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

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

A Survey of State-Level Cost 

and Benefit Estimates of 

Renewable Portfolio Standards

J. Heeter1, G. Barbose2, L. Bird1, S. Weaver2, 

F. Flores-Espino1, K. Kuskova-Burns1, and 

R. Wiser2

1 National Renewable Energy Laboratory (NREL)

2 Lawrence Berkeley National Laboratory (LBNL) 

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

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

LLC, under contract DE-AC36-08GO28308.

Berkeley Lab’s contributions to this report were funded by the Office of Energy 

Efficiency and Renewable Energy (Solar Energy Technologies Office and Strategic 

Programs Office) of the U.S. Department of Energy under Contract No. DE-AC02-

05CH11231.

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

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

Technical Report

NREL/TP-6A20-61042

LBNL-6589E

May 2014
National Renewable Energy Laboratory

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Golden, CO 80401

303-275-3000 • www.nrel.gov

Lawrence Berkeley National Laboratory

1 Cyclotron Road

Berkeley, CA 94720

510-486-4000 • www.lbl.gov

A Survey of State-Level Cost 

and Benefit Estimates of 

Renewable Portfolio Standards 

J. Heeter1, G. Barbose2, L. Bird1, S. Weaver2, 

F. Flores-Espino1

, K. Kuskova-Burns1, and 

R. Wiser2

1 National Renewable Energy Laboratory (NREL)

2 Lawrence Berkeley National Laboratory (LBNL)

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

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

LLC, under contract DE-AC36-08GO28308.

This work was supported by the Director, Office of Science, U.S. Department of 

Energy under Contract Number DE- AC02-05CH11231

Berkeley Lab’s contributions to this report were funded by the Office of Energy 

Efficiency and Renewable Energy (Solar Energy Technologies Office and 

Strategic Programs Office) of the U.S. Department of Energy under Contract No. 

DE-AC02-05CH11231.

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

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

Technical Report

NREL/TP-6A20-61042

LBNL-6589E

May 2014
NOTICE

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Acknowledgments

The authors would like to thank the U.S. Department of Energy’s (DOE) Office of Energy 

Efficiency and Renewable Energy’s (EERE) Strategic Programs Office for primary funding 

support for this analysis. In particular, the authors are grateful to Steve Capanna and Jason Walsh 

of the Strategic Programs Office for their support of this project. Participation by Lawrence 

Berkeley National Laboratory (LBNL) was co-funded by EERE’s Solar Energy Technologies 

Office, and was made possible through long-standing support by the National Electricity 

Delivery Division of the DOE’s Office of Electricity Delivery and Energy Reliability. 

The authors would also like to thank the following individuals for their thoughtful review: 

Michael Casper and Paul McCurley, National Rural Electric Cooperative Association; Trish 

Fields and Malcolm Woolf, Advanced Energy Economy; Ed Holt, Ed Holt and Associates; 

Andrew Kell, Wisconsin Public Utilities Commission; Dwight Lamberson, New Mexico Public 

Regulatory Commission; Will Lent and Rick Umoff, Solar Energy Industry Association; Warren 

Leon, Clean Energy States Alliance; Kevin Mosier, Maryland Public Service Commission; 

Elizabeth Salerno, American Wind Energy Association; Virinder Singh, EDF Renewable 

Energy; David Smithson, Texas Public Utilities Commission; as well as Jeff Logan, David 

Keyser, Thomas Jenkin, Gian Porro, Robin Newmark, Bobi Garrett, and Doug Arent of the 

National Renewable Energy Laboratory (NREL), Andrew Mills of LBNL and Kelly Knutsen, 

Ookie Ma, and Rich Tusing of DOE. We also wish to thank Kendra Palmer and Scott Gossett of 

NREL for editorial support.
iv

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Executive Summary

More than half of U.S. states have renewable portfolio standards (RPS) in place and have 

collectively deployed approximately 46,000 MW of new renewable energy capacity through 

year-end 2012. Most of these policies have five or more years of implementation experience, 

enabling an assessment of their costs and benefits. Understanding RPS benefits and costs is 

essential for policymakers evaluating existing RPS policies, assessing the need for modifications, 

and considering new policies. 

This report surveys and summarizes existing state-level RPS cost and benefit estimates and 

examines the various methods used to calculate such estimates. The report relies largely upon 

data or results reported directly by electric utilities and state regulators. As such, the estimated 

costs and benefits itemized in this document do not result from the application of a standardized 

approach or the use of a consistent set of underlying assumptions. Because the reported values 

may differ from those derived through a more consistent analytical treatment, we do not provide 

an aggregate national estimate of RPS costs and benefits, nor do we attempt to quantify net RPS 

benefits at national or state levels. 

The report summarizes state-level RPS costs to date and considers how those costs may evolve 

going forward given scheduled increases in RPS targets and cost containment mechanisms 

incorporated into existing policies. The report also summarizes RPS benefits estimates, based on 

published studies for individual states, and discusses key methodological considerations. These 

estimates, for example, of the social value of carbon emissions reduction and the human health 

impacts of reduced air emissions, are based on a variety of methodologies and assumptions. In 

comparison to the summary of estimated RPS costs, the summary of RPS benefits is more 

limited, as relatively few states have undertaken detailed benefits estimates. Further, for those 

states that have estimated RPS benefits, most assess only a limited number of impact types; as a 

consequence, some types of benefits are not reflected in this report. 

RPS Costs

Our analysis focuses specifically on the incremental cost of meeting RPS targets, i.e., the cost 

above and beyond what would have been incurred absent the RPS, over the 2010-2012 period. 

For states with restructured markets, we derive RPS compliance costs based on the cost of 

renewable energy certificates (RECs) and alternative compliance payments (ACPs). For 

traditionally regulated states, we instead rely upon RPS cost estimates reported directly by 

utilities or regulators within annual compliance reports or other regulatory filings (not 

prospective studies), and translate those estimates into a set of common metrics for comparison. 

The methods used by utilities and regulators to estimate incremental compliance costs vary 

considerably from state to state, in some cases reflecting statutory or regulatory requirements, 

and a number of states are currently engaged in processes to refine and standardize their 

approaches to RPS cost calculation. 

Importantly, the estimated RPS costs summarized within this report must be considered in light 

of what the underlying data represent and the limitations therein. First and foremost, the 

comparisons across states are imperfect, given the varying methods and assumptions used 

(especially among regulated states). Second, the data presented most closely correspond to the 

costs borne by utilities or other load serving entities; they do not represent net costs to society, 
v 

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nor do they necessarily represent the costs ultimately borne by ratepayers, such as in cases where 

ACPs or financial penalties are not passed through to rates or differences in the timing of when 

costs are incurred and recovered in rates. Third, depending upon the state and particular 

methodology used, the cost data may omit certain costs incurred by utilities (e.g., integration 

costs), as well as possible benefits. Other analysis has examined integration costs; for example, a 

number of U.S.-focused studies have found wind integration costs to be less than $5/MWh 

(Wiser and Bolinger 2013). Finally, the use of REC prices to compute RPS compliance costs in

restructured markets is limited in some cases by a lack of REC price transparency and 

incomplete data on long-term contracts. In addition, REC prices can be quite volatile, with large 

swings from year to year, depending upon whether a given state or region is in surplus or deficit 

relative to its RPS obligations. As such, the calculated RPS compliance costs for restructured 

markets may not correspond well to trends in the underlying cost of renewable electricity. 

Figure ES-1. Estimated incremental RPS costs compared to recent and future RPS targets

In light of what the underlying data represent and the limitations therein, the following are key 

findings with respect to RPS costs. 

• Over the 2010-2012 period, average estimated incremental RPS compliance costs in the 

United States were equivalent to 0.9% of retail electricity rates when calculated as a 

weighted-average (based on revenues from retail electricity sales in each RPS state) or 1.2% 

when calculated as a simple average, although substantial variation exists around the 

averages, both from year-to-year and across states. Focusing on the most recent historical 

year available, estimated incremental RPS compliance costs were less than 2% of average 

retail rates for the large majority of states (see Figure ES-1). 

• Among restructured markets, estimated incremental compliance costs ranged from 0.1% to 

3.8% of retail rates. Expressed in terms of the cost per unit of renewable energy required, 

estimated incremental RPS compliance costs in these states ranged from $2-$48/MWh. 

-20%

-10%

0%

10%

20%

30%

40%

-4%

-2%

0%

2%

4%

6%

8%

CT

DC

DE

IL

MA

MD

ME

NH

NJ

NY

OH

PA

RI

TXAZ

CA

CO

MI

MN

MO

NC

NM

OR

WA

WI

Restructured Regulated

Estimated Incremental RPS Costs (Most-Recent Year)

RPS Target (Most-Recent Year)

RPS Target (Final Year)

Estimated RPS Cost 

(% of Average Retail Rates)

RPS Target 

(% of Retail Sales)

* For most states shown, the most-recent year RPS cost and target data are for 2012; exceptions are CA (2011), MN (2010), and 

WI (2010). MA does not have single terminal year for its RPS; the final-year target shown is based on 2020. For CA, high and low 

cost estimates are shown, reflecting the alternate methodologies employed by the CPUC and utilities. Excluded from the chart are

those states without available data on historical incremental RPS costs (KS, HI, IA, MT, NV). The values shown for RPS targets 

exclude any secondary RPS tiers (e.g., for pre-existing resources). For most regulated states, RPS targets shown for the mostrecent historical year represent actual RPS procurement percentages in those years, but for MO and OR represent REC 

retirements (for consistency with the cost data). 
vi 

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Variation among those states reflects differences in RPS target levels, REC pricing, the 

composition of RPS resource tiers, and other factors. 

• Among traditionally regulated states (excluding California), estimated incremental

compliance costs varied from -0.2% (i.e., a net savings) to 3.5% of average retail rates. 

Variation among these states partly reflects differences in RPS procurement levels. In 

addition, relatively high estimated costs for a number of states are associated with the 

presence of distributed generation (DG) set-asides, for which compliance costs tend to be 

“front-loaded.” The estimated incremental costs of meeting general RPS obligations (i.e., 

excluding DG or solar set-asides) ranged from -$4 to $44/MWh of renewable energy 

procured. 

• Methodological differences contribute to observed variations in these compliance cost

estimates, especially among regulated states. For example, in California, two different 

methodologies yield derived incremental compliance cost estimates ranging from a net 

savings equal to 3.6% of retail rates to a net cost of 6.5%, as shown in Figure ES-1. 

• Utilities in eight states assess surcharges on customer bills to recoup RPS compliance costs. 

These utility-reported surcharges, which represent the costs borne directly by customers, 

ranged in 2012 from about $0.50/month to $4.00/month for average residential customers,

and on a statewide average basis, equate to roughly 0.5% to 4% of average retail electricity 

rates. These customer surcharges may differ from the estimated compliance costs borne by 

the utility for a variety of reasons, such as differences in the timing or type of costs that can 

be passed through to customers. 

• Estimated incremental RPS compliance costs over the historical period of our analysis reflect

the RPS targets applicable during those years (the open circles in Figure ES-1). Under 

current policies, RPS targets are scheduled to increase significantly, eventually reaching 

levels represented by the closed circles. Whether and the extent to which incremental RPS 

costs rise in tandem depends on many factors: renewable energy technology costs trends, 

natural gas prices, federal tax incentives, and environmental regulations, among others. 

• Future RPS compliance costs are limited by cost containment mechanisms built into most 

RPS policies. Among those states relying principally upon an ACP mechanism for cost 

containment, RPS costs are effectively capped at roughly 6-9% of average retail rates in most 

cases. Cost caps in most other states are considerably more stringent, often limiting 

compliance costs to 1-4% of average retail rates. Compliance costs in several of those states 

have already reached or are approaching the respective caps. 

RPS Benefits

Policymakers often consider RPS costs within the context of broader social benefits beyond any 

direct cost savings that may accrue to utilities. Potential benefits of RPS policies include reduced 

emissions, water savings, fuel diversity, electricity price stability, and economic development. 

States have most commonly attempted to quantitatively assess avoided emissions and associated 

human health benefits, economic development impacts, and savings from reductions in 

wholesale electricity prices. In many cases, these assessments are required by the legislature or 

public utilities commission (PUC), filed as part of an integrated resource plan (IRP) docket, and 

prepared for regulatory commissions, energy boards, or public benefit corporations. In this work, 

we focused on analyses conducted as part of state-level RPS evaluations, but did not review the 
vii 

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

broader literature on renewable energy benefits in general. While we attempted to conduct a 

thorough literature review, we have likely omitted some analyses; however, this review provides 

an indication of the types of benefits analyses that have been conducted and the range of benefits 

found. 

Key findings include: 

• A relatively small number of RPS benefits estimates have been developed and methodologies 

vary considerably, which limits the ability to make comparisons and bounds the range of 

impacts. We identified studies for eight states that assessed the societal benefits or broader 

impacts of RPS policies based on our review of literature. Most studies of benefits or impacts 

are prospective in nature, assessing not only the current RPS impacts, but also examining 

future impacts, in contrast to the cost estimates previously discussed that are retrospective. 

Some types of benefits, such as avoided emissions, can accrue for the lifetime of the 

renewable energy plant, while costs are incurred typically over a shorter period. 

• We identified six studies that attempted to quantify the emissions or human health benefits of 

state RPS policies. Most used modeling approaches to assess scenarios with and without 

renewable energy and some estimated the dollar values associated with emissions reductions. 

In some cases, emissions benefits may be captured in estimates of net incremental costs, such 

as if allowance prices are already embedded in wholesale electricity prices. Estimates of 

benefits ranged from roughly tens to hundreds of millions of dollars on an annual basis 

depending on the state and scenario. These estimates translate to approximately $4-23/MWh 

of renewable generation, depending on the study and the cost value assumed for CO2. 

• Similarly, we identified six studies that attempted to quantify economic impacts of an RPS. 

Two used economic modeling approaches while the others used input-output models or 

simplified case study approaches. Often input-output models or simplified approaches 

estimate gross jobs, which do not account for shifts in employment that may occur, as 

opposed to new net jobs. A number of the studies examined economic development benefits 

annually or over the lifespan of the renewable energy projects, with benefits on the order of 

$1-$6 billion, or $22-30/MWh of renewable generation. 

• Six states estimated wholesale market price reductions that resulted from an RPS (i.e., the 

reduction in market clearing prices resulting from an increase in the supply of low marginalcost renewable resources), typically using electric system modeling or applying estimates 

from other modeling efforts. The studies generally found wholesale price reductions of about 

$1/MWh or less within specific markets (total generation), or price suppression benefits of 

$2-$50/MWh of renewable energy generation. 

• Comparison of costs to benefits is challenging, even when they are reported in the same 

study, given that some incremental cost calculations may already take into account specific 

benefits, analysis time periods may differ, benefits assessments may address only particular 

types of benefits, and other factors. Most states for which we have identified benefits 

estimates did not conduct direct comparisons.

In the future, additional efforts could be undertaken to comprehensively assess the costs and 

benefits of state RPS policies by comparing costs and benefits directly, using similar 

methodologies and level of rigor. Further, additional work could be done to standardize 
viii

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incremental cost calculations within and among states provided that such cost calculations are 

often required by RPS statutes. Efforts in a few states are underway to address standardization of 

incremental cost calculations; states that have not examined standardization may see the issue 

arise in the future and be able to learn from the processes and outcomes of existing state 

standardization efforts. 
ix

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Table of Contents

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

Executive Summary................................................................................................................................... iv

List of Figures ............................................................................................................................................ xi

List of Tables .............................................................................................................................................. xi

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

2 Methods of Determining Cost Impact................................................................................................. 3

2.1 Methods for Estimating Incremental RPS Costs in States with Traditionally Regulated Markets.. 4

2.1.1 Comparing to a Proxy Non-renewable Generator............................................................. 5

2.1.2 Comparing to Market Price............................................................................................... 6

2.1.3 Modeling Approaches....................................................................................................... 7

2.1.4 Additional Considerations for Estimating Incremental RPS Costs in Regulated States... 9

2.2 Approaches for Estimating Incremental RPS Costs in States with Restructured Electricity 

Markets .......................................................................................................................................... 11

2.3 Gross RPS Compliance Costs........................................................................................................ 14

2.4 Including Other Expenses in RPS Cost Calculations..................................................................... 15

2.4.1 Integration Costs and Network Transmission Costs....................................................... 15

2.4.2 Inclusion of Administrative Expenses ............................................................................ 16

2.4.3 Treatment of Energy Efficiency Eligible to Meet RPS................................................... 17

2.5 Summary of Methodological Considerations ................................................................................ 17

3 Incremental RPS Compliance Costs: Historical Data for 2010 to 2012 ........................................ 21

3.1 States with Restructured Markets .................................................................................................. 22

3.1.1 Methodology and Data Sources...................................................................................... 23

3.1.2 REC Prices...................................................................................................................... 26

3.1.3 Estimated incremental RPS Costs per Unit of Renewable Generation........................... 29

3.1.4 Estimated incremental RPS Costs as a Percentage of Retail Rates................................. 30

3.2 States with Regulated Markets....................................................................................................... 33

3.2.1 Methodology and Data Sources...................................................................................... 33

3.2.2 Estimated incremental RPS Costs per Unit of Renewable Generation........................... 35

3.2.3 Estimated incremental RPS Cost as a Percentage of Retail Rate.................................... 36

3.3 RPS Surcharges.............................................................................................................................. 40

3.4 Assessment of Future RPS Costs and Cost Containment Mechanisms......................................... 43

3.4.1 RPS Cost Containment Mechanisms .............................................................................. 45

4 Benefits of RPS................................................................................................................................... 51

4.1 Emissions and Human Health........................................................................................................ 52

4.1.1 Emissions Rate Approach ............................................................................................... 54

4.1.2 Modeling Avoided Emissions Approach ........................................................................ 54

4.2 Economic Development Impacts................................................................................................... 56

4.2.1 Input-Output Models and Simplified Approaches.......................................................... 58

4.2.2 Economic Modeling Approach ....................................................................................... 60

4.3 Wholesale Market Price Impacts................................................................................................... 61

5 Conclusion .......................................................................................................................................... 64

References................................................................................................................................................. 66

Appendix: State Summaries .................................................................................................................... 79

Arizona ................................................................................................................................................. 79

California.............................................................................................................................................. 79

Colorado ............................................................................................................................................... 80

Connecticut........................................................................................................................................... 81

The District of Columbia...................................................................................................................... 82

Delaware............................................................................................................................................... 82
x 

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Hawaii .................................................................................................................................................. 83

Illinois................................................................................................................................................... 84

Iowa...................................................................................................................................................... 85

Kansas .................................................................................................................................................. 85

Maine.................................................................................................................................................... 86

Maryland .............................................................................................................................................. 86

Massachusetts....................................................................................................................................... 87

Michigan............................................................................................................................................... 88

Minnesota ............................................................................................................................................. 89

Missouri................................................................................................................................................ 89

Montana................................................................................................................................................ 90

Nevada.................................................................................................................................................. 90

New Jersey ........................................................................................................................................... 91

New Hampshire.................................................................................................................................... 91

New Mexico ......................................................................................................................................... 92

North Carolina...................................................................................................................................... 92

New York ............................................................................................................................................. 93

Ohio...................................................................................................................................................... 94

Oregon.................................................................................................................................................. 95

Pennsylvania......................................................................................................................................... 95

Rhode Island......................................................................................................................................... 96

Texas .................................................................................................................................................... 96

Washington........................................................................................................................................... 96

Wisconsin ............................................................................................................................................. 97
xi 

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List of Figures

Figure ES-1. Estimated incremental RPS costs compared to recent and future RPS targets................. v

Figure 1. Overview of methodologies used to calculate RPS costs ..................................................... 21

Figure 2. REC spot market prices......................................................................................................... 28

Figure 3. Estimated incremental RPS cost over time in states with restructured markets ($/MWh of 

renewable electricity)..................................................................................................................... 30

Figure 4. Estimated incremental RPS cost over time in states with restructured markets (% of retail 

rates)............................................................................................................................................... 31

Figure 5. Estimated incremental RPS cost by tier in restructured markets (% of retail rates) ............. 32

Figure 6. Estimated incremental RPS costs from RECs and ACPs in restructured markets (% of retail 

rates)............................................................................................................................................... 32

Figure 7. Estimated incremental RPS cost over time for general RPS obligations in regulated states 

($/MWh of renewable electricity).................................................................................................. 36

Figure 8. Estimated incremental RPS cost over time in regulated states (% of retail rates) ................ 38

Figure 9. RPS surcharges over time (% of retail rates) ........................................................................ 42

Figure 10. Estimated incremental RPS costs compared to recent and future RPS targets................... 43

Figure 11. RPS cost caps compared to estimated recent historical costs ............................................. 50

 

List of Tables

Table 1. Methods for Estimating Incremental RPS Costs...................................................................... 5

Table 2. Publically Available Information on REC Pricing................................................................. 13

Table 3. ACP Cost Recovery Provisions.............................................................................................. 14

Table 4. Data Sources Used to Calculate RPS Compliance Costs for Restructured States.................. 25

Table 5. ACP Rates: 2010-2012 ($/MWh)........................................................................................... 26

Table 6. Data Sources Used to Calculate Estimated RPS Compliance Costs for Regulated States..... 34

Table 7. Alternate RPS Incremental Cost Estimates for California (2011).......................................... 39

Table 8. Average RPS Surcharges for Residential Customers in 2012................................................ 41

Table 9. Cost Containment Mechanisms.............................................................................................. 47

Table 10. Summary of State Studies of RPS Benefits and Benefits Assessed ..................................... 52

Table 11. Summary of Estimates of Emissions and Human Health Benefits of State RPS ................. 53

Table 12. Summary of Estimates of RPS Economic Impacts .............................................................. 58

Table 13. Summary of Estimates of Wholesale Market Price Impacts of Renewables Developed for 

RPS ................................................................................................................................................ 61

Table 14. California Utilities’ Estimated Average RPS Costs in ¢/kWh (2003-2011) ........................ 80

Table 15. Estimated Avoided Energy Cost in ¢/kWh Purchases from Qualifying Facilities of >100 

kW.................................................................................................................................................. 84

Table 16. IPA Reported Costs of Unbundled RECs and Conventional Supply (June 2009-May 2013)85

Table 17. ACP Rates for the 2013 CY (in $/MWh)............................................................................. 87

Table 18. The Weighted Average Cost/REC for Ohio’s Electric Distribution Utilities and Electric 

Service Companies in 2011 ........................................................................................................... 94
1 

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1 Introduction

Renewable portfolio standards (RPS) have been widely adopted by states and have reached 

moderate-to-advanced stages of implementation, so that there is now sufficient experience to 

examine implementation costs and benefits. RPS policies call for electricity providers to acquire 

specific amounts of renewable energy generation over time, often as a percentage of overall 

electricity supplied. These policies have been a significant driver of development of new 

renewable capacity additions in the United States, with roughly 46 GW or two-thirds of all nonhydroelectric renewable capacity additions since 1998 occurring in states with active or 

impending RPS targets.1

 Today, RPS policies are established in 29 states plus Washington D.C. 

and Puerto Rico.

2 RPS policies in 22 states have been in place for five or more years, and RPS 

polices in five states have been in place for more than a decade; this degree of implementation 

experience has led to cost and benefit assessments by utilities, states, and others. 

Understanding the costs and benefits of RPS policies can be important for program evaluation, 

understanding policy effectiveness, consideration of new policies, and assessing potential 

modifications to existing RPS policies. In recent years, there has been significant legislative 

activity to modify RPS targets (CNEE 2012), and information on RPS implementation costs 

across states can be particularly important for informing legislative decisions. 

Information about RPS costs is also often needed to support other regulatory and legislative 

processes. RPS costs, in some cases, are recovered through a dedicated surcharge or tariff rider 

on customer bills that is adjusted regularly and approved by the public utilities commission 

(PUC). In these instances, utilities must estimate the costs when requesting adjustments to the 

surcharge. States may also conduct occasional evaluations of their RPS programs, which may be 

required by statute. Such evaluations are often much broader in scope than the aforementioned 

administrative processes, and may include analyses of benefits, such as economic development 

and environmental impacts. 

Many states have cost containment mechanisms in place that limit RPS compliance costs and the 

associated impact on ratepayers (Stockmayer et al. 2012; CPI 2012). For example, several states 

have developed rules precluding the cost of RPS compliance from exceeding 2-4% of retail 

electricity rates. As a result of these provisions, utilities and PUCs must routinely evaluate RPS 

program costs—typically within the context of annual compliance filings or reports to the 

legislature—to ensure that the compliance costs do not exceed the cost caps. 

In implementing RPS cost caps, surcharges, and program evaluations, states have faced 

methodological issues associated with determining compliance costs. In some cases, methods for 

calculating such costs may be briefly specified in statute or in implementing rules by the PUC. 

Even in cases where the broad methods are defined, there can be significant variability in utility 

 

1 The 46 GW figure is intended as a rough proxy for the impact of state RPS programs on renewable energy 

development to date, and was derived by simply considering the date and location of renewable energy capacity 

additions. For the purpose of this tabulation, renewable additions are counted if and only if they are located in a state 

with an RPS policy and commercial operation began no more than one year before the first year of RPS compliance 

obligations in that state. 2 For additional detail, see the DSIRE database: http://www.dsireusa.org/rpsdata/index.cfm. 
2 

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calculations. As a result, a number of states (e.g., New Mexico, Minnesota, Washington) have 

recently conducted or are currently engaged in regulatory proceedings to develop consistent RPS 

cost calculation methods across utilities. Some of the key challenges include assessing the 

incremental or above-market costs of acquiring renewable generation rather than conventional 

generation sources and the timeframe of the cost calculation. 

While most states or utilities have estimated or collected data on compliance costs, only a few 

have assessed benefits quantitatively. Benefits of RPS policies can include environmental 

benefits, such as avoided air pollutant emissions, human health effects, and reduced water 

consumption, as well as fuel diversity, economic development, electricity price stability, and 

others. Methods used to assess benefits are substantially different than for estimating costs, and 

these are covered separately in this report. 

This analysis adds to a relatively small, but varied, literature analyzing RPS costs across states.

At the national level, cost impacts of a proposed federal RPS have been studied with the use of 

modeling tools (Bird et al. 2011, Fischer 2010, and Wiser and Bolinger 2007). At the state level, 

Morey and Kirsch (2013) use regression analysis to examine the impact of various policies, 

including an RPS, on electricity rates, using historical data. Chen et al. (2007) examined 

prospective, rather than retrospective, RPS studies, the majority of which were funded by 

nongovernmental organizations. Of the studies reviewed by Chen et al., 21 of 30 projected a 

retail rate increase of less than or equal to one percent in the RPS peak target year, while nine 

studies predict rate impacts above 1% and two of those studies predict rate impacts of more than 

5%. 

While prospective RPS studies have been conducted in many cases, in some instances at the 

request of state legislatures, this analysis does not utilize forward looking cost studies, but rather 

focuses on estimates of actual incurred costs. The approach used in our analysis focuses on 

estimated incurred costs so as to better determine rate changes that are attributable to RPS 

implementation costs rather than other factors that can influence rates. 

This paper examines estimated costs and benefits from RPS implementation to date and the 

expected costs if they continue to evolve over time to their end target. In general, the information 

presented in this report can be important for policymakers and other stakeholders to understand 

how state RPS implementation costs and benefits compare as they evaluate existing RPS policies 

and consider revisions going forward. The focus of this report is on estimated costs to load 

serving entities subject to RPS targets; we do not focus on broader societal costs (such as federal 

tax subsidies). Data for this report are obtained primarily from PUC compliance filings, program 

evaluations conducted or authorized by state commissions, and other state-commissioned studies.

Section 2 assesses current methods used to evaluate RPS costs and discusses the issues and 

challenges associated with various approaches. Section 3 assesses estimated RPS cost data for 

states where information is available, discussing underlying reasons for differences across states 

and the impacts of policy design (for example, the presence of solar carve-outs ). The potential to 

reach cost caps in coming years is also examined. Section 4 reviews quantitative benefits 

information, focusing on estimates of broader societal benefits prepared for formal evaluations of 

state-level RPS policies, often at the request of legislatures. 
3 

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

2 Methods of Determining Cost Impact

Section 2 and Section 3 of this report survey various methods used to estimate the costs of 

renewable portfolio standards and summarize estimates of state RPS costs to date, relying largely 

upon data or results reported directly by electric utilities and state regulators. As such, the 

estimated costs itemized in this document do not result from the application of a standardized 

approach or the use of a consistent set of underlying assumptions. 

Costs examined by utilities, states, and regulators may be defined as either “gross costs” or 

“incremental costs.” Gross costs consist of the total cost of procuring renewables to meet the 

RPS, while incremental costs (also referred to as “net” or “above market” costs) examine the 

difference between gross costs and the costs that would have been borne absent the RPS. 

“Incremental” is sometimes defined in different ways; here we refer to incremental cost as the 

additional cost of renewable electricity above and beyond what would have been incurred to 

procure electricity in the absence of the RPS. Most states focus on calculating the incremental 

costs of RPS compliance, though three (California, Kansas, and Nevada) have published 

estimates of gross costs. RPS benefits are discussed in Section 4. 

In general, the method by which costs may be determined depends on the regulatory structure of 

the state.3 In traditionally regulated states, utilities commonly enter into long-term power 

purchase agreements (PPAs) for the electricity and renewable energy certificates (RECs) from a 

project, or build and own renewable generation projects directly. RECs represent the 

environmental attributes of renewable generation and are used to demonstrate compliance with 

the RPS. Because these long-term PPAs include both the electricity and the REC (referred to as a 

“bundled contract”), determining the “incremental” cost of the renewable energy requires a 

comparison to the cost of conventional generation that would otherwise have been procured. In 

traditionally regulated states, RPS costs are typically estimated by either the obligated utility or 

by the PUC. The general methodology for assessing costs has in some cases been outlined by 

statute or regulation; however, statutory or regulatory language can still be open to interpretation 

by the compliance entity, sometimes resulting in differing methodologies across utilities within a 

state. 

In states with restructured markets, compliance entities are typically buying “unbundled” RECs, 

and thus, the incremental cost of RPS compliance is derived from the cost of RECs in addition to 

any alternative compliance payments (ACPs) made to achieve compliance. Most restructured 

states have ACPs that enable obligated entities to make a payment at a pre-established price in 

lieu of procuring renewables (e.g., $50/MWh). These essentially establish a ceiling on the cost of 

compliance because obligated entities would not enter into contracts to procure renewable 

generation above the ACP price. Though REC prices (in combination with ACPs) can be used to 

 

3 In states with restructured markets, the traditional electric utility monopoly, where the utility provides generation, 

transmission, and distribution, has been split. Customers in restructured states can choose which electric service 

company will supply their generation. In traditionally regulated states, vertically integrated utilities provide 

generation, transmission, and distribution service to a captive market (i.e., franchise service territory). While there is 

a spectrum of restructuring, for purposes of this study, we classify the following RPS jurisdictions as operating in 

restructured markets: Connecticut, Delaware, Illinois, Massachusetts, Maryland, Maine, New Hampshire, New 

Jersey, New York, Ohio, Pennsylvania, Rhode Island, Texas, and Washington, D.C. 
4 

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

estimate the incremental cost of RPS compliance, it is important to note that REC prices are 

influenced by market supply and demand, and can fluctuate widely, thus not necessarily 

representing the above market costs for renewable energy, as discussed further in Section 2.2. 

