a new employee before interviews to ensure that the candidate fits the need 

rather than molding the need to the individual who stands out most in the process. In 

understanding the needs specific to a project or set of projects, it is perhaps equally important to 

understand the future trajectory of the firm or portfolio as the current state that the software 

solutions will benefit right away.

Current state: Below are several of the different data points that can be helpful in the process:

• Stakeholder assessment: Understanding who has an interest in the business challenge at 

hand and who will be most influential in its successful adoption and implementation. A 

stakeholder matrix is an approach to cataloguing stakeholders during a change process, 

such as implementing a software solution, but there are many other frameworks that can 

serve that purpose. 

• Prospective users: Assessing who the users are going to be and what their capabilities 

and technical skill sets are. 

• Data availability: What are available data streams that will feed into new software 

solutions and how standardized are those inputs.

Future trajectory: Several large asset management firms have reported using Excel spreadsheets 

to serve critical business support and analysis functions even after scaling, which is a testament 

to the value of looking ahead to future activities when a need arises for a tool. Areas of analysis 

to consider about future trajectory include:

• Portfolio growth – size: For example, some firms may be seeking growth while others

decide to focus on maximizing profits or market share in a niche. For companies in the 

growth category, it may make sense to invest in an oversized solution that the firm can 

grow into over time.

• Portfolio growth – geography: Geographical spread that is anticipated in a growing 

portfolio has a bearing on solutions that are employed for issues such as training staff and 

interacting with support staff from software providers or partners.

• Human capital: Assessing how growth in the usage of software might influence human 

capital needs can play a role in deciding between licensing software packages that are 

implemented in-house or software as a service, for example. Some firms decide that as 

they grow, they will not prioritize building core competency in software packages that are 
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central to their business but not a strong suit from a human capital and recruiting 

perspective.

9.7.2 Selection Criteria

Selection criteria for software solutions will depend on specific needs and how they compare to 

what is available internally or on the market, so this section covers some high-level, 

interconnected considerations that can go into the due diligence process.

Scope: It is often preferred to have a software solution that is an all-in-one product or service. 

However, this may be hard to find depending on the degree of interconnection between O&M 

activities and other aspects of the business. There may not be a platform that spans the different 

uses that were established in the needs assessment stage, or the all-in-one platform may force a 

trade-off in quality for particular features or services. There are benefits from integrated 

solutions, such as alleviating the number of different log-ins and passwords needed to navigate 

different systems, which is often cited as a challenge, to be weighed against those costs. On the 

other hand, with good in-house abilities to integrate solutions, it may be optimal to interlink the 

best fit for different services together.

Human capital requirements: An important determinant of scope decisions is the human capital 

needs associated with the solutions. At the highest level, human capital needs have bearing on 

pursuing software-as-service options where limited technical staff are needed, but higher 

ongoing costs may be incurred or deploying software packages on a licensing basis and 

leveraging internal talent to interlink them with existing systems.

Outputs: Users of the ever-growing suite of advanced analytics that are available for PV-only 

and PV plus storage systems sometimes note that data overload can be an issue. Rather than 

prioritizing solutions with a broad swath of approaches to analyze and output data, it may be 

more effective to focus on key performance indicators specific to a given context or company 

and in-house capabilities to parse and understand output data and analytics.

Execution: There are a few practical elements of execution that are valuable to consider upfront 

in the due diligence process, including the amount of time to make changes in the future and the 

speed to train new people. There will always be user turnover and training times may differ 

substantially between different product options.

Track record: As noted elsewhere in this guide, firm track record and financial solvency for 

providers is important to evaluate before committing to a long-term software solution that will be 

hard to change later.

9.7.3 Integration

Best practices for integrating a new software product depend heavily on the nature of the product 

and its features. This subsection covers high-level issues to consider. Building on the stakeholder 

evaluation done in the assessment stage, it can be valuable to reach outside the direct users of the 

product to raise awareness with other stakeholders. For example, sometimes system owners can 

benefit from understanding the nature and capabilities of a new tool, even if they will never use it 

directly. There may also be data standards that can be incorporated in roll-out that would be 

beneficial to other segments of the business, such as financial reporting functions. 
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A key theme throughout this guide is the importance of clear documentation. This is just as 

important with software solutions as elsewhere in this guide. It is important to develop 

institutional knowledge and resiliency to staffing changes at software providers and within O&M 

staff or service providers.

9.7.4 Workflow and Decision Support Software

For plants where onsite environmental sensing equipment is not practical (i.e., most residential 

plants), measurements of irradiance and ambient temperature should be supplied by a nearby 

weather station or estimated from satellite data. These proxies for actual irradiance 

measurements may only be accurate to <±7% for global horizontal radiation and ±12% for direct

normal radiation (http://solargis.com/support/knowledge-base/accuracy/overview/) and 

temperature measurements to ±5°C—which increases uncertainty but is currently acceptable in 

the residential setting as opposed to onsite measurements for such small systems. In fact, this 

accuracy of satellite data can be more accurate than a poorly maintained or dirty sensor onsite.

A dedicated network connection such as a cellular, satellite, or dedicated broadband backhaul is 

required for plants that are greater than 100 kW. For smaller plants, where it is not practical to 

implement a dedicated network connection, a shared network connection may be used, but this 

raises the service risk profile considerably. In fact, shared Internet Protocol (IP) network outages 

have been reported by industry-leading vendors as the number-one source of service calls. Where 

possible, a dedicated network connection is highly recommended.

Onsite data storage is required to prevent data loss during communication network outages. The 

amount of storage needed depends on the expected mean time to repair should an outage occur.

An amount of storage that is equal to two times the highest-recorded communications outage is 

recommended. If you don’t know what the highest recorded communications outage is, six 

months of data storage is recommended.

Standard data-encryption techniques should be employed to protect the confidentiality and 

integrity of the data in transit over wide-area networks. For example, the SunSpec Alliance 

Logger Upload protocol specifies the use of Transport Layer Security standards (e.g., https, SSL) 

for data transmission over the IP-based networks.

Trouble-report code definitions, corrective actions taken, and results should be standardized at 

the fleet or large-system level. This allows more definitive tracking of cause-and-effect, 

repetitive problems, corrective action deficiencies, and more. This also leads to better operating 

efficiencies, better preventive techniques, identification of large-scale equipment problems, and 

more.

9.7.5 Enterprise Asset Management platforms

Fleet management and aggregation requires developing or adopting software systems termed 

enterprise asset management (EAM); these are specialized workflow platforms similar to 

enterprise resource planning (ERP) software.

EAM/O&M software platforms and services are available from several companies including 

Meteocontrol, Alectris, Draker Labs, and MaxGen Energy Services (formerly True South), 

whereas several large-fleet operators such as SolarCity and First Solar have developed their own 
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custom platform. Deployment of these software platforms, which are now a requirement for 

large-fleet operators, enables tight resource control to optimize O&M cost, especially 

administration and document cost.
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10 O&M Implementation Strategies

The asset owner or asset manager should allocate sufficient internal resources and secure any 

required external resources to implement the O&M plan.

Operating and maintaining a fleet of PV systems requires active resource management and data 

acquisition and analysis by the asset and operation manager(s).

The choices for resourcing O&M are:

• Use the EPC company or the installer who built and warrants the system (who has a 

dedicated plant O&M department to provide the necessary care)

• Bring the O&M service in-house

• Outsource the service to a specialized third-party O&M provider. 

Often a mix of these three strategies is chosen, depending on the age of the PV system, 

provider’s business model, system composition (either commercial or residential), fleet 

geographic density/distribution, and strengths of the available resources in-house. 

For commercial systems, the EPC/installer O&M model is common because most early failures 

will be warranted, and the provider can perform routine maintenance at the same time. One 

disadvantage of this model is that the EPC/installer may lack dedicated O&M resources; thus,

O&M services will compete with higher-margin installation and construction businesses. As 

warranties expire, the dedicated third-party O&M model gets more attractive because fleets can 

be combined or allocated to specialists who may have many systems in geographic 

concentrations to gain cost advantages.

For residential systems, “vertically integrated” developers/installers are using more in-house 

services because they can gain an advantage in providing uniform quality across the whole PV 

system life cycle. Meanwhile, developers using the “partner” residential model—in which the 

finance and development company partner with an installer—rely on the installer for O&M 

services and/or a dedicated third-party O&M provider as needed.

10.1O&M Contract and Performance Guarantee

Detailed contract terms are beyond the scope of this document. However, it is important to 

define the parameters for the O&M of a PV project during its life. As stated earlier, these

conditions must, as a minimum, cover the maintenance requirements to ensure compliance with 

the individual component warranties and EPCs or the installer’s contract guarantee.

Most contracts will specify a fixed cost for plant operations, standard preventive maintenance,

and agreed-upon response time, with additional fees for corrective maintenance and non-covered 

services.

So-called “performance contracts” cite KPIs, which are agreed-to measures of whether the 

contracted-for level of performance is achieved or not. It is sometimes required for third-partyowned systems to provide a guarantee for the energy yield output and/or the availability of the 

PV system when plant operations are included in the contract or an O&M provider is not well 

known or does not have significant financial backing. It is also possible for the system warranty 
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to include targets for the energy yield, PR, or availability (Klise and Balfour 2015). In fact, these 

warranties are also available from third parties, O&M contractors, and insurance companies.

How each indicator is calculated must be specified in detail, and standards are under 

development (IEC TC82) to provide standard definitions that distinguish, for example, 

availability as a fraction of time or as a fraction of energy. The agreed limits are often based on 

the independently verified energy yield report, produced at the time of commissioning. For an 

example of the calculation method, see Appendix A. As time goes on, comparison to the initial 

yield report, from before a system starts operation, becomes less accurate. A multi-year yield 

report uses average historical weather and irradiance to predict output. Actual output will vary 

year to year based on actual weather and irradiance. It is more important for the stakeholders to 

have a yield report based on an acceptable model and then use that same model to measure 

performance each year based on measured weather and irradiance, as well as operations that may 

affect the yield such as curtailment of output.

