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

Contract No. DE-AC36-08GO28308

Distributed Solar Incentive 

Programs: Recent Experience 

and Best Practices for Design 

and Implementation

Lori Bird, Andrew Reger, and Jenny Heeter

National Renewable Energy Laboratory

Technical Report

NREL/TP-6A20-56308

December 2012
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Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

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Contract No. DE-AC36-08GO28308

Distributed Solar Incentive 

Programs: Recent Experience 

and Best Practices for Design 

and Implementation 

Lori Bird, Andrew Reger, and Jenny Heeter

National Renewable Energy Laboratory

Prepared under Task No. SM12.1030

Technical Report

NREL/TP-6A20-56308

December 2012
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iii

Acknowledgments

The authors would like to thank Rachel Tronstein of the U.S. Department of Energy Solar 

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

following individuals for their thoughtful review: Rick Gilliam, VoteSolar; Joseph Wiedman, 

Interstate Renewable Energy Council (Keyes, Fox & Wiedman LLP); Eran Mahrer, Solar 

Electric Power Association (SEPA); Steven Hammer, Massachusetts Institute of Technology; 

John Stanton, SolarCity; Holly Gordon, SunRun; Melicia Charles, California Public Utilities 

Commission; Dana Levy, Frank Mace, Christine Gifford, Sarah Osgood, Carl Mas, and Alison 

Neligan of NYSERDA as well as Jason Coughlin, Karlynn Cory, Jeffrey Logan, Robin 

Newmark, and Elizabeth Doris of the National Renewable Energy Laboratory (NREL). We also 

wish to thank Mike Meshek of NREL for editorial support. The authors retain responsibility for 

any remaining errors and omissions and for the findings of this report. Finally, we wish to thank 

the following individuals for providing information about utility solar power programs that was 

invaluable to the preparation of this report: 

• Erik Anderson and Jason Zappe, Pacific Power (Oregon and Utah programs) 

• Adam Browning, Vote Solar Initiative

• Amanda Bybee, Vice President, Namaste Solar

• Melicia Charles, James Loewen and Molly Sterkel, California Public Utilities 

Commission (California Solar Initiative) 

• Carrie Cullen-Hitt, Solar Energy Industries Association

• David Felix, Salt River Project

• Dana Levy and Frank Mace, New York State Energy Research and Development 

Authority (NYSERDA) 

• Eran Mahrer, Solar Electric Power Association 

• Rebecca O’Neil, Oregon State Department of Energy 

• Susannah Pedigo, Xcel Energy 
iv

Executive Summary

Dozens of utilities1 throughout the United States offer incentive programs designed to encourage 

the adoption of solar energy, and the number has been growing as utilities respond to state solar 

mandates or internal goals. Rapidly changing market conditions in the past several years have 

made implementing solar power programs challenging. Various design and implementation 

methods have emerged as utilities or other program administrators have modified programs to 

respond to market changes, such as declining solar costs, increasing customer demand, and new 

business models. 

Based on lessons from recent program experience, this report explores best practices for 

designing and implementing incentives for small and mid-sized residential and commercial 

distributed solar energy projects. The findings of this paper are relevant to both new incentive 

programs as well as those undergoing modifications. The report covers factors to consider in 

setting and modifying incentive levels over time, differentiating incentives to encourage various 

market segments, administrative issues such as providing equitable access to incentives and 

customer protection. It also explores how incentive programs can be designed to respond to 

changing market conditions while attempting to provide a longer-term and stable environment 

for the solar industry. The findings are based on interviews with program administrators, 

regulators, and industry representatives as well as data from numerous incentive programs 

nationally, particularly the largest and longest-running programs. These best practices consider 

the perspectives of various stakeholders and the broad objectives of reducing solar costs, 

encouraging long-term market viability, minimizing ratepayer costs, and protecting consumers. 

Setting and Managing Incentive Levels

• Rebates coupled with performance guarantees can help incentivize small customerowned systems by addressing barriers related to upfront costs. 

• Performance-based incentives (PBIs) that are paid based on system output and credited 

on customer bills can be effective for commercial-scale and third-party owned systems. 

PBIs can minimize upfront impacts on program budgets by spreading incentive costs over 

several years. 

• Appropriate incentive levels can be assessed by benchmarking against programs in 

neighboring states or service territories, using multiple data sources on installed costs, 

and limiting capacity offered in early stages of the program to test uptake rates. 

• Pre-determined schedules for reducing incentives in multiple steps can establish a path 

for reducing incentive levels that provides market transparency, simplicity, and certainty 

for market participants, although they may not continuously align with market conditions. 

• Competitive procurement mechanisms or auctions allow for market-based pricing, which 

can be important in an environment with rapidly changing pricing. These can be 

particularly important for large systems that require substantial incentive payments and 

can have cost considerations that vary by size. Auctions can also be extended to smaller 

 

1 In some cases, these programs are administered by independent organizations, but in most of the programs we 

examined, utilities were responsible for implementation. This report addresses distributed solar incentive programs

broadly, whether implemented by utilities or other entities.
v 

commercial systems if simplified processes are used -- at least one utility has used 

auctions for dispersing incentives to all commercial systems. 

• Encouraging various market segments can be important for ratepayer considerations, grid 

benefits, market diversity, building support for the program, and balancing program 

costs. Multiple approaches may be required to encourage a diversity of systems because 

the costs and financing of systems vary substantially by size. For example, rebates or 

PBIs with pre-established step-down levels may be appropriate for small- to mediumsized systems. Competitive solicitations or auctions can be used to achieve market-based 

pricing for commercial systems or larger systems. 

• Differentiating incentives can encourage systems to be sited in areas where they are most 

beneficial to the grid or to establish comparable incentives when solar resources vary. 

Administrative and Consumer Protection Issues 

• Consumer protection measures can encourage reputable business practices that help 

ensure the long-term viability of the solar industry. These can include ensuring optimal 

system performance through equipment, installer, or system requirements; encouraging 

consumers to explore energy efficiency; and protecting customers from price gouging.

• Ensuring equitable access to incentives requires fair queuing processes, particularly for

programs with modest budgets that are not able to fully meet demand. 

• While multi-year programs provide greater market stability, annual programs can use 

multiple offer periods throughout a year to increase market stability and program 

flexibility. Multiple offers can allow a utility to adjust incentive levels according to 

program uptake and market conditions, as necessary. 

• Transparency and up-to-date communications are important to enable customers to 

evaluate projects, particularly in programs that reduce incentives when program 

thresholds are met. 
vi 

Table of Contents

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

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

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

2 Key Elements to Incentive Program Success ................................................................................... 3

3 Capacity-based Rebates versus Production-based Incentives....................................................... 5

3.1 Capacity-based Rebates................................................................................................................... 5

3.2 Performance-based Incentives (PBIs).............................................................................................. 6

3.3 Program Budgetary Considerations................................................................................................. 9

4 Establishing the Incentive Level and Designing the Program....................................................... 11

4.1 Targeting Payback Periods and Return on Investment .................................................................. 11

4.2 Assessing Solar Costs and Benchmarking..................................................................................... 12

4.3 Incentivizing Different Market Segments...................................................................................... 13

4.4 Establishing Rebate and PBI Levels.............................................................................................. 14

4.5 Establishing Incentive Limits per Installation ............................................................................... 17

5 Differentiating Incentive Levels ........................................................................................................ 18

5.1 Differentiating Incentives for Third-Party Owned Systems .......................................................... 18

5.2 Differentiating incentives for Grid Benefits .................................................................................. 19

5.3 Differentiating Incentives based on Expected Solar Radiation...................................................... 19

6 Managing Incentives and Responding to Market Conditions ........................................................ 21

6.1 Setting Incentive Decline Schedules.............................................................................................. 21

6.2 Employing an Auction Mechanism or Competitive Solicitation ................................................... 27

6.3 Transitioning to a Post-Incentives Environment............................................................................ 29

7 Administering the Program and Application Process.................................................................... 30

7.1 Ensuring Equal Access to Available Incentives ............................................................................ 30

7.2 Charging a Nominal but Consequential Application Fee .............................................................. 31

7.3 Managing Project Flow and Incentive Offer Periods..................................................................... 31

7.4 Requiring Inspections and Ensuring Proper System Design and Implementation......................... 32

7.5 Administering PBI Payments......................................................................................................... 33

8 Consumer Protection and Transparency......................................................................................... 35

8.1 System Performance ...................................................................................................................... 35

8.2 Installed Cost Transparency and Price Protection ......................................................................... 38

8.3 Encouraging Energy Efficiency First............................................................................................. 38

8.4 Ownership of Renewable Energy Certificates (RECs).................................................................. 39

9 Best Practices for Incentivizing Solar.............................................................................................. 40

References................................................................................................................................................. 43

Appendix. Solar Incentive Programs Analyzed ..................................................................................... 48
vii 

List of Figures

Figure 1. California Solar Initiative: Trends in third–party owned systems .......................................... 8

Figure 2. Rebate versus PBI: Budgetary comparison........................................................................... 10

Figure 3. Residential rebate programs as a portion of installed cost of solar....................................... 15

Figure 4. Present value of PBI payments as portion of installed cost of solar ..................................... 16

Figure 5. Pacific Power commercial rebate levels and budget............................................................. 22

Figure 6. California Solar Initiative’s Upfront Incentive Program step-down and budget (for Expected 

Performance Based Buydown program)........................................................................................ 24

Figure 7. Incentive decline schedules: Pacific Power, PNM, LADWP................................................ 25

List of Tables

Table 1. Selected Residential Rebate Programs..................................................................................... 6

Table 2. Selected Residential PBI Programs.......................................................................................... 7

Table 3. Solar Incentive Programs' Treatment of Third-party Owned Systems................................... 19

Table 4. Oregon Solar Incentive Program: PBI Variation by System County ..................................... 20

Table 5. Arizona Public Service’s Residential Incentive Step-Down Schedule................................... 26

Table 6. NYSERDA Monthly Incentive Budget (2012–2015) ............................................................ 26

Table 7. California Solar Initiative’s Application Fee Schedule.......................................................... 31

Table 8. PBI Programs, Length of Program and Incentive Disbursement Method.............................. 34

Table 9. Utility PV Program System Performance Requirements ....................................................... 36

Table A-1. Residential Incentive Programs.......................................................................................... 48

Table A-2. Commercial Incentive Programs........................................................................................ 52

List of Text Boxes

Text Box 1. Arizona Public Service Company's Reverse Auction Program........................................ 28
1 

1 Introduction

In recent years, the number of utilities across the country offering incentives to encourage 

customers to adopt solar power has grown substantially. Often this is because utilities are 

required to meet solar energy mandates or generation targets—16 states and Washington D.C. 

have adopted specific targets for new solar capacity or distributed generation as part of their 

renewable portfolio standards (RPS), while California has a separate solar initiative. In other 

cases, utilities have voluntarily encouraged the adoption of solar energy or established incentive 

programs to meet internal clean energy goals. While solar photovoltaic (PV) system costs are 

rapidly falling, costs for distributed systems are still above retail rates in most jurisdictions, and 

require incentives to support customer adoption. 

Rapidly changing market conditions in the past two or more years have made implementing 

incentive programs challenging. In fact, programs have had difficulty keeping up with market 

demand and changes in the cost of solar. Solar installed costs have declined from $7/watt in the 

first quarter of 2010 to less than $6/watt in the first quarter of 2012 for residential systems 

nationally, while nationally nonresidential systems have dropped from just under $6.50/watt to 

nearly $4.50/watt over the same period (SEIA/GTM Research 2012). Furthermore, new business 

models have emerged, most notably residential third-party ownership models (through leasing or 

power purchase agreements) that remove the up-front capital cost hurdles for small systems and 

typically cost the same or less than the electricity otherwise purchased from the local utility. 

Under the leasing model, customers lease solar equipment from a company, while under a power 

purchase agreement (PPA) model customers purchase a system's output. In either case, the thirdparty retains ownership of the system and responsibility for maintenance. Residential third-party 

ownership is growing rapidly in several states (SEIA/GTM Research 2012). 

Because of changing market conditions, utilities and administrators have significantly modified 

existing incentive programs to respond to declining solar costs, increasing customer demand, and 

new business models. Some experimentation has occurred, and a number of programs have made 

substantial shifts over the course of several years to address the rapidly changing marketplace. In 

some cases, programs have been halted while a new course for the program was established—an 

approach that can be problematic for the continuity of the solar industry. Modifications made by 

program administrators have included altering incentive levels or introducing market-based 

mechanisms for pricing, changing the form of the incentive for certain classes of systems, and 

refining mechanisms for queuing customers to address high demand periods. 

Earlier assessments of PV incentive options have focused on how the choice of incentive 

mechanism—capacity-based rebates or performance-based incentive payments—can effect 

program budgets and demand for residential or commercial systems (Hoff 2006). Rebates cover 

part of the upfront cost of systems, while performance-based incentives are paid over time based 

on system output. Other work has focused on the need to ensure system performance when 

designing PV incentive programs to ensure optimal system output (Barbose et al. 2006), and on 

the importance of net metering and interconnection policies for solar (Fox and Varnado 2010). 

This report builds on earlier studies and explores best practices for designing and implementing 

solar incentives for distributed residential and commercial solar projects, based on lessons from 
2 

recent utility experience.2 The findings of this paper are relevant to both new solar incentive

programs as well as those undergoing modifications. While several utility solar programs in the 

West are in the late stages of implementation and incentive levels are nearing zero, new 

programs are being launched or expanded in other areas, for example in New York, Connecticut, 

and Utah. In addition, many existing programs are being substantially revised. 

The report covers factors to consider in setting and modifying incentive levels over time, 

differentiating incentives to encourage various market segments, providing equitable access to 

incentives, and protecting customer interests. It also explores how incentive programs can be 

designed to respond to changing market conditions while attempting to provide a longer-term 

and stable environment for the industry. The findings are based on information regarding 

implementation experience from interviews with program administrators, regulators, and 

industry representatives as well as data from incentive programs nationally, particularly the 

largest and longest-running programs. 

 

2 This report does not address incentives for utility-scale projects, nor does it cover incentives in markets where 

there is solar REC trading because of the different characteristics of those markets. A review of solar REC markets 

is available in Bird et al. (2011).
3 

2 Key Elements to Incentive Program Success

The goal of solar incentive programs is generally to increase the amount of solar power in a 

utility’s generation mix; however, the relative success of the program can be interpreted in 

different ways by various stakeholders. A utility may choose to implement a program to meet 

voluntary objectives for solar installation, or more commonly, to meet compliance with solar 

carve-outs in state renewable portfolio standards or other state mandates, such as the California 

Solar Initiative (CSI), which was introduced in conjunction with California's Million Solar Roofs 

Program. Another objective could be to encourage the installation of solar in areas where there is

congestion on the electrical grid or where solar can provide other grid benefits. From the 

perspective of other key stakeholders, a successful program will reduce solar costs, encourage 

long-term solar market viability, minimize ratepayer cost, and provide consumer protection and 

transparency. This paper examines best practices for implementing solar incentive programs in 

light of these various factors. 

Reducing Solar Costs: The large up-front cost of solar has historically been one of the largest 

impediments to residential solar gaining greater market penetration. To drive down these costs, 

the solar industry needs to achieve sufficient volumes to reduce equipment and installation costs. 

An incentive program can play a direct role in encouraging cost reductions for installers by 

increasing the number of solar installations over which operational fixed costs can be spread. 