Moreover, in addition to purchasing unbundled RECs, compliance entities in some restructured 

markets have begun procuring more renewables through long-term bundled PPAs, which 

requires a different methodology to calculate the incremental cost. 

This section provides an overview of the methods used to estimate the cost impacts of an RPS; 

Section 3 will present the results of studies done by states as well as our calculation of RPS 

costs, based on REC price data, ACPs, and data from long-term contracts. 

We structure the section as follows: Section 2.1 discusses methods used to estimate incremental 

RPS compliance costs in regulated states; Section 2.2 discusses methods used in states with 

restructured electricity markets; Section 2.3 discusses those states that instead report only gross 

costs; Section 2.4 highlights other issues that impact cost estimates; and Section 2.5 provides a 

summary of methodological considerations. 

2.1 Methods for Estimating Incremental RPS Costs in States with 

Traditionally Regulated Markets

In traditionally regulated states where utilities and state agencies are estimating the incremental 

cost to meet the RPS, a key decision is how to determine the counterfactual scenario—absent 

RPS procurement, what resources would have been procured, and at what cost. After the 

counterfactual scenario costs are determined, they can then be subtracted from the gross RPS 

costs to derive an “incremental” cost of RPS compliance. 

Utilities in states with traditionally regulated markets generally use one of three methods, or a 

combination of methods, for defining the counterfactual scenario and estimating incremental 

RPS costs (Table 1). In some cases, the counterfactual scenario is a particular type of 

conventional generator, which may be established by the Commission. In other cases, utilities 

use wholesale prices to determine the counterfactual scenario. Finally, many utilities use 

modeling approaches to determine the proxy conventional generator(s) or market prices. Table 1 

outlines the primary methods for determining incremental costs in regulated markets, identifies 

the methods used in various regulated states, and highlights a number of key considerations 

within those methods, as discussed further below. 
5 

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

Table 1. Methods for Estimating Incremental RPS Costs

Method States Key Considerations Considerations for 

Multiple Methods

Compare to a 

proxy nonrenewable 

generator

AZ, CA, MI, OR • What is the process for 

determining the conventional 

generator?

• Over what time period 

are costs calculated? 

• Is a carbon adder 

included in the nonrenewable costs? 

• What fossil fuel prices 

are assumed?

• What additional costs 

are included (e.g. 

capacity, transmission, 

or ancillary services)?

• Are renewable 

resources that were 

developed before the 

RPS implementation 

included?

Compare to 

market price

CA, MN, WA, 

WI 

• Is the wholesale market 

generation shaped to match 

the output of the renewable 

energy? 

• Are energy and capacity 

values included? 

Modeling 

approaches

CO, MI, MN, 

NM, NC • For future scenarios, what 

assumptions are made about 

load growth, environmental 

regulations?

2.1.1 Comparing to a Proxy Non-renewable Generator

Under this approach, utilities and states compare the cost of RPS resources to the levelized cost 

of some proxy conventional generator. The kind of proxy generator, and the set of costs included 

in the comparison, may be established by the commission or in statute. These costs may include 

(for both the renewable generation and conventional generation) those associated with fuel 

consumption, generation capacity, operations and maintenance, transmission, ancillary services, 

and emissions.

This approach takes a long-term perspective, looking at the levelized cost of a resource over its 

lifetime. It may also simplify the process for calculating incremental costs, compared to a 

modeling approach, though decisions about defining the proxy generator, timeframe of analysis, 

fuel costs, and other issues may complicate the process. In addition, the resulting estimated 

incremental costs may not represent what actually would have been used absent an RPS. This is 

because in practice, renewable generation could displace more than one generator type at 

different hours during the year, and may or may not have equal capacity value as the proxy 

generator. The generator type as well as the hours in which it is operated will impact the overall 

cost profile. 

States have used different approaches to developing a proxy. Some examples include the 

following: 

• The Michigan PUC files a report annually examining the cost of renewables procured under 

the RPS compared to the cost of a new, coal-fired power plant, as required by statute. The 

PUC report draws on data submitted in the rate-regulated electric providers’ annual 

renewable energy plans, which must demonstrate that the “life cycle cost of renewable 

energy acquired, less the life cycle net savings associated with the Energy Optimization 

Plans, did not exceed the life cycle cost of electricity generated by a new conventional coalfired facility (MPSC 2013, 23-24).” The PUC staff developed a guidepost for the cost of a 
6 

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

new coal plant of $133/MWh (or $0.133/kWh), based on a 40-year life cycle and 

forthcoming EPA regulations.4 

• In Oregon, utilities estimate incremental costs of compliance based on a combined cycle gas 

turbine (CCGT) proxy, unless otherwise specified by the PUC, the costs of which must be 

based on the most recent integrated resource plan (IRP), unless material changes have been 

made since then. 

• Although California’s cost assessment process is being revised, the historical approach for 

evaluating RPS costs was to compare RPS procurement to a “market price referent” (MPR). 

The MPR was developed by the utilities as the modeled cost to own and operate a CCGT 

over multiple time periods. In its most recent RPS cost report, the CPUC used a 20-year 

MPR of $0.101/kWh to evaluate the utilities’ 2011 RPS portfolios (CPUC 2013a). 

2.1.2 Comparing to Market Price 

Some states and utilities are estimating incremental RPS costs by comparing the cost of 

renewables procurement relative to wholesale electricity spot market prices. In order to 

determine the market price, a number of considerations need to be weighed, including: should 

the wholesale market generation be shaped to match the output of the renewable energy, and are 

both energy and capacity market costs considered? 

States and utilities have used different approaches when comparing the cost of renewables used 

to meet the RPS to market price. Text Box 1 describes how utilities in Minnesota have calculated 

incremental RPS costs, using market price as well as modeling work. Other examples using 

wholesale market prices as the presumed cost absent the RPS include the following: 

• In Washington, the three investor-owned utilities (IOUs) are comparing the costs of 

renewables to the cost of purchasing an equivalent amount of energy from the wholesale 

market.5 As part of this process, PacifiCorp used the wholesale market price curve shaped to 

the output of the renewable resource. This shaping was not done by the other IOUs. 

Differences in methodology and other factors led to a two-fold range in reported 2012 

compliance costs estimates in Washington. PacifiCorp estimated the cost of RPS compliance 

at $15.73/MWh while Avista’s estimate was $20.35/MWh and Puget Sound Energy’s 

estimate was $43.76/MWh (Stanfield 2013a). The Washington UTC is addressing cost 

standardization as it considers revisions to its RPS rules (see Docket UE-131723). 

• Although California has used the MPR approach, utilities have also estimated avoided costs 

using a market price methodology using day-ahead market price and the cost of capacity. 

 

4 The PUC staff calculation of the renewable cost includes the cost of PUC approved contracts, with the exception of 

Detroit Edison’s and Consumers Energy’s solar programs, which the PUC determined to make up less than two 

percent of contracts approved, on a generation basis.

5 Washington’s RPS statute defines incremental costs as “the difference between the levelized delivered cost of the 

eligible renewable resource, regardless of ownership, compared to the levelized delivered cost of an equivalent 

amount of reasonably available substitute resources that do not qualify as eligible renewable resources, where the 

resources being compared have the same contract length or facility life” (RCW 19.285.050(1)(b)). The Washington 

PUC staff commented that use of the wholesale market price does not appear to meet the language specified in 

statute (Washington UTC 2013).
7 

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

Compared to the MPR-based avoided cost estimate of $0.10/kWh, the utilities’ estimates 

based on market prices were much lower, roughly $0.03/kWh, which resulted in much higher 

estimates for incremental RPS costs (discussed further in Text Box 3). The PUC expressed 

concern with this approach, noting that the results would have prevented even low-cost hydro 

and nuclear resources from being determined cost-effective and that the calculations were 

based on short-run avoided costs (CPUC 2013a). 

2.1.3 Modeling Approaches

Modeling approaches can provide a system-wide look at the differences in resources built and 

dispatched with and without the addition of renewable energy (instead of just looking at one 

generator type or the wholesale market price). Key inputs to dispatch and capacity expansion 

planning models include the fuel prices for fossil generation, inclusion of environmental costs, 

and for models examining future scenarios, the availability of renewable energy tax credits. One 

advantage of the modeling approach is that it can provide a more comprehensive picture of what 

would have happened absent the RPS. Modeling approaches may also be able to better capture 

integration and transmission costs. However, modeling results are heavily dependent upon the 

key inputs, which are complex and subject to judgment. 

States have taken different approaches to modeling approaches. Some examples include the 

following: 

Text Box 1. Rate Impact Calculations in Minnesota

Utilities in Minnesota have used different methods to estimate RPS incremental 

costs. Xcel Energy (MN) examined the cost of the renewable resources compared 

to the cost of the same amount of energy and capacity in the MISO market. To 

determine the renewable energy costs, they included the price paid for contracted 

energy or annual revenue requirements at their owned facilities (Xcel Energy 

2011). Xcel Energy found that the rate impact for wind resources over 2008 and 

2009 was approximately 0.7% less than market prices, though biomass resources 

were slightly higher (0.56% and 1.16% in 2008 and 2009, respectively). 

Other utilities in Minnesota had different results. Of the fourteen utilities that 

submitted reports, eight said that complying with the renewable standard has 

resulted in little or no additional costs, if not a slight savings for customers, while 

six utilities, including Great River Energy, reported that their efforts to comply with 

the policy led to increased costs for customers. Great River Energy modeled a noRPS scenario that did not include additional non-renewable resources, then 

compared that with the RPS scenario in which renewable energy was added to 

comply with the RPS. Great River Energy found that its wind energy purchases 

increased retail customer bills by about 1.6%, or about $18/year for an average 

homeowner. 
8 

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

• In Colorado, statute requires that utilities estimate the incremental cost of the RPS through 

modeling work. Utilities must use scenario analysis, comparing the costs and benefits of the 

renewable energy standard plan to a plan that replaces the new renewable resources with new 

non-renewable resources reasonably available. 

• In Minnesota, Xcel Energy used wholesale market prices to determine historic RPS costs, but 

used a long-term resource planning tool, Strategist, to estimate future costs. The model 

calculates the present value of revenue requirements for different expansion plans. Xcel 

developed two base models, one that met the RPS, and one that replaced all incremental wind 

resources with conventional resources. Three additional scenarios explored the impact of 

extending the PTC though 2020, placing a price on carbon dioxide emissions, and a high 

natural gas price scenario. There was minimal difference between the cases; the base case 

without the RPS resulted in 1.4% higher net present cost than the RPS case. The PTC 

extension, CO2 price, and high gas price cases resulted in 0.74%, 0.41%, and 0.98% higher 

net present costs, respectively, for the conventional resource plan than the RPS case (Xcel 

Energy 2011). 

• In New Mexico, Public Service Company of New Mexico (PNM) calculates RPS costs for 

the following two years using production cost modeling. PNM models the total system costs 

with and without each existing and proposed renewable resources to determine the avoided 

fuel cost for each resource (PNM 2013a). PNM also develops a single avoided fuel cost 

figure, for all renewable resources, which it uses to validate the individual results and also in 

calculating the cost cap.

• In North Carolina, utilities use a hybrid of modeling and a proxy generator method. The 

incremental RPS costs are defined as those that “are in excess of the electric power supplier’s 

avoided costs,” where avoided costs include both energy and capacity (North Carolina G.S. 

62-133.8(h)). Duke Energy uses the Commission-approved “peaker method” to determine its 

avoided costs. The peaker method calculates avoided costs based upon the capacity cost of a 

combustion turbine peaking unit plus the marginal running costs of the system, which are 

calculated based on simulation of Duke’s system with and without the RPS resources (Duke 

Energy 2010). 

• In Michigan, utilities use a hybrid method when seeking to recover the RPS costs. 

Incremental RPS costs are specified as the difference between the gross renewable energy 

costs and the “transfer price”. The transfer price is determined by each utility and must

reflect long-term capacity and energy, but does not need to be equivalent to the cost of a new 

coal-fired facility, determined by the PUC (DTE 2009). In practice, Consumers Energy has 

calculated the transfer price based on capacity values for a gas-fired combustion facility and 

energy values calculated using a dispatch model (Consumers 2009). DTE has used the annual 

average locational marginal prices and adjusted capacity payments, by technology, compared 

to a new gas-fired combustion turbine (DTE 2009). 
9 

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

2.1.4 Additional Considerations for Estimating Incremental RPS Costs in 

Regulated States

2.1.4.1 Timeframe of Cost Calculation

When evaluating incremental RPS costs, regardless of method, a key consideration is the 

timeframe to examine. 

In most cases, cost calculations are made over a longer time period and then annualized to one 

year.6 This recognizes that procurement to meet the RPS may be “lumpy” in nature, and that the 

relative cost of renewable energy to conventional alternatives will depend on future conditions, 

e.g., natural gas prices and environmental regulations. In states where utilities are offering an 

upfront solar rebate to procure supply to meet a solar carve-out, spending may be particularly 

front-loaded because the rebate is paying upfront for a long-term resource: for example, the 

utility may offer an upfront rebate per watt in exchange for the RECs produced by the system 

over 20 years. 

For studies using the proxy generator approach, decisions will have to be made about the time 

over which the conventional and renewable generator costs are levelized. In Michigan, the PUC 

compares the costs of renewables against the 40-year life cycle cost of a coal plant. The life cycle 

approach and the 40-year lifetime introduce additional uncertainty into the cost of the coal plant, 

including uncertainty around potential future federal regulation of coal plants. For example, 

actual future fuel prices can differ significantly from forecasts. In addition, the costs of 

renewables are typically recouped over a shorter time period (15-20 years), meaning that the cost 

comparisons are not done over the same time period. 

When examining market prices, studies consider whether to use historical market prices 

compared to RPS generation in each year, or to use projections of future market prices compared 

to the RPS resource lifetime. 

On the modeling side, Missouri examines RPS compliance costs over 10 years, and then divides 

those costs into annual increments; if the one-year annual rate increase exceeds 1%, then the 

utility’s RPS obligation is decreased so that rates do not exceed 1%. In order to calculate the 

costs over the 10-year period, the utilities estimate their cost of compliance for each year based 

on an RPS-case and a no-RPS case (MO CSR 240-20.100(5)). 

California is in the process of developing a cost cap for its 33% RPS. As part of the process, the 

CPUC staff proposed using a 10-year rolling calculation. In response to the CPUC staff proposal, 

some parties argued that the timeframe should be longer (e.g., 20 years), in order to match the 

typical length of renewable energy contracts. Others argued that the cost cap should look only at 

procurement in an individual year. 

2.1.4.2 Inclusion of a Carbon Adder

Whether using a proxy generator, wholesale market prices, or modeling tools, a carbon price 

could be added to the comparison scenario given that some states or utilities may have a 

 

6 One notable exception is in New Mexico, where rules specify that cost cap calculations shall not include 

annualization.
10 

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

preference for procuring low-carbon resources. That is, even if there were no RPS, state 

regulators or utilities may have wanted to incorporate a cost of carbon when making decisions 

about procurement (potentially in anticipation of potential future carbon regulations). However, 

some argue that in markets where there is currently no carbon policy, and thus utilities are not 

paying a cost for carbon, adding it to the non-renewable resource cost is inappropriate. 

The Colorado PUC initially required that the non-RPS scenario include a carbon adder and a 

capacity credit. Adding these costs to the counterfactual scenario can be contentious, as there is 

no existing capacity market in Colorado, nor is there a state-wide price on carbon (Stockmayer et 

al. 2012). In its latest RPS compliance plan, Xcel Energy (Colorado) did not include a carbon 

price for 2014 calculations (PSCo 2013). 

California’s latest MPR calculation was done in 2011, before the state’s carbon cap and trade 

program went into effect. The CPUC determined that the market-based forward natural gas and 

electricity prices should be used to calculate the implied GHG price. This methodology resulted 

in GHG compliance costs of $16.27/CO2 metric tonne in 2013, increasing to $36.64/CO2 metric 

tonne in 2020 (CPUC 2011). 

2.1.4.3 Inclusion of Renewable Resources Not Driven by RPS

In some cases, renewable resources that are counted towards a particular state’s RPS target may 

have been procured independently from the RPS. The most prevalent example would be preexisting renewable resources that were constructed or contracted prior to the RPS. Because some 

states allow renewable resources that were in place at the time the RPS was passed to count 

toward RPS compliance, a key consideration is whether the costs of those resources are included 

in RPS cost estimates. Because those resources would have been developed regardless of an 

RPS, including the costs in an incremental cost calculation would result in overestimating RPS 

compliance costs. In other states, pre-existing resources are not eligible to meet the RPS, so this 

question is not an issue. 

• In Colorado, the state’s largest IOU, Xcel Energy, recovers incremental costs through a 

surcharge on customer bills known as the RESA surcharge. The surcharge only covers the 

above market costs of new renewables and contracts signed after July 2, 2006 (the date of the 

commission order approving the RESA) (PSCO 2013c). Renewable resources that were 

online on or after January 1, 2004 are eligible to meet the RPS. 

• In Kansas, some of the renewable projects were built prior to implementation of the RPS, but 

the costs are still being included in the cost calculation. For example, Kansas Electric Power 

Cooperative (KEPCo) is using exclusively hydropower that it has been purchasing since the 

1980s in order to meet the RPS. The utility determined that the hydropower had no cost 

impact to ratepayers because it is the least expensive generation source (KEPCo 2013). 

• In Oregon, Portland General Electric (PGE) determines an incremental cost for only one 

renewable resource, Bigelow Canyon. PGE owns and operates Bigelow Canyon, so it used its 

actual capital costs, O&M costs, capacity factor, as well as wind integration costs that were 

calculated as part of the IRP process to calculate the levelized cost of the wind farm, which is 

then compared to the life cycle costs of a combined cycle natural gas plant (PGE 2011). The 

rest of PGE’s renewable resources have been determined to have zero incremental cost. 

Oregon’s regulations specify that “incremental costs are deemed to be zero for qualifying 
11 

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electricity from generating facilities or contracts that became operational before June 6, 2007 

and for certified low-impact hydroelectric facilities under ORS 469A.025(5)” (OAR 860-

083-0100(1)(i)). 

• Ameren Missouri, which owns a hydro facility that is eligible to meet Missouri’s RPS, values 

the RECs generated by that facility at zero cost. Ameren Missouri notes that the capital and 

operational expenses for the facility are already included in existing rates, therefore, there are 

no additional costs to use the generated RECs for RPS compliance (Ameren Missouri 2013a). 

Another example of renewable resources that may be procured independently from an RPS are 

upgrades to hydroelectric facilities, which are often treated as an eligible RPS resource. This 

issue has arisen in Washington, where some utilities have included the cost for efficiency 

upgrades at hydropower facilities. Hydropower upgrades are eligible to meet the RPS, but the 

upgrades were required by the Federal Energy Regulatory Commission; therefore, the upgrades 

would have occurred even if there were no RPS in Washington. In Washington, PacifiCorp has 

not included hydropower upgrades in its incremental RPS cost calculation, while Avista has 

included the cost of hydropower upgrades (Pacific Power 2013a; Avista 2013). 

2.2 Approaches for Estimating Incremental RPS Costs in States with 

Restructured Electricity Markets

In restructured markets, as electricity rates are not regulated, obligated entities typically do not 

disclose the cost to meet RPS.7 In some restructured markets, however, information on the cost 

of RECs is required to be provided and these costs, along with the costs of ACPs, can be used to 

estimate incremental RPS costs. RECs can be purchased separately from electricity, and in such 

cases, it is commonly assumed that the RECs represent the incremental RPS costs, as the RECs 

would not have been purchased absent an RPS.8 There are, however, a variety of limitations with 

this approach, most notably, REC price volatility, limited REC price transparency (especially for 

medium- and long-term REC price contracts), and the fact that REC prices and ACPs ignore a 

number of potentially important costs and benefits from renewable energy. 

REC prices do not necessarily reflect the underlying cost of renewable electricity generation, 

because they are influenced by supply and demand in the marketplace. There is substantial 

variability in REC prices from year to year depending on how states are meeting their RPS 

targets. In oversupply situations, REC prices can fall dramatically while in shortages they can 

rise to the level of the ACP. Therefore, cost calculations based on REC pricing can vary 

considerably from year to year. In the next section, we examine costs over a three-year period to 

try to capture this variability. 

In addition, there is a lack of transparency in REC prices. Many load-serving entities enter into 

multi-year contracts for RECs–usually not more than three years–to meet RPS requirements. 

Little publically available data are available on these contracts. Spot market transaction data are 

available from some brokers, and can be used as a proxy, but these prices can differ from the 

 

7 REC prices paid by utilities in regulated states are also often deemed confidential by the PUCs and therefore they 

are not made public.

8 For additional information on RECs, see Heeter and Bird (2011). 
12 

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

longer-term bilateral transactions. The source of data and assumptions about REC prices can 

substantially influence the cost calculation.9

 

In Illinois, Maine, Maryland, New Jersey, Ohio, Pennsylvania, and Washington, D.C., data on 

REC pricing and use of ACPs as purchased and employed by compliance entities are publically 

available (Table 2).10 Publically available data sources for these states provide information on 

the cost of the RECs retired, including those RECs that were procured under long-term contracts, 

which may be procured at a higher or lower price than is seen in the current spot market. 

However, in New Jersey, only data on solar RECs are comprehensive, because the Board of 

Public Utilities (BPU) set up a system for collecting data on the price of solar RECs as of the last 

transaction before a REC is used for compliance. However, for Class I RECs11, the same data are 

not collected on every transaction. As a result, in order to estimate costs, the New Jersey Office 

of Clean Energy relies on REC pricing information from other sources (e.g., brokers) (NJ BPU 

2011). 

In Delaware, Massachusetts, New Hampshire, Rhode Island, and Texas, no such publically 

available source on the REC prices paid by compliance entities is available. In these states, 

available spot market REC pricing from REC brokers can be used to approximate the cost of 

RPS compliance. Broker prices may represent a small volume of transactions, however, and it is 

uncertain how indicative they are of the average price of all RECs used for compliance by 

obligated entities.

 

9 One example of REC price approximation comes from by New Mexico, a traditionally regulated state. 

Southwestern Public Service Company (SPS) used a proxy REC price to determine RPS costs associated with two 

bundled PPAs for wind generation. To determine a proxy REC price, SPS examined REC prices in the national, 

western U.S., and Texas REC markets ($0.89/MWh, $2.31/MWh, and $1/40/MWh, respectively). The proxy REC 

price agreed upon was $1.35/MWh, slightly less than the average of the three markets, recognizing that REC prices 

are decreasing and that SPS has been unable to sell existing RECs into the western U.S. REC market (NM PRC 

2011).

10 REC pricing data from Maryland have been provided upon request to the PUC. Data from other states may also be 

available by request.

11 Class I RECs are for the primary RPS target. 
13 

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

Table 2. Publically Available Information on REC Pricing

State Type of Pricing 

Available 

Frequency Data Source

Illinois Average price by 

product type, for each 

Illinois Power Agency 

RFP

Following approval of 

annual Illinois Power 

Agency RFP bid awards

Illinois Corporation 

Commission notices of 

RFP results

Maine Weighted average REC 

price and range

Annually Maine PUC reportsa

Maryland Weighted average REC 

price

Annually Suppliers provide data 

to PUC, not published

New Jersey Weighted average 

SREC price

Monthly Website, New Jersey 

Clean Energy Programb

Ohio Weighted average REC 

price 

Annually Ohio PUC reports

Pennsylvania Weighted average REC 

price and REC price 

range

Annually Pennsylvania PUC 

website and reportsc 

Washington, D.C. Average REC price by 

resource type

Annually District PSC reportsd

a “Reports to the Legislature.” (2013). Maine Public Utilities Commission. Accessed February 

2014: http://www.maine.gov/mpuc/legislative/reports.shtml. b “SREC Pricing.” (2013). New Jersey Clean Energy Program. Accessed January 

2014: http://www.njcleanenergy.com/renewable-energy/project-activity-reports/srec-pricing/srec-pricing. c “Pricing.” Pennsylvania AEPS Alternative Energy Credit Program. Accessed December 

2013: http://paaeps.com/credit/pricing.do. d “PSC Reports to the DC Council.” (2013). Public Service Commission of the District of Columbia. Accessed 

December 2013: http://www.dcpsc.org/reports/dc_council.asp. 

Note: Weighted average REC prices take into account the volume of RECs purchased at different prices. 

Washington, D.C. does not publish weighted average REC prices but does publish the average REC price by

resource type.

Additional REC pricing information is provided by several SREC brokers as well as PJM-GATS, 

the REC tracking system for the mid-Atlantic, though each source has limitations. SREC brokers 

provide only information on spot market transactions.12 PJM-GATS reports solar-weighted 

average prices for transactions in the PJM market that include pricing from long- or mid-term 

contracts as well as spot prices. PJM-GATS reports prices on a monthly basis based on when the 

SREC was issued, traded, or retired, not on when the generation occurred.13 As a result of this 

type of reporting and the decline in spot SREC prices, the SREC prices reported in PJM-GATS 

have been higher than spot market SREC prices. 

One final limitation associated with relying on REC and ACP costs to estimate RPS compliance 

costs is that a number of potentially important costs and benefits may be omitted. For example, 

the approach may ignore certain integration costs associated with variable RPS resources and 

may not fully capture transmission capacity expansion costs. This approach, however, also 

ignores any cost savings that LSEs may receive as a result of the reduction in market clearing 

 

12 For example, see www.srectrade.com or www.flettexchange.com. 13 For example, if a company contracted for SRECs that were generated in January 2010 at a given price but did not 

retire those SRECs until August of 2011, the January 2010 price would be reflected in PJM-GATS’s August 2011 

solar weighted average price report.
14 

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

prices in regional energy markets, associated with low marginal-cost renewable resources. These 

issues are addressed in more detail in Section 2.4.

2.2.1 Treatment of ACPs

Utility ACPs are a component of RPS compliance costs. Although ACPs will always – at least 

initially – be a cost to the utility or supplier, whether these costs may be passed through to 

ratepayers varies by jurisdiction (Table 3). In some states, utilities are explicitly not allowed to 

receive cost recovery for ACPs. In other states, cost recovery is possible, but not guaranteed. 

Finally, some states allow for automatic cost recovery (though, even in these cases, retail prices 

charged by competitive suppliers are established through market dynamics, and so pass-through 

of ACPs is generally not directly observable). In some states, the funds raised by ACPs collected 

are used to support renewable energy project development in the state, which may further reduce 

overall cost impacts. While the treatment of ACPs is not important in determining the cost that 

the supplier will initially pay to meet the RPS, it does impact the ability of compliance entities to 

pass on those costs, and therefore also impacts the ultimate costs that ratepayers pay for RPS 

compliance. 

In Ohio, Pennsylvania, and Texas, utilities are not allowed to pass through ACPs to ratepayers. 

In Connecticut, the ACPs are used to offset other ratepayer costs, and in New Jersey, solar ACPs 

are refunded to ratepayers. In Delaware, Maryland, Oregon, New Hampshire, and Washington, 

D.C., ACP cost recovery is possible, but not guaranteed. Finally, in Illinois, Massachusetts, 

Maine, New Jersey (non-solar), and Rhode Island, ACP cost recovery is automatic. 

Table 3. ACP Cost Recovery Provisions

ACP cost recovery provision States

Utilities not allowed to pass through ACPs 

to ratepayers

OH, PA, TX

ACPs used to offset other ratepayer costs 

or refunded to ratepayers

CT, NJ (solar)*

ACP cost recovery is possible DE, MD, OR, DC, NH 

ACP cost recovery is automatic IL, MA, ME, NJ (non-solar), RI

* In New Jersey, the Solar Advancement Act of 2010 required that solar ACPs be returned to ratepayers.

2.3 Gross RPS Compliance Costs

Three states (Kansas, Nevada, and California) examine gross, rather than incremental, RPS costs. 

Gross costs are the total costs of renewable energy procurement, as opposed to incremental costs 

that reflect the difference between these total costs and conventional generation. There are some 

advantages to examining gross costs–namely, that no modeling work needs to be done, nor does 

a proxy conventional generator need to be assigned. While gross costs do not allow for 

comparison against what would have happened absent the RPS, they can help regulators 

understand trends in renewable pricing, and they may be used as part of a cost cap calculation. 

Gross compliance costs could also be used as part of a complete cost-benefit assessment, where 

in avoided costs would be treated as a benefit. 

The Kansas Corporation Commission (KCC) develops gross costs as part of rate impact 

calculations. The KCC developed regulations that require each obligated utility to submit 

compliance reports that detail the retail revenue requirement of renewable generation used to 
15 

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

meet the RPS.14 Using this information as well as volumetric sales data, the KCC calculated the 

rate impact on a statewide basis, thus holding confidential individual utility revenue information. 

In Nevada, Nevada Power and Sierra Pacific report estimated gross RPS compliance costs for 

approval by the Nevada PUC. Costs include the cost of purchased power and RECs, general and 

administrative expenses, O&M for company-owned renewable generation, as well as costs of 

renewable incentive programs and energy efficiency programs. Energy efficiency can be used to 

meet up to 25% of the RPS target through 2014, and then this provision phases out so that by 

2025, energy efficiency cannot meet any part of the RPS target. 

The California PUC is in the process of developing a method for calculating and implementing a 

cost containment mechanism, as required by SB 2(1X), signed in 2011. The new method will 

replace the MPR methodology that was calculated on an annual basis by PUC staff. The 

California PUC staff proposal outlines a process that would calculate a procurement expenditure 

limit based on an IOU’s RPS gross procurement expenditures divided by the IOU’s total revenue 

requirement on a rolling 10-year basis (CPUC 2013b). 

2.4 Including Other Expenses in RPS Cost Calculations

In some cases, factors that affect the economic value or costs of renewable resources may not be 

reflected in REC prices or in the costs that utilities and states include when estimating the 

incremental cost of RPS resources. Although typically RPS cost assessments look exclusively at 

the cost of renewable generation or RECs, some assessments also include information about nonrenewable generation that is eligible for the RPS (e.g., energy efficiency) or indirect and/or 

administrative expenses. 

2.4.1 Integration Costs and Network Transmission Costs

Two costs in particular – integration costs and network transmission costs – are often not 

allocated to the renewable generator and are instead borne by other users or by the power system. 

Thus, although these costs are not typically included in RPS incremental cost estimates, this 

section provides information on other estimates of integration and network transmission costs. 

In the U.S. numerous studies estimate integration costs for wind to be less than $5/MWh even 

with very high wind penetration levels (>20% penetration on an energy basis), though some 

smaller individual utilities estimate costs up to $12/MWh, and one utility (Idaho Power) 

estimated cost over $18/MWh (Wiser and Bolinger 2013). 

Aside from forward looking studies, two other indicators of integration costs are actual 

integration tariffs charged to wind generators in particular balancing areas (which may already 

be reflected in REC prices for those wind generators) and backward looking assessments of 

integration costs by system operators with significant amounts of wind. Retrospective analysis of 

actual wind balancing reserves and integration costs in ERCOT (with 8.5% wind penetration on 

an energy basis) resulted in wind integration costs on the order of $1.2/MWh (Maggio 2012). 