To summarize, important items to observe regarding warranty coverage and performance 

guarantees include: 

• Define what is involved in plant operations—who is watching the system, identifying the 

issue, and dispatching the required personnel to fix the issue in a timely manner

• Examine the parameters for the PV project preventive maintenance requirements 

documented during its life, which are required to keep the warranty in effect and identify 

issues that may void the warranty

• Examine the warranty in terms of KPIs (plant availability, specific energy delivery, and 

PR) to ensure that each is defined in enough detail such that all parties calculate the same 

value

• Ensure at the conclusion of an installer warranty, which may be only 1–5 years, that any 

equipment warranties (which may be as long as 25 years for PV modules) transfer or are 

designated to the responsible O&M provider

• Ensure the current status of KPIs is available to all parties in the performance contract—

both present values and trends over time.
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11 Estimating PV O&M Costs

Research of the PV O&M Working Group has concentrated on three estimates related to the cost

of delivering a PV O&M program: annual cash flow, net present value, and reserve account.

1. Annual cash flow: Costs for administrative or preventive maintenance that are scheduled 

on regular intervals are escalated according to an inflation rate to the year in which they 

occur. Costs for corrective maintenance are the replacement cost of the component 

multiplied by the probability that a failure will occur in that year. The probability that a 

component will fail in any given year is calculated by a Weibull, log-normal, or other 

distribution that is informed (ideally) by actuarial data. Warranties affect whether a 

failure will result in hardware costs, labor costs, or both if the year is within the warranty 

period. This provides a cash flow ($/year) for each year of an analysis period.

2. Net present value: Each of the future years’ cash flows calculated are then discounted to 

their present value according to a discount rate. The discount rate is the owner’s 

corporate bond rate or “minimum attractive rate of return.” Net present value is useful for 

evaluating an overall financial prospectus and calculating the impact of O&M on LCOE.

3. Reserve account: The Weibull distribution of failure gives us a good estimate of life cycle 

cost, but the method spreads the costs over the years and shows a rather uniform average 

cost per year—when, in fact, expensive repairs can occur all at once (Figure 22).

Financiers and operators want to know “maximum exposure.” In other words, what dollar 

amount of a “reserve account” or “line of credit” would a bank offer to sell to a project?

Reserve account is calculated for each year of the analysis period.

Consider a simple example regarding reserve account: A PV system with two inverters, each 

with a replacement cost of $10,000 in year 1 and each with a Weibull failure distribution of mean 

interval 20 years and shape factor 5.0. In year 20, this failure distribution would predict a 

probability of failure of Q = 0.092, and thus, a probability of non-failure of P = 0.908. If we have 

enough in reserve or in stock to replace NEITHER of the two inverters, then P1P2 = P^N =

(0.908)^2 = 0.824 (you get this level of probability that the reserve account would be sufficient 

even with no funds in the reserve account). If we have enough in reserve to replace EITHER 

ONE of the two inverters, the reserve account would be = $10,000 (inflated to year 20), and the 

resulting probability that the reserve amount would be sufficient is P1P2 + P1Q2 + P2Q1 = 

0.824+(0.908*0.092)* 2 = 0.991. If we have enough in reserve to replace BOTH of the inverters, 

the reserve account = $20,000, and the probability that the reserve account is sufficient is P1P2 + 

P1Q2 + P2Q1 + Q1Q2 = 0.666+0.300+ (0.092)^2 = 1.00. So, in this simple example, if the 

desired availability is 0.824, then we would need $0 in reserve; if the desired availability is 

0.991, then we would need $10,000 in reserve; and if the desired reliability is 1.0, then we would 

need $20,000 in reserve.

We generalize this approach to a very large number of components, N, where n/N is the fraction 

of the total number of components funded in the reserve account; R is the desired probability that 

the reserve account will be sufficient; and Q is the probability of failure in each year of the 

analysis period according to the failure distribution. This is done for each measure (PV module 

replacement, inverter replacement, every other type of component) and added up to calculate the 

total amount in the reserve account for each year of the analysis period.
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Figure 22. Probability that the reserve account amount will be sufficient to cover costs in a given 

year as a function of the fraction of the total number of a type of component and the probability of 

failure of the type of component in that given year. Figure by Andy Walker, NREL

Figure 22 shows a graph of the fraction of components to be covered by the reserve account,

depending on the probability of failure in a given year and desired confidence that the reserve 

account will be sufficient. For example, if we had 10 inverters and the probability of each 

inverter failing in a given year was Q = 0.1, and if we desired a probability of 99% that our 

reserve account would be sufficient, then we would need to have enough in the reserve account 

to cover 3.25 times the cost of a single inverter replacement. In reality, low values of Q and high 

values of R are of interest, but this chart shows the behavior of the relationship over the whole 

range.

The PV O&M Working Group has developed a PV O&M cost model (version 1.0) with a long 

list of O&M measures (Figure 23). Each measure has estimated materials, equipment, and labor 

costs, many of which are on a per-unit basis (per kilowatt or per square meter). Each measure is 

applicable based on system type (commercial rooftop, residential, or ground mount); inverter 

type (micro-, string, DC-optimized, or central-inverter); mounting type (fixed tilt or tracking, 

attached or ballasted rack); and environmental conditions (snow, pollen, bird populations, 
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sand/dust, humidity, heat, high wind, hail, salty air, diesel soot, industrial emissions, nearby 

construction site, and high insolation). Cost depends on warranty/service plan modeling 

switches. The PV O&M cost model is available from NREL and SunSpec.org as a standalone 

Excel spreadsheet tool for O&M cost modeling and planning, and an online version is currently 

being developed at SunSpec Alliance.

The cost model contains selections of scheduled and corrective maintenance tasks that are 

detailed in Appendices B and C. A list of job roles, requirements, and sample costs are included 

in Appendix D. As noted above, the model allows customization of all these variables to suit 

system configuration, job time estimates, failure rates, and local costs. 

Administrative and preventive-maintenance measures are on defined schedule intervals (e.g., 

once per year), whereas corrective-maintenance measures are scheduled according to a failure 

distribution curve (Weibull distribution) for each measure. Selection by the user of the 

environmental conditions (e.g., bird populations, pollen, snow) trigger measures such as 

additional cleanings or snow-removal costs.

This cost model based on failure distribution (Weibull distribution) is an accepted way to 

estimate net present value of the O&M program, which is useful in a life cycle cost analysis (for 

a feasibility study) or to estimate metrics such as cents/kWh delivered or average $/kW/year.

However, financiers and system operators also need to know the maximum exposure. This is the 

amount that should be secured in a line of credit or reserve fund to cover worst-case scenarios of 

O&M costs. The need for this is exemplified by a 924-kW carport system that was down for 2 

years because the owner did not have funds immediately available to replace a failed inverter.

Accurately estimating this maximum exposure based on statistics has proven to be prohibitively 

complex if the number of components exceeds approximately 10, which is the case even for a 

small PV system. Thus, the PV O&M cost model takes a simpler approach of identifying (with a 

“1” or a “0”) which of the long list of measures and costs should be included in the reserve 

account, and this would include major items such as complete inverter replacement.
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Figure 23. Results of PV O&M cost model for 10-MW ground-mount PV system with tracking, 

central inverters, and pollen as an environmental condition. Figure by Andy Walker, NREL
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12 PV O&M Cost Survey Information and Trends

In a 2018 report LBNL researchers report that average O&M costs for a sample of 39 utilityscale PV projects have declined from about $31/kWAC-year (or $20/MWh) in 2011 to about 

$16/kWAC-year ($8.4/MWh) in 2017 (Bollinger and See 2018).

EPRI (2015) reported average O&M budgets costs of $16/kW/year in 2016, down from over 

$20/kW/year reported in 2015 for utility-scale systems. Overall budget for O&M varies from 

$10.00-45.00/kW-yr, and the report provides a breakdown of cost for General Site Maintenance 

$0.20-$3.00/kW-yr; Wiring/Electrical Inspection $1.40-$5.00/kW-yr; Cleaning $0.80-$1.30/kWyr; Vegetation Management $0.50-1.80/kW-yr; Inverter Maintenance $3.00-7.50/kW-yr; Inverter 

Replacement $6.00-10.00/kW; and Spares $2.00-$20.00/kW-yr). In 2010, EPRI reported costs 

of $6–$27/kW/year (<1% to 5% of installed cost per year) for systems less than 1 MW and costs 

of $47–$60/kW/year for larger utility-scale systems, depending on PV type and fixed or tracking 

mounts (EPRI 2010). An early study reports O&M costs of $12/kW/year or 0.17% of capital cost 

without tracking and 0.35% of initial cost with tracking (Mortensen 2001).

The Federal Energy Management Program (FEMP) has tabulated O&M costs for grid-tied 

distributed generation-scale systems varying from $21 ± $20/kW/year for systems <10 kW to 

$19 ± $10/kW/year for large systems >1 MW (NREL 2013).

Another estimate approximates O&M of PV systems at $40/kW/year (about 0.5% of initial cost 

per year for these early systems), about half of which is amortized inverter replacements (Wiser, 

Barbose, and Peterman 2009). 

Data collected by Tucson Electric Power from 2002 to 2006 (Tucson Electric Power 2007) report 

annual preventive maintenance at 0.04% to 0.08% of initial cost per year and corrective/reactive 

unplanned maintenance at 0.01% to 0.22% of initial cost per year. The average combined cost 

for these utility-scale ground-mounted systems was 0.16%/year. Costs are not evenly distributed, 

with several years of low cost punctuated by a year of high cost when the inverter is replaced.

Arizona Public Service reports 0.35% of initial costs for O&M exclusive of inverter 

replacements (Moore and Post 2008) for large grid-connected systems. For small off-grid 

systems with batteries, Arizona Public Service reports that the average annual O&M cost is 5%–

6% of the initial capital cost (Canada et al. 2005) and that travel time and mileage account for 

42% of the unscheduled maintenance cost of these remote systems. 

Members of the working group have discussed these results and are currently recommending 

0.5% for large systems and 1% of system initial cost per year for small systems as a reasonable 

expectation of PV system O&M costs.