Also, variable costs can be reduced through both efficiencies of scale and installation practices 

that can be realized as an installer’s workforce gains experience. In addition to incentives, the 

availability of net energy metering, fair interconnection policies, and utility rate structures are

important for the economics of solar energy projects.3

 Today, net metering is available in most 

(if not all) utility service territories where solar incentive programs are in place.4

 

Encouraging Long-Term Solar Market Viability: For incentive programs seeking to help 

permanently drive down the cost of solar, important considerations are program longevity, 

stability, and predictability. Short-term boosts to the market may be insufficient for installers to 

gain efficiencies of scale to drive down costs. However, incentive programs have not always 

provided solar markets with stability or longevity. The renewable energy market, in general, has 

experienced substantial variability in installation rates and levels, and solar incentives have in 

some cases contributed to and responded to these cycles.

5

 A long-term perspective can help 

achieve both the utility’s desired increase in solar generation to meet its near-term goals and help 

 

3 For example, see Solar Alliance “The Four Pillars of Cost Effective Solar Policy” http://www.frontpagepr.com/

powerpoint/Tom%20Alston%20-%20Solar%20Alliance%20Four%20Pillars%20of%20Solar%20Success.pdf, 

accessed December 7, 2012.

4 See DSIRE for additional information on where net metering is offered, 

http://www.dsireusa.org/summarytables/rrpre.cfm, accessed December 7, 2012. 5 For example, several programs have sold out rapidly and have been placed on hold until further funds are 

available. Others have been modified midstream. For example, Xcel Energy altered its Solar Rewards incentive 

program in early 2011 by reducing its incentives, and then shifted its program from a rebate to a PBI program. 

Subsequently, residential installations in Colorado saw a 25% decrease in capacity in 2011 compared to 2010. 

(SEIA/GTM Research 2012). On April 8, 2011, LADWP suspended its solar program after receiving $112M in 

rebate requests, when it had only a $30M budget for the year. (http://www.ladwpnews.com/go/doc/1475/1061811/) 

The program stayed closed until September 1, 2012 (5 months closed), when it reopened and received requests for 

3.25 MW of capacity in its first week of reopening. (http://www.ladwpnews.com/go/doc/1475/1187095/) 
4 

the solar installer community develop in a sustainable fashion that will lead to decreases in the 

installed costs of solar.

Minimizing Ratepayer Costs—When designing a program, it is important to consider the 

interests of the ratepayers who typically fund incentive programs. For ratepayers, the costeffectiveness of the program is an important metric of program success. Program costeffectiveness can be achieved by 1) managing the administrative costs of the program effectively 

and 2) setting an appropriate level of incentives so that the program does not overpay for solar 

development, therefore, maximizing the amount of installed solar capacity per the available 

program funding. Equity among rate classes is another consideration. Programs funded by both 

residential and commercial ratepayers may need to support both residential and commercialscale solar projects to achieve equity among contributors. 

Providing Consumer Protection and Transparency—A utility or entity offering a solar incentive 

program is uniquely positioned to help set industry standards and institute consumer protections. 

Consumer protection measures typically involve helping ensure system performance, but they 

can also relate to helping a customer purchase an appropriately sized system at a fair price. 

Instituting standards designed to ensure optimal system performance protects the interests of 

consumers who want to maximize production to recoup their costs for the system; the utility, 

which is often interested in maximizing system energy production to meet renewable energy 

goals; and the ratepayers who fund incentive programs. 
5 

3 Capacity-based Rebates versus Production-based 

Incentives

To stimulate solar market adoption and diminish the up-front capital costs of solar power, 

utilities have often developed incentive programs designed to bridge the gap between the retail 

rate of electricity and the cost of solar by 1) providing an up-front rebate to a developer (or 

system owner) based on the system capacity or expected production or 2) offering a 

performance-based incentive (PBI) based on the actual measured electrical production of the 

system over time (Hoff 2006). This section explores the benefits and tradeoffs of using rebates 

and PBIs as well as recent experience with these mechanisms. 

3.1 Capacity-based Rebates

Rebates are often used primarily for smaller systems, for which upfront costs have historically 

been of greatest concern. Rebates vary by the incentive payment offered, the eligible project size, 

and the maximum payment available per project. 

Over the past decade, solar rebate programs in the United States have dramatically reduced 

available incentive levels. In 2003, residential incentive levels offered in distributed solar 

programs generally ranged from $4-$6/watt, and by 2008, the average available rebate incentive 

had dropped to roughly $3.50/watt. (Bolinger and Wiser 2003; Lantz and Doris 2009) Today, 

residential incentive levels have declined further and currently range from $0.20-$2.25/watt (see 

Table 1). 6 Table 1 presents a selected list of rebate programs representing a range of incentive 

levels, system sizes, location, and utility type. A full listing of the solar incentive programs 

analyzed for this paper can be found in the appendix. Rebates are as low as $0.20/watt in 

California and Arizona, where incentive programs have been stepping down payment levels as 

solar capacity is installed. In most other regions, utility program incentive levels are often in the

range of $1.50- $2/watt, and sometimes above. Of course, rebate level also depends on electricity 

prices and the solar resource in the region, among other factors. 

Incentives are available for a wide range of system sizes. For example, Gulf Power limits rebates 

to systems less than 5 kilowatts (kW) while Los Angeles Department of Water and Power 

(LADWP) rebates are available for systems of up to 1 megawatt (MW). 

 

6 Some utilities, as shown for Austin Energy, Pacific Power and Pacific Gas & Electric in California below, offer 

their rebate incentive on an AC, as opposed to DC-basis, to minimize conversion losses and encourage the use of 

efficient inverters. In some cases, the incentive level may be adjusted for system orientation and shading as well (see 

Section 8.1).
6 

Table 1. Selected Residential Rebate Programs

Program Administrator Rebate Maximum Payment Eligible System 

Size

Austin Energy $2.00/watt AC $15,000 1 kW – 20 kW

Gulf Power $2.00/watt $10,000 < 5 kW

Long Island Power Authority $1.75/watt $17,500 or 50% < 10 kW

LADWP $1.62/watt 75% 1 kW – 1,000 kW

NYSERDA $1.50/watt $10,500 or 40% <7 kW

Pacific Power (CA) $1.13/watt AC 1 kW – 5,000 kW

Arizona Public Service $0.20/watt $75,000 or 50% < 30 kW

Pacific Gas and Electric Company $0.20/watt AC < 30 kW

Data derived from program websites and DSIRE

Rebates and System Performance

Rebates incentivize the installation of capacity only, as opposed to actual electricity production. 

As a result, a concern for rebate programs has been sub-optimal system performance based on 

either improper installation techniques or inadequate operation and maintenance of the system 

after installation, or some combination of both. This is a concern for utilities that rely on the 

output of incentivized systems to meet solar generation targets under an RPS. It is also a concern 

for ratepayers who support the incentive program, as it is in their best interest to maximize the 

output of the installed systems. 

Many utility programs address performance concerns under capacity-based incentive programs 

by instituting pre-requirements that proposed systems must meet to qualify for available 

incentives. Performance requirements for modules and inverters often include a listing by 

Underwriters Laboratories (UL listed); meeting minimum equipment warranties; and 

certification and proper licensing of installers. Many programs also provide reduced incentive 

payments if a system is shaded or sub-optimally oriented, or may exclude eligibility altogether if 

expected performance thresholds are not met. To enforce compliance with performance 

requirements, most utilities will conduct a site inspection of the system. Methods that utilities use 

to inspect systems and encourage optimal system performance are discussed further in Sections 

7.4 and 8.1. 

3.2 Performance-based Incentives (PBIs) 

One way to encourage optimal system performance is to offer incentives based on actual 

electrical production of the system. Several utilities offer PBIs, providing payments (typically in 

dollars per kilowatt-hour [$/kWh]) to a system owner over a certain period—anywhere from 5 to 

15 years (up to 20 years for some commercial programs). PBI payments range from $.02/kWh to 
7 

$.41/kWh for residential systems with varying contract terms (see Table 2). PBIs are also used 

for a variety of system sizes, ranging from less than 10 kW up to 2 MW.

Table 2. Selected Residential PBI Programs

Utility PBI Length Eligible System 

Size

PacifiCorp (OR) $0.411/kWh 15 years < 10 kW

Portland General Electric (OR) $0.285/kWh 15 years 10 kW – 100 kW

Madison Gas and Electric (WI) $0.250/kWh 10 years < 10 kW

Xcel Energy (CO) $0.150/kWh 10 years 0.5 kW – 10 kW

Sacramento Municipal Utility District (SMUD) $0.100/kWh 5 years No limit

Green Mountain Power $0.060/kWh 10 years < 250 kW

Orlando Utilities $0.050/kWh 5 years < 2 MW

Southern Cal Edison (CSI) $0.044/kWh 5 years < 100 kW

PG&E (CSI) $0.025/kWh 5 years < 100kW

Public Service New Mexico $0.020/kWh Ends 12/2020 100 kW – 1,000 kW

Data derived from (Database of State Incentives for Renewables & Efficiency)

System size and ownership structure are important considerations for PBI programs. For 

financial reasons, they have most commonly been offered for non-residential systems in the past, 

although they are increasingly being used for residential and smaller systems. The major 

consideration for their use to incentivize small systems is whether they are sufficient to address 

the hurdle of the initial capital outlay necessary to purchase a new system, which is a concern 

particularly for small customer-owned systems. PBIs, which provide only a set of future 

payments to the system owner and do not directly address upfront investment, may not be 

sufficient to drive substantial installations of residential or small commercial customer-owned 

solar systems. They can be effective, however, in driving third-party owned systems. 

Developers of larger systems or companies that own larger portfolios of systems are often more 

financially sophisticated than residential customers. Consequently, large system developers are 

better able to evaluate the discounted present value of a PBI’s future cash flows, and are better 

equipped to finance and depreciate a solar system’s up-front investment in a way residential 

customers generally do not. In addition, they can also utilize accelerated depreciation tax 

benefits, which are not available to residential customers.

Third-party Owned Systems

Third-party owned systems—through a either a PPA or lease7

—are more likely able to accept 

PBI payments than residential customer-owners who are more concerned with reducing the 

 

7 Solar leases and PPA agreements are similar in concept but differ contractually. A PPA agreement involves a sale 

of electricity from the third-party owner of the system to the entity hosting the system. Solar lease agreements 

involve leasing of equipment, whereby the leasing company retains ownership of the solar system in exchange for 

monthly lease payments from the customer for the energy produced by the system. The lessee will realize cost 

savings upon leasing a system if the lease payments minus any incentives or net metering benefits results in a lower 
8 

initial cost of purchasing a system. A third-party owned system is managed as a portfolio by the 

company retaining ownership, and can be financed like a larger system, though the introduction 

of financing costs may necessitate higher internal rate of return requirements if the third-party 

system owner must raise tax equity or other investor capital. 

The rapid expansion of third-party ownership models in residential markets (leasing and PPAs)

have the potential to expand the use of PBIs for residential systems. In California, third-party 

owned installed capacity surpassed direct ownership installed capacity for the first time in Q4 

2011, and has continued to increase (Figure 1). In Colorado, the percentage of third-party owned 

systems applying for Xcel Energy’s incentive program increased from zero in March 2010 to 

approximately 80% in March 2012 (SEIA/GTM Research 2012). Third-party owned systems are 

not allowed by law in some states, however, because such ownership arrangements can be 

considered to involve the sale of electricity by a non-utility (Kollins, Speer, and Cory 2010).8

 

Figure 1. California Solar Initiative: Trends in third–party owned systems 

(SEIA/GTM Research 2012)

One consideration for program administrators offering incentives to the residential and small 

commercial market segment is whether both the customer-owned and third-party ownership 

market segments should be developed by targeted and separate incentives. This could be 

accomplished in a variety of ways such as providing the option for rebates or PBIs for the 

smallest systems, or capping the amount of incentives available to each of the customer-owned 

and third-party owned market segments to encourage a diversity of ownership arrangements in 

the market. 

 monthly payment than the customer’s original monthly energy bill (Cory 2009). Similarly, customers entering into 

PPA agreements can realize cost savings if the PPA price is less than the customer’s current electricity payments. 

Companies that offer leases or PPA contracts to solar power customers tend to be larger organizations that are able 

to achieve economies of scale and more effectively monetize the tax equity and accelerated depreciation available to 

non-residential purchasers of a solar power system. 8 States allowing third party ownership can be found on the DSIRE website at 

http://dsireusa.org/summarymaps/index.cfm?ee=0&RE=0, accessed August 2012. 

0

5

10

15

20

25

Q1

2009

Q3

2009

Q1

2010

Q3

2010

Q1

2011

Q3

2011

Q1

New Installed Capacity 

2012

(MW/dc) 

CSI - New Residential Systems

Third party ownership Direct ownership
9 

3.3 Program Budgetary Considerations

Program budgetary constraints are another consideration in assessing whether to use rebates or 

performance-based incentives. Budgetary demands for rebate payments are much more frontloaded than performance based incentive programs (Hoff 2006). Upfront rebates require full 

payment up front, whereas PBI payments are often made over a period of 5 to 15 years based on 

system production. For PBI programs, incentive costs are shifted from the current year to future 

years. This can be particularly important for large systems. For example, offering a $1.00/watt 

rebate on a 1-MW system equals a $1,000,000 up-front rebate payment—a large cash outlay for 

the utility. Although PBIs shift cost burdens out over time, they do not necessarily lower 

program costs for ratepayers. Utilities seeking to develop new incentive programs will want to 

weigh budgetary considerations against the likelihood that a particular incentive type will 

stimulate the desired level of solar market development. 

Budgetary constraints were a consideration in Xcel Energy’s shift from its Solar*Rewards rebate 

program to a purely PBI program. Because the utility had oversubscribed its rebate offering – 

exceeding near term installation targets and over drawing its allotted solar incentive budget – 

moving to a PBI program allowed Xcel Energy to continue to offer incentive payments while 

addressing its near term cash situation. Stakeholders in the utility's Solar*Rewards program 

settlement hearings recognized that "the movement away from up-front incentive payments will 

defer the incurrence of a substantial level of costs to future periods." (Colorado Public Utilities 

Commission 2011, p. 8) Xcel Energy’s move to a PBI program also allows the utility to offer an 

incentive more closely aligned with the actual production of a solar power system.

For the purposes of illustrating the differences in budgetary demands between a rebate and PBI 

program, we have developed a hypothetical scenario of an incentive program designed to spur 

the development of 100 MW of solar in 10 years. In this scenario, we assumed a 78% increase in 

solar installations each year to reach 100 MW of capacity in 10 years. This assumed solar growth 

rate is comparable to actual solar growth rates. While the rate of program uptake will certainly be 

affected by higher or lower levels of incentives, the purpose of this scenario is to highlight the 

difference in annual budgetary requirements between rebates and PBIs. For that reason, an 

additional assumption here is demand for solar is such that the full 100 MW of the program's 

desired capacity would be installed in the 10-year timeframe, regardless of incentive level or 

type. 

Figure 2 illustrates the relative magnitude of payments over time for three different hypothetical 

programs: 1) a standard $2/watt rebate, 2) a $1/watt rebate, and 3) a fixed PBI rate of $0.10/kWh 

paid for 10 years. The figure shows the annual budget that each program would need to support 

solar installations under the assumed growth rates over time. For the PBI budget, the assumed 

solar capacity factor is 15%, and the assumed system degradation is .05%/year.
10 

Figure 2. Rebate versus PBI: Budgetary comparison

Concept adopted from (Hoff 2006)

While a utility will have many considerations in choosing to offer a rebate or PBI (e.g., system 

performance and encouraging various market segments), the budgetary impacts of each option is 

an important consideration. Rebate programs must incur the bulk of expenses up-front, and may 

have higher annual budgets while the program is operational. PBI programs, on the other hand, 

spread the budgetary requirements of the program out over a longer period, and they extend 

beyond the period during which the program is accepting applications for participation in the 

program. 