Actual wind integration charges by several different entities in the U.S. (Bonneville Power 

 

14 The retail revenue requirement is defined as: (Rate base * Rate of return) + O&M + Administrative & General 

Expenses + Depreciation + Taxes.
16 

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

Administration, Westar Energy, Puget Sound Energy, and the Nebraska Public Power District) 

range from $0.70 to $6.85/MWh (Wiser and Bolinger 2013). 

Network transmission upgrades (as opposed to dedicated grid-tied assets) are used by multiple 

resources on the grid and often have many beneficiaries. Challenges in quantifying benefits for 

specific beneficiaries of long-lived transmission assets has led to network transmission costs 

often being allocated to loads rather than particular generators. In these cases, the cost of 

renewable resources will not reflect the cost of network transmission investments needed to 

deliver power to leads. One assessment of the costs of transmission for wind implied by various 

planning studies in the U.S. found a median transmission cost of $15/MWh (Mills et al. 2012). 

California’s Section 910 Report acknowledges that for indirect costs, “it does not appear that the 

utilities use a consistent methodology to track these expenditures, that these costs are tracked in a 

manner that allows clear attribution to the RPS program, or that it is always possible to 

determine what portion of the costs should be attributed to the RPS program” (e.g., transmission 

costs) (CPUC 2013a, p. 5). 

In Minnesota, however, utilities are required to estimate the rate impact of the RPS, including 

energy purchases, generation facility acquisition and construction, and transmission 

improvements (Minn. Stat. Section 216B.1691 Subd. 2e.). Xcel Energy (MN) recognized that 

new transmission lines have multiple benefits, making it difficult to allocate costs; as such, they 

only provide a “rough estimate” of transmission costs associated with the RPS (Xcel Energy 

2011, p. 10). 

The New Mexico Public Regulation Commission (PRC) ruled in November 2013—after years of 

discussion about how to calculate costs pursuant to the state’s cost cap—that cost calculations 

can include O&M, back-up and load following generation, off-system sales opportunity impacts, 

or other facilities and improvements or functions that may be required (NM PRC 2013a). In 

January 2014, however, the PRC agreed to re-hear the case, as requested by the New Mexico 

Independent Power Producers (NMIPP). NMIPP argues that the new cost methodology includes 

“expansive new costs of renewable energy while narrowing the benefits of renewable energy 

(NMIPP 2013, p. 10-11)” and does not reflect the intent of the states’ RPS policy or the 

comments submitted in the case. 

2.4.2 Inclusion of Administrative Expenses

Another methodological consideration is whether to include other indirect costs, such as 

administrative expenditures. Administrative expenses may also be easy to track on a gross basis, 

but difficult to determine on an incremental basis, as it is likely unknown what the administrative 

expenses would have been to procure non-RPS resources. 

Although most states have not addressed administrative expenses, in Nevada, utilities include 

administrative expenses in their gross cost calculations and in Colorado, administrative expenses 

are limited by statute to 10% of total annual RPS revenue collection. However, Colorado utilities 

can request a waiver during the ramp-up stage of the RPS program. This presumably 

acknowledges that administrative expenses may be higher in initial years due to start-up costs. 
17 

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

2.4.3 Treatment of Energy Efficiency Eligible to Meet RPS

Seven state RPS policies (Michigan, Ohio, Pennsylvania, Connecticut, Hawaii, Nevada, and 

North Carolina) include energy efficiency as an eligible resource (though energy efficiency is 

being phased out as an eligible resource in Nevada). These policies cap the amount of energy 

efficiency that can be used and to the extent that data are available, energy efficiency is generally 

being used to the maximum amount allowed (Heeter and Bird 2013). 

Little cost data on energy efficiency being used to meet RPS policies are available. However, 

Michigan looks at the weighted average cost of energy efficiency and incorporates that figure 

into the cost of RPS compliance. The weighted average cost of energy efficiency was $20/MWh, 

compared to the weighted average cost of renewable energy at $83/MWh. Together, the 

combined weighted average cost of energy efficiency and renewable energy was $46/MWh. 

In Connecticut, the state uses a separate tier for energy efficiency. Compliance is achieved 

through the use of credits, and some price information is available for those credits from brokers. 

Pennsylvania publishes data on an annual basis for its Tier II RPS, for which energy efficiency is 

eligible, but appears to not be making a major contribution. Of over 9,000 registered facilities, 

there are only a dozen energy efficiency or demand side management (DSM) facilities. In 

addition, in 2012, there were no EE or DSM credits retired to meet the RPS. 

2.5 Summary of Methodological Considerations 

In order to assess the impact of RPS policies, incremental cost estimates are preferable, rather 

than estimates of gross costs. While gross compliance costs can help understand trends in 

renewable pricing, if not netted out from benefits, they can overestimate the actual policy costs 

since other energy sources would have been used to meet loads absent the RPS. The use of 

renewable sources could displace some need for fossil fuels use in existing generators, and, in 

many cases, could displace the need for other fossil-fuel-based generation capacity. 

At the same time, calculating incremental costs can be challenging; given the number of ways in 

which incremental cost calculation methodologies can differ, several state PUCs have begun 

discussions about how to standardize RPS cost calculations. These standardization efforts are 

underway or recently concluded in California, Delaware, Minnesota, Oregon, and Washington 

(see Text Box 2 for more detail). 
18 

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

Currently, incremental RPS costs are being examined in traditionally regulated states by 

comparing RPS costs to a proxy generator, to market electricity prices, or through modeling 

approaches. Each of these three methodologies has advantages and disadvantages: 

• Using a proxy generator may be a simpler approach but may not represent what actually 

would have happened absent an RPS as well as using wholesale market prices or a modeling 

approach. The proxy generator may not be the type of resource that is always displaced, 

because the renewable resources may displace different types of resources over the course of 

the day. In Minnesota, Minnesota Power submitted comments to the PUC suggesting that 

Text Box 2. State PUC Cost Standardization Efforts

In California, the PUC is developing a methodology to calculate spending limits to meet the 

state’s 33% RPS requirement. The PUC has issued a staff proposal on the methodology; 

stakeholders have developed alternative proposals and comments on all proposals are due in 

March 2014 (CPUC 2014). 

Rulemaking is underway in Delaware to clarify the state’s RPS cost cap provision. Draft 

regulations specify that the Division of Energy & Climate will determine the cost of 

compliance, which will then be review by the Director. The Division Director shall then 

determine the whether to freeze RPS requirements. As part of that determination, draft 

regulations specify that the Director may consider benefits such as price suppression, savings 

in health and mortality costs, and economic development benefits from renewable energy 

deployment in the state. (DE DNREC 2013) 

The Minnesota PUC is developing a uniform reporting system for RPS rate impact data. The 

PUC is currently accepting comments on general guiding principles for cost impacts as well 

as on a uniform reporting system. The general guiding principles proposed by the PUC staff 

include: Foster transparency; support consistency, coordination and non-burdensome 

administration; provide realistic representation of baseline, actual (to date) and future 

expected costs; and enable comparison across utilities. (MN PUC 2013). 

In Oregon, a methodology for calculating incremental RPS costs was developed but it was 

noted that the assumptions would be modified as utilities gained more experience with the 

incremental cost calculation. The PUC held workshops in 2012 and 2013 to discuss such 

issues; the PUC approved a stakeholder agreement in January 2014. The agreement continues 

use of a CCCT as a proxy generator. The parties did not agree on whether a capacity payment 

should be included, but they did agree that utilities should consider incorporating a capacity 

value. Utilities will also provide an additional scenario that assumes reduction in long-term 

fuel price risk. (PUC OR 2014) 

Rulemaking is underway in Washington, where the PUC has an open rulemaking to address 

modifications to the RPS (UE-131723). Some stakeholders have expressed interest in creating 

a uniform approach to calculating incremental costs of RPS. 
19 

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

using a combined cycle proxy unit could understate the costs of the RPS because natural gas 

is not the marginal unit in both on- and off-peak time periods.15 

• Comparing to a wholesale market price requires determining a number of variables, 

including whether wholesale market generation is shaped to match the output of renewable 

energy. In Washington State, utilities have taken different approaches towards shaping the 

wholesale market generation, and the Washington UTC is examining cost standardization. 

• Modeling approaches can more fully explore alternative options beyond using a single proxy 

generator and can assess capacity savings. However, stakeholders may disagree on the 

appropriate modeling inputs, for example, whether to include carbon or other adders in the 

non-RPS scenario. If a carbon price is added to the cost of non-renewable generation, then 

the resulting incremental cost will be lower than if a carbon price is not added.

Within each primary methodology (proxy generator, market price, or modeling), a number of key 

considerations can influence the magnitude of the resulting incremental cost: 

• Including pre-RPS renewables. Including pre-RPS renewables in the cost calculation will 

overestimate the cost of meeting the RPS, since the pre-RPS renewables would have been 

developed regardless of the RPS policy. 

• Indirect expenditures. Indirect expenditures, such as integration costs, transmission or 

distribution expenditures, or administrative expenditures, can be challenging to quantify, as 

they may be related to both renewable and non-renewable energy; if including indirect 

expenditures in an incremental RPS cost calculation, the indirect expenditures should also be 

incremental. If the RPS were not implemented, there would likely be expenses associated 

with procuring non-renewable generation. 

• Plant lifetime. Assumptions about the operating life of a non-renewable plant can introduce 

uncertainty about future fuel costs. For example, fuel costs for a coal or natural gas plant 

become more uncertain when a longer plant life is assumed. For renewable resources, the 

assumed lifetime can also impact the levelized cost of the generation.

• Annualizing costs. Annualizing costs can account for the “lumpiness” of renewable energy 

procurement, but may obscure annual ratepayer impact. If a utility is making large 

investments on a non-annual timeframe, it may see higher costs in some years than others. 

For example, if a utility is operating a solar rebate program, it may provide upfront financial 

incentives in exchange for the RECs produced by the solar system over its lifetime. 

• Including energy efficiency. Including energy efficiency in an incremental RPS cost 

calculation provides an assessment of total policy costs, where standards are combined, but 

could complicate the ability to assess the renewable energy costs. However, most states have 

moved to separate standards or tiers for renewable energy and energy efficiency, which 

eliminates competition between the two resource types (Heeter and Bird 2013). 

In restructured markets, incremental RPS costs are typically calculated using REC prices. This 

reflects the cost that load serving entities must pay to achieve compliance, but may not reflect the 

 

15 The Minnesota PUC is currently considering accepting comments on the utility cost impact reports required by 

statute (Docket E999/CI-11-852).
20 

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

cost of developing renewable generation in the region. In addition to some of the considerations 

listed above, using a REC price approach can be limited because REC prices may fluctuate 

dramatically based on supply and demand considerations, which can substantially differ from the 

levelized cost of the renewable energy developed. The treatment of ACPs will also influence 

how closely the costs incurred by the compliance entity track the costs passed on to ratepayers. 

Another consideration is the source of the data on REC prices. PUCs collecting data on the price 

of RECs retired to meet the RPS will have a more precise representation of the RPS costs, 

compared to using prices from a broker. 
21 

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

3 Incremental RPS Compliance Costs: Historical Data 

for 2010 to 2012

This section summarizes and compares estimated incremental RPS compliance costs for the 

period 2010 to 2012.16 For states with restructured markets, we estimate RPS costs using 

available REC price data and ACP prices and volumes. For traditionally regulated states, we 

instead rely upon RPS cost estimates reported directly by utilities or regulators, translating those 

results, where necessary, into a set of common metrics. As discussed in Section 2 and described 

further below, the cost estimates for regulated states employ widely varying methods and 

assumptions (see Figure 1). As such, the estimated costs itemized in this section do not result 

from the application of a standardized approach or the use of a consistent set of underlying 

assumptions. Because the reported values may differ from those derived through a more 

consistent analytical treatment, we do not provide an aggregate national estimate of RPS costs. 

The section also provides data on RPS surcharges levied on customer bills, for states where such 

mechanisms are in place; those surcharges represent the net cost borne directly by customers. 

Finally, the section assesses the potential for increases in RPS compliance costs as RPS targets 

rise, and for cost caps to become binding. 

Figure 1. Overview of methodologies used to calculate RPS costs

Note: While there is a spectrum of restructuring in states, for the purposes of this study, we classify the following RPS 

jurisdictions as operating in traditionally regulated markets: Arizona, California, Colorado, Iowa, Kansas, Michigan, 

Minnesota, Missouri, New Mexico, North Carolina, Oregon Washington, Wisconsin, and Wyoming.

Two metrics are used within this section to describe incremental RPS costs:

 

16 We examine a multi-year period in order to capture fluctuations in REC pricing and to expand the scope of states 

that can be included, given varying data availability in some states from year to year. As of this report writing, 

insufficient data for 2013 were available for inclusion.

REC Price 

Proxy Generator

Market Price

Modeling

Other/Hybrid

Gross Costs

No Data Available

No RPS

Traditionally regulated state

R R

R

R

R

R

R

R R R

R

R R R

R

R

R
22 

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

• Dollars-per-MWh ($/MWh) of renewable energy required or procured. This metric 

represents the average incremental cost of RPS resources relative to conventional generation. 

It answers the question: On average, how much more was paid for renewable energy than for 

an equivalent amount of conventional generation? 

• Percentage of average retail electricity rates. This metric represents the dollar magnitude of 

incremental RPS costs relative to the total cost of retail electricity service (generation, 

transmission, and distribution). It answers the question: How significant are RPS costs 

compared to the overall cost of retail electricity service, and what impact might that have on 

electricity prices faced by consumers?

Several general caveats about the estimated incremental cost data must be stated up front. First, 

comparisons across states are highly imperfect, given the widely varying methods and 

assumptions employed to estimate incremental costs. This is particularly true among regulated 

states where we rely upon estimates produced by utilities and regulators. To the extent possible, 

we highlight instances where these methodological differences may be a particularly significant 

driver for the results observed, though ultimately the available information does not allow for a 

rigorous analysis of this issue. Second, the incremental cost data represent the estimated net cost 

of RPS compliance to utilities (or to LSEs, more generally). Accordingly, they do not represent 

net costs to society at large, which would require a broader set of considerations (some of which 

are discussed in Section 4). Utility compliance costs also should not be equated to ratepayer 

costs, as the two may diverge for a variety of reasons.17 Third, the incremental cost estimates

presented here may omit both certain costs and benefits borne by utilities. Elsewhere within the 

report, we discuss the potential magnitude of perhaps the most significant of these omitted items: 

on the cost-side, integration and network transmission costs (see Section 2) and among the 

benefits, wholesale electricity market price suppression (see Section 4). 

3.1 States with Restructured Markets

In restructured markets with competitive retail markets, RPS compliance obligations are 

generally placed on LSEs, and compliance is achieved through the purchase and retirement of 

RECs. Retail suppliers in these markets typically do not have long-term certainty regarding their 

load obligations, and therefore typically purchase RECs through short-term transactions (e.g., 

spot market purchases or two- to three-year “strips”) for unbundled RECs. In recent years, 

longer-term (i.e., 10- to 20-year) contracting for bundled or unbundled RECs has become more 

prevalent, particularly among default service suppliers and as the result of requirements or 

programs established to facilitate financing for renewable project developers. 18

Many RPS policies divide the overall RPS target into multiple resource tiers or classes, each with 

an associated percentage target. These typically consist of some combination of a “main tier” for 

those resources deemed to be most preferred or most in need of support (e.g., new wind, solar, 

 

17 For example, ACPs and financial penalties are costs to the utility but are not always allowed to be recovered from 

ratepayers, or are often used to fund customer rebate programs. More generally, in regulated markets, the timing and 

extent to which RPS costs are passed through to ratepayers is subject to the ratemaking process within each state, 

while in competitive markets, the degree to which RPS compliance costs are passed through to retail electricity 

prices depends upon the competitive dynamics of the market. 

18 Default service, sometimes also called Provider of Last Resort service, is the retail supply option for customers 

that do not choose a competitive retail supplier, and is often provided by the regulated distribution service company. 
23 

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

geothermal, biomass, small hydro); one or more “secondary tiers” (e.g., existing renewables that 

pre-date the RPS, large hydro, municipal solid waste); and a solar or distributed generation (DG) 

set-aside. Most states with restructured markets include an ACP mechanism whereby an LSE 

may alternatively meet its obligations through issuing a payment to the program administrator, 

the dollar amount of which is determined by multiplying the LSE’s shortfall by a specified ACP 

price. In effect, the ACP price serves as a cap on REC prices, at least when ACPs can be 

recovered from ratepayers, as LSEs generally would not pay more than the ACP rate for RECs. 

3.1.1 Methodology and Data Sources

In general, we estimate incremental RPS compliance costs based on REC and ACP prices and 

volumes for each tier.19 For several states, exceptions (New York) or slight variations (Illinois 

and Delaware) on this approach were used.20 Again, these estimates represent the costs borne by 

LSEs, which may differ from the costs ultimately borne by customers, especially in cases where 

ACPs are not recoverable from customers. We translate these dollar costs into $/MWh by 

dividing by the amount of renewable generation required, and into a percentage of average retail 

electricity rates based on obligated LSEs’ retail sales and average statewide retail electricity 

prices published by the U.S. Energy Information Administration (EIA) (EIA 2013). 

The primary data sources used to compute incremental RPS costs are summarized in Table 4. For 

REC prices, we rely on PUC-reported data for the average price of RECs used for compliance in 

each year, wherever such data are available. Those prices, which are often based on data reported 

confidentially by individual LSEs, are presumed to reflect the cost of all RECs retired to fulfill 

the RPS obligation in each year, including short-term purchases of varying durations as well as 

RECs purchased under longer-term contracts. If PUC-reported REC price data are unavailable, 

we instead use the average of monthly spot market prices published by REC brokers (Marex 

Spectron for main tier and secondary tier RECs and a combination of sources for SRECs). 

Broker-reported spot market data were supplemented, when possible, with REC pricing data for 

any long-term contracts that may have been in effect during the 2010-2012 period. Data on longterm contract pricing for New England states was provided by Sustainable Energy Advantage 

(SEA) and for Delaware was obtained from Delmarva Power & Light’s Integrated Resource 

Plans.21 Volumes of REC retirements and ACPs are generally based on ex post data published in 

utility or PUC compliance reports or otherwise obtained directly from PUC staff. ACP prices are 

typically established by statute or regulation; main-tier and secondary-tier ACPs are generally 

 

19 Specifically, incremental costs are calculated according to: C = ∑ ��PREC,i × QREC,i� + �PACP,i × QACP,i�� n

i=1 , 

where C is the calculated incremental compliance cost (in dollars) for a particular state in a particular CY, n is the 

number of resource tiers within the RPS, PREC is the average annual REC price, QREC is the number of RECs retired 

for RPS compliance purposes, PACP is the ACP price, and QACP is the number of ACPs issued. 20 For New York, we calculate incremental RPS costs based on reported expenditures by the New York State Energy 

Research and Development Agency (NYSERDA), which procures RECs on behalf of the state’s IOUs. Those 

expenditures consist primarily of costs to procure RECs for the main tier and the cost of incentive programs for the 

distributed generation set-aside, as well as administrative costs. For Illinois, compliance costs for default service 

load are based estimates reported directly by the Illinois Power Agency (IPA), which reflect the cost of RECs 

procured by IPA on behalf of default service customers. For Delaware, 2012 compliance costs for Delmarva are 

based on the surcharge collections, which are a direct pass-through of REC costs. 21 SEA provided data on long-term REC contract pricing based on its own internal research and analysis. For 

bundled contracts, SEA estimated the implied REC price premium based on a comparison of the bundled renewable 

PPA prices to market prices for energy and capacity.
24 

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

are either fixed over time or increase with inflation, while solar ACPs often decline according to 

a pre-specified schedule (see Table 5 for ACP rates in effect during 2010-2012). 

There are various limitations inherent in our approach to estimating incremental RPS costs for 

restructured markets, including the following: 

• Omitted costs and savings. As noted previously, REC and ACP costs do not capture the full 

range of costs and benefits to the LSE. Of particular note, perhaps, are the omission of 

integration costs and the omission of savings from reductions to wholesale energy market 

clearing prices. As discussed in Section 2, wind integration cost studies have yielded a wide 

range of estimates, though generally less than $5/MWh up to relatively high penetration 

levels. Wholesale market price reductions, in comparison, have often been estimated through 

modeling to be on the order of $1/MWh or less (for all generation in the market). However, 

this price suppression benefit expressed as a fraction of renewable energy generation can be 

substantially larger in some cases, with estimates ranging from $2-50/MWh, as discussed 

further in Section 4. 

• Limited REC price transparency and liquidity. Broker-published REC price indices may be a 

poor proxy for the average price of all RECs used for compliance. This may occur in cases 

where a significant portion of REC transactions are occurring through long- or medium-term 

contracts and/or if broker prices are based on a small volume of transactions, in which case 

they may not even be representative of spot market prices as a whole. We attempted to 

mitigate these potential issues by relying, wherever possible, upon PUC-published average 

REC prices and available long-term contract data. However, for some states and years, spot 

market index prices were the only available data source and were therefore used in isolation 

(specifically, for DC in 2012, New Jersey in 2012, Ohio in 2010, Pennsylvania in 2012, and 

Texas in 2010-2012).

• REC price volatility. Although not a limitation of the methodology, per se, REC prices–and 

hence RPS compliance costs–can be quite volatile, with large swings from year-to-year 

depending on whether the state is under- or over-supplied. This fundamental feature of many 

RPS markets tends to complicate and obscure cross-state comparisons and long-term 

temporal trends of RPS compliance costs. This volatility also underscores the importance of 

recognizing that REC prices in any particular year do not necessarily reflect the underlying 

incremental levelized cost of renewable generation.
25 

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

Table 4. Data Sources Used to Calculate RPS Compliance Costs for Restructured States

State REC prices* REC and ACP volumes**

CT Spot market data, SEA long-term contract 

data

Decisions issued by the Connecticut 

Department of Public Utilities Authority 

in annual RPS compliance dockets (CT 

PURA, 2013)

DC

DC PSC annual reports for 2010 and 2011 

(DC PSC, 2012b and 2013), spot market 

data for 2012

Personal communication with DC PSC 

staff

DE

Spot market data and Delmarva IRP (DP&L 

2012) for 2010 and 2011, RCPR rider for 

2012

Personal communication with DE PSC 

staff

IL

RPS compliance costs for the IOUs are provided directly within IPA’s Annual Report on RPS 

Costs (IPA, 2013); REC and ACP volumes for competitive suppliers are based on personal 

communication with ICC staff (Zuraski, 2014)

MA Spot market data, SEA long-term contract 

data

Annual compliance reports issued by 

the Massachusetts Department of 

Energy Resources (Massachusetts 

DOER 2012a and 2013a)

MD MD PSC staff Personal communication with MD PSC 

staff

ME

ME PUC annual reports for 2010 and 2011 

(ME PUC 2012 and 2013), spot market data 

for 2012, SEA long-term contract data

ME PUC annual reports (ME PUC 2012 

and 2013)

NH Spot market data, SEA long-term contract 

data

New Hampshire PUC annual RPS 

compliance reports (NHPUC 2011a, 

2012, 2013)

NJ NJ BPU staff for 2010 and 2011, spot market 

data for 2012

Personal communication with NJ BPU 

staff

NY

RPS compliance costs based directly on NYSERDA’s reported annual RPS expenditures 

(NYSERDA 2011, 2012, and 2013a); REC volumes estimated based on contract start dates and 

maximum deliveries

OH

Spot market data for 2010, OH PUC annual 

report for 2011 and 2012 (PUCO 2013a, 

2014)

OH PUC annual reports (PUCO 2012, 

2013a, and 2014)

PA

PA PUC annual reports for 2010 and 2011 

(PPUC 2012 and 2013), spot market data for 

2012

PA PUC annual reports (PPUC 2012 

and 2013)

RI Spot market data, SEA long-term contract 

data

RI PUC annual reports (RI PUC 2012 

and 2013)

TX Spot market data ERCOT annual reports (ERCOT 2012 

and 2013)

*Spot market data typically consist of monthly bid and offer prices and monthly closing prices for RECs of a particular 

state, resource tier, and vintage. For main tier and secondary tier REC spot market prices, we rely on data published 

by Marex Spectron. For SREC spot market prices, we average data across Spectron, SRECTrade, and Flett 

Exchange; if none of those indices are available for a particular market, we use data from PJM-GATS.

** Historical data on REC retirement and ACP volumes were not available for all years during the 2010-2012 period. 

In those instances, compliance costs were estimated by simply multiplying the applicable REC prices (spot market or 

otherwise) by the estimated RPS requirement. This approach was used for CT (2011 and 2012), DC (2011 and 

2012), DE (2012), MA (2012), ME (2012), NJ (2012), and PA (2012). Given that REC prices will approach the ACP 

during periods of shortage, this approach should produce a similar result as what would be obtained under the more 

general methodology used.
26 

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

Table 5. ACP Rates: 2010-2012 ($/MWh) 

State Main Tier Secondary Tier Solar/DG Set-aside

CT $55 $55 n/a

DC $50 $10 $500

DE $25-80 $25-80 $400-500

IL $5-14 (ComEd territory)

$4-10 (Ameren territory)

n/a Same as Main Tier

MA $60.9-$64.0 $25.00-26.28 (existing RE)

$10-10.5 (waste-energy)

$550-600

MD $40 $15 $400

ME $60.9-$64.0 n/a n/a

NH $55-60.9 (Class I RE)

$25 (Thermal)

$29.9-31.5 (Class III)

$26.5-29.9 (Class IV)

$55-160

NJ $50 $50 $658-693

OH $45-$47.6 n/a $350-400

PA $45 $45 $550.2**

RI $60.9-64 $60.9-64 n/a

TX $50 n/a n/a

* ACP rates for IL have been translated into the typical units of $/ MWh of renewable energy, for comparison to other 

states. 

** Fluctuates according to a formula as follows: 200% X (market value of SRECs + levelized value of solar rebates). 

The current value applies to 2008/2009.

3.1.2 REC Prices

REC spot market prices for the 2007-2013 period are presented in Figure 2, which differentiates 

between REC prices for the main tier, secondary tier, and solar set-aside in each state, as 

applicable.22 As shown, REC spot market prices vary considerably over time, according to shifts 

in the balance of supply and demand (sometimes induced by revisions to RPS rules and 

eligibility requirements), but do not necessarily correspond well to trends in underlying 

renewable energy technology costs. REC prices also vary considerably across states, though 

main tier REC prices tend to be clustered regionally among the ISO-NE and PJM states, where 

inter-state REC trade is most prevalent. Solar set-aside markets, in comparison, tend to be 

somewhat more balkanized, as many states effectively limit eligibility to in-state systems.

Within the narrower timeframe of our historical analysis period (2010-2012), main tier REC 

prices in northeastern states rose from roughly $15/MWh as regional REC supplies tightened and 

shortfalls emerged. As of year-end 2012, main tier RECs in all New England states other than 

Maine were trading near their respective ACP prices ($55/MWh in Connecticut and New 

Hampshire and roughly $65 in Massachusetts and Rhode Island). Ohio In-State RECs followed 

the opposite trajectory, trading at a relatively high price of roughly $30/MWh in 2010 before 

dropping steadily over the course of 2011 and bottoming out below $5/MWh throughout 2012. 

Main tier RECs in all other states have remained in a prolonged period of oversupply and have 

traded below $5/MWh more or less continuously since 2010. 

 

22 The figure also differentiates between prices for Ohio In-State and Out-of-State RECs, and between the multiple 

secondary tiers in Massachusetts and New Hampshire. For information on what kinds of resources are included in 

each state’s RPS tiers, refer to the state RPS policy summaries posted on DSIRE: http://www.dsireusa.org. 
27 

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

Secondary tier REC markets, which typically trade below main tier REC prices because of lower 

technology costs or inclusion of pre-existing resources, have also been persistently oversupplied 

in most states, with prices generally remaining below $1/MWh. Notable exceptions are 

Massachusetts and New Hampshire, where significant shortfalls have arisen and secondary tier 

REC prices have remained relatively high (at or near their respective ACP prices). Massachusetts 

has two secondary tiers: a Class II tier for existing renewables (of the same technology types as 

qualify for the main tier) and a Waste Energy tier for municipal solid waste. The Massachusetts 

Class II market has remained undersupplied, due in large part to a shortage of existing biomass 

units that meet the requisite emissions criteria (DOER 2012b). New Hampshire similarly has two 

secondary tiers: Class III for existing biomass and landfill gas and Class IV for existing small 

hydro. Although the state has sufficient in-state resources to meet the targets, both tiers have 

experienced shortfalls due to competition for those RECs with neighboring states. 

SREC prices have historically been significantly higher than main tier or secondary tier REC 

prices due to the higher underlying technology costs for solar and correspondingly higher ACPs. 

Throughout 2010, for example, SREC prices for most state markets were trading in the $200-

$350/MWh range (and above $600/MWh in New Jersey, which had a much higher solar ACP 

and higher solar targets). The lone exception is New Hampshire, where SREC prices have 

remained persistently low. This is partly due to the fact that the state allows participation by 

SRECs generated in other states, including SRECs produced in Massachusetts that are ineligible 

for that state’s solar set-aside and SRECs produced in other northeastern states without an RPS 

solar set-aside. In addition, under certain circumstances, utilities are able to claim title to SRECs 

produced by customer-sited PV systems in New Hampshire without any payment to the 

customer.

Within the past several years, however, many SREC markets have become significantly 

oversupplied as a result of steeply falling PV module prices and, to varying degrees, the 

availability of financial incentives for solar. SREC prices have correspondingly dropped, in some 

cases quite precipitously. As of year-end 2012, SRECs in Delaware, Maryland, New Hampshire, 

New Jersey, Ohio, and Pennsylvania were trading near or below $100/MWh (in some cases well 

below). SREC prices in Massachusetts also fell markedly over the course of 2012, though not as 

far as in other states, due partly to the state’s SREC clearinghouse, which serves as a partial price 

support mechanism.23 In addition, Massachusetts announced in 2013 that it would expand its 

solar set-aside targets. Only in Washington, D.C. have SREC prices followed a generally 

increasing trajectory over the period shown; the market has remained undersupplied due partly to 

its unique geographical constraints (i.e., a single urban area with limited potential for large 

projects), and also due to a tightening of the geographical eligibility rules in 2011. 

