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

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

The Relevance of Generation 

Interconnection Procedures to 

Feed-in Tariffs in the United States 

Sari Fink, Kevin Porter, and Jennifer Rogers

Exeter Associates, Inc.

Columbia, Maryland

Subcontract Report

NREL/SR-6A20-48987

October 2010
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

The Relevance of Generation 

Interconnection Procedures to 

Feed-in Tariffs in the United 

States

Sari Fink, Kevin Porter, and Jennifer Rogers

Exeter Associates, Inc.

Columbia, Maryland

NREL Technical Monitor: Karlynn Cory

Prepared under Subcontract No. LEU-9-99277-01

Subcontract Report

NREL/SR-6A20-48987

October 2010
This publication received minimal editorial review at NREL.

NOTICE

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iii

Acknowledgments

The U.S. Department of Energy and the National Renewable Energy Laboratory funded the 

research that went into this project. The authors thank Jennifer DeCesaro of the U.S. Department 

of Energy’s Solar Energy Technologies Program; Cody Taylor of the U.S. Department of 

Energy’s Office of Strategic Policy Analysis in the Office of Energy Efficiency and Renewable 

Energy; and Karlynn Cory, Lori Bird, and Elizabeth Doris of the National Renewable Energy 

Laboratory for supporting this work. 

We also thank Michael Coddington and Jim Newcomb of the National Renewable Energy 

Laboratory; Lawrence Mansueti and Cody Taylor of the Department of Energy; Jason Keyes of 

the Interstate Renewable Energy Council; James Rose of the Network for New Energy Choices; 

Julie Taylor of the National Association of Regulatory Utility Commissioners; Tom Stanton of 

the Michigan Public Service Commission; Steve Johnson of the Washington Utilities and 

Transportation Commission; Wilson Rickerson and Chad Laurent of Meister Consultants Group; 

and Lisa Schwartz of the Regulatory Assistance Project for their review comments. We would 

also like to thank Scott Hunter and Michael Winka of the New Jersey Board of Public Utilities 

for their review comments on the New Jersey section of the Appendix. 
iv

Executive Summary

Feed-in tariffs (FITs) have been used to promote renewable electricity development in over 40 

countries throughout the past two decades. These policies generally provide guaranteed prices 

for the full system output from eligible generators for a fixed time period (typically 15–20 years). 

Due in part to the success of FIT policies in Europe, some jurisdictions in the United States are 

considering implementing similar policies, and a few have already put such policies in place. 

This report is intended to offer some guidance to policymakers and regulators on how generator 

interconnection procedures may affect the implementation of FITs and how state generator 

interconnection procedures can be formulated to support state renewable energy objectives. This 

report is based on a literature review of model interconnection procedures formulated by several 

organizations, as well as other documents that have reviewed, commented on, and in some cases, 

ranked state interconnection procedures.

Significant differences in electricity policies, markets, and regulations between the United States 

and Europe, however, constrain the implementation of European-style FIT policies for FERCjurisdictional entities in the United States. FITs in Europe are supported by policies that provide 

guaranteed and preferred dispatch and interconnection provisions for qualifying renewable 

electricity generators. European Union Member States have been directed to guarantee the 

interconnection of renewable generators, to prioritize the dispatch of renewable energy, and to 

consider requiring the purchase of that energy. European Union Member States also have the 

option of prioritizing the interconnection of renewable generators, in effect moving them to the 

front of the generator interconnection queue. Additionally, the costs of interconnecting a new 

renewable energy generator to the electric grid (at both the transmission and distribution level) 

are borne mainly by electricity customers. Such priority dispatch or interconnection guarantees 

or preferences for particular technologies are barred in the United States for generators subject to 

federal jurisdiction under the Federal Power Act.

Interconnecting new generators to the electric grid in the United States is complicated by state 

and federal jurisdictional issues. The Federal Energy Regulatory Commission (FERC) has 

jurisdiction over all transmission systems involved in wholesale power markets and interstate 

commerce. State regulators have jurisdiction over retail activities and intrastate commerce, 

which generally involves distribution-level interconnections. For generators subject to FERC 

jurisdiction, new generators are given non-discriminatory access to interconnection and 

applications are processed on a first come, first served basis, with no priority given to any 

particular technology or type of generator. Generators must also obtain dispatch, transmission 

service, and customers for their energy separate from interconnection. Generators are required to 

pay the cost for directly connecting their facility to the transmission grid and to provide the 

initial funding for any necessary transmission upgrades, which are generally later reimbursed. 

Under FERC rules, dispatch cannot be guaranteed; in competitive wholesale markets, dispatch is 

based on power prices and the economics of individual generators. 

While implementation of a European-style FIT for FERC-jurisdictional entities at the national 

level in the United States would require significant changes in law and regulation, there are 

opportunities at the state level for FIT implementation, particularly for small and distributed 

generation connected to the distribution grid. In order for those to happen, state interconnection 

policies and procedures need to be reviewed and optimized. There is no single legal framework 
v 

for state interconnection policies and procedures but several entities have developed 

interconnection procedures and model interconnection procedures (also referred to as model 

rules) that can assist state regulators in creating interconnection procedures for small and 

distributed generation. The more prominent examples are the FERC Small Generator 

Interconnection Procedures outlined in FERC Order 2006, California’s Rule 21, the Mid-Atlantic 

Distributed Resources Initiative model rule, and the Interstate Renewable Energy Council model 

rule. There are significant differences between these four, but common elements include: 

• coverage of all generation technologies, interconnection of systems up to at least 

10 MW, and standard agreements; 

• simplified procedures for small solar PV systems covering most residential 

installations; 

• fast track procedures for systems up to 2 MW; 

• a three-part study (feasibility, impact, and facilities) process for interconnection of 

more complex and larger systems; and 

• comprehensive coverage of issues eliminating a utility’s ability to create additional 

and unnecessary rules. 

The four differ with respect to whether they include standard agreements for all types of systems 

and have different capacity limits, timelines, fee levels, insurance requirements, and dispute 

resolution processes.

As of July 2010, all but eight states—Alabama, Alaska, Idaho, Oklahoma, Mississippi, North 

Dakota, Rhode Island, and Tennessee—had created some type of state interconnection 

procedures applying to various entities and containing varying capacity limits. Key state 

interconnection procedure characteristics that can affect the development of distributed 

generation include: 

• capacity limits, 

• standard agreements and application processes, 

• expedited processing for smaller systems,

• interconnection costs, and

• insurance requirements. 

State interconnection policies can help facilitate the success of state renewable energy policies, 

including FITs. Four of the five top-ranking states in installed solar electric capacity received 

grades of B or better from the Interstate Renewable Energy Council, a non-profit organization 

that evaluates state generator interconnection procedures in the Freeing the Grid report. The top 

five states also have renewable portfolio standards and do not impose capacity limits for net 

metering. 
vi 

Table of Contents

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

2 Electricity Regulation in the United States and Europe ................................................................... 3

3 Generator Interconnection Procedures in the United States........................................................... 6

4 Model Interconnection Procedures in the United States ................................................................. 8

5 Comparing the Model Interconnection Procedures........................................................................ 10

6 Evolution of State Interconnection Procedures in the United States ........................................... 12

7 Review of Issues and Barriers to Interconnection.......................................................................... 16

8 Enabling Development of Renewable Energy and Distributed Generation ................................. 18

9 Conclusion .......................................................................................................................................... 20

Appendix.................................................................................................................................................... 22

References................................................................................................................................................. 27

List of Figures

Figure 1. Grid-connected PV capacity through 2009 (MW) ........................................................ 19

Figure A-1. California Rule 21 screening process ........................................................................ 23

Figure A-2. New Jersey installed solar capacity by year .............................................................. 25

List of Tables

Table 1. Top Countries for New Solar Electric in 2009 ................................................................. 1

Table 2. State Interconnection Procedure Size Limitations ............................................................ 7

Table 3. Comparing Model Interconnection Procedure Characteristics ....................................... 10

Table 4. State Interconnection Procedure Scores from Freeing the Grid, 2009 Edition .............. 15

Table 5. Installed Grid-connected Solar Electric Capacity by State Through 2009 (MW) .......... 19
1 

1 Introduction

A feed-in tariff (FIT) is an energy policy that has been used to promote renewable energy 

development in over 40 countries, most prominently in Europe. Although the details differ, a FIT 

essentially provides a guaranteed payment in $/MWh for electricity and renewable energy credits 

for the energy output from an eligible generator for a guaranteed period of time (typically 15–20 

years; see Table 1). Payment amounts may be differentiated by technology, project size, 

resource quality, or other project-specific variables (Cory, Couture, and Kreycik 2009). 

Due in large part to the success of FIT policies in Europe and elsewhere, various jurisdictions in 

the United States have begun to consider implementing FIT policies, and a few have put FIT 

policies in place.1

 FIT policies, in various forms, have been utilized in Europe for at least a 

decade and are widely considered to have been effective in advancing renewable energy 

development (Cory and Couture 2009). Currently, FITs are used as the primary renewable 

energy support mechanism in 20 of the 27 European Union Member States.2

Table 1. Top Countries for New Solar Electric in 2009

 As of 2008, 75% of 

global photovoltaic (PV) capacity and 45% of global wind capacity were developed under FIT 

policies (DB Climate Advisors 2010). Germany implemented its current FIT policy in 2000 and 

has seen substantial renewable energy growth over the last decade. Renewable electricity 

generation rose from 4.8% of Germany’s electricity mix in 1998 to 16.1% in 2009, with 

approximately 77% of the renewable electricity receiving payments under Germany’s FIT 

(German Federal Ministry for the Environment, Nature Conservation, and Nuclear Safety 2010). 

In 2009, new solar PV installations were dominated by European countries (see Table 1). 

Country MW Installed in 

2009

Cumulative 

Capacity End of 

2009

FIT in Place Duration of FIT 

Contract

Germany 3,800 9,677 X 20 years

Italy 700 1,158 X 20 years

Japan 484 2,628 X 15 years

United States 481 2,108

Czech 

Republic

411 465 X 15 years

Belgium 292 362

France 285 465 X 20 years

Spain 180 3,595 X 25 years

Sources: SEIA 2010 and Klein et al. 2008.

