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

Solar Renewable Energy 

Certificate (SREC) Markets: 

Status and Trends

Lori Bird, Jenny Heeter, and Claire Kreycik

Technical Report

NREL/TP-6A20-52868

November 2011
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

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Contract No. DE-AC36-08GO28308

Solar Renewable Energy 

Certificate (SREC) Markets: 

Status and Trends

Lori Bird, Jenny Heeter, and Claire Kreycik

Prepared under Task No. SM10.2464

Technical Report

NREL/TP-6A20-52868

November 2011
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iii

Acknowledgments

The authors would like to thank Jennifer DeCesaro of the U.S. Department of Energy Solar 

Technologies Program for her support of this work. The authors would also like to thank the 

following individuals for reviewing this report: Brad Bowery of SRECTrade; Charlie Coggeshall 

of New West Technologies, LLC; Jennifer DeCesaro of DOE; Galen Barbose of Lawrence 

Berkeley National Laboratory; Dan Yonkin and Yuri Horwitz of Sol Systems; and Karlynn Cory,

David Feldman, and Robin Newmark of NREL. We also wish to thank Mary Lukkonen of 

NREL and PWT Communications for editorial support. Finally, we wish to thank the following 

individuals for reviewing and providing information about their state solar requirements and 

SREC markets:

• Delaware: Courtney Stewart, Delaware Public Service Commission

• District of Columbia: Roger Fujihara, DC Public Service Commission

• Maryland: Kevin Mosier, Maryland Public Service Commission

• Massachusetts: Howard Bernstein, Mike Judge, and Natalie Andrews, Massachusetts 

Department of Energy Resources

• Missouri: Michael Taylor, Missouri Public Service Commission

• New Hampshire: Kate Epsen, New Hampshire Public Utilities Commission 

• North Carolina: Sam Watson, North Carolina Utilities Commission

• Ohio: Stuart Siegfried, Anne Goodge, Mark Bellamy, Katie Johnson, and Kristin 

Braun, Public Utilities Commission of Ohio

• Pennsylvania: Scott Gebhardt and Matt Wurst, Pennsylvania Public Utility 

Commission.
iv

List of Acronyms

AC alternating current

ACP alternative compliance payment

BTU British thermal unit

AC alternating current

DC direct current

EDC electric distribution company

EGS electric generation supplier

EY energy year

IOU investor-owned utility

kW kilowatts

MW megawatts

MWh megawatt-hour

PJM Pennsylvania New Jersey Maryland Interconnection

PSC public service commission

PUC public utility commission

PV photovoltaic

RFP request for proposal

RPS renewable portfolio standard

SREC solar renewable energy certificate

W Watt
v

Executive Summary

Solar renewable energy certificates (SRECs) represent the generation attributes of solar energy 

systems and can be traded separately from commodity electricity. A SREC is created for each 

megawatt-hour of electricity generated from solar energy systems. SREC markets have emerged 

in nine U.S. states and Washington, D.C., as a method to meet compliance with solar carve out 

provisions of renewable energy portfolio standards (RPS). Solar carve out provisions set 

requirements for solar generation or capacity. This report examines the status and trends of 

SREC markets. Key issues and trends discussed in the report include: 

• SREC markets are relatively young but expected to grow rapidly in coming years as 

state solar requirements ramp up. New Jersey has been the dominant market for 

SREC trading to date, but SREC markets in other states are expanding. Nationwide, 

solar carve outs in SREC markets are scheduled to grow from more than 520 MWAC

in 2011 to nearly 7,300 MWAC in 2025. 

• Policymakers establish key elements when designing SREC policies. Some states 

allow solar thermal to participate in SREC markets, but overall the SREC market is 

dominated by solar photovoltaics (PV). In terms of geographic eligibility, several 

states limit eligibility to in-state development, while a few allow SRECs from a 

broader geographic region. 

• Solar alternative compliance payments (ACPs) generally set a ceiling on prices and 

are scheduled to decline over time, reflecting expectations of declining PV costs. In 

shortage situations, SRECs typically trade near the solar ACP. 

• Lack of long-term contracts has been a barrier to project developers obtaining 

financing in some markets. This issue may continue to be a problem particularly in 

areas where rebates or other supplemental incentives expire and SRECs become the 

primary incentive stream for financing systems. Several states have instituted 

provisions such as long-term contracting requirements, price floors, or standardized 

long-term contracts to try to overcome these challenges.

• Rate caps exist in some form in five SREC markets but have not been reached or are 

yet to be evaluated. The modest size of most solar carve outs suggests that it is not 

likely that rate caps will be reached in the near term. 

• SREC markets are supporting a mix of PV system sizes, including residential, nonresidential, and utility-scale systems. In most markets, about two-thirds of registered 

projects are smaller than 10 kW. Projects larger than 250 kW dominate capacity 

installed in a few markets, including North Carolina, Massachusetts, and New Jersey. 

There has been a trend toward large-sized projects in recent years.

• Compliance has proved challenging in a number of SREC markets in recent years, but 

adequate supplies are expected going forward in many of these regions. A handful of 

states reported compliance shortfalls in 2009. The first compliance periods for a few 

markets occurred in 2010 or 2011. Recently, SREC spot prices have leveled or 

decreased in a number of markets as supplies have increased and compliance 

challenges have eased. 
vi

• SREC markets are expected to grow to more than 4,300 MW by 2020. In the near 

term, a sharp drop in SREC prices indicates that some markets may be oversupplied. 

An increase in installations has occurred in the last year due to a greater focus on U.S. 

markets, in large part due to slower growth in Europe, as well as a substantial drop in 

module prices. Capacity growth has been fueled in part by the approaching end of the 

Federal Treasury 1603 cash grant program, which will expire at the end of 2011. 

Looking forward, the largest markets to date are expected to slow over the next year 

or two but others are expected to continue to expand in the interim. 
vii

Table of Contents

List of Figures ..........................................................................................................................................viii

List of Tables ............................................................................................................................................viii

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

2 SREC Market Overview and Design .................................................................................................2

2.1 Market Size and Scope.................................................................................................... 2

2.2 System Eligibility: PV and Solar Thermal...................................................................... 5

2.3 State and Regional Eligibility Rules Define Markets..................................................... 7

2.4 Solar Alternative Compliance Payment Levels.............................................................. 8

2.5 Measurement and Verification Methods for SRECs .................................................... 10

2.6 Long-Term Contracting and Financing Provisions....................................................... 12

2.7 Rate Caps...................................................................................................................... 17

3 SREC Market Trends........................................................................................................................19

3.1 Trading Volumes and Market Activity ......................................................................... 19

3.2 In-State Versus Out-of-State Sourcing ......................................................................... 21

3.3 Size of Systems Supplying SRECs............................................................................... 25

3.4 SREC Prices.................................................................................................................. 30

3.5 Compliance in SREC Markets...................................................................................... 32

4 Future Outlook..................................................................................................................................35

5 Summary and Conclusions .............................................................................................................38

References.................................................................................................................................................40

Appendix.................................................................................................................................................... 47

Long-Term Contracting Provisions: SREC Auctions in New Jersey ....................................... 47

Long-Term Contracting Provisions: Competitive Solicitations in Pennsylvania..................... 48

SREC Price Floor Programs: Massachusetts and New Jersey Utility PSE&G ........................ 48
viii

List of Figures

Figure 1. Map of states with SREC markets................................................................................... 2

Figure 2. Future capacity required in SREC markets (2011–2025)................................................ 4

Figure 3. Solar alternative compliance payment levels over time ................................................ 10

Figure 4. SRECs issued in PJM-GATS, 2010 .............................................................................. 19

Figure 5. Monthly SREC trading volumes in PJM-GATS, 2009–2011 ....................................... 21

Figure 6. (a) Source of SRECs retired for 2010 compliance in Maryland (b) Source of SRECs 

retired for 2010 compliance in Washington, D.C................................................................. 24

Figure 7. (a) Source of SRECs retired for 2010 compliance in Pennsylvania (b) Source of SRECs 

retired for 2010 compliance in Ohio..................................................................................... 24

Figure 8. Number of PV projects by size and jurisdiction............................................................ 26

Figure 9. Aggregate capacity (in MW) of registered PV projects by size and jurisdiction.......... 26

Figure 10. Number and average size of facilities >250 kW installed annually in PJM-GATS.... 28

Figure 11. Aggregate capacity of utility scale (>1 MW) PV projects (completed and under 

development)......................................................................................................................... 29

Figure 12. SREC spot prices (per MWh), August 2009 to September 2011................................ 30

Figure 13. New Jersey solar carve out compliance....................................................................... 32

Figure 14. Average PV installed price Q1 2010 through Q2 2011............................................... 35

Figure 15. Capacity installed by month in New Jersey ................................................................ 37

List of Tables

Table 1. State SREC Policy Overview ........................................................................................... 3

Table 2. Capacity Required in SREC Markets (in MWAC)............................................................. 4

Table 3. Technologies Eligible to Participate in SREC Markets.................................................... 6

Table 4. Geographic Eligibility Requirements in SREC Markets.................................................. 7

Table 5. State Solar Alternative Compliance Payments............................................................... 10

Table 6. State Requirements for Verifying Solar Output to Sell SRECs...................................... 11

Table 7. Rate Cap on RPS or Solar Set-Aside.............................................................................. 17

Table 8. PV Capacity Additions (Annual and Cumulative) ......................................................... 20

Table 9. In-State Versus Out-of-State Project Registration as of October 2011 .......................... 22

Table 10. New Jersey EDC Solicitation 10-Year Contract Pricing, 2011.................................... 31

Table 11. Pennsylvania EDC Solicitation Contract Pricing, 2010–2011 ..................................... 31

Table 12. State Solar Carve Out Compliance, 2007–2009 ........................................................... 33
1

1 Introduction

Solar renewable energy certificate (SREC) markets have emerged in a number of U.S. states 

to encourage the adoption of solar energy systems. SRECs represent the generation attributes 

of solar energy systems and can be traded separately from commodity electricity. A SREC is 

created for each megawatt-hour (MWh) of electricity generated from solar energy systems. 

SREC markets have emerged in some U.S. states that have renewable portfolio standards 

(RPS). These standards require utilities or load-serving entities (LSEs) to procure minimum 

amounts of renewable energy, including solar energy, to serve their electricity loads. 

Obligated entities demonstrate compliance with RPS solar energy requirements by retiring

SRECs that they have acquired from the market.

RPS policies are widespread in the United States. By June 2011, 29 states, Washington, D.C., 

and Puerto Rico had adopted RPS policies, while another eight states had renewable portfolio 

goals. Of the jurisdictions with RPS policies in place, 17 had adopted specific targets, or 

“RPS carve outs,” for solar energy or distributed energy resources to ensure that these 

sources would be part of the resource mix (Wiser et al. 2010). More than half of the 17 

jurisdictions with solar carve outs in their RPS allow the use of SRECs to demonstrate 

compliance with solar targets. Other states have relied on financial incentives such as grants, 

rebates, performance-based incentives, feed-in tariffs, or standard offer contracts to achieve 

solar requirements or goals. In many cases, these financial incentives are used in conjunction 

with SRECs to help achieve compliance with solar carve outs. 

SREC markets are relatively new. New Jersey was the first state to rely heavily on SRECs as 

a market mechanism to meet its solar carve out. New Jersey’s first compliance year with its 

carve out was 2005, and initially, New Jersey established a rebate program to incentivize 

systems. Due to the high cost and constraints on the state budget, the state switched to a 

market-based SREC program in 2007 (Hart 2010). Since then, some states in the midAtlantic and surrounding regions have used SRECs to enable obligated entities to meet their 

solar carve outs, sometimes with other support schemes as well. 

In several western states, SRECs are used to track compliance with solar carve outs, but there 

is no active trading market. In some cases, SRECs may be sold into voluntary markets in 

which consumers, businesses, and institutions purchase the renewable energy equivalent of

their electricity needs. However, SRECs have played a limited role in these markets to date.

This paper examines experience in SREC markets in the United States. It describes how 

SREC markets function—key policy design provisions, eligible technologies, state and 

regional eligibility rules, solar alternative compliance payments (ACPs), measurement and 

verification methods, long-term contracting provisions, and rate caps. It also examines the

trends of SREC markets—trading volumes, sourcing trends, trends in the size of solar 

photovoltaic (PV) systems driven by these markets, and trends in price and compliance.

Throughout, the paper explores key issues and challenges facing SREC markets and attempts 

by policymakers to address some of these market barriers. Data and information presented in 

this report are derived from SREC tracking systems, brokers and auctions, published reports, 

and information gleaned from market participants and interviews with state regulators 

responsible for SREC market implementation. The last section summarizes key findings.
2 

2 SREC Market Overview and Design

2.1 Market Size and Scope

SREC Markets Have Expanded to 10 Jurisdictions 

SREC markets have emerged or are in the early stages of implementation in 10 jurisdictions. 

While 17 jurisdictions have an RPS carve out requiring electricity providers to obtain a 

certain fraction of their generation portfolio from solar, distributed generation (DG), or 

customer-sited sources, not all of these states allow the use of SRECs for compliance. Figure 

1 details the states that have an RPS solar carve out, and of those, which allow SREC trading. 

Figure 1. Map of states with SREC markets

Trading in SRECs is relatively new. SREC markets began when state solar targets took effect 

in New Jersey and Pennsylvania in 2005 and in Delaware and Washington, D.C., in 2007 

(see Table 1). SREC trading increased substantially in 2007 when New Jersey shifted from a 

rebate program to greater reliance on SREC markets to support solar projects. Since then, 

Maryland (2008), Ohio (2009), North Carolina (2010), New Hampshire (2010), and 

Massachusetts (2010) have begun implementation of their solar carve outs and associated 

SREC markets. Missouri’s solar requirement took effect in 2011. 