 

23 Massachusetts Department of Energy Resources (DOER) administers an annual auction, with a fixed-price of 

$300/MWh (less a $15/MWh administrative fee), in which any unsold SRECs from the previous year can be 

deposited for sale. There is no guarantee that SRECs placed into the auction will be sold, and thus the auction price 

serves only as a “soft” price floor.
28 

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

Figure 2. REC spot market prices

$0

$10

$20

$30

$40

$50

$60

$70

$80

Jan-07

Jul-07

Jan-08

Jul-08

Jan-09

Jul-09

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

CT DC DE IL MA

MD ME NH NJ OH-In

OH-Out PA RI TX

nominal $/MWh

Main Tier

$0

$5

$10

$15

$20

$25

$30

$35

$40

Jan-07

Jul-07

Jan-08

Jul-08

Jan-09

Jul-09

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

CT DC

DE MA-II

MA-WE MD

ME NH-III

NH-IV NJ

PA RI

nominal $/MWh

Secondary Tier

$0

$100

$200

$300

$400

$500

$600

$700

$800

Jan-07

Jul-07

Jan-08

Jul-08

Jan-09

Jul-09

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

DC DE

MA MD

NH NJ

OH-In OH-Out

PA

nominal $/MWh

Solar Set-Aside

Sources: Spectron, SRECTrade, Flett Exchange, PJM-GATS, and NJ Clean Energy Program. Depending on the source used, 

plotted values are either the mid-point of monthly average bid and offer prices, the average monthly closing price, or the weighted 

average price of all RECs transacted in the month, and generally refer to SREC prices for the current or nearest future compliance 

year traded in each month. In Main Tier and Solar Set-Aside graphics, "OH-In" and "OH-Out" refer to OH In-State and OH Out-ofState RECs. In the Secondary Tier graphic, MA-II and MA-WE refer to MA Class II and MA Waste Energy RECs, respectively, 

while NH-III and NH-IV refer NH Class III and Class IV RECs.
29 

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

3.1.3 Estimated incremental RPS Costs per Unit of Renewable Generation

We use the spot market REC prices reported in Figure 2, in combination with the other data 

described in Tables 4 and 5, to estimate total incremental RPS compliance costs in each state. 

The results of those calculations are presented in Figure 3 in terms of $/MWh of renewable 

energy required. In effect, these values are an estimate of the weighted average price of all RECs 

retired and ACPs made in each year, across all tiers. Note that the years shown in Figure 3 and 

all subsequent figures correspond to each state’s definition of “compliance year” (CY), which 

begins on June 1 in Delaware, Illinois, New Jersey, and Pennsylvania. 

The variation in these estimated costs–ranging from well below $10/MWh to upwards of 

$60/MWh–partly reflects differences in REC and ACP prices across states and years. For 

example, low main-tier REC prices in Maryland, Pennsylvania, and Texas, as shown previously 

in Figure 2, led to correspondingly low incremental RPS costs in those states (less than $5/MWh 

across the years shown). Conversely, relatively high and progressively increasing main tier REC 

prices among northeastern states underlie the trends in RPS incremental costs show in Figure 3. 

Of some note are Ohio and Delaware, which both experienced relatively high estimated RPS 

costs compared to contemporaneous spot market REC prices. In the case of Ohio, the 

discrepancy was most pronounced in 2011 when the state’s distribution utilities paid an average 

of $110.55/MWh for in-state non-solar RECs (PUCO 2013a) compared to spot market prices 

ranging from roughly $10-$30/MWh and ACP rates of $46/MWh. The PUC subsequently ruled 

that one of the state’s utilities, FirstEnergy, substantially overpaid for RECs, and ordered the 

utility to refund its customers $43.3 million for excess REC purchase costs over the 2009-2011 

period (PUCO 2013b). In the case of Delaware, the state’s lone distribution utility, Delmarva 

Power & Light, has met much of its compliance obligation with long-term bundled PPAs, and 

the above-market costs of those resources are greater than spot market REC prices.24 The perMWh compliance costs rose over the 2010-2012 period as an increasing share of the compliance 

obligations were met through those long-term PPAs.

Aside from differences in REC pricing, the variations in estimated incremental RPS costs shown 

in Figure 3 also reflect the differing mixes of resource tiers within each state’s RPS. In particular, 

average incremental RPS costs were generally low for states with large secondary tier targets, as 

those tiers are typically characterized by low REC prices. The most pronounced example is 

Maine, where the secondary tier for existing resources constituted roughly 85-90% of the overall 

RPS requirement each year. Conversely, states with higher solar set-aside requirements tended to 

have higher incremental RPS costs, given that SREC prices have generally been relatively high 

compared to other tiers. For example, New Jersey and Washington, D.C. both had relatively high 

solar set-aside targets over the 2010-2012 period, contributing to relatively high average 

estimated incremental costs for the RPS as a whole, at least in some years. The decline in SREC 

prices in most markets over the 2010-2012 period, however, tended to dampen the impact of 

 

24 Based on Delmarva’s 2012 IRP, above-market costs for RPS contracts in 2012 were projected to be $53/MWh for 

its three wind PPAs (in aggregate), $179/MWh for the Dover SunPark solar PPA, $241/MWh for the collection of 

PPAs with smaller solar projects, and $268/MWh for the Bloom fuel cell project (Delmarva Power & Light 2012). 

Delmarva’s RPS surcharge, which serves to recover the entirety of the above-market costs of the utility’s RPS 

resources costs in each year, equated to an average above-market cost of $55/MWh in 2012.
30 

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

solar requirements on overall RPS compliance costs, and in the case of New Jersey led to a 

marked decline in average per-MWh RPS compliance costs.

Figure 3. Estimated incremental RPS cost over time in states with restructured markets ($/MWh of 

renewable electricity)

3.1.4 Estimated incremental RPS Costs as a Percentage of Retail Rates

RPS compliance costs can alternatively be expressed as a percentage of retail electricity rates, 

which we calculate as the ratio of the dollar value of RPS compliance costs to total revenues 

from retail electricity sales in each year. Unlike the data presented in the previous section, RPS 

compliance costs measured as a percentage of retail rates are a directly tied to the size of the 

target (given that higher targets, all else being equal, correspond to higher dollar costs associated 

with REC and ACP purchases) and are, in effect, normalized to the retail cost of electricity in 

each state. To reiterate, compliance costs denoted in these terms are not necessarily equivalent to 

actual retail rate impacts (such as for states where ACP costs are not recovered from ratepayers).

As shown in Figure 4, estimated incremental RPS costs in most states constituted less than 2% of 

average retail rates over the 2010-2012 period (with an average in 2012 of 1.4%).25 Clearly 

though, some variation exists across states and years, with estimated costs ranging from below 

0.5% of retail rates in many states up to 3-4% in Delaware and Massachusetts in 2012. That 

variation reflects many of the same fundamental underlying drivers discussed above (e.g., 

differences in REC pricing and differences in the mix of resource tiers). Variation in Figure 4 

further reflects differences in the size of the RPS targets across states and over time. It is for this 

reason that, in most states, estimated costs increased over the period shown as the RPS 

percentage targets ramped up (the most notable exception being New Jersey, where the decline 

in SREC prices more than offset the impact of the increasing RPS targets). We discuss further at 

 

25 Several of the states included in Figure 4 have independently published their own estimates of RPS compliance 

costs (CEEEP and R/ECON 2011; LEI 2012; NHPUC 2011b; ME PUC 2012; ME PUC 2013; NJ BPU 2011; 

NYSERDA 2013b). Those analyses are often based on similar methods as used within the present study, and thus 

not surprisingly, the results are generally consistent. 

0

10

20

30

40

50

60

70

80

CT

DC

DE

IL

MA

MD

ME

NH

NJ

NY

OH

PA

RI

TX

2010

2011

2012

Estimated Incremental Cost of RPS*

(Average Cost of RECs+ACPs Across All Tiers)

* Incremental costs are estimated from REC and ACP prices and volumes for each compliance year, which may differ from 

calendar years. If available, REC prices are based on average prices reported by the PUC (DC, IL, MD, ME, OH, NJ, PA); they 

are otherwise based on published spot market prices, supplemented with data on long-term contract prices where available. 

Incremental costs for NY are based on NYSERDA's annual RPS expenditures and estimated REC deliveries. nominal $/MWh
31 

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

the end of this section some considerations related to how RPS costs may evolve going forward 

given continued increases in RPS targets over the next decade. 

Figure 4. Estimated incremental RPS cost over time in states with restructured markets (% of retail 

rates)

Figure 5 shows the estimated incremental cost associated with each resource tier and its relative 

contributions to total RPS costs in each state. These data are averaged over the 2010-2012 period 

in order to smooth out fluctuations associated with large swings in REC prices from year to year. 

For most states, main tier requirements represented the bulk of total RPS compliance costs, 

though a number of notable exeptions exist. In Washington, D.C. and New Jersey, which had 

both relatively high solar set-aside targets and relatively high SREC prices, solar set-aside costs 

constituted the majority of total RPS costs over 2010-2012 and were on the order of 1% of 

average retail electricity rates. New York’s DG set-aside has similarly constitituted a large 

fraction, roughly 50%, of total RPS costs. In Massachusetts and New Hampshire, where 

shortages in the secondary tiers have led to high REC prices, the costs of the secondary tier 

requirements were relatively significant and, in the case of New Hampshire, represented the bulk 

of total RPS costs.

0%

1%

2%

3%

4%

5%

CT

DC

DE

IL

MA

MD

ME

NH

NJ

NY

OH

PA

RI

TX

2010 2011 2012

Estimated Incremental Cost of RPS*

(Percent of Average Statewide Retail Electricity Rate)

* Incremental costs are estimated from REC and ACP prices and volumes for each compliance year, which may differ from 

calendar years. If available, REC prices are based on average prices reported by the PUC (DC, IL, MD, ME, OH, NJ, PA); they are 

otherwise based on published spot market prices, supplemented with data on long-term contract prices where available. 

Incremental costs for NY are based on NYSERDA's annual RPS expenditures and estimated REC deliveries. 
32 

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

Figure 5. Estimated incremental RPS cost by tier in restructured markets (% of retail rates)

RPS estimated compliance costs in most states with restructured markets consist of some 

combination of direct REC procurement and ACPs or penalties (which, in some cases, may be 

directed toward programs or funds to support renewables deployment). RPS rules in some states 

may prohibit or limit the ability of suppliers from passing through the cost of ACPs or penalties 

to ratepayers (as discussed earlier in Section 2). In most states, the majority of RPS obligations 

were met with RECs during the 2010-2012 period (or at least for those years with available 

data). As such, REC costs constituted the overwhelming bulk of total RPS costs in most states, as 

shown in Figure 6. The three primary exceptions are Massachusetts, New Hampshire, and Rhode 

Island, where significant shortages in one or more years led to a substantial quantity of ACPs. 

Figure 6. Estimated incremental RPS costs from RECs and ACPs in restructured markets (% of 

retail rates)

0%

1%

2%

3%

4%

5%

CT

DC

DE

IL

MA

MD

ME

NH

NJ

NY

OH

PA

RI

TX

Solar/DG Set-Aside

Main Tier

Secondary Tier(s)

Estimated Incremental Cost of RPS (2010-2012 Avg.)*

(Percent of Average Statewide Retail Electricity Rate)

* Incremental costs are estimated from REC and ACP prices and volumes for each compliance year, which may differ from 

calendar years. If available, REC prices are based on average prices reported by the PUC (DC, IL, MD, ME, OH, NJ, PA); they are 

otherwise based on published spot market prices, supplemented with data on long-term contract prices where available. 

Incremental costs for NY are based on NYSERDA's annual RPS expenditures and estimated REC deliveries. 

0%

1%

2%

3%

4%

5%

CT

DC

DE

IL

MA

MD

ME

NH

NJ

NY

OH

PA

RI

TX

ACPs & Penalties

RECs

Estimated Incremental Cost of RPS (2010-2012 Avg.)*

(Percent of Average Statewide Retail Electricity Rate)

* Incremental costs are estimated from REC and ACP prices and volumes, averaged over the 2010-2012 compliance years, based 

on those years for which data are available. Only 2010 data available for CT and DC. If available, REC prices are based on 

average prices reported by the PUC (DC, IL, MD, ME, OH, NJ, PA); they are otherwise based on published spot market prices, 

supplemented with data on long-term contract prices where available. For IL, ACP costs reflect the requirement that competitive 

suppliers must meet at least 50% of RPS target with ACPs. NY does not have ACPs or penalties; all costs are therefore 

associated with REC procurement and program administration.
33 

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

3.2 States with Regulated Markets

For states with traditionally regulated electricity markets, where RPS obligations are met 

principally through long-term bundled PPAs and/or utility-owned renewable generation, states 

and utilities estimate the incremental RPS costs by comparing the gross cost of RPS resources 

procured against the counterfactual cost of resources that would have been procured but for the 

RPS. As discussed in Section 2, states and utilities can, and have, employed a variety of methods 

to estimate incremental RPS compliance costs in regulated RPS states. We have not developed 

independent cost estimates, but rather, have synthesized estimates published by utilities and 

regulators in regulated RPS states, and have translated those data into a common set of metrics 

for comparison. 

In particular, we summarize incremental RPS compliance cost estimates for eleven regulated 

states where sufficient data were available. For California, two separate estimates are presented 

based on different underlying methodologies, and those results are summarized and discussed 

separately in Text Box 3. Although the focus throughout the section is on incremental costs, we 

present data on gross compliance cost estimates for two states (Kansas and Nevada) where data 

on incremental costs are unavailable (Text Box 4).

3.2.1 Methodology and Data Sources

The specific RPS cost studies synthesized for this report are listed in Table 6. For most

traditionally regulated states, the cost data are derived primarily from utility compliance reports 

where RPS compliance costs are reported ex post, in some cases for ratemaking purposes and/or 

to demonstrate compliance with any applicable cost caps. For New Mexico, the RPS cost data 

are instead based on prospective cost estimates from annual procurement plans, while data for 

California and Wisconsin are based on estimates developed or published by the state PUC. In 

general, the cost data are limited to IOUs, either because only those entities are subject to the 

RPS or because only those entities issue public compliance reports, though the data for 

Minnesota, North Carolina, Washington, and Wisconsin also include publically owned utilities 

with RPS obligations. 

Table 6 also highlights several important caveats and complexities. First, incremental cost data 

are wholly unavailable for a number of regulated RPS states (Hawaii, Iowa, Kansas, Montana, 

and Nevada; see the Appendix for discussions of available cost data for those states) or are 

available for only a subset of utilities or years. Second, although we present data on a statewide 

basis, estimated costs for individual utilities may differ from the statewide average. Where 

possible, we note within the text where variations among utilities in a given state are particularly 

significant. Third, the methods and conventions used by utilities and regulators when estimating 

incremental RPS costs vary considerably (and are often not completely transparent). The 

comparisons across states are thus necessarily imperfect, though to the extent possible, we 

discuss qualitatively how methodological differences may impact the results. Finally, there are 

often disconnects in regulated states between the timing of RPS obligations and when costs are 

incurred. For example, utilities often procure renewable resources in advance of their compliance 

obligations, and some utilities provide up-front incentives for renewable DG (in effect, providing 

an up-front payment for RECs generated over the lifetime of the systems). In general, the data 

we report represent estimated costs incurred by utilities in each year and therefore correspond to 

actual renewable energy procurement in that year. For several states, though, the data instead 
34 

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

represent the estimated incremental cost of renewable energy applied towards the requirement in 

each year (which may differ both in quantity and in the underlying resources from the renewable 

energy procured in the same year). These differences in accounting methods are noted within the 

text, where relevant.

Table 6. Data Sources Used to Calculate Estimated RPS Compliance Costs for Regulated States 

State Data Source* Coverage Methodology and Key Conventions

AZ Utility compliance 

reports IOUs (2010-2012)

Incremental costs as a percent of retail rates 

calculated from IOUs’ annual RPS expenditures, 

consisting of administrative costs, above-market costs 

for utility-scale RE, and DG incentive program costs; 

excludes committed (but not yet spent) incentives

CA CPUC Section 910 

report IOUs (2011 only)

Two alternative methods used: Proxy generator 

(levelized cost of CCGT) and market prices (see Text 

Box 3)

CO Utility compliance 

reports PSCo (2010-2012) Modeling: PSCo compares system wide costs with and without post-2006 RPS resources

MI Utility compliance 

reports

Detroit Edison, 

Consumers Energy, 

Wisconsin Electric, 

Alpena (2010-2012)

Hybrid approach: avoided energy costs based on 

projected market prices (DTE) or modeling 

(Consumers); avoided capacity costs based on proxy 

generator (CT)

MN Utility rate impact 

reports

Great River, Minnesota 

Power, Minnkota, 

MMPA, Missouri River, 

SMMPA, Otter Tail 

(2010 only)

Market prices: compare PPA prices to MISO LMPs; 

significant methodological variations**

MO Utility compliance 

reports and plans IOUs (2011-2012) Costs based on only solar REC and solar rebate costs; 

no non-solar compliance costs***

NC Utility compliance 

reports Varies by year****

Hybrid approach: avoided energy costs based on 

modeling and avoided capacity costs based on proxy 

generator (CT).

NM

Utility procurement 

plans and compliance 

reports

SPS (2010-2012) PNM 

(2010 and 2012 only)

SPS: Modeling for avoided energy costs, proxy 

generator (CT) for avoided capacity costs; and REC 

prices. PNM: Modeling for avoided fuel costs; no 

avoided capacity costs included

OR Utility compliance 

reports

PGE and PacifiCorp 

(2011/2012 only) Proxy generator (levelized cost of CCGT)

WA

IOU compliance reports 

and I-937 filings with 

WA Dept. of Commerce

Statewide 

(2012 only)

Market prices: Most utilities compare RPS resource 

revenue requirements to market prices; significant 

methodological variation

WI

Wisconsin Public 

Service Commission 

RPS cost report

Statewide 

(2010 only)

Market prices: Compares levelized cost of new 

renewable generation built/procured over the 2006-

2010 period to MISO LMPs

* Data Sources: AZ (APS 2011, 2012, 2013; TEP 2011, 2012, 2013; UNS 2011, 2012, 2013), CA (CPUC 2013a), CO (PSCO 

2013a), MI (DTE 2011, 2012, 2013a; Consumers 2011, 2012, 2013a; Wisconsin Electric 2011, 2012, 2013; Alpena 2011, 2012, 

2013), MN (Great River 2011, Minnesota Power 2011, SMMPA 2011, Minnkota 2011, MMPA 2011, Missouri River Energy Services 

2011, Otter Tail 2011), MO (Ameren Missouri 2013b; KCPL 2012, 2013; KCPL GMO 2012, 2013), NC (Dominion 2012, 2013; Duke 

2012, 2013; GreenCo 2012; NCEMPA 2011, 2012, 2013; NCMPA1 2011, 2012, 2013; Progress Energy Carolinas 2011, 2012, 

2013; Halifax 2013; Town of Winterville 2013; Town of Fountain 2013), NM (SPS 2009, 2012, 2013; PNM 2009 and 2013b), OR 

(PGE 2011, 2012, 2013; Pacific Power 2011, 2012, 2013b), WA (Avista 2013; PacifiCorp 2013b; PSE 2013; WDOC 2013), WI 

(WPSC 2012) 

** For example, some utilities include capacity credits, curtailment costs, transmission costs, and/or financial transmission rights 

costs/revenues; some use hourly LMPs, while others use average peak and off-peak prices; most consider only post-2006 

renewables. 

*** For MO, compliance costs were calculated from data provided in the compliance plans and reports, rather than using the 

reported “rate impacts”, which could not be readily compared within the summary figures in this report. In performing these 

calculations, compliance costs associated with the non-solar requirements in 2011 and 2012 were assumed to be zero, as those 

obligations were met entirely with pre-existing renewables procured prior to enactment of the RPS. 

**** Depending on the year, a different set of utilities included data on incremental compliance costs within their annual filings. The 

state’s largest utility, Progress Energy, included such data in all years. The state’s other IOUs, Duke Energy and Dominion, included 

incremental cost data for 2011 and 2012, as did a number of smaller publically owned utilities. 
35 

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

3.2.2 Estimated incremental RPS Costs per Unit of Renewable Generation

Figure 7 presents estimated incremental cost data in terms of $/MWh of renewable energy 

procured, focusing on resources procured for each state’s general RPS obligations (that is, 

excluding any solar or DG set-aside).26 These data are, in effect, the average estimated abovemarket cost (i.e., implicit REC price) of the various contracts and projects procured for general 

RPS obligations in each state, based on the particular methodology used by the reporting entity. 

This information was available for only seven states, including California, which is discussed 

separately in Text Box 3. 

Among the six states in Figure 7, average estimated incremental costs were generally near or 

below roughly $20/MWh. Incremental costs in Wisconsin were somewhat higher ($44/MWh) for 

the single year available (2010). As noted in Table 6, the Wisconsin PSC estimated compliance 

costs using historical Midwest energy spot market prices as the basis for avoided costs, and those 

market prices were particularly depressed in 2010 as a result of the economic downturn (WI PSC 

2012). At the opposite end of the spectrum is Oregon, where average utility estimates of 

incremental compliance costs were actually negative for the years shown; that is, RPS resources 

were determined to cost less, on a statewide average basis, than the proxy non-renewable 

resources that would have otherwise been procured.27 In part, this reflects the integrated resource 

planning process in the state, through which the state’s two large IOUs have procured costeffective renewable resources on economic grounds, as well as opportunistic purchases of lowcost unbundled RECs.28

The variation in estimated costs observed in Figure 7 reflects a number of considerations. 

Although most of the states shown have relied primarily on wind power to meet general RPS 

obligations, wind energy costs vary across states and regions (e.g., due to differences in wind 

speeds and the vintage of wind projects installed). The cost of non-renewable power, which 

forms the basis for the avoided cost of renewable energy, also varies regionally, depending on 

the fuel mix, market structure, and other factors. 

Methodological differences also undoubtedly play some role. In particular, reliance upon 

wholesale electricity market prices as the reference point for estimating incremental RPS costs 

(i.e., the approach used in Washington and Wisconsin) may capture fewer sources of avoided 

cost than the other approaches used, thereby resulting in somewhat higher RPS compliance cost 

estimates. At a minimum, reliance upon historical wholesale market prices as the basis for 

avoided costs can yield volatile results, given potentially wide fluctuations in wholesale 

electricity market prices from year-to-year. This is illustrated by the data for Wisconsin, where 

the PSC estimated RPS compliance costs for 2008 (which is outside our period of analysis and 

thus not included in Figure 7) to be considerably lower than in 2010 ($27/MWh in 2008 vs. 

$44/MWh in 2010), as a result of higher wholesale electricity market prices in 2008. 

 

26 We focus here on general RPS obligations because of the complications associated with calculating the 

incremental cost of DG set-asides in $/MWh terms and lack of the requisite data. DG set-aside costs are, however, 

included in subsequent figures where RPS costs are presented as a percentage of average retail rates.

27 Of the two utilities with compliance obligations in 2011-2012, only PacifiCorp estimated net cost savings from its 

RPS resources, while Portland General Electric estimated a slight increase in revenue requirements.

28 The IOUs are allowed to meet up to 20% of their RPS obligation in each year with unbundled RECs.
36 

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

Figure 7. Estimated incremental RPS cost over time for general RPS obligations in regulated 

states ($/MWh of renewable electricity)

3.2.3 Estimated incremental RPS Cost as a Percentage of Retail Rate

Estimated incremental costs are presented as a percentage of average retail rates in Figure 8, 

which includes a larger set of states than in the prior figure, as a result of greater data 

availability. As explained previously, these data essentially represent the dollar value of annual 

estimated compliance costs as a percentage of total retail electricity costs. Again, comparability 

across states is somewhat limited by the differences in methods and conventions used by the 

utilities and regulators that developed these cost estimates. 

As shown on the left-hand side of Figure 8, estimated RPS costs during 2010-2012 were 

generally at or below 2% of average retail rates for many states, though these costs span a wide 

range. At the low end is Oregon, where estimated incremental RPS costs were negative, as 

discussed above. Estimated compliance costs in Missouri were also quite low, on account of the 

fact that the state’s utilities were able to meet the entirety of their non-solar obligations in 2011 

and 2012 with banked RECs from renewable resources procured prior to enactment of the RPS 

(and which thus entail no incremental compliance costs). Thus the data in Figure 8 represent 

solely the estimated cost of solar REC purchases and solar rebates issued for compliance with the 

state’s solar set-aside. Note that for both Oregon and Missouri, the data are based on the 

estimated incremental cost of resources applied towards the RPS requirement in the years shown, 

but utilities in these states procured substantially greater amounts of renewables, banking the 

excess for compliance in future years.29 

 

29 Data on the incremental cost of the renewable energy procured in each year are not available for Oregon or 

Missouri, but the available information suggests that those costs could, at least for some utilities, be less than the 

amounts shown in Figure 8, even though they would be based on a larger volume of renewable energy. In Missouri, 

for example, both KCP&L and KCP&L GMO indicated that “all non-solar renewable additions caused revenue 

requirements to decrease” (KCPL 2013; KCPL GMO 2013); including those resources in the cost calculations 

would therefore reduce the estimated rate impact.

-10

0

10

20

30

40

50

AZ

CO

MI

OR

WA

WI

2010 2011 2012

nominal $/MWh

* Incremental cost of general RPS obligations (i.e., RPS obligations excluding any set-asides) are based on utility- or PUC-reported 

estimates. Data for AZ and CO are based only on the single largest utility in each state (APS and PSCo, respectively). States 

omitted if data on the incremental costs of general RPS obligations are unavailable (HI, IA, KS, MT, NV) or if available data cannot 

be translated into the requisite form for this figure (MN, NC, NM, MO). See Text Box 3 for data on CA. 

Estimated Incremental Cost of General RPS Obligations*

(Average Above-Market Cost of Utility RPS Procurement)
37 

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

At the opposite end are Arizona, Colorado, and New Mexico, where statewide average estimated

incremental costs ranged from 3-4% of average retail rates in most years. Higher estimated RPS 

costs in those states are associated with several factors. To a significant degree, they can be 

attributed to DG and/or solar set-aside requirements in those states, which, as shown on the righthand side of Figure 8, constituted the bulk of total estimated RPS compliance costs in most 

years. Important to understand, however, is that the apparently high cost of the DG set-asides is 

partially due to the fact that the costs are heavily front-loaded: rebates and performance-based 

incentives are paid upfront (or over several initial years of production) in exchange for RECs 

delivered over each DG system’s lifetime. Those costs have declined somewhat over time, 

though, as utilities in these states have reduced incentive levels and moved away from upfront 

rebates. In addition to the impact of the DG set-aside, RPS costs in Colorado are also relatively 

high, owing to the fact that Colorado’s RPS procurement levels were substantially higher than 

other states shown in Figure 8. In particular, the state’s largest utility, Xcel Energy, attained 

renewable procurement levels equal to 15% to 22% of retail sales over the 2010-2012 period, 

compared to renewables procurement levels of 5-10% in most of the other states in Figure 8.30

For Arizona, an additional factor contributing to the relatively high estimated incremental RPS 

costs in Figure 8 is that those data include administrative expenses (unlike in most other states), 

which add roughly 10% to total RPS costs for the years shown. 

Importantly, the statewide averages presented in Figure 8 may mask variability in RPS costs 

among utilities within some states. In Washington, for example, all three IOUs as well as the 

state’s largest municipal utility reported costs for 2012 on the order of 0.5-1.4% of retail rates, 

but many of the smaller publically owned utilities reported higher costs (in several cases as high 

as 8-9%). Substantial variability was also evident among Minnesota utilities, which reported RPS 

costs in 2010 ranging from 0.1%-8.6% of average retail rates (though most were within the range 

of 1-3%). For New Mexico, the statewide averages are based on only two utilities (PNM and 

SPS), but those utilities reported divergent costs for 2012: 1.9% for PNM vs. 4.4% for SPS. In 

general, this intra-state variability is rooted in many of the same factors that drive differences in 

RPS costs across states – e.g., differences in procurement levels, resource costs, and cost 

calculation methodologies – though teasing out the relative significance of these underlying 

drivers is typically not feasible.

Unlike restructured markets, where compliance is often enforced through ACP mechanisms, RPS 

targets in regulated states are generally enforced through the potential for the PUC to assess 

penalties. Although utilities in regulated states have occasionally been subject to administrative 

penalties for RPS non-compliance, no significant penalties were levied over the 2010-2012 

period in any of the states listed in Figure 8. Thus, the entirety of the costs shown consists of 

costs associated with renewable electricity purchases.

 

30 Incidentally, Xcel’s renewable energy procurement well-exceeded its RPS targets over the 2010-2012, which 

ranged from 5-12% of retail sales. Thus, the company’s RPS costs for those years includes costs associated with 

renewable energy credits that were banked for use in subsequent CYs, thus potentially reducing RPS procurement 

costs in those future years. 
38 

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

Figure 8. Estimated incremental RPS cost over time in regulated states (% of retail rates)

-1%

0%

1%

2%

3%

4%

5%

6%

AZ

CO

MI

MN

MO

NC

NM

OR

WA

WI

2010 2011 2012

* Incremental costs are based on utility- or PUC-reported estimates and are based on either RPS resources procured or RPS 

resources applied to the target in each year. Data for AZ include administrative costs, which are grouped in "General RPS 

Obligations" in the right-hand figure. Data for CO are for Xcel only. Data for NM in the left-hand figure include SPS (2010-2012) 

and PNM (2010 and 2012), but include only SPS in the right-hand figure. States omitted if data on RPS incremental costs are 

unavailable (HI, IA, KS, MT, NV). 

Estimated Incremental Cost of RPS* 

(Percent of Average Statewide Retail Electricity Rate)

0%

1%

2%

3%

4%

5%

6%

2010 2011 2012 2010 2011 2012 2011 2012

AZ CO NM

DG and/or Solar Set-Aside

General RPS Obligations
39 

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

Text Box 3. Estimated incremental RPS Costs in California

The California PUC has issued several reports related to the cost of the state’s RPS. The 

March 2013 report, entitled Report to the Legislature in Compliance with Public Utilities 

Code Section 910, provided data on gross RPS expenditures for each of the state’s three 

IOUs, along with two sets of avoided cost estimates that can be used to compute incremental 

costs (i.e., gross costs minus avoided costs). One set of avoided cost estimates are based on 

the state’s MPR, which is intended to estimate the all-in cost of a CCGT and is used by the 

CPUC as a proxy for long-term electricity market prices when calculating the above-market 

costs of individual RPS contracts. The other set of avoided cost estimates, which were 

provided by the utilities, are based on day-ahead CAISO energy market prices and the cost of 

capacity in the CAISO market.

As shown below, these alternate avoided cost estimates yield dramatically different results 

when used to calculate incremental RPS costs. Relative to the MPR, the estimated 

incremental cost of the RPS in 2011 was negative (i.e., the RPS yielded net cost savings), 

equal to -$24/MWh of renewable energy procured or -3.6% of average retail rates. In contrast, 

relative to short-term market prices, estimated incremental RPS costs in 2011 were equivalent 

to $43/MWh or 6.5% of average retail rates. At a minimum, these results clearly demonstrate 

the importance of assumptions about the costs avoided through increasing the use of 

renewable energy.

