ML103620067

2010/12/28-Rooftop Photovoltaics Market Penetration Scenarios

ML103620067
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Site:	Davis Besse
Issue date:	12/28/2010
From:	Sawyer H, Frantzis L, Kurrasch A, Paidipati J Navigant Consulting, National Renewable Energy Lab, US Dept of Energy, Office of Energy Efficiency & Renewable Energy
To:	Atomic Safety and Licensing Board Panel
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A national laboratory of the U.S. Department of Energy Office of Energy Efficiency & Renewable Energy National Renewable Energy Laboratory Innovation for Our Energy Future Subcontract Report Rooftop Photovoltaics Market NREL/SR-581-42306 Penetration Scenarios February 2008 J. Paidipati, L. Frantzis, H. Sawyer, and A. Kurrasch Navigant Consulting, Inc.

Burlington, Massachusetts NREL is operated by Midwest Research Institute Battelle Contract No. DE-AC36-99-GO10337

Subcontract Report Rooftop Photovoltaics Market NREL/SR-581-42306 Penetration Scenarios February 2008 J. Paidipati, L. Frantzis, H. Sawyer, and A. Kurrasch Navigant Consulting, Inc.

Burlington, Massachusetts NREL Technical Monitor: Robert Margolis Prepared under Subcontract No. KACX-4-44451-08 National Renewable Energy Laboratory 1617 Cole Boulevard, Golden, Colorado 80401-3393 303-275-3000

• www.nrel.gov Operated for the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy by Midwest Research Institute

• Battelle Contract No. DE-AC36-99-GO10337

NOTICE This report was prepared as an account of work sponsored by an agency of the United States government.

Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.

Available electronically at http://www.osti.gov/bridge Available for a processing fee to U.S. Department of Energy and its contractors, in paper, from:

U.S. Department of Energy Office of Scientific and Technical Information P.O. Box 62 Oak Ridge, TN 37831-0062 phone: 865.576.8401 fax: 865.576.5728 email: mailto:reports@adonis.osti.gov Available for sale to the public, in paper, from:

U.S. Department of Commerce National Technical Information Service 5285 Port Royal Road Springfield, VA 22161 phone: 800.553.6847 fax: 703.605.6900 email: orders@ntis.fedworld.gov online ordering: http://www.ntis.gov/ordering.htm This publication received minimal editorial review at NREL Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste

Preface Now is the time to plan for the integration of significant quantities of distributed renewable energy into the electricity grid. Concerns about climate change, the adoption of state-level renewable portfolio standards and incentives, and accelerated cost reductions are driving steep growth in U.S. renewable energy technologies. The number of distributed solar photovoltaic (PV) installations, in particular, is growing rapidly. As distributed PV and other renewable energy technologies mature, they can provide a significant share of our nations electricity demand. However, as their market share grows, concerns about potential impacts on the stability and operation of the electricity grid may create barriers to their future expansion.

To facilitate more extensive adoption of renewable distributed electric generation, the U.S.

Department of Energy launched the Renewable Systems Interconnection (RSI) study during the spring of 2007. This study addresses the technical and analytical challenges that must be addressed to enable high penetration levels of distributed renewable energy technologies.

Because integration-related issues at the distribution system are likely to emerge first for PV technology, the RSI study focuses on this area. A key goal of the RSI study is to identify the research and development needed to build the foundation for a high-penetration renewable energy future while enhancing the operation of the electricity grid.

The RSI study consists of 15 reports that address a variety of issues related to distributed systems technology development; advanced distribution systems integration; system-level tests and demonstrations; technical and market analysis; resource assessment; and codes, standards, and regulatory implementation. The RSI reports are:

• Renewable Systems Interconnection: Executive Summary

• Distributed Photovoltaic Systems Design and Technology Requirements

• Advanced Grid Planning and Operation

• Utility Models, Analysis, and Simulation Tools

• Cyber Security Analysis

• Power System Planning: Emerging Practices Suitable for Evaluating the Impact of High-Penetration Photovoltaics

• Distribution System Voltage Performance Analysis for High-Penetration Photovoltaics

• Enhanced Reliability of Photovoltaic Systems with Energy Storage and Controls

• Transmission System Performance Analysis for High-Penetration Photovoltaics

• Solar Resource Assessment

• Test and Demonstration Program Definition

• Photovoltaics Value Analysis

• Photovoltaics Business Models iii

• Production Cost Modeling for High Levels of Photovoltaic Penetration

• Rooftop Photovoltaics Market Penetration Scenarios.

Addressing grid-integration issues is a necessary prerequisite for the long-term viability of the distributed renewable energy industry, in general, and the distributed PV industry, in particular.

The RSI study is one step on this path. The Department of Energy is also working with stakeholders to develop a research and development plan aimed at making this vision a reality.

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Acknowledgments Navigant Consulting Inc. (NCI) would like to first thank the U.S. Department of Energy (DOE) and the DOE National Renewable Energy Laboratory (NREL) for sponsoring this work. NCI would also like to thank the McGraw-Hill Companies for providing floor space data, a crucial component of this study. Furthermore, many independent reviewers took the time to review this report and provide valuable insights; their efforts were very much appreciated.

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List of Acronyms BAU business as usual scenario CBECS Commercial Building Energy Consumption Survey DOE U.S. Department of Energy EIA Energy Information Administration FERC Federal Energy Regulatory Commission IREC Interstate Renewable Energy Council MW megawatt MWh megawatt-hour NCI Navigant Consulting, Inc.

NREL National Renewable Energy Laboratory O&M operation and maintenance RECS Residential Energy Consumption Survey RPS Renewable Portfolio Standard RSI Renewable System Integration (study)

SAI Solar America Initiative TOU time of use vi

Executive Summary The goal of this study was to model the market penetration of rooftop photovoltaics (PV) in the United States under a variety of scenarios, on a state-by-state basis, from 2007 to 2015.

The study was performed by Navigant Consulting Inc. (NCI) for the U.S. Department of Energy (DOE) under a subcontract to the DOE National Renewable Energy Laboratory. The model looked at the retrofit and new construction segments of the residential and commercial rooftop markets. For each state, the model calculated the market penetration percent, annual installations, and cumulative installations. The scenarios studied included net metering rules, electric rate tariff levels and structures, the availability of financial incentives, system pricing, and carbon legislation.

To perform the market penetration analysis, NCI first calculated the technical potential for PV implementation for each of the 50 states by using data on floor space, building characteristics, PV solar access factors, and PV system efficiency. Next, based on a selection of 98 representative utilities within the states and the District of Columbia, NCI calculated economic potential using current electric rate structures and tariffs, local and federal incentive levels, system costs, operation and maintenance (O&M) and inverter replacement costs, building load profiles, PV output profiles, and net metering rules. This work yielded a simple payback period, which was incorporated into a market penetration curve. To arrive at the final estimate of economic potential, the market penetration results were augmented by a technology adoption curve, screens related to interconnection standards, and Renewable Portfolio Standard (RPS) solar set-aside requirements.

NCI ran a variety of scenarios to examine the impacts of different variables, including variations on system pricing, interconnection standards, net metering availability, net metering caps, carbon legislation, electric price escalation, availability of time-of-use rates, RPS enforcement, and availability of federal and local incentives for PV. The variables with the largest impact on market penetration were system pricing, net metering policy, extending the commercial and residential federal tax credits to 2015 (as opposed to our baseline assumption of commercial incentives to 2015 and residential ones to 2010), and interconnection policy, as shown in Figure E-1.

Figure E-1 illustrates that there is significant potential in the United States for PV on buildings. However, several variables that were not modeled in this study could impact the results. Constraints along the PV supply chain (such as the current silicon shortage) could result in higher module prices or constrained supply, thus decreasing market penetration. In addition, significant international demand could draw supply away from the U.S. market, thus decreasing U.S. market penetration. In contrast, new state or federal policies, such as incentive programs or RPS, could drive U.S. demand even higher.

vii

30,000 + INT Cumulative Installations [MW]

25,000

+ ITC 20,000

+ Net 15,000

+ Pricing 10,000 5,000 Base 0

20 20 20 20 20 2001 02 03 04 05 20 20 20 20 2006 07 08 09 10 11 20 20 20 2012 13 14 Year 15 Figure E-1. Influence on cumulative U.S. PV installations of system pricing, net metering policy, federal tax credits, and interconnection standards viii

Table of Contents 1.0 Introduction........................................................................................................................................... 1 2.0 Current Status of the Research........................................................................................................... 2 3.0 Project Approach.................................................................................................................................. 3 3.1 Technical Potential...............................................................................................................3 3.2 Preliminary Economic Potential ..........................................................................................7 3.3 Scenarios Analyzed............................................................................................................10 4.0 Project Results.................................................................................................................................... 15 4.1 The Worst Case..................................................................................................................15 4.2 The Base Case....................................................................................................................17 4.3 Focused Policy Cases.........................................................................................................20 4.4 The Best Case ....................................................................................................................22 5.0 Conclusions and Recommendations ............................................................................................... 26 Bibliography .............................................................................................................................................. 29 Appendix: Detailed Results...................................................................................................................... 31 A-1 Net Metering Improvements...........................................................................................31 A-2 Interconnection Standard Improvements ........................................................................33 A-3 Nationwide Availability of Time-of-Use Rates ..............................................................35 A-4 Fully Extended Residential Federal Tax Credit..............................................................36 A-5 State-by-State Results .....................................................................................................38 A-6 Input Data........................................................................................................................72 ix

List of Figures Figure E-1. Influence on cumulative U.S. PV installations of system pricing, net metering policy, federal tax credits, and interconnection standards ................................. viii Figure 1. Market penetration flow diagram...........................................................................3 Figure 2. State-level climate type designations.....................................................................4 Figure 3. PV access factor for residential buildings in warmer climates ..............................5 Figure 4. PV access factor for residential buildings in cooler climates ................................5 Figure 5. PV access factor for commercial buildings in warmer climates............................5 Figure 6. PV access factor for commercial buildings in cooler climates ..............................6 Figure 7. U.S. rooftop PV technical potential in 2015 (independent of economics) ............7 Figure 8. Market penetration curves used .............................................................................8 Figure 9. Technology adoption curve used ...........................................................................9 Figure 10. Availability of net metering .................................................................................11 Figure 11. Solar set-aside targets ..........................................................................................12 Figure 12. Cumulative installations in 2015 under the worst case........................................16 Figure 13. Impact of RPS solar set-asides, with all other scenarios at worst case................17 Figure 14. Cumulative installations in 2015 under the base case, with BAU system pricing ..................................................................................................................18 Figure 15. Cumulative installations in 2015 under the base case, with SAI system pricing ..................................................................................................................19 Figure 16. Cumulative installations in 2015 in the focused policy case, BAU system pricing ..................................................................................................................21 Figure 17. Cumulative installations in 2015 in the focused policy case, SAI system pricing ..................................................................................................................21 Figure 18. Cumulative installations in 2015 in the best case, BAU system pricing .............23 Figure 19. Cumulative installations in 2015 in the best case, SAI system pricing ...............24 Figure 20. Influence of system pricing, net metering policy, federal tax credits, and interconnection policy on cumulative installations..............................................26 Figure A-1. Cumulative installations in 2015 in the net metering improvement case ............31 Figure A-2. Impact of improved net metering policies in California, Florida, New York, and Oregon...........................................................................................................32 Figure A-3. Cumulative installations in 2015 in the interconnection standards improvement case ................................................................................................33 Figure A-4. Result of improved interconnection standards in Connecticut, Florida, Hawaii, Illinois, Maine, Pennsylvania, Washington, and Wisconsin ..................34 Figure A-5. Cumulative installations in 2015 in the time-of-use availability case .................35 Figure A-6. Cumulative installations in 2015: fully extended tax credit case ........................37 Figure A-7. Impact of extending the residential federal tax credit through 2015 in California, Connecticut, Pennsylvania, and Texas ..............................................38 x

List of Tables Table 1. Five Classes of Technology Adoption Characteristics (Fisher-Pry)......................9 Table 2. IRECs Interconnection Assessment Rating System ...........................................10 Table 3. System Pricing Assumptions ...............................................................................12 Table 4. Provisions of Low Carbon Economy Act ............................................................13 Table 5. Inputs into Each Run............................................................................................15 Table 6. Worst-Case Scenario Inputs.................................................................................16 Table 7. Nationwide Results for the Worst Case ...............................................................17 Table 8. Base-Case Scenario Inputs...................................................................................18 Table 9. Nationwide Results for the Base Case, with BAU System Pricing .....................19 Table 10. Nationwide Results for the Base Case, with SAI System Pricing .......................20 Table 11. Focused Policy Case Inputs .................................................................................20 Table 12. Nationwide Results for the Focused Policy Case, BAU System Pricing ............22 Table 13. Nationwide Results for the Focused Policy Case, SAI System Pricing ..............22 Table 14. Best-Case Scenario Inputs ...................................................................................23 Table 15. Nationwide Results for the Best Case, BAU System Pricing..............................24 Table 16. Nationwide Results for the Best Case, SAI System Pricing................................25 Table 17. Comparison of Planned Capacity Additions to Cumulative PV Installations with SAI Pricing ..................................................................................................27 Table A-1. Net Metering Improvements (Case Scenario Inputs)...........................................31 Table A-2. Nationwide Results for the Net Metering Improvement Case.............................32 Table A-3. Interconnection Standard Improvements Case Scenario Inputs ..........................33 Table A-4. Nationwide Results for the Interconnection Standards Improvement Case ........34 Table A-5. Time-of-Use Availability Scenario Inputs...........................................................35 Table A-6. Nationwide Results for the Time-of-Use Availability Case ................................36 Table A-7. Fully Extended Federal Tax Credit Scenario Inputs............................................36 Table A-8. Nationwide Results for the Fully Extended Tax Credit Case ..............................37 Table A-9. State-by-State Technical Potential, Over Time ...................................................38 Table A-10. State-by-State Results for the Worst Case ...........................................................40 Table A-11. State-by-State Results for the Base-Case, with BAU System Pricing.................44 Table A-12. State-by-State Results for the Base Case, with SAI System Pricing ...................48 Table A-13. State-by-State Results for the Focused Policy Case, BAU System Pricing ........52 Table A-14. State-by-State Results for the Focused Policy Case, SAI System Pricing ..........56 Table A-15. State-by-State Results for the Focused Policy Case, SAI System Pricing ..........60 Table A-16. State-by-State Results for the Best Case, BAU System Pricing..........................64 Table A-17. State-by-State Results for the Best Case, SAI System Pricing............................68 Table A-18. Utilities Analyzed ................................................................................................72 Table A-19. IRECs Interconnection Assessments ..................................................................74 Table A-20. Net Metering Availability and Sell-Back Rules for Representative Utilities Analyzed ..............................................................................................................78 Table A-21. Net Metering Caps for Representative Utilities Analyzed ..................................80 Table A-22. O&M and Inverter Replacement Costs................................................................84 Table A-23. Impact of Carbon Cap..........................................................................................85 Table A-24. Annual Year Over Year Changes in Electricity Prices as Projected by EIA for the Residential Market ...................................................................................88 xi

Table A-25. Annual Year-Over-Year Changes in Electricity Prices as Projected by EIA for the Commercial Market..................................................................................89 Table A-26. Annual Year-Over-Year Changes in Electricity Prices as Projected by NCI......90 xii

1.0 Introduction The economic viability of photovoltaics (PV) in the United States is a function of several variables, including electricity prices, system costs, net metering laws, and incentives. Given the fragmented nature of electricity markets, regulations, and incentives, the economics of PV need to be assessed locally. Accordingly, for this study, we modeled the market penetration of rooftop PV in the United States under a variety of scenarios, on a state-by-state basis, from 2007 to 2015.

The study was performed by Navigant Consulting Inc. (NCI) for the U.S. Department of Energy (DOE) under a subcontract to the DOE National Renewable Energy Laboratory (NREL). The analysts were challenged to ensure that the modeling methodology was highly clear and transparent. The model looked at the retrofit and new construction segments of the residential and commercial rooftop markets. It did not include field-based systems, a potentially significant market segment for growth. It also did not capture price dynamics related to international competition for PV modules, or downward changes in electricity prices resulting from a potential drop in demand because of PV.

For each state, the model calculated the percent market penetration, annual installations, and cumulative installations. The scenarios studied included net metering rules, electric rate tariff levels and structures, availability of financial incentives, system pricing, and carbon legislation. This report and the current version of the model are important early steps in the development of a better understanding of the market dynamics of the U.S. PV industry.

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2.0 Current Status of the Research Many market studies of the PV industry have been performed during the past few years.

Examples include DOE PV road maps (www.eere.energy.gov/solar/deployment.html), PV Services Program reports (www.navigantconsulting.com), Solarbuzz projections (www.solarbuzz.com), and reports from the Prometheus Institute (www.prometheus.com).

NCI and others have completed in-depth market penetration studies for constrained areas (Arizona, California, and Austin, Texas), but each of these markets is unique, so study results cannot be extrapolated to the entire nation.

Most previous studies have not used a market penetration approach that captures all facets of project economics. Prior projections have used a variety of approaches:

• A simple extrapolation of historical PV demand, using factors to represent aggressive or decreasing demand

• Market surveys to obtain key player views on future projections

• Reviews of the projected levelized cost of electricity for PV versus retail electricity rates to assess project attractiveness.

None of these methods, however, are in publicly available models. The goal of this research was to create a publicly available model that captures local variables such as retail electric rates, insolation levels, weather (and hence building load), incentives, net metering policy, and interconnection policy.

2

3.0 Project Approach NCI created a Microsoft Excel©-based spreadsheet tool for calculating market penetration.

shows a flow diagram of the model. This chapter discusses each section of the model:

technical potential, economic potential, and the scenarios studied.

Floorspace Data Key

=Technical Potential Building Characteristics

=Preliminary Economic Potential System PV Access =Final Economic Potential Prices Factors Technical System RECs Incentives Potential Efficiency O&M &

Market Technology Preliminary Net Inverter Simple Interconnection Penetration Adoption Economic Metering Replacement Payback Screen Curve Curve Potential Screen Costs 5 Year Inverter RPS MACRS Efficiency Annual Screen Electric Bill PV System Utility Level Output Demand Savings Building Results Charges Load Profile Final Economic Rate Potential Net Metering Structure State Level Rules Results Price of Carbon Figure 1. Market penetration flow diagram 3.1 Technical Potential To calculate the market penetration of PV, we must first know the size of the available market. Current and projected total U.S. roof space was thus estimated for 2007 through 2015, by state, for residential and commercial buildings. A PV solar access factor was then applied to the roof space data to estimate how much roof space is actually available for PV. The PV access factor takes into account shading, building orientation, and roof structural soundness.

PV power density data are then used to calculate potential installed capacity on a state-by-state basis.

To calculate total roof space, we began with data on the total amount of floor space in residential and commercial buildings, by state, from McGraw-Hill for 2007 through 2011.

They used the growth (or decline) trends from 2007 to 2011 to project growth (or decline) from 2012 to 2015. To estimate how floor space translates into roof space, we used data on the average number of floors per building from the Energy Information Administrations (EIA) Residential Energy Consumption Survey (RECS) and Commercial Building Energy Consumption Survey (CBECS) databases. For pitched roofs, assumed to be 92% of the residential market, NCI assumed an 18-degree pitch to calculate roof space. Although 18 3

degrees is a typical number, the angle can very from 0 to 45 degrees in any given region. We defined new construction based upon the floor space added in any year.

To estimate how much of the total roof space is available for PV, NCI developed PV access factors based on a study for a major U.S. utility company. The study was adjusted for California conditions after interviews with Ed Kern of Irradiance, who has many years of installation experience in the industry. Separate access factors were developed for cooler and warmer climates. State designations are shown in Figure 2. Figure 3, 4, 5, and 6 show the different analyses with the assumptions used for flat residential roofs. The PV access factors were then applied to state-level roof space data to estimate the available roof area for PV. The results should not be confused with the share of homes that are not suitable for PV, however, since the study is focusing on roof space. However, the factors used in the study (~25% for residential and ~60% for commercial) are similar to the space taken up by current PV systems.