$0

$20,000,000

$40,000,000

$60,000,000

$80,000,000

$100,000,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Program Budget/Incentive Step

Program Budget/Year

Rebate $2.00/watt Rebate $1.00/watt Constant PBI $.10/kWh
11 

4 Establishing the Incentive Level and Designing 

the Program

Setting the initial incentive level can be one of the most important determinants of a solar 

incentive program’s success and one of the most difficult elements of the overall program 

design. Providing incentives that are too large can cause an artificial rush to reserve incentive 

payments, which may overdraw the program’s budget, and can lead to shorter program duration 

than originally planned or to overpayment for solar capacity. Alternatively, setting an incentive 

payment too low can lead to an undersubscribed program in which insufficient capacity is 

installed to meet a utility’s solar targets. The goal for a utility in setting an incentive level is 

typically to provide sufficient payment to encourage enough customers to install solar 

technologies so that the utility can meet its solar capacity targets at the lowest cost (Couture et al. 

2010). This section discusses targeting payback periods or returns, benchmarking incentive 

levels, incentivizing different market segments, and establishing rebate and PBI levels. 

4.1 Targeting Payback Periods and Return on Investment

To establish an appropriate incentive level, utilities often target a specific payback period for 

customers or a return on investment (ROI) for installers. Other considerations for determining 

the level of incentive are: 1) the status and level of activity of the solar industry within the state 

or region, 2) the size and scope of the program, 3) budgetary constraints, and 4) customer 

monthly cash flow where third-party owned systems are an option (i.e., the comparison of 

monthly solar costs through a lease or PPA to retail rates). 

Based on our discussions with program administrators, some utilities target a 10–15 year 

payback for consumers. For example, the Oregon Solar Incentive Program targets a 15-year 

payback with its “volumetric incentive rate” (PBI), which coincides with the utility’s purchase of 

a system’s renewable energy certificates (RECs) for the same 15-year period (Public Utility 

Commission of Oregon 2011). Utilities may also target a specific ROI for system installers. 

Information on these targeted returns is not widely available, but one utility indicated that it 

seeks to allow installers a return of 8%–10%. 

We analyzed payback periods for residential programs included in the appendix and found that 

of the customer-owned, small system programs, only 6 utilities of 25 offered programs that 

yielded after-incentive payback periods of less than 15 years. Of the remaining small, residential, 

customer-owned solar programs analyzed, we calculated that 

• Five programs offered after-incentive payback periods of 15–25 years, 

• Eight programs offered after-incentive payback periods of 25–30 years, and 

• Six programs offered after-incentive payback period exceeding 30 years.9

Calculations of payback and ROI for solar systems require data for installed capacity costs (in 

the case of a rebate payment) or production costs (in the case of a PBI payment); the cost of 

 

9 Calculations were done in NREL’s System Advisor Model. We used OpenEI utility data for standard/base 

residential rate structure; solar cost data from SEIA/GTM for Q1 2012; weather data for a zip code in the utility’s 

service territory; the 30% Federal Investment Tax Credit; building load data for a building in a zip code in the 

utility’s service territory; and incentive levels available for the relevant program.
12 

retail electricity avoided (including time of use rates, where applicable); and any other financial 

incentives available, including net metering, federal tax credits, and possible revenues from the 

sale of RECs. Models, such as the publicly available System Advisor Model (SAM) or the Cost 

of Renewable Energy Spreadsheet Tool (CREST),10 can be used to determine payback periods 

and the impact of incentive levels on a system's net present value, given assumptions about 

system cost, expected performance, utility rates, and expected average annual hourly building 

load demand. 

While targeting a specific payback or return seems straightforward, it is complicated by rapidly 

changing prices and differences in electricity rate structures and installed costs for various 

system sizes. Given the rapidly declining costs of PV and wide variations in reported prices, 

obtaining accurate cost data for calculating payback and returns can be particularly challenging. 

Prices can vary substantially even within a single utility service territory. Price fluctuations also 

make it difficult to maintain a targeted ROI over the duration of the program. In addition, 

because cost parameters differ among customer classes, incentive levels must typically be 

developed for various customer classes or system sizes in order to maintain the targeted customer 

ROI or payback period across program participants. These issues are discussed in detail in the 

following two sections. 

4.2 Assessing Solar Costs and Benchmarking

Accurate data on solar installation and equipment costs are essential to setting appropriate 

incentive levels, but rapid changes in the marketplace in recent years have made it difficult for 

program administrators to stay abreast of current prices. Several sources have reported wide 

variation in installed costs—not only from state to state but also often from project to project. 

National data from the first quarter of 2012 shows installed costs for residential systems ranging 

from roughly $4-$8/watt (SEIA/GTM Research 2012, p. 38) and CSI's available cost data shows 

residential prices in the range of $4-$7/watt DC.

11 (Go Solar California 2012). Installed costs

have been declining steadily on average, although recent studies have shown that decreases in 

component costs of a solar system have not translated to comparable decreases in the installed

cost of solar systems (Goodrich, James, and Woodhouse 2012). 

Because of challenges in obtaining accurate installed cost data, benchmarking against incentive 

levels, uptake rates, and installed costs of neighboring utilities can help assess appropriate 

incentive levels. Also, more accurate cost data can be obtained by using multiple sources, 

including costs from independent sources and information provided by the local installer 

community where available. A list of currently available incentives, which was largely gathered 

from publicly available data from Database of State Incentives for Renewables & Efficiency 

(DSIRE)12, is available in the appendix. In addition, comprehensive data on installed solar costs 

is available online under the Open PV project, while CSI and other California utility programs

data, including installed costs and incentives received, are also posted online.13

 

10 The SAM model is available at http://sam.nrel.gov/ and CREST is available at 

https://financere.nrel.gov/finance/content/crest-cost-energy-models. 11 Of systems installed in 2012, 26% cost between $4-$5/watt DC, 34% cost from $5-$6/watt DC, and 18% cost 

from $6-$7/watt DC, according to statistics for the CSI program. 

http://www.californiasolarstatistics.ca.gov/reports/cost_per_watt/ (Go Solar California 2012). 12 See http://www.dsireusa.org/. 13 See Open PV at https://openpv.nrel.gov/ and the California data at http://www.californiasolarstatistics.ca.gov/. 
13 

Particularly for programs with long approval processes, another consideration is the timeliness of 

solar market data. The regulatory approval process for establishing or modifying programs can 

often take months to complete. During this period, pricing can change. Installed cost estimates 

that were accurate at the beginning of the process may not be accurate once final approval is 

granted. Therefore, mechanisms for updating and revising pricing may be necessary. 

To address cost uncertainty, some utilities have tested incentive levels by making them available 

in the form of pilot programs, such as the Oregon Solar Volumetric Incentive Rate and the 

LADWP feed-in tariff. Others have limited the capacity available for the first stage of a program 

to similar effect. In this way, offering a given level of incentive to the market provides direct 

evidence with respect to its efficacy in market development. 

4.3 Incentivizing Different Market Segments 

Solar programs are generally designed to encourage a range of small and larger systems, and 

there are various reasons why such market diversity can be beneficial to the solar market. One 

such reason is ratepayer equity if all classes of ratepayers support the solar program. Other 

considerations are that encouraging larger systems can achieve solar capacity installation targets 

at lower cost, while many small distributed systems can provide benefits to consumers who can 

build support for a program. Utilities can also derive system benefits from having particular 

classes of systems on the grid. From an industry perspective, encouraging the development of a 

variety of sizes and types of systems can build a more robust and stable solar industry in the long 

term.

It is important to differentiate incentive levels for smaller and larger systems because of 

differences in system economics. Having several tiers of incentives can help utilities more 

accurately price and design incentives for each tier. Larger system owners likely have different 

electricity rates, demand charges, and perhaps greater access to financing—all of which can 

influence a system's economics. In addition, commercial customers and solar leasing companies 

can take advantage of accelerated depreciation, which is not available to residential customerowned systems. 

Accurately pricing incentives for large systems is important because of the magnitude of the 

payment to large system owners and its potential impact on the program budget; modest 

overpayment for small systems does not have such a significant impact. To accurately price 

incentives, some programs have instituted competitive bidding processes for their largest 

systems. For example, Xcel Energy historically gave rebates to small systems, a productionbased incentive for the output of mid-sized systems, and used a competitive bidding process to 

determine awards for the largest category of systems. In addition, NYSERDA has a competitive 

solicitation for systems greater than 50 kW, and Arizona Public Service has an auction program 

for all commercial systems. 

There is little consistency in where utilities draw distinctions between small and large 

commercial systems. Some utilities define small systems as those less than 10 kW, while others 

make the distinction between 30 kW and 50 kW. Further, several utilities only distinguish 

between small and large systems, while others have a third or fourth tier. Large system limits are 

often set at 1 MW, but they can vary. These categories may be designed to match net metering 

limits, which vary substantially from state to state. The appendix lists size categories and 

incentive levels for the programs examined for this report. 
14 

The cutoff for system size can be important for program uptake and establishing accurate 

incentives. For example, in the Delmarva solar program in Delaware, auctions were held for 

small systems, defined as up to 50 kW. In response, nearly all projects were sized near the 50 

kW limit, and small residential systems were priced out of the market.14

Another example of considerations that can be made with regard to system size requirements in a 

solar program can be found in discussions associated with Xcel Energy's restructuring of its 

commercial system size requirements within its Solar*Rewards Program in the summer of 2012. 

In conjunction with moving from a rebate to a PBI program, Xcel proposed combining its small 

and large commercial incentive capacity allocations into one single commercial segment. Solar 

industry advocates argued that combining the two commercial programs would 

disproportionately favor large system installers whose economies of scale make their systems 

more cost effective, and would consequently bar small system installers from participating in the 

program.15 Xcel argued that because the larger commercial segment was more popular than the 

smaller commercial segment, any greater likelihood of larger system participation would simply 

lead to more solar being installed more quickly in Xcel's service territory (CoSEIA/SEIA 2012). 

These examples in Connecticut and Colorado show that utilities or program administrators can 

have substantial influence on the size of systems supported by solar programs. Key design 

tradeoffs can encourage market diversity and the rate of program uptake and solar installation. 

4.4 Establishing Rebate and PBI Levels

Rebate incentives are generally designed to mitigate the up-front solar investment’s prohibitory 

size and lump-sum nature. A cross-section of available residential rebate incentive offerings, 

expressed as a portion of the average installed cost (per watt) of solar for the relevant state based 

on data from SEIA/GTM Research 2012, can be seen in Figure 3. Based on our calculations, 

rebates represent 25% to nearly 40% of the average residential installed system costs in most 

jurisdictions. However, in California and Arizona, where incentive rates have declined as 

programs have achieved installed capacity targets, rebate levels range from 3% to 13% of 

average installed costs. Of course, examining a rebate as a fraction of installed cost does not 

capture differences in electricity prices, solar radiation, or other available incentives, which are 

very important for determining system economics. Also, the substantial variation in and 

availability of installed cost figures should also be considered in assessing system economics in a 

particular state or region. However, Figure 3 provides some information on the magnitude of 

current rebate levels relative to installed cost estimates.

 

14 Personal communication with Kevin Quilliam, SRECTrade, August 10, 2012 15In the rehearing, industry advocates stated ”with 16.4 MW approved for acquisition in the Medium Program in the 

Commission Decision, a mere 32 Solar*Rewards applications (for 500 kW PV systems) could easily consume 

roughly the entire Medium Program, leaving no capacity for the highly popular and critically important small 

commercial PV market of systems 10 kW–100 kW." In addition, the industry groups argued that attrition was far 

more common in the large system section of the incentive program, and thus by combining the two program 

buckets, overall attrition would likely increase and more applications for systems that would not ultimately be built 

would be submitted to Xcel. 
15 

Figure 3. Residential rebate programs as a portion of installed cost of solar16

Installed cost data derived from (SEIA/GTM Research 2012); electricity rate data derived from 

(PV Watts); utility rebate level derived from (Database of State Incentives for Renewables & Efficiency) 

When examined on a net present value basis, PBI payments generally represent a smaller 

fraction of installed costs than rebates. Figure 4 presents our estimate of the net present value of 

PBI payments (discounted at 5%) compared to the average installed cost of solar for programs 

that we examined. Figure 4 also shows an estimate of the electricity price in each utility's service 

territory. Our calculations show that the net present value of PBI payments ranges from roughly 

$1.40/watt to a very small fraction of system costs ($.09/watt).17 When using a net present value 

approach, payments in late years are discounted and represent a small fraction of solar 

installation costs.

While other methods can be used to calculate PBI payments as a portion of solar costs, 

particularly a comparison of PBI levels to the levelized cost of solar electricity, discounting 

future PBI payments and comparing that value to average installed costs allowed for a rough 

apples-to-apples comparison to the $/watt rebate levels as a portion of installed costs displayed 

in Figure 4. 

 

16 Electricity prices are derived from PV Watts based on a single a zip code in each utility's service territory. They 

do not account for tiered or time of use rate structures. The electricity rate for ConEdison is from Westchester, 

outside of New York City. This figure does not adjust for differences in solar potential. Installed costs data were 

derived from SEIA/GTM Research 2012. The programs presented here vary in terms of implementation stage, 

which influences incentive level (i.e., some programs in advanced stages have declined incentives to substantially 

lower levels over time). 

17 Present values are discounted at a rate of 5% and system performance is assumed to degrade at a rate of .005% 

annually. 

$0.00

$0.05

$0.10

$0.15

$0.20

$0.00

$2.00

$4.00

$6.00

$8.00

NSP (MN)

Austin Energy (TX)

CPS (TX)

El Paso (TX)

Gulf Power (FL)

Mn. Power (MN)

Co. Springs (CO)

LIPA (NY)

SWEPCO (TX)

LADWP (CA)

Col. Southern (OH)

Ohio Power (OH)

ConEdison (NY)

Pacific Power (CA)

UES (AZ)

SMUD (CA)

APS (AZ)

SRP (AZ)

Snohomish (WA)

SCE (CA)

PG&E (CA)

SDG&E (CA)

Residential Elec Rate (¢/kWh)

$/watt

Utility Rebate ($/watt) Installed Cost of Solar ($/watt) Elec. Rate (¢/kWh)
16 

Figure 4. Present value of PBI payments as portion of installed cost of solar18

Installed cost data derived from (SEIA/GTM Research 2012); electricity rate data derived from 

(PV Watts); utility rebate level derived from (Database of State Incentives for Renewables & Efficiency)

An important consideration for establishing a PBI is the payment term. In utility programs 

examined for this paper, PBI payments range from 5 to 15 years, with a couple of programs 

offering a 20-year option to commercial customers. While solar systems have longer lifespans 

with module warranties generally for 20–25 years, shorter PBI payment periods can be more 

practical for several reasons. First, developers and customers likely discount payments in later 

years because of the time value of money, so later year payments may be less significant to 

system economics unless they are unusually large. Second, there could be substantial 

administrative costs associated with crediting customers (or issuing checks) over 15–20 year 

periods, unless the process is fully automated. Finally, if solar cost trends continue to decline and 

reach grid parity during a PBI's payment term, programs will continue to disburse payments to 

system owners under the program, when new systems are economic. Such an arrangement may 

not be viewed favorably by future stakeholders. While utilities may require the RECs from 

systems incentivized under these programs for 15–20 years to meet RPS requirements, REC 

ownership provisions can be separated from the incentive payment period, as is done with rebate 

programs that acquire system RECs for long periods of time despite a one-time, up-front 

incentive payment. 

 

18 Electricity prices are derived from PV Watts based on a single a zip code in each utility's service territory. They 

do not account for tiered or time of use rate structures. This figure does not adjust for differences in solar potential. 

Installed costs data were derived from SEIA/GTM Research 2012. The programs presented here vary in terms of 

implementation stage, which influences incentive level (i.e., some programs in advanced stages have declined 

incentives to substantially lower levels over time).