The European Union has established a shared renewable energy target of 12% overall share of 

energy from renewable sources by 2010 and 20% by 2020. The directive instructs European 

Union Member States to guarantee the interconnection of renewable energy facilities and to 

 

1 California, Vermont, Oregon, Washington, and Wisconsin have enacted various FIT-type policies. For more 

information see Cory and Couture 2009. 2 Concerns often raised with FITs are the potential cross-subsidization of one ratepayer class versus another and 

whether FITs may negatively impact electricity rates to the particular detriment of certain customer classes such as 

low-income customers and energy-intensive industries. These concerns are beyond the scope of this report.
2 

guarantee and prioritize the dispatch of renewable energy.3

In the United States, jurisdiction over electric power is divided between the Federal Energy 

Regulatory Commission (FERC) and the states. FERC has jurisdiction over wholesale electricity 

and transmission rates and service, while states have jurisdiction over retail rates, distribution 

service, and siting. Rates and service for wholesale power and transmission must meet statutory 

requirements and receive FERC approval for being just and reasonable and not unduly 

discriminatory. FERC also has jurisdiction over generator interconnections that are at 

transmission-level voltage or involve wholesale power transactions. FERC created standard 

generator interconnection procedures and agreements for all generators and transmission 

customers, but these specifically state that interconnection does not guarantee electricity sales or 

dispatch.

The directive also grants European 

Union Member States the option to prioritize renewable energy interconnection; i.e., allow 

renewable energy projects to jump to the head of the interconnection queue. Germany, Spain, 

and Denmark have opted to prioritize the interconnection of renewable energy facilities (IPA 

Energy and Water Economics 2008). Along with guaranteed interconnection and prioritized 

dispatch, most European Union Member States apply a purchase obligation, wherein the relevant 

receiving entity (generally the grid operator) must purchase all renewable generation. 

Additionally, a significant portion of the transmission upgrade costs and, in some countries, the 

direct connection costs are borne by electricity customers, rather than the interconnecting 

generator (IPA Energy and Water Economics 2008). 

4

For retail electric service and transactions, state-level interconnection policies are an important, 

if not essential, tool for meeting state renewable energy requirements or other state policies. 

There is, however, no single legal framework for state interconnection policies and procedures, 

although several model interconnection procedures are available to build from. As of July 2010, 

all but eight states—Alabama, Alaska, Idaho, Mississippi, North Dakota, Oklahoma, Rhode 

Island, and Tennessee—had created some type of state interconnection procedure applying to 

various entities and containing varying capacity limits (DSIRE 2010). 

 Power purchase contracts are obtained separately from interconnection and 

transmission. Interconnection service must also be comparable and non-discriminatory (FERC

2003). There is no technology-specific priority rank in interconnecting generators such as 

renewable energy technologies or in dispatching such technologies. Therefore, European-style 

FIT policies are not compatible with U.S. non-discriminatory open-access transmission and 

interconnection requirements where dispatch cannot be guaranteed or prioritized. Jurisdictional 

issues, electricity regulation, and FERC policies complicate the implementation of Europeanstyle FITs in the United States. 

This report examines interconnection procedures in the United States, how those procedures 

relate to FIT policies in the United States and Europe, and options for state-level interconnection 

procedures.5

 

3 Interconnection refers to the technical requirements and legal procedures whereby an electric generator interfaces 

with the electricity grid. 

 Section 2 discusses electricity regulation in the United States and Europe, Section 3 

describes federal and state generation interconnection procedures, Section 4 describes model 

state interconnection procedures, and Section 5 compares these model procedures. Section 6 

4 FERC’s role and jurisdiction is discussed in greater detail in Section 2.

5 Another report examines the legal issues surrounding the implementation of a FIT in U.S. wholesale power 

markets. See Hempling, et al. 2010.
3 

considers the evolution of state generator interconnection procedures, while Section 7 elaborates 

on issues and barriers to generator interconnection. Section 8 discusses how generator 

interconnection procedures can help enable the successful implementation of state renewable 

energy policies, and Section 9 concludes the report. 

This report does not address issues and procedures related to net metering, but rather, the focus is 

on generation interconnection. Additionally, the report focuses on interconnection policies and 

procedures rather than technical standards. Technical codes and standards consist of the technical 

requirements for safely interconnecting new generating facilities to the electric grid while 

maintaining reliability.6

2 Electricity Regulation in the United States and Europe

This section broadly describes the differences in electricity regulation and industry structure 

between the United States and Europe. 

United States 

In the United States, the Federal Power Act (FPA) grants FERC jurisdiction over interstate 

commerce with respect to energy (both electricity and fuels), which is generally understood as 

jurisdiction over all aspects of wholesale power markets.7, 8

Transmission providers are obligated to process all generator interconnection requests in a nondiscriminatory manner and connect generators to their transmission grid as detailed in their 

Related to wholesale generator 

interconnection, FERC issued Order 2003 in 2003 (followed later by 2003A, 2003B, and 2003C) 

to establish the standard procedures governing large generator interconnection, including the 

standard Large Generator Interconnection Procedures and the standard Large Generator 

Interconnection Agreement, for all FERC-jurisdictional facilities with a capacity greater than 

20 MW (FERC 2003). This was later followed by Order 2006, which established the Small 

Generator Interconnection Procedures and the standard Small Generator Interconnection

Agreement for FERC-jurisdictional facilities up to 20 MW (FERC 2005). 

 

6 The technical aspects of interconnection are governed by codes and standards developed by various organizations, 

mainly the North American Electric Reliability Corporation, the National Fire Protection Association, and the 

Institute of Electrical and Electronics Engineers (IEEE). 7 FERC jurisdiction over wholesale transmission, however, applies only to entities that own, control, or operate 

interstate transmission facilities, primarily the 176 investor-owned utilities (IOUs). FERC cannot require nonjurisdictional utilities, principally electric cooperatives that are borrowers of funds from the Rural Utilities Service, 

as well as municipal utilities and public power agencies to file generation interconnection agreements. However, 

FERC has stated that some of these entities own or operate facilities used or capable of being used for transmission 

in interstate commerce, and therefore are "transmitting utilities" under the FPA. In addition, FERC jurisdiction over 

Federal Power Marketing Administrations is limited, and FERC jurisdiction does not extend to regions not engaged 

in interstate commerce: the part of Texas under the Electric Reliability Council of Texas and the states of Alaska and 

Hawaii. 8 FERC, in conjunction with states, also administers the Public Utility Regulatory Policies Act of 1978 (PURPA) 

that allows certain cogeneration and renewable energy “qualifying facilities” that meet certain eligibility 

requirements to sell power to utilities at a utility’s avoided cost of generating the power itself or purchasing the 

power. Utilities are also required to interconnect with qualifying facilities. PURPA has diminished relevance these 

days as the Energy Policy Act of 2005 (EPAct 2005) allows utilities to petition FERC to be removed from the 

obligation to buy power from future qualifying facilities if certain conditions are met. As discussed later, EPAct 

2005 amended PURPA to include a new standard for interconnection.
4 

FERC-approved Open Access Transmission Tariffs (OATTs; FERC 2003). Once interconnected, 

however, the transmission provider is not obligated to actually receive and transmit the 

electricity generated by the supplier. It is up to the generator to obtain a buyer for their energy 

and to arrange a transmission service schedule, subject to transmission availability and pricing. 

Guaranteeing interconnection, therefore, does not equate to receiving transmission service or 

guaranteeing electricity dispatch. Under the FPA and FERC regulations, utilities cannot grant 

priority to interconnecting generation by technology type in the United States. Additionally, 

under FERC rules, generation owners in the United States are typically required to pay the costs 

of interconnecting their facilities to the transmission grid, generally both direct connection 

facilities and any necessary network upgrades; although in most instances, transmission owners 

or operators reimburse the transmission network upgrade costs to generators through 

transmission service credits or as financial transmission rights (FTRs), if available (FERC

2003).9

FERC jurisdiction does not include entities involved in retail-only activities and intrastate 

commerce, which generally involves distribution system-level interconnections and distributed 

generation facilities. Distribution level interconnection policies are therefore governed by state 

laws and procedures. FERC does have jurisdiction over a distributed generation facility’s 

interconnection (and a wholesale power transaction) if that facility is participating in the 

wholesale energy market.

Distributed generation facilities that interconnect to the grid at the distribution level generally are 

facilities with a capacity of 2 MW and smaller. However, distributed generation can include 

larger facilities if those facilities are interconnected with a distribution system that is capable of 

accepting the output from the facility. The interconnection jurisdiction issue is complicated by 

the fact that some states have created interconnection procedures for small and distributed 

generation while eight states have not. If a facility interconnection falls under FERC jurisdiction, 

then FERC-jurisdictional utilities in states without small or distributed generation 

interconnection procedures follow the FERC pro-forma small generator interconnection 

procedures for all facilities up to 20 MW. For interconnections that fall under state jurisdiction, 

when a state has not implemented interconnection procedures, both FERC-jurisdictional utilities 

and non-FERC jurisdictional utilities (e.g., most municipal electric utilities, rural electric 

cooperatives, and federal government facilities) are able to create their own interconnection 

policies and procedures, leaving facility owners with no recourse but to accept whatever 

conditions the utility imposes. 

Europe

In September 2001, the European Parliament issued Directive 2001/77/EC concerning the 

promotion of electricity produced from renewable energy sources (The European Parliament and 

the Council of the European Union 2001). Directive 2001/77/EC set a target for the European 

Union to collectively reach a 12% share of renewable energy by 2010. This target was increased 

in 2007 with the enactment of a mandatory target that 20% of overall energy consumption be 

 

9 FERC Order 2003 states that the credits (or FTRs) are restricted to transmission service on the relevant 

transmission provider’s system and only with respect to the particular interconnecting generating facility, as long as

that facility has achieved commercial operation and continues to operate. The refund is to be spread over five years. 

As discussed later, FERC allows more discretion to Regional Transmission Organization (RTOs) in allocating costs 

for transmission upgrades.
5 

from renewable energy generation by 2020 for all European Union Member States (European 

Energy Commission 2010). Directive 2001/77/EC also addressed grid access issues. Article 7 

states:

Without prejudice to the maintenance of the reliability and safety of the grid, 

Member States shall take the necessary measures to ensure that transmission 

system operators and distribution system operators in their territory guarantee the 

transmission and distribution of electricity produced from renewable energy 

sources. They may also provide for priority access to the grid system of electricity 

produced from renewable energy sources. When dispatching generating 

installations, transmission system operators shall give priority to generating 

installations using renewable energy sources insofar as the operation of the 

electricity system permits (The European Parliament and the Council of the 

European Union 2001, Article 7.1).