= Warm

= Cool Figure 2. State-level climate type designations 4

Tree Shading 90% Other Shading 90%

Orientation 30%

Pitched Roofs

• 30o tilt 100% 90% 81% 24% Residential -

• 92% of residential Warmer Climate roof space Area Available for PV systems in Residential Flat Buildings = 27% of Roofs

• 0o tilt total roof area

• 8% of 60%

residential roof space Figure 3. PV access factor for residential buildings in warmer climates Tree Shading 6070% Other Shading 90% Orientation Pitched 30%

Roofs

• 30o tilt Residential -

• 92% of 100% 65% 59% 18%

residential Cooler Climate roof space Area Available for PV systems in Residential Flat Buildings = 22%

Roofs of total roof area

• 0o tilt 65%

• 8% of residential roof space Figure 4. PV access factor for residential buildings in cooler climates Material Compatibility Structural 100% adequacy 80% Shading Orientation/

75% Coverage Commercial -

Total Roof 100% Warmer Climate Area

• 0o tilt Area Available for PV

• 100% of 100% 100% 80% 60% 60% Systems in commercial roof space Commercial &

Industrial Buildings =

60% of total roof area Figure 5. PV access factor for commercial buildings in warmer climates 5

Material Compatibility Structural 100%

adequacy 100% Shading Orientation/

65% Coverage Commercial -

Total Roof 100% Cooler Climate Area Area Available for PV

• 0o tilt

• 100% of 100% 100% 100% 65% 65% systems in commercial Commercial &

roof space Industrial Buildings =

65% of total roof area Figure 6. PV access factor for commercial buildings in cooler climates We estimated the technical potential using data on PV power density from DOEs Solar America Initiative Technology Pathway Partnership (for information, see www.eere.energy.gov/solar/solar_america/index.html). Technical potential is defined as PV system power density (in MWpDC per million square feet) times the roof space available for PV in a given area.

To calculate the power density of a solar PV system in 2007, we developed a weighted-average module efficiency using market share for the three most prevalent technologies in the market today. The power density of a module was then calculated on a square-footage basis, and the power density of a PV system was calculated by applying a packing factor of 1.25 for residential and commercial systems. The packing factor modifies (as a decrease) the PV power density by taking into account space need for the system, such as space for access between modules, wiring, and inverters.

The resulting system power density is 10 MW/million ft2, as derived from an average module efficiency of 13.5%. For 2015, we assumed an average module efficiency of 18.5% for all installations, resulting in a power density of 13.7 MW/million ft2 in 2015. Figure 7 shows the technical potential in 2015. Technical potential increases over time for two reasons: rooftop area grows over time and system efficiencies increase over time. See the appendix in this report for a table of state-by-state results.

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Range Unit Color Greater than 75000 MW 75000 to 65000 MW 65000 to 55000 MW 55000 to 45000 MW 45000 to 35000 MW 35000 to 25000 MW 25000 to 15000 MW 15000 to 5000 MW 5000 to 1000 MW 1000 to 0 MW Figure 7. U.S. rooftop PV technical potential in 2015 (independent of economics) 3.2 Preliminary Economic Potential After calculating the technical potential for each state, we looked at the economics of PV to assess the economic potential. Referring back to Figure 3-1, economic potential is calculated by taking market penetration as a percentage of technical potential and multiplying the results by a technology adoption curve.

The input to NCIs market penetration curves is simple payback, so we picked from one to five utilities in each state to represent PV economics. For each utility analyzed (or state, for certain variables), we collected rate structure and tariff data, net metering rules, incentives data, building load profiles, and PV output profiles. See the appendix for more details about the sources and values of each of these variables and the list of utilities analyzed, by state.

Equation 1 shows the simple payback calculation for the residential market, and Equation 2 shows the calculation for the commercial market. Note that, according to EIAs CBECS database, approximately 25% of all commercial building floor space is contained in buildings that do not pay taxes (such as schools and government buildings), so this calculation is somewhat conservative for those segments.

Simple Payback = [Installed Cost - Federal Incentives - Capacity Based Incentives + Tax Rate*Rebate Amount]

[Annual Electric Bill Savings + Performance Based Incentives - O&M Costs]

Equation 1. Residential simple payback Simple Payback = [Installed Cost - Federal Incentives - Capacity Based Incentives + Tax Rate*Rebate Amount]

[(1-Tax Rate)*(Annual Electric Bill Savings-O&M Costs) + Performance Based Incentives + Amortized MACRS savings]

Equation 2. Commercial simple payback We used two different market penetration curves (both of which use simple payback as inputs): one for the retrofit market and one for the new construction market. Figure 8 shows the market penetration curves used. Based on interviews with key stakeholders, we used a different curve for new construction because builders are in general reluctant to add PV as a 7

standard feature and require shorter paybacks before making it standard. We used two studies of market penetration to develop curves for this study. Kastovich et al. calculated market penetration curves for retrofit and new construction markets of energy technologies. They surveyed customer behaviors based on simple payback. NCI produced a curve based on field interviews, consumer surveys, and market data on the adoption of efficient energy technologies in the market, again based on simple payback.

Several variables could influence the evolution of these market penetration curves over time.

The most important would be government policies that support the adoption of PV. One example is the California Solar Initiative, which after 2010 requires that all new subdivisions with more than 50 homes must offer PV as an option to potential homebuyers. Another variable could be consumer awareness campaigns that shift consumer behavior to adopt PV at higher paybacks.

100%

90% Residential and Commercial Retrofit Market Market Penetration [%]

80%

70% Residential and Commercial New Construction 60% Market 50%

40%

30%

20%

10%

0%

- 5 10 15 20 25 Modified Simple Pay-back [Years]

Figure 8. Market penetration curves used After calculating the percent market penetration, we used an S-curve to model technology adoption. An S-curve provides the rate of adoption of technologies as a function of the technologys characteristics and market conditions. Figure 9 shows the S-curves used, which are Fisher-Pry curves. The Fisher-Pry technology substitution model predicts the market adoption rate for an existing market of known size. We used this model because consumers are replacing grid power with PV power. The market of known size comes from technical potential and market potential calculations.

The rate at which technologies are adopted depends on several market characteristics:

technology characteristics (e.g., technology economics, new vs. retrofit); industry characteristics (e.g., industry growth, competition); and external factors (e.g., government regulation, trade restrictions). Historical data collected by Fisher-Pry and NCI reveal that major classes of technology/segment with common segment-penetration characteristics can be classified into five categories, each with its own time to segment saturation, as shown in Table 3-1.

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For PV, we picked the two classes that closely resembled the PV market in the United States, class B and class C. They then used the average of the two classes curves, as shown in Figure 9.

Table 1. Five Classes of Technology Adoption Characteristics (Fisher-Pry)

Characteristics A B C D E Time to Saturation (ts) 5 years 10 years 20 years 40 years >40 years Technology Factors Equipment Life < 5 years 5-15 years 15-25 years 25-45 years >40 years Equipment Replacement None Minor Unit operation Plant section Entire plant Technology Experience New to U.S. only New to U.S. only New to U.S. only New New Industry Factors Growth (% per year) >5% >5% 2~5% 1-2% <1%

Attitude to Risk Open Open Cautious Conservative Adverse External Factors Government Regulation Forcing Forcing Driving None None 100%

Percent of Achievable Market 90%

80%

70%

60%

50%

Share 40%

30%

20%

10%

0%

0 5 10 15 20 25 30 Years after introduction Class B Class C Average Figure 9. Technology adoption curve used Because 2007 was more than half over when this report was written, the model assumes annual installations and cumulative installations through 2007 and starts calculating penetration for 2008.

After applying these curves, we arrived at cumulative installations up to the year of analysis.

A final market penetration was calculated after applying the RPS and interconnection screens discussed in the next section. Final market penetration is defined as cumulative installations (defined by peak DC rating) in a given area as a percentage of the technical potential in that area.

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3.3 Scenarios Analyzed We developed a set of scenarios dealing with interconnection policy, RPS solar set-aside policy, system pricing, net metering policy, carbon legislation, rate structure policy, electric rate escalation, and federal incentives. For the first of the scenarios, we used data provided to DOE from the Interstate Renewable Energy Councils (IREC) assessment of each states interconnection standards (or utilitys, in states without state-level laws) in regard to facilitating distributed generation. IREC gave each location a rating on a five-point scale, as shown in Table 2, that assesses the likelihood of a system being installed. We then translated these assessments into an assumed percentage of achievable market, also shown in Table 2.

They scaled preliminary economic potential by this amount. (See the appendix for a complete list of state rankings.)

Many states interconnection standards are a barrier to the wider adoption of PV, although several are considering revising them. Recognizing this, we created a scenario in which all states improve their interconnection standards to the point at which the standards do not hinder PV interconnection (i.e., a superior ranking in IRECs scale in Table 2).

Table 2. IRECs Interconnection Assessment Rating System IREC IRECs NCIs Assumed Achievable Rating Assessment Market Superior (A) Interconnection policies encourage distributed generation 100%

Good (B) Interconnection policies contain some difficulties but less 95%

than 5% of solar projects will incur needless costs or delays because of interconnection problems Fair (C) Interconnection policies allow interconnection but with 75%

some difficulty. Up to 25% of proposed solar projects will incur needless delays, costs, or some will fail because of interconnection Poor (D) Interconnection policies are very poor. Costs of systems 60%

and time to complete interconnection will be significant. Up to 50% of projects will incur significant costs and delays to complete interconnection process. An undesirable number of projects will fail.

Barrier (E) Interconnection policies represent a major barrier to the 40%

use of solar. 50% or greater will experience significant costs, delays or project cancellation because of interconnection policies Some states or utilities have net metering caps, typically expressed as a percentage of the utilitys or states peak load. This study used EIA peak demand data to translate net metering caps as percentages into megawatts. For each year of analysis, market penetration is the ratio of cumulative installations to net metering caps. The model assumes that if net metering caps are reached in a given year, net metering is not allowed in the next year of analysis. We used EIAs Annual Energy Outlook projections for load growth to estimate how peak demand will change over time.

10

The next two scenarios concern net metering standards. The first net metering scenario assumes all net metering caps are lifted in 2007. The second one concerns the availability of net metering. Currently, most states and the District of Columbia offer net metering, but some states and utilities still do not allow it. Figure 10 shows net metering assumptions for the utilities used in this study, by state. This scenario assumes net metering is available nationwide, starting in 2008.

Net Metering Net Metering Not Allowed Net Metering Allowed for Certain Utilities Figure 10. Availability of net metering The next scenario involved RPS solar set-asides. Several states have solar set-asides or distributed generation set-asides as part of their RPS (i.e., a certain percentage of RPS megawatt-hours must be from PV systems). For each year of analysis, the market penetration model will ensure that market penetration at least meets the level required by solar set-asides, independent of net metering caps, economics, or poor interconnection standards. The exact mechanisms for this are not specified, but examples could be extra utility rebates or utilities owning rooftop PV systems.

For reference, Figure 11 shows solar set-aside requirements in 2015. As shown in the figure, RPS could account for a total of ~2,200 MW of installed PV in 2015. Achieving these goals will depend on a number of factors, such as compliance mechanisms, so they may or may not be met. The model has a switch in which RPS solar set-asides goals are met or not met.

11

Estimated Solar Set Aside Capacity Targets by 2015 (MW) 700 Cummulative PV Installed (MWp) 600 500 400 300 200 100 0

MD CO DC NH NV NJ PA NY AZ NC DE Figure 11. Solar set-aside targets NCI used two different system pricing cases. The first case assumed that system prices decline at historical rates. The second case used targets from the DOEs Solar America Initiative (SAI) program. DOEs targets are based on a combination of internal analysis of potential cost reductions in PV technologies and a review of information provided in applications submitted to the SAI Technology Pathway Partnership solicitation during 2006.

Table 3 lists the two pricing cases.

Table 3. System Pricing Assumptions System Price Scenario Market Segment Retrofit Installed New Construction System Price Installed System

($2007/Wpdc) Price ($2007/Wpdc) 2007 2010 2015 2007 2010 2015 Business as Usual Residential $7.40 $6.20 $4.80 $7.40 $5.90 $4.50 (BAU)

Commercial $6.41 $5.80 $4.50 $6.70 $5.50 $4.20 Solar America Initiative Residential $7.40 $5.11 $3.10 $7.10 $3.86 $2.44 (SAI)

Commercial $6.41 $3.75 $2.49 $6.23 $3.60 $2.32 At the time of this project, several bills were circulating through the U.S. House of Representatives and the U.S. Senate that would introduce some type of carbon legislation.

During the course of this project, for illustration purposes the study used the Senates Low Carbon Economy Act bill sponsored by Senator Bingaman of New Mexico. The Act creates a national cap-and-trade system with a ceiling on the price of carbon, as shown in Table 4. We assume that carbon will trade at the ceiling price. To assess the effect of this on potential PV 12

customers, we used carbon intensity data from EIA (in tonnes of CO2 per kWh) and modeled the price of carbon as a surcharge on electric bills. Refer to the appendix for details on the calculations. Thus, we modeled a scenario that assumes the legislation is introduced.

Table 4. Provisions of Low Carbon Economy Act Year Ceiling on Carbon Price

[$/Tonne CO2]

2007 $0.00 2008 $0.00 2009 $0.00 2010 $0.00 2011 $0.00 2012 $12.00 2013 $12.60 2014 $13.23 2015 $13.89 Time-of-use (TOU) rates can significantly impact PV economics, yet they are not available in all areas. We created a scenario in which TOU rates are made available from every utility. To create TOU rates, we used a rate-multiplier approach. Within the eight North American Electric Reliability Corporation (NERC) regions, utilities from each state with established TOU rates were selected for analysis. For each utility, we calculated the ratio of peak-to-standard and non-peak-to-standard rates for both the summer and winter seasons. Overall averages of those ratios were then taken for each region to use as benchmarks when estimating TOU rates for utilities that do not offer them. Another component of the rate-multiplier analysis involved calculating an average number of peak hours and start times of those peak periods within each region. See the appendix for more detail.

Given the influence of electricity prices on simple payback, we looked at three different forward price projections. The first (and most conservative) projection uses EIAs Annual Energy Outlook pricing projections. These projections show real cost decreases over time.

The second projection uses state-by-state projections developed by NCI using NERC reports, ISO reports, and other data sources to look at the impact of policy changes (e.g., rate caps lifted), capacity shortfalls, and market dynamics. The result was an annual percentage year-over-year change in price, by state.

The final two scenarios we analyzed involved federal incentives for PV. Federal residential incentives (tax credits) are set to expire at the end of 2008; at that time, the commercial incentive will be reduced from 30% to 10%. However, the U.S. House of Representatives and the U.S. Senate are working on legislation to extend those tax credits. Each chamber has different provisions for extension, and we worked with the Solar Energy Industries Association to come up with a best estimate about which legislation will pass. The first scenario assumes the commercial incentive is extended to 2015 and the residential incentive is extended to 2010, with the $2,000-per-system cap lifted. The second scenario assumes that both the residential and commercial credits are fully extended to 2015, with the $2,000-per-system cap lifted.

13

Many participants in the PV market have concerns regarding the availability of installers to meet a growing demand. In discussing this issue with stakeholders, we found that the time to train a qualified PV installer ranges from six weeks to three months, which fits within the one-year temporal resolution of this model. To understand future requirements for installers, we calculated estimated installer requirements state by state for each year of analysis.

14

4.0 Project Results We conducted several model runs, varying each of the scenarios. The first run used values for each variable that provided the least support for PV penetration. The next run served as a base case and used inputs that are more representative of what is likely to occur. Next, using the base case as a starting point, we looked at the impact of individual policy improvements for net metering, interconnection standards, and TOU rates, along with a full extension of the residential federal tax credit. Using the results of these four runs, we chose the two variables with the largest impact and looked at the results. Finally, we conducted a best-case run within the context of this model/set of assumptions. There is potential for more rapid market penetration, for example, if electricity prices rise faster then projected here, if states (or the federal government) institute more aggressive solar or climate-related policies, and so on. All runs were done using business-as-usual (BAU) and SAI system pricing.

Table 5. Inputs into Each Run Focused Scenario Worst-Case Base-Case Policies Best-Case Interconnection Current Rules Current Rules Current Rules Improved Policy Scenario Net Metering Current Current Nationwide Nationwide Availability Availability Availability Availability Availability Scenario Net Metering Cap Current Caps Current Caps Caps Lifted Caps Lifted Scenario Cap and Trade Low Carbon Low Carbon Low Carbon None Scenario Economy Act Economy Act Economy Act Electricity Price EIAs Accelerated Accelerated Accelerated Escalation Projections Federal Tax Credit Baseline Extended Fully Extended Fully Extended Current Current Current Nationwide Time-of-Use Rates Availability Availability Availability Availability RPS Solar Set No Yes Yes Yes Aside Enforcement 4.1 The Worst Case The first run used the worst case for each input assumption, as shown in Table 6. The run assumed that federal tax credits are not extended, carbon legislation is not passed, system price declines occur at historical rates, and electricity prices evolve per the EIAs projections.

All of these factors combine to decrease the economic attractiveness of PV.

15

Table 6. Worst-Case Scenario Inputs Scenario Value System Pricing Scenario Business-As-Usual Interconnection Policy Scenario Current Rules Net Metering Availability Scenario Current Availability Net Metering Cap Scenario Current Caps Cap and Trade Scenario None Electricity Price Escalation EIAs Projections Federal Tax Credit Baseline Time-of-Use Rates Current Availability RPS Solar Set-Aside Enforcement No Figure 12 shows cumulative installations by state for 2015. See the appendix for a table of state-by-state results. Installations are strong in 2007 and 2008, but once the federal tax credits expire, the market shrinks by 90% in 2009. The only state in which significant installations occur is California, where the California Solar Initiative mitigates the loss of federal tax credits. The assumption that RPS solar set-asides are not enforced has a large impact, as shown in Figure 13. Given that most RPS have a ceiling on alternative compliance payments, market forces (i.e., a lucrative renewable energy credit, or REC, price improves system economics) can only go so far in enforcing the solar set-asides.

Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 12. Cumulative installations in 2015 under the worst case 16

Table 7. Nationwide Results for the Worst Case Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 155 889 1,117 0.19%

2009 35 924 245 0.18%

2010 100 1,024 670 0.19%

2011 54 1,077 336 0.19%

2012 216 1,293 1,251 0.21%

2013 275 1,568 1,466 0.25%

2014 326 1,895 1,592 0.28%

2015 70 1,965 309 0.28%

2500 Cumulative Installations [MW No Enforcement Enforcement 2000 1500 1000 500 0

2007 2008 2009 2010 2011 2012 2013 2014 2015 Year Figure 13. Impact of RPS solar set-asides, with all other scenarios at worst case 4.2 The Base Case The next case used more probable scenario inputs. An extension to the federal tax credits was assumed to pass (only to 2010 in the case of the residential tax credit, electricity prices were assumed to increase over time, carbon legislation was assumed to be enacted, and RPS solar set-asides were enforced, as detailed in Table 8. We ran this scenario with BAU and SAI pricing to show not only the impact of the Solar America Initiative, but also what would happen if demand outpaced supply and prices do not decrease.

The positive impact on market penetration is noticeable compared with the worst case, as shown in the figures. The extension of the tax credits and RPS enforcement have the greatest 17

impact. However, the market stalls temporarily in 2011 because the residential tax credit has expired. BAU system pricing yields a 26% compound annual growth rate (CAGR) to 2015.

SAI system pricing results in a ~65% increase in cumulative installations over BAU pricing, with a 34%/year CAGR. State-by-state results are shown in the appendix.

Table 8. Base-Case Scenario Inputs Scenario Value System Pricing Scenario BAU/SAI Interconnection Policy Scenario Current Rules Net Metering Availability Scenario Current Availability Net Metering Cap Scenario Current Caps Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Medium Federal Tax Credit Extended Time-of-Use Rates Current Availability RPS Solar Set Aside Enforcement Yes Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 14. Cumulative installations in 2015 under the base case, with BAU system pricing 18

Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 15. Cumulative installations in 2015 under the base case, with SAI system pricing Table 9. Nationwide Results for the Base Case, with BAU System Pricing Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 833 1,567 4,885 0.33%

2009 223 1,790 1,554 0.35%

2010 288 2,078 1,937 0.39%

2011 270 2,348 1,687 0.41%

2012 527 2,875 3,055 0.48%

2013 313 3,188 1,668 0.50%

2014 544 3,732 2,654 0.55%

2015 813 4,545 3,588 0.64%

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Table 10. Nationwide Results for the Base Case, with SAI System Pricing Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,012 1,745 6,172 0.37%

2009 196 1,941 1,362 0.38%

2010 408 2,349 2,737 0.44%

2011 364 2,713 2,280 0.48%

2012 648 3,361 3,778 0.56%

2013 842 4,203 4,491 0.66%

2014 1,922 6,125 9,394 0.91%

2015 1,367 7,492 6,035 1.05%

4.3 Focused Policy Cases Realizing that large amounts of effort are required to change state-level policies on a national scale, we took the two policies with the greatest impact and ran them together with the base case. Our analysis (shown in the appendix) found that improved net metering policy had the greatest impact on cumulative installations in 2015 (a 58% increase over the base case with SAI pricing). Next, fully extending the residential Investment Tax Credit (ITC) to 2015 had a 40% impact on cumulative installations. Table 11 shows the corresponding scenario inputs for the focused policy case. Figure 16 and Table 12 show the results. With SAI system pricing, these two policies combine to increase cumulative installations by more than double by 2015 over the base-case, from 7,492 MW to 17,353 MW. State-by-state results can be found in the appendix.

