1 Renewables Portfolio Standards in the United States 
2 Renewables Portfolio Standards in the United States 

Executive Summary................................................................................................ 1 

Introduction............................................................................................................. 2 

Four States Added RPS Policies in 2007, Raising the Total to 25 States and 

Washington D.C. .................................................................................................... 3

Eleven States Significantly Revised their RPS in 2007........................................... 5

Forty-Six Percent of Load in the U.S. Will Ultimately Be Covered by Existing 

RPS Policies............................................................................................................ 5

The Design of State RPS Policies Continues to Differ Widely................................ 6

Resource Eligibility Is Expanding Beyond Traditional Renewable Sources to 

Include Energy Efficiency and Other Supply-Side Technologies.......................... 11

Operational Experience Remains Limited............................................................. 12

Renewables Portfolio Standards Are Increasingly Motivating Renewable 

Energy Development............................................................................................. 12

State RPS Policies Are Primarily Supporting Wind Power, Though Some 

Resource Diversity Is Apparent............................................................................. 13

The Future Impacts of Existing State RPS Policies Are Projected To Be 

Relatively Sizable.................................................................................................. 14 

Solar-Specific RPS Designs Are Becoming More Prevalent................................. 16

Compliance with State RPS Mandates Has Been Strong in General, Though 

Important Exceptions Exist.................................................................................... 20

The Use of Renewable Energy Certificates and Certificate Tracking Systems 

Is Expanding.......................................................................................................... 24

REC Prices Have Been Highly Variable Across States......................................... 26

The Price Impacts of State RPS Policies Are Not Always Observable, But 

Have Been Modest in Most Cases So Far............................................................ 29

States Are Increasingly Recognizing Transmission as a Key Limitation to 

Achieving RPS Targets......................................................................................... 32

Federal RPS Policies Received Consideration in the U.S. Congress in 2007...... 34

Conclusions........................................................................................................... 34

Appendix................................................................................................................ 35

LBNL-154E

April 25 Revision
1 Renewables Portfolio Standards in the United States 

Executive Summary 

As the popularity of renewables portfolio standards (RPS) has grown, so too has the need to keep up 

with the design, early experience, and projected impacts of these programs. This report – the first in a 

regular series – seeks to fill this need by providing basic, factual information on RPS policies in the 

United States. Key findings of this inaugural edition are as follows: 

• Mandatory RPS policies have been created in 25 states and Washington D.C.; four additional states have 

non-binding goals 

• In 2007, four states established new RPS policies, 11 states significantly revised pre-existing RPS programs 

(mostly to strengthen them), and three states created non-binding renewable energy goals 

• Forty-six percent of nationwide retail electricity sales will be covered by the mandatory state RPS policies 

established through the end of 2007, once these programs are fully implemented 

• RPS policy designs vary widely among states, and a “common” design has not yet emerged 

• Resource eligibility in state RPS programs has expanded beyond traditional renewables, with three states 

now allowing demand-side energy efficiency to meet at least a portion of their RPS requirement; additional 

states have stand-alone mandatory energy efficiency portfolio standards 

• Eleven states now have four or more years of operational experience with an RPS, though many other state 

programs are just getting underway 

• Though not an ideal metric, over 50% of the non-hydro renewable capacity additions in the U.S. from 1998 

through 2007 occurred in states with RPS programs (~8,900 MW); 93% of these additions came from wind 

power, 4% from biomass, 2% from solar, and 1% from geothermal 

• Assuming that full compliance is achieved, current mandatory state RPS policies will require the addition 

of roughly 61 gigawatts (GW) of new renewables capacity by 2025, equivalent to 4.7% of projected 2025 

electricity generation in the U.S., and 15% of projected electricity demand growth 

• Solar-specific RPS designs are becoming more common, with 11 states and Washington D.C. adopting 

solar or distributed generation (DG) set-asides so far; these policies have already supported 102 MW of 

photovoltaics and 65 MW of solar-thermal electric capacity, and a total of roughly 6,700 MW of solar 

capacity would be needed by 2025 to fully meet existing set-aside requirements 

• The early-year renewable energy targets in the majority of state RPS policies have been fully or almostfully achieved through the application of renewable electricity or renewable energy certificates (REC) 

towards RPS targets; the overall average level of RPS “compliance” in 2006 was 94%, and nine states 

achieved renewable energy deliveries, as a proportion of RPS targets, of above 95% 

• Several states have struggled to meet early-year RPS targets, however, and alternative compliance 

payments of more than $18 million were paid in 2006; financial penalties have been applied in two states 

• Renewable energy certificate tracking systems continue to expand and, as of the end of 2007, all but four 

RPS states allowed unbundled RECs to count towards RPS compliance 

• Renewable energy certificate markets remain fragmented, and prices have varied dramatically across states, 

and over time, reflecting variations in RPS design 

• The electricity rate increases associated with existing state RPS policies, for those states in which such 

impacts are readily calculable, generally equal 1% or less so far; in several states, the renewable electricity 

required by these policies appears to be priced competitively with fossil generation 

• States are increasingly recognizing lack of transmission investment as a key barrier to achieving RPS 

targets, and at least five states – Texas, Colorado, California, Minnesota, and New Mexico – took important 

steps in 2007 to mitigate this barrier 

• The U.S. House of Representatives passed a Federal RPS in 2007, but the bill was unable to pass out of the 

U.S. Senate 
2 Renewables Portfolio Standards in the United States 

Introduction 

 Renewables portfolio standards (RPS) have proliferated at the state level in the United States since 

the late 1990s.1 In combination with Federal tax incentives, state RPS requirements have emerged as 

one of the most important drivers of renewable energy capacity additions. The focus of most RPS 

activity in the U.S. has been within the states. Nonetheless, the U.S. House of Representatives and 

Senate have, at different times, each passed versions of a Federal RPS; a Federal RPS, however, has 

not yet been signed into law.2 

 The design of an RPS can and does vary, but at 

its heart an RPS simply requires retail electricity 

suppliers (also called load-serving entities, or 

LSEs) to procure a certain minimum quantity of 

eligible renewable energy. An RPS establishes 

numeric targets for renewable energy supply, 

applies those targets to retail electricity suppliers, 

and seeks to encourage competition among 

renewable developers to meet the targets in a leastcost fashion. RPS purchase obligations generally 

increase over time, and retail suppliers typically 

must demonstrate compliance on an annual basis. 

Mandatory RPS policies are backed by various 

types of compliance enforcement mechanisms, and 

many – but not all – such policies include the 

trading of renewable energy certificates (RECs3). 

 Renewables portfolio standards are a relatively 

recent addition to the renewable energy policy 

landscape, and these policies continue to evolve. 

Keeping up with the design, early experience, and 

projected impacts of these programs is a challenge. 

This report seeks to fill this need by providing 

basic, factual information on RPS policies in the 

United States. It focuses on state-level initiatives, 

though a later section briefly discusses Federal 

developments as well. The report does not cover 

municipal-level renewable energy goals, unless 

required by state law. Similarly, this report 

focuses on mandatory state RPS requirements, 

though it also touches on non-binding renewable 

energy goals, especially when those goals are 

 

1

 RPS policies are sometimes called “Renewable Energy Standards,” “Quota Systems,” or “Renewable Obligations.” 2

 Mandatory RPS requirements also exist in Australia, Japan, Belgium, Sweden, Italy, the United Kingdom, and Poland. 

Certain provinces in India and Canada have also developed RPS instruments, and renewable energy purchase obligations 

of a somewhat similar form are used in China. 

3

 Sometimes referred to as a “Tradable Green Certificate” or “Green Tag”, a REC is created when a megawatt-hour of 

renewable energy is generated, is a purely financial product, and can be traded separately from the underlying electricity 

generation. REC transactions create a supplemental revenue stream for renewable generators, and allow retail suppliers to 

demonstrate compliance with an RPS by purchasing RECs in lieu of directly purchasing renewable electricity. 

ACRONYMS 

ACP alternative compliance payment 

CPCN certificate of public convenience and necessity 

CREZ competitive renewable energy zone 

DG distributed generation 

ERCOT Electric Reliability Council of Texas 

ERZ energy resource zone 

ESP competitive electric service provider 

GATS PJM Generation Attributes Tracking System 

GIS New England Power Pool Gen. Info. System 

GW gigawatt 

GWh gigawatt-hour 

IOU investor-owned utility 

LSE load-serving entity 

MISO Midwest Independent System Operator 

M-RETS Midwest Renewable Energy Tracking System 

MSW municipal solid waste 

MW megawatt 

MWh megawatt-hour 

PJM PJM Interconnection 

POU publicly owned utility 

PRC public regulation commission 

PSC public service commission 

PUC public utilities commission 

PV photovoltaics 

REC renewable energy certificate 

RPS renewables portfolio standard 

SEP supplemental energy payment 

TWh terrawatt-hour 

WECC Western Electricity Coordinating Council 

WREGIS Western Renewable Energy Gen. Info. System 
3 Renewables Portfolio Standards in the United States 

developed by state law or regulation. This report is the first of what is envisioned to be an ongoing 

series; as such, it concentrates on key recent developments, while also providing basic information on 

historical RPS experience and design. 

 The report begins with an overview of state RPS policies: where they have been developed, when, 

and with what design features. Though most RPS programs are still in their infancy, the report 

summarizes the early impacts of these policies on renewable energy development, and provides a 

forecast of possible future impacts. It then turns to the implications of the growing trend towards 

solar and/or distributed generation set-asides within state RPS programs. Next, the report highlights 

state RPS compliance levels, enforcement actions, and cost impacts, as well as key developments in 

REC markets. Finally, the report provides a brief overview of Federal RPS proposals. 

Four States Added RPS Policies in 2007, Raising the Total to 

25 States and Washington D.C. 

The popularity of mandatory state RPS policies has grown in recent years. Four states – Illinois, 

New Hampshire, North Carolina, and Oregon – established new RPS programs in 2007 alone (the 

details of which are described further in Table A-1 in the Appendix). At the end of 2007, 25 states 

and Washington D.C. had a mandatory RPS (see Figure 1). Figure 2 shows the rate of state RPS 

adoption over time, presenting both the year of initial enactment and the years in which major changes 

to state RPS policies have been made. Of the 26 programs in existence at the end of 2007, half had 

been created since the beginning of 2004. 

Figure 1. State RPS Policies and Non-Binding Renewable Energy Goals 

WI: 10% by 2015

NV: 20% by 2015

TX: 5,880 MW by 2015

PA: 8% by 2020

NJ: 22.5% by 2021

CT: 23% by 2020

MA: 9% by 2014

ME: 40% by 2017

NM: 20% by 2020 (IOUs)

10% by 2020 (co-ops)

CA: 20% by 2010 

MN: 25% by 2025

Xcel: 30% by 2020

IA: 105 MW by 1999 

MD: 9.5% by 2022

RI: 16% by 2019

HI: 20% by 2020

AZ: 15% by 2025 

NY: 24% by 2013

CO: 20% by 2020 (IOUs)

10% by 2020 (co-ops and munis)

MT: 15% by 2015

DE: 20% by 2019

DC: 11% by 2022

WA: 15% by 2020

NH: 23.8% by 2025

OR: 25% by 2025 (large utilities)

5-10% by 2025 (smaller utilities)

NC: 12.5% by 2021 (IOUs)

10% by 2018 (co-ops and munis)

IL: 25% by 2025

Mandatory RPS

Non-Binding Goal

VT: Load growth by 2012

up to cap of 10%

ND: 10% by 2015

VA: 12% by 2022

MO: 11% by 2020

WI: 10% by 2015

NV: 20% by 2015

TX: 5,880 MW by 2015

PA: 8% by 2020

NJ: 22.5% by 2021

CT: 23% by 2020

MA: 9% by 2014

ME: 40% by 2017

NM: 20% by 2020 (IOUs)

10% by 2020 (co-ops)

CA: 20% by 2010 

MN: 25% by 2025

Xcel: 30% by 2020

IA: 105 MW by 1999 

MD: 9.5% by 2022

RI: 16% by 2019

HI: 20% by 2020

AZ: 15% by 2025 

NY: 24% by 2013

CO: 20% by 2020 (IOUs)

10% by 2020 (co-ops and munis)

MT: 15% by 2015

DE: 20% by 2019

DC: 11% by 2022

WA: 15% by 2020

NH: 23.8% by 2025

OR: 25% by 2025 (large utilities)

5-10% by 2025 (smaller utilities)

NC: 12.5% by 2021 (IOUs)

10% by 2018 (co-ops and munis)

IL: 25% by 2025

Mandatory RPS

Non-Binding Goal

VT: Load growth by 2012

up to cap of 10%

ND: 10% by 2015

VA: 12% by 2022

MO: 11% by 2020
4 Renewables Portfolio Standards in the United States 

Figure 2. The Adoption and Revision of Mandatory State RPS Policies4

 Most state RPS policies, including all four new programs created in 2007, have been established by 

legislative action. Alternatively, two states (New York and Arizona) developed their programs 

through regulatory channels, and two other states (Washington and Colorado) did so via voterapproved ballot initiatives.5

 In the 1990s, state RPS policies were generally incorporated into much 

broader state electricity restructuring legislation. More recently, these policies have been adopted 

through stand-alone legislation. In most cases, RPS programs are implemented by state utility 

regulatory agencies (i.e., public utilities commissions, variously referred to as PUCs, PSCs, PRCs, 

etc). 

 In addition to mandatory RPS policies, several states have developed non-binding renewable 

energy goals. As of the end of 2007, four states without a mandatory RPS had instead created nonbinding targets through legislative action. Three of these states – Missouri, North Dakota, and 

Virginia – created their targets in 2007 (see Table A-3 in the Appendix), while Vermont established 

its target in 2005.6

 Other states, such as Illinois and Maine, previously had non-binding renewable 

energy goals that have subsequently been changed to mandatory RPS programs. Finally, some states 

with a mandatory RPS also have more-aggressive non-binding goals, including California (33% 

renewable energy by 2020, established by the Governor and the state’s energy agencies), Iowa (1000 

MW of wind capacity by 2010, recommended by the Governor's Energy Policy Task Force in 2001), 

and Texas (10,000 MW by 2025, established through legislation). 

 

4

 Some states have adopted annual RPS compliance periods that do not coincide with calendar years. Throughout this 

report, RPS compliance periods are referred to based on the starting year of the annual compliance period. 5

 The Colorado RPS passed based on a voter initiative in 2004, with 53% support. The Washington state RPS passed in 

2006 with 52% of the vote. 