SREC targets vary considerably depending on the goals of each jurisdiction. The ultimate 

target for the percent of retail sales that must be met by solar energy varies from 0.2% by 

2018 in North Carolina to a high of 3.5% by 2026 in Delaware (see Table 1 and Figure 1). If 

RPS solar carve 

out 

SREC trading 

allowed

DC

OR: 20 MW 

solar PV by 

2020

NV: 

1.5% 

solar by 

2025

AZ: 4.5% DG by 2025

CO: 3% DG and 

1.5% customersited by 2020

NM: 4% solar electric 

and 0.6% DG by 2020 MO: 0.3% solar 

electric by 2021

IL: 1.5% PV by 2025

NJ: 5,316 GWh solar 

electric by 2026

NC: 0.2% solar 

by 2023

NH: 0.3% solar 

electric by 2014 NY: 0.4788% 

customer-sited 

by 2015

OH: 0.5% solar 

electric by 2025

MA: 400 MW 

PV by 2020

PA: 0.5% PV by 2021

MD: 2% solar by 2022

DE: 3.5% PV by 2026

DC: 2.5% 

solar by 2023
3

converted to a percentage of retail sales, New Jersey’s target is even higher. The stringency 

of the solar target, as well as other policy features, determines the extent to which new solar 

development is encouraged. 

Table 1. State SREC Policy Overview

State

Initial 

compliance 

year

Target 

(% of Retail 

Sales)

Obligated Entities

DC 2007 2.5% by 2023 All EDCs and EGSs 

DE 2007 3.5% by EY 2026 All EDCs 

Municipals/co-ops can set their 

own comparable RPS schedule 

by 2013

MA 2010 400 MW PV* All EDCs and EGSs

MD 2008 2% by 2022 All EDCs and EGSs, 

municipals, co-ops

MO 2011 0.3% by 2021 All IOUs**

NC 2010 0.2% by 2018 All IOUs, municipals, co-ops

NH 2010 0.3% by 2014 All IOUs and retail suppliers, 

excluding municipals

NJ 2005 5,316 GWh by EY 

2026

All EDCs and EGSs

OH 2009 0.5% by 2024 All EDCs and EGSs

PA 2005 0.5% by 2021 All EDCs and EGSs, voluntary 

participation by municipals, coops

Source: DSIRE 2011a.

Note: EY = energy year; EGS = electric generation supplier; EDC = electric distribution company; IOU = investorowned utility

*Massachusetts’s target is adjusted based on market conditions during previous years. In 2010, the compliance 

obligation was 34,164 MWh, the generation equivalent of 30 MW of capacity operating at a 13% capacity factor. 

This is equivalent to 0.07% of retail sales.

** Empire District Electric, one of Missouri’s four IOUs, is exempt from the state’s solar energy standard because 

it installed renewable energy capacity equal to 15% of the utility’s total owned fossil-fired generating capacity by 

January 2009 (DSIRE 2011a). 

In terms of total megawatts required under SREC policies, New Jersey is by far the largest 

market, requiring approximately 319 MWAC of solar capacity in 2011 and projected to have 

more than 4,000 MWAC by 2025 (see

Table 2 and Figure 2). The next largest near-term markets are Massachusetts, Pennsylvania, 

and Ohio. The Maryland market, while relatively modest in 2011, has aggressive targets that 

would require it to increase rapidly, making it the fourth largest market by 2015 and second 

largest market after New Jersey in 2020.
4 

Figure 2. Future capacity required in SREC markets (2011–2025)

Source: Barbose 2011, with updates

Table 2. Capacity Required in SREC Markets (in MWAC)

State 2011 2015 2020 2025

DC >3 63 146 240

DE 10 69 162 261

MA 69 299 312 312

MD 22 179 693 958

MO 11 28 59 93

NC 18 121 181 190

NH 6 22 23 24

NJ 319 829 1,825 4,053

OH 31 155 363 553

PA 33 264 546 567

TOTAL >522

 

2,029 

 

4,310 

 

7,251 

Source: Barbose 2011, with updates.

Note: Most states have annual targets based on a percentage of retail electric sales in the compliance 

year. These estimates use the megawatt-hour target and convert it to megawatts using default capacity 

factors in NREL’s PVWatts model, which determines the energy production of grid-connected PV 

systems. The capacity factors used assume that systems are south-facing and that the tilt is equal to 

the latitude of the state. The Massachusetts ultimate target, while not based on a percent of retail sales, 

requires a cumulative installment of 400 MWDC of solar capacity. These figures assume that 

Massachusetts’s solar requirement are not adjusted for under- or over-supply.

Note: In Washington, D.C., the 2011 compliance obligation is uncertain because contracts entered into 

before July 12, 2011, are exempt from the District’s increased solar requirement. This analysis assumes 

that existing contracts will expire before 2015 (Council of the District of Columbia 2011).

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2011 2015 2020 2025

Required solar capacity (MW)

NH

MO

NC

DC

DE

MA

PA

OH

MD

NJ
5

SREC markets began in restructured1 states in the mid-Atlantic and Northeast but have since 

expanded into states with regulated electricity markets. In restructured states, where 

organized electricity markets are in place, multiple LSEs may need to procure SRECs to 

meet RPS requirements. The responsibility of satisfying the RPS requirements is placed on 

both electricity distribution companies (EDCs) that supply default service to customers and 

alternative suppliers, known as electricity generation suppliers (EGSs). In these markets,

SRECs have been a useful tool. They enable trading among parties and they enable EGSs to 

procure SRECs from the spot market on a short-term basis or bi-laterally on a long-term 

basis. This flexibility of acquiring SRECs is important to both EDCs and EGSs because of 

uncertainty in future loads due to retail choice. 

Several states with traditionally regulated electric utilities, including Missouri and North 

Carolina, allow the use of SRECs to achieve compliance with RPS targets. This enables

utilities to procure SRECs from a broader geographic region than the state or balancing area.

In a few states, municipal utilities and electric cooperatives are also obligated (or 

encouraged) to comply with RPS standards (see Table 1), in some cases with different 

targets.

2

States measure RPS and solar set-aside compliance by looking at SRECs retired by the 

obligated entities. SRECs are retired when the owner designates that the SRECs will be used 

for compliance with a particular state RPS and transfers the SRECs to a retirement 

subaccount in the tracking system used to verify compliance. Regulators consider a 12-month 

span referred to as an energy year (EY) or compliance year. For example, the 2010 

compliance period may consider SRECs retired between January 1, 2010, and December 31, 

2010, or June 1, 2009, to May 31, 2010. Delaware, New Jersey, and Pennsylvania use a June 

1 to May 31 period, while D.C., Maryland, Massachusetts, New Hampshire, North Carolina, 

and Ohio use a January 1 to December 31 period (SRECTrade 2011a).

2.2 System Eligibility: PV and Solar Thermal

SREC Market is Dominated by PV, Although Solar Thermal Is Eligible in Some States

A key policy design feature of solar carve outs that impacts SREC markets is technology 

eligibility. PV is an eligible—and most commonly used—technology in meeting solar carve

out requirements in all SREC markets. Eligibility of solar thermal technologies is more 

varied. 

About half of the state SREC markets allow solar thermal systems to participate (Table 3). 

Maryland, North Carolina, Ohio, and Washington, D.C., allow solar thermal technologies,

including solar water heating, space heating and cooling systems, and other applications to 

 1 In states that have undergone electricity market restructuring, electricity customers have retail choice, meaning 

that they can shop among electricity suppliers. EDCs own the distribution infrastructure and are the providers of 

last resort. EGSs are suppliers that have entered the market to provide electricity generation service. 2 Publicly owned utilities are obligated in Maryland, while they are encouraged to comply voluntarily in 

Pennsylvania (UCS 2008) and can opt out of the Delaware RPS and solar set-aside if they create their own RPS 

standard by 2013. In North Carolina, a traditionally regulated electric market, investor-owned utilities (IOUs), 

municipal utilities, and electric cooperatives are required to meet the solar electricity requirement, though their 

overall RPS targets vary (12.5% for IOUs and 10% for munis/co-ops). 
6

participate in the SREC market. Solar thermal systems in Delaware, Missouri, and Ohio must 

generate electricity in order to be eligible.3 In Pennsylvania, solar thermal that generates 

electricity is eligible for the primary resource targets of Pennsylvania’s RPS, but it is not 

eligible for the state’s solar carve out.

Despite its eligibility in a number of states, solar thermal has played a limited role in SREC 

markets to date. Based on interviews with state regulators, few solar thermal projects have 

been used in SREC markets in Missouri, Ohio, and Washington, D.C. As of October 2011, 

287 solar thermal projects have been registered in PJM-GATS; the majority of systems 

(75%) are located in Virginia and North Carolina (PJM-GATS 2011a). For example, in North 

Carolina, the public utilities commission had approved 50 solar thermal projects, primarily

solar hot water systems, compared to 205 PV projects (NCUC 2011a). 

Table 3. Technologies Eligible to Participate in SREC Markets

State Solar PV Solar Thermal

DC Yes Yes

DE Yes Yes, but must generate electricity

MA Yes No

MD Yes Solar water heating, but must be installed on or after June 1, 2011

MO Yes Yes, but must generate electricity

NC Yes Yes*

NH Yes No**

NJ Yes No

OH Yes Yes, but must generate electricity

PA Yes No***

Source: SRECTrade 2011a

* Eligible solar thermal resources include solar hot water, solar absorption cooling, solar dehumidification, solar 

thermally driven refrigeration, and solar industrial process heat.

** Solar water heating that displaces electricity is eligible for Class I of New Hampshire’s RPS (Epsen 2011). 

*** Solar thermal is eligible for Tier 1 of Pennsylvania’s RPS. 

States have expanded eligibility for use of solar thermal over time, indicating that there may 

be more development of solar thermal in the future. In December 2010, under the “Solar 

Collector Certification Temporary Amendment Act of 2010,” the Washington, D.C., SREC 

market was expanded to include non-residential solar thermal systems, whereas previously 

only residential solar thermal systems were eligible. In May 2011, Maryland passed 

legislation enabling solar water heating systems to be eligible in the Maryland SREC market.

Systems installed on or after June 1, 2011, are eligible.

 3 Solar thermal is also eligible to meet solar set-aside targets in states that do not use SRECs. These states 

include Arizona, Nevada, and New York (Wiser et al. 2010). 
7

2.3 State and Regional Eligibility Rules Define Markets

Geographic Eligibility Requirements Influence the Location of Development 

Another key policy design feature of solar carve outs that impacts SREC markets is 

limitations on the geographic eligibility of systems. Table 4 summarizes state geographic 

eligibility rules. Some jurisdictions limit the eligibility of solar to in-state projects through 

interconnection or other requirements (Delaware, Massachusetts, and New Jersey), while

others allow a portion of the projects to come from out of state (North Carolina and Ohio).

Other states allow SRECs sourced from projects in a specified region, such as the electric

balancing area (Pennsylvania), or allow regional resources if in-state resources are

insufficient (Maryland, though a binding in-state requirement goes into effect after 2011)

(DSIRE 2011b). Washington, D.C., previously allowed regional resources to be used if local

resources were insufficient; however, legislation enacted in August 2011 specifies that solar 

generating systems must be located within D.C. or in locations served by a distribution feeder 

serving D.C. Missouri is unique in that 100% of its solar standard can be met with SRECs 

from anywhere in the United States. North Carolina allows SRECs from anywhere in the 

United States to meet up to 25% of its solar carve out.

Table 4. Geographic Eligibility Requirements in SREC Markets

State Geographic Eligibility

DC In-district or in locations served by a distribution feeder serving the District

DE Customer-sited solar must be located in state; non-customer sited solar can be 

located with PJM, or show import capabilities into PJM

MA In state

MD Solar resources must be connected with the distribution grid serving Maryland. On 

or before December 31, 2011, solar resources not connected to the Maryland grid 

are eligible if electricity suppliers were unable to contract for in-state SRECs

MO Out-of-state eligible (anywhere)

NC 25% from out-of-state eligible (anywhere)

NH Within New England or New York

NJ In state

OH 50% of SRECs must be generated by in-state resources; bordering states (DC, IN, 

KY, MD, MI, PA, WV) and areas able to prove delivery to Ohio are eligible for 50%

PA Out-of-state eligible (within PJM)

Source: DSIRE 2011a, Epsen 2011

Because only a few states allow SRECs to come from a broad geographic region, the national 

market for SRECs is limited. Generally, for nationally sourced SRECs to be eligible to 

qualify for RPS compliance, systems must be registered in renewable energy certificate 

(REC) tracking systems. For example, California and other western states have supplied 

SRECs registered in the Western Renewable Energy Generation Information System 

(WREGIS) tracking system to North Carolina and Missouri to help meet their solar 
8

requirements. There are currently nine REC tracking systems in operation in the 

United States.

In California, the state with the most grid-connected PV capacity, system owners retain the 

RECs and can resell them into SREC markets, even if they receive financial incentives under 

the California Solar Initiative.

4 The California Public Utilities Commission has issued a 

proposed decision that would allow system owners who install PV systems under the 

California Solar Initiative program to sell their SRECs to California utilities to meet the 

portion of the new 33% by 2020 RPS that can be met with RECs (CPUC 2011). 

Some states have faced challenges regarding RPS geographic eligibility rules on the basis of

the Dormant Commerce Clause of the U.S. Constitution, which precludes states from 

discriminating against or impeding interstate commerce. For example, Massachusetts faced a 

Commerce Clause challenge to its solar requirement, resulting in a partial settlement 

whereby the in-state requirement remains in place with modifications to its solar price cap, or 

solar alternative compliance payment (ACP), mechanism among other changes (Elefant and 

Holt 2011). However, in-state solar or DG requirements are untested by the courts to date.