Table 11. Focused Policy Case Inputs Scenario Value System Pricing Scenario BAU/SAI Interconnection Policy Scenario Current Rules Net Metering Availability Scenario Nationwide Availability Net Metering Cap Scenario Caps Lifted Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Accelerated Federal Tax Credit Fully Extended Time-of-Use Rates Current Availability RPS Solar Set Aside Enforcement Yes 20

Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 16. Cumulative installations in 2015 in the focused policy case, BAU system pricing Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 17. Cumulative installations in 2015 in the focused policy case, SAI system pricing 21

Table 12. Nationwide Results for the Focused Policy Case, BAU System Pricing Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 835 1,568 4,897 0.33%

2009 223 1,792 1,554 0.35%

2010 288 2,080 1,937 0.39%

2011 781 2,861 4,888 0.50%

2012 1,144 4,005 6,629 0.66%

2013 709 4,715 3,785 0.74%

2014 2,289 7,004 11,176 1.04%

2015 1,637 8,641 7,229 1.21%

Table 13. Nationwide Results for the Focused Policy Case, SAI System Pricing Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,014 1,747 6,187 0.37%

2009 417 2,165 2,903 0.43%

2010 739 2,903 4,960 0.54%

2011 1,372 4,275 8,582 0.75%

2012 1,822 6,097 10,582 1.01%

2013 2,052 8,149 10,947 1.28%

2014 4,368 12,517 21,320 1.86%

2015 4,836 17,353 21,351 2.44%

4.4 The Best Case The final case used inputs most favorable for PV market penetration, as shown in Table 14.

Figure 18 and Table 15 show the national results. Achieving policy improvements in all these areas would require a large effort and potentially a considerable amount of federal funding.

However, if this were successful, a very large, sustained demand (55%/year CAGR to 2015 with SAI pricing) can be created. State-by-state results are shown in the appendix.

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Table 14. Best-Case Scenario Inputs Scenario Value System Pricing Scenario BAU/SAI Interconnection Policy Scenario Improved Year of Policy Implementation 2008 Net Metering Availability Scenario Nationwide Availability Net Metering Cap Scenario Caps Lifted Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Accelerated Federal Tax Credit Fully Extended Time-of-Use Rates Nationwide Availability RPS Solar Set Aside Enforcement Yes Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 18. Cumulative installations in 2015 in the best case, BAU system pricing 23

Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure 19. Cumulative installations in 2015 in the best case, SAI system pricing Table 15. Nationwide Results for the Best Case, BAU System Pricing Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,019 1,753 6,226 0.37%

2009 314 2,067 2,183 0.41%

2010 420 2,487 2,822 0.46%

2011 1,004 3,491 6,282 0.61%

2012 1,372 4,864 7,953 0.81%

2013 1,045 5,909 5,577 0.93%

2014 2,633 8,542 12,886 1.27%

2015 2,565 11,107 11,326 1.56%

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Table 16. Nationwide Results for the Best Case, SAI System Pricing Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,237 1,970 7,793 0.41%

2009 622 2,593 4,328 0.51%

2010 1,187 3,780 7,974 0.70%

2011 1,496 5,276 9,357 0.92%

2012 2,383 7,659 13,868 1.27%

2013 2,807 10,466 14,989 1.64%

2014 6,724 17,190 32,780 2.55%

2015 7,522 24,712 33,208 3.47%

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5.0 Conclusions and Recommendations The critically important findings in this report are the influences of each scenario discussed.

System pricing is the input with the largest impact. In the base case, the focused policy case, and the best case, using SAI system pricing caused cumulative installations to more than double by 2015. Other high-impact factors are net metering policy, extension of the federal tax credits, and interconnection policy. Figure 20 shows the cumulative effects of these variables.

30,000 + INT Cumulative Installations [MW]

25,000

+ ITC 20,000

+ Net 15,000

+ Pricing 10,000 5,000 Base 0

20 20 20 20 20 2001 02 03 04 05 20 20 20 20 2006 07 08 09 10 11 20 20 20 2012 13 14 Year 15

.

Figure 20. Influence of system pricing, net metering policy, federal tax credits, and interconnection policy on cumulative installations To understand the implication of these scenarios relative to planned generating capacity additions, we used data from EIAs 2007 Annual Energy Outlook. We compared the planned capacity projections in EIAs reference case from 2007 to 2015 to the cumulative installations of PV by 2015, as shown in Table 17. Table 17 shows that PV could contribute between 27%

to 91% of planned capacity additions per EIAs projections. Given that the U.S. market has strong regional variations, PVs contribution to capacity additions could be much higher on a regional or interconnect basis. This would have significant implications for utility planning and grid operations.

26

Table 17. Comparison of Planned Capacity Additions to Cumulative PV Installations with SAI Pricing EIA Projected 2015 Capacity Cumulative PV PV as % of Additions, 2007 Installations Planned Capacity Scenario to 2015 [MW] [MW] Additions [%]

Base-Case 27,038 7,423 27%

Focused Policy Initiatives 27,038 17,353 64%

Best-Case 27,038 24,712 91%

During the course of this project, we identified several items that might enhance this analysis.

The first would be an easily accessible database for building load profiles that might be similar to PV Watts for output profiles. Fortunately, NRELs commercial building load profiles were readily available for use, but the time required to generate profiles prevented us from using a unique residential profile for each utility analyzed. If a database of sample profiles were available, we could have used them for each utilitys residential analysis.

Our analysis focused on rooftop applications, but other potential structures, such as parking garages or carports, are also suitable for PV installations. A useful activity might be to assess the feasibility of conducting a market potential analysis for PV on unoccupied structures. In addition, this study did not assess the potential for ground-mounted structures. A feasibility study should be conducted to identify or create methods and models for calculating the market potential for ground-mounted systems.

As discussed in Section 0, many groups within the PV industry, and those who monitor the PV industry (such as the investment community), have concerns about the availability of installers to meet a growing demand. For this study, we estimated installer requirements on a state-by-state basis for each year. However, it would provide valuable insights to model actual installer availability dynamics and feed the results back into the model.

The model we developed looks solely at the U.S. market and uses pricing assumptions that do not take into account demand outside the United States. If international markets (such as Spain or South Korea) experience dramatic surges in demand, module supplies could be diverted to those markets. A supply-constrained environment would then develop in the United States, however, and prices might not fall.

One key variable that the model does not now address is the impact of system financing. The market penetration curves used simple paybacks as inputs and did not consider financing. In reality, interest payments for financed systems affect economic attractiveness. Also, this model cannot assess the impact of innovative financing mechanisms or new business models (such as the power purchase agreement model) developing in the U.S. market. These drawbacks point to the need to develop a market penetration model based on return on investment or demand elasticity.

27

Finally, the model did not take into account possible electricity price feedbacks if the demand for grid power drops because of significant PV deployment.

However, even with these few shortcomings, this model reasonably simulates a very complex, intricate market by analyzing a large number of variables including system prices, electricity price forecasts, public policy, consumer behavior, and technology diffusion. The key findings of this study indicate that the technical potential and market opportunity for photovoltaics in the United States is significant if the government supports the appropriate policy mechanisms analyzed in the study.

28

Bibliography California Energy Commission. (September 2007). California Solar Initiative Program Handbook. Available online at www.gosolarcalifornia.ca.gov.

Energy Information Administration. (2007). Annual Energy Outlook 2007. Available online at www.eia.doe.gov.

Energy Information Administration. (2003). Commercial Building Energy Consumption Survey. Available online at www.eia.doe.gov.

Energy Information Administration. Form 861. Available online at www.eia.doe.gov.

Energy Information Administration. Form 860. Available online at www.eia.doe.gov.

Energy Information Administration. (2001). Residential Energy Consumption Survey.

Available online at www.eia.doe.gov.

Fisher, J.C.; Pry, R.H. (1971). A Simple Substitution Model of Technological Change.

Technological Forecasting and Social Change, Vol. 3, pp. 75-88.

Network for New Energy Choices. (2007). Freeing the Grid, 2007 Edition. Available online at www.newenergychoices.org/uploads/FreeingTheGrid2007_report.pdf.

North Carolina Solar Center. (2007). Database of State Incentives for Renewables and Efficiency. Raleigh, NC: North Carolina State University; www.dsireusa.org.

Kastovich, J.C.; Lawrence, R.R.; Hoffman, R.R.; Pavlak, C. (1982). Advanced Electric Heat Pump Market and Business Analysis. Report no. ORNL/Sub/79-24712/1, prepared under subcontract to ORNL by Westinghouse Electric Corp. Oak Ridge, TN: Oak Ridge National Laboratory.

Roth, K.W.; Westphalen, D.; Dieckmann, J.; Hamilton, S.D.; Goetzler, W. (July 2002).

Energy Consumption Characteristics of Commercial Building HVAC Systems, Volume III:

Energy Savings Potential. Prepared by TIAX LLC for the DOE Building Technologies Program. Washington, DC: U.S. Department of Energy.

United States Senate Committee on Energy and Natural Resources. (July 2007).

Bingaman/Specter Climate Change Bill. For information, see http://energy.senate.gov/public/.

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30 Appendix: Detailed Results A-1. Net Metering Improvements After establishing a base case, NCI looked at the impact of lifting net-metering caps and allowing net metering in all states, as shown in Table A-1. Figure A-1 and Table A-2 show the cumulative installations in 2015 and nationwide results, respectively.

Table A-1. Net Metering Improvements (Case Scenario Inputs)

Scenario Value System Pricing Scenario SAI Interconnection Policy Scenario Current Rules Net Metering Availability Scenario Nationwide Availability Net Metering Cap Scenario Caps Lifted Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Accelerated Federal Tax Credit Extended Time-of-Use Rates Current Availability RPS Solar Set Aside Enforcement Yes Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure A-1. Cumulative installations in 2015 in the net metering improvement case 31

Table A-2. Nationwide Results for the Net Metering Improvement Case Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,014 1,747 6,187 0.37%

2009 417 2,165 2,903 0.43%

2010 739 2,903 4,960 0.54%

2011 329 3,232 2,059 0.57%

2012 1,140 4,372 6,630 0.72%

2013 1,333 5,705 7,109 0.89%

2014 3,136 8,841 15,311 1.31%

2015 2,973 11,813 13,124 1.66%

Lifting net metering caps and establishing net metering have noticeable impacts in a few statesCalifornia, Florida, New York, and Oregon. This means that installations do not reach net-metering cap amounts in any other states, and net metering improves system economics in states that do not allow net metering. California has a net-metering cap of 2.5% of a utilitys peak load, New York has a net metering cap of 0.1% of a utilitys peak load, and Oregon has a net metering cap of 0.5% of a utilitys peak load. Florida does not currently allow net metering. Figure A-2 shows the combined impact of improved net-metering policies in these states, but most is driven by California.

Cumulative Installations [MW 10000 Current Net Metering Policy 8000 Improved Net Metering Policy 6000 4000 2000 0

2007 2008 2009 2010 2011 2012 2013 2014 2015 Year Figure A-2. Impact of improved net metering policies in California, Florida, New York, and Oregon 32

A-2. Interconnection Standard Improvements The next case started back at the base case and looked at improved interconnection standards, as shown in Table A-3. Many states (or utilities) have interconnection standards that inhibit PV adoption. However, many state legislatures are in the process of revising their interconnection standards. This case examines the impact of all states improving their interconnection standards to superior per the IREC rating shown in Table 2 and assumes that improved standards are in place by 2008. Results are shown in Figure A-3 and Table A-4.

Table A-3. Interconnection Standard Improvements Case Scenario Inputs Scenario Value System Pricing Scenario SAI Interconnection Policy Scenario Improved Year of Policy Implementation 2008 Net Metering Availability Scenario Current Availability Net Metering Cap Scenario Business-As-Usual Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Accelerated Federal Tax Credit Extended Time-of-Use Rates Current Availability RPS Solar Set-Aside Enforcement Yes Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure A-3. Cumulative installations in 2015 in the interconnection standards improvement case 33

Table A-4. Nationwide Results for the Interconnection Standards Improvement Case Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,221 1,955 7,678 0.41%

2009 284 2,239 1,979 0.44%

2010 797 3,036 5,350 0.56%

2011 300 3,336 1,876 0.58%

2012 948 4,284 5,494 0.71%

2013 821 5,104 4,399 0.80%

2014 2,603 7,707 12,731 1.14%

2015 1,899 9,606 8,398 1.35%

Improving interconnection standards has a large impact in the following states, which have interconnection assessments of poor or below: Connecticut (poor), Florida (poor), Hawaii (barrier), Illinois (barrier), Maine (barrier), Pennsylvania (poor), Washington (barrier), and Wisconsin (poor). Figure A-4 shows a combined increase of ~60% in cumulative installations by 2015 in these states if interconnection standards are improved.

Cumulative Installations [MW 2000 Current Interconnection Policy Improved Interconnection Policy 1500 1000 500 0

2007 2008 2009 2010 2011 2012 2013 2014 2015 Year Figure A-4. Result of improved interconnection standards in Connecticut, Florida, Hawaii, Illinois, Maine, Pennsylvania, Washington, and Wisconsin 34

A-3. Nationwide Availability of Time-of-Use Rates The next case run assumed that TOU rates were available from every utility, as shown in Table A-5. We reviewed the economics in each utility region to determine if standard or TOU rates resulted in lower annual electric bills and then chose the cheaper option. This yielded some interesting results (see Figure A-5 and Table A-6). Some utilities in Hawaii (specifically, Maui Electric Company) and Texas (all the utilities analyzed except Entergy Gulf States) do not have TOU rates, so this increased penetration. However, the establishment of TOU rates actually decreases market penetration in Massachusetts, New Jersey, and Tennessee. Some utilities in these states do not offer TOU rates; implementing them results in lower electric bills, which in turn results in lower annual electric bill savings as a result of using PV. Thus, the simple payback increases and market penetration decreases.

Table A-5. Time-of-Use Availability Scenario Inputs Scenario Value System Pricing Scenario SAI Interconnection Policy Scenario Current Rules Net Metering Availability Scenario Current Availability Net Metering Cap Scenario Business-As-Usual Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Accelerated Federal Tax Credit Extended Time-of-Use Rates Nationwide Availability RPS Solar Set Aside Enforcement Yes Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure A-5. Cumulative installations in 2015 in the time-of-use availability case 35

Table A-6. Nationwide Results for the Time-of-Use Availability Case Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,016 1,749 6,200 0.37%

2009 201 1,950 1,396 0.38%

2010 411 2,361 2,762 0.44%

2011 360 2,722 2,254 0.48%

2012 638 3,359 3,720 0.56%

2013 841 4,201 4,488 0.66%

2014 1,845 6,046 9,019 0.90%

2015 1,370 7,415 6,048 1.04%

A-4. Fully Extended Residential Federal Tax Credit To look at the impact of the federal tax credit, we assumed the residential federal tax credit would be extended until 2016. Table A-7 shows the scenario inputs, while Figure A-6 and Table A-8 show the resulting cumulative installations. The extension affects all markets, but the impacts are strongest in California, Massachusetts, Pennsylvania, and Texas, as shown in Figure A-7.

Table A-7. Fully Extended Federal Tax Credit Scenario Inputs Scenario Value System Pricing Scenario SAI Interconnection Policy Scenario Current Rules Net Metering Availability Scenario Current Availability Net Metering Cap Scenario Business-As-Usual Cap and Trade Scenario Low Carbon Economy Act Electricity Price Escalation Accelerated Federal Tax Credit Fully Extended Time-of-Use Rates Current Availability RPS Solar Set Aside Enforcement Yes 36

Range Unit Color Greater than 5000 MW 5000 to 2000 MW 2000 to 1500 MW 1500 to 1000 MW 1000 to 750 MW 750 to 500 MW 500 to 250 MW 250 to 100 MW 100 to 10 MW 10 to 0 MW Figure A-6. Cumulative installations in 2015: fully extended tax credit case Table A-8. Nationwide Results for the Fully Extended Tax Credit Case Annual Cumulative Installers Market Installations Installation Required Penetration Year [MW] [MW] [FTE] [%]

2007 251 733 1,864 0.16%

2008 1,012 1,745 6,172 0.37%

2009 196 1,941 1,362 0.38%

2010 408 2,349 2,737 0.44%

2011 562 2,911 3,520 0.51%

2012 1,097 4,008 6,378 0.66%

2013 655 4,663 3,497 0.73%

2014 2,292 6,955 11,196 1.03%

2015 3,044 9,998 13,438 1.40%

37

Cumulative Installations [MW 8000 Residential Tax Credit Extended to 2010 6000 Residential Tax Credit Extended to 2015 4000 2000 0

2007 2008 2009 2010 2011 2012 2013 2014 2015 Year Figure A-7. Impact of extending the residential federal tax credit through 2015 in California, Connecticut, Pennsylvania, and Texas A-5. State-by-State Results Table A-9. State-by-State Technical Potential, Over Time Arkansas California Colorado Connecticut Delaware Alabama Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 9,376 840 10,515 4,655 51,667 7,778 3,986 1,217 34,087 16,574 1,883 2,194 17,594 2008 9,989 889 11,455 4,948 54,975 8,350 4,197 1,312 37,062 17,915 2,003 2,379 18,604 2009 10,601 943 12,447 5,261 58,344 8,955 4,414 1,400 40,062 19,321 2,119 2,572 19,648 2010 11,227 997 13,499 5,552 61,835 9,596 4,636 1,489 43,070 20,771 2,242 2,770 20,705 2011 11,855 1,050 14,579 5,849 65,377 10,249 4,858 1,579 46,133 22,254 2,366 2,968 21,771 2012 12,495 1,104 15,701 6,153 69,021 10,923 5,087 1,674 49,394 23,802 2,493 3,172 22,848 2013 13,178 1,161 16,946 6,479 72,828 11,644 5,317 1,777 52,985 25,487 2,626 3,402 23,974 2014 13,882 1,219 18,268 6,815 76,753 12,397 5,552 1,885 56,770 27,257 2,762 3,645 25,125 2015 14,606 1,279 19,671 7,160 80,798 13,184 5,790 1,997 60,760 29,119 2,903 3,901 26,302 38

Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Indiana Iowa Kansas Maine Mass.