6

 Though not reflected in this report, Vermont passed legislation in March 2008 establishing a new, non-binding goal that 

20% of statewide electricity sales be derived from renewable generation by 2017. 

TX

PA

NM

NJ

MN

WI ME

NJ MD

TX HI DE

NV PA NV CT CT

WI NV MN NM CO CA CO

IA MN AZ MN NM CT NJ CT AZ CA

1983 1991 1994 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

OR

(2011)

WA

(2012)

MT

(2008)

RI 

(2007)

CA

(2003)

NM

(2002)

TX

(2002)

WI 

(2000)

NV

(2001)

AZ

(1999)

MN

(2002) IA

NC

(2010)

DE

(2007)

NY 

(2006)

NJ

(2001)

PA 

(2001)

ME 

(2000)

NH

(2008)

DC

(2007)

MD

(2006)

CT

(2000)

MA 

(2003)

IL

(2008)

HI

(2005)

CO 

(2007)

TX

PA

NM

NJ

MN

WI ME

NJ MD

TX HI DE

NV PA NV CT CT

WI NV MN NM CO CA CO

IA MN AZ MN NM CT NJ CT AZ CA

1983 1991 1994 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

OR

(2011)

WA

(2012)

MT

(2008)

RI 

(2007)

CA

(2003)

NM

(2002)

TX

(2002)

WI 

(2000)

NV

(2001)

AZ

(1999)

MN

(2002) IA

NC

(2010)

DE

(2007)

NY 

(2006)

NJ

(2001)

PA 

(2001)

ME 

(2000)

NH

(2008)

DC

(2007)

MD

(2006)

CT

(2000)

MA 

(2003)

IL

(2008)

HI

(2005)

CO 

(2007)

Enactment (above timeline)

( ) Year of First Requirement 

Enactment (above timeline)

Major Revisions (below timeline)

Year of First Requirement

Enactment (above timeline)

Year of First Requirement 

Enactment (above timeline)

Major Revisions (below timeline)

Year of First Requirement
5 Renewables Portfolio Standards in the United States 

Eleven States Significantly Revised their RPS in 2007 

 Figure 2 illustrates the growing tendency for states to revise existing RPS policies. Eleven states 

made substantial modifications to their RPS programs in 2007, as described further in Table A-2 in 

the Appendix.7

 These changes have generally been to strengthen pre-existing RPS requirements, 

often by increasing renewable energy targets, removing supplier exemptions, or adding resourcespecific set-asides. 

 Examples of legislative weakening of state RPS policies exist, but are generally more-modest in 

scope (e.g., minor expansions to resource eligibility, exempting publicly owned utilities from solar 

set-aside requirements, etc.) than are the examples of a strengthening of those policies. No state RPS 

policy has yet been repealed by later legislative action. 

Forty-Six Percent of Load in the U.S. Will Ultimately Be 

Covered by Existing RPS Policies 

 Mandatory state RPS programs created through the end of 2007 will, once fully implemented, 

apply to load-serving entities that, in aggregate, supply roughly 46% of nationwide retail electricity 

sales (see Figure 3). If the four states with non-binding renewable energy goals are also included, 

then the amount of nationwide load ultimately covered by an existing RPS (once fully implemented) 

increases to almost 51%. 

 Not all RPS policies establish renewable energy purchase obligations that take effect immediately 

upon enactment, however. As a result, in 2007, LSEs serving 31% of U.S. electrical load had an 

active RPS compliance obligation, up from 30% in 2006, 24% in 2005, and just 3% in 2000. By 

2012, existing RPS policies will be nearly in full force, and active compliance obligations will extend 

to LSEs serving almost 46% of nationwide electrical load. 

 Of the LSEs serving the 31% of U.S. electrical load with RPS obligations in 2007, investor-owned 

utilities (IOUs) represent the largest share (19%), followed by competitive electric service provides 

(ESPs, 10%), and then by publicly owned utilities (POUs, 3%).8

 After 2007, the percentage share by 

each type of electricity supplier cannot be easily projected, due to potential customer switching 

between IOUs and ESPs in states with retail choice. 

 The fact that 100% of U.S. load is not covered by a state RPS reflects two factors. First, and most 

obviously, not all states have developed RPS programs. Secondly, as described in Table 2, a variety 

of states offer RPS exemptions to particular types of LSEs and/or customers. Both factors are 

incorporated into Figure 3. 

 

7

 Less-significant revisions to RPS policies in 2007 were made in the following states: (1) Hawaii (in implementing 2006 

statutory revisions to the RPS, the PUC established a framework for – among other things – reporting and non-compliance 

penalties); (2) Massachusetts (regulatory revisions were made to biomass eligibility); (3) Montana (added competitive 

ESPs serving small customers to those LSEs that must meet RPS obligations); and (4) Nevada (added geothermal heat as 

an eligible energy efficiency source). 8

 The term publicly owned utility, or POU, is broadly used in this report to include public power and cooperatives. IOU, 

ESP, and POU contributions do not sum to 31% due to rounding. 
6 Renewables Portfolio Standards in the United States 

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

1998199920002001200220032004200520062007200820092010201120122013201420152016201720182019202020212022202320242025

Percent of Total U.S. Retail Sales

POUs

IOUs & ESPs

ESPs

IOUs

Figure 3. U.S. Electrical Load with Active State RPS Obligations

The Design of State RPS Policies Continues to Differ Widely 

 State RPS programs share the common goal of encouraging renewable energy supply, but design 

variations among states are so stark that there is even some debate over what exactly constitutes an 

RPS, and whether certain states qualify as having one.9

 The tailoring of RPS designs to satisfy 

particular state objectives and political exigencies is a typical aspect of state policy making, ensuring 

that U.S. states serve as “laboratories” for RPS policy experimentation. 

 Table 1 illustrates a small subset of the important design differences among existing mandatory 

state RPS programs and non-binding state renewable energy goals. Variations exist in terms of the 

renewable energy purchase targets and timeframes, which renewable energy technologies are 

eligible10, and whether existing projects can qualify. Importantly, some states have established 

“tiered” targets or set-asides, consisting of different targets for different resource types or resource 

vintages, frequently with different schedules and compliance frameworks. Tiers and set-asides are 

often used to ensure that an RPS supports certain “preferred” resources, not just the least-cost 

renewable energy options. Alternatively, or in addition, some states have sought to support preferred 

resource types through credit multipliers of various designs. 

 One important structural difference among state RPS policies relates to how compliance is 

achieved. Three distinct RPS compliance models have thus far emerged: 

 

9

 New York, for example, has established a policy that it calls an RPS, but that involves ratepayer collection of funds and 

incentive payments from a state energy authority. New York is identified in this report as a state with an RPS, though 

such a classification is debatable. 

10 Though wind, solar, landfill-gas, and geothermal energy are eligible under most of the policies, eligibility criteria for 

biomass, municipal solid waste (MSW), and hydropower vary considerably across states. Some states also allow resources 

such as energy efficiency and gas-fired fuel cells to qualify (see later section). 
7 Renewables Portfolio Standards in the United States 

1. in states with retail electric competition, electricity suppliers are typically given broad latitude 

to comply with RPS requirements as they see fit; 

2. in states with still-regulated utility monopolies, electricity regulators oversee – to varying 

degrees – utility procurement and contracting under the RPS; and 

3. in two states, New York and Illinois, a state agency/instrumentality has direct responsibility to 

conduct procurements under the RPS. 

 As alluded to earlier, state RPS policies also differ in terms of which entities are obligated under 

the program. Many states have exempted certain LSEs or end-use customers from meeting RPS 

requirements (see Table 2). In particular, states often exempt some or all POUs from formal RPS 

obligations, or instead allow POUs to develop their own renewable energy standards. Various other 

types of permanent or temporary exemptions have also been adopted, for example, exemptions for 

small utilities, large customers, or customers in utility service territories with a rate freeze. Force 

majeure clauses and cost caps, which are common, can also effectively function as exemptions by 

reducing the amount of load subject to RPS obligations. 

 States have also adopted different eligibility rules related to geographic location and electricity 

delivery. States that enact RPS policies typically do so with the expectation that the requirement will 

stimulate new resource development in their state or region. If renewable electricity is used for 

compliance, and that electricity must be delivered to the LSE under the RPS obligation, a practical 

limitation is placed on the distance of renewable projects from the state in question. Unbundled 

RECs, on the other hand, could potentially satisfy an RPS without any geographic constraint. 

Because state interests in encouraging in-state or in-region development vary, because interpretations 

of the requirements of the Interstate Commerce Clause vary, and because wholesale electricity market 

structures differ, a variety of approaches have been used to limit the geographic eligibility of 

renewable energy projects, and to establish electricity delivery requirements. Table 3 describes the 

geographic eligibility and electricity delivery requirements for the main “tier” of each state’s RPS 

(certain sub-tiers, for example solar or DG set-asides, often have different standards). 

 Other differences in the design of state RPS policies, some of which are described in later sections 

of this report, pertain to what kind of enforcement is applied, whether and what types of cost caps 

exist, whether unbundled RECs are allowed, what level of compliance flexibility is provided, whether 

discretionary or non-discretionary regulatory waivers are offered, the degree to which contracting 

requirements are applied, and the role of state funding mechanisms. 

Tables A-1 through A-3 in the Appendix provide more-detailed textual descriptions of the key 

design elements of the new mandatory state RPS programs, major RPS program revisions, and new 

non-binding state renewable energy goals adopted in 2007. Key policy design trends among those 

states that created or revised RPS programs in 2007 include the following: 

• The stringency of renewable energy targets increased both through revisions to existing 

programs and through implementation of new RPS policies. 

• The use of resource-specific set-asides dramatically expanded, especially for solar, but also for 

other favored renewable resource options, such as wind power. 

• The applicability of RPS policies continued to expand to cover POUs, with three of four new 

state policies broadly applicable to all electricity suppliers, and revisions to existing policies 

also increasingly requiring POUs to meet renewable energy purchase objectives. 

• Though RPS policies increasingly apply to POUs, it has also become common to offer greater 

leniency and impose lower RPS targets to those supplies. 
8 Renewables Portfolio Standards in the United States 

Table 1. Select Design Elements of State RPS Policies 

State 

First 

Compliance 

Year 

Current 

Ultimate Target 

Existing 

Plants 

Eligible1

Set-Asides, Tiers, or 

Minimums Credit Multipliers 

Mandatory RPS Obligations 

Arizona 2001 15% (2025) No Distributed Generation None2

California 2003 20% (2010) Yes None None 

Colorado 2007 20% (2020): IOUs 

10% (2020): POUs 

Yes Solar In-State, Solar, CommunityOwnership 

Connecticut 2000 23% (2020) Yes Class I/II Technologies None 

Delaware 2007 20% (2019) Yes Solar, New/Existing Solar, Fuel Cells, Wind 

Hawaii 2005 20% (2020) Yes Energy Efficiency None 

Illinois 2008 25% (2025) Yes Wind None 

Iowa 1999 105 MW (1999) Yes None None 

Maine 2000 40% (2017) Yes New/Existing None 

Maryland 2006 9.5% (2022) Yes Solar, Class I/II Technologies Wind, Methane 

Massachusetts 2003 9% (2014) No None None 

Minnesota 2002 25% (2025) 

30% (2020): Xcel 

Yes Wind for Xcel; Goal for 

Community-Based Renewables 

None 

Montana 2008 15% (2015) No Community Wind None 

Nevada 2003 20% (2015) Yes Solar, Energy Efficiency PV, DG, Eff., Waste Tire 

New Hampshire 2008 23.8% (2025) Yes Solar, New, Existing Biomass/ 

Methane, Existing Hydro 

None 

New Jersey 2001 22.5% (2021) Yes Solar, Class I/II Technologies None 

New Mexico 2006 20% (2020): IOUs 

10% (2020): Co-ops 

Yes Solar, Wind, Geothermal or 

Biomass, Distributed Generation 

None2

New York 2006 24% (2013) Yes Distributed Generation None 

North Carolina 2010 12.5% (2021): IOUs 

10% (2018): POUs 

Yes Solar, Swine Waste, Poultry 

Waste, Energy Efficiency 

None 

Oregon 2011 25% (2025): Large 

5-10% (2025): Small 

No3 Goal for Community-Based and 

Small-Scale Renewables 

None 

Pennsylvania 2001 8% (2020) Yes Solar None 

Rhode Island 2007 16% (2019) Yes New/Existing None 

Texas 2002 5,880 MW (2015) Yes Goal for Non-Wind All Non-Wind 

Washington 2012 15% (2020) No None Distributed Generation 

Washington, DC 2007 11% (2022) Yes Solar, Class I/II Technologies Wind, Solar, Methane 

Wisconsin 2000 10% (2015)4 Yes None None 

Non-Binding Renewable Energy Goals6

Missouri 2012 11% (2020) Yes None PSC Authorized To Do So 

North Dakota 2015 10% (2015) Yes None None 

Vermont 2006 Up To 10% (2012)5 No None None 

Virginia 2010 12% (2022) Yes None Wind, Solar 

1 Some RPS policies allow existing facilities, but only if built after a certain date, e.g., 1995 or 1999. For the purpose of this table, these states are 

identified as not allowing existing resources, because they do not allow older existing facilities. In other states, such as Texas, existing facilities may 

qualify towards the RPS, but with restrictions not identified in the table. Note also that even those states that do not broadly allow existing facilities to 

qualify under their RPS often allow incremental generation from such facilities to qualify. 2 Credit multipliers were once used extensively, but are now being phased out and replaced by set-asides. 3 Only plants placed in service on or after January 1, 1995 are broadly eligible, except that certain small-hydro facilities owned by Oregon utilities and 

placed in service prior to 1995 are also eligible (such facilities must be certified as “low impact”, however, and there are limits to the amount of hydro 

generation that is allowed to qualify). Incremental efficiency and capacity upgrades on pre-1995 renewable facilities are also eligible. 4 Targets vary by utility, but the statewide goal is 10% by 2015. 5 Target equals load growth between January 2005 and January 2012, capped at 10% of 2005 load. The target becomes mandatory in 2013 if the nonbinding goal is not achieved. Though not reflected in this report, Vermont also passed legislation in March 2008 establishing a new, non-binding goal that 