The design of geographic restrictions may have bearing on the constitutionality. According to

a recent legal analysis, solar or DG carve outs that are limited to in-state resources are 

“facially discriminatory,” or discriminate on their face (Elefant and Holt 2011). They must be 

justified by demonstrating that the state lacks alternatives to achieve legitimate policy goals 

(Elefant and Holt 2011). However, eligibility based on functional requirements such as 

interconnection, deliverability, or displacement of power, which can be functionally 

equivalent to in-state requirements, might not be viewed as discriminatory, and therefore, has

lower risk of Commerce Clause challenges. States may be able to justify such policies

because the size of requirements would place a minimal burden on commerce and offer

legitimate benefits to the state, such as reliability and diversity of supplies that may not be 

readily achieved through other means (Elefant and Holt 2011).

2.4 Solar Alternative Compliance Payment Levels

Solar ACPs Generally Set a Ceiling on Prices and are Scheduled to Decline in Most 

Jurisdictions

The price of SRECs is generally limited by the solar ACP established by each state with a 

SREC market. If an entity obligated to meet the RPS cannot procure enough SRECs, it can 

pay the solar ACP for each megawatt-hour that it has not procured in the market. For this 

reason, the solar ACP essentially sets a ceiling on SREC prices, as obligated entities would 

not pay more than the level of the ACP to acquire SRECs for compliance. However, if SREC 

purchases are recoverable in rates and ACP payments are not, such as in Ohio and Missouri, 

it is possible that SREC payments could exceed the solar ACP. Payment of the ACP is 

generally the mechanism of last resort to achieve compliance with the RPS.

In most SREC jurisdictions, a solar ACP has been established either through legislation or by 

the state public utility commission (PUC). The solar ACP differs from the ACP established 

 4 As of June 30, 2011, more than 940 MW of PV was installed or actively reserved through the California Solar 

Initiative program (CPUC 2011).
9

for RECs used to meet the main RPS resource targets. Solar ACPs are set at levels higher 

than main RPS ACPs to reflect the higher cost of solar energy and to enable adequate support 

for solar projects. In situations where obligated entities are having difficulties in meeting 

solar RPS targets, SREC prices rise to levels near the solar ACP, and in oversupply 

situations, the price of SRECs can fall well below the solar ACP. 

Differences in solar ACP levels have affected SREC trading prices. For example, prices have 

been highest in New Jersey because New Jersey’s solar ACP of nearly $700/MWh is 

significantly higher than solar ACPs in other states, which are in the $400–$500/MWh range.

In Pennsylvania, solar ACPs are set at approximately twice the price paid for SRECs. In 

Missouri, there is a provision for non-compliance equal to twice the average market value of 

SRECs utilized for compliance during the period; non-compliance payments are not 

recoverable from ratepayers. North Carolina is unique in that there is no specific penalty or 

formula for assessing alternative compliance; it is up to the North Carolina PUC to enforce 

compliance. While Illinois has a significant solar carve out in its RPS, which takes effect in 

2013, it is unclear if there will be a separate solar ACP (Wiser et al. 2010), which would be 

necessary to encourage a distinct SREC market. If there is not, SRECs would not trade above 

the price of the main RPS ACP.

Most states have established long-term schedules for solar ACPs that generally decline over 

time given the expectation that the price of solar will fall in coming years, consistent with 

recent trends (see Table 5). The availability of long-term solar ACP schedules helps provide 

some certainty to the market, enabling developers and financiers to price forward contracts. 

Solar ACPs decline over time in New Jersey, Ohio, and Maryland, and in Massachusetts, the 

state is authorized to reduce the rate but not by more than 10% in a compliance year (Table 

5). Massachusetts recently decreased the solar ACP from $600/MWh to $550/MWh and 

proposed future levels for the next 10 years. 
10

Table 5. State Solar Alternative Compliance Payments

State Solar Alternative Compliance Payment 

DC $500/MWh through 2016, $350/MWh in 2017, $300/MWh in 2018, $200/MWh in 2019 and 2020, 

$150/MWh in 2021 and 2022, and $50/MWh in 2023 and thereafter

DE $400/MWh for LSEs first year of use, $450/MWh in second year, $500/MWh in third and 

subsequent years

MA $600/MWh in 2010; $550/MWh in 2011, 2012, and 2013; and proposed to decrease 5% each 

year through 2021

MD $450/MWh for solar shortfalls in 2008, $400/MWh in 2009 through 2014, $350/MWh in 2015 and 

2016, $200/MWh in 2017 and 2018, and continuing to decline by $50/MWh bi-annually until it 

reaches $50/MWh in 2023 and beyond

MO Penalty of at least twice the average market value of SRECs for the calendar year

NC No specified penalty but the North Carolina PUC is authorized to enforce compliance

NH $163/MWh in 2011, adjusts annually based on Consumer Price Index

NJ $693/MWh in EY 2010; declines by $16/MWh–$18/MWh annually through 2015

OH $450/MWh in 2009, $400/MWh in 2010 and 2011; declines by $50/MWh every two years to meet 

a minimum of $50/MWh in 2024a 

PA Roughly twice the price paid for PV by electricity suppliers in the stateb

a The Ohio PUC has the ability to increase the solar ACP if it determines entities are defaulting to the ACP rather 

than pursuing the necessary resources.

b The calculation also takes into account solar rebates, but this represents a small portion of the solar ACP.

Source: DSIRE 2011a

Figure 3. Solar alternative compliance payment levels over time

Source: DSIRE 2011a

Note: Massachusetts solar ACP levels for 2010 and 2011 are fixed; levels for 2012 and beyond have been 

proposed by the Department of Energy Resources but are not yet finalized.

2.5 Measurement and Verification Methods for SRECs

Methods of Verifying the Generation of SRECs Vary by System Size

Because SRECs can sell at high prices, an important issue is verifying the output from solar 

generators to ensure that the SRECs that are created match actual generation. Requirements 

$0

$100

$200

$300

$400

$500

$600

$700

$800

2010 2011 2012 2013 2014 2015 2016 2017 2018

Alternative Compliance Payment 

($/MWh)

NJ

MA

DE

DC

MD

OH

NH
11

for SREC measurement and verification vary to some degree across each state market. 

However, in general, most states allow small systems of less than about 10 kW to estimate 

annual generation based on models or engineering calculations. For example, models, such as 

PVWatts, are used to estimate the output of a facility based on system characteristics and 

average insolation for a particular location (Table 6). Typically for larger systems, a revenue 

grade meter is required to verify actual generation. This information is then self-reported to 

the REC tracking systems in most instances. Massachusetts has delegated the authority to

independent monitors to report production data for participating SREC systems greater than 

10 kW. 

Table 6. State Requirements for Verifying Solar Output to Sell SRECs

State Facility Reporting Provisions

DC Facilities <10 kW can use estimated generation based on PVWatts calculation; otherwise, 

facilities can self-report via a revenue grade meter. Energy output of solar thermal systems 

>10,000 kWh per year must be rated and certified, and energy output must be determined 

by an onsite energy meter. Solar thermal systems ≤10,000 kWh per year may use an 

onsite energy meter or the annual performance measure determined by SRCC OG-300. 

DE Self-reporting via a revenue grade meter is used.

MA All PV projects must self-report via a revenue grade meter to an independent verifier, the 

Massachusetts Clean Energy Technology Center. Projects <10 kW can report manually, 

while projects >10kW must report production using a data acquisition system (DAS). 

Currently there are 20 such DAS providers listed on the Massachusetts RPS website. The 

Massachusetts Clean Energy Technology Center maintains the production tracking 

system, verifies production data, and submits reports quarterly to NEPOOL-GIS.

MD Facilities <10 kW may use estimated generation based on the PVWatts calculator. All 

other facilities must report monthly meter readings. Solar hot water systems must be 

certified and metered. 

MO Not yet determined.

NC Projects installed “behind the meter” will be able to self-report their energy production data 

into the NC-RETS system to receive SRECs, while utility-metered projects will require a 

designated “Qualified Reporting Entity” with a separate NC-RETS account to upload 

generation data on their behalf. Systems >10 kW must be metered by the customer.

NH All projects installed on the customer side of the meter, regardless of size, require an 

independent monitor for production verification. 

NJ Facilities <10 kW may use estimated generation based on the PVWatts calculator. All 

other facilities must report monthly meter readings.

OH Self-reporting via revenue grade meter is used. If the system is ≤6 kW, generation can be 

reported from an inverter meter.

PA Facilities >15 kW must report monthly meter readings. Facilities <15 kW are eligible to use 

estimated generation based on PVWatts calculation, unless they receive funding from the 

PA Sunshine Fund.

Sources: SRECTrade 2011a; Massachusetts DOER 2011a; Epsen 2011

States allowing solar thermal systems use a conversion factor to issue SRECs to solar thermal 

projects. Converting non-electric solar thermal output into a SREC equivalent is done using a 

conversion factor of 3,412,000 British thermal units (BTUs) to 1 SREC. This standard rate is 

used by states but only specified in implementation rules by North Carolina. In Washington, 

D.C., smaller systems use the kilowatt-hour (kWh) factor supplied by the Solar Rating and 
12

Certification Corporation. Larger systems in Washington, D.C., must be metered; the BTU 

output is then converted to kilowatt-hours. Maryland specifies that BTUs created by solar 

thermal systems be converted to kilowatt-hours.

2.6 Long-Term Contracting and Financing Provisions

Lack of Long-Term Contracts Have Impeded Development in Some Cases: Some States Have 

Developed Mechanisms to Help Facilitate Financing

In some instances, reliance on spot market SREC prices has led to challenges in achieving 

compliance with solar carve outs, particularly in restructured electricity markets. Reliance on 

short-term spot markets for SRECs can pose problems for solar developers in obtaining the 

financing necessary to bring projects to fruition. Financiers (both debt and equity lenders) 

generally do not take SREC revenues into account unless a contract with a creditworthy 

purchaser is in place (Holt et al. 2011). This issue can be particularly problematic for largescale systems that require debt or equity financing. At the same time, many electricity 

suppliers, especially in restructured electricity markets, resist signing contracts longer than 

two to three years. This may be because future loads, and therefore future solar compliance 

obligations, are unknown. Additionally, suppliers in regulated states may perceive some risk 

regarding cost recovery mechanisms if the contract extends beyond the current rate plan. As 

a result, some solar developers have had difficulty obtaining financing for their projects due 

to a lack of opportunities to enter long-term SREC contracts. 

To address challenges in obtaining financing, some state policymakers have implemented 

provisions that reduce investor risk. As noted earlier, long-term solar ACP schedules can 

help reduce investor risk by providing knowledge of future price caps. In SREC markets, 

other provisions include: (1) requiring or encouraging long-term contracts or (2) establishing

payment floors to set a minimum price for SRECs, which guarantee a minimum return. Also, 

some jurisdictions have implemented price responsive demand mechanisms through which 

future solar targets are reduced in the case of shortages or increased in the case of 

oversupplies. Also, many utilities in regulated electric markets offer long-term contracts for 

the SRECs and output of solar energy systems to facilitate development or elect to own solar 

projects.

5 In some jurisdictions, rebates or other types of incentives have been offered to 

reduce the risk and need to rely solely on SREC revenues, but we do not cover these 

programs in detail below.

Long-Term Contracting Requirements 

State policymakers and regulators in New Jersey, Pennsylvania, and to a lesser extent 

Maryland encourage the use of long-term contracting to enable solar projects to obtain 

financing. 

New Jersey has created a formal SREC-based financing program that awards long-term 

contracts through requests for proposals (RFPs) to help winning residential and commercial 

developers secure financing for their solar projects. The contracts resulting from the RFPs are 

standardized and non-negotiable, and developers are encouraged to bid SREC prices that 

 5 Other mechanisms have been used to minimize or address investor risk, but these are generally outside the 

scope of SREC markets. Also, some states have used centralized procurement for their RPS. 
13 

would provide sufficient project returns. These programs represent only a fraction of the 

overall market, which called for about 320 MWAC of installed capacity in 2011 alone. The 

Jersey Central Power & Light, Atlantic City Energy, and Rockland Electric Company SRECbased financing programs were designed to support a total of 64 MW (name plate) from 2009 

through 2011 (NERA Economic Consulting (2011b). The PSEG Solar Loan program had the 

goal of supporting 81 MW in the first two phases (NJ BPU 2011 d) (see Appendix for 

additional detail). As a result of these programs and perhaps other market conditions, longterm contracts have historically been more widely available in New Jersey than in other 

markets, making it easier for developers to operate and obtain financing. However, the 

availability of long-term contracts outside of the utility programs has declined recently with 

the drop-in SREC prices and signs of near-term oversupply in the market, as one might 

expect (SEIA/GTM 2011b; SEIA/GTM 2011c). 

In Pennsylvania, the PUC issued a policy statement encouraging EDCs to conduct 

competitive solicitations for SRECs and procure SRECs from small-scale projects 

(<200 kW) through RFPs and bilateral contracts. It specifies that the price negotiated for 

SRECs from small-scale projects should not exceed the average winning bid price in the 

EDC’s most recent RFPs for large-scale solar projects (Pennsylvania PUC 2011). In 

response, Pennsylvania EDCs have started to hold competitive solicitations to procure a 

portion of their SREC obligations over a longer delivery period (e.g., 7–10 years). The 

utilities are seeking bids in tranches (i.e., 100, 250, or 500 SRECs per year from an 

individual supplier). One of the utilities, PPL Electric Utilities, is issuing RFPs for individual 

projects as well as aggregations of projects <15 kW in size. These programs have not been 

large to date, however. The Met-Ed and Penelec solicitiations in 2010 were for 25,000 MWh 

while Penn Power and PPL Electric solicitations in 2011 were for a total of 46,000 MWh 

(see Table 10 and Appendix for additional details). The state is well ahead of its 

compliance targets, but this has been largely attributed to the availability of rebates that 

created an attractive incentive for projects (SEIA/GTM 2011b). 