European grid operators not only guarantee grid interconnection for renewable energy 

generators, but they are also required to guarantee and prioritize the dispatch of that energy. 

Along with guaranteed dispatch, the majority of European Union Member States have imposed a 

purchase obligation for renewable energy, meaning that the relevant grid operator, energy supply 

company, or electric consumers are required to buy the electricity generated by renewable energy 

generators. The article allows European Union Member States to also prioritize interconnection 

of renewable energy facilities, something that has been implemented in Germany, Spain, and 

Denmark. Put more directly, various countries have employed a “connect and manage” approach 

by prioritizing the interconnection of renewable energy technologies and using strong grid codes 

and energy curtailment, as needed, to maintain grid reliability. 

Grid connection charges in Europe are mainly paid for by electricity customers. Additionally, 

some European Union Member States have special rules for renewable energy generators. 

Denmark has lower connection charges for renewable generators. On-shore wind facilities in 

designated areas only pay for direct connection facilities to the boundaries of the wind farm, and 

off-shore wind facilities pay only for connection to the nearest land point. In Germany, off-shore 

wind facilities pay only the on-site direct connection costs. In Italy, all renewable energy 

generators pay a 50% lower fee for interconnection (IPA Energy and Water Economics 2008). 

Summary

There are significant differences between electricity policies, markets, and regulations in the 

United States and Europe, and absent unforeseen federal statutory changes to the FPA, largescale European-style FITs applying to FERC-jurisdictional entities cannot be implemented in the 

United States. FITs in Europe are supported by policies that include guaranteed and preferred 

dispatch and interconnection for renewable generators, while no such dispatch or interconnection 

guarantees or preferences for particular technologies are available in the United States. U.S. 

states looking to implement FITs may wish to focus on small and distributed generation 

connected to nonfederal-jurisdictional facilities and examine other types of FITs as outlined in 

several recent reports.10

 

10 See Cory, Couture, and Kreycik 2009; Cory and Couture 2009.; Hempling et al. 2010; and KEMA 2008. 

To facilitate deployment, U.S. states may wish to examine 

interconnection procedures to ensure they do not impose procedural barriers to interconnecting 

generators, such as unnecessary requirements and excessive costs. 
6 

3 Generator Interconnection Procedures in the United States

Many FITs in Europe apply to both distributed and utility-scale facilities and some FIT proposals 

in the United States have included consideration of utility-scale facility eligibility; therefore, this 

section includes an overview of large generator interconnection procedures under FERC 

jurisdiction.

Large Generator Interconnection Procedures

The majority of large generation (greater than 20 MW) interconnections in the continental 

United States are subject to FERC jurisdiction. As noted earlier, with Order 2003, FERC created 

the standard Large Generator Interconnection Procedure (LGIP) and the standard Large 

Generator Interconnection Agreement (LGIA). Under the LGIP, the review of generator 

interconnection requests (submitted to the relevant transmission operating entity) is conducted in 

phases through a series of studies, each involving more detail and financial commitment from the 

interconnecting generator. Transmission providers assign generator interconnection queue 

positions according to the date and time that an interconnection request is received. The 

interconnection queue position then determines the order in which the series of interconnection 

studies are conducted and interconnection construction costs are allocated. Interconnecting 

customers are responsible for the full costs of their studies, all of which require an initial deposit. 

Under the LGIP, three interconnection studies are conducted, each consisting of increasingly 

more detailed engineering assessments that examine the technical considerations of 

interconnecting the particular project to the grid at a certain point while maintaining system 

reliability and not exceeding the operating limits of the grid.11 The feasibility study consists of a 

high-level evaluation of whether the project is feasible at the customer’s desired point of entry 

into the grid. The interconnection system impact study is a more detailed version of the 

feasibility study and evaluates the impact of the proposed project on system reliability. The 

interconnection facilities study identifies what equipment, engineering, procurement, and 

construction work will be required to connect the proposed generating project to the grid and 

estimates the interconnection cost and time required.12

FERC Order 2003 defines two types of construction costs: direct connection facilities and 

network upgrades. Direct connection facilities consist of all equipment and construction required 

to connect the new generating facility to the first point of interconnection with the transmission 

grid. Network upgrades consist of equipment and construction required to reinforce the existing 

transmission system in order to accommodate the new generation project. Generation facility 

owners are responsible for the cost of all direct connection facilities between the generator and 

the transmission grid and must also pay for the up-front costs of network upgrades, for which 

they generally are later reimbursed (plus interest) in the form of transmission credits or, if 

applicable, financial transmission rights. 

 The end result is the LGIA that is then 

subject to approval from FERC. 

 

11 As defined by the North American Electric Reliability Corporation FERC-approved standards. 12 Some entities have received FERC approval to modify their LGIPs and may include more or less studies, though 

the end result of the studies is essentially unchanged. For more detailed information on large generator 

interconnection procedures, see Porter et al. 2009.
7 

FERC Order 2003 allows transmission providers to create variations to the standard LGIP that 

are superior to the standard procedures described above. FERC determines on a case-by-case 

basis whether a procedure is “superior.” In addition, FERC has granted “independent entity” 

variation for regional transmission organizations (RTOs) and independent system operators 

(ISOs)—again on a case-by-case basis—whereby RTOs and ISOs are free to depart from FERC 

Order 2003 as FERC views RTOs and ISOs as independent of any market participant. Most of 

the nation’s RTOs and ISOs have gained approval from FERC to modify their LGIPs. These 

modifications have included increasing the initial study deposit amounts, including group 

studies, and adding requirements for generation developers to meet certain milestones prior to 

being able to proceed to subsequent study stages (Porter et al. 2009). 

Small and Distributed Generator Interconnection Procedures

Small generators are generally considered as those having a capacity of 20 MW or less. Statelevel interconnection procedures for non-FERC jurisdictional projects have set various size 

limits ranging from less than 100 kW to 80 MW facilities, while some procedures contain no 

specified size limits and can therefore be used to interconnect any project as long as the 

interconnection does not fall under FERC jurisdiction. Table 2 outlines the various state 

procedure size limitations. Facilities sized 20 MW or smaller do not often interconnect to 

transmission lines that fall under FERC jurisdiction, but because connecting generation facilities 

in the 5 to 20 MW range to the distribution system may be difficult, some generation facilities in 

this capacity range do connect to FERC-regulated transmission lines. 

Table 2. State Interconnection Procedure Size Limitations

Size Limit States

No size limit California, Hawaii, Indiana, Kentucky, Maine, Massachusetts, Michigan, 

New Jersey, North Carolina, Pennsylvania, Vermont

80 MW Iowa, New Mexico

20 MW Connecticut, Nevada, Ohio, Virginia, Washington 

15 MW Wisconsin

10 MW Arizona*, Colorado, District of Columbia, Illinois, Maryland, Minnesota, 

Oregon**, South Dakota, Texas 

2 MW Florida, New York, Utah***

1 MW Delaware

Under 500 kW Arkansas, Georgia, Kansas, Louisiana, Missouri, Montana, Nebraska, New 

Hampshire, South Carolina, Wyoming

No state procedures Alabama, Alaska, Idaho, Oklahoma, Mississippi, North Dakota, Rhode 

Island, Tennessee

*Arizona Corporate Commission procedures are still voluntary and recommended only. Utilities in Arizona have 

implemented various size limits.

**Oregon imposes a separate 25 kW size limit on residential net-metered systems and has adopted standard 

interconnection procedures and agreements for facilities over 20 MW.

***Utah imposes a separate 25 kW size limit on residential net-metered systems.

Note: West Virginia implemented interconnection procedures in July 2010, too late to be included in the analyses in this 

report. 

Source: Network for New Energy Choices 2009. 

The majority of small residential and commercial systems interconnect with utility-level 

distribution systems and are therefore under the jurisdiction of state-level regulations or, if 

unavailable or non-applicable, to utility-imposed interconnection guidelines. Facilities up to 
8 

2 MW in capacity rarely interconnect with anything other than utility-level distribution systems, 

which can include medium voltage class equipment. 

4 Model Interconnection Procedures in the United States

Over the last decade, the renewable energy industry, states, and utilities have cooperated in 

creating model interconnection procedures for regulators to use when developing state 

procedures. The more prominent examples are the FERC Small Generator Interconnection 

Procedures (SGIP), California Rule 21, the Mid-Atlantic Distributed Resources Initiative 

(MADRI) model rule, and the Interstate Renewable Energy Council (IREC) model rule. FERC’s 

SGIP and California Rule 21 are not technically “models”; they were created as procedures to be 

put into actual practice. These procedures have, however, been used by some states as a model 

for developing their interconnection procedures and, therefore, are often referred to as model 

procedures. The SGIP was influenced by the Small Generation Resource Interconnection 

Procedures developed by the National Association of Regulatory Utility Commissioners 

(NARUC) in 2003 and submitted to FERC early in the Order 2006 proceeding. The NARUC 

procedures were also the genesis of the IREC and MADRI rules but have not been updated since 

2003 (NARUC 2003).

FERC Small Generator Interconnection Procedures

In Order 2006, FERC created a simplified SGIP that includes a fast track process for FERCjurisdictional facilities with a nameplate capacity of 2 MW or less. The FERC SGIP primarily 

applies to FERC-jurisdictional utilities in states with no state-level procedures. The fast track 

process involves an initial screening process. If the proposed facility meets all of the various 

technical screens, the interconnection request is approved. For facilities between 2 and 20 MW 

and those that fail to pass the initial screening process, scaled-down versions of the same basic 

studies as required in the LGIP must be performed: a feasibility study, a system impact study, 

and a facilities study. The deposit requirements are much smaller for SGIP facilities, but the 

interconnecting customer is still responsible for the cost of the studies. Interconnecting 

customers are also responsible for fully funding any necessary transmission system upgrades and 

the resulting Small Generator Interconnection Agreement (SGIA) is subject to FERC approval 

(FERC 2005). 

California Rule 21

California Rule 21 was one of the first state interconnection procedures to be created and was 

developed through a stakeholder process that began in October 1999. In December 2000, the 

California Public Utility Commission (CPUC) issued a decision approving the Rule 21 tariff 

language and directed California’s three investor-owned utilities (IOUs) to adopt the tariff 

language (CPUC 2000). Several municipalities have voluntarily modeled their interconnection 

rules after Rule 21, including Riverside Utilities Department, the Los Angeles Department of 

Water and Power, Sacramento Municipal Utility District, Mountain Utilities, and Bear Valley 

Electric (Cooley et al. 2003). 