20% of statewide electricity sales be derived from renewable generation by 2017. 6 In addition to the four non-binding state renewable energy goals noted here, California, Iowa, and Texas have both mandatory RPS policies and moreaggressive non-binding goals.
9 Renewables Portfolio Standards in the United States 

Table 2. State RPS Exemptions 

Treatment of 

POUs State 

% of 

State 

Sales 

Covered Munis Coops 

Other LSE Exemptions Customer Exemptions 

AZ 59% { z Political subdivisions; utilities with >50% of 

out-of-state customers None 

CA 98%   POUs obligated to develop own RPS None 

CO 94% z z Munis with < 40,000 customers None 

CT 100%  na Munis obligated to develop own RPS None 

DE 75% { { POUs have requested/received exemptions Industrial customers > 1.5 MW load 

HI 100% na z None None 

IA 75% { { Applies only to MidAmerican and IPL None 

IL 56% { { IOUs with < 100,000 customers; all 

competitive ESPs 

IOU retail supply customers not with 

fixed-price service 

MA 86% { na None None 

MD 98% z z Coops served by existing purchase 

agreement 

Industrial process load > 300 GWh/yr; 

resid. load in area subject to rate freeze 

ME 93% { { None Sales to certain businesses, until 2010 

MN 100% z z None None 

MT 63%  

Coops and existing munis with > 5,000 

customers must develop own RPS; other 

coops exempt; ESPs and new munis that 

serve large customers exempt 

None 

NC 100% z z None None 

NH 100% z z None None 

NJ 97% { { None None 

NM 88% { z None None 

NV 88% { { None None 

NY 73% { { LIPA, NYPA, munis encouraged to establish 

RPS None 

OR 100% z z Multiple clauses offer possible exemptions to 

certain suppliers (esp. POUs) in certain years None 

PA 97% { { None Load in area subject to rate freeze 

RI 99% { na None None 

TX 75% { { Utilities under a rate freeze Certain large customers upon petition 

WA 83% z z All utilities with < 25,000 customers None 

D.C. 100% na na None None 

WI 100% z z None None 

Notes: The percent of state sales figures represent the fraction of statewide load ultimately obligated by existing RPS policies. The 

percentage totals include POUs required to meet an RPS of their own design (e.g., CA and CT) and LSEs temporarily exempted from

the RPS. In addition to the specific exemptions listed here, Federal power marketing agencies and state-owned electric utilities are 

assumed to be exempt in all cases. 

z Must generally meet RPS (in some cases, percentage targets are lower or limited exemptions apply) 

 Must meet an RPS of their own design 

{ Fully exempt from obligatory RPS 

na No entities of that type exist in the state 

 
10 Renewables Portfolio Standards in the United States 

Table 3. Geographic Eligibility and Electricity Delivery Requirements (Main Tier of Each State’s RPS) 

Geographic Eligibility and Delivery 

Requirements States Notes 

In-state generation requirement HI, IA IA: also allows location in broader utility service area 

In-region generation requirement MN, OR, 

PA 

MN: RECs originating within M-RETS; OR: WECC for unbundled 

RECs, U.S. portion of WECC and delivered to LSE for renewable 

electricity; PA: PJM projects for all LSEs, MISO projects for some 

LSEs 

Electricity delivery required to state or to LSE 

Direct transmission inter-tie between 

generators and state NV, TX NV: allows limited sharing of transmission inter-tie with other generators; TX disallows such sharing 

Broader delivery requirements to state or 

to LSE 

AZ, CA, 

MT, NM, 

NY, WI 

CA: relaxed scheduling allows shaped/firmed products; NY: strict 

hourly scheduling to state and strong preference for in-state 

resources in solicitation process; WI: projects must be owned by or 

under contract to LSE 

Electricity delivery required to broader region 

Generators anywhere outside region must 

deliver electricity to region 

DE, ME, 

NJ, WA 

DE: also provides credit multipliers for in-state wind installed 

before 2013; NJ: resources outside PJM must be “new”; WA: if 

outside Pacific Northwest, requires delivery to state 

Generators in limited areas outside region 

must deliver electricity to region 

CT, DC, 

MA, MD, 

NH, RI 

All: renewable facilities must be located in control areas adjacent to 

state’s ISO; DC & MD: LSEs may also purchase unbundled RECs 

(without electricity delivery) from states that are adjacent to PJM 

In-state generation encouragement 

In-state multipliers CO 

No restriction on location of RECs creation, but credit multiplier for 

in-state projects (DE also provides in-state encouragement through 

multipliers) 

Cost-effectiveness test IL 

In-state unless insufficient cost-effective resources, then from 

adjoining states, then from other regions; after 2011, equal 

preference to in-state and adjoining states 

Limit on RECs from out-of-state 

generators NC 

Up to 25% compliance can be met with unbundled RECs from 

outside state (no limit for one LSE, Dominion); remainder must be 

in-state or delivered to LSE 
11 Renewables Portfolio Standards in the United States 

Resource Eligibility Is Expanding Beyond Traditional 

Renewable Sources to Include Energy Efficiency and Other 

Supply-Side Technologies 

 Among those states with mandatory RPS policies, three – Hawaii, Nevada, and North Carolina – 

allow demand-side energy efficiency to qualify for a portion of the stated renewables portfolio 

standard requirement, enabling LSEs to substitute energy efficiency for renewable energy for some 

portion of RPS compliance (see Table 4). Other states, including Colorado, Connecticut, Illinois, 

Minnesota, New Jersey, New Mexico, Pennsylvania, and Texas, have established (or have authorized 

the development of) mandatory energy efficiency portfolio standards that are separate from, and 

additional to, any targets for renewable resources.11 

 Some states also allow certain supply-side efficiency technologies or non-renewable energy 

technologies to meet a portion of their RPS standard, including the electricity and/or heat from 

combined heat and power and/or waste heat recovery facilities (e.g., Colorado, Connecticut, Hawaii, 

Illinois, Maine, Nevada, North Carolina), and fuel cells using fuels derived from non-renewable 

energy sources (e.g., Connecticut, Maine, Minnesota, New York, Pennsylvania). Still other states, 

such as Pennsylvania, include portfolio standard requirements for non-renewable energy sources that 

are additional to the standards applied for renewable electricity. 

Table 4: States with Demand-Side Energy Efficiency Included in Mandatory RPS Requirements 

State Proportion of RPS that Can Be 

Met with Energy Efficiency Notes 

HI Up to 50% 

Heat pump water heating, ice storage, ratepayer-funded efficiency 

programs, and use of rejected heat from cogeneration and combined 

heat and power systems 

NV Up to 25% 

Utility-subsidized efficiency measures installed after 1/1/05, and district 

heating powered by geothermal hot water; at least 50% of savings must 

come from the residential sector; utilities can purchase energy savings 

credits from third parties; energy efficiency receives standard multiplier 

of 1.05, and 2.0 for peak savings 

NC 

IOUs: Up to 25%; up to 40% after 2021 

POUs: Unlimited for main RPS target 

Efficiency measures after 1/1/07, including waste heat from combined 

heat and power systems powered by non-renewable fuels; POUs may 

also rely on demand-management/load-shifting 

 

11 For additional information on energy efficiency portfolio standards in the United States, see: (1) Nadel, S. 2006. Energy 

Efficiency Resource Standards: Experience and Recommendations. Washington, D.C.: American Council for an EnergyEfficient Economy. (2) Hamrin, J., E. Vine, and A. Sharick. 2007. The Potential for Energy Savings Certificates as a 

Major Tool in Greenhouse Gas Reduction Programs. San Francisco, Calif.: Center for Resource Solutions. 
12 Renewables Portfolio Standards in the United States 

Operational Experience Remains Limited 

 State RPS programs are a relatively new addition to the renewable energy policy landscape, with 

most programs enacted since the late 1990s. Consequently, many RPS states have few years of 

operational experience during which active compliance obligations have been in force. As shown in 

Figure 4, six states with RPS policies had no operational experience with those policies, as of yearend 2007 (i.e., the first compliance period is 2008 or later), and six additional states had just one year 

of such experience. Eleven states have four or more years of operational experience, though in some 

instances these policies began with modest renewable energy purchase obligations, so early-year 

targets were not particularly challenging to achieve. 

Washington

Oregon

North Carolina

New Hampshire

Montana

Illinois

Washington D.C.

Rhode Island

Delaware

Colorado

New York

Maryland

Hawaii

New Mexico Texas

Minnesota

Massachusetts

California

Wisconsin

Pennsylvania Nevada New Jersey

Maine

Connecticut

Arizona

Iowa

< 1 year 1 year 2 – 3 years 4 – 6 years 7 – 8 years > 8 years

Washington

Oregon

North Carolina

New Hampshire

Montana

Illinois

Washington D.C.

Rhode Island

Delaware

Colorado

New York

Maryland

Hawaii

New Mexico Texas

Minnesota

Massachusetts

California

Wisconsin

Pennsylvania Nevada New Jersey

Maine

Connecticut

Arizona

Iowa

< 1 year 1 year 2 – 3 years 4 – 6 years 7 – 8 years > 8 years

Figure 4. Experience with State RPS Policies (Years Since First Major Compliance Period) 

Renewables Portfolio Standards Are Increasingly Motivating 

Renewable Energy Development 

 Though experience remains somewhat limited, state RPS policies are already beginning to have a 

sizable impact on the amount and location of renewable project development. These policies are one 

of a number of drivers for renewable energy. Other significant factors include Federal tax incentives, 

state renewable energy funds, voluntary green power markets, the specter of future greenhouse gas 

regulations, and the economic fundamentals of certain forms of renewable energy relative to 

conventional generation. Disentangling these various drivers is – to put it mildly – challenging. 

 As one indicator of the role of state RPS programs in renewable resource development, over 50% 

of non-hydro renewable capacity additions in the U.S. from 1998 through 2007 occurred in states with 

active, mandatory RPS policies, totaling roughly 8,900 MW (see Figure 5). Since 2002, this 

percentage rises to over 60%. In 2007 alone, approximately 76% of all non-hydro renewable capacity 

additions came from states with active RPS programs. By this metric at least, it appears that state RPS 

policies are already playing a major role in renewable resource development in the United States. 

 These numbers should be viewed with some caution, however, because they do not assess whether 

any given facility was constructed because of a state RPS or was, in fact, even eligible for a given 

state’s RPS. On the one hand, in some RPS states, such as Texas and Iowa, a substantial amount of 

renewable energy capacity has been added in recent years that has not been directly motivated by 
13 Renewables Portfolio Standards in the United States 

those states’ RPS policies. Moreover, because RPS policies have often been established in states with 

reasonably strong renewable resource potential, it is perhaps not surprising that a good fraction of the 

renewable energy development in the U.S. has occurred in those states. Given these considerations, 

the data presented in Figure 5 would tend to overstate the importance of RPS programs. On the other 

hand, most states allow out-of-state generation to count toward their RPS, so renewables capacity 

built in a non-RPS state may be used to meet another state’s mandate; the data presented in Figure 5 

do not account for this effect, which would tend to understate the importance of state RPS policies. As 

a result, it is somewhat unclear whether and to what degree the data presented here under- or overestimate the importance of state RPS policies. 

Figure 5. Cumulative and Annual Non-Hydro Renewables Capacity in RPS and Non-RPS States12 

 

 Regardless of these details, it is nevertheless evident that existing state RPS policies have already 

had a sizeable impact on new renewable resource development.13 Moreover, because many of these 

policies have only recently been enacted, and renewable energy contracting has just begun, renewable 

capacity additions to date do not fully capture the impact of existing state RPS policies. In California 

alone, for example, the state’s investor- and publicly owned utilities have contracted for more than 

7,000 MW of new renewables capacity since the RPS was enacted in 2002, but just 1,100 MW of this 

capacity was online at the end of 2007. 

State RPS Policies Are Primarily Supporting Wind Power, 

Though Some Resource Diversity Is Apparent 

 Of the more than 8,900 MW of new non-hydro renewable energy capacity that has come on line in 

RPS states from 1998 through 2007, roughly 93% has come from wind power, with biomass (4%), 

solar (2%), and geothermal (1%) playing lesser roles (see Figure 6). 

 

12 Non-solar data for 1998-2006 were sourced from EIA Form-860; wind data for 2007 were from AWEA; biomass and 

geothermal data for 2007 were from Ventyx; and solar data for all years were from Larry Sherwood (Interstate Renewable 

Energy Council) and known installations of solar thermal electric facilities. Renewable capacity additions are designated 

as having occurred in an RPS state if the facility came online in the year before the first compliance date or later. 13 Research at Berkeley Lab confirms this to some degree. In particular, Berkeley Lab estimates – based on projectspecific considerations – that, from 2001 through 2007, roughly 65% of the total wind additions in the U.S. were 

motivated, at least in part, by state RPS policies. 

Cumulative Capacity

13,000

16,000

19,000

22,000

25,000

28,000

31,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Nameplate Capacity (MW)

RPS

non-RPS

Annual Capacity Additions

0

1,000

2,000

3,000

4,000

5,000

6,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Nameplate Capacity (MW)

RPS

non-RPS
14 Renewables Portfolio Standards in the United States 

Total Capacity Additions (1998-2007)

Solar

2%

Geothermal 

1%

Wind

93%

Biomass

4%

Annual Capacity Additions 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Nameplate Capacity (MW)

Solar

Geothermal

Biomass

Wind

Figure 6. Non-Hydro Renewable Energy Capacity Additions in RPS States, By Technology Type14 

 Though renewable resource diversity has so far been limited, there is some evidence that diversity 

may increase over time as RPS policies expand, at least in some states. In California, for example, of 

the more than 7,000 MW of contracts for new or repowered renewable energy projects signed from 

2002 through 2007 by the state’s IOUs and POUs, 58% of the total capacity is wind, 23% solar, 12% 

geothermal, 7% biomass/MSW, and less than 1% is small hydro and ocean energy, demonstrating a 

greater level of diversity than historical trends, both nationally and in California.15 Additionally, 

largely because of technology tiers that exist in a number of states, a growing amount of solar energy 

is being motivated by RPS obligations, as discussed further in a later section of this report. 

The Future Impacts of Existing State RPS Policies Are 

Projected To Be Relatively Sizable 

 The impacts of state RPS programs on renewable resource development are expected to expand in 

the long term as renewable purchase obligation increase, though the magnitude of that growth will 

depend on how RPS policies are implemented, whether cost caps are limiting, whether entities elect to 

make alternative compliance payments, and whether new renewable energy projects would have come 

on line absent the support of state RPS policies. 