These heuristics inform an expectation of PV system O&M costs. The PV O&M cost model 

allows a customized, if not more accurate, estimate of system cost based on system type and 

components and on environmental conditions. Survey data on cost and backup service providers 

are being correlated with model test data to “calibrate” the cost model. The cost model can also 

lay out year-by-year fluctuations in O&M costs based on scheduled intervals for preventive

measures, failure distributions that increase with age, and inflation in the cost of O&M services.
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103

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Appendix A. System Performance Guarantee Example 

Calculation (Without Shade Correction)

Exhibit

Commercial System: System Performance Guarantee

IEC 61724 describes a PR, a temperature-corrected PR, and PRs based on either STC data or 

performance test condition data (IEC 1998). PR is actual energy delivery divided by the energy 

delivery estimated based on environmental conditions and exclusions such as clipping (when DC 

output exceeds AC output). In other words, PR is the measured electrical yield divided by POA 

irradiance, divided by nameplate rating, and multiplied by the reference irradiation value (e.g., 

1,000 W/m2) corresponding to the nameplate rating, where the electrical yield and POA 

irradiance are integrated over the same time period. If conducted over a short time period, this 

example of PR will be inaccurate because this PR will vary substantially based on the time of 

year it is calculated and weather. This variation caused by weather could be improved using

weather-adjusted energy performance index and availability. PR can vary, up or down, year to 

year, and this operator gets penalized for a year when it is down but does not get rewarded for a 

year when it is up. In addition to using different metrics for a guarantee, multi-year averaging or 

a penalty/reward type of system for calculating the guarantee can address this inequity.

The PR of the system is defined as follows:

where:

Yf = number of production equivalent hours recorded at the STC.

Yr = number of irradiation equivalent hours at the STC.

E = actual energy output (kWh) plus that number of kWh based on the operator’s goodfaith calculation lost during the contract year due to force majeure event(s) and/or by any 

action or inaction of the owner, utility, or host.

Pn = nominal peak power of the PV plant (kWp) equal to XXXX.00 kWp.

Hm = actual irradiance during the performance period recorded through a pyranometer 

(kWh/m2

). The PR is usually defined relative to the POA irradiance. Global horizontal 

(historical reported weather) data are fed into a model to correct for PV module 

orientation.

ISTC = standard condition of the irradiation equal to 1 kWh/m2.

Within 20 business days of the end of each contract year, the operator shall provide to the

owner a written report setting forth the following information:
104

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A. The actual energy output produced by the system in kWh as recorded by the DAS 

for the 12-month period of the contract year, plus that number of kWh based on 

the operator’s good-faith calculation lost during the contract year due to force 

majeure event(s) and/or by any action or inaction of the owner, utility, or host and 

as reviewed by the owner’s technical representative at the owner’s sole discretion.

B. The actual annual insolation for the contract year calculated as the sum of the 

monthly insolation levels measured in the POA or measured in the global 

horizontal plane and corrected for orientation of the PV modules in units of 

kWh/m2 for the system, as recorded by the DAS for the 12-month period of the 

contract year.

With respect to the data set forth in each annual report provided by the operator, the operator 

guarantees for each combined period i of one contract year (“PR Performance Period”) 

during the 20 contract years following the effective date that the actual relevant PR during 

the performance period exceeds or equals the expected PR of the system for the contract year 

I (“PRiExpected”) during the same i performance period:

PRi ≥ PRiExpected

where:

PRi is the PR directly measured onsite, as described above, for the performance 

period “i”.

PRiExpected is the expected PR to be achieved by the operator under its obligations 

pursuant this agreement (“Expected Performance Ratio”).

The operator shall achieve a PR contracted after availability for as listed below:

PR iExpected = 82. 8 x K x (1 - Y iDegradation) x (Y Availability)

where:

Y iDegradation is 0.5% from the previous year.

Y Availability is 98% (for the first year) and 99% (for the second and subsequent 

years).

K is the corrective factor equal to 1.3 for mono-axial tracker-based systems and 1 

for fixed systems.
105

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Table A-1. Example of Annual Degradation included in tabulation of Availability and Performance 

Ratio

Year

Degradation % 

from Previous 

Year

Y Degradation

Cumulative 

Degradation 

of the 

Modules

Y Degradation

Availability

Y Availability

PRi Expected

(for each 

year i)

0 0.50% 0.00%

1 0.50% 0.50% 98% 108.20%

2 0.50% 1.00% 99% 107.66%

3 0.50% 1.50% 99% 107.12%

4 0.50% 2.00% 99% 106.59%

5 0.50% 2.50% 99% 106.06%

6 0.50% 3.00% 99% 105.52%

7 0.50% 3.50% 99% 105.00%

8 0.50% 4.00% 99% 104.47%

9 0.50% 4.50% 99% 103.95%

10 0.50% 5.00% 99% 103.43%

11 0.50% 5.50% 99% 102.91%

12 0.50% 6.00% 99% 102.40%

13 0.50% 6.50% 99% 101.89%

14 0.50% 7.00% 99% 101.38%

15 0.50% 7.50% 99% 100.87%

16 0.50% 8.00% 99% 100.37%

17 0.0% 8.50% 99% 99.86%

18 0.50% 9.00% 99% 99.36%

19 0.50% 9.50% 99% 98.87%

20 0.50% 10.00% 99% 98.37%

Non-availability due to willful act or willful negligence of the owner, force majeure, or 

interruptions requested by or agreed with the owner will imply an equivalent reduction in Hm.

These outages may vary and should be defined and agreed to by the stakeholders when crafting 

the guarantee language.
106

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Should the PRi of the system for a performance period fall short of the PRiExpected of the system 

during the i performance period, as described in Table A-1, the operator shall pay the owner 

an amount in U.S. dollars equal to:

LDs = Hm * Pp * (PR iExpected – PR i) * R

where:

LDs = amount of performance liquidated damages.

Hm = reference horizontal plane irradiation during the PR performance period.

Pp = installed nameplate capacity of the plant (kWp).

PR = PR measured on the plant during the reference period.

PR iExpected= the PR expected.

R = average post-time-of-day (TOD) PPA-contracted revenue per unit of 

electricity generated, equal to _____$/kWh.
107

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Appendix B. PV O&M Cost Model Preventive Maintenance Service 

Descriptions

Table B-1. Service Descriptions for Preventive Maintenance Selections Available in the PV O&M Cost Model Tool

Consult equipment manuals for maintenance activities and intervals as required by the manufacturer.

Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

General 

cleaning

General 

cleaning/vegetation

mobilization

Cleaning PV array

Condition or 

study 

dependent

Mower/ trimmer N/A Site

Array cleaning Array cleaning Cleaning PV array

Condition or 

study 

dependent

Cleaner N/A Acre

Snow cleaning Snow removal Cleaning PV module

Condition or 

study 

dependent 

Cleaner N/A Acre

Dust cleaning Dust removal: 

agricultural/industrial Cleaning PV module

Condition or 

study 

dependent 

Cleaner N/A Acre

Pollen cleaning Pollen cleaning Cleaning PV module

Condition or 

study 

dependent 

Cleaner N/A Acre

Vegetation 

management

Determine if any new 

objects, such as vegetation 

growth, are causing 

shading of the array and 

move them if possible;

remove any debris from 

behind collectors and from 

gutters

Cleaning PV array As needed Mower/ trimmer N/A Acres

Bird cleaning Bird cleaning Cleaning PV array Bi-annual Cleaner N/A Acres
108

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Battery 

enclosure 

cleaning

Container or enclosure 

cleaning Cleaning Battery

Condition or 

study 

dependent

Cleaner N/A Battery bank

Contractor 

response

Contractor available by 

email and phone 24x7x365

Emergency 

Response PV array Ongoing Administrator N/A System

Corrosion 

inspection

Inspect electrical boxes for 

corrosion or intrusion of 

water or insects; seal boxes 

if required

Inspection AC wiring Annual Inspector N/A Combiner box

AC disconnect 

switch 

inspection

Check position of 

disconnect switches and 

breakers

Inspection AC wiring Annual Inspector N/A Disconnect 

box

Protection 

device 

inspection

Exercise operation of all 

protection devices Inspection AC wiring Annual Journeyman electrician N/A

AC disconnect 

box inspection

AC disconnect box 

inspection Inspection Electrical Annual Electrician N/A Disconnect box

Grounding 

inspection

Test system grounding with 

"megger" Inspection DC wiring Annual Master electrician N/A Strings

Cable 

inspection

Inspect cabling for signs of 

cracks, defects, pulling out 

of connections,

overheating, arcing, short 

or open circuits, and ground 

faults

Inspection DC wiring Annual Inspector N/A Strings

DC disconnect 

switch 

inspection

Check proper position of 

DC disconnect switches Inspection DC wiring Annual Inspector N/A

Combiner box 

inspection

Open each combiner box 

and check that no fuses 

have blown and that all 

electrical connections are 

tight; check for water 

incursion and corrosion 

damage; use an infrared 

camera for identifying loose 

connections because they 

Inspection DC wiring Annual Journeyman 

electrician N/A Combiner box
109

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

are warmer than good 

connections when passing 

current

Electrical box 

inspection

Look for any signs of 

intrusion by pests such as 

insects and rodents;

remove any nests from 

electrical boxes (junction 

boxes, pull boxes, combiner 

boxes) or around the array;

use safe sanitation 

practices because pests 

may carry disease

Inspection DC wiring Annual Pest control N/A

Inverter 

inspection

Observe instantaneous 

operational indicators on 

the faceplate of the inverter 

to ensure that the amount 

of power being generated is 

typical of the conditions;

compare current readings 

with diagnostic benchmark;

inspect inverter housing or 

shelter for physical 

maintenance required if 

present.

