Best Practices Handbook India Hyperlinks

8/2/2019 Best Practices Handbook India Hyperlinks

http://slidepdf.com/reader/full/best-practices-handbook-india-hyperlinks 1/185

With funding from the U.S. Department of State in support of the

Asia Pacific Partnership on Clean Development and Climate

Handbook on Best Practices

for the Successful Deployment of Grid-Connected Renewable Energy,

Distributed Generation, Cogeneration

and Combined Heat and Power

in India

Compiled by the United States Energy Association



AcknowledgementsThe Handbook on Best Practices for the Successful Deployment of Grid-Connected Renewable

Energy, Distributed Generation, Cogeneration, and Combined Heat and Power in India (handbook)

is made possible by the generous support o the U.S. government through the Asia-Pacic

Partnership on Clean Development and Climate (APP). The contents are the responsibility o the

U.S. Energy Association (USEA) and do not necessarily refect the views o any o the APP partner countries.

The author wishes to thank the peer reviewers or their thorough review and constructive

recommendations. While these experts provided valuable guidance and inormation, this

consultation does not constitute endorsement by their organizations o this handbook. The ollowing

proessionals reviewed this document:

Vijay Barthwal, Assistant Vice President, PTC India Ltd.

Richard Brent, Director, Government Aairs, Solar Turbines and U.S. member o the Renewable

Energy and Distributed Generation Task Force o the Asia-Pacic Partnership

David Brown, Principal Distribution System Engineer, Distribution Services, Sacramento MunicipalUtility District

S.P. Gon Chaudhuri, Director, West Bengal Green Energy Development Corporation

Lalnunmawia Chuaungo, Managing Director, Gujarat Urja Vikas Nigam Ltd.

Rakesh Kumar, Executive Vice President o Corporate Development, PTC India Ltd.

Surendra Pimparkhedkar, Senior Research Associate, World Institute o Sustainable Energy

Balour Singh, Director, Punjab Energy Development Agency

V. Subramanian, ormer Secretary, MNRE

S. Seth Vedantham, Advisor, PTC India Ltd.

Barry Worthington, Executive Director, USEA

Disclaimer: The inormation provided in this handbook is intended only to be general summaryinormation to the public. It is not intended to take the place o either the written law or regulations.

For documents available rom this handbook, the USEA does not warrant or assume any legal

liability or responsibility or the accuracy, completeness, or useulness o any inormation, apparatus,

product, or process disclosed. Some content in this handbook may be subject to copyright by

journals and publishers. Use o the copyrighted material is subject to the terms and conditions o use

established by the journal or publisher.

By using links provided on this site that lead to sites other than the USEA site, the user agrees to

hold the USEA harmless rom any liability resulting rom your use o those sites.



Handbook on Best Practices or the Successul Deployment o Grid-Connected Renewable Energy, Distributed Generation,Cogeneration, and Combined Heat and Power in India

1

TABLE OF CONTENTS

Acronyms

I. Introduction and Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

A. Asia-Pacic Partnership on Clean Development and Climate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

B. Renewable Energy and Distributed Generation Task Force . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

C. Handbook Outline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

D. Indian Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

E. Promotion o Alternative Energy In India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

II. Assessment o current policies in India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

A. Electricity Act 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

B. National Electricity Policy 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

C.Tari Policy o 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16D. National Action Plan on Climate Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

III. Barriers to the Successul Deployment o Renewable

Energy and Cogeneration in India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

A.Cross Subsidies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

B. Subsidies or Conventional Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

C. Investment Tax Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

D. Interconnection at 66 kv vs. 11 kv . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

E. Utility Objections Due to Problem o Intermittency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

F. Lack o Programs or Residential Customers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

G. Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

H. Environmental Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

I. Power Sector Reorm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

IV. Policy and Regulatory Best Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

A. Consistent Rules at National and State Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

B. Clear Rules o Ownership and Control o Alternative Energy Facilities . . . . . . . . . . . . . . . . . . . . . 34

C. Examples o Eective Market Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

V. Financial Issues and Best Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

A. Tari Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

1. Standby Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

2. Pricing Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

3. Feed-In Taris . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

4. Retail Natural Gas Rates or Wholesale Applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

5. Interconnection Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49




2

6. Utility Rates Too Low or Renewable to Compete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

7. Loss o Utility Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

8. Retail Buy-back Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

9. Payments or Locational Marginal Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

10. Cogeneration Deerral Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

11. Remittance or Line Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

12. Exit Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

B. Acquiring Renewable Energy and Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

1. Competitive Bidding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

2. Renewable Portolio Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

3. Tradable Renewable Energy Certicates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

C. Incentives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

1. Investment Tax Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

2. Production Tax Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

3. Clean Renewable Energy Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

4. Accelerated Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

5. Capacity Payment Tari . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

6. Demand Credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

7. Buy Down Capital Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

8. Carbon Credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

9. Property Tax Incentives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

10. Other Incentives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

D. Reund o Salvage Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

E. Insurance and Liability Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

VI. Technical Issues and Best Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

A. Grid Stability and Protection Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

1. Intermittency and Grid Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

2. Pre-Interconnection Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

3. Unintentional Islanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

4. Synchronization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 935. Isolation Devices and Backeed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

6. Power Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

7. Monitoring Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

8. Frequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

9. Voltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

10. Voltage Ride-Through Capabilities or Wind Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106




3

11. Area Utility System Fault Detection and Clearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

12. Faults and Reclosing Coordination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

13. Grounding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

14. Momentary Paralleling Allowed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

15. Protection rom Electromagnetic Intererence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

16. Surge Withstand Perormance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

17. Limitation o DC Injection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

B. Equipment Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

1. Isolation Device (disconnect switch) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

2. Paralleling Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

3. Customer Responsible or Protecting Their Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

4. Requirements or Metering/Meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

5. Telemetering/Communication Channels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

6. Net Metering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128

7. Synchronous Generators – Special Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

8. Induction Generators – Special Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

9. Static Power Converter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

10. Static Inverters/Inverter Systems – Special Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

11. Equipment Pre-certication/Pre-approval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

C. Testing Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

VII. Approvals and Application Processing Issues and Best Practices . . . . . . . . . . . 138

VIII. Contractual Issues and Best Practices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

A. Dispute Resolution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

B. Power Purchase Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

IX. Concluding Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

Appendix A Glossary o Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

Appendix B Sample Power Purchase Agreements . . . . . . . . . . . . . . . . . . . . . . . . . 154

Reerences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170




4

Acronyms

AC Alternating current

ANSI American National Standards Institute

app Asia-Pacic Partnership on Clean Development and Climate

AWEA American Wind Energy Association

CDM Clean Development Mechanism

CEA Central Electricity Authority

CEC Caliornia Energy Commission

CER Carbon Emission Reduction credits

CERC Central Electricity Regulatory Commission

CHP Combined heat and power

CII Conederation o Indian Industry

CPUC Caliornia Public Utilities CommissionCREB Clean Renewable Energy Bond

CVPS Central Vermont Public Service Corporation

DC Direct current

DG Distributed generation

DR Distributed resource

DSIRE Database o State Incentives or Renewable Energy

FERC Federal Energy Regulatory Commission

GBI Generation-based incentive

GHG Greenhouse gas

Hz Hertz

IEEE Institute o Electrical and Electronics Engineers, Inc.

IPP Independent Power Producer

IREDA Indian Renewable Energy Development Agency

kV Kilovolt

kVA Kilovolt-ampere

kW Kilowatt

kWh Kilowatt-hour

LMP Locational marginal pricing

MERC Maharashtra Electricity Regulatory Commission

MNRE Ministry o New and Renewable Energy




5

MRET Mandatory Renewable Energy Target

MW Megawatt

NRECA National Rural Electric Cooperative Agency

NRSE New & Renewable Sources o Energy (Policy)PBR Perormance-based regulation

PCC Point o common coupling

PPA Power purchase agreement

PSE&G Pacic Gas & Electric

PTC Production tax credit

PUCT Public Utility Commission o Texas

PV Photovoltaic

RE Renewable energyREC Renewable energy certicate

REDGTF Renewable Energy and Distributed Generation Task Force

RPS Renewable portolio standard (also called renewable purchase obligation, renewable power purchase

obligation, and renewable purchase specication in India)

Rs Rupees

SCADA Supervisory control and data acquisition

SCCR Short-circuit current ratio

SCE Southern Caliornia Edison

SDG&E San Diego Gas & Electric

SERC State Electricity Regulatory Commission

SGIP Sel-Generation Incentive Program

SMUD Sacramento Municipal Utility District

SRP Salt River Project

TOU Time o use

TREC Tradable Renewable Energy Certicate (also called Renewable Energy Certicate, or REC)

UI Unscheduled interchange

UL Underwriters LaboratoriesUSEA United States Energy Association

VAr Volt-ampere reactive

WISE World Institute o Sustainable Energy




6

I. Introduction and SummaryThe United States Energy Association (USEA) received unding in 2008 rom the U.S. Department o State as part

o the Asia-Pacic Partnership on Clean Development and Climate (APP) to create the Grid Connected Renewable

Energy and Distributed Generation Partnership. The main goal o the partnership was to promote policy and regulatory

changes and encourage incentives to accelerate the development and interconnection o alternative energy projects into

the Indian power system. The partnership had three central components: (1) the Handbook on Best Practices or the

Successul Deployment o Renewable Energy, Distributed Generation, Cogeneration and Combined Heat and Powerin India, (2) workshops and (3) a site visit to the U.S.

Workshops were held in three progressive Indian states—Gujarat, Punjab, and West Bengal—and ocused on specic

alternative energy projects and key issues that aect their interconnection. The workshops provided an open orum

or regulators and other policy makers, utility executives, and project developers to discuss initiatives and changes that

could help promote alternative energy projects. The purpose o the workshops was to promote policy and regulatory

changes and encourage incentives to accelerate the development and interconnection o renewable energy, distributed

generation, cogeneration and combined heat and power projects into the Indian power system.

Panel discussions and keynote addresses in all three states ocused on:

Successul policies• , regulation and incentives or renewable/cogeneration development,

Successul renewable energy and cogeneration technologies and projects,•

Interconnecting to the power grid while maintaining grid reliability and stability,•

Project nancing, and •

Power purchase agreements.•

The workshops drew participation rom distribution utility executives, project developers, regulators, investors, and

government policy makers. The state energy development agencies were critical partners in each workshop.

USEA invited the World Institute or Sustainable Development and the regulator, utility and energy developmenagencies rom each state to send one delegate on the U.S. exchange. Participants in the exchange met with leaders

in integrating renewable energy and cogeneration in the United States to discuss how utilities successully integrated

various technologies and alternative energy sources into their systems and policies that encourage alternative energy.

In addition, the participants visited numerous renewable and cogeneration acilities including:

Solano Wind Project (SMUD)•

Kieer Landll (SMUD)•

PV1, PV2 (SMUD photovoltaic installations)•

Cal Denier Dairy Manure Digester Project (SMUD)•

Solar Powered Hydrogen Fuel Station (SMUD)•

Demonstration Site o Concentrating Solar Power (eSolar)•

I/95 Energy/Resource Recovery Facility (Covanta waste to energy plant)•

Central Heating & Rerigeration Plant (U.S. GSA)•

Discussions at these workshops and the U.S. exchange ormed the basis or this handbook.

Introduction and Summary






8

A. Asia-Pacifc Partnership on Clean Development and Climate

The APP is a voluntary multinational partnership launched on January 12, 2006, that includes the governments o

Australia, Canada, China, India, Japan, the Republic o Korea, and the United States.

The goal o APP is to strengthen existing bilateral and multilateral arrangements and create an international

ramework or cooperation in development, energy, environment, and climate change objectives.

The APP’s charter states that the purposes o the APP are to:

Create a voluntary, non-legally-binding ramework or international cooperation to acilitate the development,•

diusion, deployment, and transer o existing, emerging, and longer term cost-eective, cleaner, more

ecient technologies and practices among the partners through concrete and substantial cooperation so as to

achieve practical results;

Promote and create enabling environments to assist in such eorts;•

Facilitate attainment o our respective national pollution reduction, energy security, and climate change•

objectives; and

Provide a orum or exploring the partners’ respective policy approaches relevant to addressing interlinked •

development, energy, environment, and climate change issues within the context o clean development goals,and or sharing experiences in developing and implementing respective national development and energy

strategies.

B. Renewable Energy and Distributed Generation Task Force

APP established eight public-private sector task orces including the Renewable Energy and Distributed Generation

Task Force (REDGTF) to ocus on issues associated with renewable energy and distributed generation (DG)

technology.

The REDGTF’s purpose is to:

Facilitate the demonstration and deployment o renewable energy and DG technologies in Partner countries;•

Identiy country development needs and the opportunities to deploy renewable energy and DG technologies,•

systems, and practices, and the enabling environments needed to support widespread deployment, including in

rural, remote, and peri-urban applications;

Enumerate nancial and engineering benets o distributed energy systems that contribute to the economic•

development and climate goals o the partnership;

Promote urther collaboration between Partner countries on research, development, and implementation o •

renewable energy technologies including supporting measures such as renewable resource identication, wind

orecasting, and energy storage technologies;

Support cooperative projects to deploy renewable and DG technologies to support rural and peri-urban•

economic development and poverty alleviation; and Identiy potential projects that would enable Partner countries to assess the applicability o renewable energy•

and DG to their specic requirements.





9

C. Handbook Outline

This handbook was developed as a tool to assist in the removal o barriers to the deployment o clean energy

technologies. The handbook is intended or policy makers, utility executives, regulators, and project developers

and is a compilation o open-source documents that are cited and listed at the end o each topic as well as in the

bibliography. The handbook compiles inormation rom multiple sources on the major barriers conronting the

deployment o renewable energy and distributed generation, cogeneration and combined heat and power (alternative

energy) projects into one document. It is not intended to be a comprehensive report on each barrier, but rather anoverview with dierent stakeholder perspectives to acilitate discussion and understanding. Each topic lists the

issue; perspectives o the utility, regulator, and developer; best practices; and links or additional inormation. All

links were accessed between January 31 and February 14, 2009, and were unctional at that time.

The term “best practice” as used throughout the handbook reers to practices that have been eective in the

deployment o renewable energy and cogeneration. Eective policies and practices have a positive impact on a

range o actors such as increased installed capacity, reductions in cost and price, technological advances, and public

acceptance. The handbook does not advocate one “best practice” over another nor does it necessarily contain all

practices and policies that have been eective.

The handbook is divided into eight main sections. Section 1 introduces and summarizes the handbook. Section 2outlines current laws and policies in India and gives brie assessments. Section 3 discusses the main barriers to the

deployment o cleaner energy projects in India. Section 4 analyzes policy and regulatory issues and best practices.

Section 5 discusses nancial incentives that have been successul in increasing the deployment o renewable energy,

distributed generation, cogeneration and combined heat and power. Section 6 outlines requirements to maintain grid

stability and protect the system. Section 7 outlines streamlined application processes to reduce the time and cost

associated with project development. Section 8 reviews other issues related to contracts and disputes.

It is hoped that the handbook will serve as a useul reerence or those interested in grid-connected renewable energy,

distributed generation, cogeneration and combined heat and power (CHP) and will expedite locating additional

inormation on these topics. Questions regarding this handbook can be addressed to the author Tricia Williams at

[email protected].

A glossary o terms used in this handbook is attached as Appendix A.

D. Indian Energy Scenario

Current power plants in India rely heavily on sources such as coal that increase greenhouse gas (GHG) emissions.

Part o the solution to mitigate overall emissions is the increased deployment o alternative energy projects. Viable

alternative energy projects could oset the construction o more ossil-uel-red power plants, thus reducing urther

GHG production. However, there are serious barriers to renewable energy, distributed generation, cogeneration and

combined heat and power deployment.

Energy supply shortages, high energy prices, and unreliable energy service are severe impediments to economic

growth in India. The demand or energy in India is increasing aster than production, thereby jeopardizing its

continued growth and stability. With an annual gross domestic product growth o 8% projected or the

Government o India’s Tenth Five-Year Plan, the energy demand is expected to grow at 5.2% per year.

The government o India unveiled an ambitious plan to have power to all households by 2012. In order to ulll this

promise, India must add almost 80,000 megawatts (MW) o power in the next ve years. Much o this additional





10

capacity will need to serve the rural areas,

which are oten not connected to the grid,

necessitating the addition o alternative

energy acillities and/or new transmission

lines to connect acilities and uture

consumers to the grid.

As part o the national energy plan, in April

2006 India launched a rural energy initiative

titled Rajiv Gandhi Grameen Vidyutikaran

Yojana to ulll the commitment o the

National Common Minimum Programme

to electriy all villages and provide elec-

tricity access to all households by 2009.

This national energy plan relies heavily on

interconnections and extensions o the cur-

rent transmission system and targets existing

utilities to provide power to unserved areas.

Each state was required to submit a Rural

Electrication Plan by February 2007 to ad-

dress these issues.

In addition, the Indian Electricity Act

o 2003 created open access to the grid

whereby generators can sell power to entities

other than the local utility. However, the

actual implementation o this plan has been

complicated or even the traditional utilities.

Though wind projects have achieved somesuccess over the past ew years, many

other renewable and alternative energy

technologies have been much slower to be included in the energy mix. Alternative energy technologies such as

reciprocating engines, microturbines, combustion gas turbines, uel cells, photovoltaics, bagasse cogeneration, waste

heat recovery systems, biomass gasication, and waste-to-energy systems have met great challenges in obtaining

approvals to build and interconnect. The cost or interconnection and the higher costs to build renewable projects

have led to slower deployment o renewable energy projects in India and around the world.

Problems with building and operating renewable, distributed generation, cogeneration and CHP projects can be

summarized as ollows:

Longer cost recovery period due to low tari rates and higher development costs (or some technologies).•

Limited access to the transmission grid or the purpose o selling power to a wider consumer base.•

Lack o interest by transmission utilities in extending the transmission network to the remote areas where most•

renewable energy projects are located.

Absence o grid connectivity standards and grid codes or renewable energy projects.•

Diculty in intra- and interstate transer o renewable energy due to stringent open-access regulations that are•

basically ramed or conventional energy projects.

Source: http://www.geni.org/globalenergy/library/national_energy_grid/

india/indiannationallectricitygrid.shtml





11

Regulated energy policies and taris that avor conventional energy sources by not internalizing externality•

costs.

Lack o government policies or distributed generation.•

Economic viability o projects given the need to recover higher development costs than conventional energy•

sources at regulated tari prices.

Subsidies and cross-subsidies that mask the true cost o conventional energy.•

Complicated and lengthy project approval processes.•

Inconsistent implementation and application process to meet renewable portolio standards (RPS orders)•

amongst states.

Resistance o major Indian utilities to the integration o signicant amounts o power rom renewable energy•

and DG power into their grids due to availability, intermittency, reliability compared to conventional sources,

and cost.

E. Promotion o Alternative Energy in India

India has moved rapidly in many areas related to renewable energy, distributed generation, cogeneration, and

combined heat and power. India is the only country with a Ministry o New and Renewable Energy (MNRE) and every state has a coordinating state nodal agency (Energy Development Agency) dedicated to advancing alternative

energy projects. The broad aim o the MNRE and its nodal agencies is to develop and deploy new and renewable

energy to supplement the energy requirements o the country. The MNRE also has several specialized technical and

nancial institutions:

The Solar Energy Centre serves as the technical ocal point or solar energy development.•

The Centre or Wind Energy Technology, an autonomous organisation under the administrative control o the•

MNRE, has been established in Chennai, Tamil Nadu, and serves as the technical ocal point or wind power

development.

The Sardar Swaran Singh National Institute o Renewable Energy is being established as an autonomous•

institution to serve as the technical ocal point or the development o bio-energy, including bio-uels, and

synthetic uels.

The Indian Renewable Energy Development Agency (IREDA) was established in 1987 to promote, develop,•

and extend nancial assistance or renewable energy and energy eciency/conservation projects. IREDA is a

nonbanking nancial institution under the administrative control o the MNRE.

The MNRE and the state development agencies have been critical in the increased deployment o alternative energy

acilities in India and have very ambitious plans. For instance, the Punjab Energy Development Agency plans to add

500 MW rom renewable energy projects in cogeneration, biomass and small hydro in the next two years, more than

doubling its current capacity rom alternative energy. The chart below outlines the achievements thus ar in India.







13

II. Assessment o Current Policies and Regulations in IndiaSince 1994, India’s promotion o renewable energy has shited rom MNRE subsidies to xed taris and private

investments. The Ministry o Non-Conventional Energy Sources guidelines assumed 1994–95 as the base year

or tari determination and or that year, the tari was set at Rs 2.25 per kilowatt-hour (kWh) with a 5% annual

escalation (the prevalent avoided cost o thermal power projects) with a provision or escalation o 5% per year

or the rst 10 years at which point the price o power would stay constant. Currently several dierent policies

and one law address renewable energy at the state level but very little legislation addresses distributed generation,cogeneration and combined heat and power .

The World Institute o Sustainable Energy (WISE) drated a model renewable energy law and submitted it to the

MNRE, which is using it as the base or new legislation. Though it is unclear what will ultimately be included in the

nal legislation, it appears the WISE model has addressed the issues listed below. Some o the highlights o the drat

Renewable Energy Law are as ollows:

Increasing the target or electricity generation rom renewables to 10% by 2010 (as against 2012 currently) and•

20% by 2020 o the total electricity generated in the country (and not as a percentage o installed capacity).

Making solar water heating mandatory throughout the urban areas o the country by 2012 in a phased manner.•

Demonstration o solar rootop lighting systems in 10,000 government buildings by 2010 in a time-bound •

manner, also incorporating building integrated photovoltaics.

Conversion o ossil-uel-based industrial heating to solar thermal heating using new solar concentrator •

technology or its hybrids.

India has at present about 30,000 MW captive generating units (industrial units) o which about 18,000•

MW are diesel based. The drat law proposes time-bound conversion o these captive units to biouel-based

generation, thus saving large amounts o diesel.

Accelerating biouel development and transportation energy to displace ossil uels. A time-bound Renewable•

Fuel Programme covering ethanol and biodiesel has been proposed.

Charting a denite road map or developing a hydrogen and uel cell economy.•

Establishing Renewable Energy Development Funds in all states (on the pattern o Maharashtra).•

Following are the relevant sections rom Indian laws as they relate to renewable energy; an assessment o their

eectiveness in promoting renewable energy, distributed generation, cogeneration, and combined heat and power;

and their impact on the deployment o these systems.

A. Electricity Act 2003

The Electricity Act 2003 was written to combine multiple energy acts related to generation, transmission, and dis-

tribution o power. The Act ocuses mostly on utilities and regulation but does include a ew provisions related to

renewable energy and cogeneration: RPS orders, preerential taris or renewable energy and cogeneration, and open

access.

Renewable Portfolio Standards

State Electricity Regulatory Commissions (SERCs) are required to speciy renewable energy as a percentage o con-

sumption in the distribution licensee’s area under Section 86 o the Electricity Act.

Assessment o Current Policies and Regulations in India




14

The State Commission shall discharge the ollowing unctions. . .

. . . (e): promote cogeneration and generation o electricity rom renewable sources o energy by providing

suitable measures or connectivity with the grid and sale o electricity to any person, and also speciy, or

purchase o electricity rom such sources, a percentage o the total consumption o electricity in the area o a

distribution license.

Tariff

Section 61 o the Act outlines the tari or cogeneration and renewable energy.

The Appropriate Commission shall, subject to the provisions o this Act, speciy the terms and conditions or

the determination o tari, and in doing so, shall be guided by the ollowing, namely . . .

. . . the promotion o cogeneration and generation o electricity rom renewable sources o energy.

Open Access

The provision mandating open access has important implications or renewable energy and cogeneration acilities.

The Act includes “the non-discriminatory provision or the use o transmission lines or distribution system or associ-

ated acilities with such lines or system by a licensee or consumer or a person engaged in generation in accordance

with the regulations specied by the Appropriate Commission.”

<http://powermin.nic.in/acts_notication/electricity_act2003/preliminary.htm>

Assessment

The Act did direct RPS orders but gave no timeline or the SERCs to do so, enabling a large percentage o states to

avoid the issue or years. In addition, allowing the individual states to determine the percentages with no minimum

requirement has led many states to create extremely low percentages with little to no increases over time. As

mentioned in the previous section assessing the Electricity Act 2003, allowances could be made or utilities to

purchase renewable power rom states with greater resources and thus a lack o resources should not be accepted as a

rationale or low RPS.

This act does not use the phrase “preerential taris” mentioned in the Tari Policy 2006; however, a preerential

tari is implied.

The open-access provision is critical or grid-connected renewable energy and cogeneration projects as it mandates

the utility must provide nondiscriminatory access and cannot deny valid interconnection requests. At present, most

generators are not selling energy via the open-access route as preerential taris are payable only i the generator

sells to local utilities. However, open access may become more important as the energy market becomes more vi-

brant and Tradable Renewable Energy Credits become a reality.

However, renewable energy acilities are treated the same as conventional energy acilities without considerationor intermittent and low plant load actor characteristics, which is causing dispatch problems. The Federal Energy

Regulatory Commission o the United States (FERC) recognized these challenges and issued open access or

renewables that created “conditional rm service” to design imbalance charges that refect the dierence between

scheduled and actual energy.





15

The dierence between scheduled energy and the actual energy is called “Unscheduled Interchange” (UI) “in the

Indian Electricity Grid Code and Central Electricity Regulatory Commission (CERC) Tari Regulations. UI is being

used by the distribution utilities to draw their peak energy requirements rom the grid. Injecting renewable energy

in the grid during o-peak hours will create an imbalance and increase requency, which will require the State Load

Dispatch Centres to give instructions to thermal generating stations to back down their generation during this time,

provided the quantum o renewable energy to be injected can be predicted. Thereore, to the extent that the amount o

renewable energy can be predicted, it can be accommodated as UI in the state grid. The concept that “inrm” energy

injected by a generator should be treated as UI is currently not in state grid codes and should be included or greater

clarity, as it is in the Indian electricity grid code.

B. National Electricity Policy 2005

The National Electricity Policy 2005 includes several provisions related to renewable energy and cogeneration that

are quoted below.

Section 5.2.20 promotes private participation in renewable energy:

Feasible potential o non-conventional energy resources, mainly small hydro, and wind and bio-mass would

also need to be exploited ully to create additional power generation capacity. With a view to increase theoverall share o non-conventional energy sources in the electricity mix, eorts will be made to encourage

private sector participation through suitable promotional measures.

Section 5.12.1 promotes the reduction in capital costs o renewable energy technologies:

Non-conventional sources o energy being the most environment riendly there is an urgent need to promote

generation o electricity based on such sources o energy. For this purpose, eorts need to be made to re-

duce the capital cost o projects based on non-conventional and renewable sources o energy. Cost o energy

can also be reduced by promoting competition within such projects. At the same time, adequate promo-

tional measures would also have to be taken or development o technologies and a sustained growth o these

sources.

Section 5.12.2 directs SERCs to speciy appropriate taris to incentivize the deployment o renewable energy and

cogeneration acilities:

The Electricity Act 2003 provides that cogeneration and generation o electricity rom non-conventional

sources would be promoted by the SERCs by providing suitable measures or connectivity with grid and sale

o electricity to any person and also by speciying, or purchase o electricity rom such sources, a percent-

age o the total consumption o electricity in the area o a distribution licensee. Such percentage or pur-

chase o power rom non-conventional source should be made applicable or the taris to be determined by

the SERCs at the earliest. Progressively the share o electricity rom non-conventional sources would need

to be increased as prescribed by State Electricity Regulatory Commissions. Such purchase by distributioncompanies shall be through competitive bidding process. Considering the act that it will take some time

beore non-conventional technologies compete, in terms o cost, with conventional sources, the Commission

may determine an appropriate dierential in prices to promote these technologies.





16

Section 5.12.3 promotes the benets o cogeneration:

Industries in which both process heat and electricity are needed are well suited or cogeneration o electric-

ity. A signicant potential or cogeneration exists in the country, particularly in the sugar industry. SERCs

may promote arrangements between the co-generator and the concerned distribution licensee or purchase

o surplus power rom such plants. Cogeneration system also needs to be encouraged in the overall interest

o energy eciency and also grid stability.

<http://powermin.nic.in/indian_electricity_scenario/national_electri,city_policy.htm> [sic]

Assessment

The National Electricity Policy 2005 does mention the benet o cogeneration and requests that the SERCs promote

it and renewable energy. As with other legislation, the SERCs are given ull responsibility or promoting alternative

energy but have no deadlines, percentages, or penalties or noncompliance, which has allowed some SERCs to move

very slowly or not at all on deploying these resources.

In general, India has some eed-in laws, standardized power purchase agreements (PPAs), nancing rom IREDA,

and market supports such as banking and wheeling which have helped make sugar cane bagasse cogeneration

successul.

C. Tari Policy 2006

Section 6.4 o the National Tari Policy 2006 requires all SERCs to speciy minimum percentages o renewable

energy by April 1, 2006.

(1) Pursuant to provisions o section 86 (1) (e) o the Act, the Appropriate Commission shall x a minimum

percentage or purchase o energy rom such sources taking into account availability o such resources in the

region and its impact on retail taris. Such percentages or purchase o energy should be made applicable or

the taris to be determined by the SERCs latest by April 01, 2006.

It will take some time beore non-conventional technologies can compete with conventional sources in terms

o cost o electricity. Thereore, procurement by distribution companies shall be done at preerential tarisdetermined by the Appropriate Commission.

(2) Such procurement by Distribution Licensees or uture requirements shall be done, as ar as possible,

through competitive bidding process under Section 63 o the Act within suppliers oering energy rom same

type o non-conventional sources. In the long-term, these technologies would need to compete with other

sources in terms o ull costs.

(3) The Central Commission should lay down guidelines within three months or pricing non-rm power,

especially rom non-conventional sources, to be ollowed in cases where such procurement is not through

competitive bidding. (<http://www.orierc.org/new1/documents/National%20Electricity%20Tari%20Policy.pd >).

Assessment

The policy states that the competitive bidding process should be with suppliers oering the same type o energysource, which will encourage development i a percentage o each renewable energy source is mandated.

While Section 86(1)(e) directed the development o RPS orders and special taris or energy, several problems arose.

To begin with, there was no penalty or enorcement or the creation o portolio standards and thus many states

still do not have RPS orders two years ater the deadline. In addition, allowing the individual states to determine

the percentages based on their available sources has led many states to create extremely low percentages (2%) with

little to no increases over time. Though some states have more resources than others, allowances could be made





17

or utilities to purchase renewable power rom states with greater renewable energy production. Because every

state may not be able to generate the renewable energy target, the scheme o renewable energy certicates should

be implemented so that interstate transer o renewable power could be settled through a market-based commercial

mechanism. The CERC is currently advocating this policy.

The Tari Policy states that the appropriate commission should x the minimum percentage o energy rom cogeneration

and renewable energy, taking into account the availability o such resources in the region and its impact on retail taris

There is lack o clarity in Tari Policy 2006 stipulations as to which commission should x what, as the CERC is

responsible or the region and the SERC or the state.

The Electricity Act requires SERCs to promote renewable energy and cogeneration, x the percentage o generation

rom such sources as a percentage o total consumption o electricity, and x taris within the state under sections

86(1)(a) and (e). Thus, the role o the CERC as per the Tari Policy seems to be limited to determining the amount o

generation rom renewable energy and cogeneration within the region or as a percentage o total generation within the

region. Past trends in India show that generation o renewable energy and cogeneration takes place more by incentive

than penalty mechanisms (UI and response to photovoltaic [PV] solar energy proposals or the rst 50 MW under the

new incentive scheme). Because the promotion o clean energy technologies is an issue o national importance, there

is a need in the initial stages or the central MNRE to provide more nancial assistance such as concessional unding

and exemption o taxes with the balance cost to be paid or by consumers through billing by distribution companies

with the approval o the SERC.

Because this is supposed to be a long, drawn-out process, the percentage o renewable energy and cogeneration or

each type may have to be increased progressively rom year to year, allowing a gestation period or developing such

generation resources, both within and across states.

The phrase “preerential taris” has been widely interpreted among the individual state commissions and

stakeholders. The general interpretation o this phrase is that the tari should be considerably higher. Commissions

are oten reluctant to grant high tari rates or ear they will lead to higher rates or consumers.

D. National Action Plan on Climate Change

The Electricity Act 2003 and the National Tari Policy 2006 both provide the CERC and the SERC with the author-

ity to prescribe a percentage o total power rom renewable energy. The National Action Plan on Climate Change

suggested the ollowing enhancements in the regulatory regime on page 43:

A dynamic minimum renewable purchase standard (DMRPS) may be set, with escalation each year till a pre-(i)

dened level is reached, at which time the requirements may be revisited. It is suggested that starting 2009-

10, the national renewable standard (excluding hydropower with storage capacity in excess o daily peaking

capacity, or based on agriculture based renewable sources that are used or human ood) may be set at 5% o

total grids purchase, to increase by 1% each year or 10 years. SERCs may set higher percentages than this

minimum at each point in time.

Central and state governments may set up a verication mechanism to ensure that the renewable based (ii) power is actually procured as per the applicable standard (SMRPS or SERC specied). Appropriate authori-

ties may also issue certicates that procure renewable based power in excess o the national standard. Such

certicates may be tradeable, to enable utilities alling short to meet their renewable standard obligations.

In the event o some utilities still alling short, penalties as may be allowed under the Electricity Act 2003 and

rules thereunder may be considered.





18

(iii) Procurement o renewable based power by the SEBs/other power utilities should, in so ar as the applicable

renewable standard (DMRPS or SERC specied) is concerned, be based on competitive bidding, without

regard to scheduling, or the taris o conventional power (however determined). Further, renewable based

power may, over and above the applicable renewable standard, be enabled to compete with conventional gen-

eration on equal basis (whether bid taris or cost-plus taris), without regard to scheduling (i.e. renewable

based power supply above the renewable standard should be considered as displacing the marginal conven-

tional peaking capacity). All else being equal, in such cases, the renewable based power should be preerred

to the competing conventional power. (http://pmindia.nic.in/Pg01-52.pd )

Assessment

The recommendations in the plan are consistent with those in this handbook. The minimum renewable portolio

standard o 5% applied to all states will greatly assist India in meeting its overall renewable energy goals. World-

wide, most nations are not meeting their target RPS and one reason is a ailure to mandate the percentage at the

state level. Most nations state a desired percentage o energy rom renewable sources but leave it up to the states to

mandate. As an example, India would like to have 10% renewable energy by 2012; however, only our states have an

RPS o 10% or higher.

Allowing the procurement o renewable energy through tradable certicates and power trade is an excellent solution

or states with low renewable energy resources. The concept o competitive bidding to procure renewable energy is a

good option; however, historically, competitive bidding in India has not resulted in anticipated capacity addition or

conventional power so urther study on this issue is needed. These solutions are outlined in greater detail in the “Fi-

nancial Issues and Best Practices” section o the handbook under “Acquiring Renewable Energy and Cogeneration.”

Sources and For More Inormation:

Electricity Act 2003: <http://powermin.nic.in/acts_notication/electricity_act2003/preliminary.htm>.

FERC Order 890: <http://www.erc.gov/industries/electric/indus-act/oatt-reorm/order-890/act-sheet.pd > and <http://www.erc.gov/

industries/electric/indus-act/oatt-reorm/order-890/pro-orma-tari-nopr.pd >.

Renewable Power Policies-Programme-wise: <http://mnes.nic.in/policy/policy-programme-wise.htm>.

National Action Plan on Climate Change: <http://pmindia.nic.in/Pg01-52.pd >.

National Electricity Policy 2005: <http://powermin.nic.in/indian_electricity_scenario/national_electricity_policy.htm>.

Tari Policy 2006: <http://www.orierc.org/new1/documents/National%20Electricity%20Tari%20Policy.pd >.

Unscheduled Interchange: <http://www.srldc.org/Downloads/Signicance_o_UI.pd > and <http://www.nldc.in/docs/abc_abt.pd >.





19

III. Barriers to the Successul Deployment o Renewable Energyand Cogeneration in India

Climate change concerns coupled with high oil prices, peak oil and increasing government support are driving

increasing alternative energy legislation, incentives and commercialization. However, signicant barriers to deploy-

ment o alternative energy exist in most countries.

USEA organized workshops on grid connected renewable energy, distributed generation, combined heat and power

and cogeneration in Gujarat, Punjab and West Bengal to determine the major barriers to their deployment in India.

Participants in these workshops identied several key barriers to the successul deployment o alternative energy

sources. The barriers can be broken down into our general categories which correspond to the outline o this hand-

book: nancial, regulatory and policy, nancial, and technical.

This section highlights the key barriers mentioned during these workshops:

Cross Subsidies•

Subsidies or Conventional Fuels•

Investment Tax Credit•

Interconnection at 66 kv vs. 11 kv•

Utility Objections Due to Problem o Intermittency•

Lack o Programs or Residential Customers•

Cost•

Environmental Regulations•

Power Sector Reorm•

Barriers to the Successul Deployment o Renewable Energy and Cogeneration in India




20

A. Cross-Subsidies

Policy

All regulatory commissions in India include cross-subsidies in their taris. The cross-subsidization benets residentia

consumers. Thus any policy that reduces industrial and commercial consumption will adversely aect the utility’s

prots and ability to assist residential consumers. Cogeneration and combined heat and power (CHP) have the potential

to be a major problem or Indian utilities or this reason; it takes away their revenue base. In addition, there is a huge problem in India with residential consumers paying their bills but very ew problems with industry and commercia

payments.

Assessment

Taris are determined based on the average cost o generation or all categories o consumers and the distribution

costs and line losses, which are ar lower or high-tension industrial consumers than low-tension residential

customers. Thus, industrial customers in India carry more than their share o the cost o electricity, which makes

CHP look more attractive. In act, industrial and commercial taris are much higher than generating one’s own

electricity rom CHP. I the cross-subsidy were decreased and industrial rates were lowered, CHP would be less

attractive, which would reduce the deployment. Eliminating or reducing cross-subsidies would thus assist the

utility’s revenue stream i industrial customers added CHP but would conversely decrease the incentive to add CHP.It is clear that subsidies cannot be changed without additional policies to address this conundrum.

I CHP is built solely to sell to the market to address energy shortages and does not take away utility revenue, there

is no barrier to CHP development. However, i the industrial or commercial load is partially met through CHP, the

reduced revenue would aect the utility’s ability to cross-subsidize residential customers and may not be welcomed.





21

B. Subsidies or Conventional Fuels

Policy

Most world governments subsidize energy; some do so signicantly. Global subsidies or conventional energy

remain many times higher than those or renewable energy. Even small subsidies or kerosene or diesel can

discourage the use o renewable energy. Conventional energy can also benet rom hidden or indirect subsidies such

as government energy purchases and exemptions rom risk or liability.

Assessment

Subsidies articially lower the cost o conventional energy to consumers. Removing these subsidies would lead to

consumers paying the true cost o energy and would narrow the gap between the cost o renewable and cogeneration

and conventional energy. However, it would increase the cost to consumers overall, which may not be politically

easible in India.





22

C. Investment Tax Credit

Policy

India used investment tax credits to incentivize the development o wind projects. These credits allowed investors to

reduce their tax liability and gain all the benets in the rst ew years ollowing the investment, greatly reducing the

risk and cost o investing in alternative energy systems. The scheme, which gives an accelerated depreciation benet

o 80% and other tax incentives or installation o the plants, gave incentives to some cash-rich investors who tookadvantage o tax benets and were not serious about generation o power. The credits did stimulate investment but

gave no incentive to actually produce power or maintain and operate the equipment ater construction. Wind energy

accounts or over 6% o India’s total installed power capacity yet just 1.6% o the country’s power.

Assessment

Investment tax credits give no incentives or maintenance o the acilities or generation o energy and have oten led

to acilities that do not run, thus hurting the utility’s ability to provide energy to its customers. It can lead to over-

invoicing or underinvestment in operation and maintenance by developers looking to make a quick prot and then

exit as their prots are received up ront with the installation. These practices impact the price o electricity rom

renewable sources and make it harder or serious developers to compete.

However, in some states investment tax credits were not a detriment to wind development. In states such as Tami

Nadu, the wind energy project developers generate electricity, step it up to grid voltage (220 kilovolts [kV]/132 kV)

eed to the grid, and are paid at rates xed by the relevant SERC, which is the reason or the success o wind energy

projects in these states. Although in initial years the developers may not get the required return, in subsequent year

they will get an adequate return because the tari becomes remunerative ater the loan is repaid.

There is some movement in India away rom investment tax credits toward production-linked incentives, as is

mentioned in the Planning Commission, Government o India documents and the Integrated Energy Policy and the

Central Governments Five-Year Plan. In line with these directives, MNRE declared the Generation-Based Incentive

(GBI) or Grid-Connected Wind and Solar Power Projects. The GBI is a Rs 0.50/kWh incentive or the rst 50

MW o wind power projects commissioned during 2007–12 and a maximum Rs 10/kWh and Rs 12/kWh incentiveor grid-connected solar PV and solar thermal power projects or the rst 50 MW commissioned between 2007 and

2012. The GBI is in addition to the tari declared by the SERCs and the benet is available only to those investors

who do not avail themselves o the accelerated depreciation benet.

Practice in the United States

The Internal Revenue Service (the entity that gave the investment tax credit) investigated developers who received the

credit and instigated legal proceedings to get the money back rom those not generating energy.

As o January 1, 2009, the U.S. ederal government allows a 30% tax deduction or the entire installed cost o

residential systems. The U.S. government removed the “up to $2,000” o the installed cost clause; the whole cost o

the system is now eligible or the deduction.





23

D. Interconnection at 66 kV vs. 11 kV

Policy

Every state in India has a grid code that states interconnection standards. Many o them, however, state

interconnections only at the 66 kV level. For instance, the Gujarat grid code states that the captive power plant, or

cogeneration acility, can be interconnected at the 400/220/132/66/22/11 kV level or as agreed with the transmission

utility. However, 22 and 11 kV is the distribution utility level, not the transmission utility level, so it is unclear whether interconnection with the distribution company is allowed. The only other interconnection it mentions

or nonutility or non-transmission companies is or extra high voltage consumers o 66 kV or higher. In practice,

although it states interconnections can occur at the 22 or 11 kV level, in India they are mostly connecting renewable

and cogeneration projects at the 66 kV level.

Assessment

There are several concerns with the state grid codes with regards to interconnections o renewable energy and

cogeneration acilities. The rst is that the Electricity Act 2003 does not speciy the voltages or transmission and

distribution systems. The Indian power sector has adopted the best practices o 66 kV and above as transmission

and 33 kV and below as distribution. In some states, transmission utilities also maintain 33 kV lines and some

distribution utilities have 66 kV, so there is overlap. These voltages should be clearly dened and uniorm between states. One possible denition is that lines that are intrastate or connect dierent utility service areas are

transmission as these tend to be 66 kV and higher.

Some states, such as Gujarat, do allow interconnection at the distribution level, especially or wind and biomass

projects. However, interconnection with the distribution system depends on the installed capacity o the generating

station, the nature o generation, the electricity demand in that area, and the condition o the distribution

inrastructure. The last point is the most problematic as in most cases problems in the distribution system, especially

in terms o the availability o capacitor banks, requent aults, and energy accounting, are a serious deterrent to

providing interconnection at the lower distribution levels.

Perhaps one o the greatest concerns is that there are no stated standards or interconnecting smaller acilities to thegrid. Connecting at the 66 kV level can add signicant costs and equipment to a project and may ruin its economic

easibility. The costs in the United States illustrate the problem. Connecting a acility at the 11 kV level or below

would simply require at most a small pad-mounted transormer that would cost thousands o dollars. Interconnecting

at the 66 kV level requires a single step-up transormer or small substation that costs substantially more ($1 million).