 Ignoring these complexities, and simply assuming that full compliance is achieved, Berkeley Lab 

estimates that over 61 GW of cumulative, new renewable energy capacity may be needed by 2025 to 

fully meet existing state RPS policies (see Figure 7), including 4 GW already required by 2007, a 

cumulative 15 GW by 2010, and a cumulative 32 GW by 2015. The 61 GW figure increases to over 

63 GW if one also includes the non-binding renewable energy targets legislatively established in 

Missouri, North Dakota, Vermont, and Virginia, and to over 77 GW if one includes the longer-term, 

non-binding renewable energy goals in California, Iowa, and Texas. 

 

14 Non-solar data for 1998-2006 were sourced from EIA Form-860; wind data for 2007 were from AWEA; biomass and 

geothermal data for 2007 were from Ventyx; and solar data for all years come from Larry Sherwood (Interstate Renewable 

Energy Council) and known installations of solar thermal electric facilities. We designate renewable capacity additions as 

having occurred in an RPS state if the facility came online in the year before the first compliance date or later. 15 Of the more than 1,100 MW of renewable capacity added in California from 1998-2007, approximately 75% was wind, 

12% biomass, 8% geothermal, and 4% small hydro. 
15 Renewables Portfolio Standards in the United States 

 The largest markets, in terms of capacity growth requirements, are projected to be California, 

Illinois, Minnesota, Texas, New Jersey, and Arizona, each of which would require over 3,000 MW of 

new renewable energy capacity by 2025 to achieve full compliance. As a proportion of expected 

statewide retail sales in 2025, however, leading states are somewhat different, and include Minnesota, 

Oregon, Connecticut, New Jersey, New Hampshire, New Mexico, and Delaware, each of which would 

require that more than 15% of statewide load in 2025 come from new renewable generation. Some of 

the leading states in terms of required capacity additions, such as Texas, require rather modest 

additions on a percentage-of-load basis. 

0 2,000 4,000 6,000 8,000 10,000

D.C.

Iowa

Hawaii

Rhode Island

Maine

Montana

New Hampshire

Delaware

Massachusetts

Nevada

New Mexico

Wisconsin

Connecticut

Maryland

North Carolina

New York

Colorado

Oregon

Washington

Pennsylvania

Arizona

New Jersey

Texas

Minnesota

Illinois

California

New Renewable Capacity Needed by 2025 

(Nameplate MW)

0% 5% 10% 15% 20% 25% 30%

D.C.

Iowa

Maryland

Texas

Hawaii

New York

Wisconsin

Maine

Montana

Arizona

Colorado

Washington

California

Nevada

Illinois

Rhode Island

Delaware

New Mexico

New Jersey

Connecticut

Oregon

Minnesota

New Renewable Generation Needed by 2025 as a 

Percent of Projected Statewide Retail Sales

New Hampshire

Pennsylvania

Massachusetts

North Carolina

Figure 7. New Renewable Energy Required to Meet Existing State RPS Policies16

 Though the eventual market impacts of existing state RPS policies are uncertain, and will depend 

critically on design and implementation details, there is little doubt that the aggregate amount of new 

renewable energy generation required under these policies is significant. The estimated 61 GW of 

new renewables capacity equates to an additional 4.7% of total projected nationwide electricity 

generation in 2025, compared to a non-hydro share of 2.1% in 1999 and 2.4% in 2006. Roughly 15% 

of the projected growth in retail electricity sales from 2000 though 2025 would come from new 

renewable generation required under existing state RPS policies. Even with this growth, however, 

non-hydro renewables would continue to provide a relatively modest contribution to U.S. electricity 

supply: adding the estimate of new renewable generation required by existing state RPS programs 

from 2000 to 2025 to the 1999 base amount of non-hydro renewables sums to just 6% of total 

projected electricity generation in the U.S. by 2025. 

 

16 Data used to generate this figure were derived by applying RPS percentage obligations in each state to our projection of 

obligated retail sales, and deducting expected contributions from existing renewable generation. The figure may overstate 

new renewables needed to fully meet state RPS policies to the extent that more-aggressive energy efficiency programs 

reduce load growth, or if LSEs use out-of-state existing renewable generation to a greater extent than assumed here. Note 

that the new renewable generation required under the Maryland and Washington, D.C. RPS policies is assumed to come 

exclusively from those states’ solar set-asides, with all remaining RPS requirements in those two states projected to be met 

by existing resources. 
16 Renewables Portfolio Standards in the United States 

Solar-Specific RPS Designs Are Becoming More Prevalent 

 Because of concerns that traditional RPS programs – in which all eligible renewable technologies 

compete – are likely to benefit only the least-cost projects, an increasing number of states have begun 

to design their RPS policies to provide differential support to promising but (currently) higher-cost 

renewable technologies or applications. Typically, this support has been provided either through 

credit multipliers, in which favored renewable technologies are given more credit towards meeting 

RPS requirements than are other technologies, or through set-asides, in which some fraction of the 

RPS must be met with favored technologies. 

 As suggested by Table 1, set-asides and credit multipliers have been used to support an array of 

favored technologies, applications, project locations, and vintages. The most popular use of these 

mechanisms, however, has been to support central and distributed solar energy specifically, and 

customer-sited distributed generation (DG) more generally.17 

 Set-asides for solar or DG exist within 12 of the 26 U.S. RPS programs (see Figure 8). Four of 

these states combine credit multipliers of some form with these set-asides. Credit multipliers have 

become somewhat less popular in recent years, and only two states – Texas and Washington – now 

use credit multipliers without an accompanying mandatory set-aside. The popularity of set-asides for 

solar or DG, on the other hand, has increased dramatically in recent years. In 2007 alone, new solar or 

DG set-asides were created in Delaware, Maryland, New Hampshire, New Mexico, and North 

Carolina, and the previously-established solar set-aside in Colorado was effectively expanded though 

an increase in that state’s overall RPS target. 

NV: 1% solar by 2015

2.4x multiplier for central PV

2.45x multiplier for distributed PV

PA: 0.5% PV by 2020

NJ: 2.12% solar electric by 2021

AZ: 4.5% customer-sited DG by 2025 

(half from residential)

NY: 0.1542% customer-sited DG by 2013

CO: 0.8% solar electric by 2020 

(half from customer-sited projects)

1.25x multiplier for in-state projects

3x multiplier for co-ops and munis

for solar installed before July 2015

DC: 0.386% solar electric by 2021

1.1x multiplier for solar 2007-09

WA: 2x multiplier for DG

NM: 4% solar electric by 2020, 

0.6% DG by 2015

DE: 2.005% PV by 2019 

3x multiplier for PV installed 

before 2015

MD: 2% solar electric by 2022

Set-aside

Multiplier

NC: 0.2% solar by 2018

NH: 0.3% solar electric by 2014

Set-aside with multiplier TX: 2x multiplier for all non-wind

NV: 1% solar by 2015

2.4x multiplier for central PV

2.45x multiplier for distributed PV

PA: 0.5% PV by 2020

NJ: 2.12% solar electric by 2021

AZ: 4.5% customer-sited DG by 2025 

(half from residential)

NY: 0.1542% customer-sited DG by 2013

CO: 0.8% solar electric by 2020 

(half from customer-sited projects)

1.25x multiplier for in-state projects

3x multiplier for co-ops and munis

for solar installed before July 2015

DC: 0.386% solar electric by 2021

1.1x multiplier for solar 2007-09

WA: 2x multiplier for DG

NM: 4% solar electric by 2020, 

0.6% DG by 2015

DE: 2.005% PV by 2019 

3x multiplier for PV installed 

before 2015

MD: 2% solar electric by 2022

Set-aside

Multiplier

NC: 0.2% solar by 2018

NH: 0.3% solar electric by 2014

Set-aside with multiplier TX: 2x multiplier for all non-wind

Figure 8. Differential Support for Solar Energy in State RPS Policies 

 

17 In addition to deciding which of these mechanisms to use, states seeking to support solar within an RPS must also 

address issues of eligibility (Are all forms of solar electricity eligible? Are customer-sited generators eligible?); 

measurement (Are metering and tracking systems in place?); and REC ownership and trading (Do owners of solar systems 

own their RECs? Do mechanisms exist to trade small quantities of RECs?). 
17 Renewables Portfolio Standards in the United States 

 Among those states with solar or DG set-asides, two are restricted to photovoltaic (PV) 

applications, nine also allow solar-thermal electric technologies to qualify, three allow solar heating 

and/or cooling to qualify18, and three states have DG set-asides in which solar PV can compete with 

other forms of renewable DG (see Table 5). The policies also differ in their targets and timeframes, 

geographic scope of project eligibility, use of cost caps and alternative compliance mechanisms, and 

degree of regulatory oversight over solar contracting. Many of these set-asides have yet to take effect; 

only Arizona, Nevada, and New Jersey have three or more years of operational experience. 

Table 5. Design Elements of State Solar and DG Set-Asides 

Resource Eligibility 

State First Compliance 

Year Photovoltaics Solar Thermal 

Electric 

Solar Heating 

and/or Cooling 

Non-PV Dist. 

Generation 

Arizona 2001 ● ● ● ●

Colorado 2007 ● ●

Delaware 2008 ●

Maryland 2008 ● ●

Nevada 2003 ● ● ●

New Hampshire 2010 ● ●

New Jersey 2004 ● ●

New Mexico 2011 ● ● ●

New York 2006 ● ●

North Carolina 2010 ● ● ●

Pennsylvania 2006 ●

Washington D.C. 2007 ● ●

 Despite their nascent state, solar and DG set-asides, in combination with state and Federal 

incentives, have already begun to have a significant impact on the grid-connected PV market in the 

United States, as shown in Figure 9. Overall, New Jersey has been the largest solar set-aside-driven 

PV market in the United States since 2000, although Nevada and Colorado emerged as equallysignificant solar set-aside markets in 2007. Additional contributions to grid-connected PV additions 

in states with solar set-asides have come from Arizona and, more recently, New York. In total, from 

2000 through 2007, 102 MW of grid-connected PV capacity was added in states with solar set-asides, 

representing 22% of all grid-connected PV installations in the U.S. over this period, and 75% of all 

grid-connected PV additions outside of California, the country’s largest market.19 

 The impact of solar and DG set-asides is not restricted to PV. In fact, the nation’s only two solarthermal electric plants built since 1991 – a 1 MW facility in Arizona commissioned in 2006 and a 64 

MW plant in Nevada commissioned in 2007 – have been motivated by solar set-asides. More 

generally, solar-thermal electric development does not, in some states, appear to require a solar setaside. In California, for example, a number of such projects are in development, driven by a moretraditionally designed RPS, without a solar set-aside (see Table 6). 

 

18 In addition to Arizona, Nevada, and North Carolina, which allow solar heating and/or cooling to qualify for their 

solar/DG set-asides, a number of other states allow solar heating and/or cooling to qualify for their overall RPS target, 

including: Delaware, Hawaii, Illinois, New Hampshire, Pennsylvania, and Texas. 

19 California’s RPS, which lacks a solar set-aside, has resulted in 15-29 MW of utility-scale PV contracts for projects not 

yet constructed (range reflects expansion options). Separately from the RPS, California has also enacted aggressive 

financial incentive programs that intend to support 3,000 MW of customer-sited solar PV by 2017, and that have already 

spurred more than 300 MW of grid-connected PV capacity from 2000-2007. 
18 Renewables Portfolio Standards in the United States 

0

10

20

30

40

50

60

70

2000 2001 2002 2003 2004 2005 2006 2007

Annual Grid-Connected PV Installations in RPS 

States with Solar or DG Set-Asides (MW)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Percent of Annual Grid-Connected 

PV Installations in the US (%)

Delaware

Maryland

District of Columbia

Pennsylvania

Colorado

Nevada

New York

Arizona

New Jersey

Percent of annual US PV 

installations [right axis]

Percent of annual US PV installations 

(excluding California) [right axis]

Figure 9. Annual Grid-Connected PV Installations in RPS States with Solar or DG Set-Asides20 

Table 6. Status of Utility-Scale Solar-Thermal Electric Facilities Proposed in the U.S. 

Power Purchaser Developer State Project Size Status Motivation 

Nevada Power Acciona Nevada 64 MW Operational Solar set-aside 

Arizona Public Service Acciona Arizona 1 MW Operational Solar set-aside

Pacific Gas & Electric Solel California 554 MW Contracted General RPS 

Pacific Gas & Electric Ausra California 177 MW Contracted General RPS 

Pacific Gas & Electric BrightSource California 500 – 900 MW Contracted General RPS 

Southern California Edison Stirling Energy Systems California 500 – 850 MW Contracted General RPS 

San Diego Gas & Electric Stirling Energy Systems California 300 – 900 MW Contracted General RPS 

San Diego Gas & Electric Bethel California 49 MW Contracted General RPS 

San Diego Gas & Electric Bethel California 49 MW Contracted General RPS 

Arizona Public Service Abengoa Arizona 280 MW Announced General RPS 

Florida Power & Light Ausra Florida 10 – 300 MW Announced Not stated 

Notes: Table does not include facilities announced by developers, unless a purchaser of the power has been identified. In addition to the specific facilities 

listed here, a number of utilities in the Southwest have issued a 250 MW RFP for central station solar power, and Colorado’s major IOU (Xcel Energy) 

has announced preliminary plans for a 200 MW facility. 

 

 The impacts of RPS solar set-asides on solar development will continue to grow as a greater 

number of the existing set-asides take effect and as targets increase over time. Figure 10 and Table 7 

present Berkeley Lab estimates of the solar electric capacity (including PV and solar thermal electric) 

that would be required to fully achieve existing state solar and DG RPS set-aside policies. Changes in 

Federal tax incentives, binding RPS cost caps, force majeure events, and other barriers will – in reality 

 

20 PV installation data from 2000-07 were provided by Larry Sherwood (Interstate Renewable Energy Council). For the 

purpose of assigning state PV installations to set-asides, the data above include installations in the year before the first setaside compliance date. Data are presented in direct-current units, at Standard Test Conditions. 
19 Renewables Portfolio Standards in the United States 

– challenge the full achievement of these policies.21 As such, the estimates presented here should be 

considered a reasonable, if uncertain, estimate of the potential impact of these set-asides under an 

aggressive assumption of full compliance. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

200820092010201120122013201420152016201720182019202020212022202320242025

Cumulative Solar Capacity (MW)

0

100

200

300

400

500

600

700

800

Annual Solar Additions (MW)

AZ

NJ

MD

PA

NM

NC

DE

NV

CO

DC

NH

NY

Annual Capacity (right axis) Cumulative Capacity 

(left axis)

Figure 10. Solar Capacity Required to Meet Existing State RPS Solar and DG Set-Asides22

 Even with these caveats, the estimates presented here demonstrate the potential importance of these 

set-asides for the solar market in the coming decades. As shown, a cumulative 550 MW of solar 

capacity may be required by these policies by 2010, growing to approximately 2,200 MW by 2015, 

5,300 MW by 2020, and 6,700 MW by 2025. Annual solar additions on the order of 100 MW may be 

required from 2008 through 2010, rapidly ramping up to nearly 300 MW a year from 2011 through 

2014, and then to over 500 MW a year from 2015 to 2021, if full compliance is to be achieved. 