California Rule 21 does not specify a size limit and states that the tariff applies to all facilities 

intending to connect to the electric grid over which the CPUC has jurisdiction. This allows for 

facilities of any size to connect to the grid in California as long as the interconnection does not 

fall under FERC jurisdiction. 
9 

Rule 21 also does not include any expedited review processes based on project size. The same 

procedures are used regardless of project capacity. There is, however, an initial review process 

consisting of eight screening criteria, and projects under 11 kW automatically satisfy three of the 

eight screens. Any project that passes the initial screens qualifies for a simplified 

interconnection. California Rule 21 is discussed in more detail in a case study in the Appendix. 

Mid-Atlantic Distributed Resources Initiative

MADRI was established in 2004 by the public utility commissions of Delaware, the District of 

Columbia, Maryland, New Jersey, and Pennsylvania, along with the Department of Energy 

(DOE), the Environmental Protection Agency (EPA), FERC, and the PJM Interconnection.13

The MADRI procedures contain four levels of review based on the size

The 

MADRI model interconnection procedures were developed through a stakeholder process and 

finalized in November 2005. The model was created as an alternative to the FERC SGIP and is 

meant to be used as a guide for states to develop their own interconnection procedures specific to 

their particular jurisdictional needs. 

14

• Level 1 is for inverter-based systems with nameplate capacities of 10 kVA or less;

 of the project: 

• Level 2 is for inverter-based systems with nameplate capacities up to 2 MVA 

including any 10 kVA and smaller systems that did not pass the screens for Level 1; 

• Level 3 is for all systems up to 10 MVA in size including those that did not pass the 

Level 1 and/or Level 2 screens; and 

• Level 3A, which is unique to the MADRI model, is a potentially expedited review 

procedure for systems that will not be exporting power to the grid. This level grants 

utilities discretion to connect non-exporting systems up to 10 kVA to their 

distribution grids if they determine there will be no adverse impacts. States using the 

MADRI model can also consider utility-supplied alternative text that allows Level 3A 

to apply to systems up to 50 kVA in size (MADRI 2005).

Though not entirely adopted by any state, the MADRI model has been used to develop 

interconnection procedures in Illinois, Maryland, Oregon, and Pennsylvania. 

Interstate Renewable Energy Council

IREC is a non-profit organization created in 1982. IREC works on creating renewable energy 

programs and policies promoting the adoption of uniform guidelines, standards, and quality 

assessment and has been involved in rulemaking for distributed power interconnection, 

workforce development, consumer protection, and stakeholder coordination. The IREC model 

procedures were originally developed in 2005, finalized in November 2006, and updated and 

revised in 2009.

The IREC procedures have four levels, three of which are based on project size: 

 

13 PJM is the regional transmission organization that administers and operates the electric transmission grid and 

wholesale markets in the Mid-Atlantic region. 14 MADRI defines project size according to kilovolt amperes (kVA). VA is the amount of apparent power in an 

electrical circuit, equal to the product of voltage and current. For DC systems, VA equals the real power (watts), but 

for AC systems, VA may differ from watts as the voltage and current may be out of phase. 
10 

• Level 1 contains a set of simplified screens for inverter-based systems with a capacity 

of 25 kW or less; 

• Level 2 is a set of screens for systems with a capacity of 2 MW or less, including 

those below 25 kW that did not pass Level 1 screening; 

• Level 3 is for systems that have a capacity of 10 MW or less and will not be exporting 

power to the grid; and 

• Level 4 is for all systems that did not qualify for the Level 1, Level 2, or Level 3 

interconnection review processes (IREC 2009). 

The IREC procedures drew on the previous models developed by FERC, MADRI, and NARUC. 

The IREC model is an attempt to incorporate the best approaches and features found in the work 

done to date on interconnecting distributed generators. 

5 Comparing the Model Interconnection Procedures

This section compares the four main models for small and distributed generation interconnection 

procedures and is drawn from a paper from the Solar America Board for Codes and Standards, 

Comparison of the Four Leading Small Generator Interconnection Procedures (Keyes and Fox 

2008), and from the 6th edition of IREC’s Connecting to the Grid report (Varnado and Sheehan 

2009). 

All resources and technologies qualify for interconnection under the model procedures. None 

call for statewide coverage, acknowledging that state jurisdiction over municipal utilities, 

cooperatives, and public utility districts varies greatly among the states. California Rule 21, for 

example, is limited to only the IOUs. Table 3 outlines some different characteristics of the model 

procedures. 

Table 3. Comparing Model Interconnection Procedure Characteristics 

Capacity Limits

FERC SGIP Covers facilities up to 20 MW.

Rule 21 No size limit specified.

MADRI Covers facilities up to 10 MVA.

IREC No size limit specified.

Standard Agreements 

and Procedures

FERC SGIP Standard form interconnection agreement and application process for all 

system sizes.

Rule 21 Several different standard forms based on system ownership and size.

MADRI Standard form interconnection agreement and application process for all 

system sizes.

IREC Standard form interconnection agreement and application process, plus a 

simplified process and agreement for inverter-based systems up to 25 kW.
11 

Fast Track Process

FERC SGIP Simplified fast track process for smaller facilities up to 2 MW.

Rule 21 Same initial screening process for all project sizes; then expedited 

procedures apply to projects that pass screens.

MADRI

Four distinct levels based on project size, each with progressively more 

extensive requirements. Simplified lower levels restricted to inverter-based 

systems only.

IREC Four distinct levels based on project size, each with progressively more 

extensive requirements.

Timelines

FERC SGIP

Requires the transmission provider make “reasonable effort” to meet the 

schedules established in the procedures. Ranges from 10 business days to 

notify customers about their application’s status to 30 business days for 

completing interim studies and 45 days for completing final facilities study.

Rule 21

A utility must inform the customer about the adequacy of their application 

within 10 business days and complete the initial review within 20 business 

days.

MADRI Same as SGIP for Level 1 applications but slightly longer timeframes for 

Level 2 and above.

IREC Similar to SGIP but grants 13 business days for application review.

Fees

FERC SGIP

A set fee for fast track process projects with a smaller fee for 10 kW and 

smaller inverter-based systems. Fees for non-fast track projects are based on 

the cost of the studies.

Rule 21

Set fee for the initial review with an exemption for net-metered systems, 

providing for a free review. Net metering restricted to PV, wind, fuel cells, 

and biogas from manure or anaerobic digestion facilities.* 

MADRI Requires cost-based fees and leaves the determination of applicable amounts 

to each utility or state.

IREC Similar to SGIP fees but with slightly smaller amounts.

Insurance 

Requirements

FERC SGIP

Requires owners of 10 kW inverter systems to follow applicable state 

insurance requirements. For larger projects, owners must carry sufficient 

general liability insurance to account for all reasonable foreseeable direct 

liabilities arising from the system being installed.

Rule 21

Not automatically required for all systems; California utilities have 

implemented various general liability insurance requirements. Not required 

for net-metered solar and wind facilities up to 30 kW.

MADRI Additional liability insurance not required.

IREC Additional liability insurance not required.
12 

Dispute Resolution

FERC SGIP Allows for the use of FERC’s Dispute Resolution Service if a project 

proponent disagrees with a utility’s determination.

Rule 21

Project sponsor can appeal to the CPUC. Project sponsors must first write a 

letter to the utility and meet with an authorized utility representative to 

attempt to resolve the dispute, which can last 45 days, followed by a second 

45-day period if either party requests an extension. Failing resolution, the 

project sponsor can submit a written request to the CPUC for mediation, 

which will last another 90 days. If the dispute is still not resolved, the project 

proponent must apply to the CPUC’s Customer Complaints division.

MADRI No defined dispute resolution process. This is left to the utilities.

IREC

Contains a set short timeline for discussions by the parties to attempt to 

resolve disputes. Failing resolution, the parties can request that the state 

utility commission rule on the dispute.

*California net metering restricts PV, wind, and fuel cell facility size to 1 MW or less; biogas size to 10 MW or less for up to 3 

digesters at the same facility; no more than 50 MW of biogas and 112.5 MW of fuel cells statewide; and no more than 5% of a 

utility’s peak demand.

Sources: Keyes and Fox 2008; Varnado and Sheehan 2009. 

Although facilities between 10 and 20 MW tend to be connected at the transmission system 

level, this is not always the case. Facilities that can be classified as “qualifying facilities” (QFs) 

that sell all of their output to the local utility can be exempt from FERC jurisdiction and would 

need to rely on state interconnection procedures.15

6 Evolution of State Interconnection Procedures in the United 

States 

 The MADRI procedures, therefore, can result 

in a gap in coverage for facilities in this size range. The standard form interconnection agreement 

and application procedures help to ensure equal treatment for all customers, but having several 

different standard forms based on system size (or other determinants) can be cumbersome and 

confusing, especially for small system owners. The level of fees imposed can also have a 

significant effect on project development. The MADRI procedures requirement for cost-based 

fees could result in higher fees being assessed on early entrants, before utilities gain the 

experience and the staff necessary to efficiently process interconnection requests. 

State interconnection procedures have evolved over the last decade, helped in part by the Energy 

Policy Act of 2005 (EPAct 2005), which included a new Public Utility Regulatory Policies Act 

(PURPA) standard for interconnection.16

 

15 QFs are defined by the Public Utility Regulatory Policies Act of 1978 (PURPA) as small power production 

facilities of 80 MW or less whose primary energy source is renewable (hydro, wind, or solar), biomass, waste, or 

geothermal resources or as cogeneration facilities of any size that sequentially produce electricity and another form 

of useful thermal energy (such as heat or steam) in a way that is more efficient than the separate production of both 

forms of energy.

EPAct 2005 directed state regulatory authorities (with 

16 PURPA was passed in 1978 as part of the National Energy Act. Among other things, PURPA created the QF 

designation and obligates electric utilities to purchase QF energy at avoided cost rates. EPAct 2005 allows utilities 

to petition FERC to be exempt from mandatory QF purchases if certain conditions are met. PURPA also includes 

Section 111 that requires states to consider, but not necessarily adopt, different issues and standards. EPAct’s 

directive on interconnection services was added as an amendment to Section 111 of PURPA.
13 

respect to their jurisdictional utilities) and each non-regulated electric utility to consider 

interconnection procedures in accordance with Section 1254, which states the following: 

• Each electric utility shall make available, upon request, interconnection service to any 

electric consumer that the electric utility serves.