Table 7. Alternate RPS Incremental Cost Estimates for California (2011)

 

RPS 

Procurement 

(% of Retail 

Sales)

Estimated Incremental Costs 

Calculated using MPR as 

Avoided Cost

Estimated Incremental Costs 

Calculated using Spot Market 

Prices as Avoided Cost

$/MWh % of Retail 

Rates $/MWh % of Retail 

Rates

PG&E 20% -28 -4.0% 36 5.2%

SCE 21% -14 -2.3% 53 8.6%

SDG&E 21% -49 -7.6% 22 3.4%

Average 20% -24 -3.6% 43 6.5%
40 

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

3.3 RPS Surcharges

RPS costs may be recovered from ratepayers through a dedicated surcharge or tariff rider (i.e., a 

“line-item” on the customer’s bill), often adjusted periodically and subject to review and 

approval by the PUC. In contrast to the preceding RPS compliance cost data, which represent the 

incremental costs borne by utilities or LSEs, surcharges represent the incremental costs borne 

directly by customers. As demonstrated and discussed below, the costs passed through to 

customers via RPS surcharges may differ from the compliance costs borne by the utility. This 

can occur for any number of reasons, including, for example, discrepancies between estimated 

and actual costs, limitations on the recovery of ACP costs, and statutory caps on the surcharge. 

Line-item surcharges on customer bills are currently used to recover RPS compliance costs in 

eight states (Arizona31, Colorado, Delaware, Michigan, North Carolina, New York, Ohio, and 

Rhode Island), though in some cases only by a subset of utilities or LSEs.32 These surcharges are 

denominated in various ways: as volumetric $/kWh charges in Arizona, Delaware, Ohio, New 

York, and Rhode Island; as a percentage of the total bill in Colorado, and as fixed monthly 

 

31 Arizona Public Service is in the process of transitioning the cost of utility-owned renewable resources developed 

through the AZ Sun Program into its rate base. Thus, going forward, the RPS surcharge will no longer represent the 

totality of RPS-related costs borne by ratepayers, as some of those costs will be embedded in base rates.

32 A number of other states, including New Mexico, use surcharges to recover only a subset of RPS compliance 

costs, while other costs are recovered through base rates or through broader fuel adjustment surcharges that include 

non-renewable resource costs. Within this section, however, we focus only on states where RPS-specific surcharges 

are used to recover the entirety of RPS compliance costs.

Text Box 4. Gross RPS Compliance Costs in Kansas and Nevada

Only gross RPS compliance costs have been reported for Kansas and Nevada. In Kansas, the 

utilities submit annual filings to the KCC, reporting the gross revenue requirements of their 

renewable energy procurement. Those cost data are confidential, but the KCC issues a public 

summary report that aggregates the data across utilities, and reports gross revenue requirements 

of renewable purchases per kWh of retail sales. In its report for the 2012 compliance year, the 

KCC found that the gross statewide costs of all renewable purchases constituted an average of 

0.16 cents/kWh of retail sales, which equates to 1.7% of statewide average retail rates in that 

year (KCC 2013). 

In Nevada, the state’s two IOUs include estimates in their annual RPS compliance reports for 

gross RPS expenditures, consisting of the cost of purchased power, RECs, incentives and rebate 

programs. For 2013, these costs were estimated at $273 million and $139 million, for Nevada 

Power and Sierra Pacific, respectively, which equates to an average gross cost per unit of 

renewable energy of approximately $64/MWh across the two utilities (NV Energy 2013). For 

reference, we estimate incremental RPS costs using the utilities’ published long-term avoided 

cost rate, which in their 2012 integrated resource plan was equal to $30/MWh (NV Energy 

2012). Using that value, we estimate average incremental RPS cost to be equal to roughly 

$34/MWh of renewable energy procured, or 8% of average retail rates. 
41 

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

customer charges in Michigan and North Carolina. For ease of comparison, Table 8 compares 

utility-specific surcharges in 2012, for residential customers specifically, translated into units of 

dollars-per-customer-per-month ($/customer-month).33 As shown, residential surcharges ranged 

from roughly $0.50/month or less for some utilities to $3-4/month for many others. 

Table 8. Average RPS Surcharges for Residential Customers in 2012

State Utility 2012 Surcharge

($/customer-mo.)*

AZ Arizona Public Service** $3.84

Tucson Electric Power $3.15

UNSE/Citizens $4.50

CO Public Service Colorado (Xcel) $1.44

Black Hills Energy $2.04

DE Delmarva Power & Light $4.29

MI Detroit Edison Co. $3.00

Consumers Energy Inc. $0.52

Indiana Michigan $0.07

Wisconsin Electric Co. $3.00

Alpena Power $0.24

NC Progress $0.56

Duke $0.49

NY Central Hudson $2.02 

Consolidated Edison $1.07 

Orange and Rockland $1.86 

New York State Electric & Gas $1.64 

Niagara Mohawk $1.92 

Rochester Gas & Electric $1.85 

OH Cleveland Electric Illuminating (FirstEnergy) $3.25

Dayton Power & Light $0.59

Ohio Edison (FirstEnergy) $2.49

Toledo Edison (FirstEnergy) $3.02

RI Narragansett Electric** $1.08

* Data Sources: AZ (ACC 2012a; ACC 2012b; ACC 2012c), CO (PSCO 2013a; Black Hills 2013), DE (DPL 2012a), 

MI (MPSC 2013), NC (NC PUC 2012), NY (NY PSC 2014), OH (DP&L 2011; Ohio Edison 2011; Cleveland Electric 

Illuminating Co. 2011; Toledo Edison Company 2011), RI (RI PUC 2013). 

** For Arizona Public Service, we show the surcharge level in effect during the first six months of the year; the 

surcharge was subsequently lowered when a portion of the costs of utility-owned renewables were moved into the 

rate base. Narragansett Electric also revised its surcharges mid-year; we show the weighted average surcharge for 

the calendar year. 

 

Statewide average RPS surcharges across all customer classes over the 2010-2012 period are 

summarized in Figure 9 and expressed as a percentage of average statewide retail electricity 

rates. As shown, surcharges ranged from less than 1% of average retail rates in a number of 

states (North Carolina, Ohio, and Rhode Island) to roughly 4% in Delaware, reflecting many of 

 

33 For those states where some translation to these units was performed, we did so using EIA data for residential 

customer count, revenues, and sales by utility (EIA 2013). 
42 

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

the same drivers discussed previously–e.g., differences in the size of the targets, cost of resources 

procured, and reliance upon front-loaded incentives for solar or DG rebates. 

Importantly, RPS surcharge costs borne by customers may, and often do, differ from the 

estimated incremental RPS costs borne by utilities or other LSEs. This can be seen in Figure 9 by 

comparing the average surcharges to the estimated incremental RPS costs for the corresponding 

years (which correspond in most cases to the data presented earlier in Figure 3 for restructured 

markets and in Figure 8 for regulated states).34 In Colorado–where, not incidentally, the state’s 

largest utility has well-surpassed its RPS targets–estimated utility compliance costs exceeded 

average surcharge collections in each year of the period shown. The RPS surcharge in Colorado 

is capped at 2%, and utilities may carry forward any deficit to be collected in future years. 

Similarly, in Rhode Island, the average customer surcharge in 2011 represented just 0.05% of 

retail rates, compared to estimated utility costs of roughly 1% of retail rates; this mismatch was 

the result of a true-up associated with over-charges in the previous year. 

In other states, the converse has occurred, where surcharge collections have exceeded utility 

compliance costs. This was the case in Michigan over the entirety of the 2010-2012 period, 

where utility compliance costs ranged from 0.2% to 1.2% of retail rates, but surcharges averaged 

roughly 2% of retail rates in each year. The surcharges levied by the state’s two large IOUs are 

based on projected long-term annual average RPS compliance costs; in effect, the utilities plan to 

over-collect in early years and under-collect in later years, in order to smooth out the rate 

impacts of RPS compliance over time. Notably, however, both utilities requested significant 

reductions for their surcharges for 2013, with Detroit Edison proposing a reduction in its 

residential surcharge from $3.00 to $0.43 per month, and Consumers Energy proposed to 

eliminate its residential surcharge.

Figure 9. RPS surcharges over time (% of retail rates)

 

34 Incremental RPS cost data for Ohio are omitted from Figure 9 as the surcharges apply only to a subset of utilities 

(First Energy and Dayton Power & Light) and comparable cost data are not available for those particular utilities. 

0%

1%

2%

3%

4%

5%

6%

AZ

CO

DE

MI

NC

NY

OH

RI

2010 Surcharge

2011 Surcharge

2012 Surcharge

Est. Incremental RPS Costs

* Surcharge data represent statewide averages for investor-owned utilities (AZ, CO, DE, MI, NC, NY) or default service providers 

(OH, RI). The DE surcharge commenced in 2012. Incremental RPS Costs represent compliance costs and generally correspond to 

the values presented previously in Figure 3 and Figure 8 . Incremental RPS cost data for OH are omitted from this figure, as the 

surcharges apply only to First Energy and Dayton Power & Light, and comparable cost data are not available.

Average RPS Surcharges*

(Percent of Average Statewide Retail Electricity Rate)
43 

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

3.4 Assessment of Future RPS Costs and Cost Containment 

Mechanisms

Estimated RPS compliance costs over our historical period of analysis are a function partly of the 

RPS targets applicable during those years. As shown in Figure 10, which summarizes estimated 

RPS compliance cost data for the most-recent historical year available for each state, the 

corresponding RPS targets or procurement levels in those years (i.e., the open circles within the 

figure) ranged from 2% to 22% of retail sales, but in most cases were within a band of 4-8% 

(excluding secondary tiers).35 

Though there is certainly some relationship between the stringency of the target or procurement 

level and the magnitude of estimated compliance costs (e.g., Colorado had relatively high RPS 

procurement levels and high costs, while Ohio had a correspondingly low RPS target and low 

costs), a variety of other conditions have also strongly impacted compliance costs. As discussed 

previously, such factors include–among other things–regional REC supply/demand balance, the 

presence of solar or DG set-asides, and the cost calculation methodology, itself. 

Figure 10. Estimated incremental RPS costs compared to recent and future RPS targets

Over the 2010-2012 period, average estimated RPS compliance costs in the United States were 

equivalent to 0.9% of retail electricity rates when calculated as a weighted-average (based on 

 

35 The open circles in Figure 10 represent somewhat different things depending on the state, and are intended to be 

consistent with the corresponding cost data. For restructured states, the open circles represent RPS targets, as the 

costs are based on the total volume of REC purchases and ACPs. For most regulated states, the cost data represent 

the cost of RPS-eligible procurement (sometimes excluding pre-existing RPS resources), and thus the open circles 

represent the corresponding quantity of RPS-eligible resources procured. For two regulated states, Oregon and 

Missouri, the cost data are instead based on only the cost of renewable energy applied towards the target, and thus 

the open circles represent the corresponding quantity of renewable energy.

-20%

-10%

0%

10%

20%

30%

40%

-4%

-2%

0%

2%

4%

6%

8%

CT

DC

DE

IL

MA

MD

ME

NH

NJ

NY

OH

PA

RI

TXAZ

CA

CO

MI

MN

MO

NC

NM

OR

WA

WI

Restructured Regulated

Estimated Incremental RPS Costs (Most-Recent Year)

RPS Target (Most-Recent Year)

RPS Target (Final Year)

Estimated RPS Cost 

(% of Average Retail Rates)

RPS Target 

(% of Retail Sales)

* For most states shown, the most-recent year RPS cost and target data are for 2012; exceptions are CA (2011), MN (2010), and 

WI (2010). MA does not have single terminal year for its RPS; the final-year target shown is based on 2020. For CA, high and low 

cost estimates are shown, reflecting the alternate methodologies employed by the CPUC and utilities. Excluded from the chart are

those states without available data on historical incremental RPS costs (KS, HI, IA, MT, NV). The values shown for RPS targets 

exclude any secondary RPS tiers (e.g., for pre-existing resources). For most regulated states, RPS targets shown for the mostrecent historical year represent actual RPS procurement percentages in those years, but for MO and OR represent REC 

retirements (for consistency with the cost data). 
44 

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

revenues from retail electricity sales in each RPS state) or 1.2% when calculated as a simple 

average, although substantial variation exists around the averages, both from year-to-year and 

across states.36 Going forward, RPS targets will rise, reaching their peak in most states within the 

2020-2025 timeframe. These final-year targets, also shown in Figure 10 (the closed circles), rise 

to anywhere from 7% to 33% of retail sales, but in most cases to at least 15%. Compared to the 

RPS targets or procurement levels for the most recent historical year, the final-year RPS targets 

constitute, on average, roughly a three-fold increase in RPS obligations. All else remaining 

constant, one would expect RPS costs, in absolute dollar terms, to rise as additional renewable 

generation is added to meet the higher final targets set by existing policies. 

Whether and the extent to which RPS compliance costs increase over time will, of course, 

depend on a great many factors. First and foremost, perhaps, is the underlying cost of renewable 

energy technologies, and whether they continue to decline as they have in recent years. Second is 

the price of natural gas, as gas-fired electricity is generally the baseline against which marketbased REC prices or the calculated above-market costs of renewables are established. Third, RPS 

costs may be significantly impacted by changes to state and federal tax incentives for 

renewables–in particular, the federal production tax credit (PTC), which (as of this writing) 

expired at the end of 2013, and the federal investment tax credit (ITC), which is scheduled to 

decline from 30% to 10% in 2017–as these tax incentives reduce the costs borne directly by 

utilities. Fourth, environmental policies related to the power sector, such as federal greenhouse 

gas regulations and air pollution regulations, could have a significant impact on RPS costs, by 

raising the cost of non-renewable resources and thereby reducing the incremental cost of 

renewables. And finally, future RPS costs could potentially be affected–in particular, 

constrained–by cost containment mechanisms built into many state RPS policies, which, if they 

became binding, would also limit achievement of the RPS targets. 

To gauge the potential trajectory of future RPS compliance costs, one can look to the various 

prospective RPS cost studies that have been conducted for individual states or utilities. An earlier 

meta-analysis by Chen et al. (2007) synthesized the results of 28 distinct state or utility-level 

RPS cost impact analyses, finding that 70% of the studies in their sample projected retail 

electricity rate increases of no greater than 1% in the year that each modeled RPS policy reaches 

its peak percentage target. Five of the studies projected net reductions in retail rates, while two 

studies projected rate impacts greater than 5%. Much has changed on the RPS landscape since 

the time of that study, however, as many states have increased their RPS targets and/or added 

set-aside provisions, and renewable energy technology costs have fallen significantly while 

natural gas prices have simultaneously declined. 

More-recent prospective RPS cost analyses have estimated rate impacts in the final target year 

equal to roughly: 10% in California (CPUC 2009), 2.2-4.8% in Connecticut (CEEEP and 

R/ECON 2011), 7.9% in Delaware (Delmarva Power & Light 2012), 1.1-2.6% in Maine (LEI 

2012), 0.3-1.7% for Northern States Power in Minnesota (Xcel Energy 2011), 2.2% for Great 

River Energy in Minnesota (Great River Energy 2011), and a 0.5% reduction in North Carolina 

 

36 California is excluded from the calculation of this average, given the lack of a single point estimate.
45 

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

(RTI International 2013).37 As with retrospective RPS cost analyses, the scope, methodology, 

and assumptions also vary widely among prospective cost studies, limiting their comparability to 

one another and to the historical cost data presented earlier. They nevertheless provide an 

illustrative range when considering how RPS costs may evolve as the targets rise. 

3.4.1 RPS Cost Containment Mechanisms

Given the inherent uncertainty in future RPS costs, and the desire among policymakers to limit 

the potential burden to ratepayers, most RPS policies include one or more cost containment 

mechanisms or “off-ramps” (see Table 9). Various approaches are used, though the most 

common are ACPs and rate impact/revenue requirement caps.

• ACPs. Typical of restructured markets, ACPs function as a backstop compliance option for 

LSEs. As such, they effectively cap REC prices and thus RPS compliance costs (though 

exceptions may exist, as discussed below). 

• Rate impact/revenue requirement caps. Many states cap RPS costs in terms of a maximum 

allowed percentage of revenue requirements, costs, or customer bills. This kind of 

mechanism is most common among regulated states, though is also employed in several 

restructured markets, in conjunction with ACPs. Caps generally apply to incremental RPS 

costs (though one state, Kansas, applies its cap to gross procurement costs), with varying 

methods used to calculate the cost of RPS resources and avoided non-renewable resources.

• Surcharge caps. Two states, Michigan and North Carolina, have statutory caps on RPS 

surcharges, denominated in terms of a maximum dollar cost per customer. In addition, 

Colorado has a statutory rate impact cap of 2%, but the PUC has, in effect, operationalized 

this as a surcharge cap, allowing the utilities to incur costs beyond the cap and defer the 

balance.

• Renewable energy contract price caps. Caps may be placed on individual RPS contract 

prices–as in Montana, where RPS contract prices are capped based on the avoided costs of an 

equivalent non-renewable resource.

 

37 For California, the estimated rate impact represents the projected increase in electricity costs to meet a 33% RPS 

in 2020 relative to a scenario in which gas-fired generation is used to meet all new resource needs. For Connecticut, 

the range in estimated rate impacts corresponds to varying REC price assumptions and represents the projected cost 

in 2020, relative to a scenario in which RPS targets are held constant at 2010 levels. For Delaware, the rate impact 

estimate is for the 2022/2023 CY rather than the final RPS target year (2025/2026). For Maine, the range in 

estimated rate impacts corresponds to varying REC price assumptions. For Xcel, the rate impact estimates represent 

the incremental cost of the company’s RES compliance plan in 2020, relative to an otherwise least-cost plan, across 

several scenarios. For Great River Energy, the rate impact estimate represents the net present value of the increase in 

revenue requirements over the 2013-2027 period, rather than the impact in the final target year, and furthermore 

represent the percentage increase in wholesale prices to the company’s distribution utility customers. For North 

Carolina, the rate impact estimate represents the projected incremental costs in 2021 of the state’s RPS and other 

“clean energy policies”; the net cost savings are largely attributable to energy efficiency savings used to meet a 

portion of the RPS requirements. In addition to the set of studies listed above, NYSERDA conducted a recent RPS 

evaluation, estimating that, for the 2002-2037 period, the state’s current RPS portfolio would yield a slight reduction 

in average retail rates, with wholesale market price reduction benefits more than offsetting REC purchase costs 

(NYSERDA 2013b). 
46 

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

• Renewable energy funding caps. Where specific programs are established for the purpose of 

RPS procurement (e.g., New York), cost containment may occur through statutory or 

regulatory limits on program budgets.

• Financial penalties. Texas has a pre-specified penalty that can function largely like an ACP 

in terms of its containment of REC prices and incremental RPS costs. Other states may also 

levy financial penalties for non-compliance, but often either those penalties cannot be passed 

through to ratepayers and/or the penalty rate is not pre-specified, and thus they do not 

function as a cost containment mechanism, per se. 

Aside from cost containment mechanisms with some prescribed numerical limit, such as those 

listed above, regulators in many states often have some level of discretionary power to control 

RPS costs. Some RPS laws grant the PUC the authority to delay or freeze RPS requirements, or 

grant waivers to individual utilities, if costs would be deemed excessive (e.g., under a force 

majeure clause). Regulators also often have the ability to review and approve PPAs and/or cost 

recovery for RPS resources, and thereby limit the costs incurred.

Importantly, cost containment mechanisms may sometimes serve as only a “soft” cap, depending 

upon the specifics of their design. In states with ACPs, for example, utilities might conceivably 

pay a higher price for RECs than the ACP level if ACPs are not recoverable or when RECs are 

purchased through long-term bundled PPAs. Similarly, rate impact or revenue requirement caps 

may be voluntary; in Washington, for example, a utility may opt to abide by the cap but is not 

obliged to do so. More generally, cost containment under many of the above mechanisms may be 

imperfect to the extent that certain costs or benefits are not fully counted. For a broader 

discussion of the design and limitation of RPS cost containment mechanisms, see Stockmayer et 

al. (2012). 
47 

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Table 9. Cost Containment Mechanisms

State Cost Containment Mechanism(s) Details of Cost Containment Mechanism(s) Applicable to Final Target Year

AZ No specific cap

CA No specific cap (under development)

CO Rate impact/revenue requirement cap 2% (IOUs and coops) or 1% (municipal utilities) of each customer’s annual electricity bill

CT ACP $55 (Class I and Class II)

DC ACP $50 (Tier I and Solar), $10 (Tier II)

DE Rate impact/revenue requirement cap For IOUs, 3% (total RPS) and 1% (Solar) of total retail electricity costs; for municipal utilities, 4% (total RPS); rulemaking currently underway

ACP $80 (Non-Solar), $500 (Solar)

HI No specific cap

IA No specific cap

IL Rate impact/revenue requirement cap 2.015% of average 2007 retail rates

ACP Applicable only to alternative retail electricity suppliers, which are required to meet at least 50% of RPS obligation with ACPs; equal to average REC 

price paid by IPA

KS Rate impact/revenue requirement cap 1% of retail revenue requirement (gross RPS costs)

MA ACP $73.7 (Class I Non-Solar), $30.3 (Class II-Existing RE), $12.1 (Class II-Waste Energy), $384, (Class I Solar-SREC I program), $316 (Class I SolarSREC II program)

MD ACP $40 (Tier I Non-Solar), $15 (Tier II), $50 (Tier I Solar)

Rate impact/revenue requirement cap 10% (Tier I Non-Solar), 1% (Tier I Solar) of retail sales revenue

ME ACP $70.9 (New renewables tier)

MI Surcharge cap $3.00/month (residential), $16.58/month (small commercial), $187.50/month (large commercial and industrial)

MN No specific cap

MO Rate impact/revenue requirement cap 1% of retail revenue requirements*

MT Renewable energy contract price cap Capped at avoided costs for most utilities

NC Surcharge cap $34/year (residential), $150/year (commercial), $1,000/year (industrial)

NH ACP $62.1 (Class I-New RE), $28.2 (Class I-Thermal), $62.1 (Class II-Solar), $40.1 (Class III-Existing Biomass), $33.8 (Class IV-Existing Small Hydro)

NJ ACP $50 (Tier I and Tier II), $239 (Solar)

NM Rate impact/revenue requirement cap 3% of total revenue

Per-customer cost cap For customers using >10 million kWh/year, $99,000/year (2012 dollars) or 2% of their bills, whichever is less

NV No specific cap

NY Renewable energy fund cap PSC Order establishing program budget through final target year

OH Rate impact/revenue requirement cap 3% of generation costs

ACP $61.0 (Non-Solar), $50 (Solar)

OR Rate impact/revenue requirement cap 4% of annual retail revenue requirements

ACP Established bi-annually by Oregon PUC ($110 for 2014 and 2015)

PA ACP $45 (Tier I Non-Solar and Tier II), 2x market value of RECs (Tier I Solar)

RI ACP $73.9

TX Financial penalty $50/MWh, could be passed through by competitive suppliers

WA Rate impact/revenue requirement cap 4% of annual retail revenue requirements

WI No specific cap

Note: All ACP rates identified are in units of $/MWh and represent the scheduled ACP rate for the final RPS target year. Several states (MA, ME, NH, OH, RI) 

adjust ACP rates for some or all tiers annually based on inflation; in these cases, we estimate the ACP rates for the final RPS target year using the CPI projection 

from the EIA Annual Energy Outlook 2014 Early Release. For MA, where the Class I-New RE tier has no final target year, we estimate the non-solar ACPs for 

2020, and show the scheduled solar ACP rates for that year as well. 

Note: In states without specific caps, cost containment may still occur through regulatory oversight (e.g., authority of the PUC to delay or freeze RPS requirements 

if costs are deemed burdensome, review and approval of contracts and cost recovery, etc.).

*Interpretation and implementation of the MO cost cap is currently subject to substantial debate.
48 

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

In Figure 11, we have translated, where possible, the cost containment mechanisms outlined in 

Table 9 into the equivalent maximum percentage increase in average retail rates, for the year in 

which each state’s RPS target reaches its peak.38 In effect, these values represent the maximum 

potential annual RPS cost, subject to the various caveats discussed above, for the single year in 

which each state reaches its final target. For comparison, Figure 11 also presents estimated

statewide-average RPS costs for the most recent historical year available (i.e., the same data 

presented in Figure 10). Excluded from Figure 11 are those states currently without any 

mechanism to cap total incremental RPS costs, though some of those states may have other kinds 

of mechanisms or regulatory processes to limit RPS costs. 

States relying upon ACPs as their primary cost containment mechanism are grouped on the lefthand side of the figure. Among those states, RPS costs are generally capped at the equivalent of

6-9% of average retail rates.39 The effective caps are somewhat higher in Massachusetts (16%) 

and New Jersey (13%) due to relatively high solar set-aside targets and/or ACP levels.40 As 

shown, estimated recent RPS compliance costs in this set of states are generally well below the 

corresponding caps. To a significant extent, this is simply because current RPS targets are well 

below the final-year targets, and cost caps are arithmetically related to the final-year targets. 

Rising RPS targets will put upward pressure on REC prices, which in many of the Northeastern 

states are already near their respective ACPs. At the same time, ACP rates will generally remain 

fixed (in either real or nominal terms) or, in the case of many states’ solar ACPs, will decline 

over time. Of particular note, solar ACPs in Washington D.C., Maryland, and Ohio are scheduled 

to decline to $50/MWh, from current levels of $350-500/MWh. This combination of possible 

upward pressure on REC prices and fixed or declining ACPs could constrain achievement of 

RPS targets and push total compliance costs towards the maximum levels shown in Figure 11. 

That outcome is not foregone of course, if continued reductions in renewable energy costs and/or 

increases in wholesale power prices restrain growth in REC prices.

States with some form of cost containment other than, or more binding than, an ACP are grouped 

on the right-hand side of Figure 11. In general, cost caps among these states are relatively 

restrictive, typically ranging from the equivalent of 1-4% of average retail rates. Not 

surprisingly, cost caps have already become binding in several of these states. In particular, 

utilities in New Mexico have, on a number of occasions, requested and been granted reductions 

in their RPS obligations in order to remain within the overall rate impact cap (termed the 

“Reasonable Cost Threshold”) and/or to remain within the per-customer cost cap for large 

customers. Also, utilities in Missouri (not included in Figure 11) have sought waivers from solar 

rebate requirements included in the RPS law, in order to remain within the state’s cost cap. 

 

38 Figure 11 excludes three states–Pennsylvania, Kansas, and Missouri–with numeric cost caps that cannot be 

expressed on a sufficiently comparable basis to the other states. Pennsylvania is excluded, because the ACP rate for 

its solar set-aside is not pre-defined. Kansas’s cost cap applies to gross costs, rather than incremental costs. 

Missouri’s cost cap is currently subject to substantial debate, and a binding ruling on its interpretation has not yet 

been issued. 39 Although not included in the figure, Pennsylvania’s main tier and secondary tier ACPs equate to effective cost cap 

of 7.4% of average retail rates for the final target year. In comparison, RPS costs for the most recent historical year 

(2012) equated to 0.2% of retail rates.

40 Massachusetts’s RPS does not have a single terminal year. For the purpose of constructing Figure 11, the cost cap 

was calculated based on RPS targets in 2020. This is the year when the state’s cost cap reaches a local maximum, 

declining in the years immediately following as the solar ACP rates decline and the SREC-I program expires.
49 

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

Several other states appear to have surpassed their caps, but for various reasons those caps have 

not yet been binding. In Colorado, Xcel Energy has a 2% cap on its RPS surcharge. The utility–

which, not incidentally, has far-surpassed its RPS procurement targets–has been allowed to incur 

costs in excess of the surcharge amount and defer the balance forward for collection from 

ratepayers in later years (Stockmayer et al. 2012). In Delaware, Delmarva Power & Light’s RPS 

procurement costs for 2012 appear to have exceeded the 3% cost cap; however, the 

administrative rules for implementation of the cap are still under development (as of this 

writing), and it is therefore not yet practically enforceable. Finally, Kansas had statewide average 

renewable energy costs in 2012 equivalent to 1.7% of average retail rates, which is greater than 

the 1% rate impact cap for the RPS (KCC 2013). However, the 2012 costs are based on all 

renewables procured by the state’s utilities, beyond just those resources attributed to the RPS 

(Solorio 2014). 

Other states are approaching or could begin to approach their respective caps. For example, 

Illinois, North Carolina and Ohio all have relatively low cost caps (1-2% of average retail sales) 

and targets that rise considerably over the coming decade. In Oregon as well, cost caps may 

become an issue for some utilities, even though historical compliance costs have been quite low. 

Portland General Electric, in particular, has forecasted sizeable increases in its RPS rate impacts 

over the next five years that reach or exceed the 4% rate cap under a number of scenarios. New 

York is also likely to hit its cap, though this is by design, as the cap is based on a schedule of 

revenue collections adopted by the PSC and deemed necessary for achievement of the target. In 

Montana, the cost cap effectively prohibits any net cost from RPS resources. Thus far, the cap 

has not been binding–no doubt the result of the high quality wind resource sites in the state–but 

the sheer restrictiveness of the cap suggests that it could at some point become limiting.

Of the states on the right-hand side of Figure 11, Texas and Michigan are both seemingly at low 

risk of reaching their cost caps, even though the caps are on par with other states within the 

group. In the case of Texas, scheduled increases in the RPS target are relatively small, and 

installed renewable capacity in the state already well-exceeds the final-year (2015) target. Given 

the low REC prices that have prevailed to-date, RPS compliance costs in Texas would thus seem 

unlikely to approach the state’s cost cap. In Michigan, the cost cap is specified in terms of a 

maximum customer surcharge, and the state’s two large IOUs reduced their surcharges 

substantially in 2014. In their latest RPS procurement plans, both utilities project attainment of 

their RPS targets going forward, without any significant increase in surcharges (DTE 2013b; 

Consumers 2013b). 
50 

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

Figure 11. RPS cost caps compared to estimated recent historical costs

0%

5%

10%

15%

20%

CT

DC

MA

MD

ME

NH

NJ

RI

CO

DE

IL

MI

MT

NM

NC

NY

OHOR

TX

WA

Cost Containment Based on ACP Other Cost Containment Mechanisms

Historical Compliance Cost Estimate (Most-Recent Year)

Effective Cost Cap (Max Retail Rate Increase)

* For states with multiple cost containment mechanisms, the cap shown here is based on the most-binding mechanism. MA does not 

have a single terminal year for its RPS; the calculated cost cap shown is based on RPS targets and ACP rates for 2020. "Other cost 

containment mechanisms" include: rate impact/revenue requirement caps (DE, KS, IL, NM, OH, OR, WA), surcharge caps (CO, MI, 

NC), renewable energy contract price cap (MT), renewable energy fund cap (NY), and financial penalty (TX). Excluded from the chart 

are those states currently without any mechanism to cap total incremental RPS costs (AZ, CA, IA, HI, KS, MN, MO, NV, PA, WI),

though some of those states may have other kinds of mechanisms or regulatory processes to limit RPS costs.

RPS Cost Containment Mechansims*

(Equivalent Maximum Percentage Increase in Average Retail Rates)
51 

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

4 Benefits of RPS

The estimated RPS incremental costs reported earlier are net costs that account for a narrow set 

of benefits–namely the benefits that accrue to the utility, in the form of reduced costs for 

conventional generation. However, policymakers often consider RPS costs within the broader 

context of the possible benefits of those policies to society at large. Potential societal benefits of 

RPS policies include air emissions reductions, health benefits, fuel diversity, electricity price 

stability, energy security, and economic development (EPA 2011; Cory and Swezey 2007). 

Often RPS legislation includes language indicating that the policy is designed to achieve 

particular goals, such as these. 