2007 9,909 4,602 4,444 7,596 8,359 1,483 8,203 6,959 14,347 8,081 5,207 8,487 2008 10,521 4,867 4,700 8,065 8,887 1,569 8,730 7,329 15,137 8,571 5,534 9,014 2009 11,167 5,140 4,968 8,562 9,431 1,654 9,262 7,704 15,958 9,087 5,860 9,549 2010 11,822 5,418 5,242 9,068 9,954 1,742 9,804 8,091 16,792 9,609 6,198 10,092 2011 12,487 5,692 5,521 9,575 10,484 1,831 10,356 8,482 17,635 10,137 6,537 10,639 2012 13,167 5,970 5,805 10,089 11,022 1,923 10,921 8,882 18,500 10,683 6,876 11,201 2013 13,881 6,264 6,098 10,635 11,599 2,017 11,517 9,285 19,385 11,248 7,240 11,790 2014 14,617 6,564 6,397 11,198 12,192 2,113 12,130 9,695 20,288 11,829 7,615 12,395 2015 15,376 6,870 6,703 11,777 12,800 2,212 12,761 10,111 21,211 12,427 7,999 13,016 North Dakota Pennsylvani Nebraska New Jersey New Mexico New York Oklahoma Montana North Nevada Ohio Oregon NH Carolina a

2007 1,234 2,712 5,040 1,413 7,801 2,852 14,521 15,144 1,040 18,159 6,399 5,231 11,362 2008 1,304 2,881 5,535 1,499 8,228 3,036 15,262 16,234 1,099 19,162 6,775 5,581 11,969 2009 1,376 3,051 6,061 1,588 8,685 3,230 16,011 17,398 1,159 20,208 7,169 5,962 12,605 2010 1,450 3,226 6,615 1,679 9,138 3,437 16,766 18,569 1,219 21,266 7,561 6,351 13,246 2011 1,525 3,402 7,177 1,771 9,596 3,645 17,520 19,762 1,279 22,331 7,963 6,747 13,886 2012 1,601 3,583 7,760 1,866 10,064 3,858 18,285 21,010 1,339 23,420 8,370 7,152 14,539 2013 1,680 3,772 8,429 1,965 10,545 4,080 19,067 22,341 1,403 24,540 8,795 7,582 15,209 2014 1,760 3,967 9,145 2,066 11,036 4,311 19,858 23,728 1,468 25,682 9,230 8,029 15,891 2015 1,842 4,167 9,911 2,170 11,536 4,549 20,659 25,175 1,534 26,847 9,675 8,492 16,585 Rhode Island Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Virginia South Dakota Texas Utah DC Carolina 2007 1,036 7,619 1,106 11,774 42,773 3,691 708 13,565 9,025 1,236 2,467 8,158 768 2008 1,090 8,208 1,174 12,561 45,863 3,985 749 14,506 9,646 1,297 2,599 8,647 816 2009 1,145 8,817 1,245 13,370 49,089 4,279 789 15,444 10,309 1,369 2,728 9,139 865 2010 1,200 9,422 1,317 14,206 52,320 4,603 830 16,421 10,989 1,443 2,858 9,649 914 2011 1,255 10,039 1,388 15,049 55,632 4,927 872 17,417 11,681 1,516 2,985 10,165 964 2012 1,312 10,694 1,461 15,912 59,039 5,261 915 18,448 12,395 1,588 3,112 10,696 1,013 2013 1,369 11,398 1,538 16,829 62,708 5,625 959 19,538 13,152 1,663 3,246 11,246 1,067 2014 1,428 12,133 1,618 17,776 66,527 6,006 1,004 20,667 13,938 1,740 3,383 11,810 1,123 2015 1,487 12,902 1,700 18,757 70,499 6,407 1,050 21,837 14,755 1,818 3,522 12,389 1,180 39

Table A-10. State-by-State Results for the Worst Case Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 21 1 598 23 3 5 2 1 9 1 1 Cumulative Installations 2009 1 1 21 1 625 23 3 5 3 1 9 1 1 2010 1 1 21 1 678 23 4 5 4 1 9 1 1 2011 1 1 21 1 723 23 4 5 4 1 9 1 1 2012 1 1 21 1 923 23 5 5 4 1 9 1 1 2013 1 1 21 1 1,164 25 8 5 4 1 9 1 1 2014 1 1 21 1 1,445 27 10 5 4 1 9 1 1 2015 1 1 21 1 1,445 30 13 5 4 1 9 1 1 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 7 0 100 2 0 4 1 0 3 0 0 2009 0 0 0 0 27 0 0 0 1 0 0 0 0 Annual Installations 2010 0 0 0 0 53 0 0 0 1 0 0 0 0 2011 0 0 0 0 45 0 1 0 0 0 0 0 0 2012 0 0 0 0 199 1 1 0 0 0 0 0 0 2013 0 0 0 0 241 2 2 0 0 0 0 0 0 2014 0 0 0 0 281 2 2 0 0 0 0 0 0 2015 0 0 0 0 0 3 3 0 0 0 0 0 0 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 52 0 717 18 2 26 6 0 23 1 0 2009 0 0 0 0 189 0 2 0 6 0 0 0 0 Installers Required 2010 0 0 0 0 357 0 2 0 6 0 0 0 0 2011 0 0 0 0 281 0 4 0 0 0 0 0 0 2012 0 0 0 0 1,155 4 8 0 0 0 0 0 0 2013 0 0 0 0 1,286 9 11 0 0 0 0 0 0 2014 0 0 0 0 1,369 8 10 0 0 0 0 0 0 2015 0 0 0 0 0 13 15 0 0 0 0 0 0 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0% 0% 0%

2014 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0% 0% 0%

2015 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0% 0% 0%

40

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 1 1 2 2 9 1 1 1 1 Cumulative Installations 2009 1 1 1 1 1 5 2 10 1 1 1 1 2010 1 1 1 1 1 42 2 12 1 1 1 1 2011 1 1 1 1 1 42 2 12 1 1 1 1 2012 1 1 1 1 1 42 2 14 1 1 1 1 2013 1 1 1 1 1 51 2 18 1 1 1 1 2014 1 1 1 1 1 67 2 23 1 1 1 1 2015 1 1 1 1 1 90 3 31 1 1 1 1 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 1 0 0 0 2 0 0 0 0 2009 0 0 0 0 0 2 0 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 37 0 2 0 0 0 0 2011 0 0 0 0 0 0 0 0 0 0 0 0 2012 0 0 0 0 0 0 0 2 0 0 0 0 2013 0 0 0 0 0 9 0 5 0 0 0 0 2014 0 0 0 0 0 16 0 5 0 0 0 0 2015 0 0 0 0 0 23 1 7 0 0 0 0 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 7 0 1 0 13 0 2 0 0 2009 0 0 0 0 0 17 0 13 0 0 0 0 Installers Required 2010 0 0 0 0 0 250 0 12 0 0 0 0 2011 0 0 0 0 0 0 0 0 0 0 0 0 2012 0 0 0 0 0 0 0 9 0 0 0 0 2013 0 0 0 0 0 47 0 25 0 0 0 0 2014 0 0 0 0 0 80 0 22 0 0 0 0 2015 0 0 0 0 0 100 3 33 0 0 0 0 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 3% 0% 0% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 3% 0% 0% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 4% 0% 0% 0% 0% 0% 0%

41

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 16 1 73 12 35 6 1 6 1 6 9 Cumulative Installations 2009 1 1 16 1 73 12 35 6 1 6 1 9 9 2010 1 1 16 1 73 12 36 9 1 6 1 9 9 2011 1 1 16 1 73 12 38 9 1 6 1 11 9 2012 1 1 17 1 73 12 41 9 1 6 1 14 10 2013 1 1 18 1 73 12 45 9 1 6 1 16 11 2014 1 1 19 2 73 12 49 9 1 6 1 20 13 2015 1 1 21 3 73 14 56 9 1 6 1 24 17 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 1 0 3 3 3 3 0 4 0 4 0 2009 0 0 0 0 0 0 0 0 0 0 0 3 0 Annual Installations 2010 0 0 0 0 0 0 0 2 0 0 0 0 0 2011 0 0 0 0 0 0 2 0 0 0 0 2 0 2012 0 0 1 0 0 0 3 0 0 0 0 3 1 2013 0 0 1 0 0 0 4 0 0 0 0 3 1 2014 0 0 1 1 0 0 4 0 0 0 0 3 2 2015 0 0 2 1 0 2 7 0 0 0 0 4 4 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 6 0 22 21 20 24 0 26 0 30 0 2009 0 0 0 0 0 0 0 0 0 0 0 18 0 Installers Required 2010 0 0 0 0 0 0 3 16 0 0 0 0 0 2011 0 0 2 0 0 0 14 0 0 0 0 14 0 2012 0 0 3 0 0 0 19 0 0 0 0 15 3 2013 0 0 5 2 0 0 20 0 0 0 0 15 7 2014 0 0 6 3 0 2 18 0 0 0 0 17 9 2015 0 0 8 5 0 7 30 0 0 0 0 19 16 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2014 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2015 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

42

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 6 9 1 2 1 8 1 1 9 1 Cumulative Installations 2009 1 2 1 6 9 1 2 1 8 1 1 9 1 2010 1 2 1 6 12 1 2 1 8 1 1 9 1 2011 1 2 1 6 15 1 2 1 9 1 1 9 1 2012 1 2 1 6 20 1 2 1 10 1 1 9 1 2013 1 2 1 6 25 1 2 1 11 1 1 9 1 2014 1 2 1 6 33 1 2 1 13 2 1 9 1 2015 1 2 1 6 45 1 2 1 13 2 1 10 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 5 3 0 0 1 2 0 0 3 0 2009 0 0 0 0 0 0 0 0 0 0 0 0 0 Annual Installations 2010 0 0 0 0 3 0 0 0 0 0 0 0 0 2011 0 0 0 0 3 0 0 0 1 0 0 0 0 2012 0 0 0 0 5 0 0 0 1 0 0 0 0 2013 0 0 0 0 6 0 0 0 1 0 0 0 0 2014 0 0 0 0 8 0 0 0 1 0 0 0 0 2015 0 0 0 0 12 0 0 0 0 0 0 1 0 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 36 20 0 1 4 13 0 0 22 0 2009 0 0 0 0 0 0 0 0 0 0 0 0 0 Installers Required 2010 0 0 0 0 22 0 0 0 2 1 0 0 0 2011 0 0 0 0 17 0 0 0 5 0 0 0 0 2012 0 0 0 0 29 0 0 0 6 1 0 0 0 2013 0 0 0 0 31 0 0 0 7 1 0 0 0 2014 0 0 0 0 37 0 0 0 7 1 0 0 0 2015 1 0 0 0 52 0 1 0 0 1 0 3 0 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

43

Table A-11. State-by-State Results for the Base-Case, with BAU System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,051 34 3 10 2 1 10 1 1 Cumulative Installations 2009 1 1 72 1 1,105 35 6 10 3 1 10 1 1 2010 1 1 122 1 1,105 36 8 10 4 1 10 1 1 2011 1 1 187 1 1,105 73 8 10 5 1 10 1 1 2012 1 1 268 1 1,272 75 10 10 9 1 10 1 1 2013 1 1 313 1 1,272 77 14 10 13 1 10 1 1 2014 1 1 360 1 1,275 78 21 16 21 9 10 1 1 2015 1 1 408 1 1,566 120 24 20 30 11 12 1 2 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 552 14 0 9 1 0 4 0 0 2009 0 0 31 0 55 1 3 0 1 0 0 0 0 Annual Installations 2010 0 0 50 0 0 1 1 0 1 0 0 0 0 2011 0 0 65 0 0 37 0 0 1 0 0 0 0 2012 0 0 81 0 167 2 3 0 4 0 0 0 0 2013 0 0 45 0 0 2 4 0 3 1 0 0 0 2014 0 0 47 0 3 2 7 6 9 7 0 0 0 2015 0 0 49 0 291 42 4 4 9 3 1 0 1 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 3,973 102 2 64 6 0 27 1 0 2009 0 0 214 0 379 5 24 0 6 0 0 1 0 Installers Required 2010 0 0 339 0 0 5 9 0 6 0 0 0 0 2011 0 0 407 0 0 235 0 0 8 0 0 0 0 2012 0 0 467 0 965 9 16 0 26 0 0 0 0 2013 0 0 239 0 0 9 19 0 17 5 0 0 0 2014 0 0 228 0 15 8 33 28 44 35 2 0 0 2015 0 0 214 0 1,286 184 16 18 38 12 6 0 5 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

2009 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

2011 0% 0% 1% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2012 0% 0% 2% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2013 0% 0% 2% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2014 0% 0% 2% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2015 0% 0% 2% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

44

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 2 1 2 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 2 1 25 15 10 1 1 1 1 2010 1 1 1 2 1 79 24 12 1 1 1 1 2011 1 1 1 2 1 79 24 18 1 1 1 1 2012 1 1 1 2 1 79 59 26 1 1 1 1 2013 1 1 1 2 1 79 59 34 1 1 1 1 2014 1 1 1 2 1 96 149 49 2 1 2 1 2015 1 1 1 2 1 122 149 57 2 1 2 1 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 1 0 0 1 2 0 0 0 0 2009 0 0 0 0 0 22 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 55 9 2 0 0 0 0 2011 0 0 0 0 0 0 0 5 0 0 0 0 2012 0 0 0 0 0 0 35 9 0 0 0 0 2013 0 0 0 0 0 0 0 8 0 0 0 0 2014 0 0 0 0 0 17 90 16 1 0 1 0 2015 0 0 0 0 0 25 0 8 1 0 1 0 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 8 0 3 4 13 0 2 0 0 2009 0 0 0 0 0 155 88 13 0 0 0 0 Installers Required 2010 0 0 0 0 0 367 57 12 0 0 0 0 2011 0 0 0 0 0 0 0 33 0 0 0 0 2012 0 0 0 0 0 0 202 49 0 0 2 0 2013 0 0 0 0 0 0 0 41 0 0 1 0 2014 0 0 0 0 0 84 441 76 5 0 3 0 2015 0 0 0 0 0 111 0 33 3 0 3 0 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 5% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 4% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 4% 1% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 4% 1% 0% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 5% 1% 1% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 6% 1% 1% 0% 0% 0% 0%

45

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 12 128 6 1 6 1 6 10 Cumulative Installations 2009 1 1 107 1 140 12 134 10 1 6 1 9 23 2010 1 1 109 4 194 12 140 22 1 6 1 76 37 2011 1 1 140 8 253 12 146 22 1 6 1 112 58 2012 1 1 143 16 321 14 153 76 1 6 1 150 96 2013 1 1 175 22 405 16 159 76 1 6 1 193 166 2014 1 1 179 33 502 21 160 76 1 9 1 258 290 2015 1 1 203 33 614 25 161 154 1 14 1 333 343 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 3 95 3 0 4 0 4 0 2009 0 0 28 0 37 0 6 4 0 0 0 3 13 Annual Installations 2010 0 0 2 3 55 0 6 12 0 0 0 67 14 2011 0 0 30 4 59 0 6 0 0 0 0 36 21 2012 0 0 3 8 68 2 6 54 0 0 0 38 38 2013 0 0 32 6 83 2 6 0 0 0 0 43 70 2014 0 0 4 11 98 5 1 0 0 3 1 65 124 2015 0 0 24 0 111 4 1 77 0 5 0 75 53 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 23 43 22 0 26 0 30 3 2009 0 0 198 2 255 1 42 27 0 0 0 18 91 Installers Required 2010 0 0 16 19 366 0 41 82 0 0 0 451 93 2011 0 0 189 27 366 0 39 0 0 0 0 226 133 2012 0 0 17 44 397 9 37 310 0 0 0 220 221 2013 0 0 172 30 444 11 34 2 0 1 0 231 373 2014 0 0 18 54 475 25 6 2 0 16 3 315 606 2015 0 0 107 2 492 20 5 341 0 24 1 332 233 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 0% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 1% 0%

2011 0% 0% 2% 0% 3% 0% 1% 0% 0% 0% 0% 2% 0%

2012 0% 0% 2% 1% 3% 0% 1% 0% 0% 0% 0% 2% 1%

2013 0% 0% 2% 1% 4% 0% 1% 0% 0% 0% 0% 3% 1%

2014 0% 0% 2% 2% 5% 0% 1% 0% 0% 0% 0% 3% 2%

2015 0% 0% 2% 2% 5% 1% 1% 1% 0% 0% 0% 4% 2%

46

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 6 8 1 2 1 8 1 1 10 1 Cumulative Installations 2009 1 2 1 6 12 1 2 1 9 1 1 10 1 2010 1 2 1 6 20 1 2 1 11 3 1 10 1 2011 1 2 1 6 23 1 2 1 11 3 1 10 1 2012 1 2 1 6 27 1 3 1 13 7 1 10 1 2013 1 2 1 6 32 1 3 1 15 7 1 10 1 2014 2 2 1 6 45 1 3 2 21 7 1 15 1 2015 2 3 1 6 63 1 4 3 21 7 1 17 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 5 2 0 0 1 2 0 0 4 0 2009 0 0 0 0 4 0 0 0 1 0 0 0 0 Annual Installations 2010 0 0 0 0 8 0 0 0 2 1 0 0 0 2011 0 0 0 0 3 0 0 0 0 0 0 0 0 2012 0 0 0 0 4 0 0 0 2 4 0 0 0 2013 0 0 0 0 4 0 0 0 2 0 0 0 0 2014 1 0 0 0 13 0 1 0 6 0 0 5 0 2015 0 1 0 0 18 0 0 2 0 0 0 2 0 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 37 16 0 1 4 17 1 0 29 0 2009 0 0 0 0 26 0 0 0 5 2 0 0 0 Installers Required 2010 1 0 0 0 51 0 0 0 12 8 0 0 0 2011 1 0 0 0 20 0 1 0 0 0 0 0 0 2012 1 0 0 0 25 0 1 0 12 24 0 0 0 2013 1 0 0 0 24 0 1 0 13 0 0 2 0 2014 5 1 0 0 65 0 3 1 30 1 0 24 1 2015 0 3 0 1 81 0 1 8 0 0 0 7 1 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

47

Table A-12. State-by-State Results for the Base Case, with SAI System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,220 34 3 11 2 1 10 1 1 Cumulative Installations 2009 1 1 72 1 1,220 35 8 11 3 1 10 1 1 2010 1 1 122 1 1,220 36 11 11 4 3 10 1 1 2011 1 1 187 1 1,256 73 13 11 15 6 10 1 1 2012 1 1 268 1 1,524 75 19 11 24 9 11 1 1 2013 1 1 313 1 1,886 77 26 11 32 14 12 1 1 2014 1 1 360 1 2,890 78 82 16 48 24 22 1 6 2015 3 1 408 1 3,202 146 108 18 69 31 27 2 14 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 721 14 0 10 1 0 4 0 0 2009 0 0 31 0 0 1 5 0 1 1 0 0 0 Annual Installations 2010 0 0 50 0 0 1 4 0 1 2 0 0 0 2011 0 0 65 0 36 37 2 0 11 3 0 0 0 2012 0 0 81 0 269 2 6 0 9 3 0 0 0 2013 0 0 45 0 361 2 7 0 8 4 2 0 0 2014 0 0 47 0 1,005 2 56 5 16 11 10 0 5 2015 2 0 49 0 311 67 26 1 21 6 4 1 8 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 5,192 102 2 75 6 0 32 2 0 2009 0 0 214 0 0 5 33 0 6 4 0 1 0 Installers Required 2010 0 0 339 0 0 5 25 0 6 16 0 0 0 2011 0 0 407 0 225 235 10 0 69 16 0 0 0 2012 0 0 467 0 1,557 9 34 24 52 20 1 0 0 2013 0 0 239 0 1,927 9 38 0 44 23 9 0 2 2014 0 0 228 0 4,898 8 274 49 80 51 48 2 25 2015 9 0 214 0 1,374 298 114 6 91 28 20 3 37 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 2% 0% 0% 1% 0% 0% 1% 0% 0%

2009 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

2011 0% 0% 1% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2012 0% 0% 2% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2013 0% 0% 2% 0% 3% 1% 0% 1% 0% 0% 0% 0% 0%

2014 0% 0% 2% 0% 4% 1% 1% 1% 0% 0% 1% 0% 0%

2015 0% 0% 2% 0% 4% 1% 2% 1% 0% 0% 1% 0% 0%

48

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 2 1 3 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 2 1 41 15 10 1 1 1 1 2010 1 1 1 2 1 119 15 12 1 1 1 1 2011 1 1 1 2 1 119 35 31 1 1 1 1 2012 1 1 1 2 1 119 35 64 2 1 2 1 2013 1 1 1 2 1 129 89 94 5 2 2 1 2014 1 1 1 3 3 176 89 213 12 7 3 1 2015 1 1 1 5 4 216 212 283 16 9 5 1 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 1 0 1 1 2 0 0 0 0 2009 0 0 0 0 0 38 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 78 0 2 0 0 0 0 2011 0 0 0 0 0 0 20 19 0 0 0 0 2012 0 0 0 0 0 0 0 33 1 0 1 0 2013 0 0 0 0 0 9 53 30 3 1 0 0 2014 0 0 0 1 2 47 0 119 7 5 1 0 2015 0 0 0 2 1 40 123 71 4 2 2 1 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 10 0 4 4 13 0 2 0 0 2009 0 0 0 0 0 268 89 13 0 0 1 0 Installers Required 2010 0 0 0 0 0 526 0 12 0 0 2 0 2011 0 0 0 0 0 0 125 118 2 0 2 0 2012 0 0 0 0 2 0 0 191 5 2 3 0 2013 0 0 0 0 3 50 284 159 13 6 3 0 2014 0 1 1 4 10 230 0 580 36 22 5 0 2015 0 2 1 10 4 176 545 312 18 10 8 4 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 7% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 7% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 6% 0% 1% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 6% 1% 1% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 8% 1% 2% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 10% 2% 3% 0% 0% 0% 0%

49

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 13 128 6 1 7 1 6 10 Cumulative Installations 2009 1 1 107 2 140 14 134 13 1 7 1 9 23 2010 1 1 109 6 194 14 140 55 1 7 1 118 37 2011 1 1 140 8 253 15 146 55 1 7 1 167 58 2012 1 1 143 16 321 22 153 76 1 9 1 232 96 2013 1 1 175 22 405 32 159 76 1 12 2 295 166 2014 2 1 179 33 568 73 160 76 1 23 3 400 290 2015 2 1 203 34 736 110 161 154 1 40 4 508 343 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 4 95 3 0 5 0 4 1 2009 0 0 28 1 37 1 6 6 0 0 0 3 13 Annual Installations 2010 0 0 2 4 55 0 6 43 0 0 0 109 14 2011 0 0 30 3 59 1 6 0 0 0 0 50 21 2012 0 0 3 8 68 7 6 20 0 2 0 64 38 2013 0 0 32 6 83 10 6 0 0 3 0 63 70 2014 1 0 4 11 164 40 1 0 0 10 2 106 124 2015 1 0 24 1 167 38 1 77 0 17 1 108 53 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 32 43 22 0 34 0 30 6 2009 0 0 198 5 255 4 42 45 0 0 0 18 88 Installers Required 2010 0 0 16 28 366 0 41 287 0 0 1 730 93 2011 0 0 189 16 366 8 39 0 0 1 1 312 133 2012 0 0 17 44 397 41 37 118 0 11 3 373 221 2013 0 0 172 30 444 54 34 2 0 19 2 334 373 2014 3 1 18 54 798 197 6 2 0 51 9 514 606 2015 3 1 107 6 738 166 5 341 0 76 4 477 233 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 0% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 2% 0%