• Interconnection service is for an electric consumer whose onsite generation facility on 

the customer’s premises must be connected to the local distribution facilities.

• Interconnection services shall be offered based on IEEE standards (as they may be 

amended from time to time).

• Services offered shall promote current best practices of interconnection for distributed 

generation (Soderberg 2005).

EPAct 2005 only required that state regulatory agencies consider and/or conduct hearings on 

implementing interconnection procedures to meet the above objectives. This prompted states to 

examine interconnection issues and eventually led some to adopt or to amend and improve 

existing interconnection procedures. While some states already had interconnection procedures 

in place, since EPAct 2005, several other states have created and adopted interconnection 

procedures including Arizona (Arizona’s procedures are voluntary), Colorado, Connecticut, 

Delaware, District of Columbia, Florida, Illinois, Kansas, Kentucky, Maine, Maryland, Missouri, 

Nebraska, New Mexico, North Carolina, South Carolina, South Dakota, and Washington. 

The DOE’s Office of Energy Efficiency and Renewable Energy (EERE) and Office of Electricity 

Delivery and Energy Reliability (OE) developed a set of best practices for states to consider 

when examining and establishing interconnection procedures. These best practices are described 

below: 

• Require that agreements and procedures for interconnection wholesale service “shall 

be just and reasonable, and not unduly discriminatory or preferential” (per EPAct 

2005). Treat independent generators and utilities similarly in terms of state 

requirements.

• Create simple, transparent interconnection applications for small generators up to 

2 MW (per FERC Order 2006). 

• Standardize and simplify interconnection agreements for small generators and, if 

possible, interconnection applications.

• Set minimum response and review times for interconnection applications. 

• Provide expedited procedures for certified interconnection systems that pass initial 

technical screens. 

• Establish low processing fees for small generators. Interconnection request deposits 

should be credited toward the cost of the feasibility study, as per FERC Order 2006. 

• Set liability insurance requirements commensurate with levels typically carried by the 

respective customer class.

• Require compliance with IEEE 1547 and UL 1741. 
14 

• Minimize administrative requirements unless a requirement is standard practice for 

similar electrical work.

• Develop administrative procedures for implementing interconnection requirements on 

a statewide basis through rulemaking or other regulatory mechanisms for statejurisdictional utilities to apply uniformly to all regulated electric distribution 

companies in the state. Where practical, state interconnection administrative 

procedures should reflect regional best practices and be comprehensive in scope. 

Administrative procedures should also be transparent to both small generators and 

electric distribution utilities (Varnado and Sheehan 2009).

As of July 2010, all but the following eight states have adopted some form of interconnection 

standards with varying capacity limits: Alabama, Alaska, Idaho, Mississippi, North Dakota, 

Oklahoma, Rhode Island, and Tennessee (DSIRE 2010).17

IREC and the Network for New Energy Choices periodically release a report entitled Freeing the 

Grid, which examines state net-metering and interconnection standards and identifies best and 

worst practices (Network for New Energy Choices 2009). Freeing the Grid contains a ranking 

system and assigns a letter grade to each state’s procedures. The rankings are based on the 

following criteria:

Some states, such as California, New 

Jersey, Oregon, and most recently, Maine and Virginia, have conducted extensive proceedings in 

an effort to update their interconnection standards for enabling distributed renewable energy 

development. 

• Set fair fees that are proportional to a project’s size.

• Cover all generators in order to close any state-federal jurisdictional gaps.

• Screen applications by degree of complexity and adopt simplified rules for 

residential-scale systems and expedited procedures for other systems.

• Ensure that policies are transparent, uniform, detailed, and public. 

• Prohibit requirements for extraneous devices, such as redundant disconnect switches, 

and do not impose additional liability insurance requirements above and beyond what 

is typically carried by the respective customer class.

• Apply existing relevant technical standards, such as IEEE 1547 and UL 1741. 

• Process applications in a timely manner utilizing standardize and simplify forms 

(Network for New Energy Choices 2009).

Table 4 summarizes IREC’s state rankings for interconnection procedures as found in the 2009 

Edition of Freeing the Grid and outlines the issues that lead to the results. 

 

17 West Virginia was in the process of finalizing their procedures and subsequently approved them in July 2010.
15 

Table 4. State Interconnection Procedure Scores from Freeing the Grid, 2009 Edition

Score States Issues 

A Virginia Covers all utilities and systems sized up to 20 MW. Still requires a set 

amount of insurance and the decision on a UEDS* is left to utilities.

B 

California, Colorado, 

District of Columbia, 

Illinois, Maryland, 

Massachusetts, Nevada, 

New Jersey, New Mexico, 

New York, North Carolina, 

Oregon, Pennsylvania, 

South Dakota

Limits coverage to IOUs: CA, IL, NV, NJ, NC, OR, PA

Limits size: 10 MW—CO, DC, OR, MD, SD; 5 MW—PA; 2 MW—NY

Requires additional insurance: CO, DC, IL, MA, NC, SD

Left to utilities’ discretion: NM

Requires UEDS: DC, IL, MD, NY, PA

Left to the utilities’ discretion: CA, CO, MA, NV, NM, NC, OR, SD

C 

Arizona, Florida, 

Michigan, New 

Hampshire, Ohio, Vermont

Limits coverage to IOUs: AZ, FL, OH

Limits size: left to utilities’ discretion—AZ; 2 MW—FL; 100 kW—NH

Non-standard procedures that vary by utility: AZ

Requires additional insurance: FL, MI

Left to utilities’ discretion: AZ, VT

Requires UEDS: FL, OH, VT

Left to utilities’ discretion: MI

D 

Connecticut, Delaware, 

Indiana, Texas, 

Washington, Wisconsin

Limits coverage to IOUs: all except IN; WI limits to IOUs and municipal 

utilities

Limits size: 15 MW—WI; 10 MW—TX; 1 MW—DE

Requires additional insurance: CT, IN, WA, WI 

Left to utilities’ discretion: TX 

Requires UEDS: all, but WA allows utilities to provide waivers

F 

Arkansas, Georgia, 

Hawaii, Iowa, Kansas, 

Kentucky, Louisiana, 

Minnesota, Missouri, 

Montana, Nebraska, South 

Carolina, Utah, Wyoming

Limits coverage to IOUs: HI, IA, KS

Limits to only a few resource types: GA, IA, KY, MO, MT, WY

Limits size: 10 MW—MN; 2 MW—UT; 300 kW—AR, LA; 200 kW—KS; 

100 kW—GA, MO, SC; 50 kW—MT; 30 kW—KY; 25 kW—NE, WY

Requires additional insurance: MN, MO, SC 

Left to utilities’ discretion: AR, HI, IA, LA, MT, WY

Requires UEDS: AR, HI, IA, KY, LA, MN, SC, WY

Left to utilities’ discretion: GA, KS, MO, MT, NE, UT

No interconnection procedures (at 

time of publication)

Alabama, Alaska, Idaho, Mississippi, North Dakota, Oklahoma, Rhode 

Island, Tennessee, West Virginia

*UEDS—utility external disconnect switch

Note: Maine was still developing interconnection standards at the time the report was published but did subsequently adopt those 

standards in January 2010. Maine’s new procedures are based largely on the IREC model.

Source: Network for New Energy Choices 2009. 
16 

7 Review of Issues and Barriers to Interconnection

How certain issues are addressed, or not addressed, when implementing state interconnection 

procedures can affect the development of distributed generation. Some of these issues include 

capacity limits; standard form agreements and application processes; expedited processing for 

smaller systems; interconnection costs; and insurance requirements. The issues reviewed in this 

section draw from the detailed discussions in the 6th edition of IREC’s Connecting to the Grid

report (Varnado and Sheehan 2009) and the Solar Electric Power Association’s (SEPA) survey, 

Residential Photovoltaic Metering and Interconnection Study (Letendre and Taylor 2008).

Capacity Limits

Several states have incorporated capacity limits into their net-metering statutes or their 

interconnection procedures. Setting a low capacity limit can leave a gap in regulatory oversight, 

which may limit the development of certain projects that are not wholesale generators and 

therefore not FERC-jurisdictional, yet too large to be able to apply under state interconnection 

procedures. Eleven states—California, Hawaii, Indiana, Kentucky, Maine, Massachusetts, 

Michigan, New Jersey, North Carolina, Pennsylvania, and Vermont—have created procedures 

(or amended existing ones) that do not have capacity limits, thereby allowing state 

interconnection procedures to potentially be used by projects of any capacity not falling under 

FERC jurisdiction. Nine states—Arkansas, Georgia, Kansas, Louisiana, Missouri, Nebraska, 

New Hampshire, South Carolina, and Wyoming—have set very low capacity limits, making 

interconnection procedures applicable to only a small segment of customers (Varnado and 

Sheehan 2009). 

Standardized Forms

Standard form agreements can facilitate generator interconnection by ensuring that project 

applicants know exactly what to expect and what is required with respect to their application. 

Standard form agreements also expedite utility processing of requests as employees become 

more familiar with interconnection rules and requirements. Most states with interconnection 

procedures—30 of the 40 states plus the District of Columbia (as of June 2010)—had adopted 

standard form agreements (DSIRE 2010).18 In addition, most state interconnection procedures 

have created several levels of review and documentation based on system size with simplified 

processes for smaller inverter-based systems. Of the 39 states plus the District of Columbia with 

interconnection procedures, 14 have limited their generator interconnection procedures to 

systems 2 MW in size or smaller.19

The SEPA survey notes that the majority of utilities surveyed have interconnection applications 

and agreements less than 10 pages long for small PV customers and processing times averaged 

about one month. Incomplete documentation from customers was the most oft-cited cause of 

interconnection delays, and SEPA stated that more standard requirements, updated documents 

and materials, and clearer communication between the relevant utility, customers, and inspectors 

would address these problems. One example is IREC’s 2009 model interconnection procedures, 

 Of the remaining 26, 20 contain different levels of review 

based on project size and expedited procedures for facilities 2 MW or smaller (Varnado and 

Sheehan 2009). 