This section summarizes RPS benefits estimates, based on published studies for individual states, 

and discusses key methodological considerations. As such, the estimated benefits itemized in this 

document do not result from the application of a standardized approach or the use of a consistent 

set of underlying assumptions. Because the reported values may differ from those derived 

through a more consistent analytical treatment, we do not provide an aggregate national estimate 

of RPS benefits, nor do we attempt to quantify net RPS benefits at national or state levels. 

Benefits estimates, for example, of the social value of carbon emissions reduction and the human 

health impacts of reduced air emissions, are based on a variety of methodologies and 

assumptions. In comparison to the summary of estimated RPS costs, the summary of RPS 

benefits is more limited, as relatively few states have undertaken detailed benefits estimates. 

Further, for those states that have estimated RPS benefits, most assess only a limited number of 

impact types; as a consequence, some types of benefits are not reflected in this report. 

Estimating the broader impacts of RPS policies (and other types of policies in general) 41 can be 

challenging. The level of rigor in assessment can vary substantially and a variety of methods can 

be employed (Leon 2012), depending on available resources to conduct modeling or detailed 

assessments. When preparing RPS evaluations, many states have qualitatively discussed benefits 

while a smaller number have attempted to develop quantitative estimates. 

Comparison of estimated costs to benefits is also challenging, even when they are reported in the 

same study, given that some incremental cost calculations may already take into account certain 

benefits, analysis time periods may differ, benefits assessments may address only particular types 

of benefits, and other factors. In addition, certain benefits (e.g., avoided emissions) may accrue 

for the lifetime of the renewable plant, while costs are incurred over a shorter period. One study 

conducted by NYSERDA does offer a direct comparison of RPS benefits and costs finding that 

the New York RPS yielded a net present value benefit of $1.6 to $3.5 billion, with the range 

depending primarily on assumptions of the value of CO2 savings (NYSERDA 2013b).

Massachusetts also compared estimated compliance costs to the benefits, primarily price 

suppression effects, showing 2012 costs of $111 million compared to benefits of $328 million in 

the same year (EOHED and EOEEA 2011). Most other states for which we have identified 

benefits estimates did not conduct direct comparisons. 

 

41 In this analysis, we focus on the impacts of RPS policies in particular, but do not examine the impacts of other 

renewable energy policies. While RPS policies can have positive impacts, there are other types of policies that could 

have equivalent impacts, potentially at lower cost. 
52 

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

Table 10 summarizes studies identified in our literature review that quantitatively assess benefits 

of state RPS policies in current or future years. Based on our review of studies, states have most 

commonly attempted to quantitatively assess avoided emissions and human health benefits, 

economic development impacts, and wholesale electricity price reductions. The studies identified 

include those required by statute, filed as part of an IRP docket, and prepared for regulatory 

commissions, energy boards, or public benefit corporations. Most of these studies are 

prospective in nature, assessing not only the current RPS impacts, but also examining future 

impacts, in contrast to the cost estimates previously discussed that are retrospective. Results from 

third-party studies referenced in the aforementioned documents are also included here. While we 

attempted to conduct a thorough literature review, we have likely omitted some analyses. 

However, this review provides an indication of the types of benefits analyses that have been 

conducted and the range of benefits found. In this analysis, we did not review the broader 

literature on renewable energy benefits in general, but are focused only on analyses conducted as 

part of state-level RPS evaluations. 

Table 10. Summary of State Studies of RPS Benefits and Benefits Assessed

State Emissions 

and Health

Economic 

Development 

Impacts

Wholesale 

Market 

Impacts

Study 

required? 

Source

CT

 As part of IRP The Brattle Group et al. 

2010

 

CEEEP and R/ECON 

2011

DE  As part of IRP DPL 2012b

IL     IPA 2013

ME     LEI 2012

MA

  

EOHED and EOEEA 

2011

MI    MPSC 2013

NY     NYSERDA 2013b; 2013c

OH   PUCO 2013a

  PUCO 2013c

OR   ODOE 2011

Note: The results found in a single report may have been classified under more than one category.

The following sections review estimated benefits and impacts of state-level RPS policies, with 

respect to 1) emissions and human health; 2) economic development; and 3) wholesale market 

price impacts. We summarize the estimated benefits and methods used in studies identified in the 

literature review, which were often prepared for state legislatures or commissions. While 

methods for developing benefits estimates differ substantially from methods used to assess 

policy costs, this information can provide context for considering the cost of RPS policies 

presented earlier. 

4.1 Emissions and Human Health

One of the most often quantified environmental benefits of renewable energy is the avoided air 

pollutant emissions and associated human health benefits. Typically, estimates of avoided 

emissions focus on carbon dioxide (CO2), sulfur oxides (SOX), and nitrogen oxides (NOX). In 

some cases, the human health benefits of these reduced emissions are estimated as well by 

applying monetary values to, for example, the reduced morbidity or mortality from air quality 
53 

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improvements. In other instances, monetary impacts are estimated based on the avoided cost of 

compliance with environmental regulations. 

There are two common approaches to estimating RPS emissions impacts. The most robust 

approach is to conduct detailed modeling of the electric system with and without the renewable 

generation to determine the mix of plants that would be operating and the overall system emissions 

in each scenario. This approach yields the most robust results because it accounts for the operation 

of the facilities at each hour of the day—renewable facilities may be displacing different types of 

conventional generators throughout the course of a day. A simplified approach is to estimate the 

marginal generating unit that would typically not be operating as a result of the renewable 

generator and apply the unit’s emission rate to the displaced generation. This approach is 

simplified and yields approximate results. Table 11 summarizes estimates of the emissions and 

associated monetary benefits from RPS policies for several states where data are available. 

Table 11. Summary of Estimates of Emissions and Human Health Benefits of State RPS 

State Estimated 

Benefit 

Benefits 

$/MWh of 

RE 

Avoided 

CO2/MWh 

Period Description Source 

CT Not 

estimated N/A 0.39-0.53 tons/MWh 2020 

Avoided CO2 emissions of 

0.39-0.53 tons/MWh of 

renewable generation 

Brattle 

Group et 

al. 2010 

OH Not 

estimated N/A N/A 2014 

CO2 emissions reduced from 

116.36 million metric tons in 

reference case to 116.16 (-

0.17%), and to 115.79 (-0.5%) 

in scenarios 

PUCO 

2013c 

ME $13 million $7/MWh 0.57 

tons/MWh Annual 

Avoided allowance costs for 

96 tons for SO2, 1,629 tons for 

NOX and 1.1 million tons for 

CO2. CO2 valued at $12/ton. 

LEI 2012 

DE 

$980 - 

$2,200 

million* 

N/A N/A 2013 – 

2022 

Human health benefits due to 

improvements in air quality 

from emission reductions in 

power generation and other 

sectors 

DPL 2012b

IL $75 million $11/MWh** 0.79 

tons/MWh** 2011 

Avoided allowance costs for 

5,481,327 tons of CO2 and 

4,765 tons of NOX. CO2

valued at $5/ton.

IPA 2013 

NY 

Not 

estimated N/A N/A 2002-2006 

4,028 tons of NOX, 8,853 tons 

of SO2, and 4.1 million tons of 

CO2

NYSERDA 

2013a 

$312 - 

$2,196 

million*** 

$3–

22/MWh 

0.05 

tons/MWh 

2002 – 

2037 

Value of avoiding 50.29 million 

tons of CO2. CO2 valued at $15 

/ton and $85/ton.** 

NYSERDA 

2013b 

$48 million $0.5/MWh N/A 2002 – 

2037 

Value of avoiding 278 pounds 

of mercury, 15,214 tons of 

NOX and 14,987 tons of SO2

NYSERDA 

2013b 

*Delaware estimates reported in $2010 dollars. 

**Estimated based on 6.9 million MWh of renewable energy needed to meet the 2011 RPS requirements (IPA 2010, 

Zuraski 2014). 

*** The estimated monetary impact is a net present value calculation reported in $2012, thus the avoided tons of CO2 

multiplied by values of $15/ton and $85/ton differs from the reported $312 - $2,196 million. 
54 

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4.1.1 Emissions Rate Approach 

In our literature review, we identified only one state—Maine—that used a simplified emission 

rate method to estimate the avoided emissions. 

Maine. Maine’s PUC (MPUC) retained London Economics International (LEI) to analyze the 

costs and benefits of RPS compliance, as required by the state legislature.42 To estimate 

emissions benefits, LEI used half of the aggregate nameplate capacity of wind generation 

projects proposed in the ISO New England interconnection queue located in Maine, or 625 MW, 

to calculate impacts (LEI 2012). LEI calculated avoided emissions by assuming that natural gasfired generation was displaced by the renewable energy generated under Maine’s RPS. Using 

U.S. EPA average emission rates for natural gas-fired generation, LEI calculated an annual 

reduction of 96 tons for SO2, 1,629 tons for NOX, and 1.1 million tons for CO2. The annual 

monetary value of avoided emissions was calculated at $13 million based on allowance prices of 

$0.80/ton for SO2 (based on the current forwards), $20/ton for NOX (based on the current 

forwards), and $12/ton for CO2 (LEI 2012). 

4.1.2 Modeling Avoided Emissions Approach 

Several states have conducted more detailed electric system modeling to understand avoided 

emissions. The following are examples of this approach. 

Connecticut. As part of their IRP for Connecticut, a private consultant and two electric 

distribution companies used the Day-Ahead Locational Market Clearing Prices Analyzer 

(DAYZER) model to simulate resource dispatch and measure economic impacts and emission 

levels for the ISO New England region. The study compared the RPS requirements as of 2010 

with lower levels of ISO-wide renewable energy deployment under five scenarios and also 

varied assumptions regarding natural gas prices, carbon prices, and load growth. Using this 

methodology, the study found avoided CO2 emissions of between 0.39 tons/MWh and 

0.53tons/MWh of renewable generation (The Brattle Group et al. 2010).

Delaware. The electric distribution company Delmarva Power and Light (DPL) used a group of 

modeling tools to calculate the expected emissions from power plants in the PJM Delmarva zone 

between 2012 and 2022 as part of its 2012 IRP for Delaware. The study assessed the impact of 

not only the RPS, but also demand side management programs, energy efficiency programs, and 

emission controls for coal plants. DPL’s results show a reduction in CO2, SO2, and NOX

emissions from power plants of approximately 30%, 66%, and 56%, respectively, from 2012 

levels, in 2022 (DPL 2012b). Human health benefits over the 2013-2022 period for Delaware 

due to the improvements in air quality, including reductions from the transportation and other 

sectors, were estimated to be between $980 million and $2.2 billion for Delaware, and between 

$13 and $29 billion for the mid-Atlantic Region. Monetized benefits of improvements in air 

quality were based on estimates of reduced health effects specifically related to ozone and 

particulate matter-related morbidity and mortality (e.g., from chronic bronchitis, emergency 

room visits for asthma). DPL estimated that the health-related costs associated with power plant 

 

42MPUC was tasked with examining direct investment, induced effects, job creation, and other benefits resulting 

from a diversified electricity generation fleet. 
55 

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emissions in Delaware during the same period ranges between $2.5 and $6.8 billion (DPL 

2012b). 

Illinois. The Illinois Power Agency (IPA), an independent agency established by the legislature 

to procure power for the state’s two largest electric utilities to comply with the RPS, prepares an 

annual report as required by statute that includes RPS compliance status and an analysis of costs 

and benefits. To assess RPS benefits, IPA hired a private consultant to model the electricity 

market. The study examines both PJM and MISO markets, both of which operate in Illinois, with 

and without renewable generation to calculate emission reductions and effects on locational 

marginal prices (LMP) for calendar year 2011 (an historical rather than prospective analysis). 

The study used the MarSi model, a software tool developed by GEMS for electricity market 

simulations. The reduction in emissions directly attributable to renewable energy generation 

amounted to 5,481,327 tons of CO2 and 4,765 tons of NOX. Using trading values for emission 

allowances of $10,000/ton of NOX and $5/ton of CO2, IPA calculated a total emission cost 

reduction of approximately $75 million due to renewable energy generation (IPA 2013). 

New York. NYSERDA has examined historical and future emissions reductions as part of its 

annual RPS performance reports and also within periodic RPS evaluations. In its 2012 historical 

performance report (covering the 2006-2012 period), NYSERDA found emissions reductions 

attributable to renewable energy generation of approximately 4,028 tons of NOX, 8,853 tons of 

SO2, and 4.1 million tons of CO2 (NYSERDA 2013a). 

In 2013, NYSERDA completed an historical and forward-looking assessment of the New York 

RPS Main Tier, as required by the Public Service Commission, focusing on compliance status, 

direct economic impacts, cost-benefits analyses, and resource availability and costs.43 The study 

estimated avoided carbon emissions and other electric system impacts using ICF International’s 

Integrated Planning Model (IPM). The study considered main tier renewable energy projects 

with signed contracts as of December 31, 2012, referred to as the Current Portfolio. The avoided 

emissions calculated for the Current Portfolio over the course of the 2002-2037 study period44

were 50.29 million tons of CO2, 278 pounds of mercury, 15,214 tons of NOX, and 14,987 tons of 

SO2 (NYSERDA 2013b). Using $15/ton and $85/ton as boundaries for the value of avoiding 

CO2 emissions, NYSERDA estimated a present value between $312 million and $2,196 million. 

For monetization of health benefits from criteria pollutants, NOX and SO2 were valued at 

$3,500/ton and $1,100/ton, respectively. A value of $194.5 million/ton was used for mercury. 

Avoided emissions of NOX, SO2, and mercury were estimated to produce $48 million in health 

benefits (NYSERDA 2013b). 

Ohio. The Public Utilities Commission of Ohio (PUCO) used PROMOD IV, a nodal electricity 

market simulation tool, to quantify changes in generator emissions that occur as a result of 

Ohio’s Alternative Energy Portfolio Standard (AEPS). The study examined two scenarios over 

calendar year 2014. The first scenario considered projects that were operational at the time of the 

study; the second considered projects that had been approved by the Ohio Power Siting Board, 

 

43 The Main Tier of NY’s RPS includes larger power generation plants in the utility side of the meter and accounts 

for approximately 92% of the total RPS requirement. 

44 This period spans over the life of the systems in the current portfolio. 
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but were not operational. The results for each of these scenarios were compared to a scenario 

where “no utility-scale renewable resources are developed within Ohio.” CO2 emissions were 

reduced relative to this no utility-scale renewable resources scenario from 116.36 million metric 

tons to 116.16 for the first scenario, a change of -0.17% in, and to 115.79 million metric tons, in 

the second scenario, a change of -0.5% (PUCO 2013c). 

Overall, estimates of air quality benefits range from on the order of tens to hundreds of million 

dollars annually or about $4-$22/MWh of renewable generation, with some studies presenting a 

wide range of estimates depending on assumptions. Often, the value of CO2 emissions benefits 

(Table 11) drives the estimates, because of the magnitude of those reductions, compared to 

reductions of other air pollutants. In order to calculate the estimated monetary impact of avoided 

CO2 emissions, the tons of avoided CO2 emissions can be multiplied by the value of the CO2. 

Thus, assumptions regarding the value of CO2 influence results considerably. An interagency 

assessment of the social cost of carbon found a range from $11 to $89/metric ton of CO2 for the 

year 2010 (in $2007 dollars) depending on the discount rate used (Interagency Working Group 

on Social Cost of Carbon 2013). The NYSERDA study used a similar range ($15/ton and 

$85/ton) for valuing avoided CO2 emissions, while most of the other studies examined used a 

single estimate of the value of CO2 typically consistent with the lower end of the range (or 

below) estimates reported by the interagency working group. Maine’s assessment valued CO2 at 

$12/ton (LEI 2012) and the IPA assessment valued CO2 at $5/ton (IPA 2013). 

There are a number of considerations with respect to methods of assessing air emissions impacts 

that can influence their ability to be compared to incremental costs. In cases where cap and trade 

policies are in place, renewable energy may not provide emissions reductions from capped 

pollutants, unless there is a set-aside for renewable energy. At the same time, even in this 

instance the increased production of emissions-free renewable electricity will reduce the cost of 

complying with the cap-and-trade program, as proxied by the marginal allowance price. If 

allowance prices are used to estimate benefits, however, it is important to ensure that they are not 

already captured in the estimated incremental cost of the renewable energy. Allowance prices 

should already be embedded in wholesale electricity prices, for example, so if wholesale prices 

are used in cost calculations, then those estimates should already take into account these impacts. 

Similarly, if a proxy plant used to calculate the incremental cost of the RPS includes allowance 

prices or carbon costs, then these emissions impacts are captured in the incremental cost 

assessment. Another factor that complicates comparison is that often benefits estimates are 

forward looking, while the incremental costs are based on historical compliance. For these 

reasons, it is difficult to compare these estimates to the incremental costs discussed earlier; 

however, treatment of these issues varies from state to state. 

4.2 Economic Development Impacts 

Economic development impacts are also of significant interest in evaluating RPS policies. Often 

policymakers seek to achieve economic development goals with RPS policies; therefore, these 

impacts are generally of interest, and in some cases, their quantification is required by the state 

legislature. 

Economic impacts of renewable energy development resulting from an RPS include impacts on 

the number of jobs, direct investment from construction and operation of facilities, tax revenues, 

as well as indirect and induced economic impacts, which result from the purchase of goods and 
57 

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services.45 An RPS can also affect electricity prices, which can impact economic activity. One 

key issue is whether the assessment examines gross impacts (e.g., new jobs supported) versus net 

impacts that consider shifts in employment. Understanding net impacts associated with the 

development of new renewable energy projects requires more detailed analysis of changes in the 

operation of other generating units, fuel usage, utility revenues, electricity prices, and residential 

and commercial energy expenditures (Steinberg et al. 2011). Many states focus on the boundary 

of impacts within the state, but in reality, shifts in jobs may occur within the region. 

Furthermore, some assessments focus on only one particular aspect of the economic impacts. 

A variety of methods can be employed to conduct economic assessments; these involve varying 

degrees of rigor. Simplified methods, which yield estimates of gross impacts, include inputoutput models or case study approaches often focused on specific renewable energy facilities. 

Input-output models, the most common method used in gross impact analysis, calculate the 

direct, indirect, and induced economic impacts by quantifying relationships between sectors in an 

economy at a point in time, but cannot analyze changes in electricity prices (e.g., IMPLAN, 

RIMS II). More sophisticated economic modeling tools can also be used to assess net impacts, 

including: 1) econometric models that assess impacts on the economy; and 2) computable 

general equilibrium models (CGE models) that examine the flow of goods and services through 

the economy (see U.S. EPA 2011 for more detail on methods and models available). Table 12 

summarizes estimates of the economic impacts of RPS policies for several states. 

 

45 See the RIMS II user’s guide for more in-depth discussion of these components, Bureau of Economic Analysis, 

Department of Commerce, https://www.bea.gov/regional/pdf/rims/RIMSII_User_Guide.pdf, accessed January 30, 

2014. 
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Table 12. Summary of Estimates of RPS Economic Impacts

State Estimated 

Benefit/Impact

Benefits 

$/MWh of RE

Period Description Source

CT

Negative to 

positive GSP 

impact

N/A Through 

2020

Modeling showed retail 

electricity prices increased 

0.86% to 3.48%, which 

reduced gross state product 

(GSP) 0.01% to 0.03%. One 

scenario showed an increase 

in GSP of 0.02%

CEEEP 

and 

R/ECON 

2011

IL $3003 million* $14/MWh* Construction

Construction impact of the 23 

largest wind farms installed by 

2012

IPA 2013; 

Loomis 

2013

$140 $16/MWh

Annual, 

during 

project 

lifespan

Annual operational impacts 

from onsite labor, local 

revenue and induced impacts

IPA 2013; 

Loomis 

2013

ME

$1,140 million $24/MWh Construction 2% increase in GSP LEI 2012

$7.3 million $4/MWh 

Annual, 

during 

project 

lifespan

$6.3 million annually in tax 

revenue for local governments 

and $1 million of revenue/year 

for private landowners during 

the operating life of the 

projects

LEI 2012

MI $159.8 million N/A Construction Economic impacts of four wind 

farms built in Michigan

MPSC 

2013

NY

$1,252**

million $13/MWh Project lifespan

Present value of the total 

direct investments in NY 

during the life of the projects

NYSERDA 

2013b

$921 million $9/MWh Project 

lifespan Cumulative impact on GSP NYSERDA 2013b

OR Not estimated N/A Project 

lifespan

Estimated jobs resulting from 

renewable energy projects, 

based on survey

ODOE 

2011

*Illinois benefits estimates converted from $2008 to $2012. Calculations per MWh are estimated assuming a 30% 

capacity factor and for the construction benefits, spread over generation for a 25-year project life. 

**New York estimates are in net present value and $2012. 

4.2.1 Input-output Models and Simplified Approaches 

The following states conducted assessments using input-output models, case studies, or 

anecdotal information on the impacts of particular renewable energy facilities to assess economic 

impacts. These typically assess gross impacts. 

Illinois. In 2012, Illinois State University used the Jobs and Economic Development Impact 

(JEDI) model,46 an input-output model for estimating gross economic impacts, to estimate the 

state-level economic impacts of the 23 largest wind farms installed in Illinois at the time of the 

analysis (Loomis et al. 2013). The results showed that 3,335 MW47 of nameplate wind capacity 

could support a total economic impact of $5.98 billion over the estimated 25-year life of the 

 

46 The JEDI model was developed by NREL and is publically available at: http://www.nrel.gov/analysis/jedi/. 47 For comparison, Illinois had 3,568 MW of cumulative wind capacity by the end of 2012.
59 

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projects (IPA 2013). The study also estimated that the projects would support 19,047 full-time 

equivalent jobs during construction periods with a total payroll of more than $1.1 billion, 814 

permanent jobs with an annual payroll of nearly $48 million, $28.5 million in annual property 

taxes, and $13 million annually in extra income for Illinois landowners who lease their land to 

wind farm developers (Loomis et al. 2013). 

Maine. In addition to assessing emissions benefits, the LEI report for the Maine PUC (see 

Emissions and Human Health section) quantified the economic impacts of RPS compliance using 

Maine-specific multipliers from the Regional Input-Output Modeling System (RIMS II), which 

was developed by the U.S. Bureau of Economic Analysis. LEI used half of the aggregate 

capacity of the wind projects proposed to be built in Maine, or 625 MW, as an input for the 

RIMS II model. Assuming an average cost of $2,563/kW for wind generation capital costs and 

assuming 35% of the total investment, or roughly $560 million, stays in Maine, LEI estimated 

that the investment supported $1,140 million (2%) in GSP and roughly 11,700 jobs during 

construction, plus $6.3 million annually in tax revenue for local governments and $1 million of 

revenue/year for private landowners during the operating life of the projects (LEI 2012). LEI 

also calculated the potential increase in electricity prices resulting from a higher RPS 

requirement and REC price and its effect on jobs and Maine’s GSP. LEI used RIMS II 

multipliers to calculate that a 10% RPS requirement with a REC price of $33/MWh48 would lead 

to a reduction in GSP of 0.06% and the loss of 129 jobs statewide (LEI 2012). 

Michigan. The Michigan Public Service Commission (MPSC) is required by state statute to 

submit to the legislature an annual report on the implementation of the state’s RPS and its costeffectiveness, including the impact on employment. In its 2013 report, the MPSC included 

information on the economic impacts of wind farms owned by two utilities, although no 

information was provided on the methods used to determine these impacts (MPSC 2013). 

Consumers Energy reported that the construction of the 100-MW Lake Winds Energy Park wind 

farm resulted in more than $4 million in direct payments to Michigan vendors, $4.8 million in 

indirect economic impact, plus more than $1 million in induced impacts. DTE Energy estimated 

its three wind parks, one constructed per year through 2013, contribute $150 million in total 

economic benefits to Michigan. 

Oregon. Oregon Department of Energy (ODOE), which is required by law to evaluate the 

impact of the state’s RPS on employment, surveyed Oregon RPS-eligible facilities to assess 

economic impacts in 2011. Nine of twelve non-solar facilities surveyed reported 82 full-time 

equivalents employed at the time of the study. Reported salaries ranged between $30,000 and 

$70,000 for administration jobs, $50,000 to $125,000 for managerial jobs, and $30,000 and 

$65,000 for O&M jobs (ODOE 2011). In addition, prospective wind facilities of 35 MW or 

greater anticipated the creation of 6 to 40 permanent operation jobs and between 120 and 475 

temporary construction jobs per wind farm. Portland General Electric also provided information 

about its 450-MW Biglow Canyon wind farm, which employed about 200,000 person hours 

(about 95 FTEs) during each of the three phases of construction (ODOE 2011).

 

48 The RPS requirement was 3% and REC price was $24/MWh at the time of the study.
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4.2.2 Economic Modeling Approach 

In our review, we identified assessments conducted for the following states using more detailed 

modeling approaching, including use of econometric models. While these assessments utilized 

more detailed modeling approaches, in some instances they focused on only one aspect of the 

economic impacts of the RPS. 

Connecticut. In 2011 the Center for Energy, Economic, and Environmental Policy (CEEEP) at 

Rutgers and the Rutgers Economic Advisory Service (R/ECON) employed the R/ECON 

econometric model, which examines net effects, to show the “direction and magnitude” of the 

effects that the RPS requirement could have on Connecticut’s economy. The team modeled a 

comparison scenario to serve as a baseline, in which current RPS requirements continue 

unchanged until 2020 and REC prices are set to $0. Five additional scenarios consider different 

REC prices and the job impacts associated with energy efficiency programs and a solar carveout. In the six scenarios, the study assumed no additional direct jobs would be supported in 

Connecticut as a result of the RPS outside the solar carve-out considered in one scenario. In four 

of the five scenarios, retail electricity prices increased between 0.86% and 3.48%, which in turn 

reduced the GSP between 0.01% and 0.03%. In contrast, the Flat RPS scenario, which is the 

same as the Comparison scenario (except the RPS is kept flat after 2010), saw an increase in 

GSP of 0.02%. Price increases also put downward pressure on non-agricultural jobs, creating a 

loss of 880 to 2,790 jobs across the state. The two scenarios with absolute jobs higher than the 

Comparison scenario were the Flat RPS (560 jobs) and the Solar Carve-out (130 jobs) scenarios 

(CEEEP and R/ECON 2011).

New York. In New York, energy suppliers contracted through RPS solicitations are required to 

report direct economic benefits every three years to demonstrate compliance with the 

requirement that at least 85% of said benefits accrue to the state. NYSERDA calculated that instate economic benefits average $27/MWh, in 2012 dollars, for Main Tier projects with contracts 

as of December 31, 2012, based on data reported by energy suppliers. NYSERDA estimated the 

present value of the total direct investments in New York during the life of the projects at $1,252 

million, compared to an estimated ratepayer cost of $431 million49 (NYSERDA 2013b). 

Using REMI’s PI+ model,

50 NYSERDA estimated a net increase of 668 direct, indirect, and 

induced jobs per year during the study period (2002-2037), equivalent to approximately 24,000 

job-years, including jobs added, saved, and lost. The cumulative impact on GSP is approximately 

$921 million (net present value, 2012 dollars). This number includes direct impacts from the 

construction and O&M of renewable energy plants, a net increase on the percentage of energy 

produced in-state, wholesale energy price reductions, and net capital and operation costs 

reductions (NYSERDA 2013b). 

Overall, states have estimated economic impacts on the order of hundreds of millions of dollars 

for the construction period (one-time), and in some cases tens of millions of dollars in annual 

economic benefits over the project lifetime. These estimates translate to about $22-$30/MWh of 

renewable generation. One study found that the RPS led to electricity price increases that 

 

49 Present values calculated in 2012 dollars with a 5.5% discount rate.

50 The REMI model is a combination of input-output, computational general equilibrium, and econometric models.
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reduced gross state product by less than 1%. The methods and assumptions used to conduct 

assessments vary considerably across states with several states using screening or simplified 

approaches, while others have used more detailed modeling. For those studies that estimate gross 

impacts (e.g., jobs supported), an obvious limitation is the lack of consideration of net job 

impacts and therefore an inability to capture the true economy-wide impact of increased use of 

renewable energy. Often, the studies evaluated are limited by focusing on only one particular 

aspect of the economic impacts. 

4.3 Wholesale Market Price Impacts 

Finally, in some cases, studies have attempted to assess reductions in wholesale market prices 

resulting from additional renewable generation (see Table 13). Renewable generation can 

depress wholesale market prices by eliminating more expensive generating sources from the 

dispatch stack, which reduces the market clearing price that is paid to all generators. Dispatch 

modeling can be used to estimate these impacts by running scenarios with and without the 

renewable generation on the system. Wholesale price suppression benefits differ from the 

benefits previously covered in that they pertain to electricity rates and wholesale prices, which 

could be embedded in cost calculations, depending on methods used. 

Table 13. Summary of Estimates of Wholesale Market Price Impacts of Renewables Developed for 

RPS 

State Estimated 

Benefit

Benefit 

$/MWh of 

RE

Period Description Source

ME $4.5 million $2/MWh 2010

Savings for consumers from 

reduced electricity prices. 

Extrapolating from a study by ISONE, LEI estimated that 625 MW 

new wind in Maine would reduce 

wholesale prices by $0.375/MWh

of total Maine retail sales.

LEI 2012

MA $328 

million ~$50/MWh 2012

Savings for consumers from 

reduced wholesale electricity 

prices.

EOHED 

and 

EOEEA 

2011

IL $177 

million 

$26/MWh

 2011

Renewable energy lowers 

wholesale prices, by $1.3/MWh (all 

generation) due to low operating 

costs.

IPA 2013

MI N/A N/A 2011

2% decline in wholesale prices 

attributed to wind generation, net 

imports, and decrease in load.

Potomac 

Economics 

2012

NY $455 

million* $5/MWh Project 

lifespan

Savings for consumers from 

reduced wholesale energy and 

capacity prices.

NYSERDA 

2013b; 

2013c

OH Not 

estimated N/A 2014

Renewable energy lowers 

wholesale prices by $0.05-

$0.17/MWh (all generation).

PUCO 

2013c

*Net present value calculation reported in $2012. 

Illinois. IPA’s model of the Eastern Interconnection, as described in the Emissions and Human 

Health section, was also used to calculate wholesale market price reductions. Because wind 
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power does not have fuel costs—it is a zero-marginal cost resource—it can result in reducing 

wholesale power prices by displacing more expensive generation sources. IPA’s modeling shows 

an estimated average reduction in LMPs of $1.30/ MWh attributable to renewable energy 

produced in Illinois in 2011. The model estimates an average LMP of $36.40/MWh when Illinois 

renewable energy fleet is excluded, and $35.10/MWh when it is included (IPA 2013). 

Maine. MPUC’s consultants, LEI, cited an ISO New England study that estimated average 

clearing prices for different levels of wind penetration installed in the western part of Maine by 

2016 (Coste 2011). In a scenario where there were no transmission constraints, 1 GW of wind 

reduced wholesale prices by about $0.60/MWh. Assuming a linear relationship between cost 

reductions and added wind capacity, LEI estimated that 625 MW of new wind in Maine would 

reduce wholesale prices by $0.375/ MWh. Considering annual retail sales of roughly 12,000 

GWh and assuming that the savings are passed 100% to retail consumers, LEI calculated annual 

savings of $4.5 million for ratepayers from reduced electricity prices (LEI 2012). 