A acility that generates only 5 MW or less would nd the costs o interconnecting at the 66 kV level uneasible.

In the Central Electricity Authority (CEA) Regulations on Grid Connectivity, the term “Distribution System” has

been dened as “the system o wires and acilities between the delivery points on the transmission lines or generating

stations and the points o connection to the installation o the consumers and may comprise lines and equipment o

any distribution voltage,” according to which generation can be at 11kV also. However, in CEA’s specication o

generating units, it has been stated that “all generating units shall have standard protections to protect the units notonly rom aults within the units and within the station but also rom aults in transmission lines,” which implies that

generating units are connected to the transmission system. There is a need or CEA to suitably amend its regulations

to permit small generating stations to be connected to the distribution system and correspondingly SERCs should

modiy the state grid code to have clarity.

Furthermore, the grid code states the cogeneration acility can be interconnected at various levels but leaves it to the

utility’s discretion as to which level it will be interconnected. At the USEA-acilitated workshops in India, many

utilities and regulator experts expressed the view that 66 kV and above is the transmission–not the distribution–level





24

in India. Some regulators consider distribution to be part o the grid so codes would apply but clearly there is

currently no codication at the distribution level.

In addition, interconnection rules at the distribution level are much simpler. When grid problems occur, the

connected acilities would simply disconnect rom the system, making it possible or them to utilize cheap and

simplied radial connected equipment (an underlying concept o Rule 21). At the transmission level, the utility oten

wants them to stay on the system to try to help, which would require additional equipment such as power system

stabilizer or droop compensation, protection requirements or ault/trip, and transer trips, which can get expensive.

India

In Gujarat, 66 kV and above is considered transmission and is owned and operated by the transmission company.

The grid code and distribution code o Gujarat allow the injection o small amounts o power rom renewable energy

at 22 or 11 kV levels and a small number o generators are injecting at the 11 kV level. However, or technical and

commercial reasons, the utilities are not promoting injection below 66 kV. Participants in USEA’s workshops state

that additional regulatory orders are needed to address the concerns o utilities and generators to increase the number

o interconnections at lower levels.

The Punjab Energy Development Agency recently issued a PPA or a PV acility that allowed interconnection at the

11 kV level. The Punjab state grid code does state that voltage may be 66 kV, 33 kV, or 11 kV or as agreed with the

state transmission utility. However, the choice to use 11 kV or 6 kV is also dependent upon the extent o the grid

layout in various parts o the State. In Punjab, the state utilities are now part o the Northern Grid and have to strictly

maintain both the requency and voltage; the shortages in power are met by load shedding which takes place only at

11 kV and never at 66 kV. Hence, some DG and renewable energy acilities have no option but to eed power at 66

kV even though it requires higher capital costs. At the same time, small solar PV power plants at the 1 MW scale

would need a special provision to allow evacuation o power at the 11 kV level with the creation o an additional

substation near the plant at the state’s expense.

United States

The standard denition o transmission in the United States is operating voltages o 69 kV and up while distribution

is less than 69 kV.


Central Electricity Authority: <http://india.smetoolkit.org/india/en/content/en/8221/Ministry-o-Power-Notication-No-12-X-STD-

CONN-GM-CEA-21-Feb-07-The-Central-Electricity-Authority-Technical-Standards-or-Connectivity-to-the-Grid-Regulations-

2007>.

Gujarat grid codes: <http://www.pgvcl.com/regulations/DistributionCode.pd > and

<http://www.pgvcl.com/regulations/GridCode.pd >.

Punjab grid codes: <http://pserc.nic.in/pages/state_grid_code.html>.





25

E. Utility Objections Due to Problem o Intermittency

Utilities have two main objections to installing renewable energy on their system because o the issue o

intermittency: scheduling when power is not rm (i.e., known day ahead) and system reliability and stability due

to fuctuations rom wind power in particular. Many executives in India, at both the development board and utility

level, are looking or ways to “rm up” renewable energy to avoid this problem.

Assessment

Wind energy is the most intermittent source but with proper planning it can be mitigated. While rming power,

such as with a hybrid solar/wind installation, is an alternative, the American Wind Energy Association (AWEA)argues that it is better to look not at rming the individual generator, which is expensive and inecient, but athow the system as a whole is to be shaped to reliably absorb more variability. AWEA suggests that it is essentialto understand that wind is an energy resource, not a capacity resource, and that utilities should take the wind energy when it is available and rely upon other system resources when it is not.

Though India is acing a shortage and does not have spinning reserves or capacity to oset generation lostrom renewable sources, the concept o Unscheduled Interchange (UI) can be useul. In Tamil Nadu, a state

with a large percentage o wind, the State Load Dispatch Centre can balance the load and generation by either backing down thermal generation and/or regulating pumped storage hydro generating stations. The wind energy

generating acilities are able to maintain a high power actor by installing automatic capacitance controls whichshould be utilized in other states as well to address power actor issues.

In India many eel there is a need to provide physical and regulatory acilities to acilitate the fow o renewableenergy (particularly o wind) beyond a particular state. Gujarat has wind potential o around 10,000 MW, o which 1,300 MW is already harnessed, 500 MW is ready or commissioning, and another 880 MW is in the

approval process. In addition, requests or transmission system studies have been received by the GujaratTransmission Utility or installation o another 4,300 MW o wind. This much capacity has the potential tocause problems or the state utilities in their eorts at commercially sustainable load management unless there is

acilitation or export to the regional and/or national grid.

Practices for Scheduling Issues

Xcel, a large multistate utility serving portions o Colorado, Minnesota, Texas, and other states, will be lookingto wind as the major source o new energy or its system, with Xcel eventually becoming dependent upon wind or about 30% o the energy on the system. There are two keys to moving in this direction:

Xcel is relying upon strategically placed high-eciency gas turbines or about 6% o the new energy added to•

the system—this provides the necessary operational fexibility.

Xcel is participating in a large regional electric power market, the Midwest Independent System Operator,•

which allows them to eectively utilize more o a variable resource than a small electric system or control area

would allow. Another example is the PJM Interconnection, which can absorb enormous amounts o a variableresource such as wind because o its geographic scope, making wind variability a nonissue within such a

complex system. India’s new energy market could help alleviate some o the problems with intermittency.





26

Practices for System Reliability Issues

A GE Energy executive stated in a USEA-acilitated workshop that India can avoid large voltage variations and

uncontrollable power rom wind turbines by installing turbines with grid-riendly perormance eatures that regulate

voltage and ride-through aults and control power output. Voltage control will regulate the grid voltage at the point o

interconnection, regulate total wind plant reactive power through the control o individual turbines, and minimize grid

voltage fuctuations even under varying wind conditions. Voltage regulation is very important as the wind generator

cannot be in constant power actor mode. Ride-through capability allows the generator to stay online and eed reactive

power into the grid through system disturbances while meeting transmission reliability standards similar to those

o thermal generators. New technology can support reactive power even when there is no wind but regulators will

need to insist on the use o the technology in order or everyone to begin using it. Reactive power drawal should be

incentivized or disincentivized based on local voltages, generators should be able to ride through transient aults, and

active power control that limits the rate o change in power under varying wind conditions should be utilized based on

system requency.


AWEA:< http://www.awea.org/utility/pd/Wind_and_Reliability_Factsheet.pd >.

GE:<http://www.usea.org/Programs/APP/Punjab_Workshop/01_GE_Wind.pd >.





27

F. Lack o Programs or Residential Customers

Currently, there do not appear to be very many programs in India or residential customer installation o renewable

energy technologies. Solar water heaters are being promoted through a sot loan scheme through IREDA and seven

banks where domestic loans are available at a 2% interest rate. However, the capital subsidy is available only or

institutions and commercial entities, not or individual consumers.

There are currently no programs or residential PV installations, rebates or energy-ecient appliances, or other

systems that could address demand and supply energy to residences.

Both the IREDA and state-level Renewable Energy Development Agencies do give some incentives such as providing

residential consumers with concessional rates or solar water heaters and solar cookers.

There are more programs on energy eciency or residential consumers than or small-scale residential renewable energy

systems. The distribution utilities give CFL lights to consumers at concessional rates and the Energy Conservation

Act states that manuacturers o electrical appliances such as rerigerators, air conditioners, and room heaters should

begin a program to identiy high-eciency appliances. The Bureau o Energy Eciency has also recently taken many

progressive steps in this direction.





28

G. Cost

A major issue or all countries, and especially developing countries, is the issue o the higher cost o renewable

energy and cogeneration compared to conventional energy sources. Many residential customers in India already

cannot pay their energy bills, and increasing the cost by adding expensive alternative energy could strain the society.

Assessment It is undeniable that alternative energy sources cost more than conventional sources as they are currently priced.

However, i environmental externalities and diversication values are used instead o discounted cash-fow

accounting, then renewable energy is more economical. These are policy decisions that should be addressed at both

the central and state level.

Traditional nancial analysis using discounted cash-fow undervalues uture uel price risks and ignores

environmental and health costs o conventional energy sources. When uel prices and social impacts are assessed,

renewable energy is close to—or competitive with—conventional energy sources. Even in discounted cash-fow

accounting, though, uel price escalation needs to be taken into account to refect long-term tari calculations, which

is sometimes neglected because it is a “pass through” to consumers.

Subsidies are another way the cost is articially lower. Removing these subsidies would lead to consumers paying

the true cost o energy and would narrow the gap between the cost o renewable and cogeneration and conventional

energy.

In addition, the argument that alternative energy sources cost too much is not entirely accurate. Most utilities

in India have shortages and are orced to purchase energy on the spot market, where prices are ar higher. As

an example, it is believed that the cost o a 6% RPS target will increase the consumer tari in Maharashtra by

2%. Maharashtra was purchasing more costly power rom energy traders and ound that the cost o purchasing

conventional power at the margin was higher than the average 3.32 Rs per unit cost rom all renewable energy

sources. Procuring power rom renewable energy sources at the existing tari rates will thus not only add to the

availability o energy but also be cheaper than power purchased in the market and thus will not adversely aectconsumers.

One way to address the cost is to establish a market or tradable renewable energy certicates. In this way, states that

may have high renewable energy costs could “purchase” energy rom lower cost acilities in other states or utility

service areas to meet their RPS. The RPS orders in Maharashtra and Rajasthan both allow or purchasing energy to

meet RPS targets but do not include a tradable renewable energy certicate (REC) eature.





29

H. Environmental Regulations

Environmental regulations help internalize the social and environmental costs o conventional energy sources,

which makes renewable energy and cogeneration more competitive. They are also considered as critical to promote

technology transer to developing countries. Regulations can encourage renewable energy and other clean energy

sources indirectly through oset credits (tradable renewable energy credits), or directly as utilities and developers

begin to avor cleaner technologies that do not require emissions reductions. However, any environmental regulationmust be enorced. China has environmental regulations at the national level but enorcement is low and local

governments oten do not require coal-red plants in their territory to adhere to the regulations.

India included environmental protection rights and duties in its Constitution and has an elaborate ramework o envi-

ronmental legislation, policy statements, rules and notications. Key policies and legislation are listed below.

National Environment Policy o 2006•

National Environmental Appellate Authority Act o 1997•

National Environmental Tribunal Act o 1995•

National Policy on Pollution Abatement (1992)•

National Conservation Strategy and Policy Statement on Environment and Development (1992)•

Public Liability Insurance Act o 1991•

Water (Prevention and Control o Pollution) Cess Act o 1977, amended in 1991•

Water (Prevention and Control o Pollution) Act o 1974, amended in 1988•

Air (Prevention and Control o Pollution) Act o 1981, amended in 1987•

Environment (Protection) Act o 1986 (EPA)•

Despite the exhaustive legislative eorts in environmental regulation, the level o compliance and enorcement is

low. According to the Central Pollution Control Board, as o June 2006, 73% o the highly polluting industries were

in compliance with environmental regulations, a decrease o 14% rom 2004. Small and medium-sized enterprises

have a much lower compliance rate and contribute an estimated 70% o the total industrial pollution in India (see<http://www.oecd.org/dataoecd/39/27/37838061.pd > and <http://www.ijbe.org/table%20o%20content/pd/vol2-

1/02.pd >).

The lack o enorcement o environmental standards in India may be a barrier to the development o renewable

energy and cogeneration. Recommendations to improve enorcement can be ound at <http://www.oecd.org/dataoecd/39/27/37838061.pd >.





30

I. Power Sector Reorm

Power sector reorm can work against renewable energy/cogeneration development as the unbundled utility no

longer has an incentive to und research and development o new technologies. In addition, there has been increased

pressure to measure supply technologies only by the bottom-line price to consumers without taking environmental,

energy security, or other benets o renewable energy/cogeneration systems into account.

The World Bank cites the case o Nicaragua which has over 3,000 MW o commercially viable renewable energy that

can supply power at a lower cost than conventional energy sources when other actors such as uel price uncertainty

are taken into account. However, the percentage o renewable energy in the national generation mix has decreased

over the past 20 years. Because investor risk in power generation systems is mostly driven by capital costs, which

are more intensive in renewable energy technologies, and uel risks are passed directly on to consumers, there is

no incentive or renewable energy to be developed even though in the long run it would most likely be more cost-

eective. The low capital cost o thermal generation is a barrier to renewable energy generation but passing uel

risks on to consumers does help as it increases the cost o thermal generation. Furthermore, uel charges can

fuctuate with the market which also can benet renewable energy projects as they do not use uels and thus can oer

a set rate.





31

IV. Policy and Regulatory Issues and Best Practices

Renewables make up the astest-growing energy industry in the world and have the potential to meet hal the world´s

energy needs by 2050. Investment in renewables increased to almost $150 billion in 2007 rom $33 billion in 2004.

Sustaining the growth momentum, however, requires ambitious, robust climate and energy policies with long-term

commitments and concrete targets.

Alternative energy has the potential to renew the global economy, and policy-makers have it in their power to drive

and shape that renewal. Alternative energy sources can cut greenhouse gas emissions, build energy security, reduce

energy costs, improve public health, save water, and protect the local environment. Today, governments are taking a

closer look at alternative energy sources and the opportunities they oer or economic recovery and or laying the

oundations or uture prosperity.

The need or enacting policies to support alternative energy is oten attributed to a variety o “barriers” or conditions

that prevent investments rom occurring. Energy policies must refect reliable, objective, and up-to-date acts and

gures on the cost, perormance, and potential o renewable energies. Policies can explicitly promote alternative

energy or can indirectly infuence incentives and barriers.

This section highlights general principles o successul policies and cites examples o policies worldwide that have

eectively increased the deployment o alternative energy.

Policy and Regulatory Issues and Best Practices




32

A. Consistent Rules at National and State Levels

Issue: Rules and policies that vary between states or countries increase the costs or developers and lead to higher

risk and regulatory uncertainty.

Utility Perspective: States have dierent resources, electrical systems, and nancial systems and should have

dierent rules to refect this.

Developer Perspective: Dierent rules in dierent states can increase the cost o doing business or renewable

energy and cogeneration developers in terms o both time spent reviewing rules and dierent designs and equipment

required.

Regulator Perspective: Rules should refect local (state) realities but ederal policies would be more dicult to

enorce unless they are suciently broad to allow or dierences in resources and utilities. For instance, a ederal

law stating 5% o generation should come rom wind may not be easible in all states.

India

As there is no national renewable energy law, each state has dierent interpretations o Section 86(1)(e) whichmandates RPS and thus state RPS ranges rom 0.5% to 10%. The low RPS percentages or lack o a RPS in some

states has led to less renewable energy deployed. The Government o India’s 11th Plan (2007-12) states a target o

78,700 MW installed generation capacity while the Ministry o New and Renewable Energy’s 11th Plan calls or an

additional 14,000 MW o grid connected renewable energy by 2012. MNRE’s aggressive target equals a national

RPS o 17.8% o capacity added during 2007-12. It is dicult to see how India could meet this target when states

will average about 4% RPS in 2010 (based on current data or state RPS in 2010).

Because India is a ederal system and electricity is constitutionally within the state jurisdiction, prescribing and

enorcing uniorm standards will be dicult. However, entities like the Federation o Indian Regulators (FOIR)

could spearhead eorts to create uniorm standards and policies in the individual states. A holistic approach

and integrated energy planning through Renewable Energy Certicates (RECs) or example, would likely lead toincreased development. India is currently working on such a law that is expected to be in place by the end o 2009.

Best Practices:

Best practices or consistent rules all into two categories: RPS standards and interconnection standards.

India’s proposed renewable energy law suggests a national 5% RPS standard that would compel states to increase

their RPS to at least 5%. The national RPS would be a signicant boost to renewable energy development and would

lead to greater consistency and certainty or investors.

On the technical side, there are currently no interconnection standards at the distribution level. The Central

Electricity Authority Technical Standards or Connectivity to the Grid (2007) does mention connectivity conditions atthe distribution level. However, the standards do not speciy equipment and give the utility a great deal o discretion

in deciding the design o the interconnected acility. For instance, under protection system and coordination, the

standards state that “Every element o the power system shall be protected by a standard protection system having the

required reliability, selectivity, speed, discrimination and sensitivity” yet the standard protection system is not clearly

dened.

Policy and Regulatory Issues and Best Practices Consistent




33

It urther states that “Special Protection Scheme such as under requency relay or load shedding, voltage instability,

angular instability, generation backing down or Islanding Schemes may also be required” (pg. 9). This broad

latitude given to utilities may create a barrier to interconnection or smaller alternative energy acilities.

Individual states and utilities within those states can have dierent interconnection policies which create uncertainty

among investors and can substantially increase costs. To combat this problem in the U.S., the Institute o Electrical

and Electronics Engineers (IEEE) created a series o rules including 1547 which is cited in the technical portion

o this handbook. IEEE 1547 provides a uniorm standard or interconnection o alternative energy acilities

with electric power systems and includes requirements relevant to the perormance, operation, testing, saety

considerations, and maintenance o the interconnection. The creation o a similar set o standards in India may

prove useul in removing barriers to interconnecting alternative energy acilities.


India:<http://www.bakernet.com/NR/rdonlyres/0251961F-DACD-4C9E-9415-A7A24A28485C/44792/RenewableenergyinIndia.pd >

CEA Technical Standards or Connectivity to the Grid:<http://jameskutty.ino/rules/gridconregns_2007.pd >.

Policy and Regulatory Issues and Best Practices




34

B. Clear Rules o Ownership and Control o Alternative Energy Facilities

Issue: Utilities may insist on owning or controlling these acilities at least in some orm to meet obligations to pro-

vide sae and reliable distribution grid inrastructure, with the greatest level o control or alternative energy acilities

installed in lieu o a wires upgrade.

Currently in India, cogeneration projects are owned mainly by industries such as sugar industries or cooperativesocieties that produce process steam. Although the distribution utility can generate power to meet its load, not many

are involved in cogeneration because heating load is not supplied by utilities in India. So, in general the ownership

o cogeneration is not an issue in India at this time. However, this could become an issue in the uture i distribution

utilities do enter the cogeneration market, so it has been included in this handbook.

Utility Perspective: Utilities have argued that, as with other proscriptions against the incumbent utility participat-

ing in new markets, limiting utility ownership o alternative energy acilities would relieve competitors rom having

to compete against what will likely be the most knowledgeable player in the market. Thereore, eciency will be

diminished i utility involvement were minimized or prohibited. Utilities also dispute claims that utility ownership

creates market power as market control is mitigated by standardized interconnection requirements that are enorced

by both state and ederal regulatory authorities.

Developer Perspective: For alternative energy acilities on customer premises, some parties, citing market power

concerns, contend that utilities should be proscribed rom participating in this new market or allowed to own these

acilities only through an aliate with availability o distribution wheeling, a transparent utility planning process or

alternative energy acilities and perormance-based rate structure or the utility.

Regulator Perspective: The Caliornia Public Utilities Commission concluded that with sucient utility control,

or physical assurance, over alternative energy acilities installed in lieu o a distribution system upgrade, utility

ownership is not required. When the acility serves a customer’s on-site load, utility ownership or control is not

necessary.

Best Practices:

In setting policy regarding the ownership o the acility, including the role o the utilities in the alternative energy

marketplace, policies should be tailored and biurcated to whether the acility will be used to supply customer needs

or to support the distribution system. Utility ownership and operation o the alternative energy acility should be

allowed when an emergency exists and the temporary deployment o the acility on a limited basis could restore

reliability and ensure sae operation o the distribution grid. Sucient control and physical assurance is possible

or alternative energy acilities such that utility ownership is not necessary or acilities that are developed in order

to deer distribution upgrades. I an alternative energy acility is sized, located and installed consistent with the

utility’s planning process and provides physical assurance, ownership by the utility is not required in order to provide

distribution system benets.

CHP is a more complex set o responses as CHP is applied or multiple benets. Eciency at the point o use

contributes to economic savings. The utility as owner/operator with industrial and commercial customers is an

evolving question to be answered. A carbon market and carbon displacement will be signicant actors in the

compound answer.


Caliornia:<http://docs.cpuc.ca.gov/published/Final_decision/24136-05.htm>.

“Thorny Details”: <http://ndarticles.com/p/articles/mi_qa3650/is_200103/ai_n8948377/pg_1?tag=artBody;col1>.

Policy and Regulatory Issues and Best Practices Clear Rules o Owners




35

C. Examples o Eective Market Policies

Elements o Successul Policy in the United States

State commissioners received current and accurate statistics and data on the rate issues or renewable energy/

cogeneration and their benets/value to the grid system at the transmission and distribution levels.

Commissioned working groups o interested stakeholders developed consensus-based recommendations or •

rate design.The working groups and/or regulatory commissions analyzed RPS orders and other policies to determine i •

rates needed to be redesigned.

The working groups and/or regulatory commissions monitored utility compliance, the timeliness o new clean•

energy installations, and the impact on consumers or value.

Caliornia Assembly Bill No. 1613

This assembly bill has several eective policies or cogeneration and Combined Heat and Power (CHP). Rates or

CHP will be time-o-use (TOU) to encourage energy conservation with no separate cost-based TOU standby charges

and should encourage the deployment o cogeneration units in areas with transmission constraints. A pay-as-you-

save program allows eligible customers to nance all the upront costs or the purchase and installation o CHPcogeneration units. The customer would repay the costs over time at the dierence between what the customer would

have paid or electricity and the actual savings.

Utilities can receive credits or GHG emissions reductions that result rom the cogeneration unit.

State-owned buildings are required to update their systems to utilize CHP and all new buildings must incorporate

CHP systems whenever it is cost-eective, technologically easible, and environmentally benecial.

Assessment

There is some disagreement over how much the bill increased cogeneration development. Some utilities have ound

that TOU taris negatively impacted investment as their industrial customers tend to use energy during peak timewhen rates are higher. TOU is benecial i the cogeneration acility is paid to sell to the grid or uses nonpeak energy

However, i the acility is a net user during peak times, TOU would not be advisable. In addition, CHP sized to

thermal demand is a dierent application than a combined cycle cogeneration acility. CHP is oten sized to thermal

demand, making it very possible that the acility will not sell electricity back to the grid.

India

Since the 1973 oil crisis, the use o uel oil or power generation in India has been restricted to start-up and low-load

support o coal-red thermal generating units and there are incentives by the Ministry o Power annually or the

reduction o uel oil consumption by generating stations. Also, the permissible “pass through” uel oil consumption

has been progressively brought down by CERC/SERCs over a period o time, thus bringing eciency levels at par

with industry best practices. However, due to a shortage o capacity addition and the unreliability o power supply bythe distribution utilities, most industries go or captive power generation based on uel oil because o the low capital

cost o diesel engines, comparatively short gestation period or construction, and relatively simple operation.

Denmark

Denmark has gone rom being 99% dependent on sources o oreign oil to becoming completely energy sel-

sucient ater 30 years o ocused energy policy, implemented ater the 1973 oil crisis. Denmark has the highest

contribution o new renewable to electricity in the European Union. District heating accounts or 50% o Denmark’s

heating needs and about 20% o total generation is rom wind.

Policy and Regulatory Issues and Best Practices Examples o Eective Market Polici




36

Key policies that were eective in promoting alternative energy sources included the ollowing:

Energy taxes were kept high and not lowered ater ossil uel prices dropped in the 1980s;•

A eed-in tari requiring utilities to buy all power produced rom renewable energy technologies at a rate•

equal to 70 to 85% o the consumer retail price o electricity in a given distribution area;

Environmentally riendly zoning that orced cogeneration units to replace district heating units and •

prohibited the use o oil, diesel, and coal or many generators;

Long-term nancing reduced the risk o building larger projects;•

Open and guaranteed access to the grid where transmission system operators are required to nance,•

construct, interconnect, and operate the transormer stations and transmission and distributioninrastructure or renewable energy technologies;

A general carbon tax on all orms o energy, adding around 1.3 Euro cents per kWh o additional income•

or renewable energy generators; and

Streamlined permitting that made the Danish Energy Authority the “one-stop-shop” or tendering o •

bids or renewable energy construction; approval o pre-investigation o sites, environmental impactassessments, construction, and operation; and licenses to produce electricity.

Key Danish laws include the ollowing:

Law No. 3 o 3 January 1992• which set up a CHP und to support the conversion rom biomass-based district

heating to CHP;

Law No. 837 o 7 October 1992 known as the Development and Demonstration Programme or Renewable•

Energy; and

Energy 21, which set long-term planning and targets (1996).•

United States

The Interstate Renewable Energy Council created the Database o State Incentives or Renewable Energy (DSIRE),

a comprehensive source o inormation on state, local, utility, and ederal incentives that promote renewable

energy and energy eciency. States with particularly good policies include Caliornia, New Jersey, Texas, and

Pennsylvania.

Australia

Australia passed the Renewable Energy (Electricity) Act 2000 to add 9,500 gigawatt hours o renewable energy per

year. The act includes a ramework titled the Mandatory Renewable Energy Target (MRET) scheme to create, trade,

and surrender RECs. The MRET scheme allows renewable energy credits to be created by accredited entities such as

utilities that generate renewable energy and traded to others to meet their RPS targets. Australia has ound that the

cost or MRET compliance per megawatt hour is about 2% higher. Australia has since amended the MRET scheme

in two key areas. RECs must now be created within 12 months o the electricity being generated to give clear market

signals o availability and make pricing more transparent. RECs can also now be surrendered voluntarily even when

not used to meet mandatory targets.

China

China passed the Renewable Energy Law 2006 with the aim o increasing the use o renewable energy up to 10%

by 2020. The law requires transmission companies to provide grid connection to renewable energy acilities and to

purchase power rom these acilities. In addition, it oers nancial incentives such as discounted lending and tax

preerences or renewable energy projects. The tari or renewable energy is set by the National Development and

Reorm Commission at the national level and is spread out among consumers.

Policy and Regulatory Issues and Best Practices Examples o Eective Market Policie




37

European Union

In 1997, the European Commission issued a white paper setting targets to increase the renewable share o energy

production rom 5.3% in 1995 to 12% in 2010. The European Union subsequently issued a Renewables Directive in

2001 with targets or each member state commensurate with their situation and capability. Armed with constitutiona

authority, the targets issued by the European Union are mandatory. These targets are renewable standards or each

country; however, these standards do not obligate any specic producer to achieve them.

Germany

The Renewable Energy Sources Act o 2004 was created to contribute to the increase in the percentage o renewable

energy sources in power supply to at least 12.5% by 2010 and to at least 20% by 2020. The Act outlines procedures

or priority connections to the grid or plants generating electricity rom renewable energy sources and rom mine

gas; the priority purchase, transmission, and payment or such electricity by the grid system operators; and the

nationwide equalization scheme or the quantity o electricity purchased and paid or. The Act also includes eed-in

taris and outlines who pays or various interconnection costs.


Austria: <http://www.erec.org/leadmin/erec_docs/Projcet_Documents/RES2020/AUSTRIA_RES_Policy_Review_April_2008.pd >.

Australia: <http://www.comlaw.gov.au/comlaw/Legislation/ActCompilation1.ns/0/BB02A5216D6E1691CA25748A001EE975?Open

Document>.

Denmark:

<http://www.scitizen.com/stories/Future-Energies/2008/03/Is-the-Danish-Renewable-Energy-Model-Replicable/>

<http://www.agores.org/Publications/EnR/Denmark%20REPolicy2000%20update.pd > <http://www.erec.org/leadmin/erec_docs/

Projcet_Documents/RES2020/DENMARK_RES_Policy_Review_April_2008.pd >.

European Union: <http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2001:283:0033:0040:EN:PDF>.

Germany: <http://www.bmu.de/les/pds/allgemein/application/pd/eeg_en.pd > and

<http://www.wind-works.org/FeedLaws/Germany/GermanEEG2000.pd >.

India: <http://www.bakernet.com/NR/rdonlyres/0251961F-DACD-4C9E-9415-A7A24A28485C/44792/RenewableenergyinIndia.

pd >.

United Kingdom: <http://www.erec.org/leadmin/erec_docs/Projcet_Documents/RES2020/UK_RES_Policy_Review_April_2008.

pd>.

United States:

<http://www.climatechange.ca.gov/publications/legislation/ab_1613_bill_20071014_chaptered.pd > and

< http://www.dsireusa.org/>

.

World Bank RE Toolkit: <http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,contentMD

K:20772244~menuPK:2069918~pagePK:64168445~piPK:64168309~theSitePK:1040428~isCURL:Y,00.html>.

Policy and Regulatory Issues and Best Practices Examples o Eective Market Polici




38

V. Financial Issues and Best Practices

A major issue or all countries, and especially developing countries, is the higher cost o renewable energy and

cogeneration compared to conventional energy sources. It is undeniable that alternative energy sources cost more

than conventional sources as they are currently priced. Conditions placed on the alternative energy acility by the

utility and regulator can exacerbate the dierence in cost. Utilities oten lose revenue and consumers when alternate

energy acilities are built. In order to oset this loss, they place various ees on the acility, such as a ee or exitingthe system.

In general, most alternative energy policies address cost-related barriers in some manner. Many policies address the

requirements or utilities to purchase renewable energy rom power producers and the perceived risks o renewable

energy (technical, nancial, legal).

This section o the handbook ocuses on our areas:

Tari Pricing,A.Acquisition o Alternative Energy,B.

Incentives,C.Reund o Salvage Value, and D.Insurance and Liability Requirements.E.

Financial Issues and Best Practices




39

A. Tari Pricing

Utilities oten add ees and other cost-related barriers to Power Purchase Agreements, increasing the overall cost o

the project or the developer. Many policies attempt to compensate or cost-related barriers to alternative energy

acilities by establishing special pricing rules and by lowering transaction costs.

In this section o Financial Issues and Best Practices, the ollowing tari practices are evaluated:Standby Charges•

Pricing Laws•

Feed-In Taris•

Retail Natural Gas Rates or Wholesale Applications•

Interconnection Charges•

Utility Rates Too Low or Renewable to Compete•

Loss o Utility Revenue•

Retail Buy-back Rates•

Payments or Locational Marginal Pricing•

Cogeneration Deerral Rates•

Remittance or Line Losses•

Exit Fees•

Financial Issues and Best Practices T




40

1. Standby Charges

Issue: Policy makers want to acilitate the deployment o cogeneration, combined heat and power and renewable

energy. Standby charges are levied on renewable and cogeneration projects or the cost o having standby power

accessible when their systems are unavailable to cover the additional costs o generating, transmission, or distribution

capacity required to supply intermittent service.

Utility Perspective: Standby rates should refect the ull cost o service as it does or all other customers and should

include all xed costs or the system capacity to replace the unit’s generation output. System planners cannot

presume an alternative energy acility will operate at any given time, especially during peak load; this uncertainty

must be mitigated by standby rates. Furthermore, the utility has to plan to serve all standby load on a circuit in

the event o a circuit outage and must incur additional distribution inrastructure costs to serve the load. When a

circuit is de-energized, the acility is separated rom the distribution circuit to prevent backeed and the utility must

be able to supply 100% o its power until the acility comes back online. Utilities are also concerned that when an

alternative energy acility does not operate, the entire circuit will have an increase in load. They also argue that the

commission cannot take systemwide benets to all ratepayers into consideration. Until there are multiple acility on a

distribution circuit, it will not be possible to assume diversity values due to the radial design o distribution circuits.

Developer Perspective: Standby rates oten refect neither the reliability o the acility requiring backup nor the

contribution to grid stability through ancillary services which leads to overcharges. As these acilities rarely use

backup, they should not be charged as high a rate as the utility wants. When the utility charges or the worst-case

scenario—all acilities shutting down simultaneously—charges are higher than necessary. Developers can oer

several types o assurance, including physical assurance, which states that i the acility goes down, the customer will

reduce its load accordingly to address the utilities’ concern about whether a acility will be operating during peak

demand. I standby charges are too high, the developer receives an incentive to go o-grid, and the system loses the

benet.

The standby rate should charge only the costs the utility had to incur or the acility and should allow maintenance

and backup power charges to be assessed separately. The standby rates should be a stand-alone tari that refects

diversity actors and the systemwide benet that the acility adds such as deerral o distribution upgrades, extension

o equipment lie, and the decrease o electricity prices in peak periods to send the correct price signals to potential

customers and developers.

Standby service should also be adjusted based on the reliability o the acility to reward units or system support

during peak periods. Utilities should unbundle the components o the distribution system and assign cost

responsibility based on realistic calculations o how oten the customers will need to use the system and the load the

acility serves.

Another option is to make the rates usage-based (demand charge) versus xed (standby charge) since distribution

costs vary with customer usage and usage-based rates encourage demand-response behavior. Standby charges shouldalso have a capacity reservation ee or quantity, rmness, time, and location o use to allow customers to decide how

much they need, when and how rm they need it, and how much it is worth to them.

Standby charges can greatly impact the payback periods or renewable energy, cogeneration and CHP acilities. For

example, an analysis o standby charges in New York State (Energy Nexus Group and Pace Energy Project 2002)

showed that or an 800 kW engine with CHP, the simple economic payback ranged rom less than two years with no

standby charges to six years with the utility’s proposed standby charges.

Financial Issues and Best Practices Ta




41

The most important issue or developers regarding standby rates is that utilities should not be allowed to charge a

departing load charge, standby charge, and acility charge as these are all charges or the same thing.

Regulator Perspective: Balance must be struck between the utility’s need to set aside generation it could otherwise

sell and the developer’s need to keep costs down so the project is economically viable.

Best Practice:

In Caliornia, on-site generators that begin operations in the next two years are exempt rom standby charges or the

next ten years except or diesel-red generators and acilities with capacity over 5 MW. Net energy metering o wind

and solar acilities allows some o them to avoid standby costs.

When a customer gives physical assurance, the customer should not have to pay or acilities or peak-demand-related

costs and should be allowed to opt out o standby service or take only maintenance or nonrm service.

Standby Service Types: Supplemental power should be priced the same as ull requirements power, but backup

power should be priced higher than maintenance power because it is on-demand and has distribution inrastructure

costs associated with it. Maintenance power should be lower as it will be used during times when capacity is

available and thus does not need any inrastructure. Backup reservation capacity should be determined by the

customer but i the customer goes over the amount in any billing period, the amount the customer used is the new

capacity or the next year.

Diversity: Because there are so ew alternative energy acilities on the distribution system currently, the utility

must plan without taking the system-wide benets into account so standby rates should refect this reality to avoid

promoting cogeneration at the expense o other ratepayers.

Standby Rates: Standby rate design should be cost-based and any costs that vary with usage such as peak demand

costs should be refected in a usage-based charge. Utilities can oer nonrm standby rate oers to those customers

who give physical assurance.

Cost Allocation: Standby rates should be based on embedded, not incremental, costs o service. Caliornia,

Massachusetts, and New York exempt standby rates as a policy tool to encourage certain cogeneration acilities. The

exemption is based on size (too small to be cost-eective or separate standby tari) or technology (want to promote

environmentally riendliness). Some states also waive standby charges in constrained areas or in cases where the

customer will guarantee load reduction.


CA Rulemaking 99-10-025. <http://docs.cpuc.ca.gov/Published/Graphics/24842.PDF>.

“Distributed Generation: In a Fair and Competitive Marketplace.” <http://www.gasturbine.org/disgen.pd >.

Massachusetts: <http://apps1.eere.energy.gov/states/news_detail.cm/news_id=8591> and <http://www.nera.com/image/2004_04_21NSTAR_rebuttal_parmesano.pd >.

“The Potential Benets o Distributed Generation and Rate-Related Issues That May Impede Its Expansion.”

<http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd . >. (Pages 130-6).

“Standby Rates or Customers with Distributed Generation.”

<http://74.125.113.132/search?q=cache:Ge2N1SJyB9sJ:www.narucmeetings.org/Presentations/elec_chp_shirley_s06

pd+standby+charges+electricity&hl=en&ct=clnk&cd=6&gl=us&client=reox-a>. (pages 130-6).





42

2. Pricing Laws

In general, pricing laws provide a xed payment or renewable energy that varies based on technology, load, and

location. Germany, Brazil, and China have legislation that combines pricing laws and mandated capacity targets.

Pricing laws are especially eective in developing countries where power markets are oten small and dispersed,

which tends to avor smaller companies and incremental investment. The German Wind Energy Association and the

European Renewable Energies Federation both believe minimum price systems perorm better and are more ecient

than quota systems (such as RPS).

The downside to pricing laws is that the tari is dicult to set as the true costs associated with the project are not

always known, and overpayments have oten occurred with static eed-in taris that increase rates to consumers. In

general, pricing laws have increased predictability and consistency in markets and have been responsible or most

additional capacity in renewable energy. Sawin provides the ollowing comments on the pros and cons o pricing and

quota systems:

ADVANTAGES AND DISADVANTAGES OF PRICING & QUOTA SYSTEMS (SAWIN)

ARGUMENTS IN FAVOUR ARGUMENTS AGAINST

Pricing systems

To date, they have been most successul at developing renewable markets

and domestic industries, and achieving the associated social, economic,

environmental, and security benets.

I taris are not adjusted over time, consumers may pay

unnecessarily high prices or renewable power.

Flexible—can be designed to account or changes in technology and the

marketplace.

Encourage steady growth o small- and medium-scale producers.

Low transaction costs.

Ease o nancing.

Ease o entry.

Can involve restraints on renewable energy trade due to domestic

production requirements.

Quota systems

Promote least-cost projects—cheapest resources used rst, which brings

down costs early on.

High risks and low rewards or equipment industry and project

developers, which slows innovation.

Provide certainty regarding uture market share or renewable (oten not

true in practice).

Price fuctuation in “thin” markets, creating instability and gaming.

Perceived as being more compatible with open or traditional power

markets.

Tend to avor large, centralized merchant plants and not suited or small

investors.

More likely to ully integrate renewable into electricity supply

inrastructure.

Concentrate development in areas with best resources, causing

possible opposition to projects and missing many o the benets

associated with renewable energy (jobs, economic development in

rural areas, reductions in local pollution).

Targets can set upper limits or development—there are no high

prots to serve as incentives to install more than the mandated level

because protability exists only within the quota.

Tends to create cycles o stop-and-go development.

Source: National Policy Instruments: Policy Lessons rom the Advancement and Diusion o Renewable Energy Technologies around the World.http://www.renewables2004.de/pd/tbp/TBP03-policies.pd





43

Assessment

The xed price over time means that it is dicult to pass on the benets o increased technological eciency to

consumers. Instead, benets accrue at the level o the generating plant owner, who may be able to access high rates

o return. One possible solution is to lower the tari rate over time in a transparent manner to minimize investor

uncertainty; however, there is no guarantee that reductions will match the actual improvements in the technology.

Though tari mechanisms x the price available to renewable energy generators, the level o capacity is subject

to the market; there is no way o predicting how many investors will build generation due to the tari price. This

means it is not possible to predict the overall costs o the mechanism in either the short or long term, which can be

unattractive to governments and consumers/taxpayers.

Distribution network operators are compelled to accept all electricity rom renewable generators, regardless o

the demand or electricity at the time o generation. This can lead to network balancing issues, and these tend to

increase with the level o intermittent generation on the network. This leads to increasing potential or technological

problems and to increased costs or the network operator.

Compelling network operators to accept all renewable generation means electricity rom renewables is always the

rst to be bought. This eectively intereres with any open market or general electricity generation, and aects the

ability o “traditional” generators to compete in the electricity sector which can be problematic where governments

are committed to maximizing competition in markets.

Price-setting policies should include the ollowing:

Incremental adjustments built into the law that allow or periodic adjustments o the premium to eliminate•

excess rent payments by the state to renewable energy/cogeneration suppliers,

Taris based on technology and location that are high enough to cover costs and encourage development, are•

provided or all developers including the utility, and are or a long enough period o time to ensure rates o

return,

Costs shared equally across the region or country, and •

The elimination o barriers to grid connection.•


“Mandated Market Policies.” <http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,conten

MDK:20772244~menuPK:2069918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html#Requirements_or_successul_

policy>.

Sawin, J. <http://www.renewables2004.de/pd/tbp/TBP03-policies.pd >.





44

3. Feed-In Taris

Issue: Feed-in taris are a xed price or every unit o electricity produced by a renewable source that is usually

above the tari rate or conventional sources. They oer investors access to the grid and a xed minimum price or

electricity generated or a specied number o years, which oten makes the project more viable. Either the tari can

be paid rom a subsidy or the utility can pass the additional cost on to consumers. Investors have a reduced risk with

eed-in taris as they are guaranteed a price or a xed time at an economical rate. Furthermore, i a government

wishes to support a new technology it can require a tari specic to that technology and thus encourage it to move

closer to market. The balance o evidence suggests that this provides long-term benets in terms o developing

more competitive technologies. Tari mechanisms have been widely applied in Europe, and have enjoyed particular

success in Germany, Denmark , and Spain. Their employment has led to signicant increases in renewable

electricity-generating capacity, particularly o wind energy.

Some have argued that eed-in taris might have a greater impact i customers receive TOU rates or energy sold

to the grid. However, TOU may not be desirable i customers have to pay TOU or energy bought rom the utility.

The success in attracting investment in renewable energy/cogeneration depends on limits set on participation, the

price paid, grid connection standards, and enorcement mechanisms; net metering alone cannot work without other

nancial incentives.

Utility Perspective: It is impossible to plan generation when neither the amount nor the timing o the alternative

energy acility’s excess electricity is known in advance.

Developer Perspective: Allowing the alternative energy acility to sell power to the grid greatly changes the

economic viability o the project and oten makes it possible.

Regulator Perspective: The price or renewables may be set too high and the cost to the consumer will be higher

than it would have been under a more market-based incentive. However, the market incentives are not always

sensitive to the need or open access and low transaction costs.

Best Practices:

Punjab’s New & Renewable Sources o Energy (NRSE) Policy 2006 clearly outlines tari prices or each type o

generation rom renewable energy and cogeneration sources with annual escalations or ve years.