 

18 Arizona’s procedures are guidelines only and so are not included in the assessments in this section. 19 West Virginia implemented their procedures in July 2010, too late to be included in the analyses in this report.
17 

which included a two-page agreement of generator interconnection terms and conditions for 

certified, inverter-based systems up to 25 kW in capacity. Several states use a one- or two-page 

interconnection agreement for very small distributed generation systems, particularly those used 

for net metering (Varnado and Sheehan 2009). 

Fees and Charges

Though some fees and charges are necessary, the imposition of unnecessary or excessive fees 

and charges may impede or stop the development of distributed generation systems. 

Interconnection costs for distributed generators can include related application and connection 

fees and engineering, technical, and equipment charges. Some utility inspection fees for small 

PV systems have reportedly approached $900 (Varnado and Sheehan 2009). Such fees could be 

removed or minimized with more incorporation and recognition of technical standards and codes 

such as IEEE 1547 and UL 1741.20

Some utilities have included other costs, such as metering charges, ranging from $4 to $8 per 

month, for a second meter. These charges were more frequent before net-metering policies 

became prevalent. Typically, states now require utilities to furnish a second meter if the netmetered system needs one, and some require customers to either pay for the meter or to share 

some of the costs (Varnado and Sheehan 2009).

 However, most of the utilities responding to the SEPA 

survey stated they did not charge residential customers fees to connect a net-metered PV system 

to their distribution grid and of those that do, the fees are usually less than $100. 

21

Utilities have also imposed standby demand charges to have equivalent capacity available in case 

of customer system failure. These standby charges can be substantial, ranging from $2 to $20 per 

kW for small PV systems. Because of concerns that such standby charges may impede 

development of distributed renewable energy generation facilities, 21 states (as of July 2009) 

prohibited standby charges for customers with small-scale PV systems (Varnado and Sheehan 

2009). 

 

Liability Insurance

According to IREC, additional liability insurance has been a “major battleground” in developing 

interconnection procedures for small distributed generation. States and utilities have wanted to 

include additional liability insurance requirements to protect the utility and its employees from 

accidents that could be attributed to the distributed generation system. But most small businesses 

and homeowners already carry liability insurance under their standard insurance policies. 

Furthermore, IREC reports that liability claims from malfunctioning customer-sited renewable 

energy systems are very infrequent. To date, there have been no known insurance claims for 

utility damages from any of the over 50,000 solar installations in the United States; therefore, 

some states have eliminated the requirement to carry additional insurance or have specified how 

much general liability insurance a project owner must carry instead of requiring additional 

insurance for the distributed generation system (Fox, Keyes, and Sheehan 2008). 

 

20 IEEE 1547 is one of a series of technical standards for distributed generation interconnection. UL 1741 includes a 

list of UL certified equipment. 

21 For example, a net-metered system may need a second meter to measure and record the outgoing energy if the 

existing meter is not capable of performing this function.
18 

Dispute Resolution

Dispute resolution procedures can also be important factors for small and distributed generation 

development. In the absence of an adequate dispute resolution process, project sponsors have no 

option but to seek legal or regulatory recourse that may be costly and time consuming. Small and 

distributed generation project sponsors, especially at the residential level, would likely not 

pursue this course of action, opting instead to abide by the utility’s rulings or, if the financial 

burden is too high, to abandon the project. 

8 Enabling Development of Renewable Energy and Distributed 

Generation 

Simplifying and streamlining interconnection has been a primary consideration for states 

developing interconnection procedures. California and New York were the first two states to 

develop interconnection standards. New York implemented its Standard Interconnection 

Requirements in 1999 and California its Rule 21 standard in 2000. Nevada used California 

Rule 21 as a model when developing its standards. New Jersey participated in the creation of the 

MADRI rules but then opted to develop their own interconnection standards, drawing in part on 

the IREC model. Oregon adapted and improved on the MADRI rules for their non-net-metered 

interconnection standards (discussed in more detail in the Appendix), which are now being 

considered as a model for other states. Colorado and Arizona relied in part on the FERC SGIP 

when creating their standards. The Appendix contains in-depth case studies of three states with 

comprehensive interconnection procedures—California, New Jersey, and Oregon. 

Almost all of the net-metering and interconnection procedures implemented at the state level are 

restricted to renewable energy and clean energy technologies. This includes solar, wind, biomass, 

landfill gas, small hydro, combined heat and power, municipal solid waste, anaerobic digestion, 

and ocean energy. Some interconnection procedures limit eligible technologies to just a few 

types, usually solar, wind, biomass, and small hydro. This is in keeping with state policy goals 

for increasing renewable energy development. 

Well-crafted interconnection procedures can contribute to the successful implementation of state 

renewable energy objectives. Indeed, a strong correlation appears to exist between the growth of 

renewable energy generation, particularly solar energy, with Renewable Portfolio Standard 

(RPS) requirements, expansive net-metering policies, and interconnection procedures that 

incorporate many of the identified best practice features.22

 

22 Renewable energy incentives also play a significant role in encouraging development. A full analysis of the 

causes of renewable energy development is beyond the scope of this paper. The intent here is to point out that these 

policies can all work together to enable renewable energy deployment in a state. 

 To focus on just a sub-set of state 

policies, 29 states plus the District of Columbia, as of June 2010, have enacted state RPSs, and 

another seven states have renewable energy goals (DSIRE 2010). Of the states with an RPS or a 

renewable energy goal, 16 states plus the District of Columbia have solar, distributed generation 

provisions such as specific set-asides for solar and distributed generation, or renewable energy 

credit multipliers (DSIRE 2010). In addition, as of June 2010, 43 states plus the District of 

Columbia have enacted net metering (DSIRE 2010). Table 5 shows the total amount of gridconnected solar electric installed by state through the end of 2009, including both small- and 

large-scale PV and concentrating solar power.
19 

Table 5. Installed Grid-connected Solar Electric Capacity by State Through 2009 (MW)

Capacity Installed in 2009 Cumulative Capacity in 2009

Rank State MW Rank State MW

1 California 220 1 California 1,102

2 New Jersey 57 2 New Jersey 128

3 Florida 36 3 Nevada 100

4 Arizona 23 4 Colorado 59

5 Colorado 23 5 Arizona 50

6 Hawaii 14 6 Florida 39

7 New York 12 7 New York 34

8 Massachusetts 10 8 Hawaii 27

9 Connecticut 9 9 Connecticut 20

10 North Carolina 8 10 Massachusetts 18

Others 29 Others 78

Total 441 Total 1,655

Source: SEIA 2010.

Figure 1 depicts all installed grid-connected PV capacity by residential and non-residential 

customers between 2000 and 2009 (preliminary estimate by SEIA). Additionally, an estimated 

40 MW of off-grid PV capacity was added in 2009 (SEIA 2010). 

Source: SEIA 2010. Note: 2009 total is a projected amount (p).

Figure 1. Grid-connected PV capacity through 2009 (MW)

The five states with the greatest cumulative solar electric capacity all have requirements, have 

comprehensive net-metering programs, and, with the exception of Arizona, achieved a score of B 

on their interconnection procedures in the 2009 edition of Freeing the Grid. They gave Arizona a 

C, mainly due to the generator interconnection procedures never having been finalized. Several 

years ago, Arizona began a proceeding to examine interconnection procedures, but to date they 

remain as recommendations only. Arizona utilities, however, have individually adopted 
20 

interconnection procedures. Additionally, three of the top five states have included a solar 

requirement in their RPS: New Jersey—2.12% by 2021; Colorado—0.8% by 2020; and 

Nevada—1.5% by 2025. Arizona has included distributed generation requirements, which states 

that 4.5% of the electricity supply must come from customer-sited facilities by 2025 (DSIRE 

2010). 

9 Conclusion

Generator interconnection policies and procedures impact how and what type of FITs can 

successfully be implemented in the United States. FITs have been successful in Europe, leading 

to significant advances in renewable energy development in several countries. But the 

implementation of European-style FITs in the United States is constrained by legal and 

regulatory policies that determine interconnection procedures. European Union Member States 

have been directed to guarantee the interconnection of renewable generators, to prioritize the 

dispatch of renewable energy, and to consider requiring the purchase of that energy. European 

Union Member States also have the option of prioritizing the interconnection of renewable 

generators—in effect, moving them to the head of the queue. Additionally, the cost of 

interconnecting a new renewable energy generator to the electric grid is borne mainly by 

electricity customers. 

In the United States, new generators under FERC jurisdiction must be given non-discriminatory 

open-access to interconnection with no priority given to any particular technology or type of 

generator. Generators must also obtain dispatch, transmission service, and customers for their 

energy separate from interconnection. Generators are also required to pay the cost for directly 

connecting their facility to the transmission grid and to provide the initial funding for any 

necessary network upgrades. Under FERC rules, dispatch cannot be guaranteed. 

The guaranteed interconnection and dispatch preferences for generators under European-style 

FITs are incompatible with the FPA and established FERC regulations. The development of a 

national-level FIT or state-level FITs for large generators connecting to the FERC-jurisdictional 

transmission system would require changes to the FPA.23

 

23 FERC jurisdiction under FPA applies to all wholesale markets engaged in interstate commerce. A recent FERC 

order affirmed FERC's jurisdiction in this regard. The CPUC requested that FERC issue a declaratory order finding 

that a feed-in tariff for cogeneration facilities does not invoke FERC jurisdiction under the FPA. FERC ruled that the 

feed-in tariff constitutes an attempt to set wholesale rates. FERC stated the CPUC's feed-in tariff "will not be 

preempted by the FPA and PURPA as long as: (1) the CHP generators from which the CPUC is requiring the Joint 

Utilities to purchase energy and capacity are QFs pursuant to PURPA; and (2) the rate established by the CPUC 

does not exceed the avoided cost of the purchasing utility" (FERC 2010a). In response to a request for clarification 

from the CPUC, FERC clarified that "a multi-tiered avoided cost rate structure is consistent with the avoided cost 

rate requirements set forth in PURPA...(and) if a state required a utility to purchase 10 percent of its energy needs 

from renewable resources, then a natural gas-fired unit...would not be relevant to determining avoided costs for that 

segment of the utility's energy needs." (FERC 2010b, 13). FERC also explained that the CPUC could include in 

their determination of avoided costs the expected costs for avoiding upgrades to the distribution or transmission 

system, as long as those costs are based on an actual determination of expected costs (FERC 2010b). 