Massachusetts. At the direction of the state legislature, the executive offices of Housing and 

Economic Development (EOHED) and Energy and Environmental Affairs (EOEEA) prepared a 

report in 2011 on the costs and benefits of various policies, including the state’s renewable and

alternative portfolio standards. The report notes that there are a number of potential benefits of 

renewable generation, but bases its calculation primarily on the price suppression benefit 

resulting from the addition of renewable and alternative energy resources. The study relies on 

estimates of price suppression effects from the Cape Wind contract proceeding, in which the 

DPU reviewed estimates provided by various parties. To estimate the RPS benefits, the study 

assumes price suppression grows linearly in proportion to the amount of renewable energy 

generation. Using a total benefit value of approximately $50/MWh for the renewable and 

alternative sources added to the grid each year,51 the report estimates aggregate benefits of $328 

million for CY 2012 (EOHED and EOEEA 2011). 

Michigan. In its 2013 report, the MPSC also included information on wholesale market impacts 

from wind energy in MISO based on a study by the grid operator. The introduction of the 

Dispatchable Intermittent Resources (DIR) program in June 2011 allowed wind to participate in 

MISO’s real-time energy market like other power resources and set market prices of negative 

$20/MWh on average, due to low marginal operating costs and PTCs (MPSC 2013). The 

independent market monitor for MISO reported that two-thirds of the 2% decline in energy 

prices in 2011 was attributable to a decline in average load, increased generation by “intermittent 

resources”, and an increase in net imports (Potomac Economics 2012). 

New York. NYSERDA calculated wholesale price reductions using IPM to model the effect on 

capacity and energy prices from the addition of renewable energy assets in the Current Portfolio. 

The average price difference in $/MWh was multiplied by total load levels (adjusted for utilities 

that self-supply) to estimate consumer savings due to RPS resources. Savings accrue because 

most load-serving entities in the state have divested of generation resources and procure energy 

to serve loads from wholesale markets, although wholesale price reduction benefits would not 

accrue where generation is procured through long-term contracts committed prior to the 

 

51 The number was taken from the Cape Wind contract proceeding (DPU 10-54 Revised RR-DPU-NG-4).
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development. Total net present value of price suppression benefits were estimated at $455 

million over the lifetime of the renewable resources (2002-2037) (NYSERDA 2013b; 

NYSERDA 2013c). 

Ohio. PUCO calculated wholesale price reductions for the two scenarios described in the 

Emissions and Human Health section. In the first scenario, which considers only those projects 

that are already operational, wholesale prices are reduced by approximately 0.15%, from $32.25 

/MWh to $32.20/MWh. In the second scenario, which considers all approved projects, wholesale 

prices are reduced by approximately 0.51%, from $32.25/MWh to $32.08/ MWh (PUCO 2013c).

While the studies summarized here show estimated reductions in wholesale electricity prices on 

the order of about $1/MWh or less, the impact on overall reduced costs to consumers can be 

large since the price suppression effect in any given hour is applied to the entire demand in that 

hour. Estimates presented above represent price suppression benefits of about $2-$50/MWh of 

renewable generation. Typically, these wholesale price estimates have been derived through 

modeling of the electricity system. One difficulty in directly comparing these estimates to costs 

is that wholesale price suppression is a short term effect that could change over time with 

changing market conditions. In addition, these estimates focus on energy prices, but do not 

attempt to assess capacity-related impacts or the need for new transmission or infrastructure 

investments that may be required with renewable generation. Another consideration is that while 

consumers benefit from lower wholesale market prices, the reductions represent transfer 

payments from generators to consumers. 
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5 Conclusion This report surveys and summarizes existing state-level RPS cost and benefit estimates and 

examines the various methods used to calculate such estimates. The report relies largely upon 

data or results reported directly by electric utilities and state regulators. As such, the estimated 

costs and benefits itemized in this document do not result from the application of a standardized 

approach or the use of a consistent set of underlying assumptions. 

The report summarizes state-level RPS costs to date and considers how those costs may evolve 

going forward, given scheduled increases in RPS targets and cost containment mechanisms 

incorporated into existing policies. The report also summarizes RPS benefits estimates, based on 

published studies for individual states, and discusses key methodological considerations. These 

estimates, for example of the social value of carbon emissions reduction and the human health 

impacts of reduced air emissions, are based on a variety of methodologies and assumptions. In 

comparison to the summary of estimated RPS costs, the summary of RPS benefits is more 

limited, as relatively few states have undertaken detailed benefits estimates. Further, for those 

states that have estimated RPS benefits, most assess only a limited number of impact types; as a 

consequence, some types of benefits are not reflected in this report. 

This survey of RPS costs and benefit estimates across states finds that in the most recent year 

with data available, costs were estimated to be equivalent to less than 2% of retail rates in 17 

states, with 10 of these states having estimated costs equivalent to less than 1% of retail rates. 

The remaining 8 states have costs that are estimated to be equivalent to 2% to 4% of retail rates, 

averaging the two estimates for California. A limited number of states have developed 

quantitative benefits estimates, which vary widely in both methodology and magnitude. Benefits 

estimates have been most commonly developed for avoided emissions and associated air quality 

improvements, economic development, and wholesale electricity price suppression effects. 

Because the reported cost and benefit values may differ from those derived through a more 

consistent analytical treatment, we do not provide an aggregate national estimate of RPS costs 

and benefits, nor do we attempt to quantify net RPS benefits at national or state levels. 

Estimates of costs are limited by available data and the wide variety of methods and assumptions 

employed. This analysis focuses on comparing estimated incremental costs, which are most 

appropriate for assessing RPS policy because they net out costs that would otherwise have been 

incurred to serve loads if the RPS did not exist, such as the need for other forms of generation. 

We use a standardized method to derive incremental costs in restructured markets based on REC 

prices, ACP levels, and compliance obligations. Key limitations of this method include omission 

of other potential policy costs, a lack of REC price transparency, and incomplete data on long 

term contracts. While REC prices reflect compliance costs, they do not necessarily reflect the 

cost of renewable technology deployment because they can be strongly influenced by market 

supply and demand conditions. In regulated states, comparisons of costs are complicated by our 

reliance on estimates produced by utilities and regulators, who utilize a wide variety of methods 

and assumptions. 

The primary methods used in regulated states for estimating incremental RPS costs are: 1) to 

compare the cost of renewable generation to that of a proxy generator (a plant type that is most 

likely to be displaced by the renewable generation); 2) to compare to wholesale electricity 
65 

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market prices; or 3) to conduct electric system modeling with and without the renewable 

generation. While the modeling approach can provide a more detailed estimate of the resource 

mix if an RPS were not implemented, assumptions for inputs can significantly influence results. 

Simplified proxy methods may provide useful perspective on costs, but yield less comprehensive 

results. In various approaches, assumptions regarding plant lifetime and methods of annualizing 

costs are important considerations that can significantly affect estimates. The inclusion of costs 

associated with pre-RPS renewables can lead to overestimates of RPS costs while inclusion of 

efficiency and indirect expenditures may make it challenging to directly assess costs resulting 

from the addition of new renewable generation. 

Despite differences and uncertainties in cost methodologies, RPS costs are typically bounded by 

the presence of policy mechanisms to cap costs. Most states have a way to contain RPS costs, 

typically through either a cap, based on either retail electricity rates or revenue requirements, or 

by allowing ACPs. Estimated incremental RPS costs in most states are well below the respective 

cost caps, although a few states are currently operating at or near them. 

RPS costs can be considered in the context of policy benefits, although again there are 

limitations in the ability to compare estimates. While RPS policies have the potential to offer a 

variety of environmental and social benefits, often only a few types of benefits have been 

quantified. States have most commonly attempted to estimate avoided emissions and associated

human health benefits, economic development impacts, and savings associated with reductions 

in wholesale electricity prices; in many cases, these assessments have been required by the 

legislature or PUC. In some cases, the same impacts may be captured in the assessment of 

incremental costs. In addition, methodologies and level of rigor vary widely, making 

comparisons challenging. 

Going forward, more could be done to comprehensively assess the costs and benefits of state 

RPS policies. Instead of looking separately at incremental costs and benefits, future analysis 

could compare costs and benefits directly within and among states, using a consistent 

methodology and level of rigor. 

In addition to more comprehensive analysis of cost and benefits, additional work could be done 

to standardize incremental cost calculations within and among states, given that incremental cost 

calculations are often required by RPS statutes. Efforts within a few states are underway to 

address standardization of incremental cost calculations; states that have not examined 

standardization may see the issue arise in the future and be able to learn from the processes and 

outcomes of existing state standardization efforts. 

States in restructured markets may find it beneficial to promote REC price transparency, 

particularly as those markets move towards greater use of long-term contracting. REC price 

transparency could be encouraged by requiring RPS-obligated entities to report REC prices on a 

confidential basis to the PUC; prices could then be publically reported only on an aggregated 

basis. 
66 

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

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76 

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79 

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

Appendix: State Summaries

Arizona

Arizona’s RPS requires 15% of electricity be derived from renewable energy by 2025, with 30% 

(i.e., 4.5% of total retail sales in 2025) of this energy derived from distributed resources. IOUs 

and electric power cooperatives serving retail customers in Arizona--with the exception of 

distribution companies with more than half of their customers outside Arizona--are subject to the 

standard (DSIRE 2012).

APS and Tucson Electric Power (TEP) fully complied with their CY 2012 requirements, which 

include a substantial distributed generation component. In 2012, APS reports total RPS 

procurement of 1,507,021 MWh, or 5.3% of retail sales, with total distributed generation of 

503,498 MWh (APS 2013). APS’s 2011 reported above-market renewable generation cost, 

which came from PPAs and utility-owned solar facilities, was $11.28/MWh of renewable 

electricity, dropping to $9.63/MWh in 2012 (APS 2012; APS 2013). 

TEP reports total purchased renewable energy at $4,809,557, which exceeded the target of 

279,963,210 RECs representing 3% of its retail energy sales for 2011 (9,332,107 MWh) (TEP 

2012). TEP did not list renewable generation cost in MWh in its compliance report. 

RPS costs are recovered through a surcharge on customer bills. Average residential customer 

monthly surcharges in 2012 were $3.15 for TEP, $3.84 for APS, and $4.50 for UNSE/Citizens 

(ACC 2012a; ACC 2012b; ACC 2012c). The residential tariff surcharges are higher than what is 

seen in other stares with surcharges, partially reflecting the fact that Arizona’s RPS has a 

substantial distributed generation requirement. 

California

California’s RPS has a 33% target for all electric retailers by 2020. In 2011, Pacific Gas and 

Electric Company (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric 

Company (SDG&E) spent approximately $1,017 million, $1,341 million, and $170 million, 

respectively, on direct RPS procurement, whereas RPS deliveries represented 19.8%, 21.1%, and 

20.8% of the utilities’ retail sales, respectively (CPUC 2013). In 2011, the utilities’ RPS 

portfolios (in dollar terms) were primarily comprised of geothermal (35%), wind (34%), and 

biomass (12%). Table 14 provides a summary of California utilities’ average RPS costs from 

2003-2011. These data represent gross RPS procurement costs.
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Table 14. California Utilities’ Estimated Average RPS Costs in ¢/kWh (2003-2011) 

Utility 2003 2004 2005 2006 2007 2008 2009 2010 2011

Southern 

California

Edison

7.5 7.6 7.6 7.5 8.0 9.3 7.9 8.2 8.5

Pacific Gas 

and Electric 

Company

6.5 6.5 6.4 6.6 7.5 8.2 7.0 7.4 7.3

San Diego 

Gas & 

Electric 

Company52

5.4 5.3 5.3 5.3 5.2 5.8 5.4 5.9 5.1

Source: CPUC 2013

In California, two sets of incremental cost estimates have been used to compute RPS incremental 

costs, resulting in average incremental costs ranging from -2.4 ¢/kWh to 4.3 ¢/kWh in 2011.The 

MPR methodology, developed by the CPUC, is used to determine whether an “RPS contract 

selected from a competitive solicitation had above-market costs associated with it” (CPUC 2013, 

p.9). The 10-year and 20-year MPRs for contracts with a 2011 start date are 8.8 ¢/kWh and 10.1 

¢/kWh, respectively, based on 2009 MPR calculations.53 Using the MPR methodology, 

incremental cost calculations for 2011 were negative, equaling -2.4 ¢/kWh of renewable energy 

procured, or -3.6% of average retail rates.

The other set of incremental cost estimates, provided by the utilities, is based on day-ahead 

CAISO energy market prices and the cost of capacity in the CAISO market (CPUC 2013a). 

These incremental cost calculations in 2011 were 2.2 ¢/kWh for SDG&E, 3.6 ¢/kWh for PG&E, 

and 5.3 ¢/kWh for SCE. 

The CPUC is currently in the process of developing a cost containment mechanism for the RPS.

In 2013, the CPUC proposed using a Procurement Expenditure Limitation (PEL) methodology to 

calculate RPS containment mechanism, replacing the MPR method, which is composed of a ratio 

of an IOU’s RPS procurement expenditures (actual money spent by the IOU to fulfill its PPAs 

and operate its facilities over 10 years) to its total forecasted revenue requirement (the initial year 

equals the IOU’s effective revenue requirement, escalated by 2.75% over the course of 10 years) 

(CPUC 2013). 

Colorado

Colorado’s RPS has a 30% mandate for IOUs and a 20% mandate for cooperative and municipal 

utilities by 2020, with 3% of retails sales coming from distributed generation. Cooperative and 

municipal utilities with less than 100,000 meters are only required to meet 10% renewables by 

2020 (DSIRE 2013). Colorado’s RPS offers a 1.25 multiplier for projects installed before 

January 1, 2015 and a 3.00 multiplier for projects installed before July 1, 2015. 

 

52 SDG&E’s RPS cost includes RECs starting in 2009. 53 The 2011 adopted values are current, but they apply only to RPS contracts with start dates in 2012 and beyond 

(CPUC 2013).
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The major IOUs in Colorado–Xcel Energy (Public Service Company of Colorado) and Black 

Hills–have had no difficulty meeting targets. In fact, Xcel has been able to procure more 

renewable energy than required. In 2012, for example, Xcel generated or procured 6.3 million 

RECs as opposed to the required 3.5 million (PSCO 2013a). 

Xcel has been able to buy wind power through PPAs at prices competitive to what it sees for 

natural gas. Two recent wind PPAs were signed for $27.50/MWh, escalating in future years, with 

a 25-year levelized cost of $35/MWh (Stanfield 2013b). The estimated incremental RPS costs 

are determined through scenario analysis that compares the costs and benefits of the current RPS 

plan to a plan that replaces the new renewable energy with new non-renewable resources 

available. In 2011, Xcel had the equivalent of 16% of its retail sales from renewable energy (or 

20%, when including the 1.25 multiplier for in-state projects), but was only required to have 12% 

renewable energy (CO PUC 2013). 

Colorado PUC rules stipulate that the retail rate impact can be calculated as the difference 

between the cost of the renewable energy purchases and the cost of new fossil fuel-based energy 

for generation RPS-related costs and can be recovered through the Renewable Energy Standard 

Adjustment (RESA) surcharge, which is capped at 2% of annual customer bills. As of 2012, 

PSCo’s 2% monthly customer surcharge was equivalent to roughly $1.44, on average, for 

residential customers, while Black Hills Energy’s average residential customer surcharge was 

roughly $2.04 (PSCO 2013a; Black Hills 2013). To date, Xcel has spent more than 2%, but 

deferred the additional spending for collection in later years. 

Connecticut

Connecticut’s RPS requires each electric supplier and each electric distribution company (EDC) 

wholesale supplier to obtain at least 23% of its retail load by using renewable energy, in addition 

to obtaining at least 4% of its retail load by using combined heat and power (CHP) systems and 

energy efficiency, for a total of 27% by 2020 (DSIRE 2012). Connecticut uses a separate tier for 

energy efficiency, for which compliance is achieved through the use of credits, and some of the 

information on prices is available from brokers. 

In 2008, in aggregate, 3,070,869 Connecticut eligible RECs were used to comply with the RPS 

requirements, of which 1,534,981 were Class I RECs. Only 4% of Class I renewable energy is 

coming from Connecticut, 45% from Maine, 29% from New Hampshire, and the rest from 

Massachusetts, New York, Rhode Island, Quebec, and Vermont. Approximately 74% of the 

Class I RECs used for 2008 RPS compliance were obtained from biomass plants, particularly 

wood, followed by 28% of RECs generated from methane gas from landfill facilities 

(Department of Public Utility Control 2011).

In 2008, there were 17 electric suppliers and 2 EDCs subject to the Connecticut RPS; 6 suppliers 

(32%) did not meet the RPS, but this was by slim margins. Two of the state’s largest utilities, 

Connecticut Light & Power Company and the United Illuminating Company, were in 100% 

compliance with 2008 RPS requirements. Companies that fail to comply with the RPS 

requirements are required to pay an ACP of $55/MWh for Class I RECs, which is used to offset 

other ratepayer costs (Department of Public Utility Control 2011). The aggregate ACP paid by 

all suppliers for 2008 was $113,730. 
82 

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Findings from the Connecticut Center for Energy, Economic, and Environmental Policy and the 

Rutgers Economic Advisory Service indicate that future impact of the RPS on Connecticut’s 

electricity prices is between less than 1% and 3.5% of the typical residential electricity bill in 

2020. The economic and energy impacts of Connecticut’s RPS requirements were estimated 

using R/ECON Connecticut, an econometric model based on historical data for Connecticut and 

the United States. 

The District of Columbia

The District of Columbia has an RPS requirement of 20% by 2020 that applies to all retail sales 

in the district. The RPS requirement includes a solar carve-out of 2.5% by 2023. Only systems 

less than 5 MW in capacity and located within the District of Columbia54 are eligible for the 

carve-out (DSIRE 2013). RECs retired to meet the solar carve-out can be used to meet the main 

RPS requirement as well (DCPSC 2012). 

In 2010, energy suppliers reported 100% compliance with the main requirement and 97% 

compliance with the solar carve-out. In 2011, the Public Service Commission of the District of 

Columbia (DC PSC) reported that a total of over 469,000 RECs were used for main tier 

compliance–excluding carve-outs–for a total cost of approximately $820,000 and an average 

REC price of $1.75. Roughly half of the RECs retired were generated in 2011 while the other 

half was equally split between 2010 and 2009 (DC PSC 2013). 

Since the inception of this RPS, black liquor gasification has consistently been used as the 

primary source of RECs; black liquor typically costs less than other RPS-eligible resources. 

Landfill gas and wood waste are the two other most prevalent sources of renewable energy used 

for compliance in the region. Collectively, these three generation technologies accounted for 

94% of total main tier compliance in 2011, and their average costs per REC ranged between 

$1.42/MWh and $1.94/MWh. That year the solar carve-out requirement was 0.4% and 5,896 

SRECs were retired for compliance. In 2011, the average cost of SRECs was $300/MWh. Recent 

2013 SREC prices from the Flett Exchange and SRECTrade were around $375/MWh to 

$386/MWh (DCPSC 2013).The main tier ACP is set at $50 (DCPSC 2013). In 2011, the total 

reported RPS compliance cost was $2.6 million, of which ACPs totaled $229,500 (most of these 

payments came from one electricity supplier unable to acquire enough SRECs) (DCPSC 2013). 

Delaware

Delaware’s RPS requires retail electricity suppliers to purchase 25% of the electricity sold in the 

state from renewable sources by 2025, with at least 3.5% from solar photovoltaic (PV) (DSIRE 

2013). Beginning in CY 2012, the RPS applies to the state’s only electric distribution company, 

Delmarva Power & Light. 

In CY 2011, Delaware was in 99% compliance, with a total of 554,259 MWh RECs (15,741 

MWh from solar, 517,245 from new non-solar, and 21,273 from existing non-solar resources). 

Delmarva Power estimates that total costs to comply with the RPS are $45 million from 2013-

2014, increasing to $83 million from 2022-2023 (Delmarva Power & Light Company 2012). As 

 

54 Alternatively, the systems may be connected to a distribution feeder serving the District of Columbia.
83 

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far as rate impacts on customer bills are concerned, Delmarva forecasts that the RPS is likely to 

affect a typical 1,000 kWh residential monthly bill by $6.60 in CY 2013; this impact is expected 

to increase to $15.15 a month in CY 2022 (Delmarva Power & Light Company 2012). 

The total cost cap for Delmarva Power & Light Company is 1% for solar, which includes 

compliance with PV requirements. If the utility’s total retail cost of electricity exceeds 1%, then 

the RPS requirement for solar may be frozen at the percentage for the year in which the freeze is 

implemented. The total cost cap for Delmarva Power & Light Company is 3% for eligible energy 

resources; if the utility’s total retail cost of electricity exceeds the 3%, then the RPS requirement 

may be frozen at the percentage for the year in which the freeze is implemented. Delaware also 

has an ACP set at $25-$80/MWh (DSIRE 2013). 

The Department of Natural Resources and Environmental Control (DNREC) is in the process of 

developing rules for calculating the cost of compliance with the RPS, which may include 

provisions for “netting” the costs or including costs that are avoided by renewable energy 

resources, such as air emissions costs. “Netting” RPS avoidance costs of renewable energy may 

significantly reduce the impact on customer bills (Delmarva Power & Light Company 2012). 

Draft regulations specify that the Division of Energy & Climate will determine the cost of 

compliance, which will then be review by the Director. The Division Director shall then 

determine the whether to freeze RPS requirements. As part of that determination, draft 

regulations specify that the Director may consider benefits such as price suppression, savings in 

health and mortality costs, and economic development benefits from renewable energy 

deployment in the state. (DE DNREC 2013) 

Hawaii

Hawaii’s RPS requires each electric utility that sells electricity for consumption in the state to 

achieve net electricity sales from renewable energy of 15% by 2015, 25% by 2020, and 40% by 

2030. Starting in 2015, electrical energy savings from energy efficiency and solar water heating 

technologies will be excluded from counting towards the RPS. In 2012, 1,276,234 MWh were

generated from purely renewable resources, fulfilling 13.9% of the RPS requirement for the 

Hawaiian Electric Companies consisting of Hawaii Electric Light and Maui Electric Company 

(HECO). 

According to HECO, long-term fixed price contracts for renewable energy are cost-effective 

compared to avoided energy costs (see Table 15). The Oahu generation cost includes seven 

PPAs, of which one was biomass generated at approximately 26 ¢/kWh, two for wind at a cost of 

21 to 23 ¢/kWh, three for PV between 22 and 23 ¢/kWh, and one for waste to energy at 21 

¢/kWh (HECO 2012). 
84 

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Table 15. Estimated Avoided Energy Cost in ¢/kWh Purchases from Qualifying Facilities of >100 

kW55

Hawaiian 

Electric 

Company

Hawaii Electric 

Light 

Maui Division Maui Electric 

Company 

Lanai Division

Molokai Division

On peak 22.697 20.657 19.990 34.669 29.473

Off peak 16.041 15.652 19.318 29.076 26.646

Source: HECO 2012

Kauai Island Utility Cooperative (KIUC) serves the island of Kauai only. In 2012, KIUC’s RPS 

portion that was met by electrical energy generated using renewable energy was 40,793 MWh, 

which is greater than 50% of the total 2012 10% RPS requirement of 43,315 MWh (KIUC 2012). 

By the end of 2012, renewables accounted for 15% of KIUC electricity sales. The 6 MW solar 

array at Port Allen is the largest solar facility in Hawaii. It supplies almost 10% of KIUC’s 

daytime electrical load and annually produces about 3% of the total energy used on Kauai. Under 

a 20-year contract, KIUC pays 20 ¢/kWh for solar power. 

In 2008, the Hawaii Public Utilities Commission (HPUC) approved a penalty of $20/MWh for 

any shortfall in procuring renewable electricity to meet the RPS requirements (HPUC 2012). In 

Hawaii, utilities may petition the HPUC for a waiver of a penalty for failure to meet the RPS if 

contracts for procuring generation or renewable energy credits are above-market price for other 

available resources (Stockmayer et al. 2012). 

Illinois

Illinois’s RPS requires IOUs and alternative retail electric suppliers (ARES) to achieve a 25% 

RPS target by 2026, of which 75% of the requirement must be from wind, 60% wind for ARES, 

1% from distributed generation and thereafter (IOUs only), and 6% from solar in 2016 and 

thereafter (1.5% of total sales in 2026) (DSIRE 2013). In-state renewable energy is given 

preference, although out-of-state RE purchases may also count towards compliance.

Renewable energy procurement is done through the Illinois Power Agency (IPA), whose purpose 

is to develop electricity procurement plans, including for RPS compliance, for IOUs supplying 

over 100,000 Illinois customers. The IPA plans and administers the competitive procurement 

processes that result in bilateral agreements between the utilities and wholesale electric suppliers 

(DSIRE 2013). In 2010, IPA solicited bids for 20-year long-term power purchase agreements 

(LTPPAs) to purchase up to 2 million MWh of renewable energy and the associated RECs each 

year, representing approximately 3.5% of the overall portfolio. Under these contracts, a single 

price was set for the bundled product (energy plus REC) with a 2% per annum cost escalator 

over the term of the contracts. 

REC prices shown in Table 16 are calculated from the average cost of RECs and energy 

procured by IPA. For the LTPPAs, where RECs are purchased with energy (“bundled”), IPA 

estimates the REC cost by subtracting the cost of conventional generation from the total cost of 

 

55 The methodology for the avoided cost calculation was developed prior to 1995 and is currently publically 

unavailable in an electronic format.
85 

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the renewable energy contract (the price of energy and RECs bundled together). In 2011, the 

IOUs were in 100% compliance with RPS obligations. 

Table 16. IPA Reported Costs of Unbundled RECs and Conventional Supply (June 2009-May 2013) 

Company RECs

(¢/kWh)

Conventional supply 

(¢/kWh)

ComEd 0.8 3.4 

Ameren 0.7 3.4

Source: IPA 2013

Note: REC costs are the average actual cost of RECs procured by IPA; for RECs procured with energy (“bundled”) 

under the 2010 LTPPAs, IPA estimates the REC cost by subtracting the energy price from the bundled cost.

Starting in 2007, the RPS costs are limited to either 2.015% of the amount paid per kWh in 2007, 

or the amount paid in 2011, whichever is greater (DSIRE 2013). 

Iowa

Iowa’s RPS requires its two IOUs, MidAmerican Energy and Alliant Energy Interstate Power & 

Light (IPL), to own or contract for a combined total of 105 MW of renewable generating 

capacity, of which MidAmerican Energy contributes 55.2 MW (52.57% of demand) and IPL 

contributes 49.8 MW (47.43% of demand) (DSIRE 2013). In 2001, a voluntary goal of 1,000 

MW of wind generating capacity by 2010 was established. By the end of 2012, Iowa’s installed 

wind capacity totaled 5,133 MW (IWEA 2012). The two utilities have fully met their obligations 

since 1999. 

As of 2011, the Iowa Utilities Board (IUB) staff estimated that 19-20% of all electricity 

generated in the state comes from wind (IUB 2011), much of which is used to meet RPS policies 

in surrounding states. 

Kansas

Kansas’s Renewable Energy Standard (RES) requires the state’s IOUs and cooperative utilities 

to generate or purchase 10% of their electricity from eligible renewable resources in the years 

2011-2015, 15% in the years 2016-2019, and 20% by 2020. Unlike most other states, Kansas’s 

standard is based on generation capacity (i.e., generally the gross capacity owned or leased by a 

utility less the auxiliary power used to operate the facility) (DSIRE 2013). 

Kansas public utilities have already complied with the 10% threshold, and are on their way to 

meeting the 15% requirement, primarily from wind resources. In 2012, there was oversupply of 

RECs in the region for two of Kansas’s larger utilities: Empire generated an excess of 291.9 MW 

and Westar generated an excess of 280.8 MW. Importantly, for renewable capacity generated in 

Kansas, utilities are awarded an additional 10% credit toward their requirements, thus 

incentivizing utilities to keep the renewable projects within the state (as of November 2012, there 

were 19 wind projects currently in operation or under construction). 

Costs for Kansas are measured on a gross basis. The KCC estimated statewide 2012 RPS gross 

costs of about 0.16 ¢/kWh, meaning that the RPS counts for about 0.16 ¢/kWh of the 9.2 ¢/kWh 

retail electricity cost in 2012 across the state, or about 1.7% (KCC 2013). The Kansas RPS 
86 

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places a 1% cap on the rate impact of compliance based on gross compliance costs. Given that 

the statewide impact of 1.7% exceeds the 1% cap on rate impact, it can be assumed that at least 

one utility has compliance costs exceeding the cap; however, utility specific cost information is 

held confidential by the KCC. 

Additional gross cost information on wind projects in Kansas was estimated by Polsinelli 

Shughart and Kansas Energy Information Network. The study estimated the gross costs of new 

wind power in Kansas to be between $35 and $45/MWh (Anderson et al. 2012). 

Maine

Maine’s RPS requires IOUs to supply at least 10% of their total electric sales using electricity 

generated from renewable sources classified as Class I (resources that have come online after 

September 1, 2005) by 2017 and for each year thereafter. Existing renewable energy resources 

are classified as Class II and must supply at least 30% of total electric sales by 2017 (DSIRE 

2013). 

In 2010, the RPS requirement for new renewable resources (Class I) was 3%, or close to 333,000 

MWh. The cost of purchased Class I RECs ranged from $5.76/MWh to $43/MWh with a total 

cost of $8.1 million (LEI 2012). The average reported procurement cost of Class I RECs was 

$24/MWh. Only two out of 30 suppliers chose to pay the ACP at the rate of $62/MWh for a total 

cost of $22,500 in 2010 (LEI 2012). 

Over 80% of purchased RECs were produced within the State of Maine and biomass has been 

the major resource for satisfying the Class I RPS requirements. Renewable resources located in 

Maine contributed significantly to RPS Class I compliance in Connecticut and Massachusetts, 

accounting for over 30% of the New England Class I RPS compliance requirement in 2009 (LEI 

2012). 

London Economics International LLC (LEI) calculated the compliance costs for Maine’s Class I 

RPS and found that in 2010, the cost was 0.07 ¢/kWh. LEI calculated the RPS retail rate impact 

on Maine’s consumers by multiplying the RPS percent requirement by the annual electricity 

retail sales and the market price of RECs. To assess the potential impact on retail rates if RPS 

policies and/or REC market prices change, LEI implemented an analytical “what if” 

consideration for both a higher RPS requirement as well as lower REC prices based on the 2010 

compliance cost scenario. Based on the 2010 compliance scenario, the ratepayer impact of the 

current 3% RPS was found to be 0.57% of the current average retail rate, or 37¢/month for 

residential customers, assuming a REC price of $24/MWh. Ratepayer impacts for the RPS at 

10% was estimated to be 1.90% or $1.24/month for households assuming REC prices remain at 

$24/MWh, and 1.07% of the current average retail rate and 70¢/month, assuming REC prices of 

$13.50/MWh (LEI 2012). 