2011 0% 0% 2% 0% 3% 0% 1% 0% 0% 0% 0% 2% 0%

2012 0% 0% 2% 1% 3% 1% 1% 0% 0% 0% 0% 3% 1%

2013 0% 0% 2% 1% 4% 1% 1% 0% 0% 0% 0% 4% 1%

2014 0% 0% 2% 2% 5% 2% 1% 0% 0% 0% 0% 5% 2%

2015 0% 0% 2% 2% 6% 2% 1% 1% 0% 0% 0% 6% 2%

50

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 7 9 1 2 1 9 1 1 11 1 Cumulative Installations 2009 1 2 1 7 17 1 2 1 11 1 1 11 1 2010 1 2 1 7 41 1 3 1 17 4 1 13 1 2011 1 2 1 7 41 1 3 1 17 4 1 13 1 2012 2 3 1 7 52 1 3 2 24 7 1 16 1 2013 2 4 1 7 64 1 4 4 39 9 1 23 1 2014 4 8 1 10 112 1 6 10 79 9 2 37 1 2015 4 10 1 16 219 2 8 14 79 9 3 46 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 6 3 0 0 1 3 0 0 5 0 2009 0 0 0 0 8 0 0 0 2 0 0 0 0 Annual Installations 2010 1 0 0 0 25 0 1 0 6 3 0 2 0 2011 0 0 0 0 0 0 0 0 0 0 0 0 0 2012 0 1 0 0 10 0 1 1 7 2 0 3 0 2013 1 1 0 0 12 0 1 2 16 2 0 6 0 2014 1 3 0 4 48 0 2 5 40 0 1 15 0 2015 1 2 0 5 107 2 2 4 0 0 1 9 0 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 43 24 0 2 4 23 1 0 37 0 2009 1 0 0 0 53 0 0 0 16 2 0 0 0 Installers Required 2010 5 0 0 0 165 0 4 0 37 20 0 13 0 2011 0 2 0 0 0 0 0 0 1 0 0 0 1 2012 2 5 0 0 60 0 4 6 39 13 0 19 1 2013 3 6 0 0 64 0 5 9 83 13 0 33 1 2014 5 17 0 18 234 0 10 27 195 0 5 71 1 2015 4 8 0 24 474 7 7 19 0 0 5 41 1 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2014 0% 0% 0% 0% 0% 0% 1% 0% 1% 1% 0% 0% 0%

2015 0% 0% 0% 0% 0% 0% 1% 0% 1% 0% 0% 0% 0%

51

Table A-13. State-by-State Results for the Focused Policy Case, BAU System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,051 34 3 10 2 1 10 1 1 Cumulative Installations 2009 1 1 72 1 1,105 35 6 10 3 1 10 1 1 2010 1 1 122 1 1,105 36 8 10 4 1 10 1 1 2011 1 1 187 1 1,603 73 10 10 5 1 10 1 1 2012 1 1 268 1 2,364 75 15 10 10 1 10 1 1 2013 1 1 313 1 2,713 77 20 10 13 1 12 1 1 2014 5 1 360 1 4,317 78 30 16 22 9 15 1 1 2015 11 1 408 1 5,314 120 35 18 44 11 18 1 2 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 552 14 0 9 1 0 4 0 0 2009 0 0 31 0 55 1 3 0 1 0 0 0 0 Annual Installations 2010 0 0 50 0 0 1 1 0 1 0 0 0 0 2011 0 0 65 0 497 37 3 0 1 0 0 0 0 2012 0 0 81 0 761 2 5 0 5 0 0 0 0 2013 0 0 45 0 349 2 5 0 3 1 2 0 0 2014 4 0 47 0 1,604 2 10 6 9 7 3 0 0 2015 6 0 49 0 997 42 5 1 22 3 3 0 1 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 3,973 102 2 64 6 0 27 1 0 2009 0 0 214 0 379 5 24 0 6 0 0 1 0 Installers Required 2010 0 0 339 0 0 5 9 0 6 0 0 0 0 2011 0 0 407 0 3,112 235 17 0 8 0 0 0 0 2012 0 0 467 0 4,413 9 28 0 28 0 0 0 0 2013 2 0 239 0 1,861 9 27 0 17 5 11 0 0 2014 18 1 228 0 7,821 8 48 49 43 35 17 0 0 2015 28 1 214 0 4,401 184 22 6 98 12 13 0 5 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

2009 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

2011 0% 0% 1% 0% 2% 1% 0% 1% 0% 0% 0% 0% 0%

2012 0% 0% 2% 0% 3% 1% 0% 1% 0% 0% 0% 0% 0%

2013 0% 0% 2% 0% 4% 1% 0% 1% 0% 0% 0% 0% 0%

2014 0% 0% 2% 0% 6% 1% 1% 1% 0% 0% 1% 0% 0%

2015 0% 0% 2% 0% 7% 1% 1% 1% 0% 0% 1% 0% 0%

52

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 2 1 2 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 2 1 25 15 10 1 1 1 1 2010 1 1 1 2 1 79 24 12 1 1 1 1 2011 1 1 1 2 1 79 24 25 1 1 1 1 2012 1 1 1 2 1 84 59 36 1 1 1 1 2013 1 1 1 2 1 108 59 48 1 1 1 1 2014 1 1 1 2 1 139 149 70 2 1 2 1 2015 1 1 1 2 1 168 149 81 2 1 2 1 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 1 0 0 1 2 0 0 0 0 2009 0 0 0 0 0 22 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 55 9 2 0 0 0 0 2011 0 0 0 0 0 0 0 13 0 0 0 0 2012 0 0 0 0 0 5 35 11 0 0 0 0 2013 0 0 0 0 0 24 0 12 0 0 0 0 2014 0 0 0 0 0 30 90 22 1 0 1 0 2015 0 0 0 0 0 29 0 11 1 0 1 0 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 8 0 3 4 13 0 2 0 0 2009 0 0 0 0 0 155 88 13 0 0 0 0 Installers Required 2010 0 0 0 0 0 367 57 12 0 0 0 0 2011 0 0 0 0 0 0 0 81 0 0 0 0 2012 0 0 0 0 0 29 202 63 0 0 2 0 2013 0 0 0 0 0 129 0 62 0 0 1 0 2014 0 0 0 0 0 148 441 109 5 0 3 0 2015 0 0 0 0 0 128 0 49 3 0 3 0 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 5% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 4% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 4% 1% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 5% 1% 1% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 7% 1% 1% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 8% 1% 1% 0% 0% 0% 0%

53

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 12 128 6 1 6 1 6 10 Cumulative Installations 2009 1 1 107 1 140 12 134 10 1 6 1 9 23 2010 1 1 109 4 194 12 140 22 1 6 1 76 37 2011 1 1 140 8 253 13 146 22 1 6 1 112 58 2012 1 1 143 16 321 17 153 76 1 6 1 152 96 2013 1 1 175 22 405 21 159 76 1 6 1 199 166 2014 1 1 179 33 502 29 239 76 1 9 1 271 290 2015 1 1 203 33 614 35 280 154 1 14 1 352 343 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 3 95 3 0 4 0 4 0 2009 0 0 28 0 37 0 6 4 0 0 0 3 13 Annual Installations 2010 0 0 2 3 55 0 6 12 0 0 0 67 14 2011 0 0 30 4 59 1 6 0 0 0 0 36 21 2012 0 0 3 8 68 4 6 54 0 0 0 40 38 2013 0 0 32 6 83 4 6 0 0 0 0 47 70 2014 0 0 4 11 98 8 80 0 0 3 1 72 124 2015 0 0 24 0 111 6 41 77 0 5 0 81 53 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 23 43 22 0 26 0 30 3 2009 0 0 198 2 255 1 42 27 0 0 0 18 91 Installers Required 2010 0 0 16 19 366 0 41 82 0 0 0 451 93 2011 0 0 189 27 366 5 39 0 0 0 0 226 133 2012 0 0 17 44 397 25 37 310 0 0 0 230 221 2013 0 0 172 30 444 21 34 2 0 1 0 249 373 2014 0 0 18 54 475 38 390 2 0 16 3 352 606 2015 0 0 107 2 492 26 182 341 0 24 1 357 233 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 0% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 1% 0%

2011 0% 0% 2% 0% 3% 0% 1% 0% 0% 0% 0% 2% 0%

2012 0% 0% 2% 1% 3% 0% 1% 0% 0% 0% 0% 2% 1%

2013 0% 0% 2% 1% 4% 1% 1% 0% 0% 0% 0% 3% 1%

2014 0% 0% 2% 2% 5% 1% 1% 0% 0% 0% 0% 3% 2%

2015 0% 0% 2% 2% 5% 1% 1% 1% 0% 0% 0% 4% 2%

54

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 7 8 1 2 1 8 1 1 10 1 Cumulative Installations 2009 1 2 1 7 12 1 2 1 9 1 1 10 1 2010 1 2 1 7 20 1 2 1 11 3 1 10 1 2011 1 2 1 7 23 1 2 1 14 3 1 10 1 2012 2 2 1 7 27 1 3 1 19 7 1 14 1 2013 3 2 1 7 32 1 4 1 24 10 1 18 1 2014 4 7 1 7 56 1 5 2 32 10 1 28 1 2015 5 8 1 7 117 1 6 3 32 10 1 31 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 7 2 0 0 1 2 0 0 4 0 2009 0 0 0 0 4 0 0 0 1 0 0 0 0 Annual Installations 2010 0 0 0 0 8 0 0 0 2 1 0 0 0 2011 0 0 0 0 3 0 0 0 3 0 0 0 0 2012 1 0 0 0 4 0 1 0 5 4 0 4 0 2013 1 0 0 0 4 0 1 0 5 3 0 4 0 2014 1 5 0 0 25 0 1 0 8 0 0 10 0 2015 1 1 0 0 60 0 1 2 0 0 0 3 0 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 50 16 0 1 4 17 1 0 29 0 2009 0 0 0 0 26 0 0 0 5 2 0 0 0 Installers Required 2010 1 0 0 0 51 0 0 0 12 8 0 0 0 2011 2 0 0 0 20 0 2 0 18 0 0 0 0 2012 5 0 0 0 25 0 4 0 28 24 0 21 0 2013 3 0 0 0 24 0 3 0 27 16 0 23 0 2014 6 24 0 0 121 0 6 1 40 0 0 48 1 2015 3 4 0 0 266 0 2 8 0 0 0 14 1 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2014 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2015 0% 0% 0% 0% 0% 0% 1% 0% 0% 1% 0% 0% 0%

55

Table A-14. State-by-State Results for the Focused Policy Case, SAI System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,220 34 3 11 2 1 10 1 1 Cumulative Installations 2009 1 1 72 1 1,441 35 8 11 3 1 10 1 1 2010 1 1 122 1 1,771 36 11 11 4 3 10 1 1 2011 2 1 187 1 2,757 73 18 11 15 6 12 1 1 2012 4 1 268 1 4,009 75 27 11 31 9 16 1 1 2013 10 1 313 1 5,210 77 50 11 63 14 21 1 1 2014 22 2 360 1 7,961 95 176 16 135 24 39 1 6 2015 35 2 408 1 10,772 179 246 28 198 31 70 2 16 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 721 14 0 10 1 0 4 0 0 2009 0 0 31 0 222 1 5 0 1 1 0 0 0 Annual Installations 2010 0 0 50 0 330 1 4 0 1 2 0 0 0 2011 1 0 65 0 985 37 6 0 11 3 2 0 0 2012 3 0 81 0 1,252 2 9 0 16 3 4 0 0 2013 5 0 45 0 1,201 2 24 0 32 4 5 0 0 2014 12 0 47 0 2,751 18 126 5 72 11 18 0 5 2015 13 1 49 0 2,810 84 70 12 64 6 31 1 10 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 5,192 102 2 75 6 0 32 2 0 2009 0 0 214 0 1,541 5 33 0 6 4 0 1 0 Installers Required 2010 2 0 339 0 2,215 5 25 0 6 16 0 0 0 2011 6 2 407 0 6,163 235 39 2 70 16 12 0 0 2012 15 1 467 0 7,258 9 52 22 93 20 20 0 0 2013 28 2 239 0 6,407 9 127 0 169 23 26 0 2 2014 60 2 228 0 13,413 87 612 49 352 51 86 2 25 2015 58 3 214 1 12,406 372 311 53 281 29 138 3 46 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 2% 0% 0% 1% 0% 0% 1% 0% 0%

2009 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 3% 0% 0% 1% 0% 0% 0% 0% 0%

2011 0% 0% 1% 0% 4% 1% 0% 1% 0% 0% 1% 0% 0%

2012 0% 0% 2% 0% 6% 1% 1% 1% 0% 0% 1% 0% 0%

2013 0% 0% 2% 0% 7% 1% 1% 1% 0% 0% 1% 0% 0%

2014 0% 0% 2% 0% 10% 1% 3% 1% 0% 0% 1% 0% 0%

2015 0% 0% 2% 0% 13% 1% 4% 1% 0% 0% 2% 0% 0%

56

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 2 1 3 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 2 1 41 15 10 1 1 1 1 2010 1 1 1 2 1 119 15 12 1 1 1 1 2011 1 1 1 2 1 119 35 41 1 1 1 1 2012 1 1 1 2 1 126 35 80 2 1 2 1 2013 1 1 1 2 1 165 89 136 5 2 2 1 2014 1 1 1 3 3 213 89 405 22 12 8 1 2015 11 1 1 5 4 266 212 573 32 16 14 1 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 1 0 1 1 2 0 0 0 0 2009 0 0 0 0 0 38 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 78 0 2 0 0 0 0 2011 0 0 0 0 0 0 20 29 0 0 0 0 2012 0 0 0 0 0 7 0 39 1 0 1 0 2013 0 0 0 0 0 39 53 56 3 1 1 0 2014 0 0 0 1 2 47 0 268 17 10 6 0 2015 11 0 0 2 1 53 123 168 10 4 6 1 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 10 0 4 4 13 0 2 0 0 2009 0 0 0 0 0 268 89 13 0 0 1 0 Installers Required 2010 0 0 0 0 0 526 0 12 0 0 2 0 2011 0 0 0 0 0 0 125 179 2 0 2 0 2012 0 0 0 0 2 42 0 226 5 2 3 0 2013 0 0 0 0 3 208 284 301 16 6 3 0 2014 0 1 1 4 10 231 0 1,308 83 47 29 0 2015 48 2 1 10 4 233 545 743 43 19 26 4 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 2% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 7% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 7% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 7% 0% 1% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 8% 1% 1% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 10% 1% 4% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 12% 2% 6% 0% 0% 0% 0%

57

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 13 128 6 1 7 1 6 10 Cumulative Installations 2009 1 1 107 2 140 14 134 13 1 7 1 9 23 2010 1 1 109 6 194 14 140 55 1 7 1 118 37 2011 1 1 140 8 262 18 146 55 1 7 1 173 58 2012 1 1 143 22 386 28 210 76 1 9 1 244 101 2013 1 1 175 22 530 40 373 76 1 12 2 319 166 2014 3 1 179 33 530 112 698 76 1 23 3 504 290 2015 5 1 276 50 614 173 838 154 1 51 4 830 511 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 4 95 3 0 5 0 4 1 2009 0 0 28 1 37 1 6 6 0 0 0 3 13 Annual Installations 2010 0 0 2 4 55 0 6 43 0 0 0 109 14 2011 0 0 30 3 68 5 6 0 0 0 0 54 21 2012 0 0 3 13 124 10 64 20 0 2 0 72 43 2013 0 0 32 0 145 12 164 0 0 3 0 75 65 2014 2 1 4 11 0 72 325 0 0 10 2 185 124 2015 2 0 98 18 83 62 140 77 0 28 1 326 221 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 32 43 22 0 34 0 30 6 2009 0 0 198 5 255 4 42 45 0 0 0 18 88 Installers Required 2010 0 0 16 28 366 0 41 287 0 0 1 734 93 2011 0 0 189 16 424 30 39 0 0 1 1 340 133 2012 0 0 17 77 717 55 368 118 0 11 3 414 252 2013 0 0 172 0 771 63 873 2 0 19 2 402 344 2014 10 3 18 53 0 350 1,584 2 0 51 9 902 606 2015 7 2 431 77 367 273 618 341 0 123 4 1,439 974 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 0% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 2% 0%

2011 0% 0% 2% 0% 3% 1% 1% 0% 0% 0% 0% 3% 0%

2012 0% 0% 2% 1% 4% 1% 1% 0% 0% 0% 0% 3% 1%

2013 0% 0% 2% 1% 5% 1% 2% 0% 0% 0% 0% 4% 1%

2014 0% 0% 2% 2% 5% 3% 4% 0% 0% 0% 0% 6% 2%

2015 0% 0% 3% 2% 5% 4% 4% 1% 0% 0% 0% 10% 3%

58

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 9 9 1 2 1 9 1 1 11 1 Cumulative Installations 2009 1 2 1 9 17 1 2 1 11 1 1 11 1 2010 1 2 1 9 41 1 3 1 17 4 1 13 1 2011 2 3 1 9 52 1 3 1 23 4 1 18 1 2012 3 6 1 9 80 1 5 2 32 7 1 25 1 2013 5 10 1 9 108 1 6 4 52 25 1 35 1 2014 8 21 1 14 199 4 9 23 106 25 2 57 1 2015 10 27 1 27 350 7 13 38 106 61 5 71 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 8 3 0 0 1 3 0 0 5 0 2009 0 0 0 0 8 0 0 0 2 0 0 0 0 Annual Installations 2010 1 0 0 0 25 0 1 0 6 3 0 2 0 2011 1 1 0 0 11 0 1 0 6 0 0 5 0 2012 1 3 0 0 28 0 1 1 9 2 0 7 0 2013 2 4 0 0 28 0 1 2 19 18 0 9 0 2014 3 11 0 5 91 4 3 19 55 0 1 22 0 2015 2 6 0 13 151 3 4 14 0 37 4 14 0 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 59 24 0 2 4 23 1 0 37 0 2009 1 0 0 0 53 0 0 0 16 2 0 0 0 Installers Required 2010 5 1 0 0 165 0 4 0 37 20 0 13 0 2011 5 4 0 0 68 0 4 0 39 0 0 30 1 2012 7 19 0 0 162 0 7 6 54 13 0 43 1 2013 9 22 0 0 147 0 7 10 102 96 0 50 1 2014 16 52 2 24 445 19 15 93 267 0 5 109 1 2015 9 27 1 58 668 13 19 63 0 163 16 62 1 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 1% 0% 0% 1% 0% 0% 0%

2014 1% 0% 0% 0% 0% 0% 1% 0% 1% 1% 0% 0% 0%

2015 1% 0% 0% 0% 0% 0% 1% 0% 1% 3% 0% 1% 0%

59

Table A-15. State-by-State Results for the Focused Policy Case, SAI System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,059 34 3 16 2 1 11 1 1 Cumulative Installations 2009 1 1 72 1 1,605 35 11 16 3 3 11 2 1 2010 1 1 122 1 2,598 36 20 16 4 7 12 2 1 2011 1 1 187 1 2,598 73 21 16 25 11 12 2 1 2012 1 1 268 1 3,009 75 30 16 39 16 14 2 5 2013 3 1 313 1 4,471 77 42 16 57 22 18 2 10 2014 7 1 360 1 6,071 78 107 16 79 29 35 3 18 2015 14 2 408 1 8,325 120 171 19 163 41 58 4 33 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 561 14 0 15 1 0 5 0 0 2009 0 0 31 0 546 1 8 0 1 2 0 1 0 Annual Installations 2010 0 0 50 0 992 1 9 0 1 5 1 0 0 2011 0 0 65 0 0 37 2 0 22 4 0 0 1 2012 0 0 81 0 411 2 9 0 14 5 3 0 4 2013 2 0 45 0 1,462 2 13 0 18 6 4 0 5 2014 4 0 47 0 1,600 2 65 1 22 7 17 1 8 2015 8 1 49 0 2,254 42 63 3 84 12 23 2 15 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 4,037 102 2 107 6 0 35 1 0 2009 0 0 214 0 3,798 5 54 0 6 15 0 6 0 Installers Required 2010 0 0 339 0 6,663 5 62 0 6 32 5 0 0 2011 0 0 407 0 0 235 10 0 135 24 0 0 6 2012 0 0 467 0 2,384 9 49 0 82 28 15 0 22 2013 12 0 239 0 7,801 9 67 9 96 32 22 0 28 41 2014 20 0 228 0 7,799 8 316 105 34 83 5 37 2015 34 5 214 0 9,951 184 280 12 369 51 101 7 65 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 2% 0% 0% 1% 0% 0% 1% 0% 0%

2009 0% 0% 1% 0% 3% 0% 0% 1% 0% 0% 1% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 4% 0% 0% 1% 0% 0% 1% 0% 0%