Ater the declaration o the Generation Based Incentives (GBI) by the MNRE (see section “Other Incentives”), many

state regulatory commissions declared eed-in taris or grid-connected solar power projects. The present status is

given below:





45

Solar Photovoltaic Projects

Particulars

Solar PV Depreciation

beneft under

IT Act 1961Incentive/Tari or Plant

commissioned up to Dec 2009

Incentive/Tari or Plant

commissioned ater Dec 09

MNRE Incentives

(GBI)

Max Rs 12 / kWh

(GBI + tari capped at Rs 15/kWh)

Max Rs 11.40 / kWh Not allowed

RERC (Rajasthan) Rs 15.78 / kWh (Rs 3.78 /kWh – wind)

Rs 15.18 / kWh Not allowed

HERC

(Haryana)

Rs 15.96 / kWh (cost plus basis) Rs 15.16 / kWh Not allowed

WBERC

(West Bengal)

Equivalent to highest tari

oered rom among the various

RE in WB (Rs 5/kWh – biogas

power)

GBI will be reduced by 5% Not allowed

WBERC;

Projects not under

MNRE Scheme

Rs 11/kWh Rs 10/kWh Allowed

MERC

(Maharashtra)

Rs 3.00/kWh (without GBI) GBI will be reduced by 5% Allowed

TNERC

(Tamil Nadu)

Rs 3.15/kWh (without GBI)



RE in TN (biomass)



RE in TN (biomass) with 5%

reduction

Not allowed

Solar Thermal Projects

Particulars

Solar Thermal Depreciation

beneft under

IT Act 1961Incentive or Plant

commissioned up to Dec 09

Incentive or Plant

commissioned ater Dec 09

MNRE Incentives Max Rs 10 / kWh

(GBI + Tari capped at Rs13/Kwh)

Max Rs 9.50/kWh Not allowed

RERC Rs 13.78/kWh Rs 13.28/kWh Not allowed

HERC Not Declared Not Declared Not allowed

WBERC Not Declared Not Declared Not allowed

MERC (Drat order) Rs 3.00/kWh GBI will be reduced by 5% Not allowed

TNERC Rs 3.15/kWh



RE in TN (biomass)

GBI will be reduced by 5% Not allowed

Notes. GBI = generation-based incentive; IT Act = Income Tax Act; kWh = kilowatt hour; MNRE = Ministry o New and Renewable Energy; RE

= renewable energy; RERC = Rajasthan Electricity Regulatory Commission; Rs = Rupees; TN = Tamil Nadu; TNERC = Tamil Nadu Electricity

Regulatory Commission; WBERC = West Bengal Electricity Regulatory Commission.

Source. Charts courtesy o the World Institute o Sustainable Energy.





46


“Identiying Optimal Legal Frameworks or Renewable Energy in India”: <http://www.wisein.org/pd/Backer-and-Meckanzy.pd >.

[sic]

India: <http://www.pserc.nic.in/pages/NRSE_orders.html> and <http://www.mnes.nic.in>.

“Mandated Market Policies”: <http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,conten

tMDK:20772244~isCURL:Y~menuPK:2069918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html>.

“National Policy Instruments”: <http://www.renewables2004.de/pd/tbp/TBP03-policies.pd >.

“Renewable Energy Policies and Barriers”: <http://www.martinot.ino/Beck_Martinot_AP.pd >.

United States

<http://www.boell.org/docs/Feed-in%20Taris%20and%20Renewable%20Energy%20in%20the%20USA%20-%20a%20Policy%20

Update.pd >.





47

4. Retail Natural Gas Rates or Wholesale Applications

Issue: Current gas taris may not be designed or cogeneration uses and the existing high taris and conditions may

be a barrier to cogeneration development. As an example, a developer o high-load actor baseload cogeneration

may need the option o a rm high-load actor rate. A ew key issues surrounding gas rates include separate

cogeneration service classication, customer, demand, and energy charges; rozen rates; separate metering; and

system reinorcement cost.

Utility Perspective: Natural gas rates or cogeneration acilities or wholesale applications should not be

dierent rom those or other users. However, cogeneration acilities must have a separate meter to have accurate

measurement and monitoring o the cogeneration acility’s usage.

Developer Perspective: The dierences between cogeneration acilities and other acilities are not addressed

in existing natural gas rates. Current gas rates take neither size nor load actor into account, nor do they refect

cogeneration’s contribution to system costs.

Regulator Perspective (SERC): Retail natural gas rates should encourage cogeneration development.

Separate Cogeneration Service Classication

Issue: Utilities believe current rates that oer lower charges or larger volume customers are ideal or cogeneration

acilities but developers believe there should be dierent classications so that the rates address issues such as size

and load actor.

Customer, Demand, and Energy Charges

Issue: The utility and developer disagree over whether customer, demand, and energy charges should be separate.

Freezing Rates

Issue: The disagreement between utilities and developers over reezing rates is centered on the issue o the

fuctuation o gas prices, which might lead to a subsidy and the need or xed variables whenever possible to create

certainty or developers.

Separate Metering

Issue: Utilities and developers disagree over whether separate metering is necessary to have accurate measurement

and monitoring o cogeneration usage.

System Reinorcement Costs (Utility Grid)

Issue: Utilities insist the developer should pay or any system reinorcement, but developers believe small customers

should not pay or more than 100 eet rom a main line.

Best Practices: New York states the ollowing:

Utilities should oer an option with at least a 50% load actor to cogeneration customers as an incentive, and

the incentive must be established as a ceiling or at least three years to give rm market signals or cogeneration

development. However, to oset potential utility losses, utilities can deer any net lost revenues or later recovery.





48

As there are dierent rates or distributed generation and regular consumption, a separate meter is required or

commercial or industrial cogeneration acilities to distinguish the portion o the customer’s consumption priced at

the distributed generation rate rom the usage priced at the non-distributed generation rate.

Cogeneration customers should pay or any system reinorcements to the electricity grid needed to serve them and

should take the expected revenues rom the cogeneration unit into account when determining the reinorcement costs.

Cogeneration customers can receive rm or interruptible service and are treated in the same manner as any other rm

or interruptible customer.


Connecticut Natural Gas Corporation. <http://www2.cngcorp.com/marketer_services/RATE_DG.pd >.

New Jersey Natural Gas Company. <http://www.state.nj.us/bpu/pd/boardorders/21134.pd >.

New York Public Service Commission. <http://www3.dps.state.ny.us/pscweb/WebFileRoom.ns/Web/BD7AAB455FCB712685256DF

10075671F/$File/doc13154.pd?OpenElement>.

“The Potential Benets o Distributed Generation and Rate-Related Issues That May Impede its Expansion.”

http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd . (pages 137-9).





49

5. Interconnection Charges

Issue: Utilities charge a cost-based ee or any acility to connect to the grid. In addition, they might charge or the

cost o a line to connect to the grid, system upgrades, and separate meters or the acilities.

Utility Perspective: Renewable energy and cogeneration acilities must pay to receive permission to connect and

operate parallel to the grid as it is not right to orce other consumers not beneting rom the acility to pay.

Developer Perspective: Renewable energy and cogeneration acilities are oten not located close to the grid and the

cost o connecting would be prohibitive. As the costs are higher or renewable energy generators due to lower plant

load actors and the distance rom the grid, interconnection charges can be a signicant deterrent. Furthermore,

system upgrades might benet other customers as well and there is no clear methodology or determining the

percentage o the total cost each customer should pay. The utility also keeps the upgrades so it is not reasonable to

orce customers to pay or them.

Regulator Perspective: Policies should encourage renewable energy and cogeneration development while not

adding to the cost or other consumers.

Best Practice:

In Germany, the renewable energy/cogeneration developer pays or grid-connection costs and metering; the utility

pays or any system upgrades.

Similar practices are ollowed in Gujarat, Maharashtra and Tamil Nadu. Gujarat’s recent tari order or

demonstration solar power plants stated the ollowing regarding interconnection costs:

6.3 Evacuation Facilities:

a. The interacing line o appropriate capacity and voltage as per the CEA (Technical

Standard or connectivity to the grid) Regulations, 2007 shall be provided by the

STU/ Distribution Licensee at their cost. The intending generator shall apply to the

STU/ Distribution Licensee concerned well in advance.

b. The cost o switch gear, metering and protection arrangement at generator end shall

have to be borne by the owner o solar generators. (Page 4).


“Report on APP-REDGTF project on renewable energy in India.” Prepared by Baker & McKenzie and World Institute o Sustainable

Energy. April 2008 (page 33).

Gujarat:<http://www.gercin.org/docs/Orders/Other%20orders/Year%202009/Order%201%20o%202009.pd >.





50

6. Utility Rates Too Low or Renewable to Compete

Issue: Conventional energy sources have historically enjoyed very low rates, which are a barrier to renewable energy

or cogeneration projects, which tend to be more expensive.

Utility Perspective: Ratepayers and shareholders o the utility do not want to buy more expensive power rom

renewable energy or cogeneration when cheaper power is available.

Developer Perspective: Tari rates or conventional energy sources do not include the cost o pollution, uel source

extraction, or societal impacts, which leads to an articially lower rate.

Regulator Perspective: It is important to promote renewable energy and cogeneration but prices must be kept low

or consumers.

Best Practices:

I environmental externalities and diversication values are used instead o discounted cash-fow accounting,

renewable energy is more economical. Traditional nancial analysis using discounted cash-fow undervalues uture

uel price risks and ignores environmental and health costs o conventional energy sources. When uel prices and

social impacts are assessed, renewable energy is close to, or competitive with, conventional energy sources. At this

time, this option is theoretical.

Another option is to use a mean variance portolio analysis that includes the costs and economic risks o all

technologies and uel sources in a portolio and computes the expected cost o electricity and risks o that cost or the

entire portolio. The portolio approach accounts or construction and operating costs and uel risks, and oten shows

that overall system generation costs decrease with the addition o renewable acilities.

Subsidies articially lower the cost o conventional energy. Removing these subsidies would lead to consumers

paying the true cost o energy and would narrow the gap between the cost o renewable and cogeneration and

conventional energy.


“Renewable Energy Policies and Barriers.” <http://www.martinot.ino/Beck_Martinot_AP.pd >.

World Bank RE Toolkit:

<http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,contentMDK:20772234~isCURL:Y

~menuPK:2069918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html>.

<http://www.eia.doe.gov/cnea/electricity/external/external.pd >





51

7. Loss o Utility Revenue

Issue: Cogeneration acilities can represent a potential loss o revenue or the utility as the large customer uses its

own generation and thus reduces its purchase rom the utility. The perception o a potential loss o revenue oten

serves as a barrier to cogeneration and CHP acilities.

Utility Perspective: The issue o loss o utility revenue is especially problematic in India where large industrial and

commercial customers—those most likely to build cogeneration acilities—subsidize residential customers. Losing

these customers will result in lower revenue or the utility and will orce them to raise rates on other consumers,

especially residential. In addition, there may also be losses related to transmission lines and other expenditures and

system upgrades the utility paid or to connect the customer to the grid.

Developer Perspective: The utility may lose some revenue; however, cogeneration and CHP acilities sized to

thermal load may not provide all the electricity needed, so some will still be purchased rom the utility.

Regulator Perspective: Encouraging cogeneration development is important as it could decrease the need or

additional transmission lines and thus utility costs. However, the regulator has a responsibility to ensure low rates or

the consumer and the economic health o the utility.

Best Practices:

The utility can build, own, operate, dispatch, and maintain the customer/load sited cogeneration system and •

bill the customer or the benecial value rom the acility, passing through uel costs and capital recovery. The

charge is not rate based. In this way, the utility makes its money back rom the system and keeps its customer.

The utility can acknowledge the systems benets o customer sited systems through rate designs.

Revenue-based perormance-based regulation (PBR) can remove the disincentive or customer-side distributed•

resources. The utility’s revenue and prots are tied to customer growth instead o sales (price-based PBR).

Revenue-based PBRs have been adopted in Australia, the United Kingdom, and several U.S. states.

Distributed resources credits are a system o geographically de-averaged credits that give consumers better •

price signals to install alternative energy acilities in areas with high transmission and distribution costs. Theutility issues a nancial credit or acilities in a certain location based on the distribution cost savings rom

deerring distribution upgrades.

Distributed Resources Development Zones are designated areas with high transmission and distribution costs•

that are eligible or economic incentives or projects built there.

Symmetrical pricing fexibility orces the utility to increase prices in areas with high transmission and •

distribution costs i it lowers prices to discourage projects that are not cost-eective.

Regulators can create a tari or distribution companies that does not link its revenues to volumetric charges.•

Developers can locate the alternative energy acility on the utility side o the meter.•

Sources and For More Inormation:“Distributed Generation and Cogeneration Policy Roadmap or Caliornia, March 2007.” <http://www.energy.ca.gov/2007_

energypolicy/documents/2007-05-07_workshop/public_comments/ELECTRICAL_POWER_RESEARCH_INSTITUTE_2007-05-21.

PDF>.

“Prots and Progress Through Distributive Resources.” <http://www.raponline.org/showpd.asp?PDF_URL=Pubs/General/

ProtsandProgressdr.pd >.





52


<http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd .> ( pages 129-30).

“Quantitative Assessment o Distributed Energy Resource Benets.” <http://www.eere.energy.gov/de/pds/quantitative_benets.pd >.





53

8. Retail Buy-Back Rates

Issue: Renewable energy and cogeneration acilities may have power to sell back to the grid. Receiving payment or

this power can be a key component o the project’s economic viability.

Utility Perspective: Power rom renewable energy and cogeneration acilities is usually not rm power and creates

scheduling problems when it is not known how much power the utility will receive rom these acilities.

Developer Perspective: The revenue rom power sold back to the grid can be a critical component o the project’s

economic viability and should be allowed.

Regulator Perspective: The competitive market includes the value o both the energy and the transmission service.

Cogeneration in particular will oten be less costly than purchasing power in the spot market and thus should be

encouraged.

India: Many Indian states currently have buy-back rates.

Best Practices:

In an open market, the buy-back rates are at the utility’s avoided cost or the next dispatchable generating unit.

For example, i a utility would be required to purchase power at 12 Rs in the spot market during peak, then the

cogeneration or renewable energy acility should receive 12 Rs during that time.

States can direct resources to their most highly valued uses to more airly compensate alternative energy acilities or

the system benets it can provide.

Net metering may actually be more benecial to the developer than buy-back rates, depending on specic

circumstances.





54

Indian Renewable Power Policies-Programme-Wise

Buy-back rate: Rs/unit

S.No. State / UT Wind Power Small Hydro Power Biomass Power

1. Andhra Pradesh 3.37

xed or 5 yrs

2.69 (2004–05) 2.63 (2005–06)

Esc @ 1% or 5 yrs

2. Arunachal Pradesh — — —

3. Assam — — —

4. Bihar — — — Chhattisgarh — — 2.71 (05–06)

5. Gujarat 3.37

xed or 20 yrs

— 3.00

No escalation.

6. Haryana - 2.25 (1994–95) 4.00 – biomass

3.74 – cogen.

Esc. @ 2% (base 2007-08)

7. Himachal Pradesh — 2.50 —

8. J & K — — —

9. Jharkhand — — —

10. Karnataka 3.40

xed or 10 yrs

2.90 2.74 – cogen. 2.88 – biomass

Esc @1% or 10 yrs(base 2004-05)

11. Kerala 3.14

xed or 20 yrs

— 2.80 (2000-01)

Esc @ 5% or 5 yrs

12. Madhya Pradesh 3.97–3.30 2.25 3.33–5.14

Esc @ 0.03–0.08 or 20 yrs

13. Maharashtra 3.50

Esc @ 0.15 per yr

2.25

(1999–2000)

3.05 – cogen.3.04–3.43 – biomass Esc @ 1% or 13 yrs

14. Manipur — — —

15. Meghalaya — — —

16. Mizoram — — —

17. Nagaland — — — 18. Orissa — — —

19. Punjab — 2.73 (1998–99) 3.01 (2001–02) esc @ 3%

or 5 yrs limited to 3.48

20. Rajasthan 2.91

[email protected] or 10 yrs

2.75 (1998–99) 3.60–3.96 water- and air-cooled

21. Sikkim — — -

22. Tamil Nadu 2.70 (xed) — 2.73 (2000–01)*

Esc @ 5% or 9 yrs

23. Tripura — — —

24. Uttar Pradesh — 2.25 2.86 – existing plants 2.98 – new plants

Esc @ 0.04/yr

*Rs 2.48 per unit at 5% escalation (esc) or 9 years (2000-01) or o-season power generation using coal/lignite (subject to ceiling

o 90% o high-tension tari).

Source: http://mnes.nic.in/policy/policy-programme-wise.htm





55


Australia: <http://www.mce.gov.au/assets/documents/mceinternet/CenDEPCSIRO20060405135055.pd >.

International Energy Agency: <http://www.iea-pvps.org/products/download/rep1_02.pd >.


<http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd > ( pages 141-3).

“Q&A on Higher Buyback Rates or Electricity rom Renewables.” <http://renewmediacenter.blogspot.com/2008/12/buyback-rates.

html>.

U.S. Environmental Protection Agency: <http://www.epa.gov/cleanenergy/documents/gta/guide_action_ull.pd > and <http://www.

epa.gov/cleanenergy/energy-programs/state-and-local/state-best-practices.html>.





56

9. Payments or Locational Marginal Pricing

Issue: With locational marginal pricing (LMP), some o the nancial benets o cogeneration and combined heat

and power (CHP), such as reduced generation losses and lower line losses, are included in the tari design. Marginal

pricing is the idea that the market price o any commodity should be the cost o bringing the last unit o that

commodity—the one that balances supply and demand—to market. In electricity, LMP recognizes that this marginal

price may vary at dierent times and locations based on transmission congestion.

Electric grid congestion develops when one or more restrictions on the transmission system prevent the economic,

or least expensive, supply o energy rom serving the demand. For example, transmission lines may not have enough

capacity to carry all the electricity demand required to meet the demand at a specic location. This is called a

“transmission constraint.” LMP includes the cost o supplying the more expensive electricity in those locations, thus

providing a precise, market-based method or pricing energy that includes the “cost o congestion.”

LMP provides market participants with a clear and accurate signal o the price o electricity at every location on

the grid. These prices, in turn, reveal the value o locating new generation, upgrading transmission, or reducing

electricity consumption—elements needed in a well-unctioning market to alleviate constraints, increase competition

and improve the systems’ ability to meet power demand. Many acilities request a reduction in their tari allowing

or the benet o on-site generation.

India is not currently considering Locational Marginal Pricing; however, it is a best practice that encourages the

development o distributed generation, cogeneration and combined heat and power so it has been included in this

handbook or uture reerence.

Utility Perspective: LMP would give incentive to uture siting o generation near load and thus may reduce

congestion. However, applying LMP to existing acilities could increase the cost to consumers.

Developer Perspective: On-site generation has many system benets and may reduce generation and line losses

but utilities may pay wholesale rates only or the power that does not capture the true “locational” value o the

generation. These integrated resource portolio’s benets should be part o the tari i there is no LMP.

Regulator Perspective: LMP highlights transmission congestion and incentivizes distributed generation, combined

heat and power, and cogeneration in congested areas, thereby helping the grid.

Best Practices:

One way to incentivize locating alternative energy acilities near the load is ull net metering credits minus

shrinkage. Every transormer the cogeneration acility passes through causes a 2% loss so the utility could assess

a 2% shrinkage ee or each transormer. The acility would receive 100% or net metering; i the acility passed

through two transormers, it would receive 96%.

Central Vermont Public Service Corporation (CVPS) oers a production incentive to armers who own anaerobic

digesters to generate electricity. CVPS purchases electricity and renewable energy credits at 95% o the LMP o

generation published by ISO New England (roughly avoided cost), plus an additional $0.04 per kWh.

Some argue that the ability or cogeneration and CHP to participate in the wholesale market will solve the problem

o a lack o LMP pricing. India’s energy market is over a year old and growing steadily. In time, this might be a

viable solution in India.





57


DSIRE database. “Vermont - CVPS - Biomass Electricity Production Incentive:” <http://www.dsireusa.org/library/includes/

summtabsrch.cm?Incentive_Code=VT05F&Back=ntab&state=VT&type=Production&CurrentPageID=7&EE=1&RE=1>.

“Nodal Pricing or Distribution Networks.” http://www.cba.uf.edu/purc/purcdocs/papers/0520_Sotkiewicz_Nodal_Pricing_or.pd .


<http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd > (page 143).

“Renewable Energy Policies and Barriers.” <http://www.martinot.ino/Beck_Martinot_AP.pd >.





58

10. Cogeneration Deerral Rates

Issue: Some argue that excess capacity can increase retail rates, but deerral riders, which allow utilities to oer

lower rates to customers who might otherwise turn to cogeneration, distributed generation or combined heat and

power, may optimize existing generating capacity.

Utility Perspective: Traditional utilities oten deend their cogeneration deerral rates—giving a discount to an

industrial customer i the customer promises not to build cogeneration—on the basis o preserving revenues and load

so that remaining customers do not carry a greater portion o the xed costs. They also argue that cogeneration in

many cases is not cost-eective when compared to the utility’s marginal cost o supply and appears to be less only

because retail prices are above the marginal cost.

Developer Perspective: Oering a lower rate to keep the customer is a barrier to alternative energy development

and discounts its many benets to the grid and environment.

Regulator Perspective: The major concern with oering lower rates to one customer is whether other customers’

rates increase to cover the dierence. Regulators must determine whether there are any, or a sucient level o, net

system benets to justiy the discounted rates.

Best Practices:

Deployment o cogeneration should be considered in the context o least-cost provision o service, and the revenue

question should be dealt with separately.

Regulators may allow pricing fexibility in low-cost areas o the distribution system only i the utility increases

rates in high-cost areas. In this way, high-cost areas due to transmission constraints receive incentives to develop

distributed generation, combined heat and power or cogeneration.



<http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd > ( page 145).

“Prots and Progress Through Distributed Resources.” <http://www.raponline.org/Pubs/General/ProtsandProgressdr.pd >.

“Why cogeneration developers should support cogeneration deerral riders” by Scott Spiewak (April 1, 1987).





59

11. Remittance or Line Losses

Issue: Cogeneration acilities can reduce the utility’s line losses as they are generating and using energy on-site.

Developers would like tari rates to refect this decreased cost or the utility.

Utility Perspective: Determining the extent a acility reduced line losses is extremely dicult and the reduction is

not signicant enough to warrant a reduction in the tari or cogeneration acilities. As line losses are location- and

time-specic, the cogeneration acility is just as likely to increase line losses as reduce them so a tari reduction is

not justied. Net metering will show i the acility is reducing the losses.

Developer Perspective: The cogeneration acility’s tari should refect the decreased line losses by the utility to

more accurately refect the true costs and benets o cogeneration to the system.

Regulator Perspective: Taris should refect the true cost o energy and incentivize the deployment o renewable

energy and cogeneration. Adjusting the tari to take into account reduced line losses—when conrmed—would

achieve these goals.

Best Practices:

For retail situations, regulators could incorporate savings in line losses provided by cogeneration into the regulated

prices to be paid or surplus output. For wholesale situations and regional markets, expansion to incremental loss

calculations would provide the correct price signal to distributed generators with surplus output to sell.

Several Independent System Operators/Regional Transmission Operators (ISO/RTO) in the U.S., specically MISO,

PJM and the NYISO, use an incremental-losses method that is based on calculating the cost or the ISO or RTO to

provide the last MWh o loss supply. The loss calculation is used within the Locational Marginal Pricing (LMP)

process to give both incremental and locational value o where losses are supplied and used. The ISO or RTO then

dispatches generation to provide the losses, load customers pay incremental costs or the losses, and generators are

paid or the incremental losses.



http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd . Page 145-146.

FERC: http://www.erc.gov/eventcalendar/Files/20080505161320-ER08-358-000.pd

“Nodal Pricing or Distribution Networks: Ecient Pricing or Eciency Enhancing Distributed Generation.” http://www.cba.uf.

edu/purc/purcdocs/papers/0520_Sotkiewicz_Nodal_Pricing_or.pd .





60

12. Exit Fees

Issue: Many utilities assess exit ees on departing load to recover the xed costs associated with the stranded asset

the load no longer uses. Utilities argue that without these exit ees, other customers would have to pay or these

costs. However, many actors can aect utility rates and revenue and it is not necessarily true that a reduction in load

will result in cost increases.

Utility Perspective: The utility built its distribution network and contracted or generation based on the load.

Large-load customers (1 MW or larger) are those most likely to build cogeneration acilities, and their reduction o

load on the system will increase the stranded asset, orcing either the remaining customers to pay more or the utility

to take a loss.

Developer Perspective: Exit ees can be prohibitive, especially when it is a small cogeneration acility. While it

is understood the utility will not recover all its stranded assets when a customer leaves its service, the utility should

receive additional gains in the orm o system reliability, a decrease in transmission congestion, and a reduction in

system expansion that should make up or these losses.

Regulator Perspective: Renewable energy and cogeneration projects must be encouraged as RPS orders must be

met. At the same time, it is the regulator’s responsibility to keep rates low, air, and reasonable or all consumers.

Best Practices:

Regulatory commissions should include a requirement o proo that an asset is actually being stranded, resulting in

higher costs to the utility.

India

Regulators are required to provide these charges in the orm o an “additional surcharge.” However, in view o the

large capacity shortages, most regulators have not added this charge.

United States

Some U.S. states have exempted CHP and renewable energy projects rom the exit ees in recognition o their

positive impact on grid congestion and reliability enhancement benets.

Caliornia: Systems smaller than 1 MW that are net metered are exempt rom exit ees, as are zero-emitting, highly

ecient (>42.5%) systems.

Illinois: Utilities could assess exit ees but only until December 31, 2006. However, a departing customer’s acility

must be sized to meet its thermal and electrical needs and must use all the energy produced.

Massachusetts: Exit ees can be assessed or acilities over 60 kW but renewable energy and uel cell technologies

are exempt. Utilities cannot charge exit ees unless there is a “signicant” revenue loss, but “signicant” is not

dened, which has led to problems.


“Clean Energy Environment–Guide to Action.” <http://www.epa.gov/cleanenergy/documents/gta/guide_action_ull.pd >.


<http://www.oe.energy.gov/DocumentsandMedia/1817_Study_Sep_07.pd > ( pages 136-7).





61

B. Acquiring Renewable Energy and Cogeneration Capacity

Quantity-setting policies (RPS orders and competitive bidding) promote the least-cost projects, provide certainty

or market share or renewable energy, are more likely to integrate renewable energy into the grid, and lead to

development in areas with the greatest resources. However, the World Bank states that policy makers should take care

in drating policies to ensure they do not avor large plants over small investors; produce high risks and low rewards

or developers and equipment manuacturers, which slows innovation; or include targets that set the upper limit thusdiscouraging urther development beyond the target.

Best Practices or Quantity-Setting Policies:

Laws apply to a large segment o the market.•

Set dierent bands or dierent technologies.•

Contracts are long-term to reduce uncertainty and include specic purchase obligations and end dates.•

Penalties are in place or noncompliance and enorcement.•

No time gap exists between quotas or competitive bidding.•

Sources and For More Inormation:“Identiying optimal legal rameworks or renewable energy in India.”

<http://www.wisein.org/pd/Backer-and-Meckanzy.pd >.

“National Policy Instruments: Policy Lessons or the Advancement & Diusion o Renewable Energy Technologies Around the

World.” <http://www.renewables2004.de/pd/tbp/TBP03-policies.pd >.


<http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,contentMDK:20772244~isCURL:Y

~menuPK:2069939~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html>.

Financial Issues and Best Practices Acquirin




62

1. Competitive Bidding

Issue: Competitive solicitations speciy a target or share o generation and allow developers to submit bids.

Utility Perspective: The main concern with competitive bidding is that projects will be underbid and thus never

built, aecting the utility’s ability to serve load. Alternatively, all the bids could be higher than expected, leading to

higher rates passed on to consumers.

Developer Perspective: Competitive bidding can lead to bids below cost to obtain contracts that are oten not

nancially easible. These low bids hurt developers with more reasonable costs; reasonable bidders ear making

realistic bids and losing to low-quality bidders.

Regulator Perspective: Competitive bidding can be a valuable tool in increasing renewable energy development,

but policies must be in place to ensure the projects are built according to their contract.

India

Competitive bidding has not been very successul in India to date even or conventional power projects and some

believe it is too early to introduce it. In India competitive bidding or conventional power projects (coal, gas) is not

encouraging and did not resulted in the anticipated capacity addition. Since 1992, only a ew thermal-gas-based

power projects have been commissioned via competitive bidding. However, competitive bidding or renewables has

been suggested in Andhra Pradesh by the Andhra Pradesh Electricity Regulatory Commission.

Best Practice:

Caliornia uses an incentive program based on competitive bidding that uses a system benet charge. It also has

production-based incentives that can be paid over a ve-year period at most and has a cap o 1.5 cents per kWh.

Projects that come online early receive a 10% bonus on top o their incentive bid to be no more than 1.5 cents total

and also receive 10% reductions in the incentive payment i there are project delays. I the project is delayed one

year, the incentive payment is reduced 50% and i it is over a year, there is no incentive payment.

Competitive bidding has been more successul in Ireland and Caliornia because they apply very stringent criteria

or prequaliying bidders, ensuring the quality o bidders is at a similar level and ensuring the bidders they can make

more realistic bids and not lose to a low-quality bidder. The bid process is also designed so that the tari is set at the

second lowest bid price.

Competitive bidding is practiced in Canada, China, and the United Kingdom.


“R.E. Policy Revvs Up Across the Globe.” <http://www.wisein.org/pd/GEPDF/GE-July-Aug-08.pd >.

World Bank RE Toolkit:<http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,contentMDK:20772244~isCURL:Y

~menuPK:2069939~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html#Competitive_Bidding>.





63

2. Renewable Portolio Standards

Issue: RPS orders are a policy measure that mandates a percentage o total generation comes rom renewable energy

sources.

Utility Perspective: Some utilities recognize the need to reduce emissions but do not eel a mandatory RPS is the

answer as many regions do not have adequate renewable resources. In addition, renewable energy is more expensive

than conventional energy, increasing the cost to consumers. Incentives or the development o renewable energy

projects when economically and technically viable, combined with programs to assist in the mitigation o emissions

rom conventional plants, would be a better approach.

Developer Perspective: RPS orders are critical or the development o renewable energy and cogeneration projects.

The RPS also provides market stability to all participants by reducing regulatory risk or generators and utilities and

improves the ability to obtain long-term nance.

Regulator Perspective: RPS orders are a key method to increasing the deployment o cleaner energy technologies,

but any RPS must take into account the availability o renewable sources in the area and the impact o renewable

energy on the retail tari.

India

As o December 2008, 17 o India’s 28 states had RPS. The RPS minimum percentages in these states range

rom 1% in Delhi to 10% in Tamil Nadu. Most states specied these percentages or three years although some

specied percentages or only one year or as many as six years. Karnataka and Rajasthan also placed an upper cap

on the amount o renewable energy (10% in Karnataka); however, on January 23, 2008, the Karnataka Electricity

Regulatory Commission removed the upper ceiling on the procurement o renewable energy.

Renewable Portolio Standards in India by State

State 2007-08 2008-09 2009-10

Andhra Pradesh 5% 5% NA

Chhattisgarh 10% 10% 10%

Gujarat 1% 2% 10%

Haryana 3% 5% 10%

Himachal Pradesh 20% 20% 20%

Karnataka 7-10% 7-10% 7-10%

Kerala 5% 5% 5%

Madhya Pradesh 10% 10% 10%

Maharashtra 4% 5% 6%

Orissa 3% 3.5% 4%

Punjab 1% 1% 2%

Rajasthan 4% 55 6%

Tamil Nadu 10% 10% NA

Uttar Pradesh 7.5% 7.5% 7.5%

Uttaranchal 5% 5% 8%

West Bengal NA 2-4.8% 4-6.8%







65

penalties have been levied by the state regulatory commissions in Maharashtra, Rajasthan, and Gujarat. In

Maharashtra, the Maharashtra Energy Development Agency has issued penalty notices to the distribution licensees

who do not meet the RPS obligation in 2007–08. Penalties levied on utilities or noncompliance in renewable energy

procurement will not be allowed as a “pass through” expense in their Annual Revenue Requirement.

It is believed that the cost o a 6% RPS target will increase the consumer tari in Maharashtra by 2%. In addition,

the cost o purchasing conventional power at the margin is higher than the average 3.32 Rs per unit cost rom all

renewable energy sources. Procuring power rom renewable energy sources at the existing tari rates will thus

not only add to the availability o energy but also be cheaper than power purchased in the market and thus will not

adversely aect consumers.


“Identiying optimal legal rameworks or renewable energy in India.” <http://www.wisein.org/pd/Backer-and-Meckanzy.pd >.

MERC: <http://www.mahaurja.com/PDF/MERC_RPS_ORDER_16-08-06.pd >.



United States: <http://www.dsireusa.org/ >.


<http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,contentMDK:20772244~menuPK:2

069918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html>.





66

3. Tradable Renewable Energy Certifcates

Issue: There are a number o dierent schemes to procure renewable energy including the Tradable Renewable

Energy Certicate (TREC)—sometimes called Renewable Energy Certicate—where the portolio standard or

target is met with some orm o certied renewable energy that is purchased or traded. An electricity supplier that

generates electricity above its RPS can create TRECs rom the excess generation that can be sold to another entity

or third party to meet its RPS requirements. I the market is properly designed, the transaction costs are low, and

there is sucient competition and price discovery, the TREC scheme should achieve the required renewable energy

capacity with the least possible impact on electricity consumers. As o the time o publication, the MNRE has hired

a consultant to develop a TREC scheme in India.

Advantages o TRECs:

Lower cost renewable energy as TRECs allow development in areas with the highest potential or production•

regardless o the location o load

Market-set incentive is more ecient•

Separate tradable instruments are more fexible•

Cover grid-connected and o-grid acilities•

Overcome issue o uneven distribution o renewable energy resources•

Overcome cost/skill dierentials•

Overcome dierent market types•

Can be combined with other measures•

Desired design eatures o TRECs:Sucient duration o scheme to provide investment certainty given a 15- to 30-year payback time rame•

Large enough TREC target that it cannot be met in the short term•

Penalties or noncompliance•

Market that is large enough to be liquid and competitive•

Coverage o small generation plants•

Identical transmission and distribution costs across jurisdictions•

Available data on renewable resources•

Exchange o inormation on the total amount o electricity that has been generated and the amount generated •

rom renewable resources

Limited and reasonable transaction costs•

Renewable energy verication standards•

Utility Perspective: The TRECs could assist the utilities in meeting mandatory RPS goals, but only i renewable energy is available or purchase.

Developer Perspective: TRECs can create a market or renewable energy and may improve revenueopportunities that are central to the deployment o renewable energy.





67

Regulator Perspective: In theory, policy-driven TREC schemes could assist utilities in meeting their RPS goals.

However, care should be taken to ensure nes are suciently large to avoid utilities simply electing to pay the

penalty, which would not achieve the goal o increased deployment o renewable energy.

Best Practices:

TREC schemes are eective i they are

well designed to ensure harmonization with existing measures, domestic laws, and local context;•

ecient with low transaction costs; and •

mandatory and enorceable.•

Australia

The electricity generator requires regulator accreditation to be eligible to gain accreditation under the mandatory

scheme. The electricity that the generator produces rom renewable energy sources must then also be recognized in

accordance with the scheme rules, so that the TRECs can be registered or each megawatt hour o electricity that

is generated by the generator. The Australian mandatory RPS set a contained legal ramework or the creation and

surrender o RECs.

United States

Under the model used in some states, TRECs might not be registered under the state law. The retailer must ensure

that the benet o the renewable energy purchased comprises electricity that meets scheme requirements. The scheme

might set minimum requirements or electricity that is entitled to be included in the renewable energy portolio.

Some U.S. states adopted a fexible ramework that allows TRECs to not be ormally accredited as long as they meet

prescribed criteria.


“Identiying optimal legal rameworks or renewable energy in India” (pages 64-72).

<http://www.wisein.org/pd/Backer-and-Meckanzy.pd >. [sic]

Massachusetts: <http://www.dsireusa.org/library/includes/incentive2.cm?Incentive_Code=MA10F&state=MA&CurrentPageID=1&R

E=1&EE=1>.

“Renewable energy certicate improve commercial viability o RE electricity.” DailyIndia.com. <http://www.dailyindia.com/

show/287344.php>.

“Report on APP-REDGTF project on renewable energy in India.” <http://www.bakernet.com/NR/rdonlyres/0251961F-DACD-4C9E-

9415-A7A24A28485C/44792/RenewableenergyinIndia.pd >.





68

C. Incentives

Renewable energy projects are typically small with disproportionately high transaction costs (easibility studies, etc.)

with higher capital costs but lower operational costs than traditional energy sources. The large upront costs require

high external nancing that must be amortized over the lie o the project. Developers usually nd incentives are

necessary to make alternative energy projects competitive with conventional energy sources. Utilities do not object

to incentives as long as they do not aect the utility’s nances.

Best Practices:

There are ve general design principles to ollow when developing and implementing eective unding and

incentive programs:

Develop specic target markets and technologies based on technical and economic analyses.•

Use unding and incentives as part o a broader policy to encourage renewable energy and cogeneration•

development.

Establish specic nancial and technical criteria or investments in renewable energy and cogeneration.•

Track and evaluate details o program participation, costs, savings, and production to improve the program and•

ensure goals are met.Create a stable and long-term program (over ve years) to remove the barrier o uncertainty.•

Types o incentives can vary but the most common are investment tax credits, production tax credits (PTCs),

accelerated depreciation, capacity payments, demand credits, buy-down capital costs, carbon credits, and property

tax and other tax incentives. These incentives will be discussed in the next section.


“Financing Options or Renewable Energy” Environmental Financing May 2004

http://www.environmental-nance.com/2004/0504may/nanc.htm.

“Clean Energy Environment–Guide to Action.” http://www.epa.gov/cleanenergy/documents/gta/guide_action_ull.pd (pages 3-72).

U.S. Environmental Protection Agency:<http://www.epa.gov/cleanenergy/documents/gta/guide_action_ull.pd > (page 3-72).





69

1. Investment Tax Credit

Issue: Investment tax credits allow investors to reduce their tax liability and gain all the benets in the rst ew years

ollowing the investment, greatly reducing the risk and cost o investing in alternative energy systems. Investment

tax credits are eective only when an entity has prots that are taxable.

Utility Perspective: The utility expects a certain level o energy rom these alternative energy acilities. Investment

tax credits give no incentives or maintenance o the acilities or generation o energy and have oten led to acilities

that do not run, thus hurting the utility’s ability to provide energy to its customers.

Developer Perspective: Investment tax credit does not stimulate investment or give incentive to produce power

or maintain acility as the credit is linked to capacity installed, not energy generated. It can lead to overinvoicing

or underinvestment in operation and maintenance by developers looking to make a quick prot and then exit as

their prots are received up ront with the installation. There is no real incentive to operate or maintain the acility,

especially i taris are not sucient to see a prot. Developers who do not operate their acilities impact the price

o electricity rom renewable sources and make it harder or serious developers to compete. Investment tax credits

should be removed and replaced with one o the ollowing solutions.

Regulator Perspective: Investment tax credits can be eective or household systems such as solar water heaters or

PV panels but do not provide the right incentives or grid-connected renewable energy acilities.

Best Practice:

For grid-connected renewable energy acilities, a PTC is a better incentive or generation o energy. However,

investment tax credits are eective at the household level.









70

2. Production Tax Credit

Issue: Production Tax Credits (PTCs) link perormance or energy generation output with the amount o tax credit.

PTCs have been supplied in Denmark and at the ederal level in the United States; they are most eective when there

is also some other orm o support, most notably a quota mechanism. The advantage to PTCs is that they have been

eective in stimulating capacity and have reduced uncertainty and capital costs.

Utility Perspective: PTCs are better than investment tax credits, as they incentivize the developer to actually

produce needed energy with the least amount o downtime cost.

Developer Perspective: PTCs are preerred over investment tax credits, as they increase the rate o return, thus

reducing the payback period or the project, and promote the desired outcome o additional renewable energy

generated.

Regulator Perspective: These credits encourage investors to purchase the most reliable systems and to maintain

them to produce the maximum amount o energy. PTCs reward those developers with high load actor equipment

and durable and sustainable hardware that minimizes downtime or maintenance.

Best Practice:

Production tax credits in the United States have actually been oset by income taxes on corporate prots and

workers’ income, as well as tax revenues rom the projects ater the PTCs run out. According to a General Electric

study, PTCs cost the U.S. Treasury $2.5 million or 5.2 gigawatts o wind arms built in 2007 but resulted in a net

present value o $2.75 billion or a 5% internal rate o return.

Due to uncertainty about the credits’ continuation in the uture, their promising potential to increase capacity

diminishes substantially. Thus any production-based tax credit should be designed to decline as costs are reduced or

a minimum length o 10 years in order to be eective and negate the uncertainty that the political climate will shit

with a new government.

Source and For More Inormation:

“Impact o 2007 Windarms on U.S. Treasury.” http://www.geenergynancialservices.com/press_room/press_releases/PTC_

StudyFinal.pd .


http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTENERGY/EXTRETOOLKIT/0,,contentMDK:20772245~menuPK:206

9918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html.





71

3. Clean Renewable Energy Bonds

Issue: A Clean Renewable Energy Bond (CREB) oers the equivalent o an interest-ree loan to nance energy

projects or a limited term. CREBs have comparable incentives to PTCs although the benets rom a PTC are

received only ater the acility is nanced and electricity is generated, whereas under a CREB, benets are received

up ront. The electric utility or government entity issues the CREBs and sells them to bondholders who receive a tax

credit rom the government in lieu o the utility paying interest to the bondholder. The bondholder takes the amount

o the tax credit as a credit against its regular income tax liability and alternative minimum tax liability. Repayment

o principal to the bondholder occurs on a “level annual repayment” basis, meaning equal payments each year o the

term o the bond, commencing in the rst year o issuance. The value o the CREB to a bondholder or any year is

equal to the credit, less the amount o tax payable on the credit.

In February 2008, the Internal Revenue Service announced the second round o volume cap allocations, which

included 342 applications rom 33 states, pertaining to 395 projects. Approximately $477 million o CREB volume

cap was available or allocation to qualied issuers. Applications ranged in size rom $15,000 to $38.5 million.

Governmental borrowers submitted applications totaling $728 million to nance 367 projects with an average proj-

ect size o about $2 million. Governmental borrowers in 28 states received $263 million o volume cap allocations

ranging rom $15,000 to $2.95 million. Approved projects o governmental borrowers included 138 solar acilities,

88 wind acilities, 41 landll gas acilities, 12 hydropower acilities, three closed-loop biomass acilities, three trashcombustion acilities, and one open-loop biomass acility.

Cooperative borrowers submitted applications totaling about $170 million to nance 28 projects with an average

project size o about $6.1 million. Cooperative borrowers received about $143 million o volume cap allocations or

projects in 13 states ranging rom $300,000 to $30 million. Approved cooperative projects included 14 wind acili-

ties, our landll gas acilities, six hydropower acilities, one solar acility, and one open-loop biomass acility. A

complete list o the recipients can be ound on the Internal Revenue Service website.

Utility Perspective: As long as the CREBs are not unded through the utility and do not increase tari prices, they

are not an issue or the utility.

Developer Perspective: CREBs can assist with nancing renewable energy and cogeneration projects and should beencouraged.

Regulator Perspective: CREBs are a good way to nance renewable energy and cogeneration projects and should

be encouraged.

Best Practice:

In February 2008, the Internal Revenue Service (IRS) announced the second round o volume cap allocations,

which included 395 projects rom 33 states. Approximately $477 million o the CREB volume cap was available or

allocation to qualied issuers. Applications ranged in size rom $15,000 to $38.5 million.