 State-jurisdictional interconnection 

rules and procedures affecting distributed renewable generation facilities can be changed by 

states to align with state-level renewable energy goals and FIT policies. States seeking to 

implement FITs may wish to focus on creating FIT-type policies at this level. 
21 

States may also wish to examine their interconnection policies and procedures to ensure that 

these are aligned with their overall renewable energy goals and policies. The various model rules 

have been used by numerous states to inform interconnection development proceedings. The 

Freeing the Grid report studied state interconnection procedures and formulated some lessons 

learned including: 

• Ensure fees are fair and proportional to a project’s size.

• Cover all generators in order to close any state-federal jurisdictional gaps.

• Screen applications by degree of complexity and adopt “plug-and-play” rules for 

residential-scale systems and expedited procedures for other systems.

• Ensure that policies are transparent, uniform, and detailed. 

• Prohibit requirements for additional insurance and extraneous devices, such as 

redundant disconnect switches. 

• Apply existing relevant technical standards, such as IEEE 1547 and UL 1741. 

• Process applications quickly; a determination should occur within a few days. 

• Standardize and simplify forms. 
22 

Appendix

State Interconnection Procedures Case Studies

California

CPUC approved California Rule 21 in 2000 making California one of the first states to adopt a 

comprehensive state interconnection policy. Rule 21 was developed with the aim of streamlining 

the state’s interconnection protocols through simplification and standardization and to encourage 

the installation of renewable energy generation facilities. As one of the first comprehensive 

procedures developed for state-jurisdictional generation facilities, and because it included model 

tariff language, Rule 21 has become a model for other states’ policies. 

Rule 21 details the standard interconnection, operating, and metering requirements for statejurisdictional generation systems. There is no specified system capacity limit under Rule 21. The 

amount of general liability insurance that project proponents are required to carry are established 

by CPUC and determined by the size and type of the proposed project, with some projects not 

needing any insurance beyond standard policies. Net-metered solar and wind systems, for 

example, do not require any additional insurance. The technical requirements for distributionlevel generation installations in California are similar to the technical requirements established in 

IEEE 1547, such as those concerning voltage and frequency fluctuations, flicker, DC injection, 

harmonics, protection devices, and islanding. The testing and certification requirements include 

the IEEE standards as well as the UL standards.

Under Rule 21, applicants begin at the same point in the review process regardless of project 

capacity and are later sorted by the complexity of the interconnection. The interconnecting 

utility conducts an Initial Review Process to determine if the generation facility is eligible for a 

simplified interconnection. Under a simplified interconnection, no supplemental review or 

interconnection studies are required. If the initial review process is not passed, a supplemental 

review process follows. If the applicant passes the supplemental review process, interconnection 

may be permitted if certain requirements are met. If it fails, however, an interconnection study 

will be pursued, with the costs determined by the utility and paid for by the system owner. A 

basic outline of the screening process can be found in Figure A-1. 
23 

Source: Cooley et al. 2003. 

Figure A-1. California Rule 21 screening process 

California Public Utilities Code 2827 specifies that small PV and wind turbine generation 

systems under 1 MW, which is the capacity limit in California to qualify for net metering, are 

exempt from installing additional controls, performing or paying for additional tests, and 

purchasing additional liability insurance. This is provided they comply with the applicable safety 

and performance standards of the National Electric Code, IEEE, accredited testing laboratories 

including UL, and CPUC rules regarding safety and reliability. Although utilities are required to 
24 

supply a two-way meter for net-metered systems, a system owner will be only be required to pay 

for it if they choose time-of-use metering. California’s requirements for an external disconnect 

switch varies by utility and system size. 

A 2005 report found that while it took roughly a year for utilities to approve interconnection 

requests prior to the adoption of Rule 21, it was taking less than three months to do so by 2003 

(Michel and Prabhu 2005). The same report stated that interconnection fees decreased for most 

of the applicants from about $5,000 to between $800 and $1,400 after Rule 21 was approved. 

Between January 2001 and June 2006, 533 renewable energy projects, totaling 606.8 MW, were 

authorized to interconnect under Rule 21 (California Energy Commission 2006). 

New Jersey

New Jersey was one of several states involved in the development of the MADRI model 

generator interconnection procedures, which were published in 2004, though New Jersey opted 

to create their own standards rather than adopt the MADRI model. Motivated by the state’s RPS, 

set at 20% renewable energy by 2020, New Jersey’s Board of Public Utilities (BPU) had already 

adopted interim interconnection standards in 2001, which were then finalized in 2004. The New 

Jersey standards have been amended several times, most recently in 2010. 

Interconnection requests in New Jersey are reviewed at three different levels, based on size and 

certification. Level 1, for which there is no fee for interconnection, is applicable to inverterbased systems that have a capacity rating of up to 10 kW. Level 2 applies to systems with up to 2 

MW of capacity. For both Levels 1 and 2, the systems must be certified as meeting IEEE 1547 

and UL 1741 standards. At Level 2, the interconnection could include a fee of $50 plus an 

additional $1 per kW of capacity. The costs of any additional reviews or modifications to the 

utility distribution system, based on estimates prepared by the electric utilities, may also be 

included, but are subject to a case-by-case review. Charges for engineering work that takes place 

as part of an additional review are capped at $100 per hour. At Levels 1 and 2, utilities are not 

permitted to require the customer-generators to buy additional liability insurance, to install 

further controls or external disconnect switches not included in the equipment package, or to 

require additional testing. The Office of Clean Energy in the BPU has developed standardized 

interconnection forms with stakeholder input. The forms for Level 1 have been in use for several 

years, and the forms for Levels 2 and 3 are currently being finalized. 

Level 3 is comprised of those systems that do not qualify for review at either Levels 1 or 2. 

Level 3 systems could be subject to a $100 fee, plus an additional $2 per kW of capacity and 

direct costs from any impact or facilities studies. Similar to Level 2, the costs for engineering 

work done as part of an impact or facilities study for Level 3 are capped at $100 per hour. Also, 

the costs are borne by the applicant if the electric distribution company has to install any 

facilities to accommodate the interconnection.

From 2001 through 2009, 4,943 renewable energy technology projects were installed in New 

Jersey, totaling about 165 MW. The majority of these projects have been solar, which comprise 

about 126 MW of the total installed capacity during that time period (see Figure A-2).
25 

NJ Solar Installed Capacity by Year

0

20

40

60

80

100

120

140

160

180

200

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Installed Capacity (MW dc)

Capacity Added Total Installed Capacity

Source: New Jersey Clean Energy Program 2010; Includes New Jersey solar installations for 2010 as of 6/30/10.

Figure A-2. New Jersey installed solar capacity by year

Oregon

Oregon’s net-metering law was enacted in 1999 and amended in 2005 to add biomass and allow 

the Oregon Public Utility Commission (Oregon PUC) to expand the net-metering facility size for 

Oregon’s two primary IOUs, Portland General Electric (PGE) and Pacific Power & Light 

Company (dba PacifiCorp). The net-metering law applies to solar power, wind power, 

hydropower, fuel cells, and biomass resources used to generate electricity. Utilities must allow 

net-metering facilities with a generating capacity up to 25 kW. The law applies to all utilities in 

the state, although the law allows Idaho Power to adhere to net-metering rules set by the Idaho 

Public Utilities Commission. Except for IOUs, a utility may limit net metering when the

cumulative generating capacity of all net-metered systems in its service area reaches 0.5% of its

historic single-hour peak load. PGE and PacifiCorp may not limit the aggregate capacity of netmetered systems in their service territories unless ordered to do so by Oregon PUC. 

The law contains a handful of provisions addressing interconnection requirements. Net-metering 

systems must meet all applicable safety and performance standards established in the state 

building code. Those standards must be consistent with the applicable portions of the National 

Electric Code, IEEE standards, and an accredited laboratory, such as UL. Utilities may not 

require additional tests or the purchase of additional liability insurance, though it is specified that 

utilities are not legally responsible for any loss, injury, or death related to the interconnection of 

a net-metered system.

In 2007, the Oregon PUC established standard interconnection requirements for net-metered 

facilities for PGE and PacifiCorp. The Oregon PUC opted to base its interconnection rules for 

net-metered systems on the MADRI model standards. Rather than adopt the model procedures 

verbatim, however, Oregon made some modifications, resulting in Oregon’s unique generator 

interconnection procedures. 

For net-metering in PGE’s and PacifiCorp’s territories, the Oregon PUC retained the minimum 

capacity limit for individual residential systems at 25 kW and expanded that limit to 2 MW for 

non-residential systems. The interconnection procedures require a standard application and a 
26 

standard agreement. The installation of grid-connected PV systems rose 330% in 2008 in 

Oregon, increasing PV capacity from 1.1 MWDC to 4.8 MWDC (Sherwood 2009). 

There are three levels of review for the interconnection of PGE and PacifiCorp’s net-metered 

systems. Certified, inverter-based systems with a capacity of up to 25 kW that are in compliance 

with UL 1741 and IEEE standards are reviewed under Level 1. This is provided that the systems 

have passed certain technical screens, a requirement for all three levels. At this first level of 

review, utilities are not permitted to levy application fees or other charges. Level 2 extends to 

certified systems of up to 2 MW that are not qualified for review under Level 1. At this level, 

utilities are permitted to charge fees, with a cap of $50 plus $1 per kW of system capacity. In 

addition, utilities may recover the costs for any additional reviews that are required and the costs 

for any upgrades to the electric distribution system, provided they are considered to be within 

reason. For both Level 2 and Level 3, a cap of $100 per hour is imposed on costs associated with 

engineering work done for an impact study or an interconnection facilities study. Systems that 

are ineligible for review under Levels 1 or 2 and have a maximum capacity of 2 MW are 

reviewed under Level 3. Utilities may charge fees up to $100 plus $2 per kW of the system’s 

capacity, as well as the costs for any impact or facilities studies. The applicant is also responsible 

for the costs of any distribution system upgrades the utility has to install to accommodate the 

interconnection. 

The Oregon PUC also established interconnection standards for other distributed generators 

under its jurisdiction, primarily PURPA facilities. All three investor-owned utilities—PGE, 

PacificCorp, and Idaho Power—are subject to these regulations. To date, interconnection 

regulations have been adopted for facilities up to 10 MW and for facilities over 20 MW (based 

on the FERC interconnection regulations for large generators). Interconnection regulations for 

facilities between 10 and 20 MW have not yet been adopted. 

Oregon adopted the interconnection rules for non-net-metered small generator facilities up to 

10 MW in 2009. The Oregon interconnection procedures for these systems have four levels of 

review. All systems must adhere to the IEEE 1547 and IEEE 1547.1 standards, unless otherwise 

specified by the Oregon PUC. The levels are divided by capacity with varying application fees. 