2011 0% 0% 1% 0% 4% 1% 0% 2% 0% 0% 0% 0% 0%

2012 0% 0% 2% 0% 4% 1% 1% 3% 0% 0% 1% 0% 0%

2013 0% 0% 2% 0% 6% 1% 1% 6% 0% 0% 1% 0% 0%

2014 0% 0% 2% 0% 8% 1% 2% 8% 0% 0% 1% 0% 0%

2015 0% 0% 2% 0% 10% 1% 3% 12% 0% 0% 2% 0% 0%

60

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 2 1 3 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 2 1 100 15 10 1 1 1 1 2010 1 1 1 2 1 302 15 12 2 1 1 1 2011 1 1 1 2 1 302 35 30 3 1 2 1 2012 1 1 1 2 1 302 35 42 5 1 4 1 2013 1 1 1 3 2 319 89 55 9 1 5 1 2014 1 1 1 6 4 424 89 124 14 1 7 1 2015 1 1 1 12 7 536 212 194 24 2 11 3 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 2 0 1 1 2 0 0 0 0 2009 0 0 0 0 0 97 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 203 0 2 1 0 1 0 2011 0 0 0 0 0 0 20 17 1 0 1 0 2012 0 0 0 0 0 0 0 12 2 0 1 0 2013 0 0 0 1 1 17 53 13 4 0 1 0 2014 0 0 0 3 1 106 0 70 5 0 2 0 2015 0 1 0 6 4 112 123 70 11 1 4 2 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 12 0 5 4 13 0 2 0 0 2009 0 0 0 0 0 674 89 13 0 0 0 0 Installers Required 2010 0 0 0 0 0 1,360 0 12 6 0 6 0 2011 0 0 0 0 0 0 125 108 6 0 6 0 2012 0 0 0 0 3 0 0 70 13 0 7 0 2013 0 0 0 6 6 88 284 69 20 0 8 0 2014 0 0 0 13 7 515 0 341 25 0 9 0 2015 0 3 0 28 17 494 545 308 47 5 19 11 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 6% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 17% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 17% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 16% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 16% 1% 1% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 20% 1% 1% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 24% 2% 2% 0% 0% 0% 0%

61

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 12 128 6 1 5 1 48 9 Cumulative Installations 2009 1 1 107 2 140 14 134 29 1 5 1 48 23 2010 1 1 109 9 322 15 140 140 1 7 1 48 45 2011 1 1 140 9 322 16 146 140 1 9 2 48 58 2012 1 1 143 21 472 26 153 140 1 12 3 48 96 2013 2 1 175 30 405 43 159 140 1 16 4 48 166 2014 2 1 179 33 502 79 275 140 1 20 5 48 290 2015 5 2 314 33 614 123 435 154 1 34 7 48 442 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 4 95 3 0 3 0 46 0 2009 0 0 28 1 37 2 6 23 0 0 0 0 13 Annual Installations 2010 0 0 2 7 183 1 6 112 0 1 1 0 23 2011 0 0 30 0 0 1 6 0 0 2 1 0 13 2012 0 0 3 12 150 10 6 0 0 3 1 0 38 2013 0 0 32 9 -68 17 6 0 0 4 1 0 70 2014 1 0 4 2 98 36 116 0 0 4 1 0 124 2015 3 2 136 0 111 44 160 13 0 14 2 0 152 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 27 43 22 0 25 0 329 1 2009 0 0 198 8 255 12 42 158 0 0 0 0 93 Installers Required 2010 0 0 16 48 1,226 4 41 750 0 9 6 0 152 2011 0 0 189 0 0 7 39 0 0 15 3 0 78 2012 1 0 17 68 868 56 37 0 0 18 4 0 221 2013 3 0 172 50 -360 92 34 0 0 19 5 0 373 2014 4 1 18 11 475 176 566 0 0 20 5 0 606 2015 13 8 599 2 492 196 705 58 0 63 11 0 671 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 1% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 1% 0%

Market Penetration 2010 0% 0% 2% 1% 4% 0% 1% 1% 0% 0% 0% 1% 0%

2011 0% 0% 2% 1% 3% 0% 1% 1% 0% 0% 0% 1% 0%

2012 0% 0% 2% 1% 5% 1% 1% 1% 0% 0% 0% 1% 1%

2013 0% 0% 2% 2% 4% 1% 1% 1% 0% 0% 0% 1% 1%

2014 0% 0% 2% 2% 5% 2% 1% 1% 0% 0% 0% 1% 2%

2015 0% 0% 3% 2% 5% 3% 2% 1% 0% 0% 0% 1% 3%

62

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 11 9 1 2 1 10 1 1 12 1 Cumulative Installations 2009 1 2 1 11 13 1 2 1 19 1 1 12 1 2010 3 2 1 11 21 1 3 1 36 13 1 20 1 2011 3 2 1 11 27 1 3 2 37 13 1 20 1 2012 4 3 1 11 35 1 4 4 53 13 1 25 1 2013 6 4 1 16 45 1 6 8 109 24 1 35 2 2014 8 6 1 24 56 1 7 13 211 24 2 48 2 2015 12 11 1 39 83 1 10 22 211 37 4 70 3 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 11 3 0 0 1 4 0 0 6 0 2009 0 0 0 0 3 0 0 0 10 0 0 0 0 Annual Installations 2010 2 0 0 0 8 0 1 0 16 11 0 8 0 2011 0 0 0 0 6 0 0 0 1 0 0 0 0 2012 1 1 0 0 8 0 1 3 16 0 0 5 0 2013 2 1 0 5 9 0 1 4 55 11 0 10 0 2014 3 2 0 8 11 0 2 5 103 0 1 13 0 2015 4 5 0 15 27 1 2 10 0 13 2 21 1 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 77 25 0 1 4 27 1 0 43 0 2009 2 0 0 0 24 0 0 0 67 2 0 0 0 Installers Required 2010 12 0 0 0 57 0 7 0 109 77 0 52 1 2011 0 1 0 0 37 0 0 3 6 0 0 0 1 2012 7 4 0 0 47 0 5 15 95 0 0 29 2 2013 11 7 0 27 49 0 8 19 296 93 2 56 2 2014 12 10 0 40 55 0 9 23 501 0 5 65 2 2015 17 21 0 66 119 3 10 43 0 56 9 94 3 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 1% 0% 1% 1% 0% 0% 0%

2014 1% 0% 0% 0% 0% 0% 1% 0% 2% 1% 0% 0% 0%

2015 1% 0% 0% 0% 0% 0% 1% 0% 1% 2% 0% 1% 0%

63

Table A-16. State-by-State Results for the Best Case, BAU System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,215 34 3 17 2 1 13 1 1 Cumulative Installations 2009 1 1 72 1 1,302 35 9 17 3 1 13 1 1 2010 1 1 122 1 1,302 36 11 17 4 1 13 1 1 2011 1 1 187 1 1,971 73 16 17 8 1 18 1 1 2012 1 1 268 1 2,940 75 24 17 16 1 24 1 1 2013 2 1 313 1 3,429 77 32 17 21 2 31 1 1 2014 11 1 360 1 5,293 78 49 17 36 11 40 1 1 2015 27 2 408 1 6,917 120 57 18 72 15 54 1 3 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 716 14 0 16 1 0 7 0 0 2009 0 0 31 0 88 1 6 0 1 0 0 0 0 Annual Installations 2010 0 0 50 0 0 1 2 0 1 0 0 0 0 2011 0 0 65 0 668 37 5 0 4 0 5 0 0 2012 0 0 81 0 970 2 8 0 8 0 6 0 0 2013 1 0 45 0 489 2 8 0 5 1 7 0 0 2014 9 0 47 0 1,864 2 17 0 15 9 9 0 0 2015 16 1 49 0 1,624 42 8 1 37 3 14 0 3 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 5,156 102 2 116 6 0 53 1 0 2009 0 0 214 0 609 5 41 0 6 0 0 3 0 Installers Required 2010 0 0 339 0 0 5 16 0 6 0 0 0 0 2011 0 0 407 0 4,180 235 28 0 25 0 30 0 0 2012 0 0 467 0 5,621 9 47 0 46 0 36 0 0 2013 6 2 239 0 2,609 9 44 1 29 7 36 0 0 2014 44 2 228 0 9,086 8 81 48 71 46 44 0 0 2015 71 3 214 0 7,171 184 37 6 163 15 63 0 12 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 2% 0% 0% 1% 0% 0% 1% 0% 0%

2009 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 1% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 2% 0% 0% 1% 0% 0% 1% 0% 0%

2011 0% 0% 1% 0% 3% 1% 0% 1% 0% 0% 1% 0% 0%

2012 0% 0% 2% 0% 4% 1% 0% 1% 0% 0% 1% 0% 0%

2013 0% 0% 2% 0% 5% 1% 1% 1% 0% 0% 1% 0% 0%

2014 0% 0% 2% 0% 7% 1% 1% 1% 0% 0% 1% 0% 0%

2015 0% 0% 2% 0% 9% 1% 1% 1% 0% 0% 2% 0% 0%

64

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 2 1 3 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 2 1 59 15 10 1 1 1 1 2010 1 1 1 2 1 195 15 12 1 1 1 1 2011 1 1 1 2 1 195 35 29 1 1 1 1 2012 1 1 1 2 1 208 35 43 1 1 5 1 2013 1 1 1 2 1 268 89 57 1 1 9 1 2014 1 1 1 2 1 344 89 84 2 1 19 1 2015 1 1 1 3 1 417 212 97 3 1 27 1 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 2 0 1 1 2 0 0 0 0 2009 0 0 0 0 0 56 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 137 0 2 0 0 0 0 2011 0 0 0 0 0 0 20 17 0 0 0 0 2012 0 0 0 0 0 12 0 14 0 0 5 0 2013 0 0 0 0 0 61 53 14 0 0 4 0 2014 0 0 0 0 0 76 0 27 1 0 10 0 2015 0 0 0 1 0 73 123 13 1 0 7 0 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 14 0 4 4 13 0 2 0 0 2009 0 0 0 0 0 389 89 13 0 0 0 0 Installers Required 2010 0 0 0 0 0 919 0 12 0 0 0 0 2011 0 0 0 0 0 0 125 107 0 0 0 0 2012 0 0 0 0 0 71 0 82 0 0 28 0 2013 0 0 0 0 0 323 284 75 0 0 20 0 2014 0 0 0 0 0 369 0 130 6 0 49 0 2015 0 0 0 4 0 321 545 58 4 0 33 0 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 4% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 11% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 11% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 11% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 13% 1% 1% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 16% 1% 1% 0% 0% 0% 0%

2015 0% 0% 0% 0% 0% 19% 2% 1% 0% 0% 0% 0%

65

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 12 128 6 1 6 1 6 10 Cumulative Installations 2009 1 1 107 1 140 14 134 20 1 6 1 9 23 2010 1 1 109 6 194 14 140 51 1 6 1 101 37 2011 1 1 140 8 253 15 146 51 1 6 1 149 58 2012 1 1 143 16 346 21 153 76 1 6 1 202 96 2013 1 1 175 22 472 26 159 76 1 7 1 264 166 2014 1 1 179 33 518 37 303 76 1 11 1 360 290 2015 2 1 203 33 614 55 357 154 1 19 2 468 343 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 4 95 3 0 4 0 4 1 2009 0 0 28 0 37 1 6 14 0 0 0 3 13 Annual Installations 2010 0 0 2 4 55 0 6 31 0 0 0 92 14 2011 0 0 30 3 59 1 6 0 0 0 0 48 21 2012 0 0 3 8 93 6 6 25 0 0 0 53 38 2013 0 0 32 6 126 5 6 0 0 1 0 62 70 2014 0 0 4 11 46 11 144 0 0 4 1 96 124 2015 1 0 24 0 96 19 55 77 0 8 0 108 53 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 26 43 22 0 25 0 30 5 2009 0 0 198 3 255 9 42 98 0 0 0 18 89 Installers Required 2010 0 0 16 28 366 0 41 205 0 0 0 616 93 2011 0 0 189 17 366 7 39 0 0 0 0 302 133 2012 0 0 17 44 537 36 37 144 0 0 0 307 221 2013 0 0 172 30 672 28 34 2 0 6 0 332 373 2014 0 0 18 54 226 52 700 2 0 21 4 469 606 2015 4 0 107 2 423 82 241 341 0 33 2 476 233 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 0% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 2% 0%

2011 0% 0% 2% 0% 3% 0% 1% 0% 0% 0% 0% 2% 0%

2012 0% 0% 2% 1% 3% 1% 1% 0% 0% 0% 0% 3% 1%

2013 0% 0% 2% 1% 4% 1% 1% 0% 0% 0% 0% 3% 1%

2014 0% 0% 2% 2% 5% 1% 2% 0% 0% 0% 0% 4% 2%

2015 0% 0% 2% 2% 5% 1% 2% 1% 0% 0% 0% 6% 2%

66

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 12 9 1 2 1 10 1 1 11 1 Cumulative Installations 2009 1 2 1 12 18 1 2 1 15 1 1 11 1 2010 1 2 1 12 34 1 2 1 20 5 1 11 1 2011 1 2 1 12 39 1 3 1 28 5 1 12 1 2012 2 2 1 12 50 1 4 1 41 7 1 19 1 2013 3 2 1 12 58 1 4 1 54 22 1 26 1 2014 5 10 1 17 108 1 6 2 75 22 1 42 1 2015 6 12 1 28 195 1 7 5 75 22 1 47 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 11 3 0 0 1 4 0 0 5 0 2009 0 0 0 0 9 0 0 0 5 0 0 0 0 Annual Installations 2010 0 0 0 0 16 0 0 0 5 3 0 0 0 2011 0 0 0 0 5 0 0 0 8 0 0 1 0 2012 1 0 0 0 11 0 1 0 13 2 0 7 0 2013 1 0 0 0 8 0 1 0 13 16 0 7 0 2014 2 8 0 5 51 0 2 1 21 0 0 16 0 2015 1 1 0 11 87 0 1 3 0 0 0 5 0 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 79 25 0 1 4 29 1 0 33 0 2009 0 0 0 0 63 0 0 0 36 2 0 0 0 Installers Required 2010 0 0 0 0 105 0 1 0 31 23 0 0 0 2011 3 0 0 0 30 0 2 0 49 0 0 7 0 2012 7 0 0 0 63 0 5 0 77 10 0 41 0 2013 5 0 0 0 44 0 4 0 71 84 0 38 0 2014 10 40 0 27 247 0 8 4 104 0 0 80 0 2015 4 6 0 47 382 0 3 13 0 0 0 23 0 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2014 0% 0% 0% 0% 0% 0% 1% 0% 1% 1% 0% 0% 0%

2015 0% 0% 0% 0% 0% 0% 1% 0% 1% 1% 0% 0% 0%

67

Table A-17. State-by-State Results for the Best Case, SAI System Pricing Alabama Arkansas California Colorado Connecticut Delaware Alaska Arizona Florida Georgia Hawaii Idaho Illinois 2007 1 1 14 1 499 20 3 1 1 1 6 1 1 2008 1 1 41 1 1,416 34 3 20 2 1 15 1 1 Cumulative Installations 2009 1 1 72 1 1,748 35 11 20 3 1 15 1 1 2010 1 1 122 1 2,135 36 17 20 4 4 23 1 1 2011 4 1 187 1 3,233 73 28 20 24 8 33 1 1 2012 10 2 268 1 4,997 75 43 20 51 12 47 1 1 2013 23 3 313 1 6,571 77 82 20 104 18 90 1 1 2014 54 3 382 1 10,449 119 291 44 224 32 155 2 13 2015 87 5 843 1 14,133 232 409 70 330 41 243 3 36 2007 0 0 5 0 166 6 1 1 1 0 3 0 0 2008 0 0 27 0 917 14 0 19 1 0 9 0 0 2009 0 0 31 0 332 1 8 0 1 1 0 1 0 Annual Installations 2010 1 0 50 0 387 1 6 0 1 3 7 0 0 2011 2 1 65 0 1,098 37 11 0 20 3 10 0 0 2012 6 0 81 0 1,764 2 15 0 27 5 14 0 0 2013 13 1 45 0 1,574 2 40 0 53 6 43 0 1 2014 31 1 69 0 3,878 42 209 25 120 14 66 0 12 2015 33 2 461 1 3,684 112 117 25 106 9 88 2 23 2007 0 0 35 0 1,232 48 7 4 4 0 23 0 0 2008 0 0 171 0 6,602 102 2 136 6 0 68 1 0 2009 0 0 214 0 2,313 5 56 0 6 5 0 5 0 Installers Required 2010 6 1 339 0 2,599 5 42 0 6 21 49 0 0 2011 14 4 407 0 6,868 235 66 0 128 21 65 0 0 2012 36 3 467 0 10,222 9 86 0 154 26 79 0 0 2013 70 4 239 0 8,399 12 211 0 282 31 228 0 4 2014 150 4 335 0 18,904 205 1,020 120 586 68 319 2 57 2015 146 8 2,036 2 16,264 496 518 111 469 38 388 8 101 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 3% 0% 0% 2% 0% 0% 1% 0% 0%

2009 0% 0% 1% 0% 3% 0% 0% 1% 0% 0% 1% 0% 0%

Market Penetration 2010 0% 0% 1% 0% 3% 0% 0% 1% 0% 0% 1% 0% 0%

2011 0% 0% 1% 0% 5% 1% 1% 1% 0% 0% 1% 0% 0%

2012 0% 0% 2% 0% 7% 1% 1% 1% 0% 0% 2% 0% 0%

2013 0% 0% 2% 0% 9% 1% 2% 1% 0% 0% 3% 0% 0%

2014 0% 0% 2% 0% 14% 1% 5% 2% 0% 0% 6% 0% 0%

2015 1% 0% 4% 0% 17% 2% 7% 3% 1% 0% 8% 0% 0%

68

Indiana Kansas Kentucky Louisiana Maryland Michigan Minnesota Mississippi Missouri Iowa Maine Mass.