$0.00

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

$0.18

$0.20

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

Residential Elec. Rate (¢/kWh)

$/watt

PV of PBI Payments ($/watt) Avg. Cost of Solar ($/watt) Avg. Cost of Elect (¢/kWh)
17 

The uncertainty of actual system production and the associated budgetary impacts if production 

and PBI payments are higher than anticipated is another important consideration in the

implementation of PBI contracts. The CSI program ran into challenges associated with its PBI 

payments when system production was greater than anticipated. Specifically, in 2010, CSI 

moved to address a roughly $260 million budgetary shortfall that stemmed partially from PBI 

systems over-performing expectations, especially in the case of single- or multi-axis solar 

tracking systems19 (California Public Utilities Commission 2010; California Public Utilities 

Commission 2011, p. 44). 

To avoid future budgetary challenges, some programs have based future payments on expected 

system production. For example, in its competitive bidding program, the New York State Energy 

Research and Development Authority (NYSERDA) pays system owners for actual system 

production for the first three years after installation, but will not provide payments beyond those 

requested in the bidding process. Therefore, if systems perform better than estimated in the first 

two years of the program, they will receive PBI payments based on actual system performance in 

years one and two, but will receive payments in year three that bring the aggregate incentive 

payment to the total incentive requested in the initial bid. In this case, the project developer will 

receive a portion of its requested incentive earlier in the three-year incentive payment schedule if 

the solar system performs better than expected. This does help the solar developer to improve 

their odds of getting the full amount established in the contract, and this contracted amount had 

(at the time of bid) been determined by the solar developer to be sufficient to leverage the 

project. Therefore, any additional incentive payment would be to the advantage of the solar

developer at the expense of the ratepayers.

4.5 Establishing Incentive Limits per Installation

Many utilities define a maximum incentive limit per installation, particularly for smaller systems. 

Often, this is defined as a dollar amount, such as $25,000, but in other cases, it is defined as a 

percentage of the system's installed cost. Additionally, utilities often restrict system size by 

limiting a proposed system in relation to the customer's expected electrical demand. When they 

are used, limits on the fraction of installed cost that can be supported by incentive programs are 

generally set between 40%–60%. Dollar limits vary widely from $2,500 to more than $150,000. 

Where utilities limit system sizes with percent-of-electrical demand restrictions, system sizes can 

be capped anywhere between 80%–120% of a customer’s expected monthly load. The appendix 

includes details on maximum benefits. 

 

19 CSI also referred to a change in economic conditions and a consequent miscalculation of a discount rate used to 

determine PBI values based on rebate levels as another source of the PBI budget shortfall.
18 

5 Differentiating Incentive Levels

Several utilities have offered different incentive levels to consumers based on system 

characteristics other than system size. At least a few utilities have offered a different level of 

incentive to third-party owned systems and customer-owned systems, while others vary incentive 

levels either based on differences in solar radiation within the utility's service territory or to 

encourage solar installations that provide benefits to the electrical grid. This section discusses 

differentiating incentives based on such system characteristics. 

5.1 Differentiating Incentives for Third-Party Owned Systems

As third-party owned systems begin to dominate the solar power market (SEIA/GTM Research 

2012; Go Solar California 2012), program administrators may want to differentiate incentive 

levels based on system ownership. A rationale for offering a lower incentive to third-party 

owners is that they benefit from economies of scale and financial arrangements that can reduce 

some financing and installation costs compared to customer-owned systems. In addition, thirdparty owned systems can take advantage of accelerated depreciation, which residential system 

owners cannot do. Differentiating incentives by ownership can be one method of maintaining a 

targeted ROI or payback period by market segment and minimizing incentive expenditures. 

On the other hand, program administrators may wish not to differentiate incentives so as not to 

penalize financial innovations in the marketplace. The amount of installed capacity is the same, 

no matter whether such capacity is customer-owned or third-party owned, so distinguishing the 

incentive amount by system ownership may not be equitable or could diminish competition. 

Further, customer-owners may have access to other mechanisms that reduce financing costs, 

such as community bulk purchase discounts or Property Assessed Clean Energy financing, and 

the financial return hurdle rates for third-party investors may be higher than for customer-owned 

systems particularly if tax equity investors are involved. Further, differentiating incentives by 

ownership arrangement could create inequities if a greater proportion of lower-income 

homeowners take advantage of leasing (Drury et al. 2012); i.e., if larger incentives were provided 

to customer-owned systems purchased by higher income households, this could be perceived as 

inequitable. As discussed earlier, some utilities may wish to work to incentivize both types of 

system ownership to encourage market diversity. 

Xcel Energy (CO) differentiates incentives for third-party owned and customer-owned systems, 

as does LADWP (see Table 3). Xcel Energy (CO) developed a lower incentive ($0.10/kWh 

compared to $0.15/kWh for customer-owned) and step-down schedule for third-party owned 

systems under 10kW. However, Xcel does not make this distinction for larger systems. For 

systems 10kW–500kW, incentive levels are the same at $0.09/kWh for customer- and third-party 

owned systems. LADWP’s rebate program offers $1.50/watt for third-party owned systems 

compared to $1.62/watt for customer owned-systems. Finally, some utilities have not allowed 

third-party owned systems to participate at all. In some jurisdictions, third-party owned systems 

have been precluded by law because they involve the sale of electricity by an entity other than a 

regulated utility (Kollins, Speer, and Cory 2010). In other cases, the rationale for the exclusion is 

unclear. Table 3 provides an example of the manner in which various programs differentiate 

available incentives by ownership model, including some utilities that have precluded third-party 

ownership from participation even when allowed by law. 
19 

Table 3. Solar Incentive Programs' Treatment of Third-party Owned Systems

Utility Incentive for 

Customer-owned

Systems

Incentive for 

Third-party Owned

Systems

Eligible System 

Size

Xcel Energy (CO) $.15/kWh $.10/kWh 0.5 kW – 10 kW

LADWP $1.62/watt $1.50/watt 1 kW – 1 MW

Colorado Springs Utilities $1.80/watt Not Allowed 0.5 kW – 10 kW

Long Island Power Authority $1.75/watt Not Allowed <10 kW

CPS Energy $2.00/watt Not Allowed <25 kW

Xcel Energy (MN) $2.25/watt Not Allowed .5 kW – 40 kW

Source: Utility solar program websites and (Database of State Incentives for Renewables & Efficiency)

5.2 Differentiating Incentives for Grid Benefits

PV systems have the potential to provide benefits to the grid, typically involving the easing of 

transmission congestion or deferring transmission and distribution investments. Programs can

consider providing additional incentives to projects that are sited in areas that provide substantial 

grid benefits. For example, NYSERDA encourages the placement of solar projects in areas that 

are deemed to have such benefits by providing a 15% bonus payment to the bid price in its 

competitive solicitation program (Levy 2012). The determination of preferred areas is based on 

analyses conducted by utilities (who provided data to NYSERDA) of locations where circuits 

have the potential to be overloaded or where the placement of solar projects could defer 

transmission or distribution investments. NYSERDA encourages developers to install systems in 

these areas. 

5.3 Differentiating Incentives based on Expected Solar Radiation

If an incentive program applies to a large geographic area, incentive levels could be varied based 

on solar radiation. Providing incentives based on expected performance by location (based on 

solar radiation) can help achieve a desired ROI across program locations with dramatically 

different weather patterns. Such differentiation can also ensure that systems are not all located in 

the same area, which could put pressure on the distribution system (Couture et al. 2010). 

The Oregon Solar Program’s PBI differentiates incentive levels based on expected solar 

radiation. Because solar radiation varies across the state, incentive levels differ by customer 

location so that the program's targeted payback period can be maintained for all customers. The 

PBI program targets a 15-year payback, after which system owners will be compensated for the 

resource value of the electricity their systems produce (75th Oregon Legislative Assembly 2010). 

Table 4 shows the differentiated incentive levels for the April 2012 application period of the 

Oregon Solar Program based on the counties in which the proposed solar system will be installed 

(Oregon Public Utility Commission 2012). 
20 

Table 4. Oregon Solar Incentive Program: PBI Variation by System County

Region Counties Electric 

Companies 

Incentive for 

Small Systems 

(<10 kW)

Incentive for 

Medium Systems 

(10 kW–100 kW)

1 Benton, Clackamas, Clatsop, 

Columbia, Lane, Lincoln, Linn, 

Marion, Multnomah, Polk, 

Tillamook, Washington, and 

Yamhill

Pacific Power 

and PGE

$0.411/kWh $0.285/kWh

2 Coos, Douglas, and Hood 

River

Pacific Power 

and PGE

$0.346/kWh $0.250/kWh

3 Gilliam, Jackson, Josephine, 

Klamath, Morrow, Sherman, 

Umatilla, Wallowa, and Wasco

Pacific Power $0.346/kWh $0.250/kWh

4 Baker, Crook, Deschutes, 

Jefferson, Lake

Pacific Power 

and Idaho Power

$0.317/kWh $0.250/kWh

Source: (Oregon Public Utility Commission 2012)

 
21 

6 Managing Incentives and Responding to 

Market Conditions

Over the last five years, the price of solar modules and the installed cost of solar power has been 

trending downward. As the installed cost of solar decreases, administrators generally wish to 

reduce their incentive offers in response to changing market conditions to minimize ratepayer 

impacts. However, the installer community prefers transparency and predictability in incentive 

offerings to maintain stable business operations. When incentive programs are abruptly stopped 

to adjust incentive levels, the solar industry has difficulty maintaining local resources and staff. 

To balance these interests, utilities have generally used two approaches to modify incentive 

levels: 1) developing a fixed schedule by which incentive levels will decline based on capacity

installation, program uptake, or budgetary usage or timing, or 2) using an auction or competitive 

bidding mechanism to obtain market-based pricing for each enrollment period. Experience with 

these approaches and the relative merits and disadvantages of each option are discussed in this 

section. 

6.1 Setting Incentive Decline Schedules

A declining incentive payment schedule—a forward-looking schedule under which incentive 

levels will decline based on the passage of time, meeting of installed capacity targets, the usage 

of available program budget, or some combination—can help minimize payments and provide 

predictability. Establishing and communicating a long-term schedule of incentive declines in 

advance benefits industry by allowing it to better anticipate and adapt to changes. A 

predetermined schedule for incentive decline also helps exert downward price pressure on the 

solar market, which can improve its cost-effectiveness (Couture et al. 2010). However, one 

disadvantage to predetermined program declines is that reductions in incentives will not 

necessarily align with market conditions. For example, market prices could fall more quickly 

than incentive levels, resulting in overpayment for a particular portion of installed solar capacity. 

On the other hand, if incentive levels decline faster than market prices, installations can halt. 

Thus, the lack of knowledge of future market prices makes this approach challenging. Depending 

on whether there are periodic limits to uptake based on timing, this approach may also make 

predicting annual budgets challenging. 

The CSI—which is implemented by California's three investor-owned utilities: Pacific Gas & 

Electric (PG&E), San Diego Gas & Electric (SDG&E), and Southern California Edison (SCE)—

was a leader in implementing a predetermined incentive decline schedule based on capacity, and 

several other utilities have followed suit. These utilities have included Xcel Energy, Roseville 

Electric, Pacific Power, Public Service Company of New Mexico (PNM), Ohio Power of 

American Electric Power, LADWP, Salt River Project, Arizona Public Service (APS), Tucson 

Electric Power (TEP), Austin Energy, and Sacramento Municipal Utilities District (SMUD). 

When designing a step-down schedule, allocating a smaller amount of capacity or program 

budget for the earliest stages of the program when incentive levels are at their highest can be 

advantageous. In addition, offering the most profitable incentives to a relatively small segment at 

the outset of the program can help jump-start the market. This approach can also protect 

ratepayers by limiting the amount of incentive payments in the early stages of the program if the 

initial offering is higher than it should be and the rate of program uptake is unnaturally 

accelerated. Program administrators we interviewed also indicated that creating numerous steps 
22 

for incentive decline can benefit the solar industry; having more steps helps the utility more 

effectively reduce incentives in relation to changes in the solar market, and it helps solar 

installers make sales to customers because solar is “on sale” before the incentives drop. In this 

way, installers can encourage potential customers to act quickly before incentive levels decline.

Setting an appropriate schedule for declining incentives can likely lead to lower costs as a 

program hits certain installation or investment milestones. However, actual annual outlays of 

incentive payments will depend on how quickly adoption occurs and whether there are limits on 

the timing of uptake. Figure 5 shows the easing of budgetary requirements when administering a 

rebate program with declining incentives. For Pacific Power, the program budget allocation 

increases in the first three steps of the program but then declines. CSI’s Expected PerformanceBased Buydown program budget increases through the first five steps of the program, then 

declines. Reductions in payment outlays in later years may help gain initial support for 

establishing a long-term program.

Figure 5. Pacific Power commercial rebate levels and budget 

Source: Pacific Power (CA)

0

0.5

1

1.5

2

2.5

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

1 2 3 4 5 6 7

Rebate Level ($/watt)

Installed Capacity (MW)

Incentive Steps

Pacific Power Non-Residential 

Rebate Program

Cumulative Installed Capacity (MW)

Capacity Rebate ($/watt)

$0

$1

$2

$3

$4

$5

$6

$7

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

1 2 3 4 5 6 7

Cumulative Budget ($M)

Budget/Step ($M)

Incentive Steps

Pacific Power Non-Residential 

Budget 

Budget Allocation/Step ($M)

Cumulative Budget ($M)
23 

Programs differ in the manner in which they determine targets or the thresholds at which 

incentive levels will decline. The prevailing trend is to either set incentive decline targets based 

on meeting installed capacity goals for a particular incentive level or to set targets based on 

criteria related to meeting budgetary thresholds and the annual timing of the achievement of 

those thresholds. In either case, communicating the status of the incentive level to relevant 

stakeholders in real time is essential. It is important to provide potential participants with clear 

and up-to-date information on the remaining availability of incentives within a level. The 

communication of how much capacity (or budget) remains in a step and is eligible for the current 

level of incentives is an important element of ensuring that step-down programs work 

effectively.20

Incentive Decline Based on Capacity Targets

Capacity targets represent a common approach to stepping down the level of available

incentives; once the installed capacity reaches a certain threshold of capacity, the available 

incentive declines to a lower level. CSI uses this approach, and each administering utility has its 

own capacity allocations based on the utility’s size. The available capacity in each incentive step 

in CSI is larger than that available in the previous step, with the percentage increases in capacity 

targets from one step to the next being the largest early in the program. 

Because there are ten steps in the program, four separate incentive decline schedules for small 

and large residential and small and large non-residential systems, and three administering 

utilities with identical incentive decline schedules, a total of 120 incentive steps occur in 

California. The frequency of incentive declines has led to an almost perpetual state of solar being 

"on sale" in some jurisdiction in California, for some customer segment, at any given time over 

the course of the incentive program. The incentive decline schedule for systems of less than 30 

kW in CSI is shown in Figure 6. 

 

20 Examples of how utilities communicate the incentive step-down schedule include SMUD 

https://www.smud.org/en/residential/environment/solar-for-your-home/solar-basics.htm; APS 

http://www.aps.com/main/green/choice/solar/funding.html; and PNM 

http://www.pnm.com/customers/pv/rec_price_table.htm?source=solar_home. 
24 

Figure 6. California Solar Initiative’s Upfront Incentive Program step-down and budget (for 

Expected Performance Based Buydown program)

Source: (Go Solar California 2007)

Several other programs, including Pacific Power, PNM, and LADWP, have incentive decline 

schedules based on capacity targets. Figure 7 shows the different rates of incentive decline across 

programs. In the case of Pacific Power, the slope of the incentive decline is exponential whereas 

PNM follows a constant rate of decline for incentives from one step to the next. The shape of 

LADWP’s incentive decline trajectory demonstrates the incentive price adjustment that LADWP 

undertook in moving from Step 4 to Step 5 in April 2011. At that time, LADWP suspended its 

incentive program to adjust to a substantial drop in solar prices, which left LADWP’s incentive 

levels lucrative, and participation in the program had oversubscribed the program budget by a 

ratio of 3:1 (Los Angeles Department of Water and Power 2011). Xcel Energy in Colorado 

underwent a similar adjustment to its program in March of 2011, and modified the program to a 

PBI-only incentive that now includes a predictable incentive step-down schedule as of May 

2012. 