Level 1 includes facilities up to 25 kW, with the application fees capped at $100, while Level 2 

extends to facilities ineligible for Level 1 that have a capacity of up to 2 MW, and an application 

fee limit of $500. The rules for Levels 1 and 2 parallel the rules set in place by the Oregon PUC 

for net-metered systems. Levels 3 and 4 both limit the application fees to $1,000. Level 3 covers 

those non-exporting systems with a nameplate capacity up to 10 MW that are ineligible under 

Levels 1 or 2, and Tier 4 covers other systems ineligible for Tiers 1, 2, or 3 with a capacity of 

10 MW or less. Additional charges could apply but the applicant must review and provide 

written consent for any charges beyond the application fee.

Oregon’s net-metering law does not explicitly require external disconnect switches for netmetered systems but conversely does not prohibit their inclusion. Therefore, some utilities 

require them. The Oregon PUC allows PGE and PacifiCorp to require external disconnect 

switches except for inverter-based systems with a capacity of 25 kW or less. 
27 

References 

California Energy Commission. (2006). “Summary of Rule 21 Activity As Of 6/30/06 As 

Reported by Utilities.” California Distributed Energy Resource Guide. Rule 21 Statistics: 

Approved and Pending. http://www.energy.ca.gov/distgen/interconnection/rule21_stats.html. 

Accessed February 2010. 

California Public Utilities Commission (CPUC). (21 December 2000). Decision 00-12-037. 

Decision Adopting Interconnection Standards, Rulemaking 99-10-025. 

Cooley, C.; Whitaker, C.; Brooks, B.; Prabhu, E. (September 2003). California Interconnection 

Guidebook: A Guide to Interconnecting Customer-owned Electric Generation Equipment to the 

Electric Utility Distribution System Using California’s Electric Rule 21. Consultant Report 

prepared by Overdomain, Endecon Engineering, and Reflective Energies for the California 

Energy Commission Public Interest Energy Research Program. 

http://www.energy.ca.gov/reports/2003-11-13_500-03-083F.PDF. Accessed August 2010. 

Cory, K.; Couture, T. (June 2009). State Clean Energy Policies Analysis (SCEPA) Project: An 

Analysis of Renewable Energy Feed-in Tariffs in the United States. NREL/TP-6A2-45551. 

Golden, CO: National Renewable Energy Laboratory. 

http://www.nrel.gov/docs/fy09osti/45551.pdf. Accessed August 2010. 

Cory, K.; Couture, T.; Kreycik, C. (March 2009). Feed-in Tariff Policy: Design, Implementation, 

and RPS Policy Interactions. NREL/TP-6A2-45549. Golden, CO: National Renewable Energy 

Laboratory. http://www.nrel.gov/docs/fy09osti/45549.pdf. Accessed August 2010. 

DB Climate Change Advisors. (April 2010). GET FiT Program: Global Energy Transfer Feed-in 

Tariffs for Developing Countries. New York, NY: Deutsche Bank Group. 

http://www.dbcca.com/dbcca/EN/_media/GET_FiT_Program.pdf. Accessed August 2010. 

DSIRE. (2010). Database of State Incentives for Renewables & Efficiency. 

http://www.dsireusa.org/index.cfm?EE=0&RE=1. Accessed July 2010. 

European Energy Commission (2010). Renewable Energy, Targets. 

http://ec.europa.eu/energy/renewables/targets_en.htm . Accessed August 2010.

The European Parliament and the Council of the European Union. (27 September 2001).

“Directive 2001/77/EC of the European Parliament and of the Council of 27 September 2001 on 

the Promotion of Electricity Produced from Renewable Energy Sources in the Internal Electricity 

Market.” 

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:140:0016:0062:EN:PDF . 

Accessed August 2010. 

FERC. (2003). Standardization of Generator Interconnection Agreements and Procedures. 18 

CFR Part 35. Docket No. RM02-1-000; Order 2003-C, issued June 16, 2005. 

http://www.ferc.gov/industries/electric/indus-act/gi/stnd-gen.asp. Accessed August 2010. 
28 

FERC. (2005). Standardization of Small Generator Interconnection Agreements and Procedures.

18 CFR Part 35. Docket No. RM02-12-000; Order 2006-B, issued July 20, 2006. 

http://www.ferc.gov/industries/electric/indus-act/gi/small-gen.asp. Accessed August 2010. 

FERC. (2010a). Order on Petitions for Declaratory Order, Docket No. EL10-64, issued July 15, 

2010. http://elibrary.ferc.gov/idmws/File_list.asp?document_id=13832624. Accessed August 

2010. 

FERC. (2010b). Order Granting Clarification and Dismissing Rehearing, Dockets No. EL10-64-

001 and EL10-66-001, issued October 21, 2010. 

Fox, K.; Keyes, J.; Sheehan, M. (30 September 2008). Interconnection and Net Metering of 

Distributed Generation. Interstate Renewable Energy Council Telephone Seminar. 

http://www.irecusa.org/uploads/media/IREC_IC_and_NM_Sep_2008.pdf. Accessed August 

2010. 

German Federal Ministry for the Environment, Nature Conservation, and Nuclear Safety. (March 

2010). Development of Renewable Energy Sources in Germany 2009. 

http://www.bmu.de/files/pdfs/allgemein/application/pdf/ee_in_deutschland_graf_tab_2009_en.p

df. Accessed August 2010. 

Hempling, S.; Elefant, C.; Cory, K.; Porter, K. (January 2010). Renewable Energy Prices in State 

Feed-in Tariffs: Federal Law Constraints and Possible Solutions. NREL/TP-6A2-47408. 

Golden, CO: National Renewable Energy Laboratory. 

http://www.nrel.gov/docs/fy10osti/47408.pdf. Accessed August 2010. 

Interstate Renewable Energy Council (IREC). (2009). Model Interconnection Procedures: 2009 

Edition. http://irecusa.org/wp-content/uploads/2010/01/IREC-Interconnection-Procedures2010final.pdf. Accessed August 2010. 

IPA Energy and Water Economics. (July 2008). Innovative Electricity Markets to Incorporate 

Variable Production. Final Report to International Energy Agency - Renewable Energy 

Technology Deployment. http://www.iearetd.org/files/IEMVP_Innovative%20electricity%20markets_MAIN.pdf. Accessed August 2010. 

KEMA, Inc. (November 2008). Exploring Feed-in Tariffs for California, Feed-In Tariff Design 

and Implementation Issues and Options. Prepared for the California Energy Commission. 

Keyes, J.B.; Fox, K.T. (October 2008). Comparison of the Four Leading Small Generator 

Interconnection Procedures. Interstate Renewable Energy Council. Prepared for the Solar 

America Board for Codes and Standards. http://www.solarabcs.org/interconnection/ABCS07_studyreport.pdf. Accessed August 2010. 

Klein, A.; Pfluger, B.; Held, A.; Ragwitz, M; Resch, G.; Faber, T. (October 2008). Evaluation of 

Different Feed-in Tariff Design Options – Best Practice Paper for the International Feed-In 

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Letendre, S.E.; Taylor, M. (March 2008). Residential Photovoltaic Metering and Interconnection 

Study. SEPA Report #01-08. Solar Electric Power Association. 

http://www.solarelectricpower.org/resources/reports.aspx. Accessed August 2010. 

MADRI. (25 November 2005). MADRI Model Small Generator Interconnection Procedures. 

http://sites.energetics.com/madri/docs.html. Accessed August 2010.

Michel, D.; Prabhu, E. (April 2005). “Interconnecting Distributed Generation: The California 

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http://www.ts-publishers.com/downloads/vol1no301.pdf. Accessed August 2010. 

National Association of Regulatory Utility Commissioners. (October 2003). Model 

Interconnection Procedures and Agreement for Small Distributed Generation Resources. 

http://www.naruc.org/Publications/dgiaip_oct03.pdf. Accessed August 2010.

Network for New Energy Choices. (November 2009). Freeing the Grid: Best and Worst 

Practices in State Net Metering Policies and Interconnection Procedures, 2009 Edition. 

http://www.newenergychoices.org/uploads/FreeingTheGrid2009.pdf. Accessed August 2010. 

New Jersey Clean Energy Program. (2010). Solar Installations Projects.

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Porter, K.; Fink, S.; Mudd, C.; DeCesaro, J. (January 2009). Generation Interconnection Policies 

and Wind Power: A Discussion of Issues, Problems, and Potential Solutions. NREL/SR-550-

44508. Golden, CO: National Renewable Energy Laboratory. 

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Sherwood, L. (July 2009). U.S. Solar Market Trends 2008. Interstate Renewable Energy Council. 

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_Solar_Market_Trends_Report_2008.pdf. Accessed August 2010. 

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Varnado, L.; Sheehan, M. (2009). Connecting to the Grid: A Guide to Distributed Generation 

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Center. 6th Edition. http://irecusa.org/wp-content/uploads/2009/11/Connecting-to-the-GridGuide-6th-edition.pdf. Accessed August 2010. 
F1146-E(10/2008) 

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4. TITLE AND SUBTITLE

The Relevance of Generation Interconnection Procedures to 

Feed-in Tariffs in the United States

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DE-AC36-08GO28308

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Sari Fink, Kevin Porter, and Jennifer Rogers

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NREL/SR-6A20-48987

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SS10.2444

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14. ABSTRACT (Maximum 200 Words)

Feed-in tariffs (FITs) have been used to promote renewable electricity development in over 40 countries throughout 

the past two decades. These policies generally provide guaranteed prices for the full system output from eligible 

generators for a fixed time period (typically 15–20 years). Due in part to the success of FIT policies in Europe, some 

jurisdictions in the United States are considering implementing similar policies, and a few have already put such 

policies in place. This report is intended to offer some guidance to policymakers and regulators on how generator 

interconnection procedures may affect the implementation of FITs and how state generator interconnection 

procedures can be formulated to support state renewable energy objectives. This report is based on a literature 

review of model interconnection procedures formulated by several organizations, as well as other documents that 

have reviewed, commented on, and in some cases, ranked state interconnection procedures.

15. SUBJECT TERMS

feed-in tariffs; FIT; generator interconnection; renewable energy; electricity regulation; Europe; United States; FERC; 

interconnection procedures; MADRI

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