Governmental borrowers in 28 states received $263 million o volume cap allocations ranging rom $15,000 to $2.95million. Approved projects o governmental borrowers included: 138 solar acilities, 88 wind acilities, 41 landll

gas acilities, 12 hydropower acilities, three closed-loop biomass acilities, three trash combustion acilities and one

open-loop biomass acility. Governmental borrowers included:

Altoona School District Altoona - $875,000 or a wind project•

The City o Cloverdale, CA - $644,000 or a solar project•

The City o San Diego, CA - $1,215,000 or a landll gas project•

Koochiching County, Minnesota - $1,700,000 or a trash combustion project•





72

Los Angeles County Sanitation District 15 - $2,621,080 or a landll gas project•

Merced Irrigation District - $1,340,000 or a hydropower project•

Regents o the University o Minnesota - $1,500,000 or an open-loop biomass project•

Electric cooperative borrowers received about $143 million o volume cap allocations or projects in 13 states rang-

ing rom $300,000 to $30 million. Approved electric cooperative projects included: 14 wind acilities, our landll

gas acilities, six hydropower acilities, one solar acility and one open-loop biomass acility. Electric cooperative

borrowers included:

New Ulm, MN Public Utilities - $2,975,000 or a wind project•

Wabash Valley Power Association Inc. - $4,500,000 or a landll gas project•

CFC, National Rural Utilities Cooperative in Livingston, TX - $10,200,000 or a hydropower project•

CFC, National Rural Utilities Cooperative in Park Rapids, MN - $30,000,000 or an open-loop biomass project•

CFC, National Rural Utilities Cooperative in Tavernier, FL - $1,000,000 or a solar project•

A complete list o the recipients can be ound on the IRS website ( http://www.irs.gov/pub/irs-tege/creb_2007_disclosure.

pd ).

CREB issuers must spend 95% o the proceeds within ve years or that project, or they may not receive any tax

credits.


DSIRE database: <http://www.dsireusa.org/library/includes/incentive2.cm?Incentive_Code=US45F&State=ederal&currentpageid=1

&ee=0&re=1>.

Internal Revenue Service: <http://www.irs.gov/irb/2007-14_IRB/ar17.html> and <http://www.irs.gov/pub/irs-tege/creb_2007_

disclosure.pd > (list o recipients).

NRECA: <http://www.nreca.org/documents/publicpolicy/cleanrenewableenergybonds.pd >.

Public Renewables Partnership. <http://www.repartners.org/webcast/4%20RECs%20Lieberman.pd >.

USDA “Section 9006 grants”: <http://armenergy.org/documents/S9006NOFA2008.pd >.





73

4. Accelerated Depreciation

Issue: Accelerated depreciation is similar to investment tax credits in that it allows renewable energy developers

to receive their tax benets much sooner. However, as with the investment tax credits, allowing accelerated

depreciation can lead to investments with lower capacity actors.

Utility Perspective: Accelerated depreciation must take long-term operating perormance and maintenance into

account to ensure capacity actors are not lower. In addition, the developer could take all the credits, and then not

operate the acility. This has happened with a ew wind projects in India.

Developer Perspective: Accelerated depreciation greatly decreases the risk associated with projects and is a great

way to incentivize the development o renewable energy projects.

Regulator Perspective: Care must be taken to ensure renewable energy projects are correctly incentivized to

maximize capacity and minimize cost.

India: Section 32 Rule 5 o the Income Tax Act currently allows accelerated depreciation at the rate o 80 to 100%

on a written-down value basis or various renewable energy items.

Best Practice:

Germany included technical standards and certication requirements that must be met by developers to ensure

capacity actors were not lower.

In the United States, business can recover investments in renewable acilities by depreciating them over a period o

ve years instead o the more typical 15 to 20 years.

Depreciation schedules should account or technology improvements and societal values such as carbon reduction.


CII paper “Promotion o Renewable Power Projects in India Through Generation Based Incentives.” <http://www.cii.in>

“Report on APP-REDGTF project on renewable energy in India”: <http://www.bakernet.com/NR/rdonlyres/0251961F-DACD-4C9E-

9415-A7A24A28485C/44792/RenewableenergyinIndia.pd >.


K:20772245~menuPK:2069918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html>.





74

5. Capacity Payment Tari

Issue: Alterative energy acilities can provide rm power to the utility during peak periods. Higher tari rates to

cogeneration acilities that provide energy during these times can help meet system shortages by incentivizing these

acilities to sell energy to the grid.

Utility Perspective: As long as capacity payment taris are not higher than the market price to purchase the

additional power during peak periods, they can be an eective way to address shortages.

Developer Perspective: Developers believe their tari should include capacity payments to recognize their

assistance to the utility and grid during peak periods.

Regulator Perspective: A capacity payment tari can incentivize generation in areas o transmission congestion and

is an important tool in meeting generation shortages.

Best Practices:

The Orange and Rockland Utilities, Inc. (now a part o Consolidated Edison), instituted a tari that recognized the

capability o distributed generation, cogeneration and combined heat and power to provide capacity during peak

periods. The capacity payment tari increased the tari rate given to the distributed generator or generating during

the our peak summer months. The higher capacity payment incentivized cogeneration to increase capacity in

constrained areas and assisted the utility in meeting demand.

However, regulators must ensure utilities do not seek to alter the taris in such a way that it negates the benets.

Examples include modiying taris so customers cannot capture savings, shiting high peak demand charges on

standby service so revenue recovery is on the backup peak demand, or shirting peak demand charges to the standby

tari to receive additional revenue rom the cogeneration acility. These types o standby penalty approaches have

lead to cogeneration acilities disconnecting rom the grid, thus losing the system benets.


“Making Connections” <http://www1.eere.energy.gov/emp/pds/28053.pd > (Page 17).





75

6. Demand Credit

Issue: Demand credits are credits given to the cogeneration acility based on previous generation capability.

Cogeneration can provide capacity during peak periods, reducing demand charges rom the supplier that increase

with peak demand.

Utility Perspective: Any rm capacity that can assist during peak periods is welcome.

Developer Perspective: Demand credits are very benecial to the nancial viability o a project.

Regulator Perspective: Demand credits can encourage cogeneration, combined heat and power and distributed

generation that may benet the grid, especially during peak times.

Best Practices:

The United Kingdom created a demand credit to encourage cogeneration in areas with transmission congestion. This

reduces the congestion on the system and negates the need or the utility to build costly new lines or substations.

The MERC, in its Order dated 25 January 2006, in Case No. 29 o 2005, in the matter o Conederation o Indian

Industry (CII) Proposal to use captive power to mitigate load shedding in Pune Urban Circles o MSEDCL, ordered

as ollows on page 2:

a) Considering that the demand-supply gap is expected to prevail to a certain extent

or the next ve years at least, there is an urgent need to see how best the situation

can be mitigated. The CII proposal to utilise surplus captive power during peak hours

and making available the grid power or supply to other consumers is a well intentioned

proposal to mitigate the load shedding in certain areas o the State, provided all the incremental cost

is internalized by the consumers residing within those areas. Based on the responses received rom

stakeholders in writing as well as during public hearing, the Commission has observed that a broad majority

o consumers have welcomed this CII initiative. Considering the current and expected demand-supply gap,

the Commission accepts the CII proposal to utilise surplus captive power during peak hours and making

available the grid power or supply to other consumers. However, all the incremental costs o this proposal

need to be internalized by the consumers o Pune Urban Circle. . . .

e) The Commission will adopt the principles o normative pricing, in relation to the uel

used and the heat rate, to determine the cost at which the captive generators would be

generating the electricity. The price o uel will be benchmarked to publicly available

data on uel prices rom sources such as IOC, HPCL, BPCL, RIL, etc. The dierence

in the peak hour variable tari applicable to the industrial units and the normative

price o generation determined above, will be payable to the captive generators, or

the reduction in the quantum o electricity consumed rom the grid (which will alsocorrespond to the quantum o electricity generated by the captive unit). The peak

hours or the purpose o this computation will be 0900 to 1200 hours in the morning

and 1800 to 2200 hours in the evening.

) As the approval o additional charge to be levied on the consumers o Pune Urban

circle to mitigate this load shedding is a “tari” design issue, the Commission will

address this issue while approving the ARR and Tari o MSEDCL.





76

This MERC Order, also called the Pune Model, helped save 90 MW o power during peak time. Consumers with

monthly consumption o more than 300 units paid a reliability charge o 42 paise per unit.


A&N Electric Cooperative: <http://www.anec.com/yourbill/rate_pds/LP_A_U.pd > ( page 3).

“Making Connections” <http://www1.eere.energy.gov/emp/pds/28053.pd > (Page 17).

MERC Drat Order: <http://mercindia.org.in/pd/21_Order_CN_01%20o%202006_DRAFT.pd > (page 2).

“Pune Power Model-A successul example o PPP pattern.” <http://businessstandard.com/india/storypage.php?autono=327438>.





77

7. Buy-Down Capital Cost

Issue: A buy-down program levies a small charge on every kilowatt hour o electricity sold and the money collected

is used to subsidize or “buy down” the purchase o renewable energy systems. This program is oten used to

encourage small residential installments. Rebates can also be considered a buy-down. Sacramento Municipal Utility

District (SMUD) o Caliornia gives a $1–2/watt rebate to home developers or installed solar photovoltaic systems.

Utility Perspective: Rebates and other buy-down programs are not an issue as long as the cost is part o tari rates

or all customers and is not a utility expense.

Developer Perspective: Buy-down programs and rebates are essential to decrease the cost o smaller systems and

incentivize their deployment.

Regulator Perspective: These programs will raise the rates on all consumers slightly but are a great tool to

encourage the deployment o smaller renewable energy systems, especially PV.

Best Practices:

The American Wind Energy Association listed several key eatures o eective buy-down programs:

The rebate or grant is easy to apply or and is received quickly.•

Minimum requirements or eligible systems are set to ensure equipment is up to standard.•

Rebates are high enough to incentivize consumers to participate (AWEA recommends 50% o system cost•

initially with gradual phase-out over time).

Rebates are limited to a certain level per watt o capacity o the system (AWEA recommends $3–4 per watt to•

ensure manuacturers and dealers do not raise prices).

Rebates should be given only to grid-connected systems as they improve the utility’s perormance and are•

more expensive than stand-alone units.

Rebates should be part o a broader policy that includes net metering laws that make the economics o •

residential systems more attractive.

Twenty-two states in the United States oer a rebate program. As an example, Nevada oers a rebate o $3 per

watt (in 2006) or grid-connected PV installations in residences, small businesses, schools, and public buildings.

Caliornia also has a very robust rebate system that covers a broad range o renewable energy technologies.

Japan has investment subsidies through rebates or PVs through its Solar Roos program. These rebates, combined

with low interest loans and net metering, led to 420 MW o PV installed during the program rom 1994 to 2002.


Database o State Incentives or Renewable Energy. <http://www.dsireusa.org >.

American Wind Energy Association:<http://www.awea.org/pubs/actsheets/buydwn_s.PDF >



U. S. Environmental Protection Agency:<http://www.epa.gov/cleanenergy/documents/gta/guide_action_ull.pd >.





78

8. Carbon Credits

Issue: The Clean Development Mechanism (CDM) is a acilitating mechanism under the Kyoto Protocol that was

designed to assist countries to meet GHG emission reduction targets and achieve sustainable development targets.

The CDM is intended to be, among other things, a vehicle or investment and technology transer between developed

countries and developing countries including India. The book Wind Energy Development in India notes in Chapter 13

(“Carbon Credits as an additional revenue source”) that CDM in developing countries can:

attract oreign capital or projects that assist in the shit to a more prosperous but less carbon-intensive•

economy;

encourage and permit the active participation o both private and public sectors in sustainable Projects;•

provide a tool or technology transer i investment is channelled into projects that replace old and inecient•

ossil-uel technology or create new industries in environmentally sustainable technologies; and

help dene investment priorities in projects that meet sustainable development goals.•

Utility Perspective: The utility should receive the carbon credits, especially i it granted the acility a rebate. In

xing the renewable energy tari, the regulator already assures that a return o 50 to 100% o the carbon credits

should go to the utility.

Developer Perspective: Many renewable energy projects that may be eligible under the CDM have had diculty

attracting nancial support due to lower emissions reduction potential o renewable energy projects and the long

liespan o acilities that can extend beyond Kyoto’s commitment period. Transaction costs associated with CDM

projects, such as the costs o registration and legal ees, may be prohibitively high compared to the volume o Carbon

Emission Reduction credits (CERs) expected to be generated by the projects.

Regulator Perspective: The carbon credits belong to the acility that creates them but that acility can sell them to

the utility (Caliornia Commission view).

IndiaTo qualiy as a CDM project, a project activity must demonstrate that GHG emissions were reduced against the

baseline scenario, a representation o GHG emissions under normal circumstances. However, Indian policies and

regulations encouraging renewable energy are not to be taken into account when calculating the baseline scenario

(this is known as “Type E additionality” under the CDM rules). The baseline is calculated as the hypothetical

scenario without the regulations being implemented. This benets developers in India because it is easier to meet the

requirement o additionality.

India designated one authority to clear all projects, the Indian Designated National Authority or the CDM, which

decreases the length o the evaluation process.

According to the REIL report, variations between the number o wind power CDM projects in dierent Indian statesillustrate that CDM alone will not be sucient to ully develop renewable energy. A tradable renewable energy

credit could help overcome the diculties o variations between States.





79

Estimated Transaction Costs o CDM ProjectsACTIVITY COST (Rs. 100,000)

Preparation o PIN/PDD 1–1.5 + 5% success ee (o the CER revenue) –

depending on consultant chosen

Host-country approval —

Validation 3–4 (one-o)

Registration See table below.

Verication 2–3 (yearly)Certication cost 2% deduction o CER + $0.10 per CER – or

adaptation und and administration expenses o the

CDM executive board

Identication o buyers and sale o CERs 1–2% o CER volume

Source: Wind Energy Development in India, Chapter 13, Carbon credits as an additional revenue source.

CER Registration Costs

Average Tonnes o CO2

Reduction per Year US$

15,000 or less 5,000

15,000 to 50,000 10,000

50,001 to 100,000 15,000

100,001 to 200,000 20,000>200,000 30,000

Source: WISE 2007.

Best Practices:

The international CDM rules now allow the “bundling” o large-scale projects (not just small-scale projects) to

urther reduce transaction costs. This additional fexibility in the CDM rules should reduce transaction costs or

renewable energy projects. In addition, many contractors now exist to acilitate CDM who receive a ee only i they

succeed in capturing CDM credit.

Programmatic CDM involves the aggregation o a number o small GHG reduction activities into a larger program,

which is then submitted to the CDM Executive Board as a single activity (using one baseline and monitoringmethodology) to overcome the cost barriers to smaller projects.


“Identiying optimal legal rameworks or renewable energy in India” (pages 88-94).

<http://www.wisein.org/pd/Backer-and-Meckanzy.pd >.

Wind Energy Development in India, Chapter 13, Carbon Credits.








80

9. Property Tax Incentives

Issue: Renewable energy projects have higher investment costs or improvements to acilities, which would lead to

higher property taxes since they are based on the installed cost o improvements.

Utility Perspective: The utility has no issue with property tax incentives.

Developer Perspective: Property tax incentives are an important way to reduce the cost o a project.

Regulator Perspective: The regulator has no issue with property tax incentives.

Best Practices:

United States

More than 24 U.S. states implement property tax incentives by partially or ully excluding them rom property

taxes, awarding tax credits that oset the property tax, or capping the value o the property at the value o a similar

conventional energy system.

India

Many Indian cities have property tax rebates or solar hot water systems.

Solar Hot Water System Initiative in Indian StatesSr No Name o State That Issued the GOs

or Amendment o Building By-laws

or Mandatory Use o SWHS

Name o the Municipal

Authorities/State Housing

Development Authority That

Has Amended the Building

By-laws or Mandatory Use o

SWHS

Any Other Incentive Oered

by the State Government

1. Chhattisgarh Korba Municipal

Corporation

Raipur Municipal

Corporation

Chhattisgarh Housing

Development Board

Residential building having

plinth area 1,000–1,500 sq t

Nil

2. Uttarakhand Nil Rebate in electricity tari Rs

75/month or each 100 LPD

installation.

3. Rajasthan Jaipur DevelopmentAuthority

Residential building

developed on plot area

500 sq m and above

Rebate in electricity tari 15 paise/unit to domestic

consumer using SWHS.

4. Punjab Nil

5. Andhra Pradesh Nil




Handbook on Best Practices for the Successful Deployment of Grid-Connected Renewable Energy, Distributed Generation,Cogeneration, and Combined Heat and Power in India

81

6. Kerala Nil Incentive o Rs 1500 to

domestic user o SWHS rom

ANERT.

7. Uttar Pradesh Lucknow, Bareilly,

Saharanpur, Muradabad

Gorakhpur Development

Authority

Residential building having

plot area 500 sq m

Subsidy o Rs 4,000 per 100

LPD SWHS installation in govt

and semi-govt establishments

by NEDA.

8. Karnataka Bangalore Municipal

Corporation

Rebate in electricity tari 50

paise/unit to a max o Rs 50

per installation to domestic

consumer using SWHS

9. Harayana Nil Rebate in electricity bill Rs 100

/100 LPD up to Rs 300/LPD to

users o SWHS

10. Maharashtra Pune, Thane, Nagpur, BMC,

Bhivandi, Nashik, Amravati,

Kalyan, Pimpri Chinchwad,Jalgaon Municipal

Corporation

11. West Bengal Durgapur Rebate in electricity tari 40

paise/unit up to max o Rs 80

per installation to domestic

consumer using SWHS or frst

two years.

12. Delhi Residential/commercial

building developed on plot

area 500 sq m and above

13. Tamil Nadu Nil

14. Madhya Pradesh Nil

15. Himachal Pradesh Nil

16. Chandigarh Nil

17. Nagaland Nil

18. Dadar & Nagar Haveli Nil

Source: World Institute of Sustainable Energy, http://www.wisein.org

Sources and For More Information:

DSIRE database: Personal Tax Incentives. <http://www.dsireusa.org/library/includes/type.cm?EE=1&RE=1>.


K:20772245~menuPK:2069918~pagePK:64168445~piPK:64168309~theSitePK:1040428,00.html>.

World Institute o Sustainable Energy. < http://www.wisein.org>.





82

10. Other Incentives

Tax Incentives

Other tax incentives include income tax exemptions on sales o renewable energy; tax exemptions or equipment

purchases; reductions or exemptions rom import taxes on equipment or components; personal and corporate income

tax credits; exemptions rom sales, excise, and property taxes; and production tax credits.


DSIRE database. Personal Tax Incentives. <http://www.dsireusa.org/library/includes/type.cm?EE=0&RE=1>.

Generation-Based Incentive (India)

The MNRE o India released a GBI or solar and grid-connected wind power in spring 2008. These incentives are

in addition to any eed-in taris given by the SERCs and are given through IREDA. Generators cannot receive

accelerated depreciation i they receive these incentives. These incentives are available only or a maximum o 50

MW or solar.

SolarEligibility Incentive Rate Limit on Incentive (power tari

plus incentive payment)

Length o Incentive (yrs)

Over a certain size

commissioned prior to 31

December 2009

Rs 12 per kWh No more than Rs 15 per kWh or photovoltaic and

Rs 13 per kWh or solar thermal plants

10 yrs

Photovoltaic commissioned

ater 31 December 2009

Rs 11.40 per kWh Slightly less than Rs 15 per kWh 10 yrs

Solar thermal Rs 10 per kWh Slightly less than Rs 13 per kWh 10 yrs

Notes: kWh = kilowatt hour; Rs = Rupees.

Source: MNRE, http://www.mnes.nic.in

Grid-Connected Wind Incentive

MNRE provides a eed-in tari o Rs 0.50 per kWh or projects over 5 MW or a period o 10 years. Eligible project

investors include Independent Power Producers (IPPs), registered companies, nongovernmental organizations, trusts,

academic and research institutions, and state nodal agencies. This tari will be reviewed ater 49 MW o capacity

has been installed.

Assessment

Because they are new and untested, it is impossible to assess the impact o these incentives on the increased

deployment o solar and wind projects. In theory they appear to be a powerul incentive to developers as the average

tari in India is about Rs 3. There has been some concern in India that the solar energy incentive is so high that it

might attract less qualifed developers interested in profts.

In addition, India has as much as 600,000 MW o solar potential but as o 2007 has only 18.2 MW o installed solar

capacity. While a 50 MW addition through this incentive would more than double the current installed capacity, it is

a very small percentage o the total potential solar capacity.

It is not clear whether the wind power scheme will continue ater 49 MW o capacity is installed. 49 MW is a very

small amount given that India currently has 7,660 MW o wind energy and has 45,195 MW potential.





83

California Public Utilities Commission Self-Generation Incentive Program

In September 2000, Assembly Bill 970 (AB 970) was approved, which called or the creation o more energy supply

and demand programs. As a result, in March 2001, the Caliornia Public Utilities Commission (CPUC) issued a

decision creating the Sel-Generation Incentive Program (SGIP) to oer fnancial incentives to their customers

who install certain types o distributed generation acilities (in the U.S. these are grid connected) to meet all or a

portion o their energy needs. This program initially provided incentives or customers o investor-owned utilities

to use microturbines, small gas turbines, wind turbines, photovoltaics, uel cells, and internal combustion engines to

provide some or all o that customer’s electricity. As o January 1, 2008, the SGIP oers incentives only or wind

and uel cell projects; internal combustion engines, microturbines, and small and large gas turbines can no longer

receive incentives through this program.

Generation must be certifed to operate in parallel with the electric system grid (not backup generation) and meet

other criteria established by the CPUC. While residential customers are not barred rom the program, it was designed

primarily with business and large institutional customers in mind. The Caliornia Energy Commission (CEC) oers a

similar program that is available to customers who install renewable generation, such as uel cells and wind turbines,

less than 30 kW in size.

The SGIP is one o the largest DG incentive programs in the United States, with nearly 1,200 projects online and

an average rate o 43 MW per year. By the end o 2007, the total online capacity o SGIP projects was 300 MW.Cogeneration technologies represent over 50% o that online capacity, while PV represents 40%.

The ollowing table describes the incentive payments and maximum incentive and system size limits. Please note

that the CEC also has a program similar to Level 1 and consumers may qualiy or incentives with the CEC and the

CPUC program but up to a maximum o $4.50/W:

The incentive levels or 2008 are as ollows:

Incentive Levels Eligible TechnologiesIncentive Offered

($/Watt)

Minimum

System Size

Maximum

System Size

Maximum

Incentive Size

Level 2

Renewable

Wind turbines $1.50/W

30 kW 5 MW 1 MWRenewable uelcells

$4.50/W

Level 3

Nonrenewable

Nonrenewable uel

cells$2.50/W None 5 MW 1 MW

Notes: MW =megawatt.

For projects that are greater than 1 MW up to 3 MW, the incentives identifed above decline according to the schedule

below:

Capacity Incentive Rate (% of Base)

0 – 1 MW 100%

>1 MW – 2 MW 50%

>2 MW – 3 MW 25%

Source: http://www.pge.com/mybusiness/energysavingsrebates/selfgeneration/equipment/

California Energy Commission Emerging Renewables Buy-down Program

The buy-down program is available to customers o Caliornia’s investor-owned utilities.

Technologies: Photovoltaics, small wind (less than 10 kW), uel cells (renewable uels only), solar thermal electric.

Incentives: $3.00/W or small residential systems (under 10 kW), up to a maximum 50% o system cost.

$2.50/W or larger systems (over 10 kW), up to a maximum o 40% o system cost.





84

Project Limits: Renewable energy systems installed under this program must be interconnected with the utility grid.

A system should primarily oset part or all o the customer’s electrical needs, but must not be sized greater than 200

percent o on-site peak demand. The maximum buy-down amount is $2.5 million or a single project.

Buy-down Process: Customers make a reservation o unds with the CEC prior to construction o the project. This

reservation will expire ater 9 months or smaller systems (under 10 kW) or 18 months (all other systems). Once

the system is completely installed and operational, customers then request the buy-down payment by submitting the

required documentation to the CEC. Within 30 days o receipt o a completed claim orm, the CEC will issue theincentive payment. This completes the buy-down process.

California Energy Commission Solar Energy and Distributed Generation Grant Program

Caliornia residents who are purchasers, sellers, owner-builders, or owner-developers o eligible solar energy or DG

systems are eligible to apply.

Technologies: Solar domestic water heating systems, solar swimming pool heating systems, battery backup or PV

systems, DG.

Incentives: $750 or solar water heaters, $750 or PV system battery backup, $250 or solar pool heaters.

Up to $2,000 or 10% o system cost, whichever is less, or the ollowing DG systems:

Microcogeneration•

Gas turbines•

Fuel cells•

Reciprocating internal combustion engines•

Electricity storage (other than or eligible solar energy systems)•


Caliornia Energy Commission Emerging Renewables Buydown Program

<http://www.energy.ca.gov/greengrid >.

Caliornia Energy Commission Solar Energy and Distributed Generation Grant Program

<http://www.consumerenergycenter.org/solaranddg >.

Caliornia Public Utilities Commission Sel-Generation Incentive Program (SGIP)

<http://www.cpuc.ca.gov/NR/rdonlyres/98A75D73-5684-45DF-A647-D869D6183D0B/0/CenterorSustainableEnergy10_08REPRIN

T.pd >.

DSIRE database. Personal Tax Incentives. <http://www.dsireusa.org/library/includes/type.cm?EE=0&RE=1>.

SGIP Evaluation Highlights. <http://www.cpuc.ca.gov/NR/rdonlyres/783F30E1-4894-42FD-BC74-449E17283F3E/0/

SGIP_7thYearImpactEvalReport_Highlights_2.pd >.





85

D. Reund o Salvage Value

Issue: Developers and utilities disagree over who should pay or acilities and interconnections and whether the

utility or the developer/operator is the ultimate beneciary o the acilities.

Utility Perspective: The electric utility and its ratepayers should not have to pay or special acilities to connect

to its system, especially given that they may have no use or them. Facilities and equipment or renewable and distributed generation units should be addressed as part o the regulatory commission’s approved line extension

policies, procedures and practices.

Developer Perspective: The utility oten insists that the developers pay or special acilities, such as transmission

lines, at a signicant cost. These acilities may eventually become the property o the electric utility with no

payment made to the developer or the costs associated with building them.

Regulator Perspective: I the developer pays or upgrades and leaves the system at some point, the developer should

receive some money back or the upgrades that are now owned by the utility, provided that the upgrades oer system

benets.

Best Practice:

In Caliornia, the electric utility will at a minimum issue a credit or the net salvage value o the renewable energy/

cogeneration unit’s special acilities i the energy/cogeneration unit either paid the installed costs or constructed and

transerred them to the electric utility.


Caliornia Rule 21: <http://www.energy.ca.gov/distgen/interconnection/RULE_21_MODEL_RULE_02-2006.PDF.>

Financial Issues and Best Practices Reund o Salvag




86

E. Insurance and Liability Requirements

Issue: Many utilities insist any acility connecting to their grid carry additional liability insurance, which adds to the

cost o a project.

Utility Perspective: The utility is seen as having major assets and would be likely to be brought into a claim due

to the perception o having plenty o cash. In addition, the generators are a greater risk than appliance and electricloads and thus should carry additional insurance with the utility as the beneciary.

Developer Perspective: Risks rom acilities that use Underwriters Laboratories (UL)-rated equipment that are

installed per Institute o Electrical and Electronics Engineers, Inc. (IEEE) procedures are minimal and comparable to

the risk rom other small equipment that is routinely interconnected without insurance. Existing laws are adequate to

allocate liability i there is an accident. The insurance costs are oten too high or small developers and can block the

project.

Regulator Perspective: I the developer ollows all the utility’s guidelines or interconnection and equipment, the

risk to the grid should be low and insurance should refect the lower risk.

Best Practice:

Texas, New York, and Caliornia scale insurance requirements based on the relative size o generator, the nature o

interconnection, and physical potential or impact to provide the greatest balance between real nancial liability and

added project costs.

SMUD changed its practice on insurance. I the developer ollowed SMUD’s rules and those rules were not

sucient, the utility is equally liable or not creating sucient rules. The belie is that SMUD should not be

indemnied against its own mistakes.

The Interstate Renewable Energy Council model states:

An electricity provider shall not charge a customer-generator any ee or charge; or require additional

equipment, insurance or any other requirement not specically authorized under this sub-section or the

interconnection rules in Section [[reerence state interconnection rules here], unless the ee, charge or other

requirement would apply to other similarly situated customers who are not customer-generators. (p. 2)


“Making Connections” <http://www1.eere.energy.gov/emp/pds/28053.pd > pg. 13.

IREC Model Net-Metering Rules: <http://www.irecusa.org/leadmin/user_upload/ConnectDocs/NM_Model.pd >.

“The Potential Benets o Distributed Generation and the Rate-Related Issues That May Impede Its Expansion”: <http://www.oe.energy.gov/DocumentsandMedia/1817_Report_-nal.pd >.

Financial Issues and Best Practices Insurance and Liability Requirem




87

VI. Technical Issues and Best PracticesTo assist in overcoming the barriers related to small generation technical interconnection procedures, the Institute o

Electrical and Electronics Engineers (IEEE), through industry Standards Coordinating Committee 21, developed and

published two standards (1547 and 1547.1) related to interconnecting distributed resources with the electric power

grid (IEEE Std. 1547-2003; IEEE Std. 1547.1-2005). These standards documents were developed through a broad

stakeholder consensus process approved by the American National Standards Institute (ANSI) and now provide the

basis upon which most (i not all) U.S. utilities and states develop their specic set o rules and requirements.

These IEEE interconnection standards and standards in several U.S. states are the basis or this section on “Technical

Issues and Best Practices.” The section is divided into Grid Stability and Protection and Equipment Requirements.

These practices are only relevant at lower voltages and are eective ways to simpliy interconnections or small-scale

renewable energy, distributed generation, cogeneration, and combined heat and power acilities.

Sources and For More Inormation:Interconnection Guidebook: http://www.energy.ca.gov/distgen/interconnection/guide_book.html

Public Utility Commission o Texas: http://www.puc.state.tx.us/electric/business/dg/dgmanual.pd

China: http://74.125.47.132/search?q=cache:Abi0-4eRZPUJ:www.inive.org/members_area/medias/pd/

Inive%255CIAQVEC2007%255CWu.pd+STUDY+ON+THE+DEVELOPMENT+STATUS+AND+TREND+OF&hl=en&ct=clnk&c

d=1&gl=us

DSIRE Database: http://www.dsireusa.org/library/includes/type.cm?EE=1&RE=1

“Improving Distribution System Reliability By Means O Distributed Generation”:

http://www.cired.be/CIRED07/pds/CIRED2007_0070_paper.pd

The NRECA Guide to IEEE 1547: http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd

“Stability o Power Systems with Large Amounts o Distributed Generation” www.diva-portal.org/diva/getDocument?urn_nbn_se_ kth_diva-46-1__ulltext.pd

“Supplemental Recommendation Regarding Distributed Generation Interconnection Rules” http://www.energy.ca.gov/reports/2000-11

-07_700-00-014.PDF

Standard Interconnection Agreements & Procedures or Large Generators

http://www.erc.gov/industries/electric/indus-act/gi/stnd-gen.asp

Standard Interconnection Agreements & Procedures or Small Generators http://www.erc.gov/industries/electric/indus-act/gi/small-

gen.asp

Standard Interconnection Agreements or Wind Energy and Other Alternative Technologies http://www.erc.gov/industries/electric/

indus-act/gi/wind.asp

Technical Issues and Best Practices




88

A. Grid Stability and Protection Requirements

1. Intermittency and Grid Stability

Issue: Renewable energy resources are intermittent energy sources whose power output can vary widely, even within

the hour, and potentially cause grid instability.

Utility Perspective: A utility must be condent that power needs can be met on a second-by-second basis and

thereore, intermittent power sources cannot be relied on to meet load. The utility must still generate or purchase

sucient power to meet peak demand.

Developer Perspective: The developer should be able to generate and sell power to the grid when it can.

Furthermore, when enough renewable energy acilities are connected to the grid, the likelihood o all o them

being ofine at the same time diminishes and, thus, at least some percentage o alternative energy acilities could

be considered dependable. Furthermore, alternative energy acilities benet the grid by adding generation and by

spreading generation capacity throughout the system, which can help stabilize grid operations.

Regulator Perspective: Renewable energy sources are critical to reduce greenhouse gas emissions and improveenergy security. However, care must be taken to ensure the transmission grid is stable and electricity supply is not

disrupted due to intermittency problems.

Best Practices:

One way to alleviate the problem o intermittency is to connect alternative energy acilities to the grid to enhance the

reliability o the system. On a system with numerous small generating acilities, the loss o one generator will have a

much smaller eect on the system. As more acilities connect to the system, intermittency becomes less o an issue.

In act, some countries are dealing quite successully with the question o intermittency and grid stability. For

example, approximately 20% o the Danish electricity consumption is met with wind power and the Danish Wind

Industry Association is working to increase that to 35% by 2015.

The Danish Wind Industry Association recommends the ollowing three steps to deal with fuctuating supply:

Conventional power plants should have a clear incentive to regulate production as the wind changes.•

Electricity consumption should be fexible, so automatic systems can move consumption to windy periods•

rom less windy periods.

Eective short-term markets should eciently balance wind power in the electricity system.•

Technical Issues and Best Practices Grid Stability and Protection Requirements




89


“Beyond Free Market Assumptions: Addressing Barriers to Distributed Generation” <http://www.energytoday.com.au/docs/CUAC-B

eyondFreeMarketAssumptionsFinalReport.pd >.

Danish Wind Industry Association: <http://www.windpower.org/en/uturesupply.htm>.

“Eect o Large Scale Wind Farms On the Egyptian Power System Dynamics” <http://www.icrepq.com/icrepq-08/216-el-sayed.pd >.

“Energy Cost Optimization Through The Implementation o Cogeneration and Grid Interconnection.”

<http://www.cired.be/CIRED07/pds/CIRED2007_0004_paper.pd .>

“Impact o Renewable Distributed Generation on Power Systems” <http://www.pserc.wisc.edu/ecow/get/publicatio/2000public/

CSSAR01.PDF>.

“Report on Distributed Generation Penetration Study” <http://www.nrel.gov/docs/y03osti/34715.pd >.

“System integration o Non-Thermal generation (SYNTER)” <www.nottingham.ac.uk/esrnetwork/Systems%20Integration%20o%20

non-thermal.doc>.

“Wind Energy Forecasting Technology Update: 2004”

<http://my.epri.com/portal/server.pt?space=CommunityPage&cached=true&parentname=ObjMgr&parentid=2&control=SetCommuni

ty&CommunityID=277&PageID=0&RaiseDocID=000000000001008389&RaiseDocType=Abstract_id >.





90

2. Pre-interconnection Studies

Issue: Utilities and developers oten disagree over whether a pre-interconnection study is needed to consider the

distributed generators’ impact on the regional power system and the grid as a whole.

Utility Perspective: Prior to connecting distributed generators, the utility must conduct a pre-interconnection study

to determine i the acility will create any adverse eects on the distribution system and whether any upgrades or

additions to the system are needed to interconnect the acility. The cost o these studies should be borne by thedeveloper o the acility because, without its acility, the upgrades and expenses would not be necessary. Simple

studies or small generators could be provided or ree.

Developer Perspective: Pre-interconnection studies are usually prohibitively expensive and can take too much

time. There oten are no limits to the amount o time a utility can take to complete the study or how much money it

will cost. Furthermore, most alternative energy acilities are so small that they would have a negligible eect on the

distribution system and thus the study is unnecessary and may be a tactic to block the developer rom completing the

project.

Regulator Perspective: The utility should conduct a study i deemed necessary to ensure system reliability. The

developer seeking the interconnection should pay or the study as he is its sole beneciary.

Best Practices:

Dierent states in the United States are taking slightly dierent approaches, but typically, the type o study required

depends on the size o the proposed cogeneration acility.

New York

For systems o 15 kW or less, utilities are not permitted to charge applicants or completion o the Preliminary

Review or the Coordinated Electric System Interconnection Review.

For systems exceeding 15 kW, the applicant pays a $350 nonreundable application ee. This ee can be reunded/

recovered under certain circumstances. The utility has ve days to inorm the applicant i it has provided all

necessary inormation and then has ve more days to nish the preliminary review. I the proposed interconnection

is viable, the utility provides a cost estimate or the completion o the Coordinated Electric System Interconnection

Review.

Texas

In Texas, i the proposed site is not on a networked secondary, no study ee may be charged to the applicant i all o

the ollowing apply:

Proposed equipment is precertied •

Proposed capacity is 500 kW or less•

Proposed acility is designed to export no more than 15% o the total load on eeder (based on the most recent•

peak load demand)

Proposed acility will contribute not more than 25% o the maximum potential short-circuit current o the•

eeder





91

Certain aspects o secondary network systems create technical diculties that may make interconnection more

costly. I the proposed site is serviced by a networked secondary, no study ee may be charged to the applicant i

Proposed equipment is precertied •

Aggregate generation, including the proposed system, represents 25% or less o the total load on the network •

(based on the most recent peak load demand) and either

Proposed acility has inverter-based protective unctions, or •

Proposed acility rating is less than the local applicant’s veriable minimum load.•

Otherwise, the transmission and distribution utility may charge the applicant a ee to oset the costs o the

interconnection study. The transmission and distribution utility must advise applicants requesting interconnection on

secondary networks about the potential problems and costs beore initiating the study.

Texas also requires that interconnection studies not take more than our weeks to complete and the utility must give

the developer an estimate o the cost prior to beginning. The study must include both the costs and benets o the

interconnection to the utility and a copy o the ndings must be given to the developer.

Sources and For More Inormation:Ohio: <http://www.puco.ohio.gov/emplibrary/Distributed_Generation_Screening_Process.pd >.

New York: <http://www.dps.state.ny.us/08E1018/SIR_Require_11_04.pd >.

Texas: <http://www.puc.state.tx.us/electric/business/dg/dgmanual.pd >.





92

3. Unintentional Islanding

Issue: Islanding occurs when a section o the grid with both load and generation is separated rom the larger grid. I

a acility is located at the end o a long radial eeder and the breakers at the base o the eeder open, the acility and

all the customers rom the open breaker to the end o the eeder will be islanded. Islanding creates a number o very

serious dangers to the system, as a whole, and to the cogeneration acility.

Utility Perspective: The biggest concern utilities have about adding cogeneration to their system is unintentional

islanding. Utilities must protect against islanding and usually do so by using mechanical relays and transer switches

to automatically isolate a generator rom the grid when the grid is de-energized. This also helps avoid damage to the

cogeneration acility when it is reconnected to the local grid.

Developer Perspective: The cost o mechanical relays and transer switches is too expensive or small generators

and the insistence that they be included prohibits alternative energy acilities rom being integrated into the grid.

Furthermore, new electronic circuitry can now be integrated into inverter components o the acility at a substantially

reduced cost. This equipment is just as eective and there is a unctional test or the anti-islanding circuitry and

IEEE standards that ensure adequate system protection.

Regulator Perspective: To ensure the grid’s protection, regulators will usually deer to the utilities, as they have the

most experience in technical matters o protection.

Best Practices:

The risk o unintentional islanding can be minimized by using induction generators, by installing proper protective

equipment, and by sizing and operating the acility to avoid the situation. (More specic solutions are oered below

in the appropriate sections.)

Texas

To make sure that power is not exported to the grid, without the use o explicit nonexport protective unctions, the

capacity o the acility must be less than or equal to the customer’s veriable minimum annual load. Even when

generation levels are below this threshold, anti-islanding equipment may still be required to ensure worker and

equipment saety.

Avoiding unintended islands is more complicated when the acility supports load beyond the point o common

coupling (PCC). Rules in Texas speciy a threshold to address these concerns. Facilities cannot generate more than

15% o the total load on a single radial eeder. The total load, in this case, is dened as the maximum load o the

eeder over the previous 12-month period. This threshold, expressed in equation orm, is as ollows:

DGexport max ≤ 0.15 × FeederLoad max

As long as the acility meets this criteria, it is assumed that the acility will not cause the complications listed above

and it can export power without incurring costly system changes. I a acility exceeds this threshold, a thorough study

may be required to determine whether it could cause islanding or adverse power fows.



Unintentional Islanding in Distribution Systems with DG. <http://www.iset.uni-kassel.de/dispower_static/documents/highlight028.pd >.





93

4. Synchronization

Issue: In order to reconnect an islanded portion o the grid to the larger system, various parameters o the power on

the separated portion must match those on the larger grid. Closing in (reconnecting) two mismatched systems can

cause catastrophic damage to equipment.

Utility Perspective: Synchronization matches voltage magnitude, requency, phase rotation, and phase angle o the

DG acility with the utility prior to closing the paralleling device. When systems are paralleled out o phase, very

high torques in rotating machines can occur, which can damage both the utility’s system and the distributed generator

equipment. Out-o-range voltages, particularly low voltages, can cause motors, semiconductors, and controls to

malunction, and may create dangerous situations or utility personnel because they can extinguish mercury vapor

and fuorescent lamps.

It is imperative that the alternative energy acility can parallel the utility’s system without causing a voltage

fuctuation o more than +/-5% at the PCC and can meet the ficker requirements.

Developer Perspective: Synchronization is mostly a major concern or synchronous generators. Induction generators

may be driven to near synchronous speed by the prime mover beore closing the paralleling device, but they will

connect very similarly to an induction motor beore actually generating a voltage o concern. Most inverters will

simply start generating voltage when the power is present on the utility system.

Regulator Perspective: Power rom the alternative energy acility must be in synch with the utility or sae and

reliable operations.

Best Practices:

When synchronicity is an issue, use automatic synchronization devices instead o manual devices, because manual

synchronization requires a highly skilled operator and unsuccessul synchronization can be quite damaging. Types o

automatic synchronizers include the ollowing:

Synch-check relays check the voltages o the utility and generator and close a contact when the voltages are within

certain limits or a particular period o time. These are the least costly and simplest devices to operate and may also

be used as a signal to automatically close the breaker at the PCC.

Automatic synchronizing relays and electronic transducer combination packages have adjustable ranges to monitor

and control the synchronism, requency, phase or power actor, and the voltage levels o the distributed generator.

They can also include dead bus relays.

Manual synchronization equipment is very rare and used only on generator equipment that is less than 100 kW or as

a backup to an automatic system.

Electric power systems over 10 kW that could potentially be islanded and rely on manual synchronization should

have, at a minimum, the ollowing equipment: two voltmeters, two requency meters, and a synchroscope. Both the

utility and the generator can monitor the system with one o the volt and requency meters. The synchroscope will

check the phase angle between the two systems and ensure they are in phase. Synchronizing lights may substitute or

the synchroscope.





94

The Caliornia Interconnection Guidebook requires the ollowing:

I the short-circuit current ratio (SCCR) ≤ 0.05 (small relative to the size o local distribution system), then the

generating acility can use either manual or automatic synchronizing methods.

I the SCCR > 0.05 (large relative to the size o the local distribution system), the generating acility must use

automatic synchronizing methods. In this case, the generating acility must be equipped with loss o synchronism

protective unctions.

Caliornia does not allow manual synchronizing when the generating acility is large, compared to the local

distribution system, because o the risk o severe voltage problems during synchronization that has the potential to

damage equipment.


Caliornia: <http://www.energy.ca.gov/distgen/interconnection/guide_book.html >.

The NRECA Guide to IEEE 1547: <http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >.

Synchronizing Renewable Energy Sources in Distributed Generation Systems. <http://www.icrepq.com/ull-paper-icrep/334-ramos.

pd >.





95

5. Isolation Devices and Backeed

Issue: Backeed occurs when a portion o the electrical system is cut o rom a utility but a nonutility generator is

still eeding power into the system.

Utility Perspective: The acility must be able to disconnect every power source rom the grid. The larger the

generation source, the greater the danger and the more important it is that the generator and its load can be separated

rom the grid. Some installations have uses or breakers that can be energized rom two directions, so an isolation

device, usually a disconnect switch, must be present. An isolation device with a visible break that is lockable and

readily accessible must be located between the acility and the utility’s system. Simply inorming the utility that the

generator is ofine (not producing power) during an outage is not sucient protection. A lineman working on the

system, who believes it is completely de-energized, could easily be injured or killed.