Maryland has a loose requirement aimed at helping buyers and sellers find each other and 

negotiate bilateral contracts. The Maryland Public Service Commission (PSC) requires solar 

generators to first offer their SRECs for sale on the PSC’s website, if they want to sell 

directly to Maryland electricity suppliers requests for proposals. If the electricity suppliers 

enter into contracts directly with generators, the contracts must be for 15 years. Because 

long-term contracts are not required for purchases from brokers, most of the transactions in 

the market are broker-facilitated spot transactions (Mosier 2011). Therefore, this non-binding 

contracting requirement has had little effect in encouraging long-term contracts to date. 

Developers have indicated that the lack of long-term contracts makes it more difficult to 

secure financing for projects in Maryland because banks will not consider SREC revenues 

without a contract (SEIA/GTM 2011b). Therefore, developers have to take on more of this 

financial risk.

In Delaware, a long-term contracting program has been proposed. Delmarva Power applied 

to the Delaware PSC for the approval of a pilot SREC procurement program on September 

16, 2011. Under the program, solar generators of different sizes could receive fixed SREC 

prices for 20 years. For example, small systems under 50 kW would receive $260/MWh for 

10 years, followed by payments of $50/MWh for another 10 years. Larger systems of 
14 

250 kW to 2 MW would receive a bid price, if they submit winning bids. The program is 

slated to support a total of about 11,500 MWh, divided among four system size categories 

(Moore 2011). 

Long-Term Price Floors

Long-term price floors have been implemented in Massachusetts and New Jersey by the 

distribution utility PSE&G (see Appendix for additional detail on these mechanisms). 

Theoretically, long-term price floors serve the same purpose as long-term contracts. If a 

long-term price floor is structured in a way that guarantees a minimum value for SRECs in 

future years, investors may view it as they would a binding SREC contract.

In Massachusetts, the Solar Credit Clearinghouse was established in 2010 with the goal of 

establishing a minimum price to encourage development. The program enables any unsold 

SRECs in a compliance period to be auctioned at a minimum price of approximately 

$300/MWh. The useful life of SRECs is extended once they are submitted into an auction 

account, and the lifetime can be extended further if the SRECs do not sell at auction initially. 

So far, the program is untested because no auctions have been held due to shortages in the 

market. Despite its complexity and initial reservations about the program, investors are 

becoming more comfortable with this market design (SEIA/GTM 2011b). However, the 

program structure does not guarantee the sale of SRECs if the final auction does not clear. 

Also, it does not guarantee cash flows in a particular year. For example, if a SREC is not 

cleared during an auction and its shelf-life is extended and it is sold in a later year, the 

inability to receive payments in the first year can impact the return on a project. 

In New Jersey, the PSE&G loan program has an element of a price floor to provide 

confidence to consumers regarding the repayment of the loan. Under the program, PSE&G 

offers loans that cover 40%–60% of the cost of a PV system. Customers may repay the loan 

principal and interest through cash payments or by signing their SRECs over to PSE&G. 

Throughout the 15-year loan term, PSE&G credits customers for each SREC generated based 

on market prices but not below the established price floor, which is initially $420/MWh for 

residential systems. While spot prices have historically been much higher than these levels, 

this situation may be changing. Forward prices for 2012 recently fell well below the 

$420/MWh price floor, which may mean that the utility will have to recover the price 

differential from ratepayers. However, this remains to be seen. 

Price Responsive Demand 

The Massachusetts program also incorporates mechanisms to adjust the solar targets based on 

compliance with targets. These provisions can help regulate the supply and demand balance 

and reduce risks of an oversupplied market. For example, under the Massachusetts Solar 

Credit Clearinghouse program, the term that SRECs can be deposited in the auction is 

adjusted based on market conditions. Initially projects can opt to deposit SRECs in the 

auction account for up to 10 years of the life of the system, but that can be reduced if the 

market is oversupplied. Additionally, the compliance targets in Massachusetts are increased 

by the amount of SRECs deposited in the auction in a given compliance year to temper 

situations of oversupply (see Appendix for additional details). 
15 

Utility Standard Offer or Long-Term Contracts 

In traditionally regulated or hybrid electricity markets, such as North Carolina, Missouri, and 

Ohio, utilities offer fixed long-term contracts to solar generators to facilitate in-state solar 

development. Standard offer contracts can help the economics of small to mid-sized projects 

in particular. They provide certainty regarding the price that consumers can obtain for their 

SRECs, although they may not significantly influence the ability of retail customers to obtain 

loans for their projects. In general, payment terms have ranged from $30/MWh to 

$300/MWh for terms ranging from 5 to 20 years. Most of these programs have been offered 

on a trial basis, with limits on the enrollment period (one or two years) or limits on the 

overall capacity that can participate in the program (see text box for examples). 

Overall, the New Jersey long-term contracting provisions have been effective in driving new 

renewable energy development and enabling projects to obtain financing. However, falling 

SREC prices may mean that ratepayers will need to pay the difference between the long-term 

contracts offered by the distribution utilities and market prices. The price floor mechanism in 

Massachusetts has yet to be fully tested as the auction mechanism has not yet been used, but 

developers and investors may be gaining comfort with this model, according to industry 

analysts (SEIA/GTM 2011b). Fixed long-term contracts will continue to be important to 

drive in-state solar energy development in other markets; however, as many of the existing 

programs have limited funds or are available for a limited duration, it is unclear if they will 

be extended in future years. 

 
16 

Sample Utility Long-Term SREC Purchasing Programs to Encourage Small to Mid-Sized Systems 

As a method of procuring SRECs, several utilities in Missouri, North Carolina, and Ohio have developed 

SREC long-term purchasing programs for retail customers. These programs are either structured as standard 

offer contracts for SRECs, or upfront incentives, which are awarded in exchange for the right to keep the 

SRECs for a pre-defined number of years. 

Ameren Missouri was the first utility to develop a standard offer contract program for solar in Missouri. 

Customers installing systems with a nameplate capacity of less than 10 kW may sell SRECs for $100/MWh 

on a 10-year upfront basis, based on PVWatts estimates of output. Systems between 10 kW up to 100 kW in 

size may sell SRECs for $100/MWh on a 5-year basis based on actual generation from their metered output 

(Ameren 2011b). The program, which is separate from the solar rebate required by law, was funded with $2 

million for 2011, and all funding was committed as of mid-May 2011 with contracts completed or pending for 

2,269 SRECs (Ameren 2011a). Ameren may continue the program in 2012 and 2013, but it has not been 

submitted to the PUC (Ameren 2011a; Ameren 2011b). 

Duke Energy Carolinas launched a standard offer purchase program for RECs including SRECs in North 

Carolina in 2008. Under the program, the utility enters into contracts ranging from 5 years to a maximum term 

of 15 years. Contracts must be for at least 35 MWh/year of SRECs (approximately the output of a 25-kW 

system). Solar systems that generate more than 250 MWh/year are ineligible and can submit an unsolicited 

bid proposal to the utility instead. In 2010, customers were paid $30/MWh for SRECs under the standard offer 

program (this represents the price for the SRECs only, not the underlying electricity). SREC prices escalate 

annually for each standing contract. Prices will ultimately increase to $42/MWh in 2025 (Duke Energy 

Carolinas 2011). 

In Ohio, Duke Energy Ohio offers a residential PV REC purchase program that was approved in July 2010. 

The program is available through December 31, 2012, to Duke's residential customers, including both 

customers purchasing their electric generation service from Duke and those purchasing from other retail 

suppliers. The REC purchase agreements have a term of 15 years. Customers received $300/MWh for 

SRECs procured in 2010, and payment levels will be adjusted in subsequent years based on market prices 

(Duke Energy Ohio 2011a). 

Progress Energy Carolinas (Progress) has a similar standard purchase offer for North and South Carolina 

non-residential customers called the SunSense Commercial PV Program. Progress pays $180/MWh for both 

the electricity and SRECs generated by the PV system for a period of at least 20 years. To be eligible, the PV 

systems must have a nameplate capacity between 11 kWDC and 500 kWDC. Annual program participation is 

limited to 5 MW and net metering is not offered. Systems owned and operated by a third-party on a Progress 

Energy customer's property are also eligible. For residential systems sized 2 kWAC to 10 kWAC the utility 

provides a $1/wattAC upfront incentive and a monthly bill credit based on the AC rating of $4.5/kW (Progress 

Energy Carolinas 2011b). 

First Energy ran a residential REC purchasing program in Ohio in the service territories of Ohio Edison, The 

Illuminating Company, and Toledo Edison’s between 2009 and May 31, 2011. Under the program, First 

Energy offered 15-year contracts for residential SRECs. The price paid was determined through a biannual 

RFP process. The PUCO and FirstEnergy determined that if the utility was unable to procure SRECs through 

competitive solicitations, an alternative purchase price would be offered to residential customers. The price 

offered for SRECs from residential systems was $360/MWh in 2009 and $320/MWh in 2010 and 2011, 

decreasing by $40/MWh every two years over the lifetime of the contract (DSIRE 2011c). 

AEP Ohio began offering an incentive program for both residential and non-residential customers called the 

Renewable Energy Technology Program Rider in July 2011. The two-year program is funded at $1 million 

annually for solar. The current solar incentive is $1.50 per Watt, and this payment is provided to customers in 

exchange for the SRECs generated by the project for a 15-year period (AEP Ohio 2011). 
17 

2.7 Rate Caps 

Rate Caps Have Yet to be Reached Although Policy Implementation is in Early Stages 

Going forward, the need for obligated entities to meet solar carve outs can be influenced by 

the presence of electricity rate impact caps. These caps were established by legislators to 

limit the ratepayer impacts of RPS policies or, in some cases, the solar carve out in particular. 

Rate caps exist in some form in five SREC markets (Maryland, Delaware, Ohio, Missouri, 

and North Carolina) but have not been reached or are yet to be evaluated (Table 7). Delaware 

and Maryland have rate caps on the cost of the solar set-aside requirement, while other states 

have caps on the entire RPS. 

In Delaware, the cost of compliance includes costs associated with any ratepayer-funded 

rebate program, SREC purchases, and solar ACPs. If these costs exceed 1% of the total retail 

cost of electricity, then the PSC may freeze the solar requirement; Delaware also has a 3% 

cap on its RPS (14 DE Reg 1241, 3.2.16). This provision went into effect in July 2010, so the 

impact cannot be assessed until after utility compliance reports are filed in September 2011 

(Stewart 2011). 

Table 7. Rate Cap on RPS or Solar Set-Aside 

Rate Cap on RPS Rate Cap on Solar SetAside No Rate Cap 

OH: 3% increase in 

generation costs 

DE: 1% increase in retail 

rates (combination of solar 

set-aside, rebates, and solar 

ACPs together)* 

DC, PA, MA, NH, NJ** NC: Caps on annual cost per 

account for incremental RPS 

costs; varies by customer 

class and year 

MD: 1% increase in retail 

rates (solar set-aside only); 

allows for 1-year delay in 

meeting solar RPS 

MO: 1% increase in retail 

rates 

Source: Wiser et al. 2010; DSIRE 2011a; N.J.A.C 14:8-2.2 and 2.3, revised effective March 30, 2011. 

* Delaware also has a 3% cap on its RPS. 

**New Jersey previously had a rate cap of 2%, but the provision was removed as of March 2011. 

In Maryland, the increase is based on the actual or projected dollar-for-dollar cost to 

purchase SRECs. If that cost is 1% or more of a supplier’s total annual electricity sales 

revenues, then compliance can be delayed by one year (DSIRE 2011a). No requests have yet 

been made to delay compliance in Maryland (PSC MD 2011). 

Ohio, Missouri, and North Carolina have rate caps on the entire RPS policy. In Ohio, the 

increase is based on “reasonably expected” rate increases of no more than 3%. If rates are 

expected to increase by 3% or more above what they would have otherwise been, the cap 

goes into effect (DSIRE 2011a). 
18 

In Missouri, utilities may be excused from their obligation if the cost of complying with the 

RPS increases retail electricity rates by more than 1% in any year. If this occurs, the 

requirement will be adjusted in that year so that the rate cap is not violated (DSIRE 2011a). 

In their RPS planning dockets, no utilities in Missouri indicated potential shortages in SREC 

supply, likely due to the fact that they can obtain SRECs from out-of-state markets. One 

utility, Ameren, noted that it was able to procure SRECs at an average price of about 

$8/MWh. Ameren’s total projected compliance cost in 2011 was $5.3 million, which 

represents 0.01% of Ameren’s total revenue requirement (Ameren 2011b). Similarly, Kansas 

City Power & Light and KCP&L Greater Missouri Operations Company estimated that the 

average increase in annual revenue requirement would be 0.14% on a 3-year average and 

0.04% on a 10-year average (KCP&L-GMO 2011), which is far less than the 1% rate cap. 

North Carolina’s RPS legislation takes a different approach to capping costs. Utilities can 

recover up to a maximum dollar amount of “incremental costs” annually from each customer 

class (residential, commercial, and industrial). In 2011, for example, utilities were allowed to 

recover a maximum of $10 per residential account, $50 per commercial account, and $500 

per industrial account (N.C. Gen. Stat. § 62-133.8(h)(4)). 