Inspection Inverter 

(electrical) Annual Inspector N/A Inverter

Instrument 

inspection

Spot-check monitoring 

instruments (e.g., 

pyranometer) with handheld instruments to ensure 

that they are operational 

and within specifications

Inspection Monitoring Annual Inspector N/A

String 

inspection

Test open-circuit voltage of 

series strings of modules Inspection PV array Annual PV module/ array specialist N/A Strings

Corrosion 

inspection

Check all hardware for 

signs of corrosion and 

remove rust and re-paint if 

necessary

Inspection PV array 

(mechanical) Annual Inspector N/A Connection
110

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Array 

inspection

Walk through each row of 

the PV array and check the 

PV modules for any 

damage; report any 

damage to rack and 

damaged modules for 

warranty replacement; note 

location and serial number 

of questionable modules

Inspection PV array Annual Inspector N/A Acres

Mounting 

system 

inspection

Inspect ballasted, nonpenetrating mounting 

system for abnormal 

movement

Inspection PV array Annual Inspector N/A Rows

Hot-spot 

inspection

Use infrared camera to 

inspect for hot spots; 

bypass diode failure

Inspection PV module Annual Inspector N/A Strings

Transformer 

inspection

Inspect transformer, oil and 

temperature gauges, 

include housing container, 

or concrete housing if 

present

Inspection Transformer Annual Master 

electrician N/A

Tracker 

inspection

Check electrical connection 

and enclosure for tracking 

motor/controller

Inspection Tracker Annual Inspector N/A Controller

Electrical 

connection 

inspection

Check electrical 

connections Inspection Tracker Annual Inspector N/A Motor

Grounding 

braids 

inspection

Check grounding braids for 

wear Inspection Tracker Annual Inspector N/A Structure

Switchgear 

inspection Switchgear inspection Inspection Electrical Annual Inspector N/A Transformer

Anemometer 

inspection Anemometer Inspection Inspection Tracker Annual Inspector N/A

Driveshaft 

inspection

Driveshaft torque check 

and visual inspection Inspection Tracker Annual Inspector N/A Driveshaft
111

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Inclinometer 

inspection Inclinometer inspection Inspection Tracker Annual Inspector N/A

Limit switch 

inspection Limit switch inspection Inspection Tracker Annual Inspector N/A Block

Module table 

inspection Module table inspection Inspection Tracker Annual Inspector N/A Connection

Screw jack 

inspection Screw jack inspection Inspection Tracker Bi-annual Inspector N/A Block

Slew gear 

inspection

Slew gear torque check and 

wear inspection Inspection Tracker Annual Inspector N/A Slew gear

Torque 

inspection Torque inspection Inspection Mechanical Annual Inspector N/A Block

Tracking 

controller 

inspection

Tracking controller 

inspection Inspection Tracker Annual Inspector N/A

Gear inspection

Universal joint inspection, 

gears, gear boxes, and 

bearings as required or 

documented by 

manufacturer

Inspection Tracker Annual Inspector N/A Driveshaft

Module torque 

inspection

PV module torque check 

and visual inspection Inspection Mechanical 5 years

PV 

module/array 

specialist 

N/A Rail/fastener

Racking torque 

inspection

Racking torque check and 

inspection Inspection Mechanical 5 years Inspector N/A Structure

Galvanization 

inspection Galvanization inspection Inspection Mechanical Annual Inspector N/A Connection

Corrosion 

inspection

Check all hardware for 

signs of corrosion and 

remove rust and re-paint if 

necessary

Inspection Battery Annual Inspector N/A Battery bank

String 

inspection

Chemistry dependent, test 

voltage, and resistance at 

module, cell, and 

connection level as 

appropriate

Inspection Battery

Condition or 

study 

dependent

Battery 

specialist N/A Battery bank
112

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Ventilation 

inspection

Inspect ventilation or air 

filtration system, replace air 

filters as needed

Inspection Battery Quarterly Inspector N/A Battery bank

Visual 

inspection

Visual survey of battery 

bank to check for cracks in 

cases, bulging, integrity of 

battery enclosure, and 

support structure

Inspection Battery Annual Inspector N/A Battery bank

Manage

operations

Daily operations and 

performance monitoring Management Asset management Ongoing Administrator N/A

Manage alarms Monitor alarms and sitespecific alert parameters Management Asset 

management As needed Administrator N/A

Manage 

inventory

Manage inventory of spare 

parts Management Asset management As needed Administrator Monitoring

Manage service 

package

Monitoring annual service 

package Management Asset management Ongoing Administrator Monitoring System

Manage O&M 

services

Document all O&M services

in a workbook available to 

all service personnel

Management Documents Ongoing Administrator N/A

Manage 

documentation 

Confirm availability and 

take any measures to 

secure operating 

instructions, warranties and 

performance guarantees, 

and other project 

documentation

Management Documents Annual Administrator N/A

Manage O&M 

agreements

Review O&M agreements 

and ensure that services 

are actually provided

Management Documents As needed Administrator N/A

Manage 

preventive

services

Update record with 

preventive maintenance 

services and track any 

problems or warranty 

issues and secure the 

record on site

Management Documents Ongoing Administrator N/A
113

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Meet with site 

staff

Meet with key site staff to 

continue awareness, 

question any issues, and 

report on findings

Management Documents Annual Administrator N/A

Maintain log

Maintain a log of cumulative 

power delivery (kWh to 

date) and chart this value 

against date; chart the 

value even for uneven or 

infrequent intervals; explain 

variation by season or 

weather

Management Meter Monthly Administrator N/A

Mobilize 

electrical labor Electrical labor mobilization Management Electrical Annual Master electrician EPC Site

Mobilize 

mechanical 

labor

Mechanical labor 

mobilization Management Mechanical Annual Mechanic EPC Site

Check central 

supervisory 

control and 

data acquisition 

(SCADA)

Check central 

SCADA/network manager, 

include software IT and IT 

hardware updates as 

required

Management Electrical Annual Network/ IT N/A NCU

Re-torque AC 

connection

Re-torque all electrical 

connections on AC side of 

system

Service AC wiring Annual Journeyman 

electrician N/A

Re-torque 

combiner box 

connections 

Re-torque all electrical 

connections in combiner 

box

Service DC wiring Annual Electrician N/A Combiner box

Replace 

weather 

sensors

Calibrate or replace 

weather sensors and 

meters

Service Electrical As per 

manufacturer Network/ IT N/A Weather station

Replace 

transient 

voltage surge 

suppression 

device

Replace transient voltage 

surge suppression devices Service Inverter As per manufacturer

Master 

electrician Inverter
114

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Install software 

upgrades

Install any recent software 

upgrades to inverter 

programming or DAS and 

monitoring systems

Service Electrical

As upgrades 

become 

available, 

maximum 5 

years

Inverter 

specialist EPC NCU

Dust cleaning 

from heat 

rejection fins

Clean (vacuum) dust from 

heat rejection fins Service Inverter Annual Cleaner N/A Inverter

Replace air 

filters

Replace any air filters on 

air-cooled equipment such 

as inverter

Service Inverter As needed Inverter 

specialist N/A Inverter

Remove bird 

nest

Remove bird nests from 

array and rack area Service PV array Annual Pest control N/A Acres

Tracker 

lubrication

Lubricate tracker mounting 

bearings/gimbals as 

required by manufacturer

Service Tracker Annual Mechanic N/A

Gearbox 

lubrication

Lubricate gearbox as 

required by manufacturer Service Tracker Bi-annual Mechanic N/A Block

Screw jack 

greasing

Screw jack greasing as 

required by manufacturer Service Tracker Bi-annual Mechanic N/A Block

Slew gear 

lubrication

Slew gear lubrication as 

required by manufacturer Service Tracker 3 years Mechanic N/A Slew gear

Universal joint 

greasing

Universal joint greasing 

(zerk fitting) as required by 

manufacturer

Service Tracker Bi-annual Mechanic N/A Driveshaft

Re-torque 

connections

Re-torque all electrical 

connections on battery 

bank

Service Battery Annual Electrician N/A Battery string

Watering Watering flooded lead-acid 

batteries Service

Battery 

(flooded leadacid only)

As per 

manufacturer Electrician N/A Battery bank

Equalizing Perform equalization 

charge Service

Battery 

(flooded leadacid only)

As per 

manufacturer

Battery 

specialist N/A Battery bank
115

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Performance 

testing

Perform performance test: 

measure incident sunlight 

and simultaneously observe 

temperature and energy 

output; calculate PV 

module efficiency as a 

function of temperature and 

calculate the balance-ofsystem efficiency; compare 

readings with diagnostic 

benchmark (original 

efficiency of system)

Testing Inverter Annual Inspector N/A

Overvoltage 

surge 

suppressor 

testing

Test overvoltage surge 

suppressors in inverter Testing Inverter 5 Years Inverter specialist Inverter Inverter

Module output 

testing

Test output of modules that 

exhibit cracked glass, 

bubble formation oxidation 

of busbars, discoloration of 

busbars, or PV module hot 

spots (bypass diode failure)

Testing PV module 5 years Journeyman 

electrician N/A Modules

Module testing

Test modules showing 

corrosion of ribbons to 

junction box

Testing PV module 5 years Journeyman 

electrician N/A Modules

Combiner box 

inspection

DC circuit test and 

combiner-box inspection Testing Electrical Annual PV module/ array specialist N/A Combiner box

Module 

electrical 

connection 

testing

PV module electrical 

connection check Testing Electrical 5 years PV module/ array specialist N/A PV module

Grounding 

hardware 

testing

Check grounding hardware Testing Electrical Annual Master 

electrician N/A Structure

Battery 

capacity testing Test battery capacity Testing Battery

Condition or 

study 

dependent

Electrician N/A Battery bank
116

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Appendix C. PV O&M Cost Model Corrective Maintenance Service 

Descriptions

The following is a list of corrective/reactive maintenance measures that would be performed to fix problems encountered in operation 

of a PV system over time.