In this way, the utility can guarantee that no power can fow rom that generator while utility personnel are

perorming maintenance or other activities that require a de-energized system. Without this ability to disconnect,

a generator can inadvertently inject power into the grid and “backeed” sections o the grid that need to be de-

energized. Backeed jeopardizes utility equipment, personnel, the public, and other operating sources.

Furthermore, the disconnect equipment should be labeled to warn utility personnel that the load-side contact may

still be energized even i the switch is in the open position. This isolation device and warning labels are critical or

employee saety and sae work practices.

Since backeed poses a real and serious risk, protection devices built into alternative energy acilities are oten not

recognized by the utility and utility personnel are not usually comortable with using such equipment in place o tried

and true methods.

Developer Perspective: The isolation device is not needed when an inverter is installed. Inverter technology—such

as the nonislanding inverter—can now ensure that the generator is not able to produce electrical energy, i the

utility’s line leading to the inverter is not energized. This technology negates the need or an isolation device.

Regulator Perspective: Energy rom distributed resources is critical to energy diversity, but all saety measures

must be in place to ensure worker saety.

Best Practices:

Several solutions to the problem o backeed exist, including manual disconnect switches, direct transer trips,

automatic bus transer switches, and nonislanding inverters.

A manual disconnect switch that can be locked is an eective way to ensure the system is de-energized beyond •

the PCC.

The direct transer trip o the grid tie can remotely disconnect multiple sources at one time.•

The automatic bus transer switch can be used to detect a loss o power beyond the PCC and open switches•

between the generator and the utility to avoid transerring power to the utility’s network beyond the PCC.

Nonislanding inverters are a new technology that have perormed well thus ar, but do not yet have a long track

record o reliability. Some utilities do not require an isolation device i the acility is using nonislanding inverters.

For projects less than 10 kW, such as small PV units, the isolation device requirement can be met by a plug (or twist-

lock plug), i it can be plugged back into the system only by utility personnel.





96

For larger units without the new inverter technology, an isolation device—usually an electrical disconnect switch—is

required and should adhere to the ollowing guidelines:

The distributed resource (DR) owner should use an external, visible, gang-operated disconnect switch that•

meets all applicable standards and is readily accessible, at all times, or operation and locking by the utility.

The switch should be externally operable without exposure to live parts.•

A power-operated switch should also have manual capabilities (can be opened manually).•

The disconnect switch should be within 10 eet o the PCC or between the DR and the PCC with a map•

showing the location o the switch permanently mounted near the PCC.

The switch must be rated or the DR acility’s voltage and current requirements.•

The switch must be clearly marked “Disconnect Switch” in large permanent letters.•

I the switch is energized rom both sides, it must have a marking indicating such.•

The switch should be installed, owned, and maintained by the owner o the DR acility.•

The operation o this switch is the utility’s responsibility. However, the utility must give appropriate notice— •

dened in its contract—to the acility prior to operation.

I the utility concurs, a draw-out circuit breaker can be used as an isolation device i it has pad locking at the•

draw-out position.

In Texas, various types o disconnecting devices are required.

Distributed Generation Interconnection Requirements

Closed

Transition

Single-

Phase

Three-Phase

Capacity

Feature ≤10 MW ≤50 kW ≤10 kW 10 kW –

500 kW

500 kW –

2 MW

2 MW –

10 MW

PUCT Rule Reerence §25.212(g) §25.212(d) §25.212

(e)(3)(A)

§25.212

(e)(3)

(B)

§25.212

(e)(3)(C)

§25.212(e)

(3)(D)

Interrupting devices

(capable o interrupting

maximum available ault

current)

X X X X X [4]

Interconnection disconnect

device (manual, lockable,

visible, accessible)X X X X X X

Generator disconnect

device X X X X X X

Notes: kW = kilowatt; MW = megawatt; PUCT = Public Utility Commission o Texas; X = Required eature; [4] = Systems exporting shall have

either redundant or listed devices.

Source: PUCT Distributed Generation Interconnection Manual 05/01/0, p. 3-3.





97


Consequences o Fault Currents Contributed by Distributed Generation. <http://www.pserc.org/cgi-pserc/getbig/publicatio/

reports/2006report/nimpitiwan_s20_report.pd >.

“The NRECA Guide to IEEE 1547.” <http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >.






98

6. Power Quality

Issue: Power quality is a major technical concern or utilities and their customers. “Clean” power is necessary or

the proper operation o electronic equipment and appliances. “Dirty” power can damage equipment, cause equipment

to malunction or ail, and/or shorten equipment lie. Some power quality issues include transients, harmonics,

power actor problems, direct current (DC) injection, and voltage fuctuations.

Transients are short, nonrepeating fuctuations in voltage or current. These are typically created by switching or

other momentary disruptions. Harmonics, on the other hand, repeat in each cycle. Harmonics are typically created

by nonlinear loads that switch current on and o. This discontinuous current draw is independent o the voltage and

creates overlapping sinusoids that can deorm the undamental waveorm.

Power actor is the ratio o true electric power (watts) to apparent power (kilovolt-ampere [kVA]). A power actor o

less than (or more than) 1 means the current and voltage waveorms are out o synch.

DC injection occurs when direct current is injected into an alternating current (AC) system by nonrotating

generators. This can damage transormers. The problem can be prevented by proper inverter design. IEEE 1547

limits DC injection to 0.5% o the inverter’s current output.

Voltage fuctuations reveal themselves in the orm o “ficker,” or the periodic fickering o incandescent light

sources. This typically occurs when cogeneration plants start up or shut down. IEEE 1547-2003 allows or a 5%

voltage fuctuation, but also notes that regardless o the standards, cogeneration operations should not “create

objectionable ficker or other customers.”

Utility Perspective: Utilities are concerned about voltage and requency disturbances, voltage ficker, and waveorm

distortion, so they require that cogeneration acilities install over/undervoltage and over/underrequency relays and

other protective devices.

Developer Perspective: All these protective devices are unnecessary and too costly. New technology, notably in

the generators themselves, meets all power quality requirements. Inverter manuacturers and others design their

products according to IEEE standards (519-1992). Utilities simply do not have the knowledge or experience with the

new equipment to recognize it is sae to interconnect to their system without additional protective devices.

Regulator Perspective: Power quality must be maintained at reasonable levels.





99

Best Practices:

Aspects o power quality, such as harmonic distortion, voltage sag, and ficker, are discussed in more detail in their

appropriate sections. Overall, though, two points are repeatedly made in interconnection plans. First, cogeneration

acilities shall in no way degrade the reliability or power quality o the distribution system. Second, it is the utility’s

responsibility to make sure the cogeneration acility is connected in a way that will prevent power quality problems.

The utility has the obligation to serve all its customers, and it must thereore make sure that generators connected to

their system do not interere with the power quality or operation o the system.

IEEE Standard 929-2000, Recommended Practice or Utility Interace o Photovoltaic (PV) Systems provides

guidance to insure compatibility o photovoltaic equipment that is connected in parallel with the electric utility.

By compatibility, IEEE means ensuring personnel saety, equipment protection, power quality, and utility system

operation.


Caliornia: <http://www.energy.ca.gov/distgen/interconnection/guide_book.html>.

Consolidated Edison: <http://m020-w5.coned.com/dg/specs_taris/EO-2115.pd >.

“Energy Quality in Voltage, Current and Power Signals.” <http://www.icrepq.com/icrepq-08/228-yebra.pd >.

Power Quality Impacts o Distributed Generation, Technical Report, <http://my.epri.com/portal/server.pt?space=CommunityPage&cac

hed=true&parentname=ObjMgr&parentid=2&control=SetCommunity&CommunityID=277&PageID=0&RaiseDocID=000000000001

008507&RaiseDocType=Abstract_id >.





100

7. Monitoring Provisions

Issue: I an alternative energy acility is exporting power to the utility, utilities must monitor the status o the

generator to properly operate the system and to protect workers. Monitoring is less necessary when the acility

does not export power to the utility and when reverse power relaying and/or power inverter logic prevents power

export. Specic types o monitoring equipment will be discussed in their appropriate sections below (e.g., requency,

voltage, and harmonics).

Utility Perspective: Facilities must be monitored or their connection status, real power output, reactive power

output, and voltage at the point o connection to ensure personnel saety and to avoid operating problems, especially

i the acility is exporting power to the utility.

Developer Perspective: Utilities oten insist on perorming the monitoring themselves and since there is a ee

associated with the monitoring, it increases the cost to develop the project. Furthermore, utilities are not always

amiliar with the equipment and insist that amiliar and more expensive monitoring equipment be used. Utilities do

not realize that most modern alternative energy acilities have multiunction microprocessor-based control systems

with the capacity to log and store data around ault conditions.

Regulator Perspective: Monitoring o equipment is important to maintain system integrity and is included in the

contract or tari between the developer and the utility.

Best Practices:

No monitoring is required or units under 200 kW. Units between 200 kW to 1 MW do not require monitoring i

protective relaying prevents the acility rom injecting energy into the utility’s network. All units over 1 MW require

monitoring.

The monitoring arrangement should include remote terminal units that provide supervisory control and data

acquisition (SCADA), communications equipment, telephone circuit protection equipment, transducers, potential and

current transormers, electrical energy and demand inormation, reactive power inormation, voltage inormation,

and alarms. The monitoring should display two seconds o data rom beore and ater any ault and should keep data

or the past 10 ault conditions.

The utility should also be able to receive signals or remote monitoring o the isolation device status and normal

voltage and requency levels and notice that the distributed generator is unable to connect to the utility network.


“Distributed generation: It’s all a matter o control” <http://pepei.pennnet.com/Articles/Article_Display.

cm?Section=CURRI&ARTICLE_ID=183681&VERSION_NUM=1&p=6>.

“The NRECA Guide to IEEE 1547” (page 37).

<http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >.

IEEE P1547.3: <http://grouper.ieee.org/groups/scc21/1547.3/1547.3_index.html>.

Power Quality and Equipment Monitoring in Distributed Generation o Multiple Wind Farm Sites or Hydro-Québec. <http://www.

cooperpower.com/library/TheLine/pd/08_08/Line_08_08_HQ.pd >.





101

8. Frequency

Issue: Maintaining requency within acceptable limits is critical to the proper operation o the grid. Higher or lower

requencies can lead to improper operation o customer equipment. Programmable logic controllers can malunction

and cause dangerous and/or costly problems in plants. Changes in requency even or small parts o AC waveorm

can cause catastrophic damage to transormers and capacitors, leading to their ailure.

In AC systems, the impedance o nonlinear loads is dependent on requency. Thereore, changes in requency can

change system loading and thereore aect voltage levels.

Utility Perspective: All sources o power must be able to maintain proper requency levels. To ensure that proper

requencies are maintained, utilities use under/overrequency sensing devices to de-energize circuits that threaten

system requency stability.

Developer Perspective: Facilities that are less than 30 kW have less impact on system operations and reliability.

These acilities can also quickly disconnect rom the utility. Furthermore, acilities over 30 kW actually improve the

utility’s reliability and should receive some credit or this unction.

Regulator Perspective: Frequency changes that can aect system operation or customer equipment must be avoided

Best Practices:

In New York, the cogenerating acility must have, as a minimum, an automatic disconnect device that is operated by

over/undervoltage and over/underrequency protection. For three-phase installations, the over/undervoltage protection

should be included or each phase and the over/underrequency protection on at least one phase. All phases o a

generator or inverter must disconnect when voltage or requency problems are detected.

In general, requency and voltage trip pickup settings or induction generators and static power converters can

be relaxed by the utility i they create too many nuisance trips or the acility. Frequency trip points should be

adjustable in increments, with a setting resolution o 0.5 hertz (Hz) or better.

In Texas, cogenerating units must not deviate more than +0.5 Hz or –0.7 Hz rom a 60 Hz base. The generator must

automatically disconnect its equipment rom the utility system within 15 cycles i these limits cannot be maintained.

The customer may reconnect when the utility system voltage and requency return to normal range and the system is

stabilized.

Trip times or requency fuctuation are based on a 60 Hz system and the assumption that there is a relatively low

penetration o alternative energy acilities.

The generator should ollow the voltage and requency imposed by the utility and should disconnect under abnormal

conditions as dened in the table below. Since the generator is not regulating voltage or current, the allowableoperating ranges are relatively wide.

I the acility is separated rom the utility (tripped ofine) due to a voltage or requency issue, the acility can

reconnect once the utility voltage and requency have returned to normal and have stabilized or two minutes (or a

shorter time i such an agreement is in place).





102

Voltage/Frequency Disturbance Delay & Trip Times

Range

(Frequency in Hz)

Trip Time

<59.3 0.25 15 (Trip)

59.3 – 60.5 Normal Operating Range

>60.5 0.25 15 (Trip)

Source: Public Utility Commission o Texas Distributed Generation Interconnection Manual 05/01/02, p. A7-5.




Texas: <http://www.puc.state.tx.us/rules/subrules/electric/25.212/25.212ei.cm> and <http://www.puc.state.tx.us/electric/business/dg/

dgmanual.pd >.





103

9. Voltage

Issue: On any utility grid, set voltage levels must be maintained to prevent damage to utility and customer

equipment. Current levels rise or all depending on the demand or power, but voltage levels are constant. Utilities

have equipment to detect and de-energize circuits that have voltages above or below acceptable levels.

Utility power systems are designed to deliver power rom main circuits to outlying areas. When cogeneration plants

are added, power may fow back along eeders. To address this undamental change, detailed engineering analysis

may be needed.

For example, voltage regulators are placed on lines to control voltage levels, which typically decline the urther the

line extends away rom a substation. But, i a cogeneration plant is injecting power into the utility’s system, voltage

levels near the end o a line may be higher. As a result, voltage protection schemes may need to be modied to

protect the utility and maintain voltage levels.

Utility Perspective: Correct voltage levels must be maintained. Voltage sensing equipment is used to identiy voltage

problems.

Developer Perspective: Small generating plants and plants that never or rarely export power to the utility will

have minimal or no eect on the utility. Complicated studies can be expensive and delay installation o generator

acilities.

Regulator Perspective: Proper voltage levels must be maintained, but studies and system modications are not

needed in all situations.

Best Practices:

There are several ways to look at the issue o voltage stability. The National Rural Electric Cooperative Agency

(NRECA) Guide to IEEE 1547 ocuses on voltage set-points, voltage monitoring, and concerns about nuisance

tripping.

I other ault detection equipment is in place, the abnormal voltage protection trip times can be set longer than

deault values, which will reduce nuisance trips.

Voltage Set-Points

Voltage set-points can be xed or eld-adjustable. Field-adjustable set-points give the utility operator some

discretion. Set-points cannot be changed or modied by either party at any time.

Distribution resources with a peak capacity o less than or equal to 30 kW will have xed or eld-adjustable set-

points. Distribution resources more than 30 kW will have eld-adjustable set-points.

Financial Issues and Best Practices Grid Stability and Protection Requirem




104

Voltage Detection

The voltages shall be detected at the PCC, i any o the ollowing occurs:

Aggregate capacity o the acility is less than or equal to 30 kW;•

The DR’s interconnection equipment is certied to pass a nonislanding test or the utility’s system; or •

I export o real or reactive power is not allowed and the aggregate capacity is less than 50% o the utility’s•

minimum annual integrated electrical demand or a 15-minute time period.

Sel-excited induction generators should have an overvoltage trip level below the equipment insulation level with an

instantaneous trip.

For transormers connected to the utility system by grounded wye-wye or single-phase installations, phase to neutral

voltage shall be detected.

For all other transormer interconnections, each phase-to-phase voltage shall be detected.

Interconnection Type Measure Phase-to Ground Measure Phase-to-Phase

Single-phase X

Three-phase, three-wire XFour-wire grounded X

Three-phase, our-wire

grounded

X

Three-phase acilities must have over- and undervoltage detection on all three phases.

In Australia, renewable energy acilities may have more latitude when it comes to voltages at the PCC.

Steady-State Voltage

The connection o wind power generation to a transmission network can aect voltage levels at the point o

common coupling. Utilities require that this steady-state voltage be within certain percentage limits o the

normal voltage to ensure that sensitive equipment not ail, malunction or trip. In Australia, these steady-

state limits range rom ±6% to ±10%, depending on the value o the normal voltage and whether or not the

location is rural, according to the Distribution Code 2006 and the Victorian Electricity System Code.

There are a number o methods or controlling steady-state voltage, which include:

on-line tap changing (OLTC) transormers;•

switched capacitors and reactors to provide reactive power support; or•

fexible alternative current transmission system (FACTS) devices, such as static VAr compensators•

(SVCs), synchronous condensers or static compensators (STATCOMs).

As wind power generation output can vary widely and at times relatively quickly, the impact on local voltages

needs to be managed within allowable ranges, and traditional tap changer transormers are generally too

slow to compensate.” (Capacity o the Victorian Electricity Transmission Network to integrate Wind Power,

prepared by Vencorp December 2007, p. 53.)

In Texas, trip times or requency fuctuation are based on a 60 Hz system and the assumption that there is a relatively

low penetration o alternative energy acilities.





105

The generator should ollow the voltage and requency imposed by the utility and should disconnect under abnormal

conditions as dened in the table below. Since the generator is not regulating voltage or current, the allowable

operating ranges are relatively wide.

I the alternative energy acility is separated rom the utility (tripped ofine) due to a voltage or requency issue,

the acility can reconnect once the utility voltage and requency have returned to normal and have stabilized or two

minutes (or a shorter time i such an agreement is in place).

Voltage/Frequency Disturbance Delay and Trip TimesRange Trip Time[2]

Percentage Voltage[1] Seconds Cycles

<70% <84 0.166 10 (Delay) & 10 (Trip)

70–90% 84–108 30.0 & 0.166 1800 (Delay) & 10 (Trip)

90–105% 108–126Normal Operating Range

105–110% 126–132 30.0 & 0.166 1800 (Delay) & 10 (Trip)

>110% >132 0.166 10 (Delay) & 10 (Trip)

[1] Voltage shown based on 120V, nominal.

[2] Trip times or voltage excursions were added or completeness by the Public Utility Commission o Texas Project No. 22318 Precertication

Working Group as the intent o 25.212.

Source: Public Utility Commission o Texas Distributed Generation Interconnection Manual 05/01/02, p. 3-2.


“Capacity o the Victorian Electricity Transmission Network to Integrate Wind Power,” <http://www.vencorp.com.au/index.

php?action=lemanager&older_id=926&pageID=7790&sectionID=8246>.







106

10. Voltage Ride-Through Capabilities or Wind Generation

Issue: Ride-through is the ability o a device or system (in this case, a generating acility) to continue operating

despite experiencing a voltage excursion due to a system ault. In the past, the resiliency o a generating acility

was not a big issue, since alternative energy acilities provided only small amounts o power to the grid. However,

acilities have become larger and now can supply more substantial power, creating the need or utilities to be sure

that minor disruptions in power will not trip generating acilities ofine.

Utility Perspective: Utilities must have some level o condence that large acilities will not be lost unnecessarily

during ault conditions. Careul analysis o a large part o the utility grid may be necessary to properly coordinate

protective relays and prevent acilities rom tripping ofine unnecessarily.

Developer Perspective: I it is let up to the utilities, there will be no end to the number o studies required to

connect a generating plant to the system. Small generating plants, whether they can ride through signicant aults or

not, will have little impact on the grid i they trip ofine and thereore should not be subject to expensive and time-

consuming studies.

Regulator Perspective: Ride-through studies may be warranted, i the loss o a large acility could have a signicant

impact on grid stability.

Best Practices:

A wind generating plant shall be able to remain online during voltage disturbances up to the time periods

and associated voltage levels set orth in the standard below. The LVRT [Low Voltage Ride Through] standard

provides or a transition period standard and a post-transition period standard. (United States o America

Federal Energy Regulatory Commission, 18 CFR Part 35 [Docket No. RM05-4-000 – Order No. 661-A],

Interconnection or Wind Energy, Appendix B)





107


ERCOT: <http://www.nrel.gov/wind/systemsintegration/pds/2005/muljadi_wind_ride_through_capability_predictions.pd >.

Federal Energy Regulatory Commission: <http://www.erc.gov/industries/electric/indus-act/gi/wind.asp#skipnavsub>.

IEEE: <http://www.uni-due.de/ean/downloads/papers/eltes2008b.pd >.

Western Electricity Coordinating Council:

<http://www.wecc.biz/documents/library/TSS/Voltage%20Ride-Through%20White%20Paper_6-13-07.pd >.

“Wind Power and Grid Reliability.” <http://www.amsc.com/newsroom/documents/AMSC_Wind%20Power%20and%20Grid%20

Reliability_0208.pd >.





108

11. Area Utility System Fault Detection and Clearing

Issue: Alternative energy acilities can have a considerable impact on the utility system’s ault-clearing capabilities,

depending on the size and type o the acility. Once an alternative energy acility is connected to the utility’s circuit,

it is capable o supplying current to a ault in the utility’s circuit. During ault conditions, it is essential that the

acility be disconnected rom the utility.

There are our types o aults: single-phase-to-ground, phase-to-phase, double-phase-to-ground, and bolted three-

phase.

The larger the ault-current contribution, the easier the ault is to detect. It is possible or a ault to occur that draws

little power rom the cogeneration acility. These types o aults may go undetected and that is why it is critical that

the cogeneration plant be careully integrated into the utility’s grounding system.

Furthermore, i the alternative energy acility contributes ault current to the utility, the utility’s coordination o

protective devices could be adversely aected and the ault current could damage equipment. It may be necessary to

recongure protection schemes ar beyond the point o common coupling (PCC).

There are three main ways a acility can detect and respond to aults:

local detection o the utility’s ault at the acility and isolation o the acility;•

remote detection o the utility’s ault and isolation o the acility via direct transer tripping; and •

local detection o the ault due to the utility’s response to the ault and isolation o the acility.•

The manner in which the alternative energy acility can detect a ault depends on the transormer winding

conguration between the alternative energy acility and the utility. The most common receiving transormer

connections are either delta-grounded wye or foating wye-delta. These connections do not contribute directly to

primary ground current and require potential transormers or another source o ground current to detect ground

aults.

Utility Perspective: The alternative energy acility must stop energizing a circuit when a ault (including a ground

ault) is detected, in order to protect the utility’s equipment and personnel and maintain system reliability.

Developer Perspective: The alternative energy acility will cease to energize the utility’s lines when a ault is

detected, but should not be responsible or responding to aults that cannot be detected, such as a low impedance

ault on an adjacent eeder that causes a perceptible voltage drop. Furthermore, most utilities’ ault-detection

devices detect most o their own aults and can even detect persistent aults in the cogeneration acility’s circuits, so

additional protection is not necessary.

Regulator Perspective: System reliability and sae work practices must be maintained.

Best Practices:

The alternative energy acility must have adequate protection and control equipment. At a minimum, this should

include an interrupting device with sucient capacity to interrupt the maximum available ault current at the

location, sized to all standards and installed according to all codes.





109

The various ault protection devices and the coordination between them should be reviewed to minimize the amount

o the system that must be isolated or aults. Coordination works best when the protective devices have similar

operating characteristics.

I the acility relies on the utility’s ault detection devices, communication rom these devices to the acility’s

interconnection system is critical and can be achieved with a dedicated communication channel, like the ones used in

a direct transer trip scheme. However, or small acilities with low ault-current contributions, the cost o adding a

dedicated communication channel is prohibitively expensive.

In this case, the cogeneration acility can use an indirect detection method. The utility detects a ault and islands the

cogeneration acility and the ault. The alternative energy acility then detects the island and stops energizing the

circuit. The main dierence between the direct and indirect ault detection is the time lag (up to two seconds) or the

island or open-phase detection.

Generator/Inverter

The type and setting o the interrupting device depend on the nature o the alternative energy acility, the type o

technology used, and the method o integration with the utility’s system.

Synchronous Interconnections

A synchronous generator requires special protective equipment to isolate it rom the utility under ault conditions.

Synchronous generators can produce ault currents or extended periods o time and they can be as high as six times

the generator ull-load current.

Protective relays to detect multiphase aults should be located on the generator or generator breaker. The relays can

be either voltage-controlled or voltage-restrained overcurrent relays.

Induction Interconnections

Whether an inductor can provide ault current during a sustained ault depends on how it is congured and excited.

I the only source o excitation is the utility system, the induction generator will not be able to produce phase ault

current, but may be able to supply phase-to-ground current.

I the VArs (reactive volt-amperes) are supplied by the induction generator, it may supply phase ault current and will

likely require protection like that used or synchronous generators.

Inverter Interconnections

Inverters are unable to supply excessive currents under ault conditions, and ault detection schemes that rely on

overcurrent principals are not eective. The acilities with inverter interconnections must use other detection

schemes to isolate rom the ault such as voltage-sensing circuitry within the inverter or detection o o-requency

operation.


“Eect O Adding Distributed Generation To Distribution Networks Case Study 3: Protection coordination considerations with

nverter and machine based DG.” <http://canmetenergy.nrcan.gc.ca/chier.php/codectec/En/2006-147/2006-147e.pd >.

“Impacts O Distributed Generation On Earth Fault Protection In

Distribution Systems With Isolated Neutral.” <http://www.cired.be/CIRED07/pds/CIRED2007_0107_paper.pd >.


SRP: <http://www.srpnet.com/electric/pdx/gen_guidelines.pd >.





110

12. Faults and Reclosing Coordination

Issues: Utilities oten use automatic reclosing devices such as reclosers and circuit breakers to limit the disruption

to customers. Since most aults on the overhead distribution circuits are temporary, they can normally be cleared

quickly i the aected circuit is quickly disconnected rom the system. When the aected area is de-energized, any

arcing created by the ault will extinguish and service can be quickly restored. It is critical that the alternative energy

acility quickly stop energizing the aected circuit prior to reclosure by the utility to ensure the ault completely

clears, to avoid out-o-synchronism conditions, and to limit use trips and equipment damage.

Coordination is thus critical to prevent damage to both the utility’s and alternative energy acility’s equipment.

Reclosing is coordinated when one or more o the ollowing are met:

The alternative energy acility is designed to stop energizing the utility system beore reclosing.•

The utility’s reclosing device will not begin until the alternative energy acility has stopped energizing the•

system.

The voltage phase-angle separation magnitude across the isolation device o the alternative energy acility•

is less than one quarter o a cycle when reclosing, such as through a synchrocheck unction in the relaying

scheme.

Utility Perspective: Alternative energy acilities on the utility’s distribution network can energize it and may

interere with the attempts to reclose and restore the circuit, which could lead to a much longer and larger outage or

consumers. An out-o-phase reclose can lead to

Severe electromechanical torques that can damage equipment;•

Severe transient overvoltage surge on the eeder which can lead to a ailure o surge arresters and customer •

surge protectors, and customer load device damage; and

Large magnetic inrush currents in transormers and motors connected to the eeder, which can cause unwanted •

operation o uses and circuit breakers in the utility and customer systems.

The installation o distributed resources negatively impacts normal reclosing practices; however, it is not possibleto change these practices without lowering the level o service to customers. The only way to integrate distributed

resources is to modiy the system, and the developer should pay or these modications.

Furthermore, energizing an area the utility de-energized could jeopardize personnel saety. The utility aces an

additional problem o liability or damage to consumers’ equipment and reduced reliability.

Developer Perspective: Utilities have dierent reclosing practices and the timing o the reclosing can vary widely.

The lack o standardization can lead to uncertainty when designing the DR acility and, depending on the type o

reclosing device, could lead to damage o the generating equipment. The aster the reclosing device operates, the

more impact it will have on the alternative energy acility. Many utilities insist the alternative energy acility pay

or unnecessary and expensive modications to their systems, particularly with reclosers and protection, prior to

interconnecting.

Distributed resources’ impact on the utility depends on the size and type o the unit. Small units will have limited to

no impact on the utility and onerous and expensive protection schemes should not be required.

Regulator Perspective: Coordination o protective devices, like reclosers, is imperative to protect the utility’s,

developer’s, and customer’s equipment.





111

Best Practices:

IEEE 1547 requires that the alternative energy acility must stop energizing any utility circuit to which it is

connected, i the utility de-energizes the circuit. This requirement allows the alternative energy acility to ignore

aults seen on other circuits and relieves it rom responding to aults the utility does not see.

Synchronous Interconnections

I the ault involves multiple phases, the synchronous interconnections can have ault currents or extended periods

o time.

Induction Generators

Induction generators will usually cease to produce current during a ault due to the loss o VArs.

Transer Trips

I the control devices at the distributed resource cannot separate rom the eeder prior to the eeder reclosing,

additional protection may be required. Direct transer trips, undervoltage permissive relaying at the eeder breaker,

or automatic line sectionalizing devices can all be used. Synchrocheck relaying is another option; however, it can

increase the reclosing time, so it might not be a good option or all acilities.

Feeder Reconfguration

Many utilities use loop designs or their eeders by joining two eeders with a normally open recloser. This

conguration creates problems when connecting distributed resources as coordination must now be maintained at

all eeders, raising the price or the developer. One way to avoid the additional cost, while protecting eeders, is to

prohibit the acility rom generating on the alternate eeders.

Reclosing Scheme Modifcation

Utilities can modiy their reclosing schemes to ensure the alternative energy acility has been isolated prior to

reclosing. One way to do this is by controlling the circuit breakers and reclosers by monitoring the voltage on the

load side o these devices. In this way, the utility can determine i voltage is present and delay the reclose until it

detects next-to-zero voltage.

Voltage monitors are necessary only i the alternative energy acility could possibly energize an unintentional island

prior to the rst attempt to reclose. A study will be needed to determine the utility’s ratio o peak to minimum load

to compare it with the size o the alternative energy acility. In general, rural lines in the United States typically have

a 5:1 ratio o peak to minimum load, suburban lines are 4:1, and urban lines are 3:1. The utility will then apply a

saety actor so that the remaining load isolated with the alternative energy acility is two to three times more than

the maximum generation, which will lead to rapid overload o generation and operation o protection.


“Caliornia Interconnection Guidebook.” <http://www.energy.ca.gov/distgen/interconnection/guide_book.html>.







112

13. Grounding

Issue: Incorrect grounding can cause overvoltages or disrupt the coordination o the ground ault protection o

the utility’s system. The concern is that during temporary islanding conditions, the generating acility may have

damaging phase-to-ground voltages during the time the island orms and when it is detected and de-energized by the

acility operator. I a generation island that serves customers on a aulted system develops, customers on unaulted

phases could see massive voltage increases, which could damage customer equipment.

Utility Perspective: Utilities also want to be sure the cogeneration acility can detect ground aults and avoid

resulting problems.

Developer Perspective: An interconnection that is eectively grounded can signicantly desensitize the ground

ault protection on the utility distribution system.

Regulator Perspective: Proper and coordinated grounding schemes are necessary to ensure sae and reliable

operation.

Best Practices:

Grounding practices can be quite complex, but there are several good sources o inormation. The Application Guide

or Distributed Generation Interconnection: 2006 Update, The NRECA Guide to IEEE 1547 discusses grounding at

length. Some recommendations ollow.

For multigrounded neutral systems, all acilities large enough to sustain an island must be an eectively grounded

source, as this design will limit voltage swells during a ault.

For interconnections to primary eeders o three-wire grounded or ungrounded systems, there should be no metallic

path to ground rom the primary eeder except through suitably rated surge arresters, high-impedance devices used

only or ault detection purposes, or both.

For installations with both parallel and isolated operating modes, the grounding system should be designed to be

eective in both modes as per IEEE 446-1995.

Consolidated Edison’s Handbook o General Requirements or Electrical Service to Dispersed Generation

Customers also provides specic guidelines on pages 21 and 22:

In order to assess the generator’s grounding as it appears to the [utilities] distribution system the generator

grounding design must include details describing the neutral grounding arrangement o the generator

and the winding conguration/grounding arrangement o any interace transormers. In cases where

the customer wishes to use its existing step-down transormer that has been serving their load as the

interace to the [utility] distribution system, it is important to recognize that an existing transormer that is perectly suitable or serving load at a site may not always be satisactory to serve as a generator interace

transormer because it may not provide proper grounding with respect to the company distribution system.

The installation o a generator at a customer site may necessitate changing out the existing transormer with

a new transormer that has appropriate grounding or adding a second transormer that is meant just or the

generator.





113

Another important consideration is that the generator installation, depending on where it ties into the

customer’s system, will need to provide grounding that complies with all applicable requirements o the

National Electrical Saety Code (NESC), National Electric Code (NEC) and the [utility]. The proper method

o generator system grounding to be used with a particular power system interconnection point is unique or

each installation. Table [below] indicates the [utility’s] distribution system grounding methods.

Consolidated Edison’s System Grounding Methods

System Nominal

Voltage*Phase / #Wire

Transormer

Connection Primary /

Secondary

Grounding

Method

120 / 208

208Y / 1203 Phase / 4 Wire

Delta / wye-ground Multigrounded

Solid neutral

265 / 460

480Y / 277 3 Phase / 4 WireDelta / wye-ground

Multigrounded

Solid neutral

2,400 / 4,160

4,160Y / 2,4003 Phase / 4 Wire

Wye-ground / wye-

ground

Multigrounded

Solid neutral

13,800 3 Phase / 4 Wire Delta/ Wye** Unigrounded

27,000 3 Phase / 4 Wire Delta / Wye**Unigrounded

33,000 3 Phase / 4 Wire Delta / Wye **Unigrounded

*Reers to transormer secondary side.

**Transormer wye neutral grounded via reactor.

Source: Handbook o General Requirements or Electrical Service to Dispersed Generation Customers File: Application And Design Manual No. 4

Field Manual No. 16, Section 4, p. 74.



“The NRECA Guide to IEEE 1547.” (pages 22-24): <http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >





114

14. Momentary Paralleling Allowed

Issue: Momentary paralleling occurs when a customer’s load is transerred rom the utility’s system to the backup

generator or vice versa. During the transer, the load is momentarily supplied by both sources. This is done to

ensure that power is continuously supplied to the load. For example, a acility with cogeneration capabilities might

want to run the generator to lower its peak and switch to its own generation.

Utility Perspective: Some acilities may not require additional protective equipment to allow momentary paralleling

Furthermore, the generator must provide all necessary equipment and procedures to eliminate the risk o long-term

paralleling, unless the generator already has in place equipment to do so saely.

Developer Perspective: Momentary paralleling should be permitted.

Regulator Perspective: The technical issues concerning momentary paralleling should be worked out as part o the

pre-interconnection study.

Best Practices:

While system protection during paralleling is required, it does not have to be as rigorous as other system protection

schemes, as long as paralleling is limited to one second or less.

For example, regulations in Texas clearly state that paralleling requirements do not apply to paralleling that occurs

or only a brie period o time.


Conectiv: <http://www.delaware-energy.com/Download/NEM.pd >.






115

15. Protection rom Electromagnetic Intererence

Issue: Hand-held transceivers such as cell phones used near a static protective relay can produce high eld-strength

electromagnetic radiation that can aect the relay’s perormance.

Utility Perspective: All static protective relays should be able to withstand electromagnetic intererence o 35 volts

per meter as stated in IEEE Std C37.90.2-1995. The tests should be applied to all interconnection system equipment

with protective or control components such as relays, programmable logic controllers, and computers.

Developer Perspective: Standard equipment already meets these requirements.

Regulator Perspective: Equipment used by the cogenerating acility must meet these standards.

Best Practice: When designing equipment or protection against electromagnetic intererence, use discrete

requency steps throughout the test requency range as an alternative to continuous sweeps o the pertinent

requencies.


“The NRECA Guide to IEEE 1547” (pages 43-44): <http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >.





116

16. Surge Withstand Perormance

Issue: Voltage and current surges in AC power circuits can cause operational problems and ailures in systems and

equipment. Surge voltages occur rom lightning on the power system and system switching transients.

More sensitive equipment and technologies such as semiconductor devices have become much more common

in recent years, leading to greater concern over the ability to withstand surges. Furthermore, newer technology

inverters based on pulse-width modulation can set up standing waves with refected harmonics rom the operation

o the inverter (the refections are additive). These inverters operate at much higher requencies, which create the

standing waves that have been known to cause inverters and other equipment to ail.

Utility Perspective: The alternative energy acility’s interconnection system must be held to the same standard o

perormance as generators, protective relaying, and other electrical equipment to protect the utility’s distribution

network and equipment.

Developer Perspective: Costs to install alternative energy acilities should be kept to a minimum.

Regulator Perspective: Reliability must be preserved.

Best Practices:

Several steps are needed to address potential problems caused by surges. First, the system (including the alternative

energy acility) should be designed so harmonics do not cause voltage/current spiking. This can be accomplished

by changing the operating requency o the inverter, or applying lters, capacitors, or inductors to change the system

tuning.

Second, the alternative energy acility and utility system must be properly protected rom direct and nearby lightning

strikes.

Third, switching transients are created in numerous ways and result in surges o various intensities. The owner o the

equipment being switched is responsible or system protection.

Most states require that acilities meet existing ANSI/IEEE standards. For example, Consolidated Edison’s

Handbook o General Requirements or Electrical Service to Dispersed Generation Customers states on page 19:

Equipment rated less than 1000 volts shall be tested in accordance with the Guide on Surge Testing or

Equipment Connected to Low Voltage AC Power Circuits, ANSI/IEEE C62.45, to conrm that the surge

withstand rating is capability is satised or the product’s surge level rating as dened in Recommended

Practice on Surge Voltages in Low Voltage AC Power Circuits, ANSI/IEEE C62.41.2.

Equipment rated greater than 1000 volts shall be tested in accordance with manuacturer or systemintegrator’s designated applicable standards. For equipment signal and control circuits use Standard Surge

Withstand Capability (SWC) Tests or Protective Relays and Relay Systems, IEEE C37.90.1.





117


Consolidated Edison Company O New York, Inc.: <http://q050-w5.coned.com/dg/specs_taris/EO-2115.pd >.



Recommended Practice on Surge Voltages in Low Voltage AC Power Circuits, ANSI/IEEE C62.41.2.

Standard Surge Withstand Capability (SWC) Tests or Protective Relays and Relay Systems, IEEE C37.90.1.





118

17. Limitation o DC Injection

Issue: Alternative energy acilities with inverters without transormers may inject DC current into the utility circuits.

This increases the peak to hal o the AC waveorm (decreasing the peak to the other hal) and can cause transormer

saturation. Even small amounts o direct current can lead to dangerous magnetic saturation o transormer cores and

cause signicant heating—potentially leading to transormer ailure or greatly shortening the operational lie o the

transormer.

Utility Perspective: DC injection must not damage utility equipment.

Developer Perspective: DC injection is a concern only with inverters, which can be tested by the manuacturer.

Regulator Perspective: The acility must not negatively impact sae and reliable operation o the utility system.

Best Practice:

IEEE 1547 (Section 4.3.1) requires that DC injection not exceed 0.5% o the ull rated output current o the acility

where it connects to the utility system.







119

B. Equipment Requirements

Issue: The equipment necessary to successully operate and integrate an alternative energy acility with a utility grid

varies rom site to site, but all aspects o a acility’s installation can be greatly simplied when standard equipment is

used.

Utility Perspective: Utilities require that the developer’s equipment meet certain standards (IEEE, NationalElectrical Code, etc.), but some leave the overall design o the acility up to the developer. Other utilities create

specic lists o the types o equipment the acility must have, usually based on generator output.

Once a list o required equipment is created, the utility can proceed with more condence that the system will work

reliably.

Developer Perspective: While developers may not agree that all the listed equipment is really necessary, all

developers will be on equal ooting as they all have to have the same types o devices.

Regulator Perspective: Using a standard equipment list simplies the application/approval process and provides

an incentive to developers to use “pre-approved” equipment. For example, the Public Utility Commission o Texasspecies what type o interconnection equipment is required or generators based on output which eliminated

arguments about necessary equipment and simplied engineering plans.

Distributed Generation Interconnection Requirements

Closed

Transition

Single-

Phase

Three-Phase

Capacity

Feature ≤10 MW ≤50 kW ≤10 kW 10 kW–

500 kW

500 kW–

2 MW

2 MW–

10 MW

PUCT Rule Reerence §25.212

(g)

§25.212(d) §25.212

(e)

(3)(A)

§25.212

(e)(3)

(B)

§25.212

(e)

(3)(C)

§25.212

(e)(3)(D)

Interrupting devices

(capable o interrupting

maximum available ault

current)

X X X X X [4]

Interconnection disconnect

device (manual, lockable,

visible, accessible)X X X X X X

Generator disconnect

deviceX X X X X X

Overvoltage trip X X X X X X

Technical Issues and Best Practices Equipment Requirements




120

Undervoltage trip X X X X X X

Over-/under-

requency tripX X X X X X

Synchronizing check

(A: Automatic, M: Manual) A A/M [1] A/M [1] A/M [1]

A

[1]

A

[1]

Ground overvoltage or

overcurrent trip [2] [2] [2] [2]

Reverse power sensing [3] [3] [3]

I exporting, power

direction unction may

be used to block or delay

underrequency trip

X X

Automatic voltage regulator [1]

Telemetry/transer trip X

[1] Required or acilities with stand-alone capability.

[2] May be required by TDU; selection based on grounding system.

[3] Required, unless generator is less than applicant minimum load, to veriy nonexport.

[4] Systems exporting shall have either redundant or listed devices.

Notes: kW = kilowatt; MW = megawatt; PUCT = Public Utility Commission o Texas; X = Required eature; blank = not required.

Source: PUCT, http://www.puc.state.tx.us/electric/business/dg/dgmanual.pd , p. 3-3.

Some interconnection requirements list specic manuacturers and devices that meet requirements. For example,

New York State has a list o “certied equipment” that must meet all unctional requirements o IEEE Std. 1547 and

must be protected by utility-grade relays using utility-approved settings.





121

Following are two examples rom the equipment list:

Manuacturer Beckwith Electric

Model No. M-3520

Date o Approval 10/22/03

Firmware Version

D0060V03.00.06 to

D0060V03.99.99

Testing Agency Underwriters Laboratories

Test Report E128716-03CA33157

Date o Report 9/24/03

Device DescriptionIntertie/Generator

Protection Relay

Manuacturer Capstone Turbine

Model No. 65

Date o Approval 7/26/06

Testing Agency Underwriters Laboratories, Nemko

Device Description65kW, 480V, Three-Phase

Microturbine

Source: http://www.dps.state.ny.us/08E1018/SIRDevices.pd .


Distributed Generation Interconnection Manual Public Utility Commission o Texas.

<http://www.puc.state.tx.us/electric/business/dg/dgmanual.pd >.

Public Utility Commission o Texas. Technical Requirements or Interconnection and Parallel Operation o On-Site Distributed Generation 25.212. <http://www.puc.state.tx.us/rules/subrules/electric/25.212/25.212ei.cm>.

New York, Department o Public Service Certied Interconnection Equipment. <http://www.dps.state.ny.us/08E1018/SIRDevices.

pd >.





122

1. Isolation Device (disconnect switch)

Issue: The acility must be able to disconnect every power source rom the utility to avoid jeopardizing utility

equipment, personnel, the public, or other operating sources.

Utility Perspective: Some installations have uses or breakers that can be energized rom two directions; thereore,

an isolation device, usually a disconnect switch, must be present to disconnect rom all sources. A visible-break,

lockable, and readily accessible isolation device must be located between the acility and the utility’s grid to

allow the circuit to be closed when the utility has maintenance or other activities that need a de-energized system.

Furthermore, it should be labeled to warn utility personnel that the load-side contact may still be energized even i

the switch is in the open position. This isolation device and warning label are critical or employee saety and sae

work practices.