 The largest set-aside driven solar markets in the long-term, based on required capacity to fully meet 

state targets, are projected by Berkeley Lab to include Arizona, New Jersey, Maryland, and 

Pennsylvania. In the next several years, however, significant growth in solar capacity will also be 

required in New Mexico, Nevada, and Colorado. Finally, as a proportion of expected statewide load 

in 2025, these set-aside policies are projected to require solar generation shares as high as 3.1% in 

New Mexico, and 2% or more in Arizona, Maryland, and New Jersey again assuming that full 

compliance is achieved. 

 

21 Actual impacts will be affected not only by whether full compliance is achieved, but also by future load growth, the 

competitiveness of solar energy in broader DG set-asides, the relative contribution of different types of eligible solar 

technologies, and other factors. 

22 Berkeley Lab developed these estimates using a number of input assumptions regarding expected load growth, capacity 

factors, compliance exemptions, the share of solar used to meet broader DG obligations, the share of PV and solar-thermal 

electric used to meet solar requirements, and other factors. Data are presented in direct-current units, at Standard Test 

Conditions. 
20 Renewables Portfolio Standards in the United States 

 Achieving these targets is not 

assured, however, and a number 

of policy design issues may 

constrain the market’s growth. 

States have developed various 

types of cost caps, for example, 

many of which may ultimately 

become binding, thereby 

limiting future solar market 

expansion to levels below those 

estimated here. 

 Additionally, some states – 

especially those in which retail 

electric competition exists – 

continue to struggle with how to 

encourage appropriate 

contracting for solar generation, 

given the political risk of future 

policy changes. In 2007, New 

Jersey sought to address this 

concern by developing plans to 

transition away from a rebatebased solar market and towards 

a market primarily supported by 

solar renewable energy credits. 

To provide some encouragement 

for longer-term REC contracting, New Jersey established, in advance, an eight-year schedule for solar 

alternative compliance payment (ACP) levels, thereby removing at least some market uncertainty. 

Other states, such as Maryland, North Carolina, Colorado, and Nevada, simply require long-term 

contracting for solar energy or RECs. Alternatively, or in addition, some states have mandated or 

encouraged the use of up-front financial incentives, at least for smaller-scale PV systems (and 

sometimes for larger commercial installations as well); this is true in Colorado, Nevada, Arizona, New 

Jersey, New York, and Maryland. 

Compliance with State RPS Mandates Has Been Strong in 

General, Though Important Exceptions Exist 

 So far at least, early-year renewable energy targets in the majority of state RPS policies have been 

fully or almost-fully achieved. “Compliance” is defined here as the application of renewable 

electricity or RECs towards RPS targets, including the use of available credit multipliers, but 

excluding any use of ACPs.23 Using this definition, of the 14 states with RPS compliance obligations 

 

23 Note that the definition of “compliance” used here is not the same as that used by individual states. This report focuses 

on the delivery and retirement of renewable electricity or RECs for use in a given compliance year (including RECs that 

are delivered in previous or subsequent years, as long as they are used to meet current-year compliance, as well as credit 

Table 7. Cumulative Solar Required to Meet State RPS Solar 

and DG Set-Asides 

State 2010 

Capacity 

2025 

Capacity 

2025 Solar Generation

as a % of State Load

Arizona 110 MW 1,600 MW 2.0% 

Colorado 29 MW 160 MW 0.4% 

Delaware 0.5 MW 190 MW 1.4% 

Maryland 14 MW 1,500 MW 2.0% 

Nevada 76 MW 180 MW 0.6% 

New Hampshire 4 MW 35 MW 0.3% 

New Jersey 210 MW 1,600 MW 2.1% 

New Mexico 64 MW 420 MW 3.1% 

New York 10 MW 15 MW 0.0% 

North Carolina 5 MW 280 MW 0.2% 

Pennsylvania 25 MW 690 MW 0.5% 

Washington D.C. 0.5 MW 54 MW 0.4% 

Total 550 MW 6,700 MW n/a 

Note: Data are presented in direct-current units, at Standard Test Conditions 
21 Renewables Portfolio Standards in the United States 

in 2006 for which data were available, nine states achieved compliance levels of greater than 95%, 

(see Table 8). These states include California, Iowa, Maryland, Maine, New Jersey, New Mexico, 

Pennsylvania, Texas, and Wisconsin. Moreover, the weighted-average compliance level (weighted by 

the level of compliance obligation) across all 14 states for which data were available was 94% in 

2006, compared to 96% in 2005 (12 states), 94% in 2004 (11 states), and 86% in 2003 (9 states).

 Nonetheless, it is also evident that a number of states have struggled to meet even their early-year 

RPS targets. In Arizona, for example, compliance has been well below 50% since 2003, even after 

accounting for credit multipliers. This is because RPS targets in that state have historically had to be 

met only to the extent that pre-specified funding amounts were sufficient to achieve compliance; in 

point of fact, funding levels have been insufficient. In Massachusetts, on the other hand, eligible 

RECs have been in short supply, in part because of a difficult project development climate in the New 

England region. For similar reasons, Connecticut also experienced a slight REC shortage in 2006, 

though much less severe than in Massachusetts due to different resource eligibility rules. Minnesota’s 

statewide RPS, which began in 2005, achieved 94% “compliance” in that year, but because Xcel’s 

mandate for additional biomass and wind capacity (beyond that required for the statewide RPS) was 

not strictly achieved on schedule, overall compliance levels (including both the statewide RPS and 

Xcel’s incremental renewable capacity mandates) averaged 61-81% from 2002 through 2005. Nevada 

has struggled with RPS compliance for a variety of reasons, including contract failures and project 

delays, as well as changing regulatory treatment of REC transfers among the state’s two major 

utilities. Finally, New York’s first-year RPS target was missed by a wide margin, in large part 

because of a modest delay in the on-line date of one of the state’s largest new renewable energy 

facilities, and in part due to REC prices that were higher than initially anticipated and budgeted. 

 The few states with obligatory solar set-asides in 2006 or earlier have had mixed success in 

meeting those requirements (see Figure 11). In Arizona, for example, just 23% of the solar set-aside 

in 2006 was met by solar energy deliveries (even after accounting for credit multipliers), due in large 

measure to insufficient funding levels. In Nevada, solar REC retirements in 2006 were only 9% of the 

solar target (again, accounting for multipliers), an increase from just 2% in 2004 and 2005. The 

addition of a 64 MW solar-thermal electric project and nearly 15 MW of PV in 2007 should 

dramatically improve the compliance of Nevada’s utilities in the years ahead. New Jersey, 

meanwhile, achieved 96% compliance with its solar set-aside in 2006 through solar deliveries, down 

from 98% in 2005, but up from just 54% in 2004. Pennsylvania achieved 100% compliance with its 

first-year solar set-aside in 2006, but that requirement was so small as to be effectively meaningless 

(the solar REC retirement obligation in the 2006 compliance year was equivalent to just 5-10 

residential PV installations, due to the limited amount of load with RPS obligations in that period). 

 multipliers). In so doing, these data ignore the possible use of ACPs as well as certain other compliance flexibility 

mechanisms. 
22 Renewables Portfolio Standards in the United States 

Table 8. Application of Renewable Electricity and/or RECs Towards RPS Targets, 

State 1999 2000 2001 2002 2003 2004 2005 2006 

AZ - - 89% 64% 31% 31% 26% 25% 

CA - - - - - 100% 100% 98% 

CT - no data no data no data no data 100% 100% 93% 

HI - - - - - - 100% - 

IA 100% 100% 100% 100% 100% 100% 100% 100% 

MA - - - - 100% 65% 64% 74% 

MD - - - - - - - 100% 

ME - 100% 100% 100% 100% 100% 100% 100% 

MN - - - 61% 72% 72% 81% no data 

NJ - - 100% 100% 100% 100% 100% 100% 

NM - - - - - - - 100% 

NV - - - - 31% 30% 95% 39% 

NY - - - - - - - 52% 

PA - - no data no data - - - 100% 

TX - - - 99% 96% 99% 99% 100% 

WI - 40% 100% 100% 100% 100% 100% 100% 

Weighted 

Average 100% 98% 100% 90% 86% 94% 96% 94% 

blank cells = no compliance obligation existed in that year 

no data = unable to obtain compliance data for that year 

Notes: 

• Arizona – data for 2001-2004 come from an ACC staff report and, after 2004, directly from compliance reports provided by the 

state’s electric utilities; 2006 data were unavailable from one of the state’s IOUs. 

• California – data come from the CEC and from self-reported information, and include the state’s major IOUs, and, starting in 2006, 

ESPs; data from small IOUs are excluded (because compliance rules have not been established) as are data from the state’s POUs 

(because yearly RPS targets are often unstated). 

• Connecticut – data were unavailable for 2000-2003, during which time RPS obligations applied only to non-standard-offer load, 

which represented less than 2% of statewide retail sales in those years. 

• Hawaii – RPS obligations under previous legislation existed in 2005, but subsequent legislation removed the 2005 obligation and

established a new RPS schedule that begins in 2010. 

• Maine, Maryland, New Jersey – compliance figures are based on emails from state RPS administrators, not based on a review of 

compliance filings. 

• New Jersey – compliance data for 2001-2003 are on a calendar year basis; beginning in 2004, compliance data are for annual periods 

beginning June 1st, which for the purpose of the table, are assigned to the starting year of the annual compliance period. 

• Minnesota – prior to 2005, data presented here only include Xcel’s wind and biomass mandates; in 2005, data include the overall

statewide renewable energy obligation and Xcel’s wind and biomass mandates, and 2005 compliance data are for the year beginning

July 1, 2005; 2006 data are not yet available. 

• Nevada – the large increase in compliance in 2005 resulted from the sale of excess non-solar RECs by Sierra Pacific to Nevada 

Power; Sierra Pacific has generated a substantially greater number of non-solar RECs in each year than required for its RPS target; 

the Nevada PUC allowed Sierra Pacific to sell excess non-solar RECs generated in 2004 and 2005 to Nevada Power, which the latter 

retired for compliance in 2005; in 2006, the utilities again requested that Sierra Pacific be allowed to sell non-solar RECs to Nevada 

Power, but the PUC did not grant this request, and thus Nevada Power fell far short of its RPS target. 

• Pennsylvania – data were unavailable for 2001-2002, during which time RPS obligations applied only to Competitive Default Service 

load (default service provided by a competitive supplier), which represented less than 1% of statewide retail sales in those years; 2006 

compliance data are for the compliance period beginning June 1, 2006. 

• Wisconsin – before 2001, the RPS was a 50 MW renewables capacity requirement on a subset of electric utilities. 

 
23 Renewables Portfolio Standards in the United States 

0%

20%

40%

60%

80%

100%

2001 2002 2003 2004 2005 2006

Solar Retirements as % of

Solar Set-Aside Target 

Weighted Average

Arizona

New Jersey

Nevada

Pennsylvania

Figure 11. Application of Solar Electricity and/or Solar RECs Towards Solar Set-Aside Targets

 Because states have developed differing compliance enforcement and flexibility mechanisms (see 

Text Box 1), one should not assume that lack of compliance, as defined here, automatically leads to 

enforcement actions. In some of the states listed as not achieving full compliance, alternative 

compliance payments (ACPs) are allowed and have been made to avoid enforcement action (funding 

collected from these payments is typically recycled to support renewable energy – and/or energy 

efficiency – through other means). This is true in Massachusetts and New Jersey (where the shortfalls 

in REC retirements have been fully met with ACPs) and, to a much lesser extent, in Maryland.24 As a 

result, in 2006, $18.2 million was paid in the form of ACPs: 97.6% from Massachusetts, 2.2% from 

New Jersey, and 0.2% from Maryland. 

 In still other cases, such as California, opportunities to “make-up” purchase shortfalls exist, 

ensuring that any enforcement actions will not occur for several years after a given compliance year. 

In Arizona and New York, funding limitations can curtail compliance. Finally, a number of states 

offer compliance waivers on a discretionary basis; this is why, for example, Nevada’s utilities have 

not been penalized, despite a long history of under-compliance, and Minnesota’s utilities have 

likewise faced no penalties. 

 In part as a result of these factors, explicit enforcement actions have been taken in only two states 

so far: Connecticut and Texas. In Connecticut, lack of compliance in 2006 resulted in $5.6 million in 

penalties (though Connecticut uses the term ACP, these payments are defined as penalties here, 

because they are not automatically recoverable in rates). In Texas, two competitive ESPs were 

penalized a total of $4,000 in 2003 for lack of RPS compliance, while in 2005 two other ESPs were 

penalized $28,000.25 In sum, enforcement actions have – up to now – been infrequent. 

 

24 Though Table 8 suggests no REC shortfalls in Maryland and New Jersey in 2006, in fact renewable deliveries in these 

two states were 99.87% and 99.95%, respectively. 

25 Although not a non-compliance penalty per se, the two Nevada IOUs agreed to make a $30,000 donation to the Desert 

Research Institute, not recoverable in rates, as part of the stipulation to its 2005 RPS compliance filing. 
24 Renewables Portfolio Standards in the United States 

The Use of Renewable Energy Certificates and Certificate 

Tracking Systems Is Expanding 

 Reliance on unbundled RECs for state RPS compliance has often gone hand-in-hand with the 

development of regional certificate tracking systems. Although several states have allowed RECs and 

relied on (manual) attestations and contract audits, states are increasingly using electronic certificate 

tracking systems to issue, record, track, and retire RECs. 