0

500

1000

1500

2000

$0.00

$1.00

$2.00

$3.00

$4.00

1 2 3 4 5 6 7 8 9 10

Rebate Level ($/watt)

Installed Capacity (MW)

Incentive Step

CSI Up-Front Incentive (<30 kW)

Installed Capacity (MW) Residential and Commercial Incentive ($/watt)

Government and Non-Profit Incentive ($/watt)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

0

200

400

600

800

1000

1 2 3 4 5 6 7 8 9 10

Rebate Incentive Level

($/watt)

Budget ($M) and 

Capacity/Step (MW)

Incentive Steps

CSI Budget and Capacity/Step

Budget Allocation/Step ($M) - left axis Available Capacity/Step (MW) - left axis

Incentive Level ($/watt) - right axis
25 

Figure 7. Incentive decline schedules: Pacific Power, PNM, LADWP

Sources: (Pacific Power (CA); Public Service Company of New Mexico 2002–2012; Los Angeles 

Department of Water and Power 2012)

Incentive Decline Based on the Timing of Meeting Budgetary Thresholds 

For budgetary predictability, declining schedules can be based on the timing of meeting 

particular budget thresholds rather than capacity targets. This approach can help ensure that 

annual budgets are not exceeded. With capacity-based schedules, how much of the budget will 

be required in a particular year is unclear; the incentive payments are based on how much 

capacity is installed (i.e., market uptake). While capacity-based thresholds may be viable for 

programs that have multi-year budgets and planning horizons, a budget timing-based schedule 

may be needed for programs that require annual plans and/or regulatory approval. 

APS and TEP are examples of programs that reduce solar incentives in accordance with annual 

budgetary thresholds (see Table 5). APS's solar incentive program budget is subject to annual 

review and approval by the Arizona Corporation Commission, and thus APS usually adjusts its 

incentives annually. At the outset of each year and upon regulatory approval, APS distributes the 

0

0.5

1

1.5

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

1 2 3 4 5 6 7

Installed Capacity (MW)

Rebate ($/watt)

Incentive Step

Pacific Power Residential Rebate 

Program

Installed Capacity (MW)

Capacity Rebate ($/watt)

0

1

2

3

4

5

$0.000

$0.050

$0.100

$0.150

1 2 3 4 5 6 7

Installed Capacity (MW)

PBI ($/kWh)

Incentive Step

Public Service NM

Small System PBI (<10 kW)

Installed Capacity (MW)

PBI Rate ($/kWh)

0

20

40

60

80

100

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

1 2 3 4 5 6 7 8 9 10

Installed Capacity (MW)

Rebate ($/watt)

Incentive Steps

LADWP Residential 

Solar Rebate Program

Installed Capacity (MW) Rebate Leve ($/watt)l
26 

schedule for incentive decline for the following year. Table 5 shows how APS reduces its 

incentive level based on how much of the annual budget is consumed during certain periods in 

2012, where the initial incentive level was $0.55/watt and was stepped down over the year. 

From the perspective of the installer and customer side of the solar industry, such annual 

uncertainty poses challenges in that the solar market must endure a period of flux each year 

during which the level of incentives for that coming year, if any, are unknown. But, this 

approach does provide certainty to the utility and ratepayers with respect to program budgets, 

and it helps smooth access to incentives across an entire year (discussed in detail in Section 7.3).

Table 5. Arizona Public Service’s Residential Incentive Step-Down Schedule

Budget Thresholds for Declining the Incentive Level Reduction

Amount Incentive Rate

If 75% of funds used by 4/21/2012 incentive reduced by $0.20

If 75% of funds used by 5/21/2012 incentive reduced by $0.10 TBD

If 75% of funds used by 6/20/2012 incentive reduced by $0.05

If 90% of funds used by 11/1/2012 and incentive is greater than 

or equal to $0.35 the incentive reduced to: $0.20

TBD

If 90% of funds used by 11/1/2012 and incentive is less than 

$0.35 then incentive reduced to: $0.10

Source: (Arizona Public Service 2012)

NYSERDA also bases incentive step-downs on timing and budgetary thresholds. NYSERDA 

operates a standard offer, up-front incentive based on capacity, which currently provides 

$1.50/watt to residential systems up to 7kW and commercial systems up to 50kW. As part of the 

New York Sun Initiative, new funds have been made availabile for administering of NYSERDA 

program in monthly increments according to the schedule in Table 6. 

Table 6. NYSERDA Monthly Incentive Budget (2012–2015)

Year Monthly Incentive Budget

2012 $3,500,000

2013 $3,125,000

2014 $2,000,00021

2015 $2,000,00013 

Source: NYSERDA 2012

If, in two successive months, the available incentive budget is exhausted, NYSERDA will reduce 

the available incentive level and begin offering the lower incentive in the following month, 

though there is no predetermined schedule for incentive decline. In addition, if in a given month, 

the entire budget is not used, NYSERDA will roll that remaining budget into the next month's 

funds, and the entire (now-larger) monthly allocation must be exhausted to trigger an incentive 

decline. At the end of a program year (December), any remaining budget is removed from the 

program and is distributed to funding renewable generation technologies based on 

determinations made by the New York Public Services Commission. Depending on this 

 

21 Funding in 2014 and 2015 has not been finalized, although it is expected to at least equal that available in 2013.
27 

determination, excess funding from one year could be reallocated to the solar program from 

which it was originally taken. 

NYSERDA holds monthly webinars with the program's registered installers to communicate

program uptake and guidance on budgetary availability to market participants. Currently, 

NYSERDA does not make the remaining budget available to the public, as other programs have 

done via websites, though NYSERDA has said it is moving to create such a tracking website in 

the future (Mace 2012). NYSERDA does not make available a predetermined schedule for 

incentive decline, which provides considerable flexibility for administrators to adjust to changing 

market conditions at some expense to providing more transparency and predictability to solar 

market participants that a predetermined incentive decline schedule could provide. 

6.2 Employing an Auction Mechanism or Competitive Solicitation

A benefit of using a competitive bid process in allocating solar incentives is to obtain up-to-date 

information on installed costs, which can be important in a rapidly changing market 

environment. Competitive bids can be obtained through auctions or competitive solicitations

such as requests for proposals. These could be used to determine incentive levels on an ongoing 

basis or to establish pricing at the outset of a program. In several programs, such as those run by 

Xcel Energy and NYSERDA larger solar projects are subject to a competitive bidding process. It 

is most important for programs to accurately price incentives for large projects because of the 

variation in installed costs, the potential impact on program budgets, and the need to ensure 

ratepayer protection. 

A reverse auction process is a market-based mechanism for setting incentive levels that are 

responsive to changing solar costs. With this approach, competing bids are evaluated against 

each other and utilities can prioritize incentive payments to solar projects whose per-unit costs 

are lowest, are expected to produce more electricity per unit of capacity, or both. Reverse 

auctions have been used in California for utility-scale projects as well as in a number of states 

with solar REC markets, such as New Jersey and Ohio. Generally, auctions have not been used 

for residential systems and other small systems because of the complexity in administering and 

participating in such processes. Residential consumers may find auctions difficult to understand 

or may view them as prohibitively complex, although simplified processes may be feasible for 

small systems. The APS auction program has been used for commercial systems of all sizes (see 

Text Box 1), and APS has streamlined its bidding and evaluation process through many years of 

iterative improvements. A utility must also determine whether its solar incentive program is large 

enough to justify the administrative burden associated with managing an auction. For smaller 

programs, the incremental savings a reverse auction may enable could be offset or eliminated by 

the administrative costs associated with running such a process.
28 

Text Box 1. Arizona Public Service Company's Reverse Auction Program

Arizona Public Service Company’s commercial solar incentive program is a notable exception to the trend 

that request for proposal (RFP) and auction processes are only employed for large solar systems. APS 

requires all commercial installations, including small systems competing for up-front rebates, to bid into a 

reverse auction process. APS has three different auctions for systems up to 30kW, 31kW to 200 kW, and 

larger systems 201kW up to 2,000 kW. The auction process is as follows:

1. APS stipulates a maximum incentive level (either a capacity rebate or PBI, depending on the 

system size) and communicates this to prospective bidders.

2. Bidders must enter their system specs into the APS ranking calculator, which includes the 

technology being employed, technology type, system size (kilowatts DC), estimated annual 

production (kWh), the total project cost, and the requested incentive level (up to the maximum).

3. The incentive calculator assigns a score to a particular bid based on system specifics in (#2). 

4. After all proposals have been received, scores are ranked and incentives disbursed at the bid price, 

starting with the lowest score, until the budget for that RFP subscription period has been exhausted.

The score that each bid receives is largely the result of the total incentive per kWh of production that is 

requested and the term of the PBI contract requested by the bidder. For upfront rebate incentives,

calculations also take into account the expected performance of the system and favor systems that are 

expected to perform at a higher level of efficiency. For instance, if two competing rebate requests bid

$1.00/watt, but one system is expected to produce 1,600 kWh per kW of capacity and the other system is 

expected to produce 1,500 kWh per kW of capacity, preference is given to the more efficient system (1,600 

kWh per kW over 1,500 kWh per kW). 

For APS’s commercial PBI program, bidders can stipulate whether their PBI agreement extends for 10, 15, 

or 20 years. APS sets different maximum incentive payments depending on the length of the agreement, 

with larger incentives offered for shorter contracts and vice versa. The process of applying for APS’s PBI 

program is much the same as the up-front incentive program in that bidders complete a spreadsheet with 

information required for the program, and their bids are scored in much the same way as described above. 

Each bid is assigned a score based on the requested level of incentive, length, and other factors, and all the 

bids are aggregated at the close of the reservation window. Incentives are then awarded starting with the 

lowest scored project moving upward until that reservation period’s capacity goals are met.

Bidders in the APS auction process are free to apply for the maximum level of incentives; however, 

because some bidders will likely apply for lower levels of incentives, there is a chance that bidders 

requesting the maximum incentive level could be outbid by projects requesting less than the maximum. 

This feature helps APS drive down their program costs and helps incentivize bidders to reduce the level of 

incentive they are requesting in a given open reservation period. This downward price pressure helps APS 

cost-effectively allocate incentives across their entire commercial program by providing the least incentive 

to achieve their stated installed capacity targets for a given period of open reservations. 
29 

6.3 Transitioning to a Post-Incentives Environment

A number of incentive programs in California and in other Western states are in late stages of 

program implementation, after which incentives are scheduled to disappear. To maintain 

installations after the expiration of these programs, solar will need to compete against standard 

retail rates of electricity without the contribution of solar program incentives. 

Currently Austin Energy offers a program with a residential rebate of $2.00/watt AC and net 

metering. Austin Energy is considering replacing the current program with a rebate that declines 

over time, at a proposed rate of 8% per year consistent with assumed solar capital cost declines, 

and a value of solar payment for all the generation of the system (Rabago et al. 2012). The 

“value of solar” payment is not tied directly to the incentive payment, but is rather based on the 

value of the solar generation to the utility. The program is innovative because it would offer a 

declining rebate level based on reductions in PV capital costs, but would also provide a valuebased payment to a system owner over time. The value calculation includes utility transmission 

line loss savings, energy savings, generation capacity savings, the fuel price hedge value, 

transmission and distribution capacity savings, and environmental benefits. Austin has calculated 

the 2011 value of solar to be 12.8 cents/kWh (Rabago et al. 2012), though the estimated value of 

solar could change from year to year. The value-of-solar rate would vary annually based on 

Texas’ nodal prices and other factors. The utility’s calculations show that the value-of-solar rate 

ranged from 10.3cents/kWh to 16.4cents/kWh for 2006 through 2011 (Austin Energy 2012). 
30 

7 Administering the Program and Application 

Process

To effectively administer programs, administrators need to balance the conflicting desires to 

keep the process as simple as possible while conducting ample due diligence to ensure the 

installation of optimally performing systems. In addition, administrators need to consider how to 

provide equitable access to incentives; manage the queue of projects; and minimize overall 

administrative costs of the program. This section discusses methods of ensuring equal access to 

incentives, application fees, managing project flow, inspections to ensure system performance, 

and administering PBI payments. 

7.1 Ensuring Equal Access to Available Incentives

Ensuring fair and equitable access to incentives can be crucial to the perceived success of an 

incentive program. The likelihood that many applicants will be denied incentives may dictate the 

procedure by which incentives are awarded. For larger programs that can meet customer 

demand, a transparent, first-come-first-served allocation method may be adequate for managing 

program applications. This approach has been used effectively by the CSI and others. However, 

even for large programs, periods of high demand, such as just before incentives are set to 

decline, can pose challenges. During periods of rapid up-take, it is important to have transparent 

procedures for determining priority and to frequently update consumers on how close the 

program is to achieving metrics that trigger when the incentive levels will decline. Software 

solutions can help manage project flow. An example of the importance of this issue is 

underscored by a lawsuit filed against Gainesville Regional Utilities in Florida by an applicant 

who claims that the utility showed favoritism in the process of awarding payments under its solar 

feed-in tariff program. (Smith 2011) 

Some modestly sized programs that have substantially more demand than available incentive 

funding have used a lottery or other random selection process to address potential issues of 

inequity, although this approach poses challenges for the planning processes of installers. For 

example, the Oregon Solar Incentive Program’s PBI is a small and highly popular program that 

instituted a lottery to manage high levels of demand. When the program was established in 2010, 

it opened an application period once every six months. In each open application period, available 

incentives were fully reserved within a matter of minutes, and many customers were turned away 

because they did not apply soon enough (Read 2012). Due to the extremely short duration of 

incentive availability and the inability for many customers to apply quickly enough, the program 

inadvertently favored program applicants with faster internet connections and led to some 

gaming of the system; larger developers helped ensure approval of more of their projects by 

applying from locations with faster internet connections. 

In response to this level of demand, the Oregon Solar Program instituted a one-day random 

lottery process that allowed all applicants in a given application window an equal opportunity to 

have their applications queued for review. In addition, the one-day lottery allows program 

administrators to gauge the demand for the program, as they can see how many applications they 

have received and can determine the amount of capacity that could be brought online if their 

program budget were increased. Such lotteries or random selection processes, however, make it 

more difficult for installers to plan and create uncertainty regarding the number of customers that 

they will be able to serve. Some programs have instituted first-come, first-served programs but 
31 

have limited the total installed capacity for each eligible installer, which would limit gaming 

concerns, but limits supplier competition as well. 

7.2 Charging a Nominal but Consequential Application Fee

A major source of potential administrative inefficiency comes from the likelihood that some 

approved applicants may eventually drop out of the program and not install a solar power 

system. In such cases, the time and resources spent by program administrators to review 

application materials are essentially lost (i.e., these efforts do not result in installed capacity). 

Therefore, it is important to establish clearly defined procedures to minimize and deal with 

program drop-outs and any incentive payments that are now not used and available to other 

program participants. To address this concern, many programs have instituted a mandatory 

application fee that is substantial enough to discourage frivolous applications, but small enough 

to avoid discouraging participation of customers with viable projects.

The CSI charges a fee for all applications submitted for systems with more than 10 kW in 

capacity (see Table 7). The California Public Utilities Commission refunds the application fee to 

the program applicant after the system has been installed. All forfeited application fees are 

reallocated to the program administrator’s CSI budget (California Public Utilities Commission 

2011). 