For small, residential generation, the meter can act as the disconnect switch.

Regulator Perspective: Although energy diversity hinges on the utilization o distributed resources, all saety

measures must be in place to ensure worker saety.

Developer Perspective: The isolation device is not needed when an inverter is installed. Inverter technology—such

as the nonislanding inverter—can now ensure that the acility is not able to generate electrical energy i the utility’s

line leading to the inverter is not energized. This technology negates the need or an isolation device.

Best Practices:

The particular conguration o the equipment necessarily designates which type o disconnecting device is most

appropriate; however, our principles should be considered.

Dependability: A high probability o clearing aults that occur on the utility’s system.1.

Security: A low probability o interrupting the circuit unnecessarily.2.

Selectivity: Ability to discriminate, so as not to isolate any area beyond the PCC.3.

Speed: Operation as rapidly as possible, consistent with coordination requirements, to minimize damage.4.

I the alternative energy acility has a nonislanding inverter, an isolation device is not necessary. For projects less

than 10 kW, such as small PV units, the isolation device requirement can be met by the meter.

For larger units without the new inverter technology, an isolation device—usually an electrical disconnect switch—

should adhere to the ollowing guidelines:

The acility owner should use an external, visible, gang-operated disconnect switch that meets all applicable•

standards and is readily accessible or operation and locking by the utility at all times.

The switch should be externally operable without exposure to live parts.•

I the switch is power operable, it should also be able to be opened manually.•

The disconnect switch should be within 10 eet o the PCC or between the acility and the PCC with a map•

showing the location o the switch permanently mounted near the PCC.

The switch must be rated or the DR acility’s voltage and current requirements.•

The switch must be clearly marked “Disconnect Switch” in large permanent letters. Also, a warning label must•

be installed or the benet o reghters.

I the switch is energized rom both sides, it must have a marking indicating such.•





123

The switch should be installed, owned, and maintained by the owner o the acility.•

The operation o this switch is the utility’s responsibility. However, it must give appropriate notice—dened •

in its contract—to the acility prior to operation.

I the utility concurs, a draw-out circuit breaker can be used as an isolation device i it has pad locking at the•

draw-out position.

Sources and For More Inormation:“Improving Distribution System Reliability By Means O Distributed Generation.”

<http://www.cired.be/CIRED07/pds/CIRED2007_0070_paper.pd >.

“The NRECA Guide to IEEE 1547.”

<http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >.





124

2. Paralleling Device

Issue: Parallel operation occurs when the generating acility produces AC power while electrically interconnected

with the utility distribution network. A parallel connection allows the customer to serve its load either with its own

generator, with utility power, or rom both sources simultaneously.

To operate in parallel, the generating acility must match the voltage and requency o the utility’s distribution

system. Most distributed generators and all renewable energy acilities, which can be either exporting or

nonexporting acilities, will operate in parallel. Nonexporting acilities consume all energy created to meet the

customer’s load, while exporting acilities send some power to the grid.

The paralleling device is located at the PCC where the two systems meet and coordinates with other protective

devices to ensure that voltage and requency do not deviate rom the utility distribution system.

Utility Perspective: In order to protect the system rom damage due to voltage, a paralleling device must be

installed. The device should have consistent opening and closing times to limit damage and provide better

coordination with the utility. A synch-check device must be installed on synchronous generators.

Developer Perspective: Paralleling equipment is necessary only when synchronous generators are used.

Regulator Perspective: Paralleling devices are critical to the sae operation o the system and must be careully

selected so that they meet all requirements.

Best Practices: The paralleling device should have consistent opening and closing times and must be able to

withstand 220% o the rated voltage across the open contacts. On synchronous generators, a digital, auto paralleling

system should be in place and it should be supervised by synch-check relays.



“Technical Requirements or Interconnection and Parallel Operation o Distributed Generation: Single Phase less than or equal to

25kW, Three Phase less than or equal to 300kW.” <http://www.puco.ohio.gov/emplibrary/les/smed/Technical_Requirements.pd >.





125

3. Customers Responsible or Protecting Their Equipment

Issue: When an alternative energy acility is connected to a utility system, numerous situations can occur that could

potentially damage the alternative energy acility’s equipment. For example, i a developer’s synchronous generator

is islanded and then reconnected out o phase, catastrophic damage to the generator can result.

Utility Perspective: The utility species what equipment is necessary or the protection o its system. The acility is

responsible or protecting its own system.

Developer Perspective: Excess protective equipment/procedures are costly.

Regulator Perspective: It is the acility’s responsibility to protect its own equipment.

Best Practices:

The alternative energy acility should be solely responsible or protecting its own equipment.

In Caliornia,

Rule 21 only covers those Protective Functions that serve to protect the utility, not those that protect the

Generator or owner’s acilities.

Even though Rule 21 does not cover Generator protection, the manuacturer should incorporate general

protection and saety practices in the Generating Facility design in order to protect the Generating Facility,

personnel, and other equipment.

The Conectiv guidelines concur:

The Generator Owner will be responsible or protecting its own generating and interconnection equipment

in such a manner so that Company system outages, short circuits, single phasing conditions or other

disturbances including zero sequence currents and erroresonant over-voltages do not damage the Generator

Owner’s generating equipment.


“Caliornia Interconnection Guidebook.”: <http://www.energy.ca.gov/distgen/interconnection/guide_book.html>.

Conectiv: <http://www.delaware-energy.com/Download/NEM.pd >.





126

4. Requirements or Metering/Meters

Issue: In order to properly account or energy exported to and imported rom the utility system, alternative energy

acilities must have proper metering. Standard meters accurately measure only power sold to the customer, not power

exported to the utility system.

Utility Perspective: Facilities must have reliable meters or their acilities, and the utility should be responsible or

the installation, reading, and maintenance o those meters.

Developer Perspective: Proper metering is important, but developers should have some latitude in selecting the type

o meter.

Regulator Perspective: The issue o metering should be part o the application process.

Best Practices:

CA Rule 21 states that all acilities must be metered and that the ownership, installation, operation, reading, and

testing o these meters must be done by the electric utility, unless the regulatory commission authorizes another

party.

Larger generation acilities will require more complex metering. The Salt River Project (SRP) requires reactive

metering or generators greater than 50 kW.

Facilities that will be selling power back to the utility will require additional metering equipment. Additional

metering is also required or TOU contracts.

When large generating acilities are involved, metering can become quite complicated and may require the

installation o potential transormers, current transormers, uses, etc. In these cases, detailed metering schemes

will have to be created by the utility or the cogeneration acility. The acility is responsible or providing, installing,

and maintaining all the wiring and miscellaneous equipment or the metering, but not the actual metering equipment

(meters, metering transormer, etc).


Caliornia Interconnection Guidebook: <http://www.energy.ca.gov/distgen/interconnection/guide_book.html>.

“Generating Your Own Electricity: Net Metering,” Public Utilities Commission o Ohio.

<http://www.puco.ohio.gov/PUCO/Consumer/Inormation.cm?id=8510&terms=metering&searchtype=1&ragment=False>.

Handbook O General Requirements For Electrical Service To Dispersed Generation Customers. <http://Q050-W5.Coned.Com/Dg/

Specs_Taris/Eo-2115.Pd >.






127

5. Telemetering/Communication Channels

Issue: Telemetering is the electronic transmission o real-time metering data to the utility. For larger generating

acilities, utilities may require alternative energy acilities to communicate real-time inormation about generator

status. Utilities want this inormation to better assess the ongoing operation o their system.

Utility Perspective: This inormation is necessary to properly integrate the alternative energy acility into the grid.

Since telemetering is a necessary part o cogeneration, the developer should pay or it.

Developer Perspective: Telemetering is just another unnecessary expense as there are other ways to collect

operations data and properly assess charges.

Regulator Perspective: Whether or not telemetering is required varies, and the issues (cost, ownership, access to,

and operation o equipment) are complicated.

Best Practice: For large generators, telemetering may be required.

SRP requires telemetering any time a transer trip scheme is necessary. This includes generators (or an aggregate

o generators) that can supply the minimum load o the eeder or support an islanded section o the eeder.

Telemetering is also necessary i the generator sells power to the grid or is remotely controlled or dispatched by SRP.

Likewise, Caliornia may require telemetering or large generators, allowing the utility to better monitor their impact

on the distribution system.








128

6. Net Metering

Issue: “Net metering” is a term used to describe the “netting” o excess electricity that a acility generates with that

o those electrons consumed in a contractual relationship with the utility. I a acility generates more electricity than

it uses, the electricity is credited to the acility’s account. Utilities may or may not pay or net excess power provided

to the grid. In Caliornia, only solar electric and wind generators less than 1 MW in size are eligible or net meter-

ing.

In addition, there is a common misconception that the utility will pay customers or the amount o the excess energy.

Instead, excess electricity rom the PV system is “banked” with the utility, eectively spinning the customer’s meter

backward. When the customer consumes more electricity than is produced (i.e., takes electricity rom the grid), the

meter spins orward—so the utility grid acts as a “bank” or the energy. The transaction occurs at the retail rate or the

appropriate TOU rate or customers with TOU meters, which record their time-o-day usage (and thus they are billed

or energy at dierent rates on that basis). At the end o a yearly billing cycle, any net excess energy sent to the utility

system is “zeroed out” and credited to the utility; the customer is not paid or this energy.

Some utilities, like SMUD, do pay or excess power. SMUD “cashes out” net power supplied to the grid by some

customers. These customers are paid a wholesale rate. Note that SMUD is not under Caliornia’s net metering law.

Utility Perspective: Standard net metering programs can be created to simpliy the billing/accounting process. Also,

net metering is a subsidized program and thereore should have dened limits.

Developer Perspective: Net metering is desirable and should be oered or all acilities, not just renewable energy

sources.

Regulator Perspective: Net metering encourages the installation o cogeneration, and standard contracts can be cre-

ated.

Best Practices:

Dierent utilities deal with this issue in dierent ways. Having a net metering standard will simpliy the situation.

West Bengal

Net metering has been adopted or rootop solar PV systems in West Bengal. The West Bengal Electricity

Regulatory Commission allows net metering in its latest order on solar power. The order states that the slab tari

shall be applicable or the net energy supplied by the licensees in a billing period i the supplied energy by the

licensees is more than the injected energy by the roo-to-solar PV sources o the consumers, ater taking into account

the amount o energy carried orward rom an earlier billing period o that nancial year. The regulator may consider

mandating the installation o a generator meter or import-export meter to determine compensation payable to the

investor. Due to the lower taris or residential consumers in comparison to commercial and industrial taris, net

metering needs to be studied in detail as an option or such consumers in the uture.

SDG&E

100% o total annual consumption o energy can be “stored” on the grid. At this time, any stored surplus energy can

not be sold back to SDG&E at the end o the 12-month cycle. This annual program automatically renews at the end

o each 12-month cycle.





129

SCE

Generating acility customers may be required to install net generating output meters to

evaluate, monitor, and veriy output;•

determine applicable standby and nonbypassable charges as dened in SCE’s taris;•

satisy applicable Caliornia Independent System Operator reliability requirements; and •

plan and operate distribution systems.•

However, a generating acility does not need to install these meters i less intrusive and/or more cost-eective options

are available, as long as the meter can provide the appropriate generator data to SCE. The generating acility may

opt to have SCE estimate its load data in accordance with SCE’s applicable taris to determine or meet applicable

standby and nonbypassable and other applicable charges and tari requirements. However, i a generating acility

objects to SCE’s estimate, the customer may elect to install the net generating output meters, or have SCE install one

at the customer’s expense.

Whatever meter is chosen, it must meet the SCE’s Rule 22 requirements. I it does not, SCE has the right to install a

utility-owned net generating output meter at the customer’s expense.

Some things to consider when choosing a meter, especially the more expensive net generating output meter:

Data requirements in relation to the need or inormation•

Cogenerator’s decision to install equipment that adequately addresses SCE’s operational requirements•

Accuracy and type o required metering consistent with purpose o collecting data•

Cost o metering relative to the need or and accuracy o the data•

The generating acility’s size relative to the cost o the metering/monitoring•

Other means o obtaining the data (e.g., generating acility logs, proxy data, etc.)•

Requirements under any interconnection agreement•

On a quarterly basis, SCE reports to the Caliornia Public Utilities Commission and explains its rationale or

requiring net generating output meters at each acility, along with the size and location o the acility.


DSIRE database: <http://www.dsireusa.org/library/includes/type.cm?EE=0&RE=1>.

Generating Your Own Electricity: Net Metering, Public Utilities Commission o Ohio,

<http://www.puco.ohio.gov/PUCO/Consumer/Inormation.cm?id=8510&terms=metering&searchtype=1&ragment=False>.

PGE, Distribution Interconnection Handbook. <http://www.pge.com/mybusiness/customerservice/nonpgeutility/generateownpower/

distributionhandbook/>.

SCE <http://www.sce.com/NR/sc3/tm2/pd/Rule21.pd >.

SDGE <http://www.sdge.com/business/netMetering.shtml>.

West Bengal: <http://wberc.net/wberc/regulation/under_2003_Act/index.htm>.





130

7. Synchronous Generators – Special Requirements

Issue: A synchronous generator rotates at a constant speed that matches the requency o the utility’s system. Most

distributed generators are synchronous. The eld excitation o a synchronous generator is supplied by a separate

motor-generator set, like a directly coupled sel-excited DC generator, or a brushless exciter. Unlike the induction

generator, the synchronous generator does not need to be connected to the utility to unction. It can be used as a

stand-alone generator or can be connected to the grid.

Utility Perspective: Utilities understand the operation o synchronous generators well; thereore, they are more

comortable with this technology. Synchronous generators can supply sustained ault current under nearly all

operating conditions and, thereore, special protective equipment is necessary to isolate the generator rom the utility

during ault conditions.

Developer Perspective: Because synchronous generators must match the utility’s requency, they require more

complex controls. Unlike an induction generator, synchronous generators also need controls to properly maintain

eld excitation.

Synchronous generators can provide power to a acility even when the grid is de-energized (i.e., backup generators).

Also, acilities can adjust the power actor by adjusting the DC eld current.

Regulator Perspective: The type o generator being used is up to the developer but must be properly integrated into

the utility system.

Best Practices:

Caliornia has numerous requirements or connecting a three-phase synchronous generator to the utility system.

Three-phase circuit breakers must be used and have electronic or electromechanical controls. I high currents1.

are detected on any phase, the breaker must open

Synchronous generators must automatically regulate power actor with operating in parallel. The utility is2.

responsible or voltage control o the utility’s system and the generator is not used or voltage control.

For generators less than 10 MW, power system stabilization is not required.3.

I the Short Circuit Current Ratio (SCCR) must be less than or equal to 0.05 (small relative to the size o the4.

utility system), the generator’s synchronizing unction may be either manual or automatic.

I the SCCR is greater than 0.05 (large relative to the size o the utility system), synchronizing must be5.

automatic and the generator must be able to detect a loss o synchronism. With this size SCCR, manualsynchronization is not permitted.

Beore starting the synchronous generator up to speed it must be brought up to speed and careully synched 6.

to the utility system. I the prime mover (turbine or internal combustion engine) gets its starting power

rom the utility, there is a possibility that voltage irregularities (ficker) may result. Thereore, starting the

synchronous generator must be done in such a way as to avoid ficker related problems.





131


Caliornia Interconnection Guidebook: <http://www.energy.ca.gov/distgen/interconnection/guide_book.html>.


SRP Interconnection Guidelines For Distributed Generators December, 2000.

<http://www.srpnet.com/electric/pdx/gen_guidelines.pd >.





132

8. Induction Generators – Special Requirements

Issue: An induction generator is asynchronous (i.e., does not spin at the same speed as the requency o the utility).

This type o generator needs an external power source to run and, thereore, must always be operated in parallel with

the utility, a synchronous generator, or a capacitor. Only in rare instances will an induction generator continue to

produce power when the utility system is de-energized, which greatly reduces the risk o back-energization.

Utility Perspective: An induction generator draws reactive power rom the utility and may adversely aect the

voltage regulation on the interconnected circuit. As the induction generator is absorbing VArs rom the utility’s

system, it is necessary to add capacitors to improve power actor and reduce reactive power draw. Also, under

certain circumstances, an induction generator may continue to run even i the power source is de-energized. This is

called sel-excitation.

Developer Perspective: Induction generators are airly simple to operate, need a basic control system, synchronize

with the utility automatically (so no synchronization procedures or equipment are needed), and will usually stop

operations when an outage occurs. When some types o induction generator are connected to the utility system at

speeds signicantly below synchronous speed, potentially damaging inrush currents and associated torques can

result.

Regulator Perspective: The type o generator used is the developer’s choice, but must be properly integrated into

the utility system.

Best Practices:

The speed o the induction generator must be within 5% o the synchronous speed beore it is connected to the utility

system.

Since induction generators will usually not support a ault, the anti-islanding protection will also provide ault

detection, unless there is sucient capacitive reactance to supply the VAr requirements o the induction generator

eld. In this case, it may be necessary to provide or direct detection o aults in a manner similar to synchronous

generators.

An induction generator can cause voltage fuctuations on the utility’s system when it starts. One solution is the

installation o capacitors, but this must be done with care. Corrective capacitors can cause erroresonant voltages,

which can damage sensitive equipment. A step-switched capacitor or some other solution to voltage fuctuations may

be necessary.



“Generating your Oown Electricity: Advice or Getting Started, Public Utilities Commission o Ohio.”<http://www.puco.ohio.gov/emplibrary/les/media/Publications/Fact_Sheets/generating%20your%20own%20electricity%20-%20

advice%20or%20getting%20started.pd >.






133

9. Static Power Converter

Issue: The electric power converter provides an interace between non-synchronous energy output by the alternative

energy acility and the utility. Non-synchronous output voltages can be direct or alternating current, which can be

converted by a DC-to-AC or AC-to-DC power converter.

Static power converters create large nonlinear loads, which can result in harmonic distortion o the waveorm. The

severity o the potential problem depends on the converter, but most new designs already address this issue.

There are two types o converters: some operate only while the utility system is energized and some will operate

while the utility system is de-energized.

Utility Perspective: Few static converters need relays to check synchronization between the acility’s rotating

generators and the grid. The energy contribution rom a static power converter during a ault is much lower than

rom a comparably sized induction or synchronous generator.

Developer Perspective: Solid-state converters oer several advantages. There are more options or protective

relaying, coordination, and communication. They also operate at much higher eciencies and are oten more reliable

than rotating machine converters.

Regulator Perspective: The type o generator being used is up to the developer, but it must be properly integrated

into the utility system.

Best Practices:

Converters must be tested and in compliance with UL’s most current applicable version o UL1741, “Inverters,

Converters and Controllers or Use in Independent Power Systems.”

The requency and voltage trip pickup settings or static power converters may be relaxed at the utility’s discretion i

the acility experiences too many nuisance trips.

I the converter’s internal microprocessor protection provides acceptable levels o accuracy, external relaying may

not be necessary. However, external test ports should be included so the utility can perorm periodic trip pickup

testing.








134

10. Static Inverters/Inverter Systems – Special Requirements

Issue: An inverter is a device that converts DC to AC power. From an interconnection standpoint, one o the most

important characteristics o inverters is their inability to supply excessive currents under ault conditions. Thereore,

standard ault detection schemes cannot be used. Equipment that can detect abnormal voltages can be eective.

Harmonic problems can arise rom the use o inverters, as they can create standing waves that can be refected.

These refective waves can add up to high levels. Newer inverters with pulse width modulation operate at higher

requencies and are more likely to create harmonic problems but typically generate very clean output and normally

satisy IEEE 1547 requirements.

There are two types o inverters:

Line-commuted inverters rely on a second source o generation to provide a “clocking signal.” This type o inverter

will shut down i a ault occurs on the utility system.

Sel-commuted inverters provide their own clocking signal and can supply ault current, but the current is airly

constant and is usually 1.2 to 1.5 times the rated load current o the inverter.

Most new inverter designs are based on newer solid-state technology that uses pulse width modulation to generate

the injected alternating current.

Utility Perspective: Inverters provide signicantly less ault current than do some other types o equipment. IEEE

1547, UL1741-tested, active anti-islanding inverters usually qualiy or simplied interconnections.

Developer Perspective: Inverters are convenient to use.

Regulator Perspective: As long as it can be successully and saely interconnected, the type o equipment used is up

to the developer.

Best Practice:

Inverter systems have two classications: utility-interactive and non-utility interactive or “stand-alone.” Utility

interactive inverter systems have their own internal synchronizing sotware and thus do not require separate

synchronizing equipment. This sotware allows them to synchronize and also prevents improper synchronization.

I the generating acility uses a non-utility interactive inverter, the acility cannot be in parallel operation with the

utility’s distribution network.

Inverters do not require separate synchronizing equipment, but in order or an inverter to be classied as utility-

interactive, it must have its own on-board synchronizing sotware that will allow it to synchronize with the utility

system and prevent it rom improperly synchronizing.

In Caliornia, Rule 21 specically prohibits nonutility-interactive (stand-alone) inverters rom operating in parallel

with the utility system.








135

11. Equipment Precertifcation/Pre-approval

Issue: Installing alternative energy acilities can be expensive and the approval process and additional requirements

placed on the developer by the utility can make a proposed acility nancially untenable. One way to simpliy

the process (and thereore make it less expensive or the developer) is to have a list o precertied/pre-approved

equipment.

Utility Perspective: Any alternative energy acility that ties in with the local grid must meet operational and saety

requirements. Untested and unamiliar technologies can jeopardize the system.

Developer Perspective: Installing an alternative energy acility should be as simple and as inexpensive as possible.

Most generating technologies have been tested and used successully. Utilities are slow to embrace new ideas.

Regulator Perspective: Having a list o certied equipment and congurations will simpliy the approval process

and help ensure the proposed alternative energy acility will integrate well with the utility system.

Best Practices:

There are numerous examples o precertied equipment and congurations. Caliornia’s Rule 21 is a good example.

In order to encourage the addition o small generation acilities, simplied interconnections were made a priority

and interconnection devices and protection equipment that were tested and approved by independent labs were pre-

approved.

Rule 21 Certication is set up as a series o tests that may be run by an independent testing laboratory

(called a Nationally Recognized Testing Laboratory, or NRTL). I the applicant makes use o a Generator/

interconnection equipment package that has passed these tests, the application will pass Initial Review

screen 3. Rule 21 Certication is designed to allow the purchaser o a Rule 21 Certied Generator/

interconnection equipment to avoid the delay o utility eld-testing o the unit’s protective unctions. All

utilities that have adopted Rule 21 accept the results o Rule 21 Certication or a particular manuacturer’s

make and model, in lieu o testing every Generator and every piece o interconnection equipment

individually. (FERC may also accept Rule 21 certied equipment under its small generation interconnection

process.) Rule 21 Certication may apply to either a pre-packaged system or an assembly o components that

perorm the necessary unctions. (p. 15, Caliornia Interconnection Guidebook)

These simplied interconnections oten apply to small-capacity generators but can apply to larger acilities, because

the importance o generator size is relative to the capacity and design o the distribution system to which it will be

connected. Size is oten used as a surrogate o the real parameters o interest, such as short-circuit duty.

In Texas, precertication can also speed up the approval process and reduce costs to developers. Generation units

that are precertied can be installed without urther review o their design (approved interconnection and protection

schemes are necessary). I the generation unit is not precertied, the utility can take up to six weeks to perorm acertication study and may charge the developer or that study.








136

C. Testing Requirements

Issue: When an alternative energy acility is being connected to the utility system, our kinds o testing are required:

Type testing makes sure the equipment meets specications.

Production testing includes voltage and requency variation tests. (See UL1741, Manuacturing and ProductionTests, Section 68.)

Commissioning testing is done the rst time the acility operates in parallel with the utility system or when

equipment or sotware that could aect the operation o the interconnection is changed. The utility may require that

its representative is present during commission testing.

This testing can include (i applicable)

Over- and undervoltage testing•

Over- and underrequency testing•

Nonislanding unction testing•

Nonexporting unction testing•

Testing inability to energize dead line•

Testing time delay on restart ater utility source is stable•

Utility system ault detection testing•

Testing synchronizing controls•

Other testing required by the interconnection agreement•

Periodic testing is specied by the equipment manuacturer and must be perormed every our years or more

requently.

Utility Perspective: Testing is critical to ensure the sae and reliable operation o the system. Precertied equipment

reduces the number o tests the utility must observe, reduces liability, and streamlines the approval process.

Developer Perspective: In order to keep costs down, testing should be kept to a minimum.

Regulator Perspective: Appropriate testing must be perormed to ensure the stability o the grid but should be kept

to a minimum cost.

Best Practices:

Dierent utilities have their own specic testing requirements, but most are consistent with IEEE 1547.

SRP, or example, requires the protective devices to be calibrated and eld-tested by “qualied personnel” prior to

witness testing. Results o the eld test have to be sent to SRP at least ve days prior to the witness test.

Technical Issues and Best Practices Testing Requirements




137

Witness/Commissioning Test Requirements:

On the day o witness testing, the Customer shall demonstrate, in the presence o SRP personnel that:

Relay settings are consistent with the written calibration tests previously provided by the Customer.(a)

Operation o each protective output contact results in the desired operation o the appropriate(b)

protective device (usually a breaker or contactor). For static inverters rated less than 50 kW, a trip-

timing test with simulated loss o voltage will be sucient.

The [distributed generator] DG is capable o synchronizing with the SRP grid.(c)

The DG properly disconnects rom the SRP system under simulated disturbance conditions.(d)

SRP remote visibility or control o any devices associated with the DG unction[s] properly, i (e)

applicable.

Settings o programmable logic devices are correct, i applicable.() (Page 9-1, SRP Interconnection

Guidelines or Distributed Generators, December, 2000)


‘Caliornia Interconnection Guidebook.” <http://www.energy.ca.gov/distgen/interconnection/guide_book.html >.


Technical Issues and Best Practices Testing Requirements




138

VII. Approvals and Application Processing Issues and Best Practices

Considerable disagreement exists between utilities and developers over what approvals should be required prior to

interconnecting to the grid and the application process. The utility believes the

approval and application process is essential to ensure the grid’s reliability and saety. The developer eels the

approval and application processes are oten lengthy and do not clearly dene what tests and studies are needed. In

addition, multiple agencies with jurisdiction over the project create delays and increase costs.

In India, dierent approvals are required or renewable energy projects o dierent types and sizes, and in some cases

approvals rom both Central and State governments are required in India. The project developer must obtain “no

objection” certicates rom several dierent government departments to obtain approval o the project. This could

be streamlined by requiring the state energy development agency to obtain these certicates once the developer has

provided sucient project inormation.

As an example, since land, water, mining rights and the environment are the states’ responsibility, clearances relating

to these issues have to be obtained rom the relevant ministries o the State Government where the project is to be

implemented. However, i part o the land happens to all under the category o orest, clearances have to be obtained

rom both State and Central Government ministries. The Central Government has recently delegated certain powersto the States to expedite the implementation o small projects.

Many U.S. states have developed streamlined application processes to address this issue. According to Caliornia

Rule 21, all acilities that plan to have net energy metering have no application or interconnection study ees. Those

acilities without Net Energy Metering have an initial review ee o $800, hal o which is reunded i the application

is rejected or pulled by the developer; a $600 supplemental review ee, and interconnection study ees specied by

the utility.

This section highlights the streamlined application processes in Caliornia and PSEG.

Approvals and Application Processing Issues and Best Practices




139

Permitting Process – Caliornia

The Caliornia Energy Commission released a report in December 2000 titled Distributed Generation: CEQA

Review and Permit Streamlining . This report describes the permitting processes conducted by city and countygovernments and air districts or small-scale electricity-generating acilities. Caliornia has already instituted a number o guidelines and programs to streamline the permitting process in order to encourage alternative

energy. For example, the State Permit Streamlining Act imposes the ollowing time limits, once a permitapplication is accepted as complete:One year or environmental impact reports•

Six months or negative declarations o mitigated negative declarations•

Developers o alternative energy acilities may apply or all required permits at the same time, but the sequenceo permit application usually ollows this order:

Air permits;1.

Land-use approvals, such as conditional-use permits;2.

Building permits; and 3.

Interconnection.4.





140

Application Requirements – Caliornia

The application process or interconnection o alternative energy devices to the electric grid involves a number o

standardized steps:

Applicant initiates contact with the electrical corporation: Upon initial request, the utility will provide1.

all relevant applications, orms, documents, and technical requirements or grid interconnection o the

distributed resource. The utility will establish an individual representative as the single point o contact or the applicant.

Applicant completes an application document. The applicant completes and les a standardized application2.

or interconnection. The utility will acknowledge receipt o the application and veriy that it has been

adequately completed.

Electrical corporation perorms an initial review and develops preliminary cost estimates and interconnection3.

requirements: The utility will perorm an initial review to determine the type o interconnection or which the

applicant qualies.

Simplifed Interconnection:a. I the applicant qualies or simplied interconnection, the utility will

provide the applicant with a written description o the interconnection requirements, in addition to a

drat interconnection agreement.

Interconnection Subject to Additional Requirements:b. The initial review will require a

supplemental review i the applicant does not qualiy or simplied interconnection. The

supplemental review provides either

Interconnection requirements that may include additional requirements beyond simplied i.

interconnection and a drat interconnection agreement.

A cost estimate and schedule or an interconnection study. In this case, the applicantii.

and utility shall enter into an interconnection study agreement. Ater completion o an

interconnection study, the utility will provide the applicant with specic requirements, costs,

and a schedule or interconnection.

Applicant and electrical corporation enter into a generation interconnection agreement: The utility provides4.

the applicant with an executable version o the interconnection agreement, net energy metering agreement, or

PPA (whichever is appropriate or the technology used and its mode o operation).

Applicant installs or constructs the generating acility to interconnect with the electric grid: The applicant5.interconnects in accordance with the provisions o the interconnection agreement, net energy metering

agreement, or PPA.





141

Applicant arranges or and completes testing o the distributed resource (DR) device: Beore operating in6.

parallel with the electric grid, the DR device and associated interconnection equipment must be tested to

ensure compliance with the saety and reliability provisions o the CPUC-approved rules and regulations.

Electrical corporation authorizes interconnection: The applicant’s DR device may commence parallel7.

operation with the utility’s electric grid.

The fow chart below outlines the initial review process or applications to interconnect DR devices.

Networked Secondary System?

Power Exported?

Equipment Certied?

Aggregate Capacity < 15% o Line Section Peak Load

Starting Voltage Drop Screen Met?

kVA 11 o Less?

Meets short Circuit Current Contribution Screen?

Meets Line Conguration Screen?

NO

NO

YES

YES

YES

NO

YES

YES

YES

YES

YES

NO

NO

NO

NO

NO

NOYES

QUALIFIES FOR INTERCONNECTION

SUBJECT TOSUPPLEMENTALREQUIREMENTS

UTILITY PROVIDESCOST ESTIMATE AND

SCHEDULE FOR INTERCONNECTION

STUDY

QUALIFIES FOR “SIMPLIFIED INTERCONNECTION”

SUPPLEMENTALREVIEW

Does supplementalreview determine

requirements?

Source: Caliornia Distributed Energy Resource Guide, http://www.energy.ca.gov/distgen/interconnection/application.html





142

Application Process – PSE&G

1. Initial Communication rom the Applicant. The applicant should supply as much technical inormation as

possible. PSE&G shall determine whether the proposed installation is an application or qualied net metering or a

conventional orm o DG.

1A. Expedited Application Process or Qualifed Net Metering Installations 100 KW or Less.1) Prior to installation o a qualied net metered system (100 kW or less), applicants must submit a ully completed

rst page o the net metering application to PSE&G, with the $100 application ee.

2) PSE&G will review the application and inorm the applicant i the applicant can proceed with the interconnection

or i a more detailed interconnection study is required (see Step 4 below).

3) Ater the applicant has received permission to interconnect rom PSE&G, has completed the installation, and has

received the appropriate municipal inspection, the applicant must submit a ully completed and signed application

(all pages) to PSE&G.

4) The ollowing sections apply to net metering 100 KW or less installations:

a) 4.2 Metering

b) 4.2.1 Net Metering

c) 4.3 Groundingd) 4.6 Disconnect switch or device

e) 4.7 Power Quality

) 4.10.1 A Compliance with IEEE 929-2000

g) 4.10.2 Verication Testing

h) 4.12 Connections to Network Systems

2. Review by PSE&G to Determine the Nature o the Project.

A PSE&G representative shall discuss the scope o the project with the applicant to determine what specic

inormation and documents (such as technical requirements and metering requirements) will be required. All such

inormation, and a copy o this application, will be sent to the applicant no more than ve business days ollowing

the initial communication rom the applicant. A PSE&G representative will serve as the single point o contact or the applicant in coordinating the project.

3. Filing an Application.

The ling must include a completed application orm and/or other inormation as indicated above and nonreundable

application ees o $100 or units o 100 KW or less or $500 or units larger than 100 KW. Within 10 business

days o receiving the application, PSE&G will notiy the applicant o receipt and whether the application has been

completed adequately.

4. Preliminary Coordinated Interconnection Review and Cost Estimate Development.

PSE&G will conduct a preliminary coordinated interconnection review and will inorm the applicant o any

necessary PSE&G system additions/modications, and o any license requirements that PSE&G may require or interconnection. The applicant will be provided with an assessment o the technical easibility o the proposed

interconnection, a preliminary schedule, and a good-aith detailed estimate o the interconnection costs, i applicable





143

A ull coordinated interconnection review may not be needed i

The aggregate generation is less than 50 KW on a single-phase branch o a distribution circuit; or •

The aggregate generation is less than 150 KW on a single three-phase distribution eeder; or •

The proposed installation is not interconnected to a network system; or •

The proposed generator has no power export capability.•

Note: Units without export capability must either be sized or 50% or less o peak acility load or be equipped with

reverse power relays to prevent power export into the PSE&G system.

Framework or standardized interconnection study costs or net metered qualied systems that do not meet the

criteria outlined above:

For requests to interconnect single-phase systems on single-phase branches ( total aggregate generation is•

greater than 50 KW but less than or equal to 100 KW) or single-phase and three-phase systems on three-phase

eeders (total aggregate generation is greater than 150 KW but less than or equal to 300 KW), the study cost

may be up to, but not exceed, the cost o three man-days o study labor at the current PSE&G loaded labor

rate.

Requests to interconnect any generation up to 100 KW or network service installations may incur a maximum•

study cost based on ve man-days o study labor at the current PSE&G loaded labor rate. Study costs or

proposed installations that all outside o the “standards” will be estimated or the acility owner beore any

work is perormed and billed at PSE&G’s loaded labor rate.

5. Applicant Commits to PSE&G’s Coordinated Interconnection Review o the Project Design.

I discussions with the applicant, review o the application, or review o the proposed design indicate a major impact

on the interconnected PSE&G acilities, the applicant will be required to

Provide PSE&G with a cost-based advance payment or the PSE&G review o the proposed generator.•

Submit a detailed design package.•

Conrm with PSE&G a mutually agreeable schedule or the project based on the applicant’s work plans and •

the discussions with the utility.

Additional exchanges o inormation between PSE&G and the applicant may be required to complete the design

package according to PSE&G’s technical requirements or interconnection.

6. PSE&G Review o Applicant’s Design Package

PSE&G will

Conduct a review o the design package to ensure that the plans/design satisy the technical requirements or •

interconnection.

Upon completion o the review, notiy the applicant o its nal acceptance o the applicant’s design or • an

explanation o the technical requirements the design ails to meet.

For type-tested systems, will complete its initial review in 10 business days.•





144

7. Applicant Commits to PSE&G Construction o PSE&G’s System Modifcations

The applicant will

Execute a standardized interconnection agreement or commit in writing to the applicable tari requirements.•

Provide PSE&G with an advance payment or PSE&G’s estimated costs associated with system modications,•

metering, and on-site verication.

8. Project ConstructionThe applicant’s acility will be constructed in accordance with PSE&G-accepted design. PSE&G will commence

construction/installation o system modications and metering requirements.

9. The Testing o the Applicant’s Facility in Accordance with PSE&G’s Technical Requirements

The applicant will develop a written testing plan to be submitted to PSE&G or review and acceptance. This testing

plan will be designed to veriy that the acility complies with the applicant’s PSE&G-accepted drawings and details

o the interconnection. The nal testing will be conducted at a mutually agreeable time, and PSE&G shall be given

the opportunity to witness the tests.


Caliornia:<http://www.energy.ca.gov/distgen/interconnection/application.html >, and

<http://www.energy.ca.gov/distgen/interconnection/SUP_REV_GUIDELINE_20050831.PDF>.

Distributed Generation CEQA Review and Permit Streamlining (Report 700-00-019). <www.energy.ca.gov/distgen/documents >.

PSEG: <http://www.pseg.com/customer/home/save/pd/PSEG_Intercon_Stds.pd >.

“Taking the Red Tape Out o Green Power: How to Overcome Permitting Obstacles to Small-Scale Distributed Renewable Energy.”

<http://www.newenergychoices.org/uploads/redTape-rep.pd >.

<http://www.bakernet.com/NR/rdonlyres/0251961F-DACD-4C9E-9415-A7A24A28485C/44792/RenewableenergyinIndia.pd >.(pages 6 and 80).





145

VIII. Contractual Issues and Best Practices

In order to connect alternative energy acilities to the grid, the developer must rst sign a contract with the utility that

outlines interconnection procedures and tari prices. These contracts are essential or project nancing and reduce

uncertainty over the acility’s long term economic viability.

This section highlights two key contractual issues that are critical to alternative energy developers: dispute resolutionand Power Purchase Agreements.

Contractual Issues and Best Practices




146

A. Dispute Resolution

Issue: Utilities, developers, and alternative energy acilities oten have disputes over payments, operations, and

interconnections.

Utility Perspective: A ormalized procedure to address disputes is necessary to ensure airness and address issues

quickly.

Developer Perspective (Operator o acility): A ormalized procedure to address disputes is necessary to ensure

airness and address issues quickly.

Regulator Perspective: A ormalized procedure to address disputes is necessary to ensure airness and address

issues quickly.

Best Practices:

Caliornia

Rule 21 states that the regulatory commission has the authority to interpret, add, delete, or modiy any agreements

between the utility and the renewable energy/cogeneration acility to implement the tari and to resolve disputes overthe renewable energy/cogeneration acility’s perormance o its obligations under its taris.

For disputes over the acility’s perormance, the procedure begins with a letter rom the aggrieved party to the other

party with all relevant known acts, the specic dispute and the relie sought, and notice that it is ocially opening

a dispute. Each party must designate a representative responsible or reviewing this dispute within seven calendar

days. I no resolution has been reached within 45 calendar days o the original dispute letter, either party can reques

an additional 45 calendar days to continue negotiations or request the commission mediate. With agreement rom

both parties, mediation can be through a third party with costs shared equally between both parties. I the dispute is

not resolved within 90 calendar days, either party may le a ormal complaint with the commission.

MinnesotaMinnesota’s statute states that either party may request that the commission decide the dispute but that the burden

o proo is on the electric utility. I the utility prevails and the renewable energy/cogeneration acility’s claims were

made in bad aith, or were a sham or rivolous, the renewable energy/cogeneration acility must pay the utility’s costs

and attorneys’ ees. However, i the renewable energy/cogeneration acility’s claims were reasonable, it will not have

to pay the utility’s costs even i the utility prevails. I the renewable energy/cogeneration acility prevails, the utility

must pay its costs and attorneys’ ees.


“Rule 21 Model Rule Drat to Implement D.05-08-013” (pages 18-19). <http://www.energy.ca.gov/distgen/interconnection/

RULE_21_MODEL_RULE_02-2006.PDF>.

216B.164, Minnesota Statutes 2007. <https://www.revisor.leg.state.mn.us/bin/getpub.php?pubtype=STAT_CHAP_SEC&year=2007&

section=216B.164>.

Contractual Issues and Best Practices Dispute Resolution






148

IX. Concluding Comments

Several key barriers to the deployment o alternative energy in India were highlighted during the three workshops

held in India and the executive exchange to the U.S. USEA has addressed these issues in this handbook but

recognizes that urther discussions with Indian counterparts has been requested and may be necessary.

Participants at the workshops highlighted the ollowing issues or uture APP activities in India:Interconnecting renewable energy and cogeneration acilities at the 11 kv level, rather than the 66 kv level.•

Ways to “rm up” power or other alternatives to address intermittency issues•

Hybrid systems such as wind/solar •

Carbon ees•

Creating policies that mandate wind technology with reactive power capabilities•

Renewable Energy Credits•

Benets, technical specications, and costs o net metering•

Landll technology and waste-to-energy acilities•

This handbook was unded by the U.S. government through the Asia-Pacic Partnership on Clean Development and

Climate. It is available on the internet at http://www.usea.org/Programs/APP/APP_home.htm and is intended to be a

living document. Due to the breadth o the subject matter, only a ew best practices could be highlighted. While the

handbook was compiled or India, the subject matter is germane in all countries and should be used accordingly.

Concluding Comments




149

Appendix A: Glossary o Terms

Active Anti-Islanding Scheme: A control scheme installed as part o the generating or interconnection acility that

senses and prevents the ormation o an unintended island.

Applicant: A customer or entity that intends to apply or has applied to an electric utility or interconnection.

Certifcation Test: A test that veries conormance o certain equipment with approved perormance standards in

order to be classied as certied equipment.

Certifed Equipment: Equipment that has passed all required certication tests.

Cogeneration: In India, “cogeneration” reers to electricity and steam production rom bagasse at sugar mills. This

handbook uses the Indian denition and lists combined heat and power separately.

Combined heat and power (CHP): CHP is dened as the sequential production o electricity and thermal energy

rom a single primary energy source. CHP provides on-site generation o electrical and/or mechanical power; waste-

heat recovery or heating, cooling, dehumidication, or process applications; and seamless system integration or a variety o technologies, thermal applications, and uel types into existing building inrastructure. The overall

eciency o energy use can be up to 85% and above in some cases.

Commissioning test: A test perormed during the commissioning o all or part o a generating acility to achieve one

or more o the ollowing:

Veriy specic aspects o its perormance;•

Calibrate its instrumentation; or •

Establish instrument or protective unction set-points.•

Customer: The entity that receives or is entitled to receive distribution service through the distribution system.

Dedicated transormer; dedicated distribution transormer: A transormer that provides electricity service to a

single customer. The customer may or may not have a acility.

Disconnecting device: Either a physical device such as a relay or switch, or a computer-controllable capability in

electronic power equipment, designed to isolate a portion o the utility system and/or generator.

Distributed generation (DG): Electricity production that is on-site or close to the load center and is interconnected

to the utility distribution system. In India, “distributed generation” reers only to isolated generation systems that

distribute power to consumers (like smart/mini grids) and are not connected with the grid. These DG systems may

use even ossil uels such as oil, gas, or coal. For the purpose o this handbook, the term “distributed generation”

reers to interconnected systems.

Distributed resource (DR): Synonym or “distributed generation.” Both terms can be used interchangeably.

Distribution eeder: An electric line operated at voltages below 60 kV that serves to deliver power rom a utility

substation or other supply point to customers.

Glossary o Terms




150

Distribution service: All services required by, or provided to, a customer pursuant to the approved taris o the

utility other than services directly related to the interconnection o a acility.

Distribution system: All electrical wires, equipment, and other acilities owned or provided by the utility, other than

interconnection acilities, by which the utility provides distribution service to its customers.

Electric utility (utility): A person or authority that owns or operates equipment or acilities to produce, generate,

transmit, distribute, sell, or urnish electricity or compensation; excluded rom this denition are municipal

corporations, power generation companies, exempt wholesale generators, power marketers, electric cooperatives, and

retail electric providers. The utility can be vertically integrated or unbundled.