2007 1 1 1 1 1 2 2 7 1 1 1 1 2008 1 1 1 3 2 3 3 9 1 1 1 1 Cumulative Installations 2009 1 1 1 3 2 100 15 10 1 1 1 1 2010 1 1 1 3 2 295 15 12 1 1 1 1 2011 1 1 1 3 2 295 35 47 1 1 5 1 2012 1 1 1 3 2 313 35 99 3 1 14 1 2013 1 1 1 3 3 411 89 174 8 3 22 1 2014 1 1 1 18 28 529 101 456 36 16 48 1 2015 1 1 1 35 34 661 212 659 52 22 92 3 2007 0 0 0 0 0 1 1 2 1 0 0 0 2008 0 0 0 2 2 1 1 2 0 0 0 0 2009 0 0 0 0 0 97 13 2 0 0 0 0 Annual Installations 2010 0 0 0 0 0 196 0 2 0 0 0 0 2011 0 0 0 0 0 0 20 35 0 0 5 0 2012 0 0 0 0 0 18 0 51 2 1 9 0 2013 0 0 0 0 0 97 53 75 5 2 7 0 2014 0 0 0 15 26 119 12 283 28 13 26 0 2015 0 1 0 16 6 132 111 202 16 6 45 2 2007 0 0 0 0 0 7 7 16 4 0 0 0 2008 0 0 0 17 14 7 4 13 0 2 0 0 2009 0 0 0 0 0 672 89 13 0 0 0 0 Installers Required 2010 0 0 0 0 0 1,314 0 12 0 0 2 0 2011 0 0 0 0 0 0 125 220 2 0 29 0 2012 0 0 0 0 0 104 0 298 9 4 52 0 2013 0 0 0 2 2 520 284 398 27 9 39 0 2014 0 1 0 74 125 578 61 1,379 138 63 126 0 2015 0 3 0 73 26 581 489 893 71 25 197 11 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 6% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 17% 0% 0% 0% 0% 0% 0%

2011 0% 0% 0% 0% 0% 16% 0% 1% 0% 0% 0% 0%

2012 0% 0% 0% 0% 0% 16% 0% 1% 0% 0% 0% 0%

2013 0% 0% 0% 0% 0% 20% 1% 2% 0% 0% 0% 0%

2014 0% 0% 0% 0% 0% 25% 1% 5% 0% 0% 1% 0%

2015 0% 0% 0% 0% 0% 30% 2% 7% 0% 0% 1% 0%

69

New Jersey New Mexico North Carolina North Dakota Pennsylvania Montana Nebraska Nevada New York Oklahoma Oregon NH Ohio 2007 1 1 15 1 69 9 32 3 1 2 1 2 9 2008 1 1 79 1 103 14 128 6 1 7 1 6 10 Cumulative Installations 2009 1 1 107 2 140 16 134 27 1 7 1 9 23 2010 1 1 109 9 316 16 140 134 1 7 1 157 41 2011 1 1 140 13 316 23 146 134 1 8 1 229 61 2012 1 1 143 22 321 32 265 134 1 11 2 325 115 2013 2 1 175 22 449 61 482 134 1 15 3 425 210 2014 5 4 373 33 502 159 913 134 1 29 5 672 479 2015 8 5 668 80 735 259 1,098 154 1 66 7 1,106 756 2007 0 0 7 1 29 3 10 1 0 1 0 1 3 2008 0 0 64 0 34 5 95 3 0 5 0 4 1 2009 0 0 28 1 37 2 6 21 0 0 0 3 12 Annual Installations 2010 0 0 2 7 176 0 6 107 0 0 0 148 18 2011 0 0 30 4 0 7 6 0 0 1 0 73 20 2012 0 0 3 9 6 9 118 0 0 3 1 95 54 2013 1 0 32 0 128 29 218 0 0 5 1 100 95 2014 3 3 198 11 53 98 431 0 0 13 3 247 268 2015 3 1 295 47 233 100 185 20 0 37 1 435 277 2007 0 0 56 4 213 24 71 7 0 4 0 4 19 2008 3 0 12 0 243 35 43 23 0 33 0 30 8 2009 0 0 198 8 255 14 42 145 0 0 0 18 86 Installers Required 2010 0 0 16 46 1,182 0 41 718 0 3 1 994 120 2011 0 0 189 26 0 43 39 0 0 8 2 454 125 2012 0 0 17 50 89 55 687 0 0 15 4 553 316 2013 6 1 172 0 683 154 1,161 0 0 25 4 535 508 2014 17 13 966 53 257 479 2,100 0 0 65 14 1,203 1,308 2015 13 6 1,304 209 1,028 440 815 88 1 163 6 1,919 1,223 2007 0% 0% 0% 0% 1% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 1% 0% 1% 0% 1% 0% 0% 0% 0% 0% 0%

2009 0% 0% 2% 0% 2% 0% 1% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 2% 1% 3% 0% 1% 1% 0% 0% 0% 2% 0%

2011 0% 0% 2% 1% 3% 1% 1% 1% 0% 0% 0% 3% 0%

2012 0% 0% 2% 1% 3% 1% 1% 1% 0% 0% 0% 5% 1%

2013 0% 0% 2% 1% 4% 1% 3% 1% 0% 0% 0% 6% 1%

2014 0% 0% 4% 2% 5% 4% 5% 1% 0% 0% 0% 8% 3%

2015 0% 0% 7% 4% 6% 6% 5% 1% 0% 0% 0% 13% 5%

70

Rhode Island South Dakota Tennessee Washington West Virginia Wisconsin Vermont Wyoming South Texas Utah Virginia DC Carolina 2007 1 2 1 1 6 1 2 1 6 1 1 6 1 2008 1 2 1 13 11 1 2 1 11 1 1 12 1 Cumulative Installations 2009 1 2 1 13 28 1 2 1 21 1 1 12 1 2010 2 2 1 13 66 1 3 1 35 9 1 18 1 2011 3 3 1 13 85 1 4 1 51 9 1 26 1 2012 5 9 1 14 127 1 5 3 77 9 1 38 1 2013 7 16 1 23 168 1 7 6 127 60 1 54 1 2014 11 33 2 50 308 10 11 38 259 60 2 91 1 2015 19 43 2 84 877 17 17 62 259 60 8 114 1 2007 1 1 0 0 1 1 1 1 3 1 0 2 0 2008 0 0 0 13 5 0 0 1 5 0 0 6 0 2009 0 0 0 0 17 0 0 0 9 0 0 0 0 Annual Installations 2010 1 0 0 0 38 0 1 0 14 8 0 6 0 2011 1 1 0 0 19 0 1 0 16 0 0 8 0 2012 2 6 0 1 42 0 2 2 26 0 0 12 0 2013 2 7 0 9 42 0 2 3 50 50 0 16 0 2014 4 18 1 27 140 10 4 32 132 0 2 37 0 2015 8 10 1 34 569 7 6 24 0 0 6 23 1 2007 4 7 0 0 8 4 7 4 22 4 0 15 0 2008 0 0 0 93 38 0 2 4 38 1 0 43 0 2009 0 0 0 0 117 0 0 0 65 2 0 0 0 Installers Required 2010 7 2 0 0 254 0 5 0 96 54 0 39 0 2011 7 6 0 0 119 0 6 0 99 0 0 50 0 2012 10 32 0 4 242 0 9 12 152 0 0 72 0 2013 13 37 0 46 223 0 9 16 265 284 1 83 0 2014 22 86 5 131 682 47 20 155 646 0 8 182 1 2015 34 44 3 152 2,512 32 26 105 0 0 26 103 3 2007 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2008 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2009 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Market Penetration 2010 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2011 0% 0% 0% 0% 0% 0% 0% 0% 0% 1% 0% 0% 0%

2012 0% 0% 0% 0% 0% 0% 1% 0% 1% 1% 0% 0% 0%

2013 1% 0% 0% 0% 0% 0% 1% 0% 1% 4% 0% 0% 0%

2014 1% 0% 0% 0% 0% 0% 1% 0% 2% 3% 0% 1% 0%

2015 1% 0% 0% 0% 1% 0% 2% 0% 2% 3% 0% 1% 0%

71

A-6. Input Data Table A-18. Utilities Analyzed State Utility Name AL Alabama Power Co.

AK Chugach AZ Arizona Public Service AZ Salt River Project AZ Tucson Electric Power AK Entergy Arkansas CA Southern California Edison CA Sacramento Municipal Utility District CA Pacific Gas and Electric Company CA San Diego Gas & Electric Company CA Los Angeles Department of Water and Power CO Public Service Company of Colorado CO Colorado Springs CT Connecticut Light and Power DE Conective (Delmarva Power)

FL Florida Power & Light Co.

FL Progress Energy Florida Inc FL Tampa Electric Company GA Georgia Power HI Hawaiian Electric Company (Oahu)

HI Maui Electric Company ID Idaho Power IL Commonwealth Edison Co.

IL Illinois Power Company IN PSI Energy Inc.

IA IES Utilities (Mid America)

IA Interstate Power and Light KS Kansas Gas & Electric Co KS Westar Energy Inc KY Kentucky Utilities Co KY Louisville Gas & Electric Co KY Kenergy Corporation LA Entergy (Louisiana Power & Light)

ME Central Maine Power ME Bangor Hydro Electric Company MD BGE (Baltimore Gas and Electric)

MD Potomac Electric Power Company MA NSTAR (Boston Edison) 72

MA Massachusetts Electric Company MI Detroit Edison MI Consumers Energy Company MN Xcel Energy (Northern States Power)

MS Entergy Mississippi (Mississippi Power and Light)

MS Mississippi Power Company MO AmerenUE - Missouri (Union Electric)

MT Northwestern Energy (Montana Power Company)

NE Omaha Public Power District NV Nevada Power NV Sierra Pacific Power Company NH Public Service of New Hampshire NH Unitil Energy Systems NJ PSE&G (Public Service Electric and Gas Co.)

NJ Jersey Central Power and Light Co.

NJ Atlantic City Electrical Company NM PNM (Public Service Company of New Mexico)

NM Southwest Public Service Company NY Niagara Mohawk NY New York State Electric and Gas Corp NY Consolidated Edison NY Long Island Power Authority NC Duke Power NC Progress Energy Carolinas Inc ND Northern States Power Co OH Ohio Power Company OH Ohio Edison OH Cincinnati Gas & Electric Company OK AEP (Public Service Company of Oklahoma)

OK Oklahoma Gas and Electric Company OR PacifiCorp (Pacific Power)

OR Portland General Electric Company PA PPL Electric Utilities PA PECO Energy Co PA West Penn Power Co.

RI Narragansett Electric SC South Carolina Electric and Gas SC Duke Energy Corporation SD Xcel Energy (Northern States Power)

TN Nashville Electric Service TN Knoxville Electric Board 73

TN City of Memphis TX TXU Electric TX Reliant Energy Services TX Entergy Gulf States Inc TX Constellation New Energy Inc TX City of San Antonio UT PacifiCorp (Utah Power & Light)

VT Green Mountain Power VT Central Vermont Public Service Corporation VA Dominion (Virginia Electric and Power)

VA Appalachian Power Co WA Puget Sound Energy WA Snohomish County PUD No 1 WA City of Seattle DC PEPCO WV American Electric (Appalachian Power)

WI We Energies (Wisconsin Electric)

WI Wisconsin Public Service Corporation WY PacifiCorp (Pacific Power)

Table A-19. IRECs Interconnection Assessments Interconnection Policy State Utility Assessment Alabama Alabama Power Co. Barrier Alaska Chugach Good Arizona Arizona Public Service Good Arizona Salt River Project Good Arizona Tucson Electric Power Good Arkansas Entergy Arkansas Poor California Southern California Edison Fair California Sacramento Municipal Utility District Fair California Pacific Gas and Electric Company Fair California San Diego Gas & Electric Company Fair California Los Angeles Department of Water and Power Fair Colorado Public Service Company of Colorado Fair Colorado Colorado Springs Fair Connecticut Connecticut Light and Power Poor Delaware Conective (Delmarva Power) Barrier Florida Florida Power & Light Co. Poor 74

Florida Progress Energy Florida Inc Poor Florida Tampa Electric Company Poor Georgia Georgia Power Fair Hawaii Hawaiian Electric Company (Oahu) Barrier Hawaii Maui Electric Company Barrier Idaho Idaho Power Barrier Illinois Commonwealth Edison Co. Barrier Illinois Illinois Power Company Barrier Indiana PSI Energy Inc. Poor Iowa IES Utilities (Mid American) Poor Iowa Interstate Power and Light Poor Kansas Kansas Gas & Electric Co Barrier Kansas Westar Energy Inc Barrier Kentucky Kentucky Utilities Co Barrier Kentucky Louisville Gas & Electric Co Barrier Kentucky Kenergy Corporation Barrier Louisiana Entergy (Louisiana Power & Light) Barrier Maine Central Maine Power Barrier Maine Bangor Hydro Electric Company Barrier Maryland BGE (Baltimore Gas and Electric) Poor Maryland Potomac Electric Power Company Poor Massachusetts NSTAR (Boston Edison) Fair Massachusetts Massachusetts Electric Company Fair Michigan Detroit Edison Poor Michigan Consumers Energy Company Poor Minnesota Xcel Energy (Northern States Power) Fair Mississippi Entergy Mississippi (Mississippi Power and Light) Barrier Mississippi Mississippi Power Company Barrier Missouri AmerenUE - Missouri (Union Electric) Barrier Montana Northwestern Energy (Montana Power Company) Poor Nebraska Omaha Public Power District Barrier Nevada Nevada Power Good Nevada Sierra Pacific Power Company Good New Hampshire Public Service of New Hampshire Poor New Hampshire Unitil Energy Systems Poor New Jersey PSE&G (Public Service Electric and Gas Co.) Good New Jersey Jersey Central Power and Light Co. Good New Jersey Atlantic City Electrical Company Good New Mexico PNM (Public Service Company of New Mexico) Fair New Mexico Southwest Public Service Company Fair New York Niagara Mohawk Fair 75

New York New York State Electric and Gas Corp Fair New York Consolidated Edison Fair New York Long Island Power Authority Fair North Carolina Duke Power Barrier North Carolina Progress Energy Carolinas Inc Barrier North Dakota Northern States Power Co Poor Ohio Ohio Power Company Fair Ohio Ohio Edison Fair Ohio Cincinnati Gas & Electric Company Fair Oklahoma AEP (Public Service Company of Oklahoma) Poor Oklahoma Oklahoma Gas and Electric Company Poor Oregon PacifiCorp (Pacific Power) Fair Oregon Portland General Electric Company Fair Pennsylvania PPL Electric Utilities Poor Pennsylvania PECO Energy Co Poor Pennsylvania West Penn Power Co. Poor Rhode Island Narragansett Electric Poor South Carolina South Carolina Electric and Gas Poor South Carolina Duke Energy Corporation Poor South Dakota Xcel Energy (Northern States Power) Barrier Tennessee Nashville Electric Service Barrier Tennessee Knoxville Electric Board Barrier Tennessee City of Memphis Barrier Texas TXU Electric Fair Texas Reliant Energy Services Fair Texas Entergy Gulf States Inc Fair Texas Constellation New Energy Inc Fair Texas City of San Antonio Fair Utah PacifiCorp (Utah Power & Light) Barrier Vermont Green Mountain Power Fair Vermont Central Vermont Public Service Corporation Fair Virginia Dominion (Virginia Electric and Power) Poor Virginia Appalachian Power Co Poor Washington Puget Sound Energy Barrier Washington Snohomish County PUD No 1 Barrier Washington City of Seattle Barrier Washington, DC PEPCO Barrier West Virginia American Electric (Appalachian Power) Poor Wisconsin We Energies (Wisconsin Electric) Poor Wisconsin Wisconsin Public Service Corporation Poor Wyoming PacifiCorp (Pacific Power) Barrier 76

Rate Structures. NCI researched each utilitys Web site to locate residential and commercial electric rates. We then confirmed with the Federal Energy Regulatory Commission (FERC)

Form 1 Database about which standard and TOU rates are most representative of that utility.

There are up to three rate structures for each utilitys residential and commercial electric services: (1) standard; (2) TOU, weekday (if TOU is available); (3) TOU, weekend (if TOU is available). For each representative utility and assumed system size, we looked at TOU and standard rates to see which rate would yield a lower annual electric utility bill (with PV). We then used that rate structure for the analysis. Refer to the model for actual rate structures.

Demand Charges. NCI cataloged utility peak demand charges from utility Web sites and tariff sheets. We assumed that PV offsets only peak demand charges.

State and Local Incentives. NCIs PV Services Program provided a comprehensive list of local incentives for PV, broken down by state or utility. We divided incentives into three types: capacity-based (in $/kW), performance-based, and capacity-based (as a percentage of system cost). We found out when program funding was scheduled to run out and integrated that into the model. In cases where data could not be found, we implemented a switch to allow incentives to expire in 2009, 2012, or 2016. All the analysis performed in the study assumed the year to be 2009, to be conservative. In reality, if tax credits are extended, most state-level subsidies will be reduced or eliminated. Given that all cases analyzed, except the worst case, assume that federal tax credits are extended, we believe this is a good assumption.

For the California Solar Initiative, we implemented a feedback mechanism in the model that mimics the actual feedback mechanism being used in the initiative. In other words, when cumulative installations within a utility service area reach a certain level, the rebate amount is reduced. However, this model reduces the incentives on an annual basis only, rather than continuously.

Five-Year MACRS Depreciation. We amortized Modified Accelerated Cost-Recovery System (MACRS) benefits over the system life to account for the benefits of accelerated depreciation within the context of a modified simple payback in the commercial sector.

Net Metering Rules. NCI catalogued net metering rules for each state (or utility, where applicable) and accounted for the following: (1) Is net metering allowed? (2) If so, at what rate is electricity sold back to the grid? (3) Can customers get credit for electricity sold back in excess of their annual bill? (4) If so, at what rate is excess credit bought? Options for sell-back include retail, wholesale, and annual average rate. We collected data on these rates where necessary from EIA and internal NCI sources.

77

Table A-20. Net Metering Availability and Sell-Back Rules for Representative Utilities Analyzed Net Metering Net Metering Sell Back State Utility Allowed? Rates Alabama Alabama Power Co.

N 0 Alaska Chugach N 0 Arizona Arizona Public Service Y Retail Arizona Salt River Project Y Retail Arizona Tucson Electric Power Y Retail Arkansas Entergy Arkansas Y Retail California Southern California Edison Y Retail California Sacramento Municipal Utility District Y Retail California Pacific Gas and Electric Company Y Retail California San Diego Gas & Electric Company Y Retail California Los Angeles Department of Water and Power Y Retail Colorado Public Service Company of Colorado Y Retail Colorado Colorado Springs Y Retail Connecticut Connecticut Light and Power Y Retail Delaware Conective (Delmarva Power)

Y Retail Florida Florida Power & Light Co.

N 0 Florida Progress Energy Florida Inc N 0 Florida Tampa Electric Company N 0 Georgia Georgia Power Y Retail Hawaii Hawaiian Electric Company (Oahu)

Y Retail Hawaii Maui Electric Company Y Retail Idaho Idaho Power Y Retail Illinois Commonwealth Edison Co.

Y Retail Illinois Illinois Power Company N 0 Indiana PSI Energy Inc.

Y Retail Iowa IES Utilities (mid america)

Y Retail Iowa Interstate Power and Light Y Retail Kansas Kansas Gas & Electric Co N 0 Kansas Westar Energy Inc N 0 Kentucky Kentucky Utilities Co Y Retail Kentucky Louisville Gas & Electric Co Y Retail Kentucky Kenergy Corporation Y Retail Louisiana Entergy (Louisiana Power & Light)

Y Retail Maine Central Maine Power Y Retail Maine Bangor Hydro Electric Company Y Retail Maryland BGE (Baltimore Gas and Electric)

Y Retail Maryland Potomac Electric Power Company Y Retail Massachusetts NSTAR (Boston Edison)

Y Retail 78

Massachusetts Massachusetts Electric Company Y Retail Michigan Detroit Edison Y Retail Michigan Consumers Energy Company Y Retail Minnesota Xcel Energy (Northern States Power)

Y Retail Mississippi Entergy Mississippi (Mississippi Power and Light) N 0 Mississippi Mississippi Power Company N 0 Missouri AmerenUE - Missouri (Union Electric)

Y Wholesale Montana Northwestern Energy (Montana Power Company) Y Retail Nebraska Omaha Public Power District N 0 Nevada Nevada Power Y Retail Nevada Sierra Pacific Power Company Y Retail New Hampshire Public Service of New Hampshire Y Retail New Hampshire Unitil Energy Systems Y Retail New Jersey PSE&G (Public Service Electric and Gas Co.)

Y Retail New Jersey Jersey Central Power and Light Co.

Y Retail New Jersey Atlantic City Electrical Company Y Retail New Mexico PNM (Public Service Company of New Mexico)

Y Retail New Mexico Southwest Public Service Company Y Retail New York Niagara Mohawk Y Retail New York New York State Electric and Gas Corp Y Retail New York Consolidated Edison Y Retail New York Long Island Power Authority Y Retail North Carolina Duke Power Y Retail North Carolina Progress Energy Carolinas Inc Y Retail North Dakota Northern States Power Co Y Wholesale Ohio Ohio Power Company Y Wholesale Ohio Ohio Edison Y Wholesale Ohio Cincinatti Gas & Electric Company Y Wholesale Oklahoma AEP (Public Service Company of Oklahoma)

Y Retail Oklahoma Oklahoma Gas and Electric Company Y Retail Oregon PacifiCorp (Pacific Power)

Y Retail Oregon Portland General Electric Company Y Retail Pennsylvania PPL Electric Utilities Y Retail Pennsylvania PECO Energy Co Y Retail Pennsylvania West Penn Power Co.

Y Retail Rhode Island Narragansett Electric Y Retail South Carolina South Carolina Electric and Gas N 0 South Carolina Duke Energy Corporation N 0 South Dakota Xcel Energy (Northern States Power)

N 0 Tennessee Nashville Electric Service N 0 Tennessee Knoxville Electric Board N 0 79

Tennessee City of Memphis N 0 Texas TXU Electric Y Retail Texas Reliant Energy Services Y Retail Texas Entergy Gulf States Inc Y Retail Texas Constellation New Energy Inc Y Retail Texas City of San Antonio Y Retail Utah PacifiCorp (Utah Power & Light)

Y Retail Vermont Green Mountain Power Y Retail Vermont Central Vermont Public Service Corporation Y Retail Virginia Dominion (Virginia Electric and Power)

Y Retail Virginia Appalachian Power Co Y Retail Washington Puget Sound Energy Y Retail Washington Snohomish County PUD No 1 Y Retail Washington City of Seattle Y Retail Washington, PEPCO DC Y Retail West Virginia American Electric (Appalachian Power)

Y Retail Wisconsin We Energies (Wisconsin Electric)

Y Retail Wisconsin Wisconsin Public Service Corporation Y Retail Wyoming PacifiCorp (Pacific Power)

Y Retail Table A-21. Net Metering Caps for Representative Utilities Analyzed Do Net Cap Amount (% of Metering Caps utilities peak demand Utility exist? unless otherwise noted)

Alabama Power Co.

N Chugach N

Arizona Public Service N

Salt River Project N

Tucson Electric Power N

Entergy Arkansas N

Southern California Edison Y 2.50%

Sacramento Municipal Utility District Y 2.50%

Pacific Gas and Electric Company Y 2.50%

San Diego Gas & Electric Company Y 2.50%

Los Angeles Department of Water and Power Y 2.50%

Public Service Company of Colorado N

Colorado Springs N

Connecticut Light and Power N

Conective (Delmarva Power)

N 80

Florida Power & Light Co.