Table 7. California Solar Initiative’s Application Fee Schedule

System Size Fee

>10 kW – <50 kW $1,250

50 kW – <100 kW $2,500

100 kW – <250 kW $5,000

250 kW – <500 kW $10,000

500 kW – <1,000 kW $20,000

Source: (California Public Utilities Commission 2011)

The Oregon Solar Incentive Program’s PBI initially did not require application fees and found 

that the frequency of dropouts was high. In an effort to diminish dropouts, the administering 

utilities have instituted a deposit ($500 or $20/kWdc of capacity, whichever amount is greater) at 

the time of application (Pacific Power 2012). The Long Island Power Authority requires a $100 

non-refundable application fee (Database of State Incentives for Renewables & Efficiency) and 

Xcel Energy (Minnesota) requires a $250 application fee designed to cover the engineering costs 

to evaluate the line diagram of the proposed system. The fee is nonrefundable once the 

application has been reviewed by Xcel Energy’s engineers (Xcel Energy 2012). 

7.3 Managing Project Flow and Incentive Offer Periods

The frequency with which a utility makes incentives available can help provide a more stable 

solar market. In the case of larger programs with multiple step-down targets, a certain amount of 

program longevity is established in the schedule. Some efforts have been made by programs that 

decline incentives based on reaching certain budget thresholds, as well as smaller programs with 
32 

constrained budgets, to spread incentive availability more evenly across calendar years in order 

to provide market stability.

APS and TEP both reduce incentive levels based on when budgetary thresholds are met 

throughout a given calendar year. This type of incentive decline schedule helps ensure that some 

amount of solar incentive is available to the market throughout the year. This approach contrasts 

that taken by other often-smaller utilities that make the entire incentive budget available on a 

first-come-first-served basis at the beginning of the year. Such program administration has led to 

programs being exhausted early in the year and solar market instability. Offering incentives in 

such a way can stimulate a large amount of activity all at once and lead to a period of inactivity 

later in the year as project pipelines run dry. In such instances, solar market participants will 

likely have to wait either until new funds are made available during the year or until the next 

year’s budget is released. Such cycles prohibit the development of a stable industry. 

Basing incentive declines on budgetary availability throughout the year, is one mechanism by 

which APS and TEP have been able to spread incentive budgets across an entire year, even if it 

means offering very low levels of incentives toward the end of the year. Another approach to 

spreading out available incentives is to offer multiple program enrollment periods. For example, 

the Oregon Solar Program offers bi-annual open enrollment periods for participation in the 

program. Despite the likelihood that the program would sell out all of its available capacity in 

just one open application period, given the program’s popularity, program administrators opted 

to spread the availability of incentives more evenly across the entire year by making capacity 

available every six months. Pacing the program’s outlay of incentives more frequently in smaller 

aggregate budgetary amounts may help provide some market stability. Similarly, competitive 

solicitations in New York have been spread out two or more times throughout the year to provide 

more continuity and opportunities for developers. 

7.4 Requiring Inspections and Ensuring Proper System Design

and Implementation

Ensuring optimized system performance in capacity-based programs may require weighing the 

increased administrative costs associated with enforcing compliance against the incremental 

gains in system production. CSI instituted a procedure to inspect the first two solar arrays 

installed by a particular solar contractor under the CSI program. These inspections are meant to 

confirm that actual system installation specifics are the same as those provided in the application 

materials. If the first two inspected systems meet the program’s requirements, CSI will inspect at 

least one in every seven systems under 30 kW for that installer going forward. For systems 

greater than 30kW, system inspections may be required at the discretion of the program

administrator. (California Public Utilities Commission 2011) 

Most rebate programs apply to small solar systems, which, by definition, are not going to 

produce a large amount of electricity relative to large systems, even when installed optimally.

Consequently, similar approaches to selectively inspecting systems have been employed by other 

utilities looking to balance optimized system performance and administrative burden. 

NYSERDA employs a process of checking each of a particular installer's systems until the 

program administrators deem that process no longer necessary, at which point between 15% and 

20% of that installer's systems are inspected to conserve resources over inspecting each installed 

system. 
33 

Salt River Project employs a different approach to monitoring system performance for its 

commercial solar program, which allows larger systems to receive incentive payments; 

Participants apply using the Power Clerk program

22, and once the system is installed and 

inspected, the first 30 days of actual system performance are compared to that predicted by 

Power Clerk's "Solar Anywhere" tool. Using actual weather data and the system specifics as a 

predictive model, as long as the system performed to 95% of its expected kWh output, the Salt 

River Project (SRP) will disburse the full incentive amount to the program participant. SRP does 

not employ this approach in its residential program because the number of systems are 

prohibitively large and the system capacity is relatively small (capped at 5kW) compared to the 

commercial systems that can be as large as 100kW. Because these commercial systems can be so 

much larger, and thus suboptimal system performance can result in a substantially larger 

difference in system production, SRP has determined that the additional administrative burden of 

monitoring commercial system performance is justified by greater assurance of optimal system 

performance. (Felix 2012) 

SRP also performs an annual study on its aggregate residential solar production, and because 

past studies have consistently shown that residential systems perform at or exceed SRP's 

expected 1,600 kWh/kW of capacity, SRP does not conduct 30-day system performance tests on 

residential systems. (Felix 2012) 

7.5 Administering PBI Payments

PBI programs require utilities to reimburse a system owner throughout the course of the PBI 

contract, which can result in significant administrative burden depending on the number of 

program participants and disbursement processes used by the program administrator. These 

disbursement processes can sometimes mean that the utility must issue a check to all participants 

in the program on a monthly basis, often for 10–15 years. Streamlined administrative processes 

are important for programs that operate over many years, and some software solutions are 

available to improve process efficiency. The method and frequency of crediting customers under 

a PBI system requires balancing administrative costs with the need for system owners to receive 

timely payments. In most cases, utilities disburse incentives monthly. To reduce the 

administrative cost of a PBI program, checks could be issued quarterly rather than monthly; 

however, this approach is less attractive to customer generators. Of the residential PBI programs 

listed in Table 8, only SMUD is disbursing PBI payments on a quarterly basis. 

On-bill crediting offers the advantage of minimizing costs over writing physical checks, while 

providing frequent crediting to customers. Contemplation of a move to such an on-bill PBI 

crediting system, however, must consider the upfront costs and efforts associated with modifying 

a utility's billing system. However, many utilities have faced such hurdles in modifying their 

billing systems to implement net metering and green power options. 

Of the eleven PBI programs in Table 8, three use on-bill crediting to administer PBI payments.23

Table 8 shows the residential PBI programs we examined, the manner in which each utility 

disburses payments to its customers, and the length of each program's PBI contract.

 

22 See http://cleanpower.com/products/powerclerk/, accessed December 15, 2012. 23 An example of offering a PBI credit on a customer’s bill can be found at the Orlando Utilities Commission 

website: http://www.ouc.com/en/pay_your_bill/how_to_read_your_bill.aspx?tabid=3.
34 

Table 8. PBI Programs, Length of Program and Incentive Disbursement Method

State Utility PBI Payment

Methoda

Length of PBI 

VT Green Mountain Power On Bill 10 years

FLb Orlando Utilities Commission On Bill 5 years (auto renewal)b

NM Public Service of New Mexico On Bill All PBIs terminate 12/31/2020

CA (CSI) San Diego Gas & Electric Check 5 years

CA (CSI) Southern California Edison Check 5 years 

CO Xcel Energy Check 10 years (RECs transfer for 20 years)

OR (OSPc)Idaho Power Check 15 years

CA (CSI) Pacific Gas and Electric Check 5 years

OR (OSPc)PacifiCorp (Pacific Power) Check 15 years

CA (CSI) Portland General Electric Check 15 years

CA SMUD (Sacramento) Quarterly check 5 years

Source: Utility websites

a All PBI payments are made monthly, with the exception of SMUD. 

b Orlando PBI contracts are automatically renewed in 5-year increments, with either party having the 

option to cancel with 60-days' notice. c Oregon Solar Incentive Program
35 

8 Consumer Protection and Transparency

Consumer protection measures typically involve helping ensure system performance, but can 

also relate to fair pricing, and encouraging investments in energy efficiently to reduce the 

necessary size of the investment in a PV systems. Consumer protections help establish the solar 

power industry in a particular locale as a reputable trade, which aids the spread and adoption of 

solar more widely throughout communities. Such requirements can also help lead to a 

sustainable solar market once incentive programs are no longer needed (Airth 2012). This section 

describes methods of encouraging optimal system performance, price transparency, and energy 

efficiency, as well as considerations of REC ownership. 

8.1 System Performance

Proper system performance is generally in the best interest of customers paying for systems, 

utilities that often need the generation to meet solar requirements, and ratepayers who fund 

incentive programs. 

Before 2006, concerns were raised that solar incentive programs, especially rebate programs, 

would not effectively incentivize optimal system production, as the reward of an incentive was 

based solely on capacity (Hoff 2006; Barbose et al. 2006). Since then, many rebate incentive 

programs have instituted performance-related prerequisites that systems must meet to qualify for 

maximum levels of incentives (see Table 9). Examples of performance requirements within a 

solar program include: 

• Mandatory installer certification and license requirements

• Minimum warranties on panels, inverters, and system performance

• Hardware requirements or equipment certification standards (e.g., UL listing) 

• Requirements for system orientation, tilt, azimuth, and shading 

Generally, utilities require applicants to comply with certification and licensing, warranties, and 

hardware requirements to be eligible for an incentive payment. Whereas utilities typically 

provide lower levels of incentives for systems that are not expected to perform optimally because 

of shading or sub-optimal orientation (e.g., north-facing systems). Often utilities will have a 

calculation for de-rating systems and adjusting incentive levels that considers system orientation, 

tilt, azimuth, and shading. Generally, these kinds of requirements are relatively easy for utilities 

to implement, although inspections may be required to ensure compliance with hardware 

requirements. 
36 

Table 9. Utility PV Program System Performance Requirements 

State Utility

Incentive Type Installer CertificationModule CertificationModule Warranty (Years)Inverter CertificationInverter Warranty (Years)Installer Guarantee (Years)System Orientation 

AZ APS PBI

TX Austin Energy PBI 20 10 5 

OH Columbus Southern Power 

(AEP) PBI

OR Idaho Power PBI

CA Pacific Gas and Electric (CSI) PBI 10 10 10

OR PacifiCorp 

(Pacific Power) PBI

OR Portland General Electric PBI

NM Public Service Company of 

New Mexico PBI

AZ Salt River Project PBI

1024

and 

20

10 2 and 

525

CA San Diego Gas & Electric 

(CSI) PBI 10 10 10

CA Southern California Edison 

(CSI) PBI 10 10 10

OH Ohio Power (AEP) PBI

AZ UniSource Energy Services PBI 20 5 5

VT Green Mountain Power PBI Must conform with Vermont state net metering laws to 

acquire certificate of good standing

FL Orlando Utilities Commission PBI

CO Xcel Energy PBI 5 5 5 

CA Sacramento Municipal Utility 

District PBI26 10 10 10

NY Long Island Power Authority PBI/FIT

AZ APS Rebate 27

TX Austin Energy Rebate 20 10 5 

OH Columbus Southern Power 

(AEP) Rebate >5 >5 >5

 

24 Modules must be guaranteed for 10 years against 10% degradation or worse; and must be guaranteed 20 years 

against 20% degradation or worse.

25 Installation must be guaranteed for 2 years against roof leaks, and 5 years against defects in overall installation 

resulting in 15% or greater level of performance. 26 PBI available for commercial customers only. 27 For leased systems, APS requires the leasing company to guarantee the system's production and components for 

20 years.
37 

State Utility

Incentive Type Installer CertificationModule CertificationModule Warranty (Years)Inverter CertificationInverter Warranty (Years)Installer Guarantee (Years)System Orientation 

TX 

CPS Energy 

(San Antonio)

residential

Rebate 20 5 1 

CA LADWP Rebate 28 20 10 10

OH Ohio Power (AEP) Rebate 5 5 5 

CA Pacific Gas & Electric (CSI) Rebate 10 10 10

AZ Salt River Project Rebate

10 

and 

20

10 2 and 

5 

CA San Diego Gas & Electric 

(CSI) Rebate 10 10 10

WA Snohomish County PUD No 1 Rebate 20 5 2 

CA Southern California Edison 

(CSI) Rebate 10 10 10

NY Long Island Power Authority Rebate 20 5

CA Pacific Power Rebate 29 10 10 10

AZ UniSource Energy Services Rebate 20 10 5

FL Gulf Power Rebate

CO Colorado Springs, City of Rebate 20 5 5

CA Sacramento Municipal Utility 

District Rebate 30 10 10 10

TX El Paso Electric Rebate 5 5 5

TX Southwestern Electric Power Rebate 10 10 10

As an example, CSI requires that solar modules and inverters be listed on the California Energy 

Commission’s website, possess a 10-year warranty (PBI payments are disbursed under CSI for 

only 5 years), and possess a UL1703 certification. Additionally, CSI stipulates that solar 

installers be appropriately licensed and encourages installer certification by North American 

Board of Certified Energy Practitioners. (California Public Utilities Commission 2011) The 

longevity and large size of CSI, coupled with these prerequisites for incentive payments has 

helped establish a high operating standard within California’s solar industry, which helps lead to 

a reputable solar installation industry. In addition, these prerequisites for incentive program 

participation mean that even at low incentive levels, assuming installers are still willing to 

complete the CSI application process, solar customers still receive a substantial degree of 

consumer protection for their systems. 

 

28 Systems may be installed by the customer. 29 Systems may be installed by the customer. 30 Systems may be installed by the customer.
38 

8.2 Installed Cost Transparency and Price Protection

A utility administering a solar incentive program is uniquely positioned to possess cost data for 

solar systems installed within its service territory because applicants must typically submit cost 

data with their application. Making data on installed costs publicly available can serve two 

purposes. First, doing so can protect solar customers who are unfamiliar with solar costs from 

extortive pricing. Second, making the data publicly available can help provide downward price 

pressure on the installer community, which should improve the likelihood of greater market 

penetration of solar in the future. Of course, competitive interests of installers should be 

protected, but aggregate statistics can be released without harming individual companies. For 

example, CSI provides extensive information on its website,31 including installations and pricing 

data, although transparency could likely be achieved with less detail than CSI provides. 

In addition to offering ample transparency and access to program data, CSI has instituted a cost 

cap for solar system applications to protect consumers from price gouging. New applicants that 

are quoted at an installed cost (on a per watt basis) that is greater than one standard deviation 

from the previous 12-month mean installation cost must submit a form signed by the customer 

explaining his or her understanding of that system’s elevated costs. (California Public Utilities 

Commission 2011 §3.4.5) In addition, the cost cap is transparently communicated to interested 

parties via a California Solar Statistics Web page listing answers to frequently asked questions 

(Go Solar California 2012). Another option for protecting customers from high pressure sales is 

to require installers to allow a three-day right to cancel, or similar provision (Airth 2012). 

8.3 Encouraging Energy Efficiency First

Investing in energy efficiency is often one of the most cost-effective measures a customer can 

take to decrease energy consumption. In some cases, efficiency can also help utilities shave peak 

demand. For consumers considering installing solar PV systems, examining all efficiency 

options first can help reduce the size of the PV system needed to offset a targeted portion of that 

customer's energy demand, which can result in substantial cost savings on a solar system (Airth 

2012). 

Some solar incentive programs require customers to participate in some form of baseline 

assessment – a full energy audit or otherwise – of the customer's building's energy efficiency in 

order to qualify for incentive payments. Such requirements can serve as a method of educating 

customers about energy efficiency options before making the investment in solar. Examples of 

utilities encouraging energy efficiency through solar incentive programs include the following: 

• SMUD instituted a procedure by which all solar incentive program applicants are 

informed of energy efficiency measures for a building that is the site of a proposed PV 

system before the design and installation (Sacramento Municipal Utility District 2012). 