Table C-1. Service Descriptions for Corrective Maintenance Selections Available in the PV O&M Cost Model

Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Dispatch 

contractor

Dispatch contractor in 

response to alarms, 

alerts, or contact by 

others

Emergency 

response

PV array As needed Administrator Monitoring

Replace inverter 

AC fuse

Replace inverter AC 

fuse(s) Repair AC wiring As needed Journeyman electrician EPC

Replace protective 

devices

Replace protective 

devices (breakers) in 

building panel

Repair AC wiring As needed Master 

electrician N/A

Replace AC wiring 

conduit

Replace 

broken/crushed AC 

wiring conduit and 

fittings

Repair AC wiring As needed Journeyman 

electrician N/A Strings

Repair line-to-line 

fault

Repair line-to-line 

fault Repair AC wiring As needed Master electrician N/A

Locate line-to-line 

fault

Locate line-to-line 

fault Repair AC wiring As needed Master electrician EPC

Replace combiner 

box fuses

Replace failed fuses 

in combiner box Repair DC wiring As needed Journeyman electrician N/A Strings

Replace 

connectors

between module

Replace connectors 

between modules Repair DC wiring As needed PV module/ array specialist

Module 

(product) Modules

Replace MC 

connector lead to 

combiner box

Replace MC 

connector lead to 

combiner box

Repair DC wiring As needed PV module/ 

array specialist

Module 

(product) Modules

Re-route conduit Re-route conduit Repair DC wiring As needed Journeyman 

electrician N/A
117

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Replace DC wiring 

conduit

Replace 

broken/crushed DC 

wiring conduit and 

fittings

Repair DC wiring As needed Journeyman 

electrician N/A

Repair ground 

fault Repair ground fault Repair DC wiring As needed Master electrician EPC

Locate ground 

fault Locate ground fault Repair DC wiring As needed Master electrician EPC

Locate 

underground DC 

wiring

Locate underground 

DC wiring as part of 

repairs to faults

Repair DC wiring As needed Utilities locator N/A

Repair DC directbury wire

Carefully dig to 

expose fault and 

repair wire

Repair DC wiring As needed Journeyman 

electrician EPC

Replace fuse on 

DC source circuits 

to inverter

Replace fuse(s) on 

DC source circuits to 

inverter

Repair DC wiring As needed Master 

electrician EPC

Repair junction 

box

Seal leaking junction 

box Repair DC wiring As needed Journeymanelectrician 

Module 

(product) Modules

Reboot inverter

Start/stop inverter 

(reboot to clear 

unknown error)

Repair Inverter As needed Inspector EPC Inverter

Replace inverter 

fan motor

Replace inverter fan 

motor Repair Inverter As needed Inverter specialist Inverter Inverter

Replace inverter 

data acquisition 

card

Replace inverter data 

acquisition 

card/board; diagnose 

with fault code

Repair Inverter As needed Inverter 

specialist Inverter Inverter

Replace inverter 

control card

Replace inverter 

control card (signal, 

voltage, phase, 

frequency, 

shutdown); diagnose 

with fault code

Repair Inverter As needed Inverter 

specialist Inverter Inverter

Replace IGBT 

driver

Replace IGBT driver 

card/board; diagnose 

with fault code

Repair Inverter As needed Inverter 

specialist Inverter Inverter
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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Replace maximum 

power-point 

tracker

Replace maximum 

power-point tracker 

card/board; diagnose 

with fault code

Repair Inverter As needed Inverter 

specialist Inverter Inverter

Replace AC 

contactor in 

inverter

Replace AC 

contactor in inverter Repair Inverter As needed Inverter specialist Inverter Inverter

Replace IGBT 

matrix in inverter

Replace IGBT matrix 

in inverter Repair Inverter As needed Inverter specialist Inverter Inverter

Replace power 

supply for inverter 

controls

Replace 24 VDC 

power supply for 

inverter controls

Repair Inverter As needed Inverter 

specialist EPC Inverter

Replace DC 

contactor in 

inverter

Replace DC 

contactor in inverter Repair Inverter As needed Inverter specialist Inverter Inverter

Replace ground 

fault interruption

(GFI) components

Replace GFI 

components in 

inverter

Repair Inverter As needed Inverter 

specialist Inverter Inverter

Replace 

capacitors

Replace capacitors in 

inverter Repair Inverter As needed Inverter specialist Inverter Inverter

Replace induction Replace inductors 

(coils) in inverter Repair Inverter As needed Inverter specialist Inverter Inverter

Replace fuses 

internal to inverter

Replace fuses 

internal to inverter Repair Inverter As needed Inverter specialist Inverter Inverter

Replace inverter 

relay/switch

Replace inverter 

relay/switch Repair Inverter As needed Inverter specialist Inverter Inverter

Replace 

overvoltage surge 

suppressors

Replace overvoltage 

surge suppressors for 

inverter

Repair Inverter As needed Inverter 

specialist Inverter Inverter

Re-install software Re-install inverter 

control software Repair Inverter As needed Inverter specialist EPC Inverter

Reset arc-fault trip

Manual reset of arcfault trip (NEC 

690.11)

Repair Inverter As needed Inverter 

specialist EPC Inverter

Restore internet Restore lost internet 

connection Repair Monitoring As needed Network/ IT N/A Site
119

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Replace 

foundation 

element

Excavate and replace 

failed foundation 

element

Repair PV array As needed Structural 

engineer N/A

Replace rack parts

Repair or replace 

rack parts damaged 

by corrosion or 

physical damage

Repair PV array As needed Mechanic EPC

Replace modules

Replace modules 

failing performance 

test and infrared scan 

after showing cracks 

in glazing, 

discoloration of 

metallic contacts, 

delamination, or 

signs of water

Repair PV module As needed Journeyman 

electrician

Module 

(product) Modules

Repair module 

backsheet

Repair cracking of PV 

module backsheet Repair PV module As needed Journeyman electrician

Module 

(product) Modules

Repair module 

frame

Repair or replace 

damage to module 

frame

Repair PV module As needed Mechanic Module 

(product) Modules

Repair roof leaks

Repair roof leaks as 

related to PV 

structure penetration 

problems

Repair Roof As needed Roofer N/A Acres

Re-roof

Re-roof (new roof) as 

related to PV 

structure penetration 

problems

Repair Roof As needed Roofer N/A Acres

Repair tracker 

drive shaft

Repair/replace 

tracker drive shaft Repair Tracker As needed Mechanic N/A Row

Replace tracker 

drive bearing

Replace tracker drive 

bearing Repair Tracker As needed Mechanic N/A Row

Replace tracker 

mount bearing

Replace tracker 

mount bearing Repair Tracker As needed Mechanic N/A 

Replace tracker 

motor controller

Replace tracker 

motor controller Repair Tracker As needed Journeyman electrician N/A
120

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Service Name Service Description Service 

Category

O&M 

Category Interval Service Provider

Warranty 

Type

Applicable 

Unit

Upgrade tracker 

software

Replace/upgrade 

tracker control 

software

Repair Tracker As needed Network/ IT N/A

Replace tracker 

power supply

Replace trackingcontroller power 

supply fan filter

Repair Tracker 2 years Mechanic EPC Controller

Replace hydraulic 

cylinder

Replace hydraulic 

cylinder Repair Tracker As needed Mechanic N/A

Replace 

transformer (e.g.,

GSU)

Replace transformer Repair Transformer As needed Master 

electrician N/A Transformer

Re-tap 

transformer Re-tap transformer Repair Transformer As needed Master electrician N/A Transformer

Replace terminal 

block

Replace terminal 

block Repair Inverter As needed Journeyman electrician Inverter Combiner box

Replace inverter Replace inverter Repair Inverter As needed Inverter 

specialist Inverter Inverter

Locate 

underground AC 

wiring

Locate underground 

AC wiring Repair AC wiring As needed Utilities locator N/A

Replace battery 

cell Replace battery cell Repair Battery As needed Battery specialist Battery Battery cell

Replace battery 

string

Replace battery 

string Repair Battery As needed Battery specialist Battery Battery string

Replace battery 

bank Replace battery bank Repair Battery As needed Battery specialist Battery Battery bank

Replace battery 

bank air 

conditioner

Replace battery bank 

air conditioner Repair Battery As needed Battery specialist N/A Battery

Perform initial 

testing on 

replacement 

battery 

Perform initial testing 

on replacement 

battery 

Repair Battery As needed Battery 

specialist N/A Battery
121

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Appendix D. PV O&M Scope of Work, Salary, and 

Qualifications

These rates are defined in the PV O&M Cost Model and can be customized by the user. They are 

from the U.S. Bureau of Labor Statistics, 2015, for each service provider, but most reviewers 

comment that these rates are too low. A “loading factor” is used to convert these values, which 

are more representative of employee take-home pay, with the cost to the employer, which 

includes the cost of benefits and fringe benefits. A typical “loading factor” is on the order of 1.7.

Table D-1. Qualifications and Loaded Labor Rates for PV O&M Service Providersa

Service 

Category

Loaded 

Rate 

($/hour)

Scope of Work Qualifications

Administrator 23.00 Record keeping, 

service confirmation, 

correspondence

Excellent interpersonal and communication 

skills (written and verbal); diligent record 

keeping; 2 to 5 years of experience; excellent 

MS Office and computer skills; management 

of contractors and quality

Cleaner 14.74 Cleaning PV arrays 10-hour OSHA card; required level of 

bonding and insurance; driver’s license and 

reliable transportation; minimum 18 years old

Designer 58.33 Specifications, 

drawings, modeling 

and analysis, codes 

and standards

B.S. in electrical engineering (4-year degree); 

registered PE licensed to practice 

engineering in the jurisdiction; NABCEP PV 

Installer certification; CAD (AutoCAD) and 

graphics skills; knowledge of IEEE, NEC, 

NESC, and other codes and standards for 

PV systems; required level of errors and 

omissions insurance

Inspector 33.12 Diagnostic analysis,

visual inspection, 

specific testing

Diagnostic analysis; NABCEP PV Installer 

Certification; 2 to 5 years of experience

Inverter 

specialist

33.17 Inverter repair, 

upgrades

(estimated) skills to perform maintenance, 

diagnostics, and repair for inverter: factory 

trained and certified; 5+ years of experience

Journeyman 

electrician

19.90 Module replacement, 

inverter replacement, 

fuse/breaker 

replacement, conduit 

routing, wiring, 

ground-fault repair

(estimated) 50 OSHA card; training in arcflash, lock-out/tag-out, and other special 

protective equipment and procedures; 

NABCEP PV Installer certification; 

experience in the design of medium-voltage 

electrical systems; 5+ years of experience 

with PV systems; color vision

Master 

electrician

32.01 Module replacement, 

inverter replacement, 

fuse/breaker 

replacement, conduit 

routing, wiring, 

ground-fault repair

Electrical contractor’s license for the 

jurisdictions; 50-hour OSHA card; NABCEP 

PV Installer certification; experience in the 

design of medium-voltage electrical systems;