 The year 2007 saw the completion of two new regional tracking systems—the Western Renewable 

Energy Generation Information System (WREGIS) and the Midwest Renewable Energy Tracking 

System (M-RETS). WREGIS serves the Western Electricity Coordinating Council (WECC), 

including 11 U.S. states, two Canadian provinces, and part of the Mexican state of Baja California. MText Box 1. State RPS Compliance Enforcement 

States use a variety of enforcement options to ensure that RPS targets are met. The most popular option in 

states that allow retail competition is an alternative compliance payment. If recoverable in rates, an ACP 

is a means of complying with an RPS – rather than procuring renewable generation or RECs – that 

effectively makes the need for explicit penalties moot (unless an LSE fails to comply through the ACP as 

well). In states that maintain vertically integrated electric utilities, on the other hand, enforcement most 

typically occurs through explicit or discretionary financial penalties. Other forms of RPS enforcement are 

also listed below. Though not shown here, it deserves note that a number of states allow LSEs to petition 

for an exemption from penalties under certain circumstances. 

Penalties for Non-Compliance States Notes 

ACP, Automatic Cost Recovery MA, ME, 

NH, NJ, RI 

Payments generally go to a renewable energy fund; if failure to pay 

ACP, remedies can include license suspension or revocation and/or 

financial penalties; ME ACP applies only to new renewables target 

ACP, Possible Cost Recovery DE, MD, OR, 

DC 

Cost recovery sometimes only allowed if ACPs are deemed to be the 

least-cost compliance option; payments generally go to a renewable 

energy fund; if failure to pay ACP, remedies can include license 

suspension or revocation and/or financial penalties 

Explicit Financial Penalties, No 

Automatic Cost Recovery 

CA, CT, MT, 

PA, TX, WA, 

WI 

CA, CT, MT, PA, TX, WA: penalty in $/MWh applies to shortfall; 

WA: penalty may, in some circumstances, be recoverable in rates; WI: 

penalty ranges from $5,000 to $500,000; suppliers often given 

opportunity to petition for a waiver 

Discretionary Financial Penalties, 

No Cost Recovery 

AZ, CO, HI, 

MN, NV 

Financial penalties assessed at the discretion of the PUC; penalties can 

be waived with sufficient cause; in MN, PUC can order renewable 

investment and can impose financial penalties 

Enforcement at PUC Discretion NC, NM PUC has legislative authority to enforce compliance, but no rules have 

been established to document how this will occur 

Not Applicable IA, IL, NY IL and NY rely on administrative agencies to procure renewables on 

behalf of LSEs; IA RPS has already been fully met 
25 Renewables Portfolio Standards in the United States 

RETS serves Wisconsin, Minnesota, Iowa, South Dakota, North Dakota, the province of Manitoba, 

and parts of Montana and Illinois.26 New and existing tracking systems are shown in Figure 12. 

Figure 12. Electronic Certificate Tracking Systems and Year of Initiation

 WREGIS and M-RETS are similar to the first electronic certificate tracking system developed by 

the Electric Reliability Council of Texas (ERCOT), in that they issue and track certificates only for 

renewable generation. In addition, WREGIS and M-RETS certificates may – in theory – be used at 

any time because they do not have an expiration date. This is in contrast to the New England Power 

Pool’s Generation Information System (GIS) and the PJM Generation Attributes Tracking System 

(GATS), which both issue certificates to all generation and then settle those certificates on a regular 

schedule to support a variety of different policies. Prior to the operation of GATS, New Jersey 

developed, and continues to operate, a separate tracking system for Solar RECs and “Class I” RECs 

from onsite customer generation. 

 New York, which manually tracks bundled energy and attributes, is currently working to develop 

an electronic system that will issue and track unbundled certificates. For the remaining states without 

a tracking system, APX, Inc., a private service provider, has announced that it will make available a 

certificate tracking system (not shown in Figure 12). 

 With the increased availability of formal certificate tracking systems, most RPS states have opted 

to allow – with restrictions – the use of unbundled RECs for compliance purposes.27 As shown in 

Figure 13, the exceptions are: Iowa, which adopted its RPS long before RECs existed and which has 

satisfied its requirement; Arizona and Hawaii, which do not currently allow the use of unbundled 

RECs; and California, which will rely on WREGIS but has not yet approved the use of unbundled 

RECs. 

 

26 Because it is bisected by different control areas, Montana is served in part by WREGIS and in part by M-RETS. 

Similarly, Illinois is served in part by M-RETS and in part by GATS. Wisconsin previously operated its own tracking 

system for Renewable Resource Credits, but its program is now supported by M-RETS. 

27 See Holt, E. and R. Wiser. 2007. The Treatment of Renewable Energy Certificates, Emission Allowances, and Green 

Power Programs in State Renewables Portfolio Standards. Berkeley, Calif.: Lawrence Berkeley National Laboratory. 

Operational

Under Development

WREGIS

2007

M-RETS

2007

GATS

2005

GIS

2002

ERCOT

2001

Operational

Under Development

WREGIS

2007

M-RETS

2007

GATS

2005

GIS

2002

ERCOT

2001
26 Renewables Portfolio Standards in the United States 

Figure 13. Treatment of Unbundled RECs for State RPS Compliance

 Although RECs are now widely used as the preferred means of demonstrating RPS compliance, 

REC definitions are not uniform. States have defined RECs differently—based on differing eligible 

resource definitions, different generator vintages, limitations on generator location and electricity 

delivery, and whether or not emissions credits, if any, must be retired with the REC for RPS 

compliance. As a result, there are multiple state and regional markets for RECs, and fungibility across 

RPS markets is limited. 

 Typical REC contracting practices also vary considerably across states. Some state RPS markets 

have primarily encouraged short-term trade in unbundled RECs. This is most-often the case in states 

where retail choice is allowed and therefore the future load obligations of individual LSEs are more 

uncertain, and where electric utilities are no longer directly in the business of electricity supply. Other 

markets have relied on a mix of short-term and longer-term purchases, where long-term purchases 

might be for unbundled RECs or RECs bundled with the underlying electricity supply. Finally, in 

states in which retail competition is not allowed and regulators retain oversight over utility supply 

decisions, electric utilities largely rely on long-term contracts for RECs that remain bundled with 

electricity; such contracts are often required by state policy (see Text Box 2). 

REC Prices Have Been Highly Variable Across States 

 Renewable energy certificate markets remain fragmented in the U.S. Figure 14 and Figure 15 

present indicative monthly data on spot-market REC prices in compliance markets, i.e., states in 

which RECs are sold to meet state RPS obligations. Figure 14 reports data on “main tier” or “Class I” 

REC prices, while Figure 15 reports data on REC prices under “Class II” or “existing tier” RPS 

requirements – typically consisting of existing hydropower, biomass, and MSW projects. These data 

were obtained from Evolution Markets, and exclude markets for which transparent spot-market REC 

pricing is not available.28 

 

28 Some care should be taken in using these data, however, because bilateral trade in RECs and longer-term REC contracts 

are not fully captured in the Evolution Markets data, and because liquidity is limited in many states. 

Unbundled RECs allowed

Unbundled RECs not 

currently allowed
27 Renewables Portfolio Standards in the United States 

$0

$10

$20

$30

$40

$50

$60

Jan-03

Apr-03

Jul-03

Oct-03

Jan-04

Apr-04

Jul-04

Oct-04

Jan-05

Apr-05

Jul-05

Oct-05

Jan-06

Apr-06

Jul-06

Oct-06

Jan-07

Apr-07

Jul-07

Oct-07

Jan-08

Average Monthly REC Prices (Nominal $/MWh)

$0

$50

$100

$150

$200

$250

$300

NJ Solar - Average Monthly REC Prices (Nominal $/MWh)

CT Class I (left axis) DC Class I (left axis)

MA (left axis) MD Class I (left axis)

NJ Class I (left axis) PA (left axis)

RI New (left axis) TX (left axis)

NJ Solar (right axis)

Figure 14. REC Prices in RPS Compliance Markets (Main Tier and Class I) 

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

Jan-03

Apr-03

Jul-03

Oct-03

Jan-04

Apr-04

Jul-04

Oct-04

Jan-05

Apr-05

Jul-05

Oct-05

Jan-06

Apr-06

Jul-06

Oct-06

Jan-07

Apr-07

Jul-07

Oct-07

Jan-08

Average Monthly REC Prices (Nominal $/MWh)

CT Class II

DC Class II

DE Existing

MD Class II

ME Existing

NJ Class II

Figure 15. REC Prices in RPS Compliance Markets (Existing Tier and Class II) 

 Though not a comprehensive picture of all states, the figures clearly indicate that spot REC prices 

have varied substantially across regions and resource types, and that significant price fluctuations are 

even possible within a particular state over time. Key trends in 2007 include continued high prices to 
28 Renewables Portfolio Standards in the United States 

serve the Massachusetts RPS, dramatically increasing prices under the Connecticut Class I RPS and, 

more recently, a large spike in the price for Class I certificates under the New Jersey RPS. Class I 

REC prices in Connecticut have shown particularly striking swings, largely reflecting policy changes 

in resource eligibility rules over time. New Jersey’s Class I REC prices rose partly because that 

state’s renewable energy targets are increasing and partly because the growth in RPS requirements in 

the PJM region is placing greater competition on available supply. The sudden spike and then (moremodest) drop in prices may also have reflected, to some degree, an (incorrect) belief that supply was 

severely limited and/or hoarding of RECs by some parties. Prices trended downwards in Texas, 

Maryland (Class I), and Washington D.C. (Class I) due to a surplus of eligible renewable energy 

supply relative to RPS-driven demand in those markets. New Jersey’s solar RECs, on the other hand, 

continue to fetch more than $200/MWh due to the underlying cost of solar electricity. 

 As shown in Figure 15, prices for “Class II” or “existing tier” RECs remained low, and trended 

downwards in most markets. Prices in these cases appear to largely reflect transaction (rather than 

supply) costs, since REC supply appears to far exceed REC demand in all of these markets. 

 Concerns have been expressed that REC price variability and uncertainty may limit the ability of 

RPS policies to support renewables investment decisions. As a result, a number of states have adopted 

RPS provisions to help projects secure financing. These efforts are summarized in Text Box 2. 

Text Box 2. Encouraging Project Financing 

Renewable projects are capital intensive, and investors therefore closely examine the long-term energy and 

REC cash flows of a project; projects that have locked-in or hedged their energy or REC prices for at least 

10 years are often viewed more favorably. LSEs, on the other hand, have in some cases decided not to sign 

long-term contracts because they are discouraged or prevented from doing so by regulators (typical for 

default service providers in restructured markets); because their future load requirements are uncertain 

(competitive ESPs); or because their credit may not be strong enough to support such contracts (typically 

competitive ESPs). Uncertain energy and/or REC prices have – in some of these cases – impeded 

renewable project development. In other instances, development has occurred on a quasi-merchant basis, 

but arguably at higher ratepayer cost because investors in such projects require inflated returns to 

compensate for the added risk. To address these barriers, several states have adopted RPS provisions to 

help projects secure financing, as summarized below. 

Contract 

Duration 

Requirement 

CA 

CO 

CT 

IA 

MD 

MT 

NV 

NC 

PA 

RI 

10+ yrs 

20+ yrs 

100 MW, 10+ yrs 

ownership or long-term contract 

solar, 15+ yrs 

10+ yrs 

10+ yrs 

solar, sufficient length to stimulate development 

good faith effort includes seeking long-term contracts 

PUC requires that default utility investigate long-term contracting 

Central 

Procurement 

NY 

IL 

central procurement where NYSERDA purchases attributes under long-term contract 

central procurement in which long-term contracts are likely to be offered 

Credit 

Protection 

NV 

CA 

created program to protect payments to generators from utility credit concerns 

initially exempted utilities from meeting RPS until they became creditworthy 

Renewables 

Fund Support 

MA renewable energy fund created “green power partnership” that offers guaranteed REC purchase or 

option contracts of up to 10 years 
29 Renewables Portfolio Standards in the United States 

The Price Impacts of State RPS Policies Are Not Always 

Observable, But Have Been Modest in Most Cases So Far 

 State RPS policies could have substantial impacts on electricity markets, ratepayers, and local 

economies. Unfortunately, the actual costs (and benefits) of state RPS policies have not been 

compiled in a comprehensive fashion, in part because of the early status of policy implementation and 

in part because of methodological complexities and data availability constraints. Despite these 

limitations, it is reasonably clear that the cost impacts of state RPS policies have varied by state but, at 

the same time, there is little evidence of a sizable impact on average retail electricity rates so far. 

 Translating unbundled REC prices, as well as the renewable electricity contracts that predominate 

in traditionally-regulated states, into retail rate impacts is challenging. Nonetheless, if one assumes 

(a) that REC prices represent the incremental above-market cost of renewable energy, (b) that the 

short-term REC prices presented in Figures 14 and 15 are representative of all RECs used for RPS 

compliance, and (c) that certain state-specific funding caps are binding, then 2007 RPS-induced retail 

rate increases, averaged over all obligated load in each state, can be estimated, as shown in Figure 

16.29 

 Though the results vary across states, in most cases, rate increases are estimated at 1% or less in 

2007. Moreover, the rate impacts shown here may, in some states, be biased upwards due to at least 

two factors: (1) longer-term REC contracts are likely to be priced below the short-term REC prices 

used for these calculations; and (2) the rate estimates presented here ignore the potential impact of 

renewable energy in reducing natural gas and wholesale electricity prices. At the same time, however, 

rate impacts will presumably grow over time as RPS obligations increase, unless REC prices or RPS 

funding levels simultaneously decline. 

0.0%

0.2%

0.4%

0.6%

0.8%

1.0%

1.2%

Maryland

Maine

Washington D.C.