Maryland

Maryland’s RPS requires all utilities and competitive retail suppliers to sell a minimum 

percentage of renewable energy at the retail level. In 2013 that requirement was 7.95%, which 

will grow to 18% in 2022. Electricity suppliers must obtain 2% of retail sales from solar 

resources by 2020. In 2013, Maryland enacted an offshore wind carve-out of up to 2.5% of retail 
87 

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sales in 2017 and beyond; the actual requirements of the carve-out will be developed by the 

Maryland Public Service Commission (DSIRE 2013). 

Electricity suppliers that fail to comply with the annual requirement must pay an ACP of $40/ 

MWh for main tier requirements. For solar generation, the ACP declines from $400/MWh in 

2011 to $50 in 2023. Payments go into the Maryland Strategic Energy Investment Fund 

(MSEIF), which is used to spur the creation of new renewable energy sources in the state (PSCM 

2013). 

In 2011, electricity suppliers in Maryland submitted more than 4.6 million RECs for compliance, 

roughly 15,000 above the requirement. The total cost was $14.6 million, of which $98,520 came 

from ACPs. Roughly 40% of the retired RECs were generated in 2011, 35% were in 2010, and 

25% were in 2009 (PSCM 2013). 

For the non-solar part of the main tier, black liquor represented 33% of the RECs retired in 2011, 

while small hydro was 26%, wind was 14%, and waste wood was 12%. Black liquor and small 

hydro are generally considered low-cost resources. Approximately 39% of the RECs were 

generated in Virginia compared to 14% generated in Maryland (PSCM 2013). 

Massachusetts

Massachusetts’s RPS retail load obligation from renewable resources was 6% in 2011, of which 

0.1627% must be met with solar. The RPS increases annually by 1% and is mandated to reach 

15% by 2020 (DOER 2013a). 

In 2011, the total retail load obligation was 49,386 GWh, of which the 5.8% Class I obligation 

(net of the 0.1627% solar carve-out obligation) was 2,883 GWh. Of this, 87% came from 2011 

generation while 9% came from banked RECs from a compliance surplus in 2009 and 2010 and 

4% from ACPs. Out of 37 suppliers, 14 did not acquire enough RECs to meet the target, but they 

met their compliance by paying the ACP of $62.13/MWh for 106,203 MWh for a total ACP 

payment of $6,598,386 (DOER 2013a). 

RPS costs in Massachusetts are capped through use of an ACP. Table 17 lists the 2013 ACP rates 

for several classes of renewables. 

Table 17. ACP Rates for the 2013 CY (in $/MWh)

RPS Class I RPS Class I Solar 

Carve-Out

RPS Class II 

Renewables

RPS Class II 

Waste Energy

$65.27 $550.00 $26.79 $10.72

Source: DOER 2013b

In 2011, RPS Class I RECs came from wind (47%), landfill methane fueled power plants (32%), 

and biomass-fired power plants (15%). The remaining supply came from anaerobic digester 

plants, hydroelectric plants, and PV arrays. Geographically, Maine’s wind supplied 28% of 

RECs, New York’s landfill methane plants and wind supplied 26%, wind farms in adjacent 

Canadian provinces supplied 13%, New Hampshire (mostly biomass) supplied 13%, 

Massachusetts (mostly landfill methane) supplied 11%, and other New England states supplied 

the balance (DOER 2013a). 
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In 2013, Fitchburg Gas and Electric Light Company, along with National Grid, NSTAR Electric 

Company, and Western Massachusetts Electric Company, collectively entered into PPAs to 

acquire their pro rata share of the total renewable energy output and RECs from six wind energy 

projects, with a combined capacity of 565 MW (MPUC 2013). If approved, utilities will pay an 

average price of less than 8 ¢/kWh over the course of these contracts compared with projected 

prices of about 10 ¢/kWh for coal, 11 ¢/kWh for nuclear, and 14 ¢/kWh for solar (Ailworth 

2013). The commercial operation dates associated with these projects range from November 

2014 to December 2016 and total generation is expected to reach 4 million MWh (MPUC 2013). 

Michigan

Michigan’s RPS requires all utilities to generate 10% of their retail electricity sales from 

renewable resources by 2015. There are additional renewable energy capacity requirements for 

large utilities above 1 million retail customers, such as Consumers Energy and Detroit Edison, 

which must respectively procure 200 MW and 300 MW by the end of 2013 and 500 MW and 

600 MW by 2015. In addition, the RPS allows utilities to use energy efficiency and advanced 

cleaner energy systems to meet a limited portion of the requirement (DSIRE 2013). 

According to projections, providers are on track to meet the 2015 requirement, with renewable 

generation expected to account for 9% of power supply in 2015 and the remainder to be fulfilled 

with RECs banked from previous years. The first RPS CY in Michigan was 2012, but in 2011, 

electric providers were well positioned to meet the 2012 standard. In 2012, electric providers 

reported a total of 11,501,525 available RECs and 116,570 Advanced Cleaner Energy Credits, 

equivalent to about 4.4% of retail sales (MPSC 2013). 

The Michigan Public Service Commission (MPSC) approved contracts in 2011 and 2013 for new 

wind capacity that have levelized gross costs of $61-$64/MWh and $50-$60/MWh, respectively 

(Engblom 2013). The renewable energy weighted average gross cost of these contracts over the 

life cycle of the systems is $91/MWh.56 

 

56 Renewable energy cost data are based on levelized costs that are provided in the renewable energy contract 

approval process. 
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Based on estimates from DTE Energy and Consumers Energy, from 2008-2012 the rate impact 

from the RPS is approximately 0.3–0.6 ¢/kWh for residential customers (or 2–4%) and 0.1–0.3 

¢/ kWh (or 1–3%) for business customers (Consumers Energy, DTE Energy, and MEGA 2012). 

Utility providers can recover the RPS incremental costs of compliance through MPSC’s approval 

of a monthly surcharge per meter on customers’ bills. Consumers Energy’s surcharge is currently 

52¢ for residential; between 90¢ and $14.40 for small commercial; and between $3.60 and 

$90.00 for large commercial and industrial customers. At the end of 2012, DTE Energy’s 

surcharge was set at the statutory maximum of $3.00 for residential; $16.58 for small 

commercial; and $187.50 for large commercial or industrial (Consumers Energy, DTE Energy, 

and MEGA 2012). Citing lower-than-expected renewable energy project costs, Consumers 

Energy has proposed to eliminate its surcharges as of the July 2014 billing cycle (Consumers 

2013c). 

Minnesota

Minnesota’s RPS requires Xcel Energy (Northern States Power) to obtain 31.5% by 2020, 

including 1.5% solar. Other utilities have separate requirements. Public utilities are required to 

obtain 26.5% renewable energy by 2025, including 1.5% solar. Non-public utilities are required 

to obtain 25% renewable energy by 2025 but do not have a solar requirement (DSIRE 2013). 

In 2012, Northern States Power met the RPS requirement of 13% with 5,637,456 MWh of RECs. 

Northern States Power has generated surplus RECs each year since 2008. The REC bank 

provides them the flexibility to defer the installation of new renewables and use banked RECs to 

comply with RPS obligations (Xcel Energy 2011). 

Of the fourteen utilities that submitted compliance reports, eight stated that complying with the 

RPS has resulted in little or no additional costs, if not slight savings for customers. Northern 

States Power reported that its renewable investments have been cost-effective and actually kept 

prices in 2008-2009 about 0.7% lower than they would have been without renewables. Northern 

States Power calculated the rate impact by determining the difference between the costs of 

implementing and not implementing the RPS, and then by determining the cost difference on a 

¢/kWh basis by dividing the costs by total retail sales (Xcel Energy 2011). 

Six utilities, including Great River Energy (GRE), reported that their efforts to comply with the 

policy are leading to increased costs for customers. GRE found that its wind energy purchases 

increased retail customer bills by about 1.6%, or about $1.50/month for an average residential 

customer (Haugen 2011). 

Missouri

Missouri’s RPS requires IOUs to procure renewable energy or RECs for 15% of electricity sales, 

including 2% from solar by 2021. Municipal utilities and electric cooperatives are not subject to 

the standard. RECs can be used to meet up to 10% of the total obligation and must be generated 

in the CY in which they are retired. In-state renewable energy generation receives a multiplier of 

1.25 compared to out-of-state generation. 
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In 2011, Ameren Missouri, Empire, KCP&L, and KCP&L Greater Missouri Operations (GMO) 

were 100% in compliance with the RES. In 2012, Ameren acquired a total of 319,489 RECs 

under a 15-year PPA with the Pioneer Prairie Wind Farm (Ameren Missouri 2013).

Missouri’s RPS requires IOUs to offer rebates of at least $2/W for customer-sited solar electric 

systems of 25 kW or less beginning in 2010. Systems of 100 kW or less qualify for rebates on 

the first 25 kW of installed capacity (DSIRE 2013). The largest electric utility in the state, 

Ameren Missouri, was expecting to reach the limit on allowable expenditures on renewables by 

the end of 2013, but reached a settlement with state regulators to continue solar rebates to 

customers who install solar systems until expenditures reach $91.9 million (Tomich 2013). Of 

the $91.9 million, $22 million in rebates has already been paid out, helping support about 11 

MW of solar in the state (Tomisch 2013). The Missouri Public Utilities Commission (MPUC) 

can excuse utilities from the RPS if compliance costs exceed standard increases retail electricity 

rates by more than 1% (DSIRE 2013).

Montana

Montana’s RPS requires load serving entities with 50 customers or more to obtain renewable 

energy equivalent to 15% of retail sales by 2015. Utilities that fail to fulfill their requirements 

must pay a penalty of $10/MWh. Alternatively, utilities may seek a short-term waiver from 

compliance. Excess RECs may be carried over for up to two subsequent CYs. Between 2012 and 

2014, public utilities must purchase all the RECs and electricity generated by community 

projects, which are defined as renewable power plants less than 25 MW, majority-owned by 

local people (DSIRE 2013). 

In CY 2011, a total of 691,872 RECs were needed for compliance in Montana. Eligible 

electricity providers retired 694,986 RECs and $481 was paid in ACPs (the lowest amount paid 

in ACPs since the inception of the program). Excess RECs will be carried over for subsequent 

CYs (MT PSC 2012). 

Nevada

Nevada’s RPS requires utilities to obtain 25% of their total electricity sales from renewable 

sources by 2025. The solar carve-out is set at 5% through 2015, but increases to 6% of the 

portfolio requirement starting in 2016. Energy efficiency qualifies as an eligible resource for 

RPS, but is limited to 25% of the requirement in 2013 and 2014, declining over time and 

becoming ineligible to meet targets in 2025 and beyond (DSIRE 2013). 

In addition, NV Energy (formerly Nevada Power and Sierra Pacific Power) is required to retire 

800 MW of coal-fired electric generators by 2020 and acquire 900 MW of power from cleaner 

facilities, including at least 350 MW from renewable energy facilities (DSIRE 2013). The utility 

must issue a request for proposals for 100 MW of generating capacity from new renewable 

energy facilities each year from 2014-2016. The final 50 MW of generating capacity from new 

renewable energy facilities must be operational by 2022. These requirements are separate from 

the 25% RPS requirement, but portfolio energy credits (PECs) associated with these projects can 

apply to meet the RPS requirements (DSIRE 2013). 
91 

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In 2012, both Nevada Power and Sierra Pacific Power exceeded RPS compliance requirements, 

supplying a total of 4,225,710 MWh and 2,317,174 MWh respectively, including energy 

efficiency savings. The estimated total 2013 compliance cost comprised of purchased power, 

REC procurement, and incentives and rebate programs is $273,230,993 and $139,052,000 for 

Nevada Power and Sierra Pacific Power, respectively (NV Energy 2013). This resulted in gross 

RPS costs of $65/MWh for Nevada Power and $60/MWh for Sierra Pacific Power. In Nevada 

Energy’s 2012 integrated resource plan (NV Energy 2012), a long-term avoided cost rate of 

$30/MWh is calculated. If this avoided cost rate is subtracted from the gross RPS costs, the 

resulting costs are $35/MWh and $30/MWh, for Nevada Power and Sierra Pacific Power, 

respectively. 

The bulk of expenses for Nevada Power were for purchased power and REC procurement ($195 

million). Sierra Pacific Power’s spending was more evenly split between purchased power and 

RECs ($77 million), and rebate programs for solar, hydro, and wind ($56 million). 

New Jersey

New Jersey’s RPS requires each electricity provider to procure 22.5% of the electricity it sells 

from qualifying renewables by 2021. There is a solar specific carve-out of 4.1% by 2028 in 

addition to a 1,100 MW offshore wind resource requirement (DSIRE 2013). 

In 2010, public utilities retired a total of 3,627,069 Class I RECs; compliance using RECs was 

nearly 100%, with only one utility paying three ACPs. Class I REC prices were reported at an 

all-time low of $2/MWh by the end of 2010. For the solar target, 123,717 MWh of SRECs were 

retired in 2010 while suppliers paid the solar ACP of $693/MWh for the remaining 47,373 MWh 

(NJ BPU 2011). 

New Jersey’s Office of Clean Energy estimates the total cost of compliance with the 2010 RPS 

was $122 million, with the solar requirement estimated to have cost $109 million. The solar costs 

included $32.8 million of SACP payments, plus more than $76 million in SRECs. The Class I 

requirements are estimated to have cost approximately $11 million. In 2010, the cumulative 

weighted average price of SRECs was $615.50/MWh (The Office of Clean Energy and in New 

Jersey’s Board of Public Utilities 2011).

New Hampshire

New Hampshire’s RPS requires electricity providers to procure 24.8% of retail sales in 2025 

from renewable resources. Of that total, 15% must come from new renewable facilities and 0.3% 

from solar generators. In 2013, ACPs for new renewable requirements are $55/ MWh for electric 

technologies, including solar, and $25/ MWh for thermal (DSIRE 2013). 

For the 2012 CY, the electricity providers were required to procure 3% new renewables and 

0.15% solar. ACPs totaled $9.3 million, equivalent to 260,957 MWh of RECs, or roughly 44% 

of the total estimated requirement (NHPUC 2013). 

According to the New Hampshire PUC (2011), the total cost of compliance (including RECs and 

ACPs) was $18,601,556, with the average cost per kWh of $0.0017, meaning that a typical 

residential ratepayer (using about 500 kWh/month) would pay about 85¢/month (NH PUC 

2011). 
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For regulated utilities, 98% of compliance was met with RECs, and 2% with ACPs. For 

competitive electricity suppliers, 67% of compliance was met with RECs, and 33% with ACPs 

(NH PUC 2011). 

New Mexico

New Mexico’s RPS requires that IOUs have 15% of retail electricity sales from renewable 

energy by 2015 and 20% by 2020. It also requires that the targets be met with diverse resources, 

including 30% wind, 20% solar, 5% other technologies, and 3% distributed generation (by 

2015). Rural electric cooperatives must maintain renewable energy at 5% of retail sales by 2015 

with annual increases at a rate of 1% to 10% in 2020 and beyond. (DSIRE 2013). 

Southwestern Public Service Company (SPS) purchases bundled wind energy from two New 

Mexico wind facilities; the cost of the RECs is estimated at $1.35/MWh, per a settlement 

agreement in SPS’s last base rate case (SPS 2012). SPS calculates the projected cost of RPS 

compliance as the REC cost multiplied by the MWh requirement. For 2014, they estimate the 

cost of compliance for wind generation at $499,709. To calculate the costs bundled solar energy, 

SPS estimates the REC costs at $10/MWh; for other solar facilities, the incremental cost is the 

above-avoided costs (SPS 2012). The total cost of solar for 2014 is projected to be $11,792,771 

(SPS 2012). 

In 2013, SPS is complying with the RPS by entering into three 20-year PPAs for nearly 700 MW 

of wind. If the PPAs are approved, assuming customer use of 800 kWh/month, the retail rate is 

projected to decrease by 60¢ (NM PRC 2013b). 

The New Mexico Public Regulation Commission (PRC) has set a cost cap in order to 

temporarily exempt utilities from meeting the RPS if they spend more than 3% of their gross 

annual revenues on renewables (Stanfield 2013). All three of the state’s IOUs have either 

requested waivers from their total RPS obligations and/or have requested modifications to their 

specific set-aside requirements, in order to remain within the rate impact cap. The Public Service 

Company of New Mexico (PNM) cap is 2.50% and 2.75% in 2013 and 2014, respectively. 

PNM’s cost cap methodology was based on projected revenues for 2013 and 2014 from electric 

charges to retail customers and separately calculated revenue contributions attributable to the 

customers subject to the rate impact cap (PNM 2013). 

North Carolina

North Carolina’s Renewable Energy and Energy Efficiency Portfolio Standard (REPS) requires 

IOUs to supply 12.5% of retail electricity sales from eligible energy resources by 2021. 

Municipal utilities and electric cooperatives must meet a target of 10% eligible energy resources

by 2018.The overall target for renewable energy includes technology-specific targets of 0.2% 

solar by 2018, 0.2% energy recovery from swine waste by 2018, and 900,000 MWh of electricity 

derived from poultry waste by 2014 (DSIRE 2013). 

Progress Energy Carolinas Inc. (PEC) indicated that it will be able to comply with the 2012 solar 

set-aside (0.07% of 2011 retail sales), but will be unable to meet its 2012 swine waste and 

poultry waste set-aside requirements. Utilities in North Carolina jointly filed to have the swine 
93 

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and poultry waste set-aside requirements delayed until 2014; the North Carolina PUC staff has 

agreed with this recommendation (NC PUC 2013). 

RTI International and La Capra Associates, Inc. (2013) calculated the rate impact of REPS 

compared to the conventional portfolio by dividing the difference in total generation costs by 

projected North Carolina retail sales. The result is an estimate of the ¢/kWh impact customers 

can expect to see in their bills as a direct result of REPS. For a typical North Carolina residential 

customer, assuming use of 1,151 kWh of electricity/month, the monthly estimated savings 

amount to almost 50¢ in 2012 and more than $1.00 by 2024 (RTI International 2013).The data 

show that over the 20-year period of REPS, electricity rates are expected to be lower than they 

would have been if North Carolina had continued to use only conventional generation sources, 

resulting in $173 million in generation cost savings compared to the conventional portfolio by 

2026. 

New York

New York’s RPS requires IOUs to procure 30% of electricity sales from renewables by 2015, of 

which 20.7% will be from existing renewable energy facilities, and 1% is expected to be met 

through voluntary green power sales. 

The New York State Energy and Research Authority (NYSERDA), which procures renewables 

for the utilities through its main tier and customer-sited tier programs, requires 10.4 million 

MWh of renewable energy annually in 2015. By the end of 2012, NYSERDA already achieved 

the main tier and customer-sited tier 2015 targets at 47% and 33%, respectively (NYSERDA 

2013a).

The aggregate MWh weighted average award price (RECs only) from the seven Main Tier 

solicitations is $19.25/ MWh. The seventh solicitation, completed in 2011, yielded the highest 

weighted average award price ($28.70/ MWh). The third solicitation, completed in 2008, resulted 

in the lowest award price ($14.75/MWh) (NYSERDA 2013a). Wind power is the predominant 

generating technology in the Main Tier, capturing 1,653 MW of new renewable capacity under 

contract, of which 1,561 MW was in operation at the end of 2012 (NYSERDA 2013a).

NYSERDA conducted a cost-benefit analysis to determine the renewable energy premium 

(incentive cost) and the retail rate impact from the RPS. The renewable energy premium was 

calculated by modeling the costs to construct, operate, and maintain a renewable facility over its

useful life and comparing those costs to revenue streams from the market and other sources, such 

as federal incentive programs. If revenues from renewable sources exceed the costs, the 

investment is cost-effective. Then, the retail rate impact is calculated by dividing the total abovemarket costs (as determined by the premiums paid) by total annual electricity expenditures in 

New York (NYSERDA 2013b). The maximum annual net rate impact of the RPS was 0.12% 

over the study period (2002-2037). Retail rates are expected to decrease by about $23 million 

over the study period compared to a total retail expenditure level of $256 billion for New York 

ratepayers (NYSERDA 2013b).
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Ohio

Ohio’s Alternative Energy Portfolio Standard (AEPS) requires that electricity retailers, excluding 

municipal utilities and electric cooperatives provide 25% of their electricity from alternative 

energy by 2025. Half must come from wind, hydropower, geothermal, and biomass resources. Of 

that 12.5%, 0.5% must come from solar energy. At least half of the renewable energy must be 

generated in-state and energy efficiency qualifies for fulfilling the requirement (DSIRE 2012).

In 2011, the total statewide AEPS compliance obligation net of the solar carve-out was 

approximately 1.3 million MWh, which slightly exceeded the required REC compliance 

obligation. The total solar carve-out obligation, including deficiencies from previous years that 

were rolled forward to 2011, was 42,089 MWh, with nearly 100% of the requirement having 

been satisfied (PUCO 2013).

The Ohio Public Utilities Commission (PUCO) calculated the weighted average REC cost for 

electric distribution and electric service companies based on the information provided in the 

utilities’ 2011 compliance reports (see Table 18).57 

Table 18. The Weighted Average Cost/REC for Ohio’s Electric Distribution Utilities and Electric 

Service Companies in 2011

Category Electric Distribution Utilities

(average $/REC)

Electric Service Companies

(average $/REC)

Ohio Solar 228.7 307.7

Other Solar 157.8 148.1

Ohio Non-Solar 110.5 20.8

Other Non-Solar 19.4 5.97

Source: PUCO 2013

Several utilities recover administrative costs and the cost of REC purchases through an 

alternative energy resource rider (AER-R) on customer bills, which may not exceed 3% of retail 

rates. PUCO’s cost cap methodology consists of comparing incremental costs (not including 

ACPs which utilities cannot recover from ratepayers) to “reasonable expected costs of 

generation,” which may not necessarily include the net retail revenue requirement, depreciation, 

tax gross-up, and a rate of return (Stockmayer et al. 2012, p. 157). Utilities may not count 

construction or environmental expenditures of generation resources that are passed on to 

consumers through a surcharge against the 3% cap (Stockmayer et al. 2012). In 2012, the RPS 

monthly surcharge for residential customers was $5.76 and $0.77 for FirstEnergy (Ohio Edison, 

Cleveland, Toledo Edison) and Dayton Power & Light, respectively (DP&L 2011; Ohio Edison 

2011; Cleveland Electric Illuminating Co. 2011; Toledo Edison Company 2011). 

In 2013, PUCO studied the changes in wholesale electricity prices and generator emissions that 

are likely to occur as a result of the AEPS. In the scenario which only includes operational 

projects, wholesale electricity prices are estimated to be reduced by approximately 0.15% in 

2014 (PUCO 2013). 

 

57 Compliance markets continue to evolve, so prices provided in Table 19 should not be interpreted as 

indicative of current market prices.
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Oregon

Oregon’s RPS requires the largest utilities to supply 15% of their retail electricity sales from 

renewable sources by 2015, 20% by 2020, and 25% by 2025. In addition 20 MW-AC of solar PV 

systems (sized 500 kW to 5 MW) must be installed by 2020. Utilities with less than 1.5% of state 

load must meet a 5% RPS, while utilities with 1.5% to 3% of state load must meet a 10% RPS by 

2025. However, utilities that buy into or sign a contract for new coal power are subject to the 

“large utility” standards. At least 8% of Oregon’s retail electrical load will come from smallscale renewable energy projects with a capacity of 20 MW or less by 2025 (DSIRE 2012). 

Oregon’s two largest utilities, PacifiCorp and Portland General Electric Company (PGE), have 

met 100% of the 2011 RPS compliance obligations. In 2011, PacifiCorp reported 650,729 MWh 

of banked RECs that were used to meet the RPS. At the end of 2011, PacifiCorp owned 1,031 

MW of wind-powered generation capacity and had entered into PPAs for the output from 749 

MW of wind capacity (Pacific Power 2012). 

For CY 2012, PGE reported that it would meet the RPS with 140,800 unbundled RECs.58 PGE’s 

projected annual revenue requirement is $1,709,111,606 and the total cost of RPS compliance for 

CY 2012 is $3,859,811. The cost of compliance as a percentage of the revenue requirement is 

0.23% (PGE 2013). PacifiCorp calculated the incremental cost of compliance at -.60% for 2011, 

meaning that the RPS lowered costs (Pacific Power 2012).

The Oregon PUC established the ACP at a rate of $50/MWh for 2011. In addition, there is a rate 

impact cap. If compliance costs exceed 4% of the utility’s annual revenue requirement for a CY, 

electric utilities are not required to fully comply with the RPS during that year (DSIRE 2012). 

Pennsylvania

Pennsylvania’s Alternative Energy Portfolio Standard (AEPS) requires electric distribution 

companies and electric generation suppliers to supply 18% of electricity using alternative energy 

resources including energy efficiency measures by 2021. A solar requirement of 0.5% is 

included in the Tier I requirement under the same schedule. For non-solar resources, the ACP is 

fixed at $45/MWh. Solar ACPs are calculated as 200% of the sum of the average cost for solar 

Alternative Energy Credits (AECs) plus the levelized value of non-Pennsylvania upfront rebates 

for solar PV systems (DSIRE 2012; PPUC 2013). 

For CY 2012, the AEPS requirement was 0.0325% for solar, 3.4675% for non-solar Tier I 

resources, and 6.2% for Tier II. The average price of unbundled AECs for solar was $180.39, 

$5.23 for non-solar Tier I resources, and $0.17 for Tier II. In total, the annual compliance 

requirement was 13,877,487 MWh, fulfilled by Load Serving Entities (LSEs) at an estimated 

total cost of $35,867,115.59 In CY 2012, no ACPs were required. The three main technologies 

used to generate Tier I AECs in CY 2012 were wind, wood and solid biomass, and black liquor 

gasification, which contributed with 50%, 12%, and 11% of the total retired AECs, respectively. 

 

58 The total cost of bundled RECs was redacted due to the proprietary nature of information.

59 The average AEC price for each tier was used in this estimate, even though average prices were calculated by 

PPUC using only data from the subset of AECs for which there was a known price.
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Pumped-storage hydropower was used to generate 65% of the retired Tier II AECs in CY 2012, 

followed by waste coal, with 16.5% (PPUC 2013). 

Rhode Island

Rhode Island’s RES requires the state’s retail electricity providers to supply 16% of their 

electricity sales from renewable resources by the end of 2019. The requirement began at 3% at 

the end of 2007, and then increases an additional 0.5%/year through 2010, 1%/year from 2011 

through 2014, and 1.5%/year from 2015 through 2019. Aside from the RES, “The Long-Term 

Contracting Standard for Renewable Energy” requires electric distribution companies enter into 

long-term contracts for 90 MW in capacity by 2014 from new renewable energy facilities, of 

which 3 MW must come from in-state solar facilities (DSIRE 2013). 

In CY 2011, the statewide RES was met with 27.3% biomass, 12.2% wind, and 5.0% hydro 

resources. Seventeen entities had Rhode Island RES obligations and a total of 201,129 MWh

were retired for RES compliance. A total of 84,402 MWh or 29.6% valued at $5,243,896 of RES 

compliance was met with ACPs at a rate of $62.13/MWh (PUC 2011). 

Narragansett Electric incurred costs of $8.43 million to meet the 2001 new and existing RES 

obligations. In 2010, the RES charge was .00123¢/kWh representing a rate impact of 62¢/month 

for an average residential payer. As of April 2011, the RES charge turned into a bill credit of 

.00031¢/kWh or approximately .15 ¢/month (PUC 2011). In 2012, the average annual RES 

charge was estimated to be .00182¢/kWh, resulting in a rate impact of $1.08/month. 

Texas

Texas’s RPS requires all municipally-owned utilities, generation and transmission cooperatives, 

and distribution cooperatives that offer customers a choice of retail providers; retail electric 

providers (REPs); and IOUs that have not been unbundled under deregulation to acquire a total 

of 5,880 MW of renewable energy resources by 2015 (about 5% of the state’s electricity 

demand), including a target of 500 MW of renewable energy capacity from resources other than 

wind, and 10,000 MW by 2025 (DSIRE 2013).

Renewable energy generation totaled 29.9 million MWh in 2013, with wind accounting for 28.9 

million MWh (ERCOT 2014). In CY 2012, the total RPS requirement for all retail entities, after 

adjustments for previous true-ups as required by the Texas Public Utility Commission (PUCT), 

was 12,119,614 RECs (PUCT 2012). 

As of 2012, Texas penalizes entities $50/MWh if a utility falls short of compliance with the RPS 

targets (Stockmayer et al. 2012). However, with over 12,000 MW of renewable generation 

capacity, Texas has exceeded its goal of 10,000 MW by 2025. 

Washington 

Washington’s RES requires all electric utilities that serve more than 25,000 customers to obtain 

15% of their electricity from new renewable resources by 2020 and pursue “cost-effective” 

energy conservation (DSIRE 2013). 
97 

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

In CY 2012, Puget Sound Energy (PSE) met initial 2012 RES requirements of 3% with more 

than 635,958 RECs and could already potentially reach the 9% 2016 goal if it uses its excess 

RECs. According to the utility’s 2012 compliance report, the incremental costs of eligible 

renewable resources were $27.83 million (PSE 2012). PacifiCorp plans to pursue compliance in 

through the purchasing of RECs while PSE and Avista have developed new renewable energy 

generation resources and are purchasing RECs. All three IOUs have met the 2012 target. 

The incremental cost of a renewable resource is defined as the difference between the levelized 

cost of the renewable resource compared to an equivalent non-renewable resource. PSE’s 

calculation of the cost of non-renewable resources included capacity cost, energy cost, and 

imputed debt. If the incremental cost is greater than 4% of its revenue requirement, as 

established by the Washington UTC, then a utility will be considered in compliance with the 

RES.

The Renewable Northwest Project and NW Energy Coalition found a lack of consistency in the 

incremental cost calculations employed by the three utilities (Stanfield 2013a). The costs of 

compliance, as reported by the utilities in 2012, were $15.73/MWh for PacifiCorp, $20.35/MWh 

for Avista, and $43.76/MWh for PSE. These costs made up the following portions of the revenue 

requirements for each utility: 0.61% 0.80%, and 1.36% respectively. The Washington UTC is

addressing cost standardization as it considers revisions to its RPS rules (Docket UT-131723). 

Wisconsin

Wisconsin’s RPS has a goal of 10% of all electric energy consumed in the state to be supplied by 

renewable energy by the end of 2015 (Wis. Stat. § 196.378). Each electric provider in the state 

has its own RPS requirement, ranging from 6.64% to 22.47%, depending on how much 

renewable electricity it provided in 2003 (PSCW 2013). Collectively, utilities in Wisconsin had 

met three-quarters of the 2015 RPS requirement by 2010. Also, all 118 electric providers met 

their individual 2010 RPS requirement (PSCW 2012). 

In 2012, the Public Service Commission of Wisconsin (PSCW) estimated the costs of statewide 

RPS compliance to be between 1% and 1.1% of the utilities’ revenue requirements for calendar 

years 2008 through 2010. Using two similar methods, the PSCW compared the levelized cost of 

electricity produced by the renewable energy sources added after the enactment of the state’s 

RPS with the marginal cost of energy in the Midwest regional energy market (PSCW 2012).