5+ years of experience with PV systems; 

color vision; certification by NERC is 
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Service 

Category

Loaded 

Rate 

($/hour)

Scope of Work Qualifications

necessary for positions that affect the power

grid

Mechanic 29.30 Maintenance and 

repair/replace of 

tracking mount 

components

50-hour OSHA card; 2 to 5 years of 

experience; required level of bonding and 

insurance

Network/IT 45.89 Internet/network 

repair, monitoring 

equipment repair

Knowledge of specific monitoring devices 

(training by system supplier) and how 

monitoring system is connected through 

network connections or wireless or cellular 

modem; knowledge of Modbus, DNP3, and 

other protocols and HMI operator interfaces; 

2 to 5 years of experience; Locus, Enphase, 

Itron, etc. monitoring device knowledge

Pest control 20.13 Nesting vermin 

removal, nesting 

vermin prevention

10 OSHA card; safety training in handling 

animals and detritus; required level of 

bonding and insurance; driver’s license and 

reliable transportation; minimum 18 years 

old; most states require license for pesticide

PV module/array 

specialist

33.17 Module repair (estimated) skills to operate, troubleshoot, 

maintain, and repair PV equipment: NABCEP 

PV Installer certification; 2 to 5 years of 

experience

Roofing 22.70 Roof leak repair, roof 

tile repair, re-roof

Roofing contractor’s license for the 

jurisdiction; 10 OSHA card; safety training in 

fall-protection equipment and use (or 50 

OSHA card); required level of bonding and 

insurance

Structural 

engineer

55.82 Foundations and rack 

inspection/design

B.S. Structural Engineering (4-year degree); 

registered PE licensed to practice 

engineering in the jurisdiction

Mower/trimmer 15.75 Removal of vegetation 50 OSHA card; driver’s license and reliable 

transportation; required level of insurance; 

minimum 18 years old; any required training 

or license for herbicide application

Utilities locator 25.55 Locate underground 

utilities

2 to 5 years of experience

a Unloaded rates from National Bureau of Labor Statistics, 2014, loaded at 1.38 factor.
123

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Appendix E. Examples of Scope of Work Documents

Below is an example Scope of Work provided by working group member SolarCity (now Tesla) 

for inclusion here.

EXHIBIT: SCOPE OF SERVICES

1. Operation and Maintenance:

● Provider will (i) keep all Covered Systems in good repair, good operating condition, 

appearance and working order in compliance with the manufacturer’s recommendations, 

the Customer Agreements, all manufacturers’ warranties and the Company’s standard 

practices (but in no event less than Prudent Industry Practices), (ii) properly service all 

components of all Covered Systems following the manufacturer’s written operating and 

servicing procedures and in accordance with the Customer Agreements, and (iii) replace 

any Part of a Covered Systems that becomes unfit or unavailable for use under the 

Customer Agreements from any cause (whether or not such replacement is covered by a 

maintenance agreement) with a replacement Part of a Covered System pursuant to 

paragraph 2 of this Exhibit A.

● Provider shall promptly furnish or cause to be furnished to the Company such 

information as may be required to enable the Company to file any reports required to be 

filed by the Company with any Governmental Authority because of the Company’s 

ownership of any Covered System.

2. Replacement of Parts:

● In accordance with the Customer Agreements, Provider will promptly replace or cause to 

be replaced all Parts that may from time to time be incorporated or installed in or 

attached to a PV System and that may from time to time become worn out, lost, stolen,

destroyed, seized, confiscated, damaged beyond repair or permanently rendered unfit for 

use under the Customer Agreements for any reason whatsoever, except as otherwise 

provided in paragraph 3 of this Exhibit A. 

● Provider may, in accordance with the Customer Agreements, remove in the ordinary 

course of maintenance, service, repair, overhaul or testing, any Parts, whether or not 

worn out, lost, stolen, destroyed, seized, confiscated, damaged beyond repair or 

permanently rendered unfit for use; provided that Provider, except as otherwise provided 

in paragraph 3 of this Exhibit A, will replace such Parts as promptly as practicable. All 

replacement Parts will be free and clear of all Liens (except for Permitted Liens and 

except in the case of replacement property temporarily installed on an emergency basis) 

and will be in as good operating condition as, and will have a value and utility at least 

equal to, the Parts replaced assuming such replaced Parts were in the condition and 

repair required to be maintained by the terms hereof.

3. Alterations, Modifications and Additions:

● Provider will make such alterations and modifications in and additions to PV Systems as 

may be required from time to time to comply with Applicable Law and the terms of the 

applicable Customer Agreements; provided, however, that Provider may, in good faith, 

contest the validity or application of any such Applicable Law in any reasonable manner, 
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but diligently and in good faith, and only if there is no material risk of the loss or 

forfeiture of a PV System or any interest therein or breach of the related Customer 

Agreement; and provided further, that Provider’s failure to make (or cause to be made) 

any such alterations, modifications of additions will not constitute noncompliance with 

the requirements of this paragraph 3 or a breach of Provider’s undertaking hereunder 

for so long a period as may be necessary to remedy such failure, if such failure can be 

remedied, so long as during such period Provider is using due diligence and best efforts 

to remedy such failure. 

4. Customary Information: Provider will furnish or cause to be furnished to the 

Company:

● Promptly upon an officer of the Provider becoming aware of the existence thereof, a 

notice stating that a breach of, or a default under, any material contractual 

obligation of the Company in respect of any Covered System has occurred and 

specifying the nature and period of existence thereof and what action the Provider 

has taken or is taking or proposes to take with respect thereto; and

● From time to time such other information regarding the PV Systems or the Projects 

as the Company may reasonably request. 

5. Reports of Liability:

● Provider shall give prompt written notice to the Company of each accident likely to 

result in material damages or claims for material damages against any Covered 

System or any such Person or likely to result in a material adverse change to the 

financial or business condition of the Company occurring in whole or in part 

(whenever asserted) during the Term, and on request shall furnish to the Company 

information as to the time, place and nature thereof, the names and addresses of the 

parties involved, any Persons injured, witnesses and owners of any property 

damaged, and such other information as may be known to it, and shall promptly upon 

request furnish the Company with copies of all material correspondence, papers, 

notices and documents whatsoever received by the Provider or the Company, as 

applicable, from third parties in connection therewith. 

6. Billing, Collecting and Enforcement of Customer Agreements:

● Provider will, at its sole cost and expense, administer or cause to be administered all 

Customer Agreements. Provider’s obligations under this paragraph 6 shall include, 

without limitation, delivering periodic bills to all Host Customers, collecting from all 

Host Customers all monies due under the Customer Agreements, and managing all 

communications with or among Host Customers.

● Provider will assist the Company in the enforcement of all Customer Agreements.

Provider will, at the Company’s direction and expense, diligently exercise any 

remedies that may become available under the Customer Agreements in respect of 

any defaults by Host Customers thereunder; provided that, in the event that the 
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Company elects, in the exercise of any such remedies, to remove a PV System from 

the Host Customer’s real property, (a) the cost of such removal shall be borne by 

Provider, and (b) Provider will use commercially reasonable efforts to redeploy such 

PV System following any such removal (it being agreed that, in connection with any 

such redeployment, Provider shall not discriminate against such PV System as 

compared to similar equipment that is not subject to this Agreement and will not 

unreasonably favor new equipment over the redeployment of the PV Systems 

hereunder). 

● In the event that a Host Customer sells its real property, changes locations or 

otherwise vacates the real property upon which the PV System is installed and 

proposes to transfer its Customer Agreement, to the extent the new owner or occupant 

does not meet the minimum credit standard applicable to the original Host Customer, 

Provider will (i) forward the transfer request to the Company for review and 

approval or (ii) require the Host Customer to relocate or purchase the PV System, or 

prepay its future obligations under the Customer Agreement as provided in the 

Customer Agreement, and Provider will be responsible for all administrative duties 

associated with the foregoing.

7. Event of Loss with Respect to a PV System:

● If any PV System is damaged or destroyed by fire, theft or other casualty, Provider 

will, at the Company’s expense, repair, restore, replace or rebuild such PV System to 

substantially the same condition as existed immediately prior to the damage or 

destruction and substantially in accordance with the Customer Agreement related to 

such PV System.

● If a PV System is required to be replaced as described above, then Provider will 

cause the supplier of the replacement equipment to deliver to the Company a bill of 

sale for such equipment free and clear of all Liens (except for Permitted Liens) and 

such replacement equipment will become a PV System subject to this Agreement. 

8. Administration of Government Incentives:

● Provider shall timely: (a) complete and submit, on behalf of the Company, all 

applications and other filings required to be submitted in connection with the 

procurement of all Government Incentives that are available in respect of each 

Covered System hereunder; (b) deliver to the Company for the Company’s signature 

such certifications, agreements and other documents required to be delivered or 

submitted under Applicable Laws in connection with such Government Incentives; 

and (c) take such other action as may be reasonably necessary to effectuate the 

procurement and receipt by the Company of such Government Incentives in 

accordance with Applicable Laws.
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Example Performance Work Statement

This example Performance Work Statement was used in a site-wide operating contract for a 

military base that included maintenance for other systems such as lighting and mechanical 

systems, and thus is necessary very concise:

“This Performance Work Statement covers all labor, supplies and materials, replacement parts, 

equipment used to provide the services, transportation to the site, and any other goods and 

services required to provide preventive and corrective maintenance on this PV system.

Performance is defined as maintaining the ability of the solar systems to provide power 

according to specifications and considering solar and temperature conditions as well as de-rated 

for expected inefficiencies such as dirt on the collector. The intent is to perform preventive

maintenance and to replace failed components, and some small degradation of performance is 

expected over time. Solar system output shall be no less than 80% of the rated output of the PV 

system, corrected for solar and temperature conditions at the time of the test. System shall be 

tested annually. Key to the performance definition is that all components be capable of 

accomplishing their intended purpose within specifications. The definition of the PV system to be 

maintained shall include PV modules, the support structure, disconnects, inverter(s), monitoring 

equipment, and all other appurtenances to make the PV system complete, grid-connected, and 

operational.”