In the future, it is possible that rate caps may be reached; whether they will be reached will 

depend on many factors, including future SREC costs and overall retail rates. Generally, the 

likelihood of reaching a cap is greater in states that cap the impact of the solar carve out (as 

opposed to the entire RPS) and also have aggressive solar targets. 
19

3 SREC Market Trends

3.1 Trading Volumes and Market Activity 

Most SRECs Have Been Sourced from New Jersey; Other Markets Are Expanding 

In recent years, the vast majority of SREC trading has occurred in New Jersey. Data on the 

source of SRECs traded or retired to meet state solar carve outs are available from the REC 

tracking systems used by the states to track RPS compliance.6 Trading and retirement data 

are generally similar for these markets, but SRECs could be traded multiple times before they 

are retired for compliance with a state solar carve out. 

Figure 4 shows SRECs issued in 2010 in the PJM Interconnection balancing area, the most 

active region for SREC trading. PJM data provide a good indication of total SREC activity 

because most states with SREC policies are in or can sell into the PJM balancing authority, 

with notable exceptions being Massachusetts, New Hampshire, and to some extent North 

Carolina.

7 In 2010, 75% of the SRECs issued in PJM were located in New Jersey, followed 

by Pennsylvania (11%), Ohio (6%), and Maryland (4%). Other states include SRECs from 

projects located in Virginia, North Carolina, Washington, D.C., and West Virginia. Data 

through October 2011 show similar general trends, with Pennsylvania seeing a higher 

percentage of issued SRECs (17%).

Figure 4. SRECs issued in PJM-GATS, 2010

Source: PJM-GATS 2011a

Solar capacity additions in recent years are consistent with the SREC trading data (see Table 

8 and Figure 4). Of the states with SREC markets in 2010, New Jersey led installed PV by 

far, with 260 MW of cumulatively installed PV capacity, much of which came online in 

 6 PJM-Generation Attribute System (PJM-GATS), the REC tracking system for the PJM balancing authority, 

provides information about the source of SRECs retired for each solar set-aside in the region. The majority of 

states with SREC markets are in PJM. This information is available on the Public Reports page of the PJMGATS website, under the heading “RPS Retired Certificates (Reporting Year)” (PJM-GATS 2011a). 

Massachusetts, Missouri, New Hampshire, and North Carolina employ different systems to track RPS 

compliance. Missouri uses the North American Renewables Registry (NARR), Massachusetts and New 

Hampshire use the NEPOOL Generation Information System (GIS) in New England, and North Carolina uses 

the NC-Renewable Energy Tracking System (NCRETS), which currently accepts credit transfers from the 

Midwest Renewable Energy Tracking System (M-RETS), NARR, the Western Renewable Energy Generation 

Information System (WREGIS), and the Electric Reliability Council of Texas (ERCOT) REC tracking system. 7 PV systems in North Carolina must choose whether to register in NC-RETS or the PJM-GATS system.

NJ, 75%

PA, 11%

OH, 6%

MD, 4%

DE, 3%

Other, 1%
20

2010, followed by Pennsylvania, North Carolina, and Massachusetts (Sherwood 2011). Note 

that North Carolina and Massachusetts are not included in the PJM-GATS SREC trading 

volume data. Missouri installations totaled less than 1 MW, but the Missouri solar 

requirement does not take effect until 2011.

Table 8. PV Capacity Additions (Annual and Cumulative)

State

2009 PV

Additions

MWDC

2010 PV

Additions

MWDC

Cumulative

Installed

Capacity MWDC

DC 0.3 3.5 4.5

DE 1.4 2.4 5.6

MA 9.6 20.4 38.2

MD 4.7 3.4 10.9

MO 0.1 0.5 0.7

NC 6.6 28.7 40.0

NH 0.5 1.3 2.0

NJ 57.3 132.4 259.9

OH 0.6 18.7 20.7

PA 4.4 46.5 54.8

Source: Sherwood 2011

Notes: Figures here are calendar year additions. Capacity for each state represents in-state generation, 

although some states allow out-of-state capacity to contribute. 

The dominance of SREC trades from New Jersey systems is not surprising because the New 

Jersey solar requirement was the first to take effect, its solar carve out is currently more than 

four times larger than the next largest state’s requirement, and its interconnection 

requirements are such that only in-state resources can meet its standard. Further, New Jersey 

has had the highest SREC prices in the region. However, there has been a move toward 

greater geographic diversity of SREC markets. Monthly SREC trading data in PJM show an 

uptick in volumes traded in markets other than New Jersey in 2010 and 2011 (see Figure 5), 

particularly from systems in Maryland, Pennsylvania, and Ohio.
21

Figure 5. Monthly SREC trading volumes in PJM-GATS, 2009–2011

SRECs can also be sold into voluntary markets in which individuals, businesses, and 

institutions make voluntary purchases of RECs to match their own electricity consumption. 

However, voluntary SREC transactions have been limited to date. In 2010, SRECs 

represented 0.2% of U.S. voluntary market sales, which includes sales by utility green 

pricing programs, competitive green power programs, and unbundled REC purchases (Heeter 

and Bird 2011). In some instances utilities use SRECs to include solar in the resource mix of 

utility green power programs offered to residential and small commercial customers, but they 

are a relatively small fraction of total program supplies. In 2010, utility programs procured 

about 39,000 MWh of solar energy to supply 0.8% of the green energy sold through their 

green pricing programs (Heeter and Bird 2011). In some instances, utilities have offered 

fixed-price, long-term contracts for the solar energy output and used the SRECs to supply 

green pricing programs. For example, the Tennessee Valley Authority (TVA) and North 

Carolina Green Power purchase the SRECs from PV system owners for a fixed fee of $0.10–

$0.12/kWh for an established period such as 10 years and supply their green power programs 

with the SRECs (TVA 2011; NCGP 2011).

3.2 In-State Versus Out-of-State Sourcing

Several States are Sourcing SRECs Primarily from In-State Systems, While Others are 

Sourcing More Broadly

The location of solar projects providing SRECs is also highly dependent on rules regarding 

whether states can source SRECs from in-state or out-of-state facilities, as mentioned earlier. 

As a result of policies that allow regional sourcing, some developers are registering their 

projects in multiple states, particularly within the PJM balancing authority, to increase their 

opportunities to sell SRECs. However, the majority of systems are being used for compliance 
22

in state. Of the roughly 17,000 PV facilities registered in PJM-GATS,

8 83% are registered 

for use in the SREC market of just one state, 12% are registered in two states, 5% are 

registered in three states, and 0.9% are registered in four states (PJM-GATS 2011b). Table 9

shows the number and aggregate capacity of PV systems registered for use in PJM-GATS 

states, as well as Massachusetts and North Carolina.9

Table 9. In-State Versus Out-of-State Project Registration as of October 2011

State Registration Number of 

Projects

Capacity 

(MWDC)

DC In State 371 2.2

Potential Imports 1,961 18.1

Potential Exports 137 0.8

DE In State 889 22.7

Potential Imports 0 0.0

Potential Exports 655 7.4

MA In State 1,015 41.1

Potential Imports N/A N/A

Potential Exports N/A N/A

MD In State 1,748 30.9

Potential Imports 778 21.2

Potential Exports 251 11.8

NJ In State 10,170 417.0

Potential Imports N/A N/A

Potential Exports 35 5.7

NC In State 125 63.3

Potential Imports 80 41.2

Potential Exports 75 1.7

OH In State 417 27.5

Potential Imports 2,752 57.9

Potential Exports 144 1.3

PA In State 4,873 110.7

Potential Imports 1,503 37.7

Potential Exports 2,683 58.6

Sources: PJM-GATS 2011b; Massachusetts DOER 2011b

Note: “In state” refers to projects located within a particular state and registered only in that state. “Potential 

imports” refers to projects located in other states that are registered for potential use in the specified state. 

“Potential exports” refers to projects in the specified state that are registered for potential use to meet compliance 

obligations in other states. The majority of these potential export facilities are also registered in the state where 

they are located. As of August 1, 2011, the potential imports to Washington, D.C., decreased as a result of the 

District’s decision to limit out-of-state generation.

 8 Typically projects are certified by state agencies for compliance and then registered in PJM-GATS. Registered 

generators are all generating units that have an account with the GATS administrator. The facilities in the 

GATS database are operational. 

9 No PV systems are registered yet in Missouri’s chosen tracking system, NARR. The first compliance year in 

Missouri is 2011.
23

Two states—New Jersey and Massachusetts—source all of their SRECs from in-state 

resources as required by state law. In another approach, Maryland regulations required

electricity suppliers to seek SRECs first from generators on the Maryland distribution grid, 

meaning that suppliers could only procure SRECs from out of state if there were no available 

in-state resources. In 2010, Maryland electricity suppliers sourced 63% of the total SRECs 

retired from in-state generators, with about another quarter from Illinois, a state without a 

SREC market or solar carve out (see Figure 6a). In 2012, a binding in-state requirement goes 

into effect in Maryland (DSIRE 2011b).

In other markets, the source of SRECs retired for compliance requirements is more diverse. 

Washington, D.C.-based solar generators only provided 13% of SRECs retired to meet the 

D.C. standard in 2010. SRECs used for compliance in Washington, D.C., have come from 14 

other states, including a number of states without SREC markets or solar carve outs, such as

Virginia (see Figure 6b). In Washington, D.C., external facilities are five times more 

numerous than facilities located within the District (see Table 9). Although Washington,

D.C.’s previous law stated a preference for in-district resources, its newly adopted law 

(August 2011) has a more stringent local requirement, starting in 2011. Out-of-state projects 

certified for the RPS program by January 31, 2011, will be eligible to continue to sell into the 

Washington, D.C., market.

While Pennsylvania has a substantial amount of registered in-state facilities, only about onethird of SRECs supplying Pennsylvania’s solar requirement were sourced from in-state 

facilities in 2010. The remainder was sourced from six other states, with the largest 

contributors being Delaware (41%) and Illinois (25%) (see Figure 7a). A small fraction of 

SRECs have been retired from systems located in a variety of states within PJM to meet the 

Pennsylvania solar standard (see Figure 7a). Pennsylvania systems are also being retired for 

compliance with requirements in Washington, D.C., and Ohio. 

Despite the 50% in-state requirement in Ohio, only 35% of SRECs retired in 2010 were 

sourced from Ohio (see Figure 7b). This may be the case because Ohio utilities and 

competitive providers did not achieve full compliance with the unadjusted solar carve outs in 

2010; several entities successfully petitioned to have their 2010 targets adjusted downward, 

with any shortfall to be made up in 2011 (Siegfried 2011). In Ohio, there are about six times 

as many out-of-state facilities registered (see Table 9). Pennsylvania contributed 63% of the 

total SRECs retired to date for compliance with the Ohio solar target. 
24

Figure 6. (a) Source of SRECs retired for 2010 compliance in Maryland (b) Source of SRECs 

retired for 2010 compliance in Washington, D.C.

Source: PJM-GATS 2011a

(a) Other includes: DE, IN, NY, OH, PA, VA, WV (b) Other includes: IL, IN, KY, MI, NJ, OH, WI, WV

Figure 7. (a) Source of SRECs retired for 2010 compliance in Pennsylvania (b) Source of 

SRECs retired for 2010 compliance in Ohio

Source: PJM-GATS 2011a

(a) Other includes: MD, VA, WV

In North Carolina, the utilities are sourcing SRECs from both out-of-state projects, which are 

limited to 25% of the standard, as well as from in-state sources. Duke Energy Carolinas 

maintains a diverse solar portfolio, including: Duke-owned PV installations (at its central 

sites and at distributed sites10), credits purchased from out-of-state suppliers (which can be 

used for up to 25% of compliance requirements), credits purchased from in-state PV and 

 10 Under the Duke Energy PV DG Program, Duke has secured 25 sites and installed roughly 9.9 MWDC

(estimated to generate 13,485 MWh annually) (Duke Energy 2011c).

MD

63%

IL

27%

NC

5%

DC

3%

Other

2% (a)

DC

13%

PA

29%

VA

26%

NC

9%

MD

6%

NY

4%

DE

4% Other

9%

(b)

PA

32%

DE

41%

IL

25%

NJ

1%

Other

1%

(a)

OH

35%

PA

63%

KY

0.7%

IN

0.4%

WV

0.2%

(b)

63% In-State 13% In-State

32% In-State 35% In-State
25

solar thermal projects, and credits purchased from a standard offer contract program 

available to the residential and commercial sectors (Duke Energy 2011b). Similarly, Progress 

Energy Carolinas purchases SRECs from in-state and out-of-state generators, as well as 

through the utility’s standard offer contract program (Progress Energy Carolinas 2011a).

In Missouri, the three investor-owned utilities (IOUs) plan to procure most of their SRECs 

from solar projects in the West that were registered in WREGIS, according to plans filed in 

2011 (Ameren 2011b; KCP&L 2011; KCP&L-GMO 2011). Additionally, Ameren plans to 

source some SRECs both from a 100 kW installation on their company headquarters and 

some through entering into standard offer contracts with residential and commercial 

customers (Ameren 2011b). For the 2011–2013 planning period, Ameren Missouri plans to 

procure SRECs from out-of-state sources, through a continuation of their standard offer 

program, potentially through utility-scale installations at several of its existing generating 

facilities and through unsolicited proposals from solar developers (Ameren 2011b). The other 

two utilities plan to continue to meet the solar requirement by purchasing SRECs from outof-state projects through brokers due to price considerations and uncertainty regarding the 

solar carve out and RPS (KCP&L 2011; KCP&L-GMO 2011).

3.3 Size of Systems Supplying SRECs

SREC Markets are Supporting a Mix of PV System Sizes; Large Systems are Increasingly 

Common

Policymakers may be interested in ensuring that SREC markets support a mix of system sizes 

in order to: (1) increase the supply of decentralized, local power generation at customer sites; 

(2) establish support for a variety of contractors, installers, and developers; and/or (3) ensure 

that a variety of customer types benefit from ratepayer-funded programs. These goals may 

also be balanced with an interest in achieving solar targets at least cost. 