• Gulf Power requires an on-site “energy check-up” for any property having its application 

approved for the receipt of incentives (Gulf Power 2012). 

 

31 http:/www.californiasolarstatistics.ca.gov/
39 

• Minnesota Power offers a bonus of $1.00/watt to its program’s existing $2.00/watt rebate 

if customers complete the ENERGY STAR Yardstick32 with a rating of 7 or greater 

(Minnesota Power 2012). 

• Austin Energy requires that all applicants to its residential solar rebate program meet 

minimum energy efficiency requirements (Austin Energy 2012). 

8.4 Ownership of Renewable Energy Certificates (RECs) 

In most cases, a utility administering a solar incentive program requires that RECs generated by 

a system receiving incentives be transferred to the utility. The utility typically uses these RECs to 

satisfy solar targets established within an RPS. As noted earlier, REC ownership provisions can 

be separated from the incentive payment period, as is done with rebate programs that acquire 

system RECs for long periods of time (e.g., 10-20 years) despite a one-time, up-front incentive 

payment. 

Some programs, such as CSI, do not require systems receiving incentive payments to sign over 

ownership of the RECs to the administering utility. In California, the CSI funded projects 

generally do not contribute to utility RPS requirements. In interviews, CSI administrators 

indicated they opted for customers to retain the RECs because much customer appeal for 

installing solar is for the environmental benefits of the electricity. Selling the RECs or essentially 

selling the environmental attributes of that system would defy customers’ desire to be “green.” 

Certainly, CSI customers have the prerogative to sell RECs associated with their solar generation 

in available markets, although market opportunities are limited at present outside of established 

SREC markets.

33

In addition to the investor-owned utilities operating under CSI, several other utilities allow

system owners to retain the RECs generated from the system. These include Pacific Power in 

California, Southwestern Electric Power Company of Texas, and Green Mountain Power of 

Vermont. Also, CPS Energy of San Antonio, Texas allows commercial system owners to retain 

the RECs produced from their systems if they are needed for compliance with Leadership in 

Energy and Environmental Design (LEED) certification. In this event, customers are offered 

reduced incentives in exchange for keeping their RECs. 

As solar incentives decline to zero, one consideration for program administrators is the handling 

of REC claims associated with solar generation. Typically, utilities have procured RECs from 

solar systems by offering financial incentives. TEP and APS have proposed to demonstrate 

compliance with solar obligations without acquiring the associated RECs – what they have 

termed a “track and record” approach.34 Because the utilities would be making a claim about the 

solar generation, they would inherently be using the RECs for compliance, which opens the REC 

market to double counting. Interveners in the case have also noted that the proposal would strip 

solar owners of their property rights without just compensation. A similar approach has been 

 

32 https://www.energystar.gov/index.cfm?fuseaction=home_energy_yardstick.showgetstarted 33 The markets available for selling SRECs outside of established SREC markets are limited, as only Missouri and 

North Carolina allow RECs produced by renewable generation from outside of Eastern markets to be used for RPS 

compliance. The California Public Utilities Commission recently allowed utilities to procure a limited amount of 

“unbundled” RECs to meet RPS mandates, but distributed solar would have to compete with utility-scale renewable 

generation for this limited market. 

34 See Dockets E‐01345A‐12‐0290 and E‐01345A‐10-0394. 
40 

tried in Hawaii. As result, Green-e Energy, the leading voluntary REC certification program, 

does not accept RECs from customer-sited, grid-connected renewable generation in Hawaii 

(Quarrier 2012).

The U.S. Department of Veterans Affairs and others have noted that the Department of Energy’s 

Renewable Energy Requirement Guidance of EPACT 2005 and Executive Order 13423 prohibits 

double counting by not allowing RECs to count towards federal goals if they are being used for 

compliance elsewhere (Cordova 2012). The Arizona case is still pending at the Arizona 

Corporation Commission.

9 Best Practices for Incentivizing Solar

Dozens of utilities throughout the United States offer incentive programs designed to encourage 

the adoption of solar energy. In recent years, various design and implementation methods have 

emerged as utilities have attempted to respond to changing solar market conditions and meet 

consumer demand. Based on a review of existing program experience and interviews with 

various stakeholders including program administrators, regulators, and industry representatives, 

we developed the following list of best practices for designing and implementing solar incentive 

programs. These best practices consider the perspectives of various stakeholders and the broad 

objectives of reducing solar costs, encouraging long-term market viability, minimizing ratepayer 

costs, and protecting consumers.

• Consider rebates coupled with performance guarantees for incentivizing small customerowned systems: Rebates reduce upfront system costs, which can be very important for 

residential customers in particular, who may face challenges in financing systems if thirdparty owned options are unavailable. Because rebates based on nameplate capacity alone 

do not ensure performance, rebates can be coupled with pre-requirements to help ensure 

that solar systems are properly designed and installed, and that they use equipment that 

will perform effectively. Programs may wish to incentivize both customer-owned and 

third-party owned systems to encourage diversity in ownership models. 

• Consider moderate-term PBIs with on-bill crediting for commercial-scale and thirdparty owned systems: PBIs can be an effective method of incentivizing third-party owned 

and larger-scale systems that can take advantage of future revenue streams in financing. 

Using PBIs can minimize the strain on limited program budgets by spreading incentive 

costs over several years, compared to upfront incentives, which are paid when systems are 

installed. Important considerations for establishing PBIs are the frequency of payments and 

the method of payment disbursement. While payment terms currently range from 5 to 20 

years, shorter payment periods (on the order of 5 years) can minimize long-term 

administrative burden and the necessary duration of the program. In addition, system 

owners more highly value payments in early years because of the time value of money. 

However, for a program to be effective, payments need to be sufficient in size and duration 

to encourage installations, and considerations of costs to ratepayers over the period must 

be balanced with selection of the term of payments. Further, on-bill crediting of PBI 

incentives is preferable to ensure timely payment to customers as well as to minimize the 

administrative costs of issuing checks over the duration of the incentive payment term. 
41 

• Use multiple approaches and data sources to evaluate appropriate incentive levels: With 

rapidly changing market conditions, utilities can use a variety of methods to ensure that it 

offers accurate incentive levels. Data on installed costs can be used to calculate expected 

returns on investment and payback periods, with publicly available models. In addition, 

utilities can benchmark incentive levels and uptake in nearby utility service territories. If a 

program involves a long commission approval process, it may be important to maintain 

some flexibility in the payment levels, as market conditions could change over the course 

of the approval process. Furthermore, initial stages of a program can offer incentives for a

limited amount of capacity to test uptake rates at a specified payment level. 

• Consider different incentive structures to encourage various market segments: Because 

the economics of systems vary substantially by size (i.e, rate structure, financing 

arrangements), it is important to develop incentives that align with the needs of each 

market segment. The classes of systems that a program seeks to incentivize may be 

influenced by ratepayer considerations, grid benefits, market diversity, building support 

for the program, and balancing program costs. A combination of approaches is generally 

needed to incentivizing multiple market segments. For example, rebates or PBIs with preestablished step-down levels may be appropriate for small- to medium-sized systems, and 

competitive solicitations or auctions may be particularly important to competitively price 

incentives for larger systems. At least one utility has used a streamlined auction process 

for all sizes of commercial systems, thus introducing competitive pricing to the smaller 

system market segment as well. 

• Modify incentive-levels to respond to changing market conditions: To maintain 

appropriate incentive levels when solar costs shift, programs have found it necessary to 

develop processes to modify incentives levels periodically. Two primary options in use 

today are an established step-down schedule or a competitive solicitation or auction 

processes for setting market prices. The primary advantages of the step-down approach are 

simplicity, transparency, and certainty for market participants. Further, a step-down 

program can encourage consumers to act before incentives are reduced. A disadvantage to 

step-down schedules is that incentive levels are established in advance and may not 

continuously align with market conditions; thus, incentives could fall too rapidly, halting 

installations, or fall too slowly, resulting in overpayment for installed capacity.

Alternatively, a step-down program could be implemented so that steps are adjusted over 

time, which could align incentive levels more directly with market conditions but reduce 

transparency and certainty. An auction or competitive solicitation theoretically leads to the 

most accurate pricing and minimizes incentive payments, but it provides less certainty to 

market participants about future incentive levels. Auctions may also be prohibitively 

complex for determining incentives for small customer-owned systems in particular, 

although at least one program successfully implemented a simplified auction mechanism 

for all sizes of commercial systems. A combination of approaches could also be used with 

pre-established step-down levels for small- to medium-sized systems, and auctions for 

larger systems.
42 

• Use multiple steps and communicate progress clearly when establishing incentive stepdown schedules: Creating multiple stages in a step-down program can create conditions, if 

set at appropriate levels, that encourage customers to install solar before the next decline in 

incentives. This can create a condition in which solar is always “on-sale.” Another 

important aspect of this design is to ensure that customers can clearly discern how much 

capacity or budget is available in a particular step so that they can determine what level of 

incentive is currently available. Utilities can convey this information by maintaining timely 

and accurate information on program progress on the internet. 

• Manage project flow and incentive offer periods to encourage a more stable market: For 

programs with limited budgets, offering incentives more frequently than annually can help 

promote a greater degree of market stability. In contrast to offering a limited budget for 

incentives once per year—allowing that budget to become exhausted and lead to periods of 

solar market inactivity—spreading incentive budgets over the course of the year can help 

encourage steady market participation throughout the year. Further, offering incentives 

through multiple application periods can allow a utility to adjust incentive levels according 

to program uptake and market conditions, as necessary.

• Institute consumer protection measures to encourage reputable business practices that 

help ensure the long-term viability of the solar industry: The most common consumer 

protection measures aim to provide checks to ensure optimal system performance and to 

educate customers about energy efficiency options that help them appropriately size solar 

systems. Other, less commonly incorporated, but potentially important measures, aim to 

protect customers from price gouging by making aggregate data on installed costs publicly 

available and alerting customers to systems that are above average cost.

• Consider offering bonus incentives to systems that provide grid benefits: PV systems 

have the potential to offer benefits to the grid by deferring transmission and distribution 

investments or if sited in areas with substantial congestion. Bonus incentive payments can 

be offered to encourage systems to be sited in areas where they are most beneficial to the 

utility grid. 

• Ensure equitable access to incentives through fair queuing processes: Particularly for 

programs with limited budgets, ensuring equitable access to incentives is important for the 

perceived success of the program. Transparent queuing processes and administrative 

processes that minimize the risk of gaming are important for encouraging market stability. 

• Require modest fees to minimize administrative burdens: Most programs charge modest 

fees, which can be refundable, to ensure that projects submitted for incentives are viable 

and that project owners have some “skin in the game.” This can preserve staff time and 

save administrative costs by helping encourage only serious project applications and 

focusing staff time on viable projects.
43 

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http://www.ladwpnews.com/go/doc/1475/1130871/LADWP-Announces-Proposed-Relaunch-ofSolar-Incentive-Program-and-Introduces-Feed-In-Tariff-Program-to-Expand-Local-Solar-inBriefing-to-Board-of-Water-and-Power-Commissioners. 

Los Angeles Department of Water and Power. (2012). LADWP Feed-in Tariff Demonstration 

Program – Frequently Asked Questions. Accessed August 2012: https://www.ladwp.com/cs/ 

idcplg?IdcService=GET_FILE&dDocName=OPLADWP011834&RevisionSelectionMethod=La

testReleased. 

Los Angeles Department of Water and Power. (2012). Program Status and Incentive Levels. 

Accessed August 2012: https://www.ladwp.com/ladwp/faces/ladwp/residential/r-gogreen/r-gginstallsolar/r-gg-isprogstusincetlvl;jsessionid=XZJhQcGTqCc9wCs51h2TnDFHlvKk2FwQD2LGyZB7cMDLbf56

MVNr!-1529791867?_adf.ctrlstate=nswihfbn6_4&_afrLoop=925954789595000&_afrWindowMode=0&_afr. 
46 

Mace, F. (29 August 2012). Communication with NYSERDA Program Manager and Solar Team 

Lead. NREL. Golden, CO. 

Minnesota Power. (undated). Renewable Energy - Solar Electric Option. Accessed July 19, 

2012: http://www.mnpower.com/powerofone/renewable_energy/solarsense/solar_electric.htm. 

Minnesota Power. (2012). Solar Sense - Solar Electric Option. Accessed July 19, 2012: 

http://www.mnpower.com/powerofone/renewable_energy/solarsense/solar_electric.htm. 

“PV Watts v.2.” (undated). National Renewable Energy Laboratory. Accessed August 2012: 

http://www.nrel.gov/rredc/pvwatts/. 

NYSERDA. (2012, August). Solar PV Program Manual Version 5.0. Accessed August 2012: 

http://www.nyserda.ny.gov/Programs/Renewables/~/media/Files/FO/Current%20Funding%20O

pportunities/PON%202112/2112atth.ashx. 

Oregon Public Utility Commission. (2012). Solar PV Systems Incentive Rate Pilot Program. 

Accessed August 2012: http://cms.oregon.gov/PUC/solar/SolarIncentivePilotProgram

20712.pdf?ga=t. 

Oregon State Legislature. Relating to feed-in tariffs on solar photovoltaic energy systems; 

creating new provisions; amendingORS 757.360 and 757.365; and declaring an emergency. 

House Bill 3690, HB 3690-A (February 2010). 75th Oregon Legislative Assembly, 2010 Special 

Session: pp. 1-3, http://www.leg.state.or.us/10ss1/measpdf/hb3600.dir/hb3690.en.pdf. 

Pacific Power (CA). (undated). Pacific Power California Solar Incentive Program. Accessed 

August 2012: http://www.pacificpowercasolar.com/solar-incentives.html. 

Pacific Power. (2012, April). Capacity Reservation Application. Accessed July 19, 2012: 

http://www.pacificpower.net/content/dam/pacific_power/doc/Efficiency_Environment/Net_Mete

ring_Customer_Generation/smallosip/CapacityReservationApplicationInformation.pdf. 

Pacific Power. (undated). Pacific Power California Solar Incentive Program. Accessed August 

2012: http://www.pacificpowercasolar.com/solar-incentives.html. 

Public Service Company of New Mexico. (2002-2012). Solar Energy Incentive Program: REC 

Prices. Accessed August 2012: http://www.pnm.com/customers/pv/rec_price_table.htm 

?source=solar_home. 

Public Utility Commission of Oregon. (2011). Solar Photovoltaic Volumetric Incentive Rate 

Pilot Program. Accessed December 17, 2012: http://www.oregon.gov/puc/docs/ 

123010finalsolarreport.pdf. 

Quarrier, R. (2012). “Comments submitted in Dockets E‐01345A‐12‐0290 and E‐01345A‐10-

0394.” November 16, 2012: http://images.edocket.azcc.gov/docketpdf/0000140799.pdf. 

Rabago, K.; Libby, L.; Harvey, T.; Norris, B.; Hoff, T. (2012). Designing Austin Energy's solar 

Tariff Using a Distributed PV Value Calculator. Accessed December 17, 2012: 

http://www.cleanpower.com/wp-content/uploads/090_DesigningAustinEnergysSolarTariff.pdf. 
47 

Read, R. (2012). “Oregon Solar Program Fills in 15 Minutes Leaving Some Customers Excited 

and Others Frustrated.” The Oregonian. Accessed August 2012: 

http://www.oregonlive.com/business/index.ssf/2010/07/oregons_new_solar_program_fill.html. 

Sacramento Municipal Utility District. (2012). SMUD PV Program Handbook. Accessed July 

19, 2012: https://www.smud.org/en/residential/environment/solar-for-yourhome/documents/SMUD%20PV%20Program%20Handbook%2003-01-11.pdf. 