N Progress Energy Florida Inc N

Tampa Electric Company N

Georgia Power Y 0.2%

Hawaiian Electric Company (Oahu)

Y 0.5%

Maui Electric Company Y 0.5%

Idaho Power 0.1% Of 2000 peak Y demand Commonwealth Edison Co.

N Illinois Power Company N

PSI Energy Inc.

Y 0.10%

IES Utilities (mid america)

N Interstate Power and Light N

Kansas Gas & Electric Co N

Westar Energy Inc N

Kentucky Utilities Co Y 0.10%

Louisville Gas & Electric Co Y 0.10%

Kenergy Corporation Y 0.10%

Entergy (Louisiana Power & Light)

N Central Maine Power N

Bangor Hydro Electric Company N

BGE (Baltimore Gas and Electric)

Y Fixed # of MW's Potomac Electric Power Company Y Fixed # of MW's NSTAR (Boston Edison)

N Massachusetts Electric Company N

Detroit Edison Y 0.1%

Consumers Energy Company Y 0.1%

Xcel Energy (Northern States Power)

N Entergy Mississippi (Mississippi Power and Light)

N Mississippi Power Company N

AmerenUE - Missouri (Union Electric)

Y 5.0%

Northwestern Energy (Montana Power Company)

N Omaha Public Power District N

Nevada Power Y 1.0%

Sierra Pacific Power Company Y 1.0%

Public Service of New Hampshire Y 0.1%

Unitil Energy Systems Y 0.1%

PSE&G (Public Service Electric and Gas Co.)

N Jersey Central Power and Light Co.

N Atlantic City Electrical Company N

81

PNM (Public Service Company of New Mexico)

N Southwest Public Service Company N

Niagara Mohawk Y 0.1%

New York State Electric and Gas Corp Y 0.1%

Consolidated Edison Y 0.1%

Long Island Power Authority Y 0.1%

Duke Power Y 0.2%

Progress Energy Carolinas Inc Y 0.2%

Northern States Power Co N

Ohio Power Company Y 1.0%

Ohio Edison Y 1.0%

Cincinatti Gas & Electric Company Y 1.0%

AEP (Public Service Company of Oklahoma)

N Oklahoma Gas and Electric Company N

PacifiCorp (Pacific Power)

Y 0.5%

Portland General Electric Company Y 0.5%

PPL Electric Utilities N

PECO Energy Co N

West Penn Power Co.

N Narragansett Electric Y Fixed # of MW's South Carolina Electric and Gas N

Duke Energy Corporation N

Xcel Energy (Northern States Power)

N Nashville Electric Service N

Knoxville Electric Board N

City of Memphis N

TXU Electric N

Reliant Energy Services N

Entergy Gulf States Inc N

Constellation New Energy Inc N

City of San Antonio N

PacifiCorp (Utah Power & Light) 0.1% of 2001 peak Y demand Green Mountain Power Y 1.0%

Central Vermont Public Service Corporation Y 1.0%

Dominion (Virginia Electric and Power)

Y 0.1%

Appalachian Power Co Y 0.1%

Puget Sound Energy N 0.25% of 1996 peak Snohomish County PUD No 1 N 0.25% of 1996 peak City of Seattle N 0.25% of 1996 peak PEPCO N

American Electric (Appalachian Power)

Y 0.1%

82

We Energies (Wisconsin Electric)

N Wisconsin Public Service Corporation N

PacifiCorp (Pacific Power)

N REC Assumptions. NCI cataloged current renewable energy credit (REC) prices in existing REC markets. For states with an RPS that have not established a REC market, we used a REC value of 15% below the alternative compliance payment. For those states, we assumed a REC market is partially developed in 2009 and fully developed in 2010. For states with separate solar alternative compliance payments, we assumed that if, in the previous year of analysis, the RPS solar set-aside target is met for the current year, the market value of a REC drops to 15% below the normal alternative compliance payment level for the current year (which is necessary only in the District of Columbia, Delaware, Maryland, New Jersey, and Pennsylvania). More refined methods cannot be used because the model has a temporal resolution of only one year.

Building Load Profiles. For residential buildings, NREL provided 8,760 building load profiles on a regional basis using weather for 2003 as an input. NCI and NREL identified 10 representative cities. We then assigned each utility a representative load profile based upon the utilitys climate zone, as specified by Building America. The 15 cities were Phoenix, Sacramento, Los Angeles, Boulder, Tampa, Atlanta, Chicago, New York City, Houston, Seattle, Honolulu, Lexington, Dallas, Medford, and Helena.

For commercial buildings, NREL provided 8,760 building load profiles for all 98 utilities being analyzed, using weather data for 2003. Typical building load profiles were for office buildings, warehouses, or hospitals.

PV Output Profiles. For residential buildings, NREL provided 8,760 PV output profiles on a regional basis using 2003 weather as an input into PV Watts with a 30-degree tilt. NCI and NREL identified 15 representative cities. We then assigned each utility a representative PV system output profile.

For commercial buildings, NREL provided 8,760 PV output profiles for all 98 utilities being analyzed, using 2003 weather data as an input to PV Watts with a 0-degree tilt.

O&M and Inverter Costs. DOE provided NCI with aggregated, combined O&M and inverter replacement costs from applicants and awardees of the Solar America Initiative.

83

Table A-22. O&M and Inverter Replacement Costs O&M Costs and Inverter Replacement Costs

($kW/yr)

Market Segment 2007 2010 2015 Residential $57.98 $39.45 $35.00 Commercial $51.28 $38.07 $27.33 System Size. NCI started with default system sizing of 5 kW in the residential sector and 250 kW in the commercial sector. We then reduced system size based on net-metering rules, interconnection standards and local incentive amounts to maximize the value of the incentive (i.e., if a utility offers rebates only for the first 100 kW, a 100-kW system size was used).

Calculation of Annual Electric Bill Savings. Using 8,760 building load profiles provided by NREL and actual utility rate structures (accounting for seasonal variation, TOU rates, and so on), first we calculated a customers annual electric bill. Next, we calculated annual electric bill savings by combining 8,760 PV output profiles, actual utility rate structures, and the local net-metering laws (i.e., whether net metering is allowed, the rate at which power is sold back to the grid, and whether a customer can sell back power in excess of their annual electric bill).

Information on Calculated TOU Rates. Not all state utility rates used in the analysis conform nicely to average TOU structures. Where applicable, extreme outliers were ignored in the calculation. For example, PSI Energy, Inc., was ignored in the analysis of the ReliabilityFirst Corporation (RFC) region because its existing TOU rate is available only to those customers with its low-load factor service, a very specific rate. Within the Northeast Power Coordinating Council (NPCC) region, Central Maine Power is the only utility with a shoulder period and rate; thus, a weighted average of the peak and shoulder rates and times was taken to create a new, representative peak rate and length of time.

As expected, TOU structures tended to vary within each region. For example, Florida utilities all establish a morning peak and an evening peak period with nonpeak rates throughout the middle of the day. The average changes in peak-hour rates and non-peak-hour rates between the the winter and summer seasons vary the most between the Northeast (NE) and Pacific states; the NE shows almost no change between seasons, and the Southwest and West show as much as a 147% increase in commercial peak rates between the two seasons. The utility structures within the RFC region vary the most, potentially as a result of the recent merger of the East Central Area Reliability Coordination Agreement (ECAR), the Mid-Atlantic Area Council (MAAC), and the Mid-America Interconnected Network (MAIN) regional reliability councils.

Impact of Carbon Pricing. To examine the impacts of potential national carbon legislation, we modeled the price of carbon as a surcharge on retail electric rates. To assess the impact on electric rates, we used carbon intensity data from EIAs Annual Energy Outlook, by EMMR, and developed $/kWh impacts for $/ton pricing. See below for the values calculated.

84

Table A-23. Impact of Carbon Cap Impact of Carbon Utility Cap IDs Utility Names [$/kWh per $/ton]

Alabama Power Co.

1 0.00058 Chugach 2 0.00016 Arizona Public Service 3 0.00064 Salt River Project 4 0.00064 Tucson Electric Power 5 0.00064 Entergy Arkansas 6 0.00058 Southern California Edison 7 0.00031 Sacramento Municipal Utility District 8 0.00031 Pacific Gas and Electric Company 9 0.00031 San Diego Gas & Electric Company 10 0.00031 Los Angeles Department of Water and Power 11 0.00031 Public Service Company of Colorado 12 0.00064 Colorado Springs 13 0.00064 Connecticut Light and Power 14 0.00039 Conective (Delmarva Power) 15 0.00051 Florida Power & Light Co.

16 0.00057 Progress Energy Florida Inc 17 0.00057 Tampa Electric Company 18 0.00057 Georgia Power 19 0.00058 Hawaiian Electric Company (Oahu) 20 0.00016 Maui Electric Company 21 0.00016 Idaho Power 22 0.00037 Commonwealth Edison Co.

23 0.00060 Illinois Power Company 24 0.00060 PSI Energy Inc.

25 0.00083 IES Utilities (mid america) 26 0.00060 Interstate Power and Light 27 0.00060 28 Kansas Gas & Electric Co 0.00084 Westar Energy Inc 29 0.00084 30 Kentucky Utilities Co 0.00083 31 Louisville Gas & Electric Co 0.00083 Kenergy Corporation 32 0.00083 Entergy (Louisiana Power & Light) 33 0.00058 Central Maine Power 34 0.00039 Bangor Hydro Electric Company 35 0.00039 BGE (Baltimore Gas and Electric) 36 0.00051 85

Potomac Electric Power Company 37 0.00051 NSTAR (Boston Edison) 38 0.00039 Massachusetts Electric Company 39 0.00039 Detroit Edison 40 0.00083 Consumers Energy Company 41 0.00083 Xcel Energy (Northern States Power) 42 0.00077 Entergy Mississippi (Mississippi Power and 43 Light) 0.00058 Mississippi Power Company 44 0.00058 AmerenUE - Missouri (Union Electric) 45 0.00060 Northwestern Energy (Montana Power 46 Company) 0.00037 Omaha Public Power District 47 0.00077 Nevada Power 48 0.00037 Sierra Pacific Power Company 49 0.00037 Public Service of New Hampshire 50 0.00039 Unitil Energy Systems 51 0.00039 PSE&G (Public Service Electric and Gas Co.)

52 0.00051 Jersey Central Power and Light Co.

53 0.00051 Atlantic City Electrical Company 54 0.00051 PNM (Public Service Company of New Mexico) 55 0.00064 Southwest Public Service Company 56 0.00064 Niagara Mohawk 57 0.00033 New York State Electric and Gas Corp 58 0.00033 Consolidated Edison 59 0.00033 Long Island Power Authority 60 0.00033 Duke Power 61 0.00058 Progress Energy Carolinas Inc 62 0.00058 63 Northern States Power Co 0.00077 Ohio Power Company 64 0.00083 Ohio Edison 65 0.00083 Cincinnati Gas & Electric Company 66 0.00083 AEP (Public Service Company of Oklahoma) 67 0.00084 Oklahoma Gas and Electric Company 68 0.00084 PacifiCorp (Pacific Power) 69 0.00037 Portland General Electric Company 70 0.00037 PPL Electric Utilities 71 0.00051 PECO Energy Co 72 0.00051 West Penn Power Co.

73 0.00051 Narragansett Electric 74 0.00039 South Carolina Electric and Gas 75 0.00058 Duke Energy Corporation 76 0.00058 Xcel Energy (Northern States Power) 77 0.00077 86

Nashville Electric Service 78 0.00058 Knoxville Electric Board 79 0.00058 City of Memphis 80 0.00058 TXU Electric 81 0.00057 Reliant Energy Services 82 0.00057 Entergy Gulf States Inc 83 0.00057 Constellation New Energy Inc 84 0.00057 City of San Antonio 85 0.00057 PacifiCorp (Utah Power & Light) 86 0.00037 Green Mountain Power 87 0.00039 Central Vermont Public Service Corporation 88 0.00039 Dominion (Virginia Electric and Power) 89 0.00058 Appalachian Power Co 90 0.00058 Puget Sound Energy 91 0.00037 92 Snohomish County PUD No 1 0.00037 City of Seattle 93 0.00037 PEPCO 94 0.00051 American Electric (Appalachian Power) 95 0.00083 We Energies (Wisconsin Electric) 96 0.00060 Wisconsin Public Service Corporation 97 0.00060 PacifiCorp (Pacific Power) 98 0.00037 Electricity Escalation Rates. We used two rate escalation scenarios, all in real terms. EIAs Annual Energy Outlook provided the first, but it shows rates staying constant or dropping in all markets. As a result, NCI conducted an analysis looking at projections of supply, capacity, and policy changes that will impact the annual wholesale price. NCI then assumed that changes in wholesale prices will be 100% translated to the retail market (the model allows the user to alter this function). This is a strong assumption, but looking at the dynamics between wholesale and retail markets is outside the scope of the project. The resulting annual percent changes in prices are shown in the tables that follow.

87

Table A-24. Annual Year Over Year Changes in Electricity Prices as Projected by EIA for the Residential Market State 2008 2009 2010 2011 2012 2013 2014 2015 Alabama

-0.68% 0.05% -0.02% -1.26% -2.02% -1.17% -0.61% -0.39%

Alaska

-0.95% -1.29% -1.53% -2.34% -1.93% -1.04% -0.46% 0.35%

Arizona 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

Arkansas

-1.31% -2.37% -2.19% -2.68% 1.18% -0.10% -0.20% -0.52%

California

-0.95% -1.29% -1.53% -2.34% -1.93% -1.04% -0.46% 0.35%

Colorado 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

Connecticut

-1.98% -0.12% -0.06% -1.29% -1.01% 1.28% -1.44% 1.61%

Delaware 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Florida 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Georgia 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Hawaii

-0.95% -1.29% -1.53% -2.34% -1.93% -1.04% -0.46% 0.35%

Idaho 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

Illinois

-0.89% 0.42% -0.12% 0.12% -1.18% -0.12% 0.02% 0.03%

Indiana

-0.89% 0.42% -0.12% 0.12% -1.18% -0.12% 0.02% 0.03%

Iowa 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

Kansas 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

Kentucky

-0.68% 0.05% -0.02% -1.26% -2.02% -1.17% -0.61% -0.39%

Louisiana

-1.31% -2.37% -2.19% -2.68% 1.18% -0.10% -0.20% -0.52%

Maine

-1.98% -0.12% -0.06% -1.29% -1.01% 1.28% -1.44% 1.61%

Maryland 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Massachusetts

-1.98% -0.12% -0.06% -1.29% -1.01% 1.28% -1.44% 1.61%

Michigan

-0.89% 0.42% -0.12% 0.12% -1.18% -0.12% 0.02% 0.03%

Minnesota 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

Mississippi

-0.68% 0.05% -0.02% -1.26% -2.02% -1.17% -0.61% -0.39%

Missouri 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

Montana 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

Nebraska 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

Nevada 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

New Hampshire

-1.98% -0.12% -0.06% -1.29% -1.01% 1.28% -1.44% 1.61%

New Jersey 0.14% -0.77% -1.99% -0.84% 1.67% 0.34% -0.39% 0.09%

New Mexico 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

New York 0.14% -0.77% -1.99% -0.84% 1.67% 0.34% -0.39% 0.09%

North Carolina 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

North Dakota 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

Ohio

-0.89% 0.42% -0.12% 0.12% -1.18% -0.12% 0.02% 0.03%

Oklahoma

-1.31% -2.37% -2.19% -2.68% 1.18% -0.10% -0.20% -0.52%

Oregon

-0.95% -1.29% -1.53% -2.34% -1.93% -1.04% -0.46% 0.35%

Pennsylvania 0.14% -0.77% -1.99% -0.84% 1.67% 0.34% -0.39% 0.09%

Rhode Island

-1.98% -0.12% -0.06% -1.29% -1.01% 1.28% -1.44% 1.61%

88

South Carolina 0.82% 1.45% 1.43% -0.10% -1.52% -0.64% -0.90% -1.12%

South Dakota 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Tennessee

-0.68% 0.05% -0.02% -1.26% -2.02% -1.17% -0.61% -0.39%

Texas

-1.31% -2.37% -2.19% -2.68% 1.18% -0.10% -0.20% -0.52%

Utah 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

Vermont

-1.98% -0.12% -0.06% -1.29% -1.01% 1.28% -1.44% 1.61%

Virginia 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Washington

-0.95% -1.29% -1.53% -2.34% -1.93% -1.04% -0.46% 0.35%

Washington, DC 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

West Virginia 0.11% -0.88% -0.48% -1.80% -2.03% -1.20% -0.78% -0.34%

Wisconsin

-0.89% 0.42% -0.12% 0.12% -1.18% -0.12% 0.02% 0.03%

Wyoming 0.08% -1.83% -1.85% -2.29% -0.24% 1.45% -0.10% -0.01%

Table A-25. Annual Year-Over-Year Changes in Electricity Prices as Projected by EIA for the Commercial Market State 2008 2009 2010 2011 2012 2013 2014 2015 Alabama -0.02% 0.33% 0.25% -1.51% -2.11% -1.30% -0.49% -0.20%

Alaska

-0.80% -1.90% -2.27% -2.90% -2.34% -1.47% -0.69% 0.15%

Arizona 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

Arkansas 0.07% -2.02% -2.20% -3.27% 0.75% -0.32% -0.15% -0.27%

California

-0.80% -1.90% -2.27% -2.90% -2.34% -1.47% -0.69% 0.15%

Colorado 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

Connecticut

-2.96% -2.81% -2.36% -4.29% -1.95% 0.91% -1.19% 2.71%

Delaware 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Florida 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Georgia 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Hawaii

-0.80% -1.90% -2.27% -2.90% -2.34% -1.47% -0.69% 0.15%

Idaho 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

Illinois

-0.04% 0.35% -0.50% -1.35% -2.48% -0.95% -0.34% 0.07%

Indiana

-0.04% 0.35% -0.50% -1.35% -2.48% -0.95% -0.34% 0.07%

Iowa 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

Kansas 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

Kentucky

-0.02% 0.33% 0.25% -1.51% -2.11% -1.30% -0.49% -0.20%

Louisiana 0.07% -2.02% -2.20% -3.27% 0.75% -0.32% -0.15% -0.27%

Maine

-2.96% -2.81% -2.36% -4.29% -1.95% 0.91% -1.19% 2.71%

Maryland 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Massachusetts

-2.96% -2.81% -2.36% -4.29% -1.95% 0.91% -1.19% 2.71%

Michigan

-0.04% 0.35% -0.50% -1.35% -2.48% -0.95% -0.34% 0.07%

Minnesota 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

Mississippi

-0.02% 0.33% 0.25% -1.51% -2.11% -1.30% -0.49% -0.20%

Missouri 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

89

Montana 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

Nebraska 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

Nevada 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

New Hampshire

-2.96% -2.81% -2.36% -4.29% -1.95% 0.91% -1.19% 2.71%

New Jersey

-1.17% -3.63% -4.75% -4.13% 1.83% -0.22% -0.67% 0.47%

New Mexico 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

New York

-1.17% -3.63% -4.75% -4.13% 1.83% -0.22% -0.67% 0.47%

North Carolina 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

North Dakota 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

Ohio

-0.04% 0.35% -0.50% -1.35% -2.48% -0.95% -0.34% 0.07%

Oklahoma 0.07% -2.02% -2.20% -3.27% 0.75% -0.32% -0.15% -0.27%

Oregon

-0.80% -1.90% -2.27% -2.90% -2.34% -1.47% -0.69% 0.15%

Pennsylvania

-1.17% -3.63% -4.75% -4.13% 1.83% -0.22% -0.67% 0.47%

Rhode Island

-2.96% -2.81% -2.36% -4.29% -1.95% 0.91% -1.19% 2.71%

South Carolina 1.61% 1.72% 1.53% -0.32% -1.94% -0.84% -0.92% -1.04%

South Dakota 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Tennessee

-0.02% 0.33% 0.25% -1.51% -2.11% -1.30% -0.49% -0.20%

Texas 0.07% -2.02% -2.20% -3.27% 0.75% -0.32% -0.15% -0.27%

Utah 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

Vermont

-2.96% -2.81% -2.36% -4.29% -1.95% 0.91% -1.19% 2.71%

Virginia 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Washington

-0.80% -1.90% -2.27% -2.90% -2.34% -1.47% -0.69% 0.15%

Washington, DC 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

West Virginia 0.58% -0.88% -0.63% -2.14% -1.80% -1.12% -0.63% -0.12%

Wisconsin

-0.04% 0.35% -0.50% -1.35% -2.48% -0.95% -0.34% 0.07%

Wyoming 0.36% -2.20% -2.56% -3.50% -0.62% 1.89% 0.00% 0.10%

Table A-26. Annual Year-Over-Year Changes in Electricity Prices as Projected by NCI State 2008 2009 2010 2011 2012 2013 2014 2015 Alabama 13.