To date, most markets are supporting a mix of residential and mid- to large-sized commercial 

PV systems, but large systems are increasingly dominating capacity in some markets (see

Figure 8). In all markets except North Carolina, approximately two-thirds or more of the total 

number of registered projects are smaller than 10 kW (see Figure 8), with mid-sized (10 kW 

to 250 kW) projects generally contributing substantially to the total project number. In North 

Carolina, about 15% of registered projects are smaller than 10 kW, nearly 50% are midsized, and the remainder is large projects that are greater than 250 kW in size. 
26

Figure 8. Number of PV projects by size and jurisdiction

Sources: Project registration data. PJM-GATS 2011b; Massachusetts DOER 2011b; N.C. Utility Commission 

2011a

Figure 9 shows the relative contribution of small (<10 kW), mid-sized (10 kW to <250 kW), 

and large systems (>250 kW) to total registered solar capacity. Large projects currently 

dominate registered capacity in a few markets—most notably, North Carolina, 

Massachusetts, and New Jersey. For example, although nearly 75% of the 8,800 projects in 

New Jersey are smaller than 10 kW, they represent 12% of the aggregate capacity. In North 

Carolina, projects greater than 250 kW represent more than 90% of the aggregate capacity, 

while small projects account for less than 1%.

Figure 9. Aggregate capacity (in MW) of registered PV projects by size and jurisdiction

Sources: PJM-GATS 2011b; Massachusetts DOER 2011b; NCUC 2011a

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

DE DC MD MA NJ NC OH PA

Number of Systems

Small (<10 kW) Medium (>10 kW, <250 kW) Large (>250 kW)

0.0

50.0

100.0

150.0

200.0

250.0

300.0

350.0

400.0

DE DC MD MA NJ NC OH PA

Capacity of All Registered Projects (MW)

Small (<10 kW) Medium (>10 kW, <250 kW) Large (>250 kW)
27 

Small residential and commercial systems may inherently face additional barriers in SREC 

markets. Small systems may not be as economic as larger systems due to the lack of 

efficiencies of scale, although this may be offset by the fact that residential systems displace 

higher retail electricity rates. Consumers may have a difficult time finding buyers for their 

SRECs; buyers are often interested in purchasing large quantities at once to minimize 

transaction costs. In addition, small consumers may not be able to access complex incentive 

programs, where they are required to bid into a competitive process. Lastly, small system 

owners may not want to take on the risk of uncertain future SREC revenues. 

Available data suggest that these challenges have not prohibited the development of small 

systems in most states to date, however. In most markets, SREC aggregators are helping 

small residential and small commercial projects sell their SRECs. For example, in 

Massachusetts, 99.8% of small-sized projects and 91% of mid-sized projects were part of an 

aggregation, as of July 2011 (Massachusetts DOER 2011b). In the rest of PJM, 55% of small 

systems and 40% of mid-sized projects participate in aggregations (Bowery 2011). Often 

utilities have used standard offers, auctions, and solicitations to help encourage development 

of projects in various size categories. Under these programs, utilities purchase the SRECs 

under long-term contracts, which provide a stable incentive for system owners. In Missouri, 

North Carolina, and Ohio, regulated utilities have created standard offer programs for their 

retail customers who are interested in installing behind-the-meter systems on their homes or 

businesses (see text box in Section 2.6). 

Additionally, separate from standard offer programs, other LSEs have solicited long-term

SREC contracts from developers of both small and large projects through competitive 

solicitations and auctions. Since most LSEs in an unregulated market do not want to sign a 

contract beyond the scope of their demand requirement, competitive solicitation and auction 

programs have been an important way for independent power producers to obtain long-term 

contracts. The New Jersey SREC-Based Financing Program (see Appendix) solicits 

SRECs from projects up to 2 MWDC in size. The program has a small project size segment 

(<50 kW) and a large project size segment (50–2,000 kW). Also, Pennsylvania utility PPL

Electric Utilities has chosen to procure SRECs from projects <10 kW through a “Small Scale 

Solar Set-Aside” RFP targeted at SREC aggregators (Appendix). These programs have 

been important for encouraging a mix of system sizes in these states.

System size has been trending larger in recent years. There has been a steady increase in the 

number of PV projects larger than 250 kW. The number of systems greater than 250 kW has 

grown cumulatively from just two in 2003 to nearly 400 through the first half of 2011. Since 

2008, the average size of projects in this class has been greater than 600 kW. As expected, 

the average has been skewed by the installation of some large utility-scale projects in recent 

years. For example, as shown in Figure 10, the average size of this class of projects was 

1.1 MW in 2009, which is much higher than previous years due to the completion of several 

utility-scale projects.
28

Figure 10. Number and average size of facilities >250 kW installed annually in PJM-GATS

Source: PJM-GATS 2011b

Utility-scale PV projects >1 MW have played an increasingly larger role in the markets in 

recent years. New Jersey leads in utility-scale solar deployment with 51 solar projects 

>1 MW operational as of August 2011 (PJM-GATS 2011b). North Carolina currently has 22 

in-state generators >1 MW completed (NCUC 2011a). Massachusetts has three operational 

PV generators >1 MW (Massachusetts DOER 2011b), and Delaware is home to a 10 MW 

solar park commissioned this year (SEIA 2011).

A number of large projects are planned over the next few years. In aggregate, these planned 

projects could result an estimated 400 MW of new PV deployment. There is variation in 

estimates of planned capacity and some projects may not come to fruition, but these data are 

indicative. Figure 11 shows the aggregate capacity of PV projects completed versus planned

as of September 2011.

0

0.2

0.4

0.6

0.8

1

1.2

0

20

40

60

80

100

120

140

160

2003 2004 2005 2006 2007 2008 2009 2010 First 

Half 

2011

Number of Projects

Average Size (MW)

Number of Projects > 250kW Average System Size
29

Figure 11. Aggregate capacity of utility scale (>1 MW) PV projects (completed and under 

development)

Sources: PJM-GATS 2011a; Massachusetts DOER 2011b; NCUC 2011a; SEIA 2011; SEPA 2011; NJ BPU 

2011c

Note: The New Jersey estimate for projects under development is derived from the list of projects that have 

registered with the NJ BPU under the SRP program prior to construction but have not yet been completed. 

Large projects can help states achieve compliance more quickly. However, they may flood 

the market with excess credits, which could reduce SREC prices, potentially to levels that 

could no longer provide adequate incentives for small PV systems. In Ohio, two utility-scale 

PV facilities are planned for the near term. Together, if completed, the 12-MW Wyandot 

Solar Facility and the 50-MW Turning Point facility would produce an estimated 24% of the 

total Ohio SREC requirement in 2013, according to an estimate by SRECTrade (SRECTrade 

2011b).

Two main mechanisms are used by states to limit the impact of large systems on the market. 

The first mechanism is to place a cap on the size of systems eligible to sell SRECs—2 of the 

10 jurisdictions currently have such a cap. In Massachusetts, solar generators must be smaller 

than 6 MWDC in order to generate SRECs. Washington, D.C., adopted legislation effective 

August 1, 2011, which caps systems eligible to generate SRECs at 5 MW. Pennsylvania has

considered capping system size. Before 2010, New Jersey had a 2-MW DC cap, which was 

lifted to help keep pace with aggressive solar growth targets.

11 The other mechanism is to 

establish separate standards for customer-sited and large-scale systems. For example, 

Colorado (which does not have a tradable SREC market) requires half of the solar carve out

to come from customer-sited systems (DSIRE 2011a).

 11 New Jersey has no specific limits, but systems must be connected to the distribution grid, and behind-themeter projects must be sized so that annual output does not exceed annual on-site load (DSIRE 2011d).

0 50 100 150 200 250 300

MA

MD

NC

OH

PA

NJ

DE

DC

Aggregate Capacity (MW)

Completed Under Development
30

3.4 SREC Prices

New Jersey has Historically Experienced the Highest Prices; Recent or Forward Prices 

Have Dropped Significantly in Most Markets

SREC prices tend to track the supply and demand in the state or regional market. Spot 

pricing for SRECs is publically available from platforms like SRECTrade and 

FlettExchange.12 SRECTrade hosts a monthly auction, while Flett Exchange is an online 

exchange. Both platforms cover markets in PJM states, Massachusetts, and Ohio, and similar 

price trends can be seen in reported data from both companies. Figure 12 shows SREC prices 

for the current or nearest compliance year. 

Historically, SRECs from New Jersey have seen the highest prices, ranging from $400/MWh

to approximately $650/MWh in recent years, while SRECs from most other states have

ranged from $200/MWh to $500/MWh (Figure 12). However, in 2011, SREC prices fell, 

sometimes dramatically, in all markets except for in-state Massachusetts and Ohio. In New 

Jersey, spot prices fell from between $600/MWh and $700/MWh in 2009 and 2010 to less 

than $200/MWh in September 2011 (Figure 12). 

Figure 12. SREC spot prices (per MWh), August 2009 to September 2011

Source: SRECTrade 2011c

Long-term contract prices can differ substantially from spot prices. Solicitations held by 

EDCs in New Jersey for procuring SRECs in 10- or 15-year contracts have resulted in SREC 

prices lower than spot prices in 2009 and 2010. In February 2011 and June 2011, average 

 12 PJM-GATS reports solar weighted average prices for transactions in the PJM market (see PJM-GATS 2011c) 

that differ from spot prices reported by SRECTrade and Flett Exchange because PJM-GATS pricing can include 

pricing from long- or mid-term contracts as well as spot prices. PJM-GATS reports prices on a monthly basis, 

based on when the SREC was issued, traded, or retired, not on when the generation occurred (PJM-GATS 

2011c). Recently, due the decline in spot pricing, PJM-GATS has reported higher solar weighted average 

prices than the spot prices reported by SRECTrade and Flett Exchange. For example, if a company contracted 

for SRECs that were generated in January 2010 at a given price but did not retire those SRECs until August of 

2011, the January 2010 price would be reflected in PJM-GATS’s August 2011 solar weighted average price 

report.

$- 

$100 

$200 

$300 

$400 

$500 

$600 

$700 

Aug-09

Oct-09

Dec-09

Feb-10

Apr-10

Jun-10

Aug-10

Oct-10

Dec-10

Feb-11

Apr-11

Jun-11

Aug-11

Auction Price Per SREC

NJ

PA

MD

DC

DE

MA

OH Instate

OH OutState
31

10-year SREC contract prices ranged from $280/MWh to $448/MWh, depending on the 

project size and timing of the solicitation (Table 10).

Table 10. New Jersey EDC Solicitation 10-Year Contract Pricing, 2011

RPS Reporting Year 

2011

Solicitation 6 Solicitation 7

Small MidSized Large Small MidSized Large

Date bids submitted 2/17/11 2/17/11 2/17/11 6/10/11 6/10/11 6/10/11

Number of bids submit 

(participation) 86 78 27 83 115 29

Contracts awarded 59 35 12 35 19 9

Total capacity awarded 

(kW) 778 7,557 8,231 693 9,170 9,512

Average size (kW) 13 216 686 20 483 1,057

Average Net Present 

Value for contracts 

($/kW)

$3,166* $2,926 $2,683 $2,145 $1,983

Corresponding 10-yr 

renewable energy 

credit contract price 

($/MWh)

$448* $414 $379 $303 $280

Lowest Net Present 

Value ($/kW) $2,819* $2,424 $2,248 $1,759 $1,774

Corresponding 10-yr 

renewable energy 

credit contract price 

($/MWh)

$399* $343 $318 $249 $251

*In earlier solicitations, small and mid-sized projects were not solicited separately. The BPU’s Solicitation 6 report 

does not distinguish between average SREC price for small and mid-sized projects.

Source: NJ BPU 2011a; NJ BPU 2011b

In Pennsylvania, SREC spot prices dropped to less than $50/MWh in September 2011 from 

approximately $300/MWh in mid-2010 (FlettExchange 2011), presumably due to oversupply 

in the market. Long-term (8.5 to 10.0 years) SREC contracts held by EDCs in Pennsylvania 

have seen prices ranging from $149/MWh to $286/MWh, as evidenced by prices from 

contracts solicited in February, May, and June 2011 (Table 11).

Table 11. Pennsylvania EDC Solicitation Contract Pricing, 2010–2011

EDC Date of 

Solicitation(s)

Delivery 

Period

Total SREC 

Volume

Average 

Price/ SREC

Met-Ed/Penelec Feb & June 

2010

10 years Feb: 10,000, 

June: 15,000

$286/MWh

Penn Power Feb 2011 9 years 19,800 $199/MWh

PPL Electric May 2011 8.5 years 25,500 $149/MWh

PPL Electric June 2011 9 years 1,000 $149/MWh*

Sources: First Energy Corporation 2011a; First Energy Corporation 2011b; PPL Electric 2011a; PPL Electric 

2011b

*Pricing was determined by the results of the May 2011 solicitation
32

In Washington, D.C., prices have declined as SRECs from other states have saturated the 

D.C. market. In 2010, SREC spot prices were closing between $200/MWh and $300/MWh, 

whereas in mid-2011, SREC spot prices dropped to between $50/MWh and $80/MWh. The 

Council of the District of Columbia addressed these issues by closing the door to most new 

out-of-district resources (current out-of-district resources will be grandfathered in) and 

increasing the ultimate solar requirement from 0.4% to 2.5% by 2023. 