SEIA/GTM Research. (2012). “U.S. Solar Market Insight - Q1 2012.” GTM Research and Solar 

Energy Industries Association. 

SEIA/GTM Research. (2012). “U.S. Solar Market Insight Q4 2011 & 2011 Year-In-Review.” 

Smith, C. (2011). “Solar Company Says GRU Isn’t Fair.” The Gainesville Sun, Gainesville.com. 

Accessed August 2012: http://www.gainesville.com/article/20111122/ARTICLES/

111129829?p=1&tc=pg. 

Xcel Energy. (2012). “Sample Application Fee Form.” Accessed July 19, 2012: 

http://www.xcelenergy.com/staticfiles/xe/Marketing/Managed%20Documents/MN-SRApplication-Fee-Form.pdf. 
48 

Appendix. Solar Incentive Programs Analyzed

Tables A-1 and B-1 list the residential and commercial solar incentive programs, respectively that were analyzed for this report. Program data are 

from the Database of State Incentives for Renewables & Efficiency, as of July 2012. 

Table A-1. Residential Incentive Programs

State Utility/Program 

Administrator 

System 

Size 

(kW)

Incentive 

Type

Rebate 

($/watt) PBI 

Length 

(years)

System

Owner

Cost of 

Solar 

($/W)35

Cost of Retail 

Electricity

(¢/kWh)36

Expected 

Annual 

kWh-AC

(4 kW)37

Max.

Benefit or 

Capacity 

Limit PBI ($/kWh)

AZ Arizona Public Service < 30 Rebate $0.20 DC n/a 6.680 8.733 6,184 40% or 

$75,000

TX Austin Energy 1 – 20 Rebate $2.00 AC n/a 6.010 9.365 5,359 $15,000 

CO Colorado Springs Utilities .5 – 10 Rebate $1.80 Customer 5.900 8.967 5,831

Size 

<120% of 

demand

OH Columbus Southern Power > 2 Rebate $1.50 n/a 5.860 7.677 4,497 50% or 

$12,000

TX CPS Energy 1 – 25 Rebate $2.00 Customer 6.010 8.565 5,513 $25,000 

TX El Paso Electric 1 – 50 Rebate $2.00 DC n/a 6.010 10.666 6,381 $20,000

FL Gulf Power < 5 Rebate $2.00 Customer 5.750 8.637 4,959 $10,000

NY Long Island Power Authority < 10 Rebate $1.75 DC Customer 5.520 17.516 4,791 50% or 

$17,500

MN Minnesota Power < 100 Rebate $2.00 DC Unknown 0.000 8.217 4,641 $20,000 

or 60%38

MN Northern States Power Co. .5 – 40 Rebate $2.25 DC Customer 0.000 8.136 4,897 $90,000 

or 60%

NY

New York State Energy 

Research & Development 

Authority (NYSERDA)

< 7 Rebate $1.50 n/a 5.520 19.743 

(NYC) 4,791 $10,500 or 40%

OH Ohio Power 2 – 8 Rebate $1.50 n/a 5.860 7.677 4,497 50% or 

$12,000

CA Pacific Power 1 – 

5,000 Rebate $1.13 AC n/a 6.480 8.388 5,267

Incentive 

capped at 

250 kW

 

35 Average cost of solar by state ($/Watt DC) (SEIA/GTM Research 2012) 36 PV Watts (http://www.nrel.gov/rredc/pvwatts/) 37 PV Watts (http://www.nrel.gov/rredc/pvwatts/) 40 Auto-renewal of PBI agreement occurs in 5-year increments. PBI agreement can be voided with 60-days notice from either party.
49 

State Utility/Program 

Administrator 

System 

Size 

(kW)

Incentive 

Type

Rebate 

($/watt) PBI 

Length 

(years)

System

Owner

Cost of 

Solar 

($/W)35

Cost of Retail 

Electricity

(¢/kWh)36

Expected 

Annual 

kWh-AC

(4 kW)37

Max.

Benefit or 

Capacity 

Limit PBI ($/kWh)

CA PG&E (CSI) < 30 Rebate $0.20 n/a 6.480 12.354 5,737

Incentive 

capped at 

1 MW

AZ Salt River Project Rebate $0.50 n/a 6.680 8.659 6,187 $2,000

CA SDG&E (CSI) 1 – 30 Rebate $0.20 n/a 6.480 17.288 5,921

Incentive 

capped at 

1 MW

WA Snohomish County PUD No 

1 < 100 Rebate $0.50 DC Customer 6.700 6.879 3,851 $2,500 

CA SCE (CSI) 1 – 30 Rebate $0.35 n/a 6.480 12.070 6,105

Incentive 

capped at 

1 MW

TX Southwestern Elec. Power < 2,000 Rebate $1.75 DC n/a 6.010 6.643 5,299

$17,500; 

size 

cannot 

exceed 

demand.

AZ UniSource Energy Services 1.2 – 30 Rebate $0.85 DC39 Unknown 6.680 10.065 6,495

50% of 

system 

cost

OH Columbus Southern Power < 100 PBI $0.263 Ends

6/2013 n/a 5.860 7.677 4,497

REC 

purchase:

$262.50

VT Green Mountain Power < 250 PBI $0.060 10 Unknown 5.630 14.042 4,550 None 

specified

OR Idaho Power Co

< 10

PBI

$0.317

10 – 15 n/a 6.72 7.232 5,010 

100 $0.250

Los Angeles Department of 

Water and Power < 1000 Rebate $1.62 AC Customer 6.480 11.502 5867 75% $1.50 AC Third-Party

WI Madison Gas & Electric Co 1 – 10 PBI $0.250 10 n/a 5.840 10.065 4,883 None 

specified

OH Ohio Power Co < 100 PBI $0.263 Ends

6/2013 n/a 5.860 7.677 4,497

REC 

purchase: 

$262.50

 

40 Auto-renewal of PBI agreement occurs in 5-year increments. PBI agreement can be voided with 60-days notice from either party.
50 

State Utility/Program 

Administrator 

System 

Size 

(kW)

Incentive 

Type

Rebate 

($/watt) PBI 

Length 

(years)

System

Owner

Cost of 

Solar 

($/W)35

Cost of Retail 

Electricity

(¢/kWh)36

Expected 

Annual 

kWh-AC

(4 kW)37

Max.

Benefit or 

Capacity 

Limit PBI ($/kWh)

FL Orlando Utilities

Commission < 2,000 PBI $0.050 540 n/a 5.750 9.260 5,360 None specified

CA PG&E (CSI)

1 – 30

PBI $0.025 5 n/a 6.480 12.354 5,737

Incentive 

capped at 

1 MW > 30

OR PacifiCorp 

< 10

PBI

$0.411

15 n/a 6.72

6.659 4,269

 

< 10 $0.346 7.25 4,639

< 10 $0.317 7.232 5,010

10 –

100 $0.285 6.659 4,269

10 –

100 $0.250 7.25 4,639

10 –

100 $0.250 7.25 4,639

NM Public Service NM

< 10

PBI

$0.060 12

n/a 5.410 8.207 6,235 None 

specified

10 –

100 $0.050 Ends

12/202

0 

100 –

1,000 $0.020

> 1,000 $0.070

OR Portland General Electric

< 10

PBI

$0.411

15 n/a

6.72 6.659 4,269

< 10 $0.346 6.72 7.232 5,010

10 –

100 $0.285 6.72 6.659 4,269

10 –

100 $0.250 6.72 7.232 5,010

CA SDG&E (CSI) 1 – 30 PBI $0.025 5 n/a 6.480 17.288 5,921

Incentive 

capped at 

1 MW

CA SCE (CSI) 1 – 30 PBI $0.044 5 n/a 6.480 12.070 6,105

Incentive 

capped at 

1 MW

CO Xcel Energy

.5 – 10

PBI

$0.150

10

Customer

5.900 8.556 5,813

Size 

<120% of 

demand

.5 – 10 $0.100 Third-party

10 –

500 $0.090 n/a

 

40 Auto-renewal of PBI agreement occurs in 5-year increments. PBI agreement can be voided with 60-days notice from either party.
51 

State Utility/Program 

Administrator 

System 

Size 

(kW)

Incentive 

Type

Rebate 

($/watt) PBI 

Length 

(years)

System

Owner

Cost of 

Solar 

($/W)35

Cost of Retail 

Electricity

(¢/kWh)36

Expected 

Annual 

kWh-AC

(4 kW)37

Max.

Benefit or 

Capacity 

Limit PBI ($/kWh)

OH Duke Energy Ohio PBI REC prices 15 n/a 5.860 7.272 4,832
52 

Table A-2. Commercial Incentive Programs

State Utility

System 

Size 

(kW)

Type

Rebate ($/watt) PBI 

Length 

(years)

System

Owner

Cost 

of 

Solar 

($/W) 41

Cost of 

Retail 

Elec. 

(¢/kWh) 42

Expected 

Annual 

kWh-AC 

(4 kW)43

Max. 

Benefit or 

Capacity PBI ($/kWh) Limitation

CO Colorado Springs, City of .5 – 25 Rebate $1.80 Customer 5.050 8.967 5,831

OH Columbus Southern Power > – 10 Rebate $1.50 n/a 4.730 7.677 4,497 50% or 

$175,000

TX CPS Energy 1 – 25 Rebate $2.00 Customer 6.460 8.565 5,513 $25,000 

TX El Paso Elec. Co 1 – 50 Rebate $1.75 DC n/a 6.460 10.666 6,381 $87,500 

FL Gulf Power Co < 5 Rebate $2.00 Customer 4.270 8.637 4,959 $10,000

NY Long Island Power Authority < 50 Rebate $1.30 DC Customer 6.050 17.516 4,791 $65,000 or 

50%

MN Minnesota Power Inc. < 100 Rebate $2.00 DC Unknown 0.000 8.217 4,641

$20,000 or 

60% 

(+bonus)

OH Ohio Power Co (AEP) 10 – 50 Rebate $1.50 n/a 4.730 7.677 4,497 50% or 

$75,000

CA PG&E (CSI) 1 – 30 Rebate $0.20 n/a 5.140 12.354 5,737

CA Pacific Power 1 – 5,000 Rebate $0.63 AC n/a 5.140 8.388 5,267 $157,500

AZ Salt River Project < 100 Rebate $0.50 n/a 5.910 8.659 6,187

CA SDG&E (CSI) 1 – 30 Rebate $0.35 n/a 5.140 17.288 5,921

WA Snohomish City PUD No 1 < 100 Rebate $0.50 DC Unknown 5.190 6.879 3,851 $10,000 

CA SCE (CSI) 1 – 30 Rebate $0.35 n/a 5.140 12.070 6,105

AZ UniSource Energy Services < 70 Rebate $0.50 DC Unknown 5.910 10.065 6,495 50% 

AZ Arizona Public Service 30 –

2,000 PBI Competitive Bidding

10, 15, or 

20 n/a 5.910 8.733 6184 50% up to $75,000

TX Austin Energy < 20 PBI $0.140 10 n/a 6.460 9.365 5359

$.035 

potential 

bonus44

CO Black Hills Energy < 3 PBI $0.122 10 Third 5.050 9.088 5948 3 – 10 $0.108

OH Columbus Southern Power < 100 PBI $0.263 Ends

6/2013 n/a 4.730 7.677 4497

REC 

purchase: 

$262.50

 

41 Average cost of solar by state ($/Watt DC) (SEIA/GTM Research 2012) 42 PVWatts (http://www.nrel.gov/rredc/pvwatts/) 43 PVWatts (http://www.nrel.gov/rredc/pvwatts/) 44 Bonus for locally manufactured system components
53 

State Utility

System 

Size 

(kW)

Type

Rebate ($/watt) PBI 

Length 

(years)

System

Owner

Cost 

of 

Solar 

($/W) 41

Cost of 

Retail 

Elec. 

(¢/kWh) 42

Expected 

Annual 

kWh-AC 

(4 kW)43

Max. 

Benefit or 

Capacity PBI ($/kWh) Limitation

VT Green Mountain Power Corp. < 250 PBI $0.060 10 Unknown 5.340 14.042 4550

OR Idaho Power Co < 10 PBI $0.317 15 n/a 4.94 7.232 5010 10 – 100 $0.250

WI Madison Gas & Electric Co 1 – 10 PBI $0.250 10 Customer 6.330 10.065 4883

NY

New York State Energy 

Research & Development 

Authority (NYSERDA)

< 50 Rebate $1.50 n/a 5.520 19.743 

(NYC) 4,791 $60,000 or 40%

NY

New York State Energy 

Research & Development 

Authority (NYSERDA)

> 50 PBI Competitive 

Bidding 3 n/a 5.520 19.743 (NYC) 4,791 $1M

OH Ohio Power Co (AEP) < 100 PBI $0.263 Ends 

6/2013 n/a 4.730 7.677 4497

REC 

purchase: 

$262.50

FL Orlando Utilities Commission < 2,000 PBI $0.050 545 Customer 4.270 9.260 5360

No 

maximum 

specified

CA PG&E (CSI)

1 – 30

PBI $0.025 5 n/a

5.140 12.354 5737

30 –

1,000 5.140 12.354 5737

OR PacifiCorp

< 10

PBI

$0.411

15 n/a 4.94

6.659 4269

< 10 $0.346 7.232 5010

< 10 $0.317 7.232 5010

10 – 100 $0.285 6.659 4269

10 – 100 $0.250 7.232 5010

10 – 100 $0.250 7.232 5010

NM PNM

< 10

PBI

$0.050 12

Customer 4.500 8.207 6235

10 – 100 $0.050 Ends

12/2020 100 –

1,000 $0.020

> – 1,000 $0.070 n/a46

OR Portland Gen Electric Co

< 10

PBI

$0.411

15 n/a 4.94

6.659 4269

< 10 $0.346 7.232 5010

10 – 100 $0.285 6.659 4269

 

45 PBI agreement renews automatically after five years until terminated with 60-days notice by either party. 46 Fully subscribed as of August 2012
54 

State Utility

System 

Size 

(kW)

Type

Rebate ($/watt) PBI 

Length 

(years)

System

Owner

Cost 

of 

Solar 

($/W) 41

Cost of 

Retail 

Elec. 

(¢/kWh) 42

Expected 

Annual 

kWh-AC 

(4 kW)43

Max. 

Benefit or 

Capacity PBI ($/kWh) Limitation

10 – 100 $0.250 7.232 5010

AZ Salt River Project 100 –

1,000 PBI $0.050 20 n/a 5.910 8.659 6187 

CA SDG&E (CSI)

1 – 30

30 – PBI $0.044 5 n/a 5.140 17.288 5921

1,000

CA SCE (CSI)

1 – 30

30 – PBI $0.044 5 n/a 5.140 12.070 6105 

1,000

AZ UniSource Energy Services

70 – 200

PBI

$0.092

10, 15 or 

20 Unknown 5.910 10.065 6495 201 –

400 $0.088

> 401 $0.084

CO Xcel Energy

.5 – 10

PBI

$0.150 20 Customer

5.900 8.556 5813

System 

<120% of 

annual 

demand

.5 – 10 $0.100 Thirdparty

10 – 500 $0.090

Customer

or Thirdparty

> 500 RFP 

Customer

or Thirdparty

CA SMUD No limit Rebate or 

PBI

$0.65 AC or

$0.100/kWh 5 n/a 6.480 11.274 5638 No limit

AZ Arizona Public Service < 30 Rebate or 

PBI

$0.60 DC or

PBI

10, 15 or 

20 Customer 5.910 8.733 6184 50% or $75,000

CA Sacramento Municipal Utilities 

District

< 1,000 Rebate or 

PBI

$0.65 AC or

$0.100/kWh 5 

n/a 5.140 11.274 5638 $1 million 

$0.65 AC or for rebate

$0.060.kWh 10