Facility: A grid-connected electrical generating installation consisting o one or more on-site generation units. In

this handbook, the acility can be renewable energy, distributed generation, cogeneration, or combined heat and

power.

Field testing: Testing perormed in the eld to determine whether equipment meets the utility’s requirements or

sae and reliable interconnection.

Generator: A device converting mechanical, chemical, or solar energy into electrical energy, including all o its

protective and control unctions and structural appurtenances. One or more generators comprise a acility.

Harmonic distortion: Nonlinear distortion o a system or transducer characterized by the appearance in the output

o harmonics other than the undamental component when the input wave is sinusoidal.

Host load: Electrical power that is consumed by the customer at the property on which the acility is located.

IEEE: The Institute o Electrical and Electronics Engineers, Inc.

In-rush current: The current determined by the in-rush current test.

Interconnection; interconnected: The physical connection o a acility in accordance with the requirements so that

parallel operation with the utility’s distribution system can occur (has occurred).

Interconnection agreement: An agreement between the utility and the producer that gives certain rights and

obligations to eect or end interconnection.

Interconnection acilities: The electrical wires, switches, and related equipment that are required in addition to the

acilities required to provide electric distribution service to a customer to allow interconnection. Interconnection

acilities may be located on either side o the point o common coupling, as appropriate to their purpose and design.

Interconnection acilities may be integral to a acility or provided separately.

Interconnection study: A study to establish the requirements or interconnection o a acility with the utility’s

distribution system.

Inverter: A machine, device, or system that changes DC power to AC power.

Glossary o Terms




151

Island; islanding: A condition on the utility’s distribution system in which one or more acilities deliver power to

customers using a portion o the utility’s distribution system that is electrically isolated rom the remainder o the

utility’s distribution system.

Isolation device: A device in one circuit that prevents the malunctions in one section o the circuit rom causing

unacceptable infuences in other sections o the circuit or other circuits.

kV: kilovolt, an amount o voltage equal to 1,000 volts.

kW: kilowatt, an amount o power equal to 1,000 watts.

Metering: The measurement o electrical power fow in kW and/or kWh, and/or energy in kWh, and, i necessary,

kVAr at a point, and its display to the utility, as required.

Metering equipment: All equipment, hardware, sotware including meter cabinets, conduit, etc., that are necessary

or metering.

Momentary parallel operation: The interconnection o a acility to the distribution system or one second or less.

MW: Megawatt, an amount o power equal to one million watts.

Nationally recognized testing laboratory (NRTL): A laboratory accredited to perorm the certication testing

requirements.

Net generation metering: Metering o the net electrical power or energy output in kW or energy in kWh,

respectively, rom a given acility. This may also be the measurement o the dierence between the total electrical

energy produced by a generator and the electrical energy consumed by the auxiliary equipment necessary to operate

the generator.

Nonexport; nonexporting: Designed to prevent the transer o electrical energy rom the acility to the utility.

Nonislanding: Designed to detect and disconnect rom a stable unintended island with matched load and generation.

Parallel operation: The operation o on-site distributed generation by a customer, while the customer is connected

to the utility’s distribution system, either on a momentary or on a continuous basis.

Periodic test: A test perormed on part or all o a acility at a predetermined time or operational intervals to achieve

one or more or the ollowing: 1) veriy specic aspects o its perormance; 2) calibrate instrumentation; and 3) veriy

and re-establish instrument or protective unction set-points.

Point o common coupling (PCC): The transer point or electricity between the electrical conductors o the utility

and the electrical conductors o the producer.

Point o interconnection: The electrical transer point between a acility and the distribution system. This may or

may not be coincident with the point o common coupling.

Glossary o Terms




152

Power actor: The ratio o the resistance to the impedance at power requency o an equivalent circuit supposed to be

ormed by an inductance and a resistance in series.

Power purchase agreement (PPA): An agreement or the sale o electricity by the producer to the utility.

Precertifed equipment: A specic generating and protective equipment system or systems that have been

certied as meeting the applicable parts o this section relating to saety and reliability by an entity approved by the

commission.

Pre-interconnection study: A study or studies that may be undertaken by a utility in response to its receipt o a

completed application or interconnection and parallel operation with the utility system. Pre-interconnection studies

may include, but are not limited to, service studies, coordination studies, and utility system impact studies.

Producer: The entity that executes an interconnection agreement with the utility. The producer may or may not own

or operate the acility, but is responsible or the rights and obligations related to the interconnection agreement.

Protective unction(s): The equipment, hardware, and/or sotware in a acility (whether discrete or integrated with

other unctions) whose purpose is to protect against unsae operating conditions.

Reactive power: The reactive power is dened as the square root o the square o the apparent power minus the

square o the active power. Reactive power is developed when there are inductive, capacitive, or nonlinear elements

in the system.

Reclosing: The act o automatically re-energizing a line in an attempt to quickly restore power to customers.

Renewable energy: Energy derived rom natural processes that are replenished constantly. In its variousorms, it derives directly rom the sun, or rom heat generated deep within the earth. In India, renewableenergy includes electricity and heat generated rom solar resources, wind, ocean, hydropower (up to 25

MW), biomass, waste-to-energy, geothermal resources, and biouels.

SCADA (supervisory control and data acquisition): A “smart” distribution system, including remote terminal unit

sensors, telemetry, or other communication capability and automated control o distribution system components.

Stabilization; stability: The return to normalcy o the utility’s distribution system, ollowing a disturbance.

Stabilization is usually measured as a time period during which voltage and requency are within acceptable ranges.

Switchgear: An enclosed metal assembly containing components or switching, protecting, monitoring, and

controlling electric power systems.

Synchronous speed: The speed o rotation o the magnetic fux, produced by or linking the primary winding.

System integrity: The condition under which a distribution system is deemed sae and can reliably perorm its

intended unctions in accordance with the saety and reliability rules o the utility.

Telemetering: The electrical or electronic transmittal o metering data in real-time basis to the utility.

Glossary o Terms




153

Total load: The sum o all customer loads on a distribution eeder.

Transer switch: An automatic or nonautomatic device or transerring one or more load conductor connections

rom one power source to another.

Transer trip: A protective unction that trips a acility remotely by means o an automated communications link

controlled by the utility.

Unintended island: The creation o an island, usually ollowing a loss o a portion o the utility’s distribution

system, without the approval o the utility.

Unsae operating conditions: Conditions that, i let uncorrected, could result in harm to personnel, damage to

equipment, loss o system integrity, or operation outside pre-established parameters required by the interconnection

agreement.

Utility grade relays: Relays specically designed to protect and control electric power apparatus, tested in

accordance with ANSI/IEEE standards.

Visible disconnect: An electrical switching device that can separate the acility rom the utility’s distribution system

and is designed to allow visible verication that separation has been accomplished. This requirement can be met by

opening the enclosure to observe the contact separation.

Glossary o Terms




154

Appendix B: Sample Power Purchase Agreements

Punjab

DRAFT POWER PURCHASE AGREEMENT FOR PURCHASE OF POWER FROM SOLAR PHOTOVOTAIC

POWER PROJECTS (IPP) BEING SET UP UNDER NRSE POLICY-2006 FACILITATED BY PEDA

I. This POWER PURCHASE AGREEMENT (hereinater reerred to as ‘Agreement’) is made on the_____ day

o __________2006 at Patiala, Punjab (hereinater reerred to as the ‘Eective Date’) by and between M/s

------------------------------(hereinater reerred to as the ‘Generating Company’) which expression shall unless

repugnant to the context or meaning thereo include its successors, administrators or permitted assigns as party

o the rst part and Punjab State Electricity Board , a body constituted under the provisions o the Electricity

(Supply) Act-1948 having its head oce at The Mall, Patiala (hereinater reerred to as the ‘Board’) which

expression shall unless repugnant to the context or meaning thereo include its successors and assigns as party

o the second part. Each o Board and Generating Company shall be reerred to as a ‘Party’ and collectively

as ‘Parties’.

II. WHEREAS, the Generating Company has been selected by Punjab Energy Development Agency (PEDA)

Government o Punjab (GOP) to design, construct, own, operate & maintain _______ MW Solar Photovoltaic

based Power Plant (hereinater reerred to as “Project”) in _________District __________in the State o Punjab

with an aggregate capacity o _____ MW as per details given in Annexure-I and has executed and signed a

MOU dated ___________and an Implementation Agreement dated________ with Punjab Energy Development

Authority (PEDA) to this eect or sale o the energy generated rom the Project to the Board under the New

& Renewable Sources o Energy (NRSE) Policy – 2006 notied by the Government o Punjab.

WHEREAS, the Punjab State Electricity Regulatory Commission (PSERC) has vide its order dated 13.12.07

approved the purchase o power by the Board rom the NRSE projects located in the State o Punjab on the

terms and at the rates approved in the said order under NRSE policy, 2006.

III. WHEREAS the Company desires to sell to the Board electric energy generated in the Company’s acility and

the Board agrees to purchase all such energy oered by the Company or sale, upon the terms & conditions setorth therein.

NOW, THEREFORE, in consideration o premises and mutual covenants and conditions set orth herein, it is

hereby agreed by and between the Parties hereto as ollows:-

1.0.0 DEFINITIONS

In this Agreement unless the context otherwise requires or implies the ollowing expressions shall have the

meaning herein respectively assigned to them:

“Act” means the Electricity Act, 2003 and includes any amendment thereo.

“Agreement” means this Agreement together with all Annexures and Schedules and any amendments thereto

made in accordance with the provisions herein contained.

“Approvals” means the consents, licenses, permits, approvals and registrations by or with any Government

agency or any other authority as may be necessary or setting up and operating the Project including but notlimited to the approvals rom GOP, Punjab Pollution Control Board (PPCB), Punjab Irrigation Department (PID)

State Nodal Agency(s) or promotion o NRSE Projects, Punjab State Electricity Regulatory Commission.

“Board” means the Punjab State Electricity Board.

“Board’s Grid Sub-station” means 66 or 132KV grid substation located at ______set up by the Board.

“Board’s Load Despatch Centre” means the State Load Despatch Centre located at 220KV Grid S/Stn. PSEB

Ablowal Patiala or such other Load Dispatch Centre authorized to issue Despatch Instructions to the Generating

Facility o the Generating Company.

Appendix B




155

“Commencement o commercial operations” means the date on which the project is capable o delivering

Active Power and Reactive power on regular basis ater having successully completing the commissioning

tests as per Prudent Utility Practices.

“Commission” means the Punjab State Electricity Regulatory Commission.

“Conventional Source o Energy” means sources conventionally used to generate electricity including interalia

coal, coke or any petroleum product, natural gas or any other similar source.

“Dispute” means any dispute or dierence whatsoever arising between the parties, out o or relating to the

construction, meaning, scope, operation or eect o this Agreement, or the validity, breach or termination

thereo.

“DPR” means the Detailed Project Report prepared by the Company and as approved by PEDA or any

revision thereo approved by PEDA.

“Debt Component” means the Debt proposed to be raised rom the Financial Institutions/Banks or nancing

a part o the project cost as per the D.P.R.

“Due Date” means 30 days ater receipt o invoice rom the Board or the generating Company as the case may

be.

“Duration o the Agreement” means 30 ( thirty) years rom the date o Commissioning o the project as per

clause-12 o the agreement.”Eective Date” means the date o signing o this Agreement.

“Energy Unit” means one Kilo Watt Hour (KWh) o electrical energy.

“Financial Closure” means the rst business day on which sucient unds are available or the implementation

o the project including Debt component.

“Generating Facility” means the ___MW generating station comprising o ______units o _______MW

capacity each located at __________.

“GOP” means the Government o Punjab and includes all agencies and authorities under its control/ regulation

including but not limited to PEDA, PID, and PPCB.

“GOI” means Government o India and includes all agencies, authorities under its control/ regulation including

but not limited to Ministry o non Conventional Energy Sources.

“Grid” means the total system o electrical transmission circuits, transormers, switchgear and other equipmen

(including Interconnection Facilities) on the Board’s side o Interconnection Point.

“Interconnection Facilities” means all the acilities to be installed by the Generating Company on the Board’s

side o the Interconnection Point to enable the Board to provide stable and adequate start up power to the

Generating Company and to receive and utilize power rom the Project in accordance with this Agreement.

“Interconnection Point ” means the point at which interconnection is made between the Generating Company’s

Generation Facility and the Grid o the Board and shall be located on the High Voltage (HV) side o the

Generating Facility o the Generating Company.

“Installed Capacity” means ____MW which is the installed capacity o the Project as per the D.P.R.

“Invoice Date” shall have the meaning ascribed to in Article 3.3.0

“Monthly Invoice” means the invoice required to be prepared in line with Article 3.2.0 o the Agreement.

“NRSE Policy, 2006” means the policy notied by GOP to incentivize the generation o power rom new and

renewable sources o energy and any amendment there to.

“Non Conventional source o Energy” means sources other than conventional sources which are set out in NRSE Policy, 2006.

“Project” means ____MW Solar Photovoltaic Power Project (Generating Facility) including all the land, civi

structures, residential colony, electrical and mechanical plant and equipment, 11or 66KV switch yard (as the

case may be) including transormer, breaker, CT/ PTs , wave traps, structures, isolators etc., dedicated telephone

lines, telephone and wireless system, components, appurtenants, communications, access road o the village

road, oot paths, carriage ways etc located at Village _________.

Appendix B




156

“Project Cost” means the cost o setting up the project as per DPR.

“Prudent Practices” means the Prudent Utility Practices applicable to Solar Photovoltaic Power Projects.

“Prudent Utility Practices” means those practices, methods, techniques and standards as adopted rom time

to time that are generally accepted or use in electric utility industries taking into account applicable law

conditions in India and commonly used or the designing, construction, testing, operation and maintenance o

the Generating Facility, lawully, saely, eciently and economically as applicable to the generating stations

o the size, service and type being set up by the Generating Company and those generally conorm to the

manuacturer’s operation and maintenance guidelines.

“Site” means village _____________ in District ________ where the Project is located.

“Scheduled Date o Synchronization” means the date on which the project shall be synchronized with the

Grid or rst time, which shall be______days (______years) rom the date o signing o this agreement (to be

provided as per the MoU / Implementation Agreement signed with PEDA).

State Grid Code: - State Grid Code notied by the Commission to which the generating utility has to comply

in respect o its various sections.

“Term” means the time period set out in Clause-12 o this Agreement.

2.0.0 ENERGY PURCHASE AND SALE

2.1.0 Sale o Energy by Generating Company.

2.1.1 The Board shall purchase and accept all energy made available at the Interconnection Point rom the

Generating Company’s Facility, pursuant to the terms and conditions o this Agreement at the rate

approved by the Commission in its order dated 13.12.07, which is set out below:

(i) Rs. 7.71/-per unit (or the year2008-09) with 5% annual escalation up to 2011-12. At the end o the

above specied escalation period, the tari payable shall be the last escalated tari or the year 2011-

2012 and shall remain in orce during the remaining term o the PPA. Any enhancement in tari ater

the last escalation shall be as determined and approved by the Commission.

(ii) This escalated tari will be applicable rom 1st day o April, 2008. The rate would be uniorm throughou

the day or the entire year. No additional payment shall on any account, be payable by the Board.

2.1.2 The Generating Company shall also generate matching MVARs corresponding to 0.88 PF lagging, so

that there is no adverse eect on Board’s system. Monthly average PF shall be computed rom the ratio

o KWH to KVAH injected into Board’s system during the month.

2.1.3 In order to protect the interest o the Board and the consumers in general, the Generating Company shall

continue to supply whole o the generated power to the Board at the rate prescribed in Article 2.1.1

above during the term o the Agreement.

Further, the Generating Company will lay transmission line to the Board’s Grid Sub Station only and wil

not be allowed to erect radial eeders to any other Distribution Licensees/Consumers/Sister Concern

rom its Generating Facility.

2.2.0 PURCHASE OF ENERGY BY GENERATING COMPANY

2.2.1 During construction o the project, the Generating Company shall purchase power rom PSEB as per

the then prevailing instructions or similar consumers o the Board.

2.2.2 The energy supplied to the Generating Company during the shut down/ start up and synchronization

o the plant in any month, as measured at the Export Meter o PSEB (Import Meter o GeneratingCompany) shall be set o rom energy generated during that month and billing will be or the net

energy sold to the Board. In case, there is no generation in the month, then energy exported to the

Generating Company shall be set o rom the energy generated during next month. But, i, there is

no generation, even in the next month, then the energy exported to the Generating Company will be

billed by the Board at the tari applicable to LS Industrial consumers (General Category) or sale rate

o energy generated rom the Project applicable or that period, whichever is higher.

Appendix B




157

3.0.0 BILLING PROCEDURE AND PAYMENTS:

3.1.0 The designated representative o the parties shall record joint readings o the meters at the Interconnection

Point and at premises o third parties to whom power is being wheeled. The meter reading in the rst

instance shall be at the time o synchronization and thereater at 12.00 Hrs. on the rst day o every

calendar month. Readings will also be recorded at 12.00 Hrs. on the dates the change o tari becomes

eective. Readings will be taken by Senior Executive Engineer (Sr. Xen)/Asstt. Executive Engineer/

Asstt. Engineer operation and CBC (to be specied at the time o signing o this Agreement depending

upon the capacity o the project) in charge o the area, under which the Generating Facility and the

premises o third parties all. It will be the responsibility o the Sr.Xen(s) in charge o the area to

designate two more ocers or taking the reading in the event Sr.Xen(s) in charge o the area is not

available. However, in the event Sr.Xen(s) in charge do not make themselves present, the Generating

Company shall also contact SE(s) o the area who would ensure taking o the joint reading either by

one or two o the designated ocers or by himsel.

3.2.0 Monthly energy account shall be prepared by the Board. This account shall depict energy delivered to

the Board at the Interconnection Point, energy imported by the Generating Company during shut down/

start up o the Project and net energy sold to the Board during the month. In case wheeling and banking

o power is undertaken by the Board under Clause 14.00 and 15.00 o this Agreement, then the monthly

energy account will also include the quantum o power delivered by the Generating Company or

wheeling, the quantum o power set o towards charges payable to the Board or wheeling the power

and quantum o energy banked by the Generating Company, which shall be determined in terms o

the agreement executed under the said clauses. In the event monthly energy account depicting energy

delivered to/ supplied by Board, is not prepared and provided by the Board within two (2) working days

then the Generating Company will be entitled to prepare the monthly energy account o its own under

intimation to Board or the purpose o raising necessary invoices. However, i the monthly energy

account involves accounting o energy wheeled and/ or energy banked, then in that case i the monthly

energy account is not prepared by Board within our (4) working days then the Generating Company

shall be entitled to prepare monthly energy account o its own under intimation to Board. Preparation

o monthly energy account by the Generating Company in such case shall be subject to adjustment o

verication o acts.

3.3.0 The monthly invoice pursuant to Clause 3.2.0 shall be delivered by the Generating Company to the

Board at its designated oce on or beore the th day o the month hereinater called the Invoice Date

However, i the energy account involves Wheeling/ Banking o energy, then the Monthly invoice shal

be raised by the Generating Company on or beore the seventh day o the month. I the Invoice Date i.e

th or seventh day o the month, as the case may be, happens to be a holiday then the Monthly Invoice

will be submitted on the next working day. The Board shall make ull payment o such Monthly Invoice

within 30 days o receipt o the Monthly Invoice hereinater called the Due Date On request o the

Company in writing or early payment or a particular period, payment shall be made by PSEB within

7 days rom the date o receipt o invoice or which a rebate o 2% on ull payment shall be availed by

the Board. All payments shall be made by Cheque payable at Patiala.

3.4.0 In case there is no Generation at the Generating Facility, the Monthly Invoice Pursuant to Clause 2.2.3shall be delivered by the Board to the Generating Company at its designated oce on Invoice Date and

shall be paid by the Generating Company by the Due Date by cheque payable at Patiala.

3.5.0 In case the payments are delayed beyond the Due Date, the Board and the Generating Company would be

liable to pay interest or the delayed amount as per State Bank o India short term Prime Lending Rate

as applicable rom time to time plus 2% or the actual period o delay.

Appendix B




158

3.6.0 Board will provide to the Generating Company, an irrevocable and revolving Letter o Credit (LC)

issued by any Nationalized Bank equal to one month’s bill amount, calculated in accordance with

terms set out in Clause 3.7.0 o this Agreement, subject to the condition that all kinds o LC charges

will be borne by the Generating Company.

3.7.0 For the rst year o the operation o the Generating Facility, ater synchronization, the amount o quarterly

LC shall be determined on the basis o the quarterly designed energy o the Generating Facility, as per

the detailed Project Report.. Thereater the amount o quarterly LC shall be based on the monthly

average o the bills or three (3) months or the corresponding period last year.

3.8.0 The Board reserves the right to make direct payment o any bill by cheque beore or on the Due Date

o payment in which case, the Generating Company shall not present the bill or payment against the

Letter o Credit.

4.0.0 PARALLEL & INTEGRATED OPERATIONS

4.1.0 The Board shall allow the Generating Company to interconnect its Generating Facility and operate it in

parallel with the Board’s system subject to the terms and provisions o this Agreement. The Generating

Company shall run the Generating Facility as a part o the integrated system to generate power in

parallel with the grid and shall inject three phase 50 Hz (nominal) AC Supply into Board’s system at

11/66KV. The Generating Company shall be under an obligation to comply with directions received

rom the Board’s Load Dispatch Centre.

5.0.0 GENERATION FACILITIES-OPERATION & MAINTENANCE

5.1.0 The Generating Company shall be responsible or obtaining and keeping in orce at its own cost, al

consents, clearances and permits required or establishing and operating the Generating Facility viz

clearances rom National Airport Authority, Competent Authority or Environment & Forests, Chie

Electrical Inspector etc. required or keeping each unit o Generating Facility in operation in accordance

with the terms o this Agreement through out its operation period.

5.2.0 The Generating Company shall be responsible at its own expense or ensuring that the Power Station

is operated and maintained in accordance with all legal requirements including the terms o all

consents/clearances /permits and Prudent Utility Practices within the acceptable technical limits so

as not to have an adverse eect on the Grid system or violation o applicable law or violation o any

provision o State Grid Code.

5.3.0 The terms and conditions o employment o Personnel employed by the Generating Company shall

meet all applicable laws, rules, regulations and requirements in orce rom time to time in the State o

Punjab/Union o India.

5.4.0 Board shall have the right to designate rom time to time its ocers/ocials who shall be responsible

or inspecting the Generating Facility or the purpose o veriying the Generating Company’s

compliance with this Agreement.

5.5.0 The details o the ollowing procedures and requirements shall be supplied by the Generating

Company to the Board as soon as possible, but in no event later than 30 (Thirty) days prior to the

Scheduled Date o Synchronization:-

i) Detailed procedure or synchronization o the Generating Facility with the Board’s Grid under

dierent conditions o operation.ii) Shut down and start-up procedures.

5.6.0 The Generating Company shall carry out regular maintenance and overhauls o the Generating

Facility as per recommended schedules and procedures o the equipment suppliers. The schedule o

maintenance and overhauls which require a shut down o the Generating Facility shall be intimated

to the Board’s Load Dispatch Centre to which the Generating Facility is attached. However, capital

maintenance/major overhaul o the Generating Facility shall not be scheduled in “Paddy Season” i.e.

15th June to 15th October o any year as ar as possible.

Appendix B




159

5.7.0 The Generating Company shall supply the particulars o the generator as well as Generator Transormer

and control gear to the Board or examining stability o Generating Facility. The Generating Company

shall also install and whenever required, augment the equipment at its own cost to match it with the

ault level o Board’s system during the tenure o this Agreement.

5.8.0 The Generating Company shall use all reasonable eorts to give advance notice to the Board to the

extent possible o any unscheduled outage and shall provide the Board with an estimate o duration

and scope o such outage.

5.9.0 For matters relating to grid operations and load dispatch, the directions o the Board’s Load Dispatch

Centre or any other ocer which may be authorized by the Board shall be strictly complied with by

the Generating Company. Any dispute on this account shall be reerred to Chie Engineer In Charge

System Operation & Communication Organization whose decision shall be nal.

5.10.0 Open Access and Other Charges:The Open Access and other ees, charges, Surcharges, i any shall be

leviable as per Open Access Regulations as approved by PSERC or NRSE Projects.

6.0.0 SYNCHRONISATION AND INTERCONNECTION FACILITIES.

6.10 The synchronization equipment will be installed by the Generating Company at its Generating

Facility at its own cost. Generating Company shall synchronize its system with the Board’s system

only ater the approval o synchronization scheme is granted by Chie Engineer (C.E), Sub-Station o

the Board and checking/verication is made by the concerned Senior Executive Engineer (Sr. Xen),

Protection o the Board. The Generating Company shall, immediately ater each synchronization/

tripping o generator, inorm the grid substation to which the Generating Facility is electrically

connected.

6.2.0 The Generating Company shall provide step up transormers, panels, kiosks, protection & metering

equipment at the Generating Facility and ully equipped line bay(s) in its switch yard or termination

o interconnecting transmission line(s) o the Board. The Generating Company shall also provide

proper and reliable communication between the generation acility and Grid Sub-Station o the Board

where power is to be delivered by the Generating Facility. The cost o these works will be borne by

the Generating Company.

6.3.0 The Generating Company shall provide and maintain at its own cost required transmission line(s)

rom the Switch Yard o the Generating Facility to the nearest technically easible Board’s Grid

Sub-Station. Associated equipment (s) at Board’s Grid Sub-Station or accepting energy rom the

Generating Facility shall be provided and maintained by the Board. However, the Board may take

up as deposit work, construction o transmission line/works or evacuation o power on behal o the

Generating Company on their specic request or which the cost o transmission line/works shall be

deposited by the Generating Company within one month rom the date o achieving nancial closure

o the Project.

6.4.0 The Generating Company and the Board shall consult with each other and jointly decide on the

scheme or protection o the interconnection line (s) and o the acilities at both its ends. All electric

equipments installed shall be consistent with the orders o the Chie Electrical Inspector, Government

o Punjab.

6.5.0 Notwithstanding the provisions o this Agreement, the Board will not be responsible or any damagethat may occur to the Generating Facility with the Board’s system.

7.0.0 PROTECTIVE EQUIPMENT & INTERLOCKING

7.1.0 The Generating Company shall provide necessary protective equipment and interlocking devices at

Generating Facility, so co-ordinated that no adverse eect is caused to Board’s Grid System. The

Generating Company shall obtain approval o the Board or the protection logic o the generator

system and synchronization schemes and any modication thereto subsequent to commissioning o

the Generating Facility.

Appendix B




160

7.2.0 The Generating Company shall energize its equipment/synchronizing scheme only ater the approval

o the Chie Engineer (C.E) Protection & Maintenance o the Board at the time o commissioning

and thereater and rectication o the deects/observations pointed out by him. Routine checking/

testing shall be carried out o the Generating Company’s substation/equipment on the same basis as

is being done or Board’s Sub-Station.

7.3.0 Testing charges shall be borne by the Generating Company or commissioning as well as routine

checking.

7.4.0 Notwithstanding such checking/verication in any event, the Board shall not be responsible or any

damage caused to the Generating Facility on account o any mistake in such checking/verication.

8.0.0 LIAISON WITH AND ASSISTANCE FROM THE BOARD

8.1.0 The Generating Company shall closely liaise with the Board’s Load Dispatch Centre and/or other

designated ocers/ocials o the Board during the Term o this Agreement. During the term o this

Agreement the Generating Company shall give seven (7) days prior intimation o synchronizing

programme or the rst time, ater completion o its annual maintenance programme and also urnish

in the last week o every month supply plan indicating the total quantum o electricity likely to be

delivered in the next month.

8.2.0 The Generating Company shall also inorm the date o commencement o delivery o power, one

month in advance and arrange or testing and commissioning o the protection system beore

synchronization.

9.0.0 METERING

9.1.0 ABT compliant Energy Meters (export and import) o 0.2S class or better accuracy meeting with the

specication laid down in State Grid Code or use on IPP/CPP generating plants shall be installed

at Interconnection Point by the Generating Company, capable o recording and storing 15 minutes

averages o all the Electrical Parameters or a minimum o 45 days (hereinater called Main Meters).

Similar meters, (export and import) o the same accuracy shall be installed by the Generating

Company at the Grid Substation o PSEB where power is received (hereinater called Check Meter).

Dedicated Current Transormers (CTs) and Potential Transormers (PTs) o 0.2S class or better

accuracy shall also be made available by the Generating Company at the Interconnection Point.

9.1.1 One set o metering equipment having 0.2S or better accuracy class and eatures identical to those

described in Clause 9.1.0 above should also be provided in the premises o each o the third parties.

9.2.0 All the Meters, CTs and PTs described in Clause 9.1.0 above shall be jointly inspected and sealed on

behal o both Parties and shall not be interered with except in the presence o the representatives o

both Parties. For testing and calibration o meters, a notice o at least seven (7) days shall be given by

the Party requesting or the testing, to enable the authorized representatives o both the Parties to be

present.

9.3.0 All meters, CTs & PTs shall be checked in Board’s Laboratory and eectively sealed by Board

and the Generating Company jointly or accuracy prior to commissioning and once in every six (6)

months by both Parties and shall be treated as working satisactorily so as long the errors are within

the limits prescribed or such meters.

9.4.0 Meter readings o the Main Meters will orm the basis o billing, so long as the hal yearly checksthere o are within the prescribed limit. I either o the meters is ound to be deective during these

checks they will be immediately calibrated.

9.5.0 Where the hal yearly check indicates errors in the Main Meters beyond the prescribed limit but no such

error is noticed in the Check Meters, billing or the month up to the date & time o such test check will

be done on the basis o Check Meters and the Main Meters will be re-calibrated immediately. Billing

or the period ater the Main Meters are calibrated shall be as per the calibrated meters.

Appendix B




161

9.6.0 I during the hal yearly checks, both the Main Meters and the Check Meters are ound to be beyond

permissible limits o error, the meters shall be immediately re-calibrated and the correction shall be

applied to the consumption registered by the Main Meters to arrive at the correct consumption o

energy or billing purposes or the period o the month up to the time o such check, billing or the

period thereater till the next monthly meter reading shall be measured by re-calibrated Main Meters

9.7.0 Corrections in billing, whenever necessary, shall be applicable to the period between date and time o the

previous last test calibration and the date and time o the test calibration in the current month when the

error is observed and this correction shall be or the ull value o the absolute error. For the purpose o

the correction to be applied the meter shall be tested at 100, 75, 50, 25 and 10 percent load at unity, 0.85

Lag and 0.75 lag power actors. O these teen values, the error at the load and power actor nearest

the average monthly load served at the point during the period shall be taken as the error to be applied

or correction.

9.8.0 The billing will be normally done on the basis o readings recorded by the meters installed at the

interconnection Point (Main Meters). In case, the metering equipment at the Interconnection Point

becomes deectives, the billing shall be done on the basis o meter readings o the meters installed at

Board’s Grid substation. The deective metering equipment shall however be replaced by the Generating

Company within two (2) months o the detection o the deect by either party.

9.9.0 I both the Energy Meters located at the Interconnection Point and Board’s Grid Substation ail to record

the electricity supplied then the electricity supplied will be computed rom the log sheets maintained at

Board’s Grid Substation or that period o deect which shall be nal and binding on both Parties.

9.10.0 For the purpose o test and calibration, the sub standard meter shall be got calibrated and sealed rom

a reputed Govt. testing Laboratory. This meter shall be calibrated once in every 2 years.

9.11.0 In addition to the above metering clauses the Generating Company has to comply with the State Grid

Code (Meter Section).

10.0.0 COMMISSIONING OF GENERATING FACILITY

10.1.0 The Generating Company shall commission the Generating Facility and synchronize with the Board’s

Grid which shall be______days (______years) rom the date o signing o this agreement (to be

provided as per the MoU / Implementation Agreement signed with PEDA).

11.0.0 CONTINUITY OF SERVICE

11.1.0 The Board may require the Generating Company to temporarily curtail or interrupt deliveries o energy

only, when necessary in the ollowing circumstances;-

11.1.1 For repair, replacement and removal o the Boards equipment or any part o its system that is associated

with the Generating Company’s acility. However, as ar as practicable such an event shall be scheduled

during the annual shut-down period o the Generating Facility.

11.1.2 Load crash in Board’s Grid System due to wide spread rains, cyclones or typhoons.

11.1.3 Conditions leading to over - loading o interconnecting transormers, transmission lines and Switch-

gears due to outage o some equipment at the Board’s interconnecting Grid.

11.1.4 I the Board determines that the continued operation o the Generating Facility may endanger the saety

o the Board’s personnel or integrity o the Board’s electric system or have an adverse eect on the

electric service to the Board’s other customers.11.1.5 Under Force – Majeure Conditions o the Board.

11.1.6 In line with directions received rom the Board’s Load Dispatch Centre.

11.1.7 Instructions or the disconnection o the Generating Facility rom the Board’s system shall be notied

by the Board’s Load Dispatch Centre or the period/ duration indicated by it. However, the Board shall

take all reasonable steps to minimize the number & duration o such interruptions, curtailments or

reductions.

Appendix B




162

12.0.0 TERM OF THE AGREEMENT

12.1.0 Except where terminated by deault, this Agreement shall remain in orce or a period o 30 (Thirty) years

rom the date o commissioning o the Project, which could be extended through mutual agreement.

13.0.0 EVENTS OF DEFAULT AND TERMINATION

13.1.0 The occurrence o any or combination o the ollowing events at any time during the term o this

Agreement shall constitute an Event o Deault by the Generating Company:-

Failure to pay to the Board any amount payable and due under this Agreement within sixty (60) calendara)

days ater receipt o Monthly Invoice, or

Failure on the part o the Generating Company to use reasonable diligence in operating, maintaining or b)

repairing, the Generating Facility, such that the saety o persons and property, the Board’s equipment

or the Board’s service to others is adversely aected, or

Failure or reusal by the Generating Company to perorm its material obligations under this Agreementc)

or

Failure to use Solar Photovoltaic Energy Sources or generation o power as per NRSE Policy 2006.d)

Abandonment o its Generating Facility by the Generating Company or the discontinuance by thee)

Generating Company o service covered under this Agreement unless such discontinuance is caused by

Force Majeure or an event o deault by the Board.

13.2.0 The occurrence o any o the ollowing at any time during the term o this Agreement shall constitute

an Event o Deault by the Board: -

Failure to pay to the Generating Company any amount payable and due under this Agreement withina)

sixty (60) calendar days ater receipt o Monthly Invoice, or

Failure to use reasonable diligence in operating, maintaining or repairing the Board’s interconnecting b)

acilities, such that the saety o persons or property, the Generating Company’s equipment or the

Generating Company is adversely aected, or

Failure or reusal by the Board to perorm its material obligations under this Agreement.c)

13.3.0 Except or ailure to make any payment due within sixty (60) calendar days ater receipt o Monthly

Invoice, i an Event o Deault by either party extends or a period o sixty (60) calendar days ater

receipt o any written notice o such Event o Deault rom the non-deaulting party, then the non

deaulting party may, at its option, terminate this agreement by delivering written notice o such

termination to the party in deault.

I the deault pertains to the Board, then provisions o Article 14.0.0 and 15.0.0 below shall apply.(i)

I the deault pertains to the Generating Company the Board may at its option:(ii)

Require the Generating Company to cure the deault and resume supply to the Board within sixty (60)a)

days o receipt o notice rom the Board.

I the Generating Company is unable to cure the deault and resume supply within the stipulated time b)

rame and in consequence thereo, the Project is sold or transerred or assigned to any third party,

in compliance with the provisions o any agreement(s) executed by the Generating Company with

any third party or raising equity/debt or the Project or in terms o the Implementation Agreement

executed with PEDA, require such third party to cure such Generating Company Deault and resume

supply rom the Generating Facility to the Board or the remaining Term o the Agreement.Terminate the Agreement.c)

The parties agree that all third parties, successors and permitted assigns o the Generating Companyiii)

shall be bound by the provisions o this Agreement which shall be binding and have ull orce, and

eect on such third parties.

Appendix B




163

I the supply is not resumed at the Generating Facility by the Generating Company or by the third partyiv)

(who takes over the Generating Facility rom the Generating Company) in accordance with Clause

13.3.0 (ii) (b) o this Agreement, the Board shall be well within its rights to approach PSERC or

deciding the compensation payable to Board or purchase o costly power rom the Generating Facility

in the initial years o this PPA and not supplying power to PSEB or entire period o the Agreement in

line with PSERC decision dt. 13.12.07.

13.4.0 The non-deaulting party may also institute such legal action or proceedings or resort to such other

remedies as it deems necessary.

13.5.0 Failure by either the Board or the Generating Company to exercise any o its rights under this

Agreement shall not constitute a waiver o such rights. Neither Party shall be deemed to have waived

any ailure to perorm by the other unless it has made such waiver specically in writing.

13.6.0 Either the Board or the Generating Company may terminate this Agreement upon notice to the other

party, i the Generating Facility ails to begin producing electric energy within three (3) years rom

the planned commercial operational date.

14.0.0 WHEELING OF POWER

14.1.0 Only in the event o deault by the Board as provided under clause 13.3.0 (i) o this Agreement,

the Board will subject to and in accordance with directions, orders or regulations issued by the

Commission provide access to its Transmission and Distribution System or wheeling o power

generated at the Generating Facility to the third parties under separate tripartite agreement among,

Generating Company, Board and third party and at a uniorm wheeling charges @ 2% o the energy

injected into Board’s Grid, or wheeling purposes. These wheeling charges will be applicable

irrespective o the distance o the third party rom the Generation Facility. The Generating Company

would not sell power at any time to any third Party consumer(s) at a rate lower than the Board’s

tari/rate applicable to such consumer(s). The third Party shall be existing 11 KV or high voltage

consumers o the Board having a minimum load o one (1) mega watt (MW) and shall include only

those consumers to whom open access has been allowed by the Commission and who are entitled to

enter into agreement or supply or purchase on mutually acceptable conditions.

14.2.0 The tripartite agreement or sale o power to third parties shall be initially or a period not exceeding 6

months extendable or 6 months each time until the deault is cured by the Board. Ater rectication

o the deault, the Board shall inorm the Generating Company. The Generating Company in such

an event shall resume power supply to the Board ater the expiry o the then existing tripartite

agreement.

14.3.0 The Generating Company shall also bear transmission and distribution losses, surcharges, operation

charges, additional surcharges, UI Charges and reactive energy charges and/or any other charge/cess

specied by the Commission as per Open Access Regulations ramed by the Commission or such

wheeling o power to third parties rom New & Renewable Sources o Energy (NRSE) based power

projects.

14.4.0 The quantum o energy towards charges or wheeling o power as per clause 14.1.0 and 14.3.0 above

shall be deducted rom the energy delivered to the Board system or wheeling as measured at the

Interconnection Point and monthly energy account pursuant to clause 3.2.0 shall be prepared by theBoard accordingly.

14.5.0 For the energy delivered by the Generating Company and wheeled to third parties, the Generating

Company shall raise Monthly Invoices on the party(ies) directly. For the energy sold by the Board to

third parties, bills shall be raised by the Board directly on third parties as per applicable commercial

instructions issued by the Board and the applicable tari.

Appendix B




164

14.6.0 Out o the energy delivered by the Generating Company to the Board or wheeling to consumers, the

quantum o energy not used by the consumers, shall be treated as ‘energy banked’ with Board in

terms o Clause 15.0.0.

14.7.0 The third Parties would continue to be governed by commercial instructions in respect o their

agreements with Board already executed including monthly minimum charges.

15.0.0. BANKING OF POWER

Only in the event o deault by the Board as provided under Clause, 13.3.0 (i), acility or banking o the

power generated shall be allowed to the Generating Company or a period o one year by the Board. Further,

the Generating Company willing to avail acility o banking o Power would indicate every month the energy

oered to Board or wheeling and to be banked. During the period starting rom 15th June to 15th October

o every year, no drawl o energy will be allowed. Chie Engineer (C.E.), In charge o the System Operation

Organization o the Board may allow drawl o banked energy during this period at his option and i Board

does not allow drawl o banked energy, during the whole or part o the said period, the period o one year will

be extended accordingly.

16.0.0 DISPUTES AND ARBITRATION

16.1.0. Both Parties shall comply with the provisions o this Agreement and discharge their respective

obligations. In the event any Dispute arises out o or in connection with any o the terms o this

Agreement between the Parties, hereto, the Parties shall attempt resolving the Dispute by mutual

discussions, to be held between designated representatives o the Generating Company and the Chie

Engineer In charge/System Operation& communication Organization or any other ocer authorized

by him. In case the Dispute remains unresolved, it shall be resolved in accordance with the provisions

o Clause 16.2.0.

16.2.0 All Disputes between the Parties arising out o or in connection with this Agreement which the Parties

are unable to resolve by mutual discussions in terms o procedure set out in Clause 16.1.0, shall be

determined by arbitration, by such person or persons as the Commission may nominate in that behal

on receipt o application by either party (unless it is otherwise expressly provided in the license

issued to the Board or its successor entity) in terms o provisions o the Electricity Act, 2003. The

venue or arbitration shall be Patiala, Punjab.

16.3.0 The arbitration shall be conducted in accordance with the provisions o the Arbitration and

Conciliation Act 1996 as amended rom time to time.

16.4.0 Notwithstanding the existence o any question, disputes and dierence reerred to arbitration the

Parties hereto shall continue to perorm their respective obligation under this Agreement and the

payment o any bill preerred shall not be with held by the Board or any reason whatsoever including

the pendency o the arbitration.

17.0.0 INDEMNIFICATION

17.1.0 The Generating Company shall indemniy, deend and hold harmless the Board and its Members,

Directors, Ocers, employees and agents and their respective heirs, successors, legal representatives

and assigns rom and against any and all liabilities, damages, costs expenses (including attorneys

ees), losses, claims, demands, action, cause o action, suits and proceedings o every kind, including

those or damage to property o any person or entity (including the Co.) and/or or injury to or death o any person (including the Generating Company’s employees and agents) which directly or

indirectly result rom or arise out o or in connection with negligence or willul misconduct o the

Generating Company.

17.2.0 The Board shall indemniy and hold harmless the Generating Company and its Directors, Ocers,

employees and agents and their respective heirs, successors, legal representatives and assigns, rom

and against any and all liabilities, damages, costs, expenses (including outside attorneys ees), losses,

claims, demands actions, cause o action, suits and proceedings o every kind, including those or

Appendix B




165

damage to the property or any person or entity (including the Board) and/or injury to or death o any

person (including the Board’s employees and agents) which directly or indirectly result rom partial/

total grid ailure or arise out o or in connection with the negligence or willul misconduct o the

Board.

18.0.0. ASSIGNMENT

18.1.0 This Agreement may not be assigned by either the Board or the Generating Company, without

the consent in writing o the other party, except that either party may assign its rights under this

Agreement, or transer such rights by operation o law, to any corporation with which or into which

such party shall merge or consolidate or to which such party shall transer all or substantially all o

its assets provided that such assignee or transeree shall expressly assume, in writing, delivered to

the other party to this Agreement, all the obligations o the assigning or transerring party under this

Agreement.

19.0.0 FORCE MAJEURE

19.1.0 I any party hereto shall be wholly or partially prevented rom perorming any o its obligations under

this Agreement by reason o or on account o lightning, earthquake, re, foods, invasion, insurrection

rebellion, mutiny, civil unrest, riot, epidemics, explosion, the order o any court, judge or civil authority

change in applicable law, war, any act o God or public enemy or any other similar cause or reason

reasonably beyond its control and not attributable to any negligent or intentional act, error or omission

then such party shall be excused o its obligations/liabilities under this Agreement and shall not be

liable or any damage, sanction or loss resulting there rom to the other party.