3.5 Compliance in SREC Markets

Compliance has Proved Challenging in Some SREC Markets, but Improved Compliance is 

Expected in Some Markets as Indicated by Price Drops and Installation Trends

The relatively high SREC prices in recent years, in many cases near the levels of solar ACPs, 

reflect the fact that some states have struggled with solar carve out compliance. However, the 

substantial drop in forward prices of SRECs in most states indicates that compliance 

challenges are dissipating and that markets may be oversupplied in some instances. 

The largest shortfalls historically have been seen in New Jersey, which has by far the largest 

requirement. New Jersey experienced a large shortfall in 2009, with utilities paying about

$39 million in solar ACPs (Figure 13). In 2010, the shortfall was slightly less, though still 

substantial, at $33 million. Recently, solar installations in New Jersey have surged, indicating 

that New Jersey will see fewer shortages in upcoming compliance periods. 

Figure 13. New Jersey solar carve out compliance

Note: RY stands for reporting year. 

Maryland, Ohio, and Washington, D.C., have experienced shortages in SREC compliance in 

recent years, though compliance is looking more likely for 2010 and 2011 based on price 

trends in these markets. In Washington, D.C., future compliance is more difficult to predict, 

given the recent change in the compliance requirement. Table 12 shows compliance 

shortages and solar ACP payments in states with SREC targets in 2009 or earlier. In 

Pennsylvania, compliance has been nearly 100%, with one supplier choosing to pay the ACP 

$0 

$5,000,000 

$10,000,000 

$15,000,000 

$20,000,000 

$25,000,000 

$30,000,000 

$35,000,000 

$40,000,000 

$45,000,000 

- 

20,000 

40,000 

60,000 

80,000 

100,000 

120,000 

140,000 

160,000 

180,000 

RY 2005 RY 2006 RY 2007 RY 2008 RY 2009 RY 2010

Total ACP

SRECs (MWh)

SREC obligation (MWh)

SREC shortage (MWh)

Total ACP ($)
33

for two SRECs in 2008. Shortages are unlikely in the future due to the pace of installations in 

the state. 

Table 12. State Solar Carve Out Compliance, 2007–2009

2007 2008 2009

SRECs 

required 

(MWh)

SREC 

shortage 

(MWh)

Total 

solar 

ACP 

($1,000)

SRECs 

required 

(MWh)

SREC 

shortage 

(MWh)

Total solar 

ACP 

($1,000)

SRECs 

required 

(MWh)

SREC 

shortage 

(MWh)

Total solar 

ACP 

($1,000)

DC N/A N/A N/A 900 146 $36 1,091 65 $18

DE 592 592 $178 1,225 1,225 $377 2,235 851 $426

MD N/A N/A N/A 2,934 2,707 $1,218 6,125 2,865 $1,147

OH N/A N/A N/A N/A N/A N/A 3,955 2,858* None**

PA 26 0 0 348 2 Not 

reported

1,221 - None

*The total number of SRECs retired in Ohio is unknown because compliance reports by Competitive Retail 

Electric Service are deemed confidential. The figures here represent only the publicly available information 

provided by Ohio’s Electric Distribution Utilities. The Ohio PUC estimated that 5,598 SRECs would be required in 

2009 for the entire market.

**The Ohio PUC approved force majeure petitions by utilities, did not assess financial penalties, and added 2009 

shortages to the 2010 obligation.

Note: Massachusetts and North Carolina began compliance in 2010. Missouri does not have a compliance 

obligation until 2011.

Maryland experienced shortfalls in 2008 and 2009, which was largely due to a shortage in 

supply. The 2008 Maryland SREC requirement was approximately 3,000, but only 276 

SRECs were generated in 2008. Similarly, approximately 6,000 SRECs were needed to meet 

Maryland’s 2009 requirement, but only 3,495 were generated. In 2008, Maryland utilities 

were short by 2,707 MWh and paid approximately $1,218,000 in solar ACPs. The shortage 

continued in 2009 when Maryland utilities were short by 2,865 MWh and paid $1,147,000 in 

solar ACPs.

In Washington, D.C., utilities did not submit any SRECs for compliance in 2007 or 2008.

This resulted in shortages of 592 MWh in 2007 and 1,255 MWh in 2008, requiring solar 

ACPs totaling $178,000 and $377,000, respectively. In 2009, utilities continued to be short, 

this time by 851 MWh, resulting in $426,000 in solar ACPs.

In Ohio, utilities and competitive suppliers were unable to meet the in-state solar carve out

requirement in 2009 but successfully petitioned to have the in-state solar requirement 

reduced for that year due to force majeure. In Ohio, the RPS includes a force majeure

provision that enables obligated entities to request commission action in the event of an 

unforeseen circumstance outside of their control. In Ohio, utilities and competitive providers 

have stated that they made efforts to secure in-state solar SRECs but were not able to obtain 

enough SRECs through that process. FirstEnergy, the parent company of three Ohio utilities, 

also offered a residential SREC purchase program but was only able to procure 13 SRECs 

through the program in 2009 (Ohio Edison Company et al. 2010). Preliminary compliance 

reports have been issued in Ohio, while some utilities and competitive providers filed for 
34

force majeure in 2009. In 2010, most of the filers for force majeure were competitive 

providers and represented smaller volumes than 2009 (Siegfried 2011).

New Hampshire’s first compliance year for its solar carve out was 2010. In 2010, entities 

paid $58,884 in ACPs (NH PUC 2011). At a solar ACP level of $160/MWh for 2010, the 

payment represents a shortage of 368 SRECs, or 8% of the total obligation of 4,255 SRECs 

(Epsen 2011).

Data from Massachusetts, Missouri, and North Carolina are not yet available because North 

Carolina and Massachusetts began compliance in 2010, and Missouri’s first compliance year 

is 2011. Preliminary data indicate that a large shortage exists in Massachusetts (which had its 

first compliance year in 2010). Data from NEPOOL GIS indicate that only 2,738 MWh of 

qualifying Massachusetts solar were issued in 2010, compared to a requirement of 

approximately 34,000 MWh (Massachusetts DOER 2011c). The gap between installations 

and the requirement helps explain why Massachusetts SREC prices have not fallen as they 

have in other state markets.

Missouri’s first compliance year is 2011 but is not expected to see shortages due to the ability 

of utilities to obtain SRECs from the national market. Similarly, in North Carolina, which 

had its first compliance year in 2010, utilities are expected to meet their solar requirements. 

SRECs can be banked for an unlimited amount of time in North Carolina and 25% of the 

SRECs can be procured nationally. One large IOU, Duke Energy, projects that it has 

contracts in place for a sufficient number of SRECs to meet its solar requirements through 

2018 (NCUC 2011b). 
35

4 Future Outlook

Looking forward, SREC markets are expected to continue to expand as state solar 

requirements ramp up over time from more than 520 MWAC in 2011 to approximately

2,000 MWAC by 2015 and 4,300 MWAC by 2020. 

While several states struggled to achieve compliance recently, some markets show signs of 

improvement. A sharp drop in SREC prices in several states indicates that the markets may 

be oversupplied and on track to achieve near-term compliance targets. For example, energy 

year 2012 SREC spot pricing in New Jersey is at about $150/MWh compared to energy year 

2011 spot market prices of more than $600/MWh. SREC prices have also eased in 

Pennsylvania. Other markets, such as Massachusetts, may continue to face shortages in the 

near term as its standard ramps up. 

Substantial increases in installed capacity have been fueled by a 30% drop in module prices 

in the last year as well as slower growth in international markets that have placed greater 

emphasis on U.S. markets. While module prices declined from $2.21/W in the first quarter

(Q1) of 2010 to $1.56/W, in Q2 2011, installed costs have not fully reflected these cost 

reductions yet, particularly in the residential market segment (SEIA GTM 2011a; SEIA GTM

2011b). Solar Energy Industries Association and Greentech Media report an approximate 

$0.50/W drop in residential installed PV costs nationally from the beginning of 2010 through 

Q2 2011 and more than $1.15/W drop in non-residential installed costs nationally over the 

same period (see Figure 14). Going forward, module cost reductions are likely to contribute 

to additional drops in installed costs. Given the drop in SREC prices in a number of markets, 

there will be increased pressure to drop installation prices to offset reduced revenue streams 

(SEIA GTM 2011b).

Figure 14. Average PV installed price Q1 2010 through Q2 2011

Sources: SEIA GTM 2011a; SEIA GTM 2011b

$4.00 

$4.50 

$5.00 

$5.50 

$6.00 

$6.50 

$7.00 

$7.50 

Q1 

2010

Q2 

2010

Q3 

2010

Q4 

2010

Q1 

2011

Q2 

2011

Average PV Installed Price per 

Watt 

Weighted 

Average 

(National)-

Res.

Weighted 

Average 

(National)-

Non-res.
36

The current pace of project development is also influenced by the rapidly approaching 

expiration date of the Federal Treasury 1603 cash grant program, currently set to expire at the 

end of 2011. For projects to be eligible for the cash grants, they must meet safe harbor rules 

for commencing construction before the end of 2011, although completion is not required 

until 2016. Once the cash grant program expires, large projects in particular may require tax 

equity investors in order for the project to monetize the investment tax credit. The rate of 

development going forward will be influenced by the availability of tax equity and whether it 

will keep up with project demand. Also, the elimination of the cash grants may mean that 

developers place even greater emphasis on long-term contracts for SRECs to obtain debt 

financing for projects; thus, the continued availability of long-term contracting provisions or 

price floors will continue to be important.

Going forward, the increase in utility-scale PV projects may impact the supply and demand 

balance in state SREC markets, particularly those with relatively small carve outs. Large 

projects have the potential to achieve significant portions of the solar targets, which could 

result in rapid reductions in SREC prices. These effects may be particularly prevalent in 

some markets where large-scale projects have been planned, such as New Jersey, Ohio, and 

Maryland.

In New Jersey, the substantial uptick in installations in 2010 and the first half of 2011 are 

expected to keep the market in oversupply in the near term. Figure 15 shows the monthly 

trends in PV capacity installations in New Jersey. SRECTrade estimates that the average 

capacity required to meet the 2012 target is 370 MW, meaning that over the 2012 energy 

year, an average of 370 MW would need to be operating (SRECTrade 2011d). As of August 

31, 2011, New Jersey had 430 MW installed (NJ OCE 2011). In addition to the current 

capacity expansion, the number of projects registered in New Jersey increased from just over 

900 approved registrations at the end of August 2010 to over 3,700 approved projects by the 

end of July 2011 (representing over 430 MW) (NJ BPU 2011c).13 While not all of these 

projects will ultimately be built, the backlog in registrations indicates that there is a potential 

for oversupply going forward in the New Jersey SREC market. As a result of recent 

installations and the existing project queue, industry analysts expect that the New Jersey 

market will be oversupplied through 2012 but may pick up again in 2013 (SEIA GTM 

2011b).

Maryland had 42 MW installed at the end of Q2 2011 and 10.8 MW installed in the first half 

of 2011 alone, which industry analysts attribute to the newly available residential solar lease 

(SEIA GTM 2011b). Residential solar rebates are also available from the state. At least two 

large projects (>15 MW) are expected to begin commercial operation in Maryland in 2012, 

which would also play a substantial role in helping the state meet its compliance targets. 

However, it is unclear how the Maryland market will react when it is closed to out-of-state 

SRECs in 2012, but this will provide a boost for in-state projects. 

In Pennsylvania, installations remained strong in the first half of 2011 due to significant 

project backlogs, despite an earlier drop in SREC prices. As of the first half of 2011, 

105 MW had been installed, which is well ahead of current targets (SEIA GTM 2011b). 

 13 These figures do not include completed projects.
37 

Declining PV installation costs may have played a role in the uptick in installations; from 

Q2 2010 to Q2 2011, residential installation prices in Pennsylvania have declined from 

$7.13/W to $5.94/W, and non-residential installation prices have decreased over the same 

period from $6.23/W to $5.17/W (SEIA GTM 2011b). The market is expected to slow in the 

near term but could recover in 2013, perhaps in part to serve markets such as Illinois (SEIA 

GTM 2011b). 

Figure 15. Capacity installed by month in New Jersey

Source: PJM-GATS 2011b

Recent legislative changes will have an impact on markets going forward. While most recent 

changes have resulted in stronger SREC targets, the uncertainty created by evolving policies 

can be a barrier to project development. Policymakers in Washington, D.C., and Connecticut 

have strengthened solar polices, while Massachusetts faced some criticism by solar 

developers for decreasing the solar ACP. In August 2011, Washington, D.C., policymakers 

expanded the solar requirement from 0.4% by 2020 to 2.5% by 2023 and specified that it be 

met by systems no larger than 5 MW and generally sited within D.C. In Connecticut, 

legislation (Bill 1243) was recently adopted requiring distribution companies to procure 

RECs from facilities <1 MW, spending $8 million in the first year and increasing by that 

same amount annually to $32 million in the fourth year. The companies must solicit 15-year 

contracts from small, mid-sized, and large facilities up to 1 MW. Finally, Massachusetts 

recently lowered its solar ACP from $600/MWh to $550/MWh and has proposed a long-term 

schedule reducing solar ACPs by 5% annually from 2013 to 2021, which helps provide 

certainty to the market for forward pricing.

Other state legislatures have recently considered bills to expand state solar carve outs, 

although none of these provisions have passed to date. In New Jersey, the Senate passed 

S2371, which would increase the SREC requirement in 2013 from 596 GWh to 772 GWh 

(the current 2014 requirement), with each subsequent annual requirement moving forward 

one year. In Pennsylvania, amendments (HB 1580) to the original RPS Act were introduced 

that would restrict solar eligibility to in-state resources and would increase the requirements 

for 2013–2015 compliance years from approximately 70 MW in 2013 to 207 MW in 2015 

(SRECTrade 2011e). The New York legislature considered a bill this year to establish a solar 

carve out with an initial compliance requirement of 0.15% in 2012. 