Example Description of Maintenance Services for Commercial

Rooftop Installations

A Performance Work Statement is a list of all the services that a service provider is expected to 

provide. The text below is offered as an example of such a description of work for a commercial 

rooftop installation. This example was provided for this Best Practices document by working 

group member SunSpec Alliance.

As of the Commencement Date, Owner and Contractor shall provide the Services marked below 

at the frequency indicated in accordance with the terms and conditions of this Agreement.

Service Schedule

Item

Services 

included 

(only if 

checked)

Service Description

Frequency/ 

Response 

Time

Preventive Maintenance

1

Visual inspection of Solar Facility’s general site conditions, 

PV arrays, electrical equipment, mounting structure, fence, 

shading, trackers, vegetation, animal damage, erosion, 

corrosion, and discolored panels.

1x per year

2 Visual inspection and correction of Solar Facility for loose 

electrical connections and ground connections. 1x per year
127

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Service Schedule

Item

Services 

included 

(only if 

checked)

Service Description

Frequency/ 

Response 

Time

3 String-level open-circuit voltage, DC operating current 

tests, and I-V curve traces on [ ]% of [ ] strings. 1x per year

4 [ ] switches and disconnects test to ensure they are not 

jammed. 1x per year

5

Infrared scans on all [ ] combiner and re-combiner boxes; 

tighten connections to manufacturer's torque specification; 

report broken terminal blocks.

1x per year

6

[ ] check calibration expiration on sensors and meters, 

including pyranometers, and anemometers and perform 

other service such as cleaning and replacement of any 

desiccant.

1x per year

7

Turn off and on logging and communications to ensure 

they are communicating and ensure battery backups are 

working.

1x per year

8 Inverter preventive maintenance for [ ] inverters per 

manufacturer’s operating guidelines See below

9 Clean inverter cabinet air vents. 1x per year

10 Clean and change inverter air filters, if present, per 

manufacturer’s warranty requirements. 1x per year

11 Clean/remove dust from inverter heat sinks per 

manufacturer’s warranty requirements. 1x per year

12

Check torque marks and re-tightening appropriate wiring 

connections to design specification torque force per 

manufacturer’s guidelines.

1x per year

13 Inspect roof penetrations to ensure sealant is applied 

properly and not degrading. 1x per year

14 PV array module maintenance for [ ] modules See below

15 Wash all panels with water with no chemicals in a method 

approved by the Owner.

1x per year or 

per study

16

Perform infrared scan of [ ] % of modules for two types of 

circuitry connections: cells on the front and junction boxes 

on the back.

1x per year
128

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Service Schedule

Item

Services 

included 

(only if 

checked)

Service Description

Frequency/ 

Response 

Time

17 Remove any sprouting seeds or vegetation, bird nests, 

leaves or debris, etc. 1x per year

18

Document details of preventive maintenance work, such 

as condition observations, work performed, meter 

readings, thermal images, and system testing results.

As performed

19 Include non-conformance reports to identify potential 

short-term and long-term power production issues. 1x per year

Service Support

20 Contractor will make available a 24x7x365 Technical 

Support. Ongoing

21

Dispatch commitment: dispatch resources in response to 

alarms and alerts/service requests received by Contractor 

from Owner.

See below

23

Alarm: means loss of one inverter’s production. The 

dispatch time incurs a fee of $XXX per alarm, in addition to 

the fees in non-covered services schedule, including 

alarms that require warranty service.

Dispatch in 

<[specify

required 

response

time]

24

Alert/service request: means noticeable anomaly or loss of 

power, but inverter in question is still operating. This 

dispatch time incurs a fee of $XXX per alert/service 

request, in addition to the fees in non-covered services 

schedule, including alerts/service requests that require 

warranty service.

Dispatch in 

<[ ] specify 

time
129

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Example Description of Maintenance Services for Commercial Ground 

Mount Installations

As of the Commencement Date, Contractor shall provide the Services marked below at the 

frequency indicated in accordance with the terms and conditions of Maintenance Agreement.

Service Schedule

Item

Services 

included 

(only if 

checked)

Service Description

Frequency / 

Response 

Time

Preventive Maintenance

1

Visual inspection of Solar Facility’s general site conditions, 

PV arrays, electrical equipment, mounting structure, fence, 

shading, trackers, vegetation, animal damage, erosion, 

corrosion, and discolored panels.

1x per year

2 Visual inspection and correction of Solar Facility for loose 

electrical connections and ground connections. 1x per year

3 String-level open-circuit voltage, DC operating current 

tests, and I-V curve traces on [ ]% of [ ] strings. 1x per year

4 [ ] switches and disconnects test to ensure they are not 

jammed. 1x per year

5 Infrared scans on all [ ] combiner and re-combiner boxes; 

tighten connections; report broken terminal blocks. 1x per year

6 [ ] sensors and meters, including pyranometers, 

anemometers, and tilt sensors 1x per year

7 Turn off and on to ensure they are communicating and 

ensure battery backups are working. 1x per year

8

Exchange units with Owner’s spares for calibration per 

manufacturer’s instructions. Report serial numbers of 

exchanged units. Calibration costs are non-covered 

services.

[ ]

9 Inverter preventive maintenance for [ ] inverters per 

manufacturer’s operating guidelines See below

10 Clean inverter cabinet air vents. 1x per year

11 Clean and change inverter air filters, if present, per 

manufacturer’s warranty. 1x per year

12 Clean and remove dust from inverter heat sinks per 

manufacturer’s warranty requirements. 1x per year
130

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Service Schedule

Item

Services 

included 

(only if 

checked)

Service Description

Frequency / 

Response 

Time

13

Check torque marks and re-tightening appropriate wiring 

connections to design specification torque force per 

manufacturer’s guidelines.

1x per year

14 If tracked, perform tracker verification and preventive 

maintenance per manufacturer’s owner manual. 1x per year

15 PV array module maintenance for [ ] modules See below

16 Wash all panels with water with no chemicals in a method 

approved by the Owner.

1x per year or 

per study

17

Perform infrared scan of [ ] % of modules for two types of 

circuitry connections: cells on the front and junction boxes 

on the back.

1x per year

18 Vegetation mitigation within the fenced area 1x per year

19

Document details of preventive maintenance work, such 

as meter readings, thermal images, and system testing 

results.

As performed

20 Include non-conformance reports to identify potential 

short-term and long-term power production issues. 1x per year

Service Support

21 Contractor will make available a 24x7x365 Technical 

Support. Ongoing

22

Dispatch commitment: dispatch resources in response to 

alarms and alerts/service requests received by Contractor 

from Owner/Offtaker.

See below

23

Alarm: means loss of one inverter’s production. The 

dispatch time incurs a fee of $XXX per alarm, in addition to 

the fees in non-covered services schedule, including 

alarms that require warranty service.

Dispatch in 

<[ ] specify 

time

24

Alert/service request: means noticeable anomaly or loss of 

power, but inverter in question is still operating. This 

dispatch time incurs a fee of $XXX per alert/service 

request, in addition to the fees in non-covered services 

schedule, including alerts/service requests that require 

warranty service.

Dispatch in 

<[ ] specify 

time
131

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Example Description of Operations Services

As of the Commencement Date, Contractor shall provide the Services marked below at the 

frequency indicated in accordance with the terms and conditions of Operations Agreement:

Service Schedule

Item Services included 

(only if

checked)

Service Description Frequency/Response 

Time

Operations Administration

1 Input and or checking of monthly 

production data 

Monthly

2 Preparation and submission of any 

declarations or notification requested by 

GSE, LAGIE, or other regulatory bodies

When needed

3 Check and approval of in-bound and outbound invoices, as well as verification 

with contracts, proper and correct 

invoicing, settlement

Continuous and on 

demand

4 Management of any SPV contract 

obligation and relationship with SPV 

counterparties

Continuous and on 

demand

5 Continuous check and reporting on 

relevant regulations 

Continuous and on 

demand

6 Advise on necessary actions /adaptations 

of the plant to change in law

Continuous and on 

demand

7 Periodic renewal of the insurance 

contracts and revision of the terms and 

conditions

Upon deadline or yearly

8 Incident intervention, based on data 

gathered through operational 

performance monitoring

When needed
132

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Service Schedule

Item Services included 

(only if

checked)

Service Description Frequency/Response 

Time

9 Insurance claim handling and settlement 

that comes with it, using data gathered 

through operational performance 

monitoring

When needed, up to 2 

events per year

10 Support to legal consultant in relation to 

ongoing litigation

On demand

11 General administrative support for project 

compliance 

When needed

12 Liaising with authorities on behalf of SPV When needed

13 Formal correspondence (authorities or 

contractual third parties)

When needed

14 Managing general compliance events When needed

15 Managing insurance policies When needed

16 Managing land leases When needed

17 Managing telecommunications contracts When needed

18 Managing security contracts (ARC, O&M, 

key holding)

When needed

19 Managing electricity supply agreements When needed

20 Managing PPAs (non-technical) When needed

21 Managing data storage and backup 

contracts

When needed
133

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Service Schedule

Item Services included 

(only if

checked)

Service Description Frequency/Response 

Time

22 Managing document storage (hard and 

soft)

When needed

23 Production register books When needed

24 Justification and calculation of liquidated 

damages (O&M)

When needed

25 Assessment on the calculation of PR and 

availability according to O&M contracts

Yearly

26 Control, follow-up, and settlement of the 

guarantees and penalties using data 

gathered through the operational 

performance monitoring

Yearly

Monitoring

1 Historical data import Upon handover

2 Data acquisition from the current SCADA 

installed & storage

Daily

3 Check on data communication, security 

signal and production and escalation to 

Service Provider

Daily

4 Plant data management, storage, backup Daily

Reporting

1 Actual Irradiance vs Expected @ P50, 

P75, P90

Monthly / Quarterly / BiAnnual / Yearly
134

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Service Schedule

Item Services included 

(only if

checked)

Service Description Frequency/Response 

Time

2 Actual Production vs Expected @ P50, 

P75, P90

Monthly / Quarterly / BiAnnual / Yearly

3 Actual Revenues vs Expected @ P50, 

P75, P90

Monthly / Quarterly / BiAnnual / Yearly

4 Actual Availability vs guaranteed Monthly / Quarterly / BiAnnual / Yearly

5 Actual Performance Ratio vs guaranteed Monthly / Quarterly / BiAnnual / Yearly

6 Delta Production and Revenues vs 

Expected @ P50, P75, P90

Monthly / Quarterly / BiAnnual / Yearly

7 Analysis on performance and 

benchmarking against similar plants 

Bi-Annual / Yearly

8 O&M preventive and corrective 

maintenance services during the current 

month and expected for the following 

month

Monthly / Quarterly / BiAnnual / Yearly

9 Main incidents recorded, incidents 

handling and resolution times

Monthly / Quarterly / BiAnnual / Yearly

10 Corporate, administrative and contractual 

tasks executed during the current month 

and expected for the following month

Monthly / Quarterly / BiAnnual / Yearly

11 Analysis of all performance data of the 

plants to ensure optimal performance 

and detect any areas for improvement.