19.2.0 The party invoking this clause shall satisy the other party o the existence o any Force Majeure event

and give written notice within seven(7) days o the occurrence o such Force Majeure event to the

other party and also take all reasonable and possible steps to eliminate, mitigate or overcome the eect

and consequence o any such Force Majeure event.

19.3.0 In the event o a Force Majeure event or conditions, any payment due under this Agreement shall be

made as provided herein and shall not be withheld.

20.0.0 AUTHORITY TO EXECUTE

20.1.0. Each respective party represents and warrants as ollows:-20.2.0 Each respective party has all necessary rights, powers and authorities to execute, deliver and perorm

this Agreement.

20.3.0 The execution, delivery and perormance o this Agreement by each respective party will not result

in a violation o any law or result in a breach o any government authority, or confict with or result

in a breach o or cause a deault under any agreement or instrument to which either respective party

is a party or by which it is bound. No consent o any person or entity not a party to this Agreement,

including and government authority is required or such execution, delivery and perormance by each

respective party.

21.0.0 LIABILITY AND DEDICATION

21.1.0 Nothing in this Agreement shall create any duty or standard o care with reerence to or any liability to

any person not a party to it.21.2.0 No undertaking by one party to the other under any provision o this Agreement shall constitute the

dedication o that party’s system or any portion thereo to the other party or to the public or eect the

status o the Board as a public utility or constitute the Generating Company or the Generating Facility

as a public utility.

Appendix B




166

22.0.0 NODAL AGENCY OF THE BOARD

22.1.0 Chie Engineer In charge/System Operation Organization o the Board shall act as a nodal agency or

implementing this Agreement.

23.0.0 AMENDMENTS

23.1.0 Any waiver, alteration, amendment or modication o this Agreement or any part hereo shall not be

valid unless it is in writing and signed by the Parties.

24.0.0 BINDING EFFECT

24.1.0 This Agreement shall be binding upon and enure to the benet o the Parties hereto and their

respective successors, legal representatives and permitted assigns.

25.0.0 NOTICES

25.1.0 Any written notice provided hereunder shall be delivered personally or sent by registered post

acknowledgement due or by Courier or receipted delivery with postage or courier charges prepaid to

the other party at the ollowing address:

Board:

Beore commissioning o the Project:

Chie Engineer (Hydel Projects)

(Investment Promotion Cell)

A-4, Shakti Vihar, PSEB,

Patiala – 147001.

Ph: 0175-2215415/2220784

Teleax: 0175-2207753/2220784

Ater commissioning o the Project

Chie Engineer/System Operation & Communication,

SLDC Building,

220 KV Grid Sub-Station, PSEB,

Ablowal, Patiala.

Phone: 0175-2366007 Fax: 2367490

Generating Company: -

M/S

Phone E-mail:

Notice delivered personally shall be deemed to have been given when it is delivered to the Generating

Company at address set orth above and actually delivered to such person or let with a responsible person in

such oce. Notice sent by post or Courier shall be deemed to have been given on the date o actual delivery

as evidenced by the date appearing on the acknowledgement o delivery.

25.2.0. Any party hereto may change its address or written notice by giving written notice o such changes to

the other party hereto.

26.0.0. EFFECT OF SECTION HEADINGS

26.1.0. The headings or titles o the several sections hereo are or convenience o reerence and shall not

eect the construction or interpretation o any provision o this Agreement.

27.0.0. NON-WAIVER

No delay or orbearance o either party in the exercise o any remedy or right will constitute a waiver thereo

and the exercise or partial exercise o remedy or right shall not preclude urther exercise o the same or any

other remedy or rights.

Appendix B




167

28.0.0. RELATIONSHIP OF THE PARTIES

28.1.0 Nothing in this Agreement shall be deemed to constitute either party hereto as partner, agent or

representative o the other party or to create any duciary relationship between the Parties.

29.0.0. ENTIRE AGREEMENT

29.1.0 This Agreement constitutes the entire understanding and Agreement between the Parties.

30.0.0. GOVERNING LAW

30.1.0 This Agreement shall be governed by and construed in accordance with applicable laws o the State o

Punjab.

31.0.0.NO PARTY DEEMED DRAFTER

The parties agree that no party shall be deemed to be drater o this Agreement and that in the event this

Agreement is ever construed by arbitrators, or by a court o law, they shall not construe this agreement

or any provision hereo against either party as the drater o the Agreement. The Board and the Company

acknowledging that both parties have contributed substantially and materially to the preparation o this

Agreement.

32.0.0. USE OF NON CONVENTIONAL ENERGY SOURCES:

32.1.0. The Generating Company will produce power using only Solar Photovoltaic energy sources or

which the project has been approved. A suitable proorma shall be devised at least one month beore

commissioning o the Project through which Generating Company shall report on a monthly basis the

continuous use o non-conventional sources(s) or which the Project has been approved or the power

generated and sold to the Board. Occasional checks shall be executed by the Board to ensure the use

o non-conventional source usage. In case the Generating Company is ound using sources other than

these, Board shall be well within its right to get the tari rates revised suitably by making reerence to

Commission.

33.0.0. APPROVAL

33.1.0. Wherever either Board or Generating Company approvals are required in this Agreement, it is

understood that such approvals shall not be unreasonably withheld.

34.0.0. FURTHER INSTRUMENTS

34.1.0. Each o the Parties agrees to execute and deliver all such urther instruments and to do and perorm

all such urther acts and things, as shall be necessary and required to carry out the provisions o this

Agreement and to consummate the transactions contemplated hereby.

Appendix B




168

35.0.0. INTERPRETATION

35.1.0 The headings used in this Agreement are inserted or convenience o reerence only and shall not

eect the interpretation o the respective clauses and paragraphs o this Agreement.

(a) This Agreement has been executed in the English language only and thus the English language shall

be the controlling language or interpretation thereo.

This Agreement together with the Annexure constitutes the whole and only Agreement as at the date(b)

hereo between the Parties with respect to the subject matter described herein.

IN WITNESS WHERE OF, the Board and the Generating Company have executed this Agreement as o the____

day o_________, in the year 2008.

For the Generating Company For the Board

by by

Its Its

Witness by: Witness by:

Name: Name:

Designation Designation

Address: Address:

ANNEXURE-I

DETAILS OF _________________SOLAR PHOTOVOLTAIC POWER PROJECT.

S.No. Name o

Project

District Capacity

(MW)

Commissioning

Schedule

Feeding

Grid o

Board

Remarks.

Appendix B




169

United States

PG&E Schedule E-SRG and a Small Generator PPA or purchases o renewable generation or eligible acilities.

<http://www.pge.com/taris/tm2/pd/ELEC_SCHEDS_E-SRG.pd >.

Power Purchase Agreement Between Del Marva Power and Light Company and Bluewater Wind Delaware LLD.

<http://www.ocean.udel.edu/Windpower/DE-Qs/Delmarva-Bluewater-PPA-10-December-07.pd >.

Appendix B




170

Reerences

Alderer, R. Brent, M. Monika Eldridge and Tomas j. Starrs. “Making Connections: Case Studies o Interconnection

Barriers and their Impact on Distributed Power Projects.” May 2000. U.S. Department o Energy. 19

February 2009. <http://www1.eere.energy.gov/emp/pds/28053.pd >.

APP Report “Pursuing Clean Energy Business in India” <http://74.125.45.104/search?q=cache:nWFc30ZvTJIJ:tp://tp.asiapacicpartnership.org/RenewableEnergyTF/RDG-06-10_Report.pd+Report+on+APP-REDGTF+pro

ject+on+renewable+energy+in+India&hl=en&ct=clnk&cd=1&gl=us >

Asian News International. “Renewable energy certicate improve commercial viability o RE electricity.” 17 Dec.

2008. DailyIndia.com. 9 Feb. 2009 <http://www.dailyindia.com/show/287344.php>.

Australia. Attorney General’s Department. “Renewable Energy (Electricity) Act 2000.” 18 July 2008.

Commonwealth o Australia Law. 8 Feb. 2009 <http://www.comlaw.gov.au/>.

---. Oce o the Renewable Energy Regulator. 29 Jan. 2009 <http://www.orer.gov.au/legislation/index.html>.

Baker & McKenzie. “Identiying optimal legal rameworks or renewable energy in India.” Nov. 2008. World

Institute or Sustainable Energy. 9 Feb. 2009. http://www.wisein.org/pd/Backer-and-Meckanzy.pd [sic].

---. “Report on APP-REDGTF project on renewable energy in India.” Prepared by Baker & McKenzie and World

Institute o Sustainable Energy. Apr. 2008. Baker & McKenzie. 9 Feb. 2009 <http://www.bakernet.com/NR/

rdonlyres/0251961F-DACD-4C9E-9415-A7A24A28485C/44792/RenewableenergyinIndia.pd >.

Beck, Fred and Eric Martinot. “Renewable Energy Policies and Barriers.” Encyclopedia o Energy. Ed. Cutler J.

Cleveland. New York: Academic Press/Elsevier Science, 2004. 10 Feb. 2009 <http://www.martinot.ino/

Beck_Martinot_AP.pd >.

Begovi, M., A. Pregelj, A. Rohatgi and D. Novosel. “Impact o Renewable Distributed Generation on Power

Systems.” Power Systems Engineering Research Center. 10 Feb. 2009 <http://www.pserc.wisc.edu/ecow/get/

publicatio/2000public/CSSAR01.PDF >.

Bhushan, Bhanu. “ABC o ABT: A Primer on Availability Tari.” 27 June 2005. Powergrid Corporation o India

Limited. 29 Jan. 2009 <http://www.nldc.in/docs/abc_abt.pd >.

Blankinship, Daniel. “Distributed generation: It’s all a matter o control.” August 2003. Power Engineering. 10 Feb.

2009 <http://pepei.pennnet.com/>.

Bode, Sven and Helmuth-M. Groscurth. “Incentives to Invest in Electricity Production rom Renewable Energy

under Dierent Support Schemes. An evaluation o eed-in taris and renewable energy certicate trading

schemes in the context o expansion targets or renewable energies in the EU.” Arrhenius Institute or Energy

and Climate Policy. 10 Feb. 2009 <http://www.arrhenius.de/leadmin/redaktion/pd/arrhenius_DP_1E.pd >.

Reerences




171

Bradley, Douglas. “Renewable Portolio Standard (RPS) & Other Incentives: Harmonization Opportunities in

Canada.” 16 Feb. 2005. Canadian Bioenergy Association. 10 Feb. 2009 <http://www.canbio.ca/documents/

publications/Renewable_Harmonize_Final_Feb_16_2005.pd >.

Bründlinger, Roland and Sara White. “Unintentional Islanding in Distribution Systems with DG.” 21 Oct. 2005.

Institut ür Solare Energieversorgungstechnik–ISET. 10 Feb. 2009 <http://www.iset.uni-kassel.de/dispower_

static/documents/highlight028.pd >.

Caliornia. Energy Commission. “Interconnection Guidebook: A Guide to Interconnecting Customer-Owned Electric

Generation Equipment to the Electric Utility Distribution System Using Caliornia’s Electric Rule 21.” Sept.

2003. Caliornia Energy Commission. 9 Feb. 2009 <http://www.energy.ca.gov/reports/2003-11-13_500-03-

083F.PDF>.

---. ---. “Caliornia Distributed Energy Resource Guide.” 4 Apr. 2005. Caliornia Energy Commission. 9 Feb. 2009

<http://www.energy.ca.gov/distgen/interconnection/application.html >.

---. ---. “Caliornia Electric Rule 21 Supplemental Review Guideline.” 26 Aug. 2005. Caliornia Energy

Commission. 9 Feb. 2009 <http://www.energy.ca.gov/distgen/interconnection/

SUP_REV_GUIDELINE_20050831.PDF>

---. ---. “Rule 21 Model Rule Drat to Implement D.05-08-013.” 24 Feb. 2006. Caliornia Energy Commission. 9 Feb.

2009 <http://www.energy.ca.gov/distgen/interconnection/RULE_21_MODEL_RULE_02-2006.PDF>.

---. --. “CPUC Sel-Generation Incentive Program (SGIP) Seventh-Year Impact Evaluation Highlights.” Caliornia

Public Utilities Commission. 9 Feb. 2009 <http://www.cpuc.ca.gov/NR/rdonlyres/783F30E1-4894-42FD-

BC74-449E17283F3E/0/SGIP_7thYearImpactEvalReport_Highlights_2.pd >.

---. ---. “Order Instituting Rulemaking Into Distributed Generation.” Rulemaking 99-10-025. 21 Oct. 1999.

Caliornia Public Utilities Commission. 9 Feb. 2009 <http://docs.cpuc.ca.gov/Published/Graphics/24842.

PDF>.

---. ---. “Supplemental Comments: Distributed Generation and Cogeneration Policy Roadmap or Caliornia, March

2007.” CEC-500-2007-021. 21 May 2007. Caliornia Energy Commission. 15 February 2009 http://www.energy.ca.gov/2007_energypolicy/documents/2007-05-07_workshop/public_comments/ELECTRICAL_ POWER_RESEARCH_INSTITUTE_2007-05-21.PDF.

“Capacity o the Victorian Electricity Transmission Network to Integrate Wind Power.” Dec. 2007. Vencorp. 9 Feb.

2009 <http://www.vencorp.com.au/>.

“Clean Renewable Energy Bonds (“CREBs”).” 3 Mar. 2006. National Rural Electric Cooperative Association. 9 Feb.2009 <http://www.nreca.org/documents/publicpolicy/cleanrenewableenergybonds.pd >

Connecticut. Natural Gas Corporation. “Connecticut Natural Gas Corporation Rider DG (Distributed Generation

Rebate Rider).” Connecticut Natural Gas Corporation. 9 Feb. 2009 <http://www2.cngcorp.com/marketer_

services/RATE_DG.pd >.

Reerences




172

Cosbey, Aaron, Jennier Ellis, Mahnaz Malik, and Howard Mann. “Clean Energy Investment Project Synthesis

Report.” July 2008. International Institute or Sustainable Development. 9 Feb. 2009 <http://www.iisd.org/

pd/2008/cei_synthesis.pd >.

Dadhich, Pradeep K. “Support Schemes or Renewable Energy: The Case or Feed-in Taris.” Akshay Urja. Volume

2 Issue 1, July-August 2008. Ministry o New and Renewable Energy. 9 Feb. 2009 <http://www.mnes.nic.in>

Dashash, Mohammad, and Emad Ragaban. “Energy Cost Optimization Through The Implementation o

Cogeneration and Grid Interconnection.” May 2007. CIRED. 10 Feb. 2009 <http://www.cired.be/CIRED07/

pds/CIRED2007_0004_paper.pd >

Deo, Pramad, A. Velayutham, and S. B. Kulkarni. “MSEDCL Proposal or approval o recovery o additional cost

as a reliability charge or mitigating load shedding in Pune Circle.” Case No. 1 o 2006. 25 Jan. 2006.

Maharashtra Electricity Regulatory Commission. 9 Feb. 2009 <http://mercindia.org.in/pd/21_Order_

CN_01%20o%202006_DRAFT.pd >.

“Distributed Generation: In a Fair and Competitive Marketplace.” Gas Turbine Association. 9 Feb. 2009. <http://

www.gasturbine.org/disgen.pd >.

El-Sayed, M. and Eat Moussa. “Eect o Large Scale Wind Farms On the Egyptian Power System Dynamics.”

ICREPQ’09. 9 Feb. 2009 <http://www.icrepq.com/icrepq-08/216-el-sayed.pd >.

“Electricity Generation and Environmental Externalities: Case Studies.” September 1995.

Energy Inormation Administration. 20 Feb. 2009. <http://www.eia.doe.gov/cnea/electricity/external/

external.pd >.

Electricity Supply Research Network. “SYStem integration o Non-ThERmal generation (SYNTER).” Mar. 2008.

The University o Nottingham. 10 Feb. 2009 <http://www.nottingham.ac.uk/esrnetwork/Systems%20

Integration%20o%20non-thermal.doc>.

European Union. Directive 2001/77/EC o the European Parliament and o the Council on the promotion o

electricity produced rom renewable energy sources in the internal electricity market. 27 September 2001.

Eur-Lex. 17 February 2009. http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2001:283:0033:0040:EN:PDF.

Feltes, C., S. Engelhardt, J. Kretschmann, J. Fortmann, F. Koch, and I. Erlich. “High Voltage Ride-Through o DFIG-

based Wind Turbines.” 2008. Herzlich Willkommen im Webangebot der Universität Duisburg-Essen. 10 Feb.

2009 <http://www.uni-due.de/ean/downloads/papers/eltes2008b.pd >.

Ferrey, Steven. “Small Power Purchase Agreement Application or Renewable Energy Development: Lessons romFive Asian Countries.” Feb. 2004. Prepared or the Asia Alternative Energy Program (ASTAE). The World

Bank, with support rom the United Nations Development Programme. 6 Feb. 2009 <http://siteresources.

worldbank.org/INTEAPREGTOPENERGY/Resources/Power-Purchase.pd >.

Fleming, Clare. “Financing or Renewable Energy.” Nov. 2005. Global Environment Facility. 9 Feb. 2009 <http://

www.geweb.org/projects/Focal_Areas/climate/documents/Financing_or_Renewable_Energy.pd >.

Reerences




173

“Generation-Based Incentive or Wind Announced: A Precursor to PTC?” Green Energy. Vol. 4 No. 3 May-June

2008. 9 Feb. 2009 <http://www.wisein.org/pd/GEPDF/GE-May-June08.pd >.

“Gujarat Electricity Regulatory Commission (GERC) Distribution Code. Notication 6 o 2004.” The Gujarat

Government Gazette. 25 Aug. 2004. Paschim Gujarat Vij Company Limited. 9 Feb. 2009 <http://www.pgvcl.

com/regulations/DistributionCode.pd >.

“Gujarat Electricity Regulatory Commission (GERC) Grid Code. Notication: No. 5 o 2004.” The Gujarat

Government Gazette. 25 Aug. 2004. State Load Despatch Centre- Gujarat. 9 Feb. 2009 <http://sldcguj.com/

compdoc/stategridcode.pd >.

Guru, Dillip. “Achieving India’s Wind Power Goal rom a Grid Interconnection Perspective.” Presentation given on

4 April 2008 in Chandigarh, India. United States Energy Association. 29 Jan. 2009 <http://www.usea.org/

Programs/APP/Punjab_Workshop/01_GE_Wind.pd >.

Hammons, T., L. L. Lai, and K. P. Wong. “International Practices in Distributed Generation.” IEEE Power

Engineering Society Energy Development and Power Generation Committee. Proc. o IEEE PES General

Meeting, Pittsburgh, PA. IEEE. 10 Feb. 2009 <http://ewh.ieee.org/cmte/ips/2008GM/2008GM_dg.pd >.

Hadley, S. W., J. W. Van Dyke, W. P. Poore, and T. K. Stovall. “Quantitative Assessment o Distributed Energy

Resource Benets.” May 2003. U.S. Department o Energy. 9 Feb. 2009 <http://www.eere.energy.gov/de/

pds/quantitative_benets.pd >.

Haynes, Rusty and Chuck Whitaker. “Connecting to the Grid: A Guide to Distributed Generation Interconnection

Issues, 5th ed.” 2007. Interstate Renewable Energy Council. 9 Feb. 2009. <http://www.irecusa.org/leadmin/

user_upload/ConnectDocs/IC_Guide.pd >.

IEEE. “IEEE P1547.3 Drat Guide For Monitoring, Inormation Exchange, and Control o Distributed Resources

Interconnected with Electric Power Systems.” 2007. IEEE. 9 Feb. 2009. <http://grouper.ieee.org/groups/

scc21/1547.3/1547.3_index.html >

India. Gujarat Electricity Regulatory Commission. “Tari or grid interactive Demonstration Solar Power Plants or

the purpose o MNRE.” Mar. 2008. Order No. 1 o 2009. Gujarat Electricity Regulatory Commission. 6 Feb.

2009 <http://www.gercin.org/docs/Orders/Other%20orders/Year%202009/Order%201%20o%202009.pd >.

---. Ministry or Non-Conventional Energy Sources. “Renewable Power Policies Programme-Wise.” Ministry or

Non-Conventional Energy Sources. 9 Feb. 2009 <http://mnes.nic.in/policy/policy-programme-wise.htm >.

---. Ministry o New and Renewable Energy. “Annual Report 2007-2008.” Ministry o New and Renewable Energy. 9

Feb. 2009. <http://www.mnes.nic.in/annualreport/2007_2008_English/content.htm >.

---. Ministry o Power. “Electricity Act, 2003.” 10 June 2003. Ministry o Power. Government o India. 9 Feb. 2009

<http://powermin.nic.in/acts_notication/electricity_act2003/preliminary.htm >.

---. ---. “National Electricity Policy (2005).” 12 Feb. 2005. Ministry o Power. Government o India. 29 Jan. 2009

<http://powermin.nic.in/indian_electricity_scenario/national_electricity_policy.htm >.

Reerences




174

---. Orissa Electricity Regulatory Commission. “National Electricity Tari Policy (2006).” Orissa Electricity

Regulatory Commission. 10 Feb. 2009 <http://www.orierc.org/new1/documents/National%20Electricity%20

Tari%20Policy.pd >.

---. Prime Minister’s Oce. “National Action Plan on Climate Change.” Prime Minister‘s Oce. 10 Feb. 2009

<http://pmindia.nic.in/Pg01-52.pd >.

---. Punjab State Electricity Regulatory Commission. “New & Renewable Sources o Energy (NRSE) Policy 2006.”

Punjab State Electricity Regulatory Commission. 9 Feb. 2009. <http://www.pserc.nic.in/pages/NRSE_orders.

html>.

---. ---. “Punjab State Grid Code (2006).” 9 Mar. 2006. Punjab State Electricity Regulatory Commission. 9 Feb. 2009

<http://pserc.nic.in/pages/state_grid_code.html>.

---. West Bengal Electricity Regulatory Commission. “Cogeneration and Generation o Electricity rom Renewable

Sources o Energy Regulations, 2008.” Kolkata, India: The Kolkata Gazette, 2008. The Kolkata Gazette. 25

Mar. 2008. West Bengal Electricity Regulatory Commission. 9 Feb. 2009 <http://wberc.net/wberc/regulation/

under_2003_Act/index.htm>.

“IREC MR-NM2005: IREC Model Net-Metering Rules.” Interstate Renewable Energy Council. 9 Feb. 2009. <http://

www.irecusa.org/leadmin/user_upload/ConnectDocs/NM_Model.pd >.

Knazkins, Valerijs. Stability o Power Systems with Large Amounts o Distributed Generation. Diss. Royal Institute

o Technology (KTH), 2004. 10 Feb. 2009 <http://www.diva-portal.org/diva/getDocument?urn_nbn_se_kth_

diva-46-1__ulltext.pd >.

Kwok, Candy, and Ate S. Morched. “Eect o Adding Distributed Generation to Distribution Networks Case Study

3: Protection coordination considerations with inverter and machine based DG.” Apr. 2006. Canmet Energy.

9 Feb. 2009 <http://canmetenergy.nrcan.gc.ca/chier.php/codectec/En/2006-147/2006-147e.pd >.

Lieberman, Dan. “Overview o RECs.” 30 November 2004. Public Renewables Partnership. 9 Feb. 2009 <http://

www.repartners.org/webcast/4%20RECs%20Lieberman.pd >.

Maki, Kari, Sami Repo, and Pertti Jarventausta. “Impacts O Distributed Generation On Earth Fault Protection In

Distribution Systems With Isolated Neutral.” Vienna, Austria, 21-24 May 2007. CIRED 19th International

Conerence on Electricity Distribution. 9 Feb. 2009 <http://www.cired.be/CIRED07/pds/CIRED2007_0107_

paper.pd >.

Martinot, Eric. “Global Renewable Energy Markets and Policies.” Spring 2004. New Academy Review. 9 Feb. 2009

<http://www.martinot.ino/Martinot_NAR.pd >.

---. “Grid-based renewable energy in developing countries: policies, strategies, and lessons rom the GEF.” In

proceedings o World Renewable Energy Policy and Strategy Forum, Berlin, June 13-15, 2002. 9 Feb. 2009

<http://www.geweb.org/Martinot_WCRE_June2002.pd >.

Miller, N., and Z. Ye. “Report on Distributed Generation Penetration Study.” August 2003. National Renewable

Energy Laboratory. 10 Feb. 2009 <http://www.nrel.gov/docs/y03osti/34715.pd >.

Reerences




175

Minnesota. Oce o Revisor o Statutes. “216B.164 COGENERATION AND SMALL POWER PRODUCTION.”

Minnesota Statutes 2008. 9 Feb. 2009. <https://www.revisor.leg.state.mn.us/revisor/pages/statute/statute_toc.

php>.

“Model Interconnection Standards and Procedures or Small Generator Facilities.” Interstate Renewable Energy

Council. 9 Feb. 2009 <http://www.irecusa.org/leadmin/user_upload/ConnectDocs/IC_Model.pd >.

Moskovitz, David, Cheryl Harrington, Richard Cowart, Wayne Shirley, and Frederick Weston. “Prots and Progress

Through Distributed Resources.” February 2002. The Regulatory Assistance Project. 9 Feb. 2009 <http://

www.raponline.org/Pubs/General/ProtsandProgressdr.pd >.

Muljadi, E, C. P. Buttereld, J. Conto, and K. Donohoo. “Ride-Through Capability Predictions or Wind Power Plants

in the ERCOT Network.” June 2005. National Renewable Energy Laboratory. 10 Feb. 2009 <http://www.nrel

gov/wind/systemsintegration/pds/2005/muljadi_wind_ride_through_capability_predictions.pd >.

National Association o Regulatory Utility Commissioners. “Model Interconnection Procedures and Agreement

or Small Distributed Generation Resources.” Oct. 2003. National Association o Regulatory Utility

Commissioners. 9 Feb. 2009 <http://www.naruc.org/Publications/dgiaip_oct03.pd >.

National Rural Electric Cooperative Association. “Application Guide or Distributed Generation Interconnection:

2006 Update, The NRECA Guide to IEEE 1547.” Mar. 2006. National Rural Electric Cooperative

Association. 9 Feb. 2009. <http://www.nreca.org/Documents/PublicPolicy/DGApplicationGuide-Final.pd >.

“Net Energy Metering (NEM).” 2008. SDG&E. 10 Feb. 2009 <http://www.sdge.com/business/netMetering.shtml >.

New Jersey. Board o Public Utilities. “In the Matter o New Jersey Natural Gas Company Distributed Generation

Tari Filing.” Decision and Order. Docket No. GT01070450. 23 Jan. 2003. State o New Jersey Board o

Public Utilities. 9 Feb. 2009. <http://www.state.nj.us/bpu/pd/boardorders/21134.pd >.

New York State. Public Service Commission. “CASE 02-M-0515 - Proceeding on Motion o the Commission to

Establish Gas Transportation Rates or Distributed Generation Technologies.” 19 Feb. 2003. New York Public

Service Commission. 9 Feb. 2009 <http://www3.dps.state.ny.us/pscweb/WebFileRoom.ns/Web/BD7AAB45

5FCB712685256DF10075671F/$File/doc13154.pd >.

---. ---. “New York State Standardized Interconnection Requirements and Application Process or New Distributed

Generators 2 MW or Less Connected in Parallel with Utility Distribution Systems.” Sept. 2005. New York

State Public Service Commission. 9 Feb. 2009 <http://www.dps.state.ny.us/08E1018/SIR_Require_11_04.

pd >.

Nimpitiwan, Natthaphob and Gerald Heydt. “Consequences o Fault Currents Contributed by Distributed Generation.” June 2006. Power Systems Engineering Research Center. 10 Feb. 2009 <http://www.pserc.org/

cgi-pserc/getbig/publicatio/reports/2006report/nimpitiwan_s20_report.pd >.

North Carolina State University, NC Solar Center. “Federal Incentives or Renewable Energy: Clean Renewable

Energy Bonds (CREBs).” 31 Oct. 2008. Database o State Incentives or Renewables and Eciency.. 9 Feb.

2009 <http://www.dsireusa.org/>.

Reerences




176

---. “Mass Energy – Renewable Energy Certicate.” Database o State Incentives or Renewables and Eciency. 10

Feb. 2009 <http://www.dsireusa.org/>.

---. “Net Metering.” Database o State Incentives or Renewables and Eciency. 10 Feb. 2009 <http://www.dsireusa.

org/>.

---. “Personal Tax Incentives.” Database o State Incentives or Renewables and Eciency. 10 Feb. 2009 <http://

www.dsireusa.org/>.

---. “Vermont - CVPS - Biomass Electricity Production Incentive:” 9 July 2008. Database o State Incentives or

Renewables and Eciency. 10 Feb. 2009 <http://www.dsireusa.org/>.

Ohio. Public Utilities Commission. “Generating your own Electricity: Advice or Getting Started.” 16 Oct. 2008.

Public Utilities Commission o Ohio. 10 Feb. 2009 <http://www.puco.ohio.gov/emplibrary/les/media/

Publications/Fact_Sheets/generating%20your%20own%20electricity%20-%20advice%20or%20getting%20

started.pd >

---. ---. “Generating Your Own Electricity: Net Metering.” Public Utilities Commission o Ohio. 10 Feb. 2009 <http://

www.puco.ohio.gov/PUCO/Consumer/Inormation.cm?id=8510 >.

---. ---. “Interconnection Request Screening Process.” Public Utilities Commission o Ohio. 10 Feb. 2009 <http://

www.puco.ohio.gov/emplibrary/Distributed_Generation_Screening_Process.pd >.

---. ---. “Sta’s Guide or Interconnection Customers to IEEE 1547 Standards and Related Terminology: Simplied

Denitions or Common Use.” Public Utilities Commission o Ohio. 10 Feb. 2009 <http://www.puco.ohio.

gov/emplibrary/les/media/Publications/DGGlossaryPics/glossary.pd >.

---. ---. “Technical Requirements or Interconnection and Parallel Operation o Distributed Generation: Single Phase

less than or equal to 25kW, Three Phase less than or equal to 300kW.” Public Utilities Commission o Ohio.

10 Feb. 2009 <http://www.puco.ohio.gov/emplibrary/les/smed/Technical_Requirements.pd >.

Outhred, Hugh, Stanley R. Bull, and Suedeen Kelly. “Meeting the Challenges o Integrating Renewable Energy

into Competitive Electricity Industries.” 3 May 2007. Federal Energy Regulatory Commission. 5 Feb. 2009

<http://www.erc.gov/about/com-mem/kelly/gridintegration.pd >.

Pimparkhedkar, Surendra. “Feed-in Taris or Solar Power Projects in India.” World Institute or Sustainable Energy.

5 Feb. 2009 <http://www.wisein.org/pd/GEPDF/GE-July-Aug-08.pd >.

--- “R.E. Policy Revvs Up Across the Globe.” Green Energy. Vol. 4 No. 4, July-Aug. 2008. World Institute or

Sustainable Energy. 5 Feb. 2009 <http://www.wisein.org/pd/GEPDF/GE-July-Aug-08.pd >.

Poor, Tim. “Wind Power and Grid Reliability: Innovative Solutions Help Wind Farms Meet Grid Interconnection

Standards.” January/February 2008. Electric Light & Power. 10 Feb. 2009 <http://www.amsc.com/newsroom/

documents/AMSC_Wind%20Power%20and%20Grid%20Reliability_0208.pd >.

Reerences






178

Rickerson, Wilson, Florian Bennhold, and James Bradbury. “Feed-in Taris and Renewable Energy in the USA a

Policy Update.” May 2008. Heinrich Boll Foundation North America. 9 Feb. 2009 <http://www.boell.org/

docs/Feed-in%20Taris%20and%20Renewable%20Energy%20in%20the%20USA%20-%20a%20Policy%20

Update.pd >.

“Rule 21, Generating Facility Interconnections.” Southern Caliornia Edison. 10 Feb. 2009 <http://www.sce.com/

NR/sc3/tm2/pd/Rule21.pd >.

Sawin, Janet L. “National Policy Instruments: Policy Lessons or the Advancement & Diusion o Renewable

Energy Technologies Around the World.” Jan. 2004. Renewables 2004. 10 Feb. 2009 <http://www.renew-

ables2004.de/pd/tbp/TBP03-policies.pd >.

--- “The Role o Government in the Development and Diusion o Renewable Energy Technologies: Wind Power in

the United States, Caliornia, Denmark, and Germany, 1970-2000.” Ph.D. thesis, Tuts University, Fletcher

School o Law and Diplomacy. UMI, Ann Arbor, MI.

Schienbein, L. A., and J. G. DeSteese. “Distributed Energy Resources, Power Quality and Reliability – Background.”

Jan. 2002. Pacic Northwest National Laboratory. 10 Feb. 2009 <http://www.pnl.gov/main/publications/

external/technical_reports/pnnl-13779.pd >.

“Sel-Generation Incentive Program.” Pacic Gas & Electric Company. 26 Jan. 2009 <http://www.pge.com/

mybusiness/customerservice/nonpgeutility/generateownpower/selgenerationincentive/index.shtml >.

Shirley, Wayne. “Standby Rates or Customers with Distributed Generation.” Presentation to the NARUC Summer

Committee Meetings. San Francisco, Caliornia. 2 Aug. 2006. National Association o Regulatory Utility

Commissioners. 10 Feb. 2009 <http://www.narucmeetings.org>.

Sonntag-O’Brien, Virginia, and Eric Usher. “Financing Options or Renewable Energy.” 4 July 2008. Environmental

Finance. 9 Feb. 2009 <http://www.environmental-nance.com/2004/0504may/nanc.htm >.

Soonee, S. K., S. R. Narasimhan and V. Pandey. “Signicance o Unscheduled Interchange Mechanism in the Indian

Electricity Supply Industry.” 2006. Power Grid Corporation o India Ltd. 29 Jan. 2009 <http://www.srldc.org/

Downloads/Signicance_o_UI.pd >.

Sotkiewicz, Paul M., and Jesus M. Vignolo. “Nodal Pricing or Distribution Networks: Ecient Pricing or Eciency

Enhancing Distributed Generation.” Aug. 2005. University o Florida Warrington College o Business

Administration. 10 Feb. 2009 <http://www.cba.uf.edu/purc/purcdocs/papers/0520_Sotkiewicz_Nodal_Pricing_

or.pd >.

“SRP Interconnection Guidelines For Distributed Generators.” December 2000. Salt River Project. 9 Feb. 2009

<http://www.srpnet.com/electric/pdx/gen_guidelines.pd >.

“Structuring a ‘Buy-Down’ Program or Small Renewable Energy Systems: Some Recommendations.” American

Wind Energy Association. 9 Feb. 2009 <http://www.awea.org/pubs/actsheets/buydwn_s.PDF>.

Sun, Yu, Math H.J. Bollen, and Graham Ault. “Improving Distribution System Reliability by Means o Distributed

Generation.” May 2007. CIRED. 10 Feb. 2009. <http://www.cired.be/CIRED07/pds/CIRED2007_0070_

paper.pd >.

Reerences




179

“Supplemental Comments: Distributed Generation and Cogeneration Policy Roadmap or Caliornia, March 2007.”

CEC-500-2007-021. Electric Power Research Institute. 21 May 2007. <http://www.energy.ca.gov/2007_

energypolicy/documents/2007-05-07_workshop/public_comments/ELECTRICAL_POWER_RESEARCH_

INSTITUTE_2007-05-21.PDF>.

Szatow, Tosh. “Beyond Free Market Assumptions: Addressing Barriers to Distributed Generation, Consumer Utilities

Advocacy Centre.” Apr. 2008. Energy Today. 10 Feb. 2009 <http://www.energytoday.com.au/docs/CUAC-Be

yondFreeMarketAssumptionsFinalReport.pd >.

“Tari or Grid Interactive Demonstration Solar Power Plants or the Purpose o MNRE.” Order No. 1 o 2009. GoI

Notications No. 32/61/2007-08 PVSE. 22 January 2009. Gujarat Electricity Regulatory Commission. 15

February 2009 <http://www.gercin.org/docs/Orders/Other%20orders/Year%202009/Order%201%20o%202009.pd >.

Taub, Steve. “GE Energy Financial Services Study: Impact o 2007 Wind Farms on U.S. Treasury.” 2007. GE Energy

Financial Services. 9 Feb. 2009 <http://www.geenergynancialservices.com/press_room/press_releases/

PTC_StudyFinal.pd >.

“Technical Considerations Covering Parallel Operations o Customer Owned Generation O One (1) Megawatt or

Greater And Interconnected with the Conectiv Power Delivery System.” 30 March 2004. Delmarva Power.

15 February 2009. <http://www.delmarva.com/_res/documents/200403301MWandGreaterDPLTechManual4

7pg.pd >.

Texas. Public Utility Commission. “Distributed Generation Interconnection Manual.” Public Utility Commission o

Texas. 5 Feb. 2009 <http://www.puc.state.tx.us/electric/business/dg/dgmanual.pd >.

---. ---. “Technical Requirements or Interconnection and Parallel Operation o On-Site Distributed

Generation§25.212.” 21 Dec. 1999. Public Utility Commission o Texas. 9 Feb. 2009 <http://www.puc.state.

tx.us/rules/subrules/electric/25.212/25.212ei.cm>.

“The Central Electricity Authority (Technical Standards or Connectivity to the Grid) Regulations, 2007.” 21 Feb.

2007. International Finance Corporation. 8 February 2009 <http://india.smetoolkit.org/india/en/content/

en/8221/>

“The Renewable Energy Law o the People’s Republic o China.” 28 Feb. 2005. Beijing Review, no. 29, 21 July

2005. Martinot.ino. 9 Feb. 2009 <http://www.martinot.ino/China_RE_Law_Beijing_Review.pd >.

“The Technical Basis or the New WECC Voltage Ride-Though (VRT) Standard: A White Paper Developed by the

Wind Generation Task Force1 (WGTF).” 13 June 2007. Wind Generation Coordinating Council. 10 Feb.

2009 <http://www.wecc.biz/documents/library/TSS/Voltage%20Ride-Through%20White%20Paper_6-13-07. pd >.

United States. Department o Energy. “Massachusetts Wind, Solar Generators Escape Standby Charge.” 1 Aug.

2004. U.S. Department o Energy. 9 Feb. 2009 <http://apps1.eere.energy.gov/states/news_detail.cm/news_

id=8591>.

Reerences




180

---. ---. “The Potential Benets o Distributed Generation and the Rate-Related Issues That May Impede Its

Expansion.” Report Pursuant to Section 1817 o the Energy Policy Act o 2005. U.S. Department o Energy.

7 Feb. 2009 <http://www.oe.energy.gov/DocumentsandMedia/1817_Report_-nal.pd >.

---. Environmental Protection Agency. “The Clean Energy-Environment Guide to Action: Policies, Best Practices,

and Action Steps or States.” Apr. 2006. U.S. Environmental Protection Agency. 9 Feb. 2009 <http://www.

epa.gov/cleanenergy/documents/gta/guide_action_ull.pd >.

---. Federal Energy Regulatory Commission. “Commission acts to remove regulatory barriers to renewable energy

development in Caliornia.” 19 Apr. 2007. Federal Energy Regulatory Commission. 7 Feb. 2009 <http://

www.erc.gov/news/news-releases/2007/2007-2/04-19-07-E-5.asp >.

---. ---. “Fact Sheet. Order No. 890 Final Rule: Preventing Undue Discrimination and Preerence in Transmission

Service.” Federal Energy Regulatory Commission. 29 Jan. 2009 <http://www.erc.gov/industries/electric/

indus-act/oatt-reorm/order-890/act-sheet.pd >.

---. ---. “Interconnection Requirements or Wind Energy and Other Alternative Technologies.” 6 Feb. 2008. U.S.

Federal Energy Regulatory Commission. 10 Feb. 2009. <http://www.erc.gov/industries/electric/indus-act/gi/

wind.asp>.

---. ---. “Pro Forma Open Access Transmission Tari.” 19 May 2006. Federal Energy Regulatory Commission. 9 Feb.

2009 <http://www.erc.gov/industries/electric/indus-act/oatt-reorm/order-890/pro-orma-tari-nopr.pd >.

---. ---. “Standard Interconnection Agreements & Procedures or Small Generators.” Federal Energy Regulatory

Commission. 10 Feb. 2009 <http://www.erc.gov/industries/electric/indus-act/gi/small-gen.asp >.

---. ---. “Standard Interconnection Agreements or Wind Energy and Other Alternative Technologies.” Federal Energy

Regulatory Commission. 10 Feb. 2009 <http://www.erc.gov/industries/electric/indus-act/gi/wind.asp >.

---. Federal Register. Vol. 73, No. 45. 6 Mar. 2008. Farmenergy.org. 9 Feb. 2009 <http://armenergy.org/documents/

S9006NOFA2008.pd >

---. Internal Revenue Service. “Clean Renewable Energy Bonds.” Internal Revenue Bulletin. 2007-14. 2 Apr. 2007.

Notice 2007-26. 9 Feb. 2009 <http://www.irs.gov/irb/2007-14_IRB/ar17.html>.

Vandal, Mario, Robert O’Reilly, and Martin Boulay. “Power Quality and Equipment Monitoring in Distributed

Generation o Multiple Wind Farm Sites or Hydro-Québec.” Aug. 2008. The Line. Cooper Power Systems.

10 Feb. 2009 <http://www.cooperpower.com/library/TheLine/pd/08_08/Line_08_08_HQ.pd >.

“West Bengal Introduces Net Metering in India. Green Energy, Vol. 4, No. 3, May-June 2008. 9 Feb. 2009 <http://

www.wisein.org/pd/GEPDF/GE-May-June08.pd >.

“Wind Energy Forecasting Technology Update: 2004.” Electric Power Research Institute. 10 Feb. 2009 <http://

my.epri.com/>.

“Wind Power – Clean AND Reliable.” American Wind Energy Association. 9 Feb. 2009 <http://www.awea.org/

utility/pd/Wind_and_Reliability_Factsheet.pd >.

Reerences




181

Wiser, Ryan, and Galen Barbose. “Renewables Portolio Standards in the United States: A Status Report with Data

Through 2007.” Apr. 2008. Lawrence Berkeley National Laboratory. 9 Feb. 2009 <http://eetd.lbl.gov/ea/ems/

reports/lbnl-154e-revised.pd >.

Wu, Jiang et al. “The Study on the Development Status and Trend o Distributed Power in China.” International

Network or Inormation on Ventilation and Energy Perormance. 10 Feb. 2009 <http:// www.inive.org>.

Yebra, T., and V. Fuster. “Energy Quality in Voltage, Current and Power Signals.” ICREEPQ ‘09. 10 Feb. 2009

<http://www.icrepq.com/icrepq-08/228-yebra.pd >.

Reerences




182

Websites:

American National Standards Institute

http://www.ansi.org/

American Wind Energy Association

http://www.awea.org

Danish Wind Industry Association

http://www.windpower.org/en/uturesupply.htm

Database o State Incentives or Renewables and Eciency

http://www.dsireusa.org

IEEE

http://www.ieee.org

Interstate Renewable Energy Councilhttp://www.irecusa.org/

Mid-Atlantic Distributed Resources Initiative (MADRI)

http://www.energetics.com/madri/

Ministry o New and Renewable Energy

http://mnes.nic.in

Reegle - the Inormation Gateway or Renewable Energy and Energy Eciency http://www.reegle.ino

Solar Energy Industries Associationhttp://www.seia.org

World Institute or Sustainable Energy (WISE)

http://www.wisein.org

Reerences