0

5

10

15

20

25

30

35

40

45

Jan-05

May-05

Sep-05

Jan-06

May-06

Sep-06

Jan-07

May-07

Sep-07

Jan-08

May-08

Sep-08

Jan-09

May-09

Sep-09

Jan-10

May-10

Sep-10

Jan-11

May-11

Capacity (MW)
38

5 Summary and Conclusions

SREC markets have been implemented by a number of states to help encourage the 

development of solar energy systems and to facilitate compliance with state RPS solar carve 

outs. These markets are relatively new with some markets just beginning to operate while 

others have had several years of implementation experience. This report documents early 

experience with the design and implementation of SRECs markets. The key findings of this 

report are the following: 

• SREC markets are expected to grow rapidly in coming years as state solar 

requirements ramp up. Of the 10 jurisdictions that allow and anticipate the use of 

SREC trading, the solar carve outs are scheduled to grow from more than 520 

MWAC in 2011 to nearly 7,300 MWAC in 2025. Targets for solar generation vary 

from 0.2% to 3.5% of retail electric sales. SREC markets are dominated by PV, 

although solar thermal is eligible to meet solar requirements in a number of states. 

• Several states limit eligibility to in-state development, while a few allow SRECs 

from a broader geographic region. Two jurisdictions—Washington, D.C., and 

Maryland—recently strengthened their in-state requirements, which will affect 

future development. A small national market for SRECs has resulted from solar 

requirements in North Carolina and Missouri that allow SRECs to be sourced 

from anywhere in the United States.

• Solar ACPs are scheduled to decline over time reflecting expectations of 

declining PV costs. Solar ACPs can be significant because they reflect the ceiling 

on SREC prices, and in shortage situations, SRECs typically trade near the solar 

ACP. New Jersey has had the highest solar ACP initially set at $700/MWh, but it 

is scheduled to be reduced to $600/MWh by 2015. Other state solar ACPs are 

scheduled to range from $300–$500/MWh by 2015. 

• New Jersey has been the dominant SREC market to date, but SREC markets in 

other states are expanding. New Jersey has dominated because it has the earliest 

and largest solar requirement (more than four times larger than any other state). 

Additionally, the high New Jersey solar ACP has driven SREC prices to be the 

highest in the nation in recent years. However, SREC requirements in other states 

are growing, and projects are being implemented in a broader region. Voluntary 

markets for SRECs have been very limited given the substantial price differential 

between SRECs and RECs sourced from other technologies. 

• SREC spot prices have eased recently in a number of markets as installations

have surged and compliance challenges have eased. SREC prices have ranged 

from about $400–$650/MWh in New Jersey and about $200–$500/MWh in other 

states in recent years. In August 2011, spot prices for energy year 2012 SRECs in 

New Jersey dropped to $150/MWh compared to $500/MWh in May 2011. 

Pennsylvania energy year 2011 spot prices fell to about $50/MWh in August 2011 

as a result of oversupply in the market. Similarly, in Washington, D.C., SREC 

spot prices dropped to $50–$80/MWh in summer 2011 from $200–$300/MWh in 

2010 because out-of-district SRECs were allowed. In response, Washington, 
39

D.C., adopted legislation generally restricting eligibility to in-district systems and 

expanded the solar targets substantially to reduce excess supply. A number of 

other states have introduced legislation that would expand the markets, but to 

date, no other legislation has passed.

• SREC markets are supporting a mix of PV system sizes, including residential 

and small to large commercial systems. In most markets, about two-thirds of 

registered projects are <10 kW. Projects >250 kW dominate capacity installed in a 

few markets, including North Carolina, Massachusetts, and New Jersey. There has 

been a trend toward large-sized projects recently, with the average size system in 

PJM exceeding 750 kW in the last few years. 

• Installation of large systems could significantly impact compliance levels and 

prices. Large projects planned for New Jersey, Ohio, Maryland, and perhaps other 

states could impact prices and compliance levels. Only Massachusetts and

Washington, D.C., currently cap the size of systems that can generate SRECs. 

• Compliance has proved challenging in a number of SREC markets in recent 

years, but adequate supplies are expected going forward in many of these 

regions. A handful of states reported compliance shortfalls in 2009. The first 

compliance periods for a few markets occurred in 2010 or 2011. However, 

compliance challenges have eased in a number of markets recently, as evidenced 

by substantial declines in SREC prices. Surges in the rates of installations in New 

Jersey and Pennsylvania in particular have placed those states ahead of targets. 

• Lack of long-term contracts has been a barrier to project developers obtaining 

financing in some markets. Several states have instituted long-term contracting 

requirements, price floors, or other provisions to try to overcome these challenges. 

The New Jersey program in particular has led to a greater number of long-term 

contracts, which has facilitated project development. However, the drop in SREC 

prices may mean that ratepayers must make up the difference between spot and 

contract prices. The price floor mechanism in Massachusetts has not been fully 

tested, but investors appear to be gaining comfort with this mechanism. The need 

for long-term contracting may continue to pose a problem, particularly in areas 

where rebates or other supplemental incentives expire and SRECs become the 

primary incentive stream for financing systems.

• Rate caps exist in some form in five SREC markets but have not been reached 

or are yet to be evaluated. The modest size of most solar carve outs suggests that 

it is not likely that rate caps will be reached in the near term. 
40

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47 

Appendix 

Long-Term Contracting Provisions: SREC Auctions in New Jersey

In 2008, the New Jersey Board of Public Utilities (the “Board”) established a three-year, 

long-term contracting program for SRECs for the state’s regulated distribution utilities 

(NJBPU 2008). The program is called the SREC-Based Financing Program because these 

auctions are intended to help winning residential and commercial developers secure 

financing for their solar projects. The contracts resulting from the auctions are standardized 

and non-negotiable, and developers are encouraged to bid for SREC contracts that would 

provide sufficient project returns. The Board has included a provision that precludes a project 

that receives an award in one solicitation to compete in a future solicitation at a higher price 

absent a “clear indication of a change in circumstances” (NJ BPU 2010). 

For RPS Reporting Years 2010–2012, Jersey Central Power and Light Company, Atlantic

City Electric Company, and Rockland Electric Company are required to hold at least two 

auctions annually to select competitive proposals for SRECs under long-term contracts. To 

recover associated costs, the utilities are able to auction the SRECs procured in the SRECBased Financing Program to the state’s generation suppliers.

The auctions are held for SREC contracts between 10 and 15 years. This length enables solar 

projects to obtain financing and addresses a barrier to development. The bidder submits a 

pricing proposal ($/SREC and contract duration) and a summary of project qualifications 

(NERA Economic Consulting 2011a). Since bids may vary in terms, the auctioneer ranks 

each bid according to the net present value of payments under the SREC agreement. There is 

an undisclosed price limit when evaluating bids, and the auctioneer decides whether or not 

there are enough competitive bids to meet the auctioned quantity (NERA Economic 

Consulting 2011a).

The Board-mandated program has the goal of procuring more than 64 MW over three years: 

42 MW for Jersey Central Power and Light Company, 19 MW for Atlantic City Electric 

Company, and 3.769 MW for Rockland Electric Company (NERA Economic Consulting 

2011b). For each solicitation, the Board publishes a planned quantity/capacity cap for each 

EDC, and the auctioneer accepts bids in order of competitiveness up to that cap. If in a given 

solicitation the planned quantity is not procured, the Board assigns the shortfall to subsequent 

auctions. In RPS reporting years 2010 and 2011, the three EDCs procured a total of 47.5 MW 

in six separate solicitations. The remaining 16.5 MW of the total program target will be 

procured in two or three solicitations during the 2012 RPS reporting year (NERA Economic 

Consulting 2011b).

In 2010, the program expanded eligibility to residential and commercial programs up to 

2 MWDC in size, from the earlier 500 kW limit, to increase participation (NERA Economic 

Consulting 2011a). The program administrators consider three segments of project sizes: a

small project size segment (<50 kW); a mid-size project segment (>50 kW, <500 kW); and a 

large project size segment (>500 kW, <2 MW). 
48

Long-Term Contracting Provisions: Competitive Solicitations in Pennsylvania

In September 2010, the Pennsylvania PUC adopted a “Policy Statement in Support of 

Pennsylvania Solar Projects” (see PUC Code §69.2901-2903). The policy statement

encourages EDCs to issue RFPs for large-scale solar projects (>200 kW) using a transparent 

and open competitive bidding process. The statement also suggests that EDCs can procure 

SRECs from small-scale projects (<200 kW) through both RFPs and bilateral contracts. The 

policy statement specifies that the price negotiated for SRECs from small-scale projects 

should not exceed the commission-approved average winning bid price in the EDC’s most 

recent RFP for large-scale solar projects (Pennsylvania PUC 2011).

In response, Pennsylvania EDCs have started to hold competitive solicitations to procure a 

portion of their SREC obligations over a longer delivery period (e.g., 7–10 years). Four of 

Pennsylvania’s 11 EDCs have held RFPs for long-term SREC contracts to date, including: 

Metropolitan Edison Company, Pennsylvania Electric Company, Pennsylvania Power 

Company, and PPL Electric Utilities. 

The utilities have structured their procurements so that long-term contracts expire in 8–10 

years (2020) when the Pennsylvania alternative energy portfolio standard concludes. The 

utilities are seeking bids in tranches (i.e., 100, 250, or 500 SRECs per year from an 

individual supplier). SREC suppliers have the responsibility of delivering the quantity of 

SRECs specified by their contract each year. One advantage of this approach is that the 

utility does not have to bear the risks associated with individual project performance 

(Bingaman 2010). 

SREC Price Floor Programs: Massachusetts and New Jersey Utility PSE&G

Massachusetts Solar Credit Clearinghouse

In 2010, Massachusetts created the Solar Credit Clearinghouse Auction, which functions as a 

long-term price floor for SRECs in the Massachusetts market. Massachusetts opted for this 

approach because there was little appetite to adopt long-term contracting provisions at the 

time the solar carve out was implemented (Bernstein et al. 2011).

Under the clearinghouse program, the Massachusetts Department of Energy Resources

(DOER) will hold an annual fixed-price SREC auction where generators can deposit eligible, 

unsold SRECs into an auction account with the NEPOOL-GIS. Solar generators may deposit 

SRECs into the account during the final 31 days of each compliance year’s Q4 trading period 

(May 16–June 15). If any SRECs are deposited, DOER must hold an auction to clear these 

SRECs prior to July 31 of that year. Bidders submit the volume that they are willing to buy 

for the fixed price of $300/MWh, the floor price for the SRECs (Massachusetts DOER 

2011d). There is a 5% auction fee, so generators will receive $285 for each SREC cleared on 

the auction (instead of $300/SREC).

At the time of qualification, generators will be given an “opt-in term,” which signifies the 

number of quarters that their project will have the opportunity to deposit SRECs into the 

auction account. The opt-in term for new projects is currently 10 years. The opt-in term for 

future projects may be adjusted annually based on market conditions, but any adjustment will 

have no impact on projects that have already been qualified. If the SREC market is 

oversupplied, the DOER will decrease the opt-in period for new systems to temper market 
49

growth (Flynn et al. 2010). For every 10% of the compliance obligation met by deposits into 

the auction, the opt-in term will be reduced by one year. It will not decrease more than two

years at a time. In the event of a shortage, the opt-in term will increase by one year for each 

10% of the compliance obligation met through solar ACP payments. The opt-in term may 

never be longer than 10 years. It cannot decrease below five years until after 2016. 

When SRECs are deposited into the auction account, they are re-minted with an initial shelf 

life of two years, meaning that they can be used for compliance for either one of the next two 

compliance years. The compliance obligation the following year is increased by the amount 

of SRECs deposited in the auction. If there is insufficient bid volume to clear the auction 

account SRECs, the shelf life is increased to three years, and the auction is repeated 

(Massachusetts DOER 2011d). If the second auction does not clear, a third and final auction 

will be held. SRECs retain the three-year shelf-life from the second auction, and the 

compliance obligation for the following year is increased a second time by the amount of 

SRECs in the auction account. If there are insufficient bids to clear this final auction, 

depositors will be paid on a pro-rated basis for the number of SRECs deposited relative to the 

number sold. Any remaining SRECs will be returned to depositors, who will have three years 

to sell them.

The auction is intended as a market of last resort. Once a SREC is moved into the auction 

account, it cannot be removed (Massachusetts DOER 2011d). The auction mechanism has 

not yet been used because there has been a shortage of SRECs to date. 

PSE&G Solar Loan Program

The Public Service Electric & Gas Company (PSE&G) Solar Loan Program has elements of 

a long-term price floor. Under the program, PSE&G lends money to its retail customers to 

cover 40%–60% of the cost of a PV system. Customers may repay the loan principal and 

interest through cash payments or by signing their SRECs over to PSE&G. The loan term is 

15 years, and during this period, PSE&G credits customers for each SREC generated 

according to market conditions but not below the established price floor. The price floor as of 

January 2011 is $420/SREC for residential borrowers and $380/SREC for commercial 

borrowers. The price floor declines over time; however, the floor price applicable at the time 

of loan closing remains in effect for a particular project for the entire duration of the loan 

(DSIRE 2011e). Customers will be paid at least the floor price for each SREC generated, but 

if trading prices are higher, customers may be paid more. PSE&G reserves the right to 

purchase SRECs generated by the system at 75% of the market price through the original 

term of the loan (DSIRE 2011e). The Solar Loan I program, which was initiated in 2008, had 

the goal of installing 30 MW of customer-sited PV. Solar Loan II, which began in December 

2009, has a current program target of 51 MW of installed capacity (NJ BPU 2011d).