Bi-Annual / Yearly
135

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Service Schedule

Item Services included 

(only if

checked)

Service Description Frequency/Response 

Time

12 Pro-active intervention, proposal of 

improvements and coordination of action 

items

Bi-Annual / Yearly

13 Operations committees, presentations 

and assistance

Quarterly / Bi-Annual / 

Yearly

Daily Plant Operations

1 Real-time data analysis Daily

2 Root-cause analysis Daily

3 Event notification management Daily

4 Alert notification management Daily

5 Proactive intervention Daily

6 Incident management Daily

7 Trouble ticket creation When needed

8 Trouble ticket management When needed

Field Service Management

1 Issue work order for preventive 

maintenance services

Quarterly or when 

needed in major events

2 Issue work order for corrective 

maintenance services

Quarterly or when 

needed in major events
136

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Service Schedule

Item Services included 

(only if

checked)

Service Description Frequency/Response 

Time

3 Check incident handling & resolution 

times

Quarterly or when 

needed in major events

4 Spare parts management Quarterly or when 

needed in major events

5 Site visits with specific site visit reports Bi-Annual / Yearly

6 Verification of the services relating to 

health & safety, security, quality and 

environment management plans

When needed

7 Supervision and management of the 

contract with the surveillance service 

provider

When needed

8 In case of under-performance, check, 

monitoring and evaluation of the services

to be performed by the Service Provider 

to identify the causes of the issue and to 

correct the issue

When needed

9 Trouble ticket management When needed

10 Major maintenance works assessment

and solutions implemented

When needed
137

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Appendix F. Using Model PV System Availability Terms 

for Contracted O&M

This appendix outlines the foundation for developing language that can be utilized in model 

equipment availability terms typically included in an O&M services agreement for a PV system 

and between a plant owner, operator, and an O&M services provider. The availability of the 

components for function is the foundation of system management and will require planned and 

corrective maintenance at times, regardless of size. Tracking this availability (or unavailability) 

provides transparency into the equipment reliability state to all parties involved in an O&M 

services contract. 

In most PV operation contracts, energy will be the driving factor of whether the system is 

operating as expected. EPC guarantees, operator guarantees, owner measure of ROI, and other 

considerations for a contract are mostly based on whether the system produced energy as it was 

expected to. By itself, the availability terms are not sufficient; energy performance over the life 

of the system should be calculated separately and according to contract terms defined for failure 

to meet those numbers. In addition, energy losses associated with unavailability will play a key 

role in contractual language and whether a system is producing as expected. Both energy and 

availability are necessary metrics for assessing PV systems.

If the stakeholders involved in a contract are most interested in energy production, and if the 

contract holds parties responsible for energy production, then it is crucial that energy losses 

associated with unavailability and system performance are accounted for. Crucial is the 

separation of losses due to unavailability from losses due to performance issues. The 

stakeholders do not want any losses accounted for twice, and they do not want any losses missed.

To further complicate the issue, stakeholders should classify energy losses by category and the 

party responsible for losses in each category. While nobody wants to accept any losses, 

sometimes it is not the fault of any stakeholders who are a party to the agreement. In these 

instances, knowing about the losses and how they are categorized are very important, but blame 

or claim may not be justified against any party to the contract.

It is also important to note that while mitigation of losses is usually the goal of most 

stakeholders, sometimes it is good to give credit where credit is due, mostly as an incentive to 

exceed expectations whenever possible. If a certain energy production is expected, and that 

production is consistently exceeded, the beneficiaries will realize the benefits. Sharing those 

unexpected gains among all parties may be an incentive for all parties to make it happen.

The IEC has specific standards on these topics and for a rigorous treatment on this topic are 

advised to consider their use for information and/or implementation.

IEC 61724-1 Photovoltaic system performance - Part 1: Monitoring

IEC 61724-2 Photovoltaic system performance - Part 2: Capacity evaluation 

method

IEC TS 61724-3 Photovoltaic system performance - Part 3: Energy evaluation 

method
138

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IEC 63019 Information Model for Availability (pending).

Starting with definitions modified from IEEE 762:

The Available state is where a unit can provide service per specification, regardless of whether it 

is in service and regardless of the capacity level and other capabilities that can be provided.

Equipment is in an Unavailable state when the equipment is not capable of operation to 

specification due to equipment failures, external restrictions, testing, maintenance, or other plant 

work being performed or some adverse condition. The unavailable state persists until the unit is 

made available for operation by being synchronized to the system in service state. 

Note in the definitions that there are clarifying thoughts regarding capacity and reasons why 

equipment may not be capable. There are many reasons for downtime and the simplest is that the 

solar irradiance at night will not power a PV system. In IEC 63019, categories of causes include 

full capability, partial capability, services set points, out of environmental specification, 

requested shutdown, scheduled maintenance, planned corrective actions, forced outages (faults 

and failures), suspended, and force majeure. These are presented in tabular form in the model, 

are adjustable, and may need greater specificity that IEC 63019 will provide. Many of these are 

external to management control of the plant, but of course, some are instrumental in the internal 

operation and asset management activities of O&M. Inclusions and exclusions should be 

determined by the scope of contract services sought. 

To successfully understand the various categories of conditions that reduce availability, the

system requires a time series DAS that tracks operating conditions and durations of outages. If 

such information is not available, some categories may require manual tracking of events.

Examples of the myriad events include faults, interruptions due to grid disturbances,

owner/customer interruptions, weather impacts, bio-fouling (e.g. bird droppings), and force 

majeure events. These will need to be identified in the service agreement for inclusion or 

exclusion, but generally, these items may fall into internal or external events or control actions.

The attached model contract clause includes an equation by which to calculate time-based total 

PV power station capacity availability.
139

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Model Equipment Availability Terms

Capacity is a physical property of the PV system and installed components. Capacity will only 

be reduced when a component integral to power production fails (and becomes unavailable).

Individual components will also have capacities associated with them. The total of all 

component capacities will comprise the plant capacity. Capacity can then be used as an input to 

compute full PV system availability, as that is an expected usual goal. With that, use the 

following formula:

Where:

Theoretical total production time (Http):

The hours in the period when sufficient sunlight exists to allow the inverters to reach the input 

voltage needed to operate. 

Nameplate power (KWnp):

The nameplate power rating of the entire solar generating facility determined by the sum of each 

module’s nameplate kWp rating.

Component unavailability hours (Hun):

The hours in the period when solar irradiance is sufficient to power the inverters, yet a 

component within the facility is not available to generate power due to an equipment fault.

Derated system power (KWdr):

The value for unavailability derated system power will be calculated by the amount of 

unavailable DC nameplate capacity for the period and is determined by sum of each module’s 

nameplate kWp rating for that given unavailable component.

Incident: 

Every outage incident during the measurement period.

Note 1: KWdr describes the fractional capacity reduction (not due to degradation).

Note 2: This calculation does not consider cumulative degradation, which should be calculated 

and tracked separately along with energy production.

( )



 





× ×

× = − H ∑ 1 PV System 1 

Availability ttp Incident

un dr

np

H KW

KW
140

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Mandatory – Information categories Availability =

1 – unavailability

MEANING OF 

COLORS:

GREEN = included in 

period hours as 

available 

RED = included in 

period hours as 

unavailable

GREY = excluded from 

period hours

Full performance Partial performance Service 

set 

points

Out of environ spec Requested shutdown Out electrical spec Scheduled 

maintenance 

Planned corrective action Forced outage Suspended Force majeureInformation unavailable Operational 

availability 

Technical 

availability 

Operational 

availability X

Technical availability X

Example: Assignment of downtime events to information categories.

Operational availability is the fraction of a given period (e.g., month) in which a PV 

system is generating. This is primarily an operator’s, user’s, or owner’s view of a PVPS 

and measures how often the asset was generating power. This may also be known as 

“raw” or “all-in” availability.

Technical availability differs from operational availability in that categories generally 

beyond the control of the PVPS systems, subsystems, components, or subcomponents are 

excluded from consideration. For instance, system performance is not being evaluated 

during hours where the operator has requested a shutdown, an electrical connection is 

not available, or a force majeure event has occurred.

(Typical contract terms are not provided in the Model Equipment Availability Terms, and items 

such as liquidated damages, warrantee procedures, exceptions and inclusions, and other 

contract terms will need to be added.)

Figure F-1. Model Availability Terms

This approach is a tool, and the users can deviate from the listed inclusions and exclusions as 

appropriate and further identify and define them for purposes of the contract.

Stated simply, unavailability events must be tracked, and the capacity reduction expressed as a 

percentage is the availability for the duration of the period respective outages. Care must be 

taken to avoid double counting, and this should be reflected in the contract terms. IEC 63019 will 

have guidance for prioritizing outages (i.e., grid outage concurrent at the time of an inverter 

outage), which usually prioritizes keeping components available (internal) versus external factors 

of control of the operator. 

For contracts, a table used to summarize, calculate, and categorize contract exclusions, energy 

gains, and losses due to performance; energy gains and losses due to availability; and associated 

contract penalties or rewards may be useful. By using a summary table, the parties may easily 

calculate offsets of losses in one area with gains in another.