Delaware

Pennsylvania

New York

Rhode Island

New Jersey

Colorado

Arizona

Massachusetts

Connecticut

California

Iowa

Minnesota

Nevada

New Mexico

Texas

Wisconsin

Hawaii

Illinois

Montana

New Hampshire

North Carolina

Oregon

Washington

Estimated Electricity Rate Impact in 2007 (%)

unknown

data not available

not applicable

RPS did not apply in '07

Figure 16. Estimated Rate Impacts of State RPS Policies in 2007

 

29 Rate impacts are estimated on a calendar year basis, using the average compliance obligation during 2007. 
30 Renewables Portfolio Standards in the United States 

 In states where long-term renewable electricity contracts (rather than purchases of unbundled 

RECs) predominate as the mode of state RPS compliance, retail rate impacts are more difficult to 

estimate, due primarily to the confidentiality of contract terms. As such, these states are shown in 

Figure 16 as having “unknown” rate impacts in 2007 (those states listed as “not applicable” had no 

RPS obligation in 2007).30 In a number of these states, however, there is at least some evidence that 

the renewable energy contracted in recent years has been priced competitively with conventional 

sources of generation. In California, for example, the majority of the renewable electricity brought 

under contract by the state’s IOUs since 2002 has been signed at prices that are below the “market 

price referent” – the estimated cost of new gas-fired generation. Anecdotal evidence suggests 

historically low renewable energy prices in many of the other states listed as having “unknown” rate 

impacts in Figure 16 as well. In these instances, it is not clear whether state RPS policies are leading 

to higher, or lower, retail electricity prices.31 

 Notwithstanding these conclusions, it is also evident that renewable electricity prices have 

increased in recent years. Wind power contract prices for projects built in 2006, for example, were 

substantially higher than for projects built from 2000 through 2005.32 At the same time, the cost of 

new gas and coal facilities has also been on the rise, making any long-term “incremental” cost of RPS 

programs difficult to estimate. 

 Given uncertainty about the future costs of RPS policies, state policymakers have developed a 

variety of approaches to limit the maximum impact of these policies on electricity rates, as shown in 

Table 9. Common approaches include alternative compliance payments that can be made in lieu of 

purchasing RECs, direct retail rate caps, renewable energy funding caps, renewable energy contract 

price caps, per-customer electric bill impact limits, and financial penalties that can serve as cost caps 

in certain circumstances. In addition, though not presented here, a number of states have established 

force majeure mechanisms that allow electricity suppliers to limit their renewable energy purchases if 

they are able to persuade regulators that those purchases would unduly raise electricity rates. Where 

calculable, Table 9 also translates the effective cost caps into the maximum possible incremental retail 

rate increase caused by RPS policies, for the year in which the state RPS achieves its highest 

percentage target. Though a sizable range exists, the majority of states have capped incremental rate 

impacts at well below 10%, and in seven states rate impacts are capped at or below 2%. 

 

30 Texas is included among these states. Though short-term REC pricing is transparent in Texas, many electricity suppliers 

have complied with their RPS obligations through long-term, renewable electricity contracts. Short-term REC prices are 

therefore not likely to be a good indicator of rate impacts in that state. 31 Another approach to estimating impacts is to review state RPS cost-impact projections. A Berkeley Lab report 

completed in 2007, for example, provides a summary of 28 state RPS cost-impact projections. See: Chen, C., R. Wiser 

and M. Bolinger. 2007. “Weighing the Costs and Benefits of Renewables Portfolio Standards: A Comparative Analysis of 

State-Level Policy Impact Projections.” Berkeley, Calif.: Lawrence Berkeley National Laboratory. 32 See Wiser, R. and M. Bolinger. 2007. “Annual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 

2006.” Berkeley, Calif.: Lawrence Berkeley National Laboratory. 
31 Renewables Portfolio Standards in the United States 

Table 9. Approaches Used to Cap the Maximum Cost of State RPS Compliance 

ACP 

State Auto. 

Cost Rec. 

Possible 

Cost Rec. 

Retail 

Rate/ 

Revenue 

Req. Cap 

Renewable 

Energy 

Contract 

Price Cap 

PerCustomer 

Cost Cap 

Renewable 

Energy 

Fund Cap 

Financial 

Penalty 

May Serve 

as Cost Cap 

Maximum Effective 

Retail Rate Increase 

AZ ● ● to be determined 

CA ● cap for portion of cost 

CO ● 1.7% 

CT ● 6.5% 

DE ● 16.3% 

HI ● 0.0% 

IA no explicit cap 

IL ● 1.4% 

MA ● 3.3% 

MD ● ● 2.1% 

ME ● 4.8% 

MN no explicit cap 

MT ● 0.1% 

NC ● 1.9% 

NH ● 8.3% 

NJ ● 10.6% 

NM ● ● ● 1.8% 

NV no explicit cap 

NY ● 0.9% 

OR ● ● 4.0% 

PA ● no explicit cap 

RI ● 6.4% 

TX ● 2.1% 

WA ● 4.0% 

D.C. ● 2.5% 

WI no explicit cap 

Notes: Maximum effective retail rate increase represents maximum incremental impact on average retail rates in the worst-case scenario, given various 

cost caps, and assumes that costs will be capped at the ACP, or financial penalty amount in states with active retail electric competition. It is averaged 

across all customers and utilities covered under each state RPS. In New York, the cap represents available funds collected from ratepayers to support 

renewable attribute purchases by NYSERDA, under that state’s current regulations. California’s RPS does have a cap insomuch as certain funding 

limitations exist, but these funding limitations do not allow a clear calculation of rate impacts in percentage terms. Maryland’s retail rate cap only applies 

to that state’s solar set-aside. Maine’s ACP only applies to that state’s new renewables requirement. New Jersey’s maximum rate impact is estimated at 

current ACP levels, and does not reflect the BPU’s recent decision to explore a 2% rate cap on solar incentives; if this 2% cap were considered, then the 

overall maximum rate impact in New Jersey would drop to 8.5%. Legislation in Texas allows the PUC to establish an ACP, but the Commission has 

chosen not to do so. Pennsylvania has a financial penalty, but because the penalty for solar set-aside non-compliance in 2x the market value of solar 

RECs, the penalty does not serve as a cost cap. 
32 Renewables Portfolio Standards in the United States 

States Are Increasingly Recognizing Transmission as a Key 

Limitation to Achieving RPS Targets 

 Transmission has quickly become recognized as among the most prominent barriers to the 

achievement of state RPS targets. The California Energy Commission, for example, has indicated that 

it does not expect the three California IOUs to meet the state’s 20% RPS by 2010, in part because of 

insufficient transmission. Nevada Power has said that, in the long-term, it will not be able to meet the 

Nevada RPS without a transmission line to connect Nevada Power to Sierra Pacific Power Company, 

and a Governor’s Advisory Committee in 2007 recommended that such a line be built and began the 

process of identifying transmission investments to support renewable energy. New Hampshire 

enacted legislation in 2007 requiring its PUC to conduct a study on expanding transmission in the 

state for renewable energy. And the North American Electric Reliability Corporation has indicated 

that state RPS requirements should be associated with investment in additional transmission. 

 In response to the transmission challenge, states and grid operators are increasingly taking moreproactive steps to encourage transmission investment, often within the context of growing state RPS 

obligations. Several examples of these initiatives are presented below. 

• Texas: A revision of the state’s RPS in 2005 directed the Public Utility Commission of Texas to 

create competitive renewable energy zones (CREZ), defined as areas of high-quality clean energy 

resources. The amended Texas RPS also authorized the PUC to order a utility to construct or 

expand transmission to meet the Texas RPS and required the PUC to approve RPS-related 

transmission applications expeditiously. In October 2007, the PUC issued an interim order 

designating five CREZ areas in west and north Texas that could stimulate the development of 

22,806 MW of wind power. ERCOT has recently completed a transmission optimization study to 

determine the optimal transmission layout for the proposed CREZs. Once the CREZ designation 

is final, the utility or utilities servicing those areas have one year to file an application for new 

transmission with the PUC.33 

• Colorado: Legislation was enacted in January 2007 modeled, to some degree, after the Texas 

CREZ approach. That legislation requires utilities to submit biennial reports designating energy 

resource zones (ERZs), identifying transmission plans for accessing the ERZs, and discussing 

potential strategies for using transmission to encourage local ownership of renewable energy 

projects. Along with the biennial reports, utilities must submit applications for certificates of 

public convenience and necessity (CPCN) for the identified ERZ areas. Subject to annual 

adjustment, utilities may recover planning, development, and construction costs for permitted 

transmission facilities via a rate adjustment clause. In October 2007, Xcel Energy identified four 

potential ERZ areas, and submitted a CPCN application for a 345 kV line in northeastern 

Colorado.34 

• California: The ISO received FERC approval for a new transmission interconnection category 

for location-constrained resources such as renewable energy facilities in late 2007. Once a 

resource area has been identified, transmission would be built in advance of generation being 

developed, and costs would be initially recovered through the California ISO transmission charge. 

 

33 Non-incumbent utilities may also be allowed to be involved in transmission to CREZs. 

34 In February 2008, Xcel Energy reached a settlement with interveners to submit CPCN applications for new transmission 

facilities in all four ERZ areas by March 2009. 
33 Renewables Portfolio Standards in the United States 

Once new generation comes on-line to use the transmission path, each generator would pay a pro 

rata share of the transmission costs. A variety of criteria would have to be met for an area to be 

treated in this fashion. Separately, California’s RPS allows the PUC to approve transmission or 

generation tie-lines that are needed for LSEs to meet the RPS and for which cost recovery is not 

otherwise available. A variety of other transmission-related initiatives are also underway in the 

state, including: (1) development and construction of transmission facilities to access more wind 

power in the Tehachapi area; (2) evaluation of transmission options to access renewable energy in 

the Imperial Valley; (3) initiation of a multi-agency Renewable Energy Transmission Initiative to 

help define renewable energy zones in and around the state, and to prepare transmission plans for 

those zones; and (4) utility recovery of costs to study the feasibility of different transmission 

investments to access renewable energy, and to recover project-level interconnection study costs. 

• Minnesota: The state has a relatively long history of planning for and developing new 

transmission for renewable resources, particularly wind. For example, in approving the merger of 

Northern States Power and New Century Energies that created Xcel Energy in 2000, the PUC 

ordered that four new transmission lines be placed into service by 2006 to access wind energy 

resources, and that an 825 MW requirement for wind be accelerated to 2006. Minnesota’s RPS, 

meanwhile, requires utilities to file five-year transmission plans necessary to meet the state’s RPS 

targets, and for those plans to be developed in conjunction with the Midwest ISO. In November 

2007, the utilities filed a joint report stating that transmission is adequate to meet the RPS 

requirements through 2010 and, with some 115 kV additions, through 2012. More transmission 

will be necessary, though, to meet the 2016 RPS requirement. 

 In addition to these initiatives, seven states have formed transmission infrastructure authorities to 

issue revenue bonds for new transmission. New Mexico’s transmission infrastructure authority, 

created in 2007, is authorized to support only transmission projects that transmit at least 30% 

renewable energy. Colorado’s transmission infrastructure authority, also created in 2007, is intended 

to support projects for the production, transportation, transmission, equipment manufacturing, and 

storage of clean energy.35 Though Colorado’s authority is allowed to support non-clean energy 

projects, this allowance is severely limited; for a transmission project, the primary purpose must be to 

transmit clean energy. In the other five states of Kansas, Wyoming, North Dakota, South Dakota, and 

Idaho the infrastructure authorities have broad authority to help support transmission infrastructure, 

and are not limited to clean energy investments. 

 

35 Clean energy is defined as: biodiesel; biomass; landfill gas; ethanol; non-fossil-fueled fuel cells; zero-emissions 

generation technology; renewables including (but not limited to) solar, wind, and geothermal; and certain clean coal 

demonstration technologies. 
34 Renewables Portfolio Standards in the United States 

Federal RPS Policies Received Consideration in the U.S. 

Congress in 2007 

 The U.S. Congress has considered a number of Federal RPS proposals in the House of 

Representatives and the Senate. These proposals typically contain certain common design features, 

including: a renewable production target and schedule; a range of qualifying technologies; tradable 

RECs and price caps; exemptions for certain classes of retail electricity suppliers; and sunset 

provisions. Though the various proposals have had common design elements, the specifics vary 

significantly. 

 A Federal RPS has passed the U.S. Senate on three occasions since 2002. In August 2007, the 

House of Representatives passed a Federal RPS for the first time, as an amendment to a larger energy 

bill, by a 220-190 vote. The U.S. Senate, however, was unable to break a filibuster to include the RPS 

in the final energy bill. The House-approved RPS would have required certain retail electric suppliers 

to include 15% renewable resources in their electricity mix by 2020. Up to 4% of the requirement 

could have been met through energy efficiency investments. 

Conclusions 

 The popularity of state-level RPS policies has grown. With 26 RPS policies now in existence in 

the U.S., covering 46% of the nation’s electrical load, the importance of these programs is expected to 

build over the coming decade. States without an RPS are continuing to consider its adoption, and if 

experience is any guide, even more states are likely to be added to the RPS roster in 2008. 

 In the meantime, it is clear that state RPS policies can be designed in a variety of ways, and that 

implementation experience has been mixed. Comparative experience from states that have and have 

not achieved substantial renewable generation growth highlight the importance of policy design 

details. As a result, as further experience and lessons learned are gained, states with existing RPS 

programs are likely to continue to tinker with their design. Some of this may occur through scheduled 

reviews of existing RPS policies, while other changes may proceed through the normal legislative 

process. An emerging challenge will be to make these changes without unduly destabilizing planning 

and investment decisions made under previous RPS designs. 
35 Renewables Portfolio Standards in the United States 

Appendix: New State RPS Policies, Major Revisions to 

Existing RPS Programs, and New Non-Binding Renewable 

Electricity Goals Established in 2007 

Table A-1. New State RPS Policies Established in 2007 

State Key Elements of Renewables Portfolio Standard Design 

Illinois In 2001, Illinois established a non-binding renewable energy goal by legislation, and in 2005 a non-binding 

goal was established through regulatory action. In August 2007, the RPS was made mandatory and targets 

were both increased and extended, starting at 2% in 2008 and increasing to 25% by 2025. The targets only 

apply to electric utilities serving over 100,000 Illinois customers, and further only to customers taking fixedprice service (i.e., the fixed-price offerings of the IOU default service providers), making POUs and 

competitive energy service providers exempt from mandatory renewable purchases. Seventy-five percent of 

each year’s target is to come from wind power, and in-state resources are strongly encouraged through 2011 

(with out-of-state resource eligible during that period only if cost-effective in-state resources are not 

available). Cost caps change over time. In 2011, the cap will equal the greater of an additional 0.5% of the 

amount paid per kWh during the year ending May 2010, or 2% of the amount paid per kWh during the year 

ending May 2007. The newly created Illinois Power Agency is responsible for developing the procurement 

plans and conducting solicitations to ensure compliance by the state’s IOU default service providers, making 

Illinois the second state (after New York) to use a variant of a central procurement model to pursue its RPS. 

New Hampshire New Hampshire’s RPS, enacted in May 2007, establishes a renewables target for all of the state’s electricity 

suppliers of 4% in 2008, increasing to 23.8% by 2025. The target is segmented into four classes of eligible 

resources: Class I is for new renewable facilities beginning operation in 2006 or later (16% by 2025); Class 

II is for solar electricity from facilities beginning operation in 2006 or later (0.3% by 2014); Class III is for 

pre-2006 biomass and methane projects (6.5% by 2011); and Class IV is for certain pre-2006 hydroelectric 

facilities with a nameplate capacity of 5 MW or less (1% by 2009). Alternative compliance payments (ACPs) 

vary according to the four classes, with starting values that range from $28/MWh for Class III and IV to 

$57.12/MWh for Class I and $150/MWh for Class II. The PUC is provided limited authority to accelerate or 

slow scheduled changes to the renewable energy targets, and to alter Class III and IV requirements. 

North Carolina North Carolina’s RPS, signed into law in August 2007 and the first mandatory RPS in the Southeast, requires 

IOUs to meet eligible energy targets of 3% in 2012 (solar targets begin in 2010), increasing to 12.5% in 2021 

and thereafter. Electric cooperatives and municipal utilities are obligated to the same early-year targets but 

are not required to achieve more than 10% in 2018 and thereafter. Utility-implemented energy efficiency 

(including waste heat from fossil CHP) qualifies as an eligible resource for IOUs, up to a limit of 25% of 

each yearly target through 2020 and 40% in years thereafter; renewable CHP, both electricity and heat, 

qualifies for the renewables portion of the RPS. POUs may include load management as a substitute for 

energy efficiency, have no limits on the use of these sources, may use hydropower to qualify for up to 30% 

of their standard, and are provided additional leniency on the vintage of projects with which they contract. 

Unbundled RECs may be used for compliance, but unbundled RECs from out-of-state facilities may not 

meet more than 25% of annual requirements (except that one supplier – Dominion – is allowed unlimited use 

of such RECs). The RPS includes set-asides for swine waste, poultry waste, and new solar electric or solar 

thermal facilities (the solar set-aside begins in 2010). Cost caps vary by customer type. 

Oregon Oregon’s RPS was signed into law in June 2007, requiring utilities serving greater than 3% of statewide load 

(and any utility making a new investment in a coal plant) to meet a renewable energy purchase target of 5% 

in 2011, increasing to 25% by 2025. Smaller utilities have 2025 targets of 10% or 5%, depending on utility 

size, and no targets in intervening years. Competitive ESPs must meet targets that are dependent on the RPS 

obligations of the utility that would otherwise have served their customers. Unbundled RECs may be used 

for RPS compliance, but IOUs are capped at 20% unbundled RECs; large POUs may use up to 50% 

unbundled RECs until 2020; other suppliers have no restrictions. The PUC and consumer-owned utility 

governing boards are required to determine ACP rates for each utility. Suppliers are not required to comply if 

incremental compliance costs exceed 4% of annual revenue requirements. Suppliers are also not required to 

comply with the RPS in individual years if doing so would require them to acquire renewable energy in 

excess of load growth, displace non-fossil energy with eligible renewable power, or displace low-cost power 

from the Bonneville Power Administration. The legislation also contains a non-binding goal that communitybased and small-scale renewable energy projects of 20 MW or less provide at least 8% of 2025 retail load. 
36 Renewables Portfolio Standards in the United States 

Table A-2. Major Revisions to Existing State RPS Policies in 2007 

State Key Elements of Renewables Portfolio Standard Revisions 

California California’s RPS first took effect in 2003, and was designed such that certain above-market renewable energy 

contract costs would be paid through a separate fund administered by the California Energy Commission (the 

payments were called supplemental energy payments, or SEPs). This structure created administrative complexity 

and imposed financing difficulties on renewable energy projects. As a result, legislation was passed in October 

2007 that repeals the SEP process and returns the funds to the state’s LSEs. To continue to ensure that the cost 

of the RPS is capped, above-market contract costs for the state’s IOUs and ESPs will be limited to the funds 

transferred to them by the California Energy Commission. Separate legislation, also enacted in October 2007, 

expanded the resource eligibility rules to include certain hydropower facilities. 

Colorado Colorado was the first state to enact an RPS via the ballot box. In March 2007, follow-up legislation doubled the 

ultimate RPS target for IOUs (now 20% in 2020, up from 10% in 2015), thereby also doubling the effective size 

of the solar set-aside. The 2007 legislation also obligates all of the state’s electric cooperatives (previously 

limited to coops serving over 40,000 customers) and municipal utilities serving more than 40,000 customers to 

meet a target of 10% by 2020, and eliminates any ability to opt-out of these requirements. POUs are now 

excluded from the solar set-aside; instead, solar projects that come online prior to July 2015 will receive a 3x 

multiplier. “Recycled” energy was added to the list of eligible technologies, while community-owned renewable 

projects of under 30 MW and located in Colorado will receive a 1.5x multiplier. The revisions also increase the 

retail-rate-cap for the RPS to 2% (up from 1%, except that electric cooperatives are still subject to the 1% cap), 

and provide some encouragement for utility-owned renewable energy projects. 

Connecticut In June 2007, new legislation increased Connecticut’s RPS to 23% by 2020, with at least 20% from Class I 

resources. The new legislation also requires the Connecticut Municipal Electric Energy Cooperative to develop 

renewable energy standards for the state’s municipal electric utilities and report progress on those standards 

annually. 

Delaware In July 2007, Delaware increased its RPS, previously at 10% by 2019, to 20% by the same year, and created a 

solar PV set-aside that reaches 2.005% by 2019. The legislation also increases the level of ACP payments that 

may be made in lieu of purchasing RECs, and establishes an ACP schedule for the solar set-aside. 

Maine Maine’s original RPS did little to support new renewable projects. In June 2007, the legislature made mandatory 

a new and additional target (stated as a non-binding goal in 2006 legislation) of 10% of supply from new 

renewable capacity by 2017, starting at 1% in 2008. ACP levels for the new requirement are determined by the 

PUC, and the PUC subsequently established an ACP for the 10% requirement starting at $57.12/MWh in 2007 

dollars, matching the ACP levels in MA, NH, and RI. The PUC is also given the discretion to suspend annual 

increases in the new standard under certain conditions. 

Maryland Legislation enacted in April 2007 raises Maryland’s existing RPS targets by adding a requirement for solar that 

increases to 2% by 2022, thereby increasing the overall renewable energy target from 7.5% to 9.5%. In exchange 

for the new solar set-aside, the revised legislation deletes the earlier 2x multiplier for solar. The legislation 

establishes solar contracting requirements, revises solar REC ownership rules, and creates a higher ACP for the 

solar set-aside. Delays in achieving the solar set-aside may be allowed if certain cost limits are reached. 

Minnesota February 2007 legislation alters the RPS in Minnesota in several respects. Most importantly, it raises Xcel’s RPS 

obligations to 30% by 2020 (of which at least 25% must come from wind; the remaining 5% may come from 

other sources), and creates somewhat lower but mandatory targets for the state’s other electric utilities (including 

POUs) increasing to 25% by 2025 (previous targets were 10% by 2015). A separate “good faith” objective of 

7% by 2010 exists for all electric utilities in the state. Unbundled RECs may now be used for compliance. 

New Jersey In 2007, New Jersey’s BPU began to significantly change the implementation of that state’s solar set-aside. In 

particular, the importance of up-front rebates for PV is to decline, with the goal of transitioning towards a 

system that relies more-heavily on the purchase and sale of solar RECs. As part of that process, among other 

proposed changes, solar ACP levels are to increase and become more predictable, with a rolling 8-year price 

schedule set in advance. The trading life of solar RECs is to be extended to two years, and PV systems will only 

be allowed to create solar RECs for 15 years. The BPU staff was also directed to develop an overall cost cap for 

solar incentive payments, at a level of roughly 2% of retail rates. Additionally, the BPU staff was directed to cap 

solar capacity requirements at a level that accounts for the state’s aggressive energy efficiency goals. New Jersey 

also extended the timeframe for 2007 RPS compliance, given the run-up in Class I REC prices. 

New Mexico In March 2007, New Mexico’s RPS for IOUs was increased to 20% by 2020 (up from 10% by 2011 previously), 

and for rural cooperatives an RPS of 10% by 2020 was established. Rules adopted by the New Mexico PRC 

encourage resource diversity for IOUs through set-asides for solar and wind (each required to meet at least 20% 

of 2011 targets, and thereafter) and biomass or geothermal (a combined minimum of 10% of 2011 targets, and 
37 Renewables Portfolio Standards in the United States 

State Key Elements of Renewables Portfolio Standard Revisions 

thereafter); distributed generation is required to serve 3% of the RPS by 2015. These set-asides replace earlierdeveloped credit multipliers. The PRC has also established caps on energy costs by resource type, and has 

developed an overall cost cap of 2% for IOUs, and 1% for coops. 

Pennsylvania In July 2007, legislation was passed that clarifies the force majeure clause in Pennsylvania’s RPS, creates a 

more-detailed schedule for the solar set-aside, adds solar thermal to the list of eligible Tier I technologies, 

confirms REC property rights for generators and customer-generators, and somewhat limits the geographic 

scope of projects that may be eligible. 

Texas Legislation in 2007 clarifies that RECs retired for other purposes (e.g., sold through a voluntary green power 

program) can not be counted toward the RPS. The legislation also permits certain large customers to opt out of 

the RPS requirements, and empowers the PUC to establish alternative compliance payments for the RPS. 

Table A-3. New Non-Binding State Renewable Energy Goals Established in 2007 

State Key Elements of Renewable Energy Goal 

Missouri Missouri legislatively adopted a non-binding renewable energy and energy efficiency goal for the state’s 

IOUs in June 2007. Utilities are required to demonstrate a “good faith” effort to meet a goal of 4% by 2012, 

using either renewable energy or energy efficiency, increasing to 11% by 2020. The Missouri PSC is 

required to adopt criteria and standards for such a demonstration by July 2008. 

North Dakota In March 2007, the North Dakota legislature adopted a “renewable and recycled energy objective” of 10% by 

2015. All retail suppliers of electricity are covered by the objective. Recycled energy systems are defined as 

those producing power from previously unused waste heat from combustion or other processes (but not from 

systems being used primarily to generate electricity). Retail suppliers are required to make an economic 

assessment of the cost-effectiveness of new renewable and recycled energy purchases. 

Virginia In April 2007, Virginia enacted a non-binding renewable energy goal for the state’s IOUs of 4% in 2010, 

increasing to 12% in 2022. The percentages are applied to 2007 retail sales, less the average amount of 

power supplied from nuclear generators between 2004 and 2006. Utilities that meet the goals are to receive 

an increased rate of return in addition to cost recovery for their renewable energy purchases. Double credit is 

to be given for solar and wind power. 
38 Renewables Portfolio Standards in the United States 

Acknowledgments

For their support of this project, the authors thank John Atcheson and 

Dan Birns of the U.S. DOE’s Weatherization and Intergovernmental 

Program, Larry Mansueti of the U.S. DOE’s Office of Electricity Delivery 

and Energy Reliability, Drew Ronneberg, Steve Lindenberg, Phil 

Dougherty, and Alejandro Moreno of the U.S. DOE’s Wind & 

Hydropower Technologies Program, and Tom Kimbis and Charles 

Hemmeline of the U.S. DOE’s Solar Energy Technologies Program. 

For providing information or reviewing elements of this paper, we 

thank: Howard Bernstein (Massachusetts Division of Energy 

Resources), David Bloom (Delaware PSC), James Brack (New Mexico 

PRC), Joe Bryson (U.S. EPA), Cathie Bussolotta (Connecticut DPUC), 

Paul Cartwright (Montana Department of Environmental Quality), Roger 

Clark (The Reinvestment Fund), Craig Cox (Interwest Energy Alliance), 

Dennis Criswell (Sierra Southwest Cooperative), Jennifer DeCesaro 

(Clean Energy Group), Bill Drumheller (Oregon Department of Energy), 

David Goldberg (Connecticut Clean Energy Fund), Kevin Hale 

(NYSERDA), Paul Helgeson (Wisconsin PSC), Scott Hennessey (Solar 

Energy Industries Association), Dennis Hughes (Navopache Electric 

Cooperative), Benjamin Hunter (New Jersey BPU), David Hurlbut 

(National Renewable Energy Laboratory),Robert Grace (Sustainable 

Energy Advantage), Gregory Kim (Maryland PSC), Tom Kimbis (U.S. 

DOE), Jesse Jenkins (Renewable Northwest Project), Barbara 

Lockwood (APS), Brian Loos (New Jersey BPU), Larry Mansueti (U.S. 

DOE), Tanya McClosky (Pennsylvania Office of the Consumer 

Advocate), Richard Mignogna (Colorado PUC), Alan Nogee (Union of 

Concerned Scientists), Larry Nordell (Montana Consumer Council), 

John Pearce (Iowa Utilities Board), Susan Peirce (Minnesota Dept. of 

Commerce), Heather Raitt (California Energy Commission), Shane 

Rooney (Pennsylvania PUC), Elizabeth Salerno (American Wind 

Energy Association), Lisa Schwartz (Oregon PUC), Larry Sherwood 

(Interstate Renewable Energy Council), Linda Silverman (U.S. DOE), 

Sean Simon (California PUC), Charlie Smisson (Delaware Energy 

Office), Mitchell Tannenbaum (Maine PUC), Jess Totten (Texas PUC), 

Sam Watson (North Carolina Utilities Commission), Ray Williamson 

(Arizona Corporation Commission), Mike Winka (New Jersey BPU). 

We also thank Anthony Ma for assistance with layout, formatting, and 

production. Of course, the authors are solely responsible for any 

remaining omissions or errors. 

Berkeley Lab’s contributions to this report were funded by the Office of 

Energy Efficiency and Renewable Energy (Weatherization and 

Intergovernmental Program, Wind & Hydropower Technologies 

Program, and Solar Energy Technologies Program) and by the Office 

of Electricity Delivery and Energy Reliability (Permitting, Siting and 

Analysis Division) of the U.S. Department of Energy under Contract No. 

DE-AC02-05CH11231. 

Disclaimer

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agency thereof, or The Regents of the University of 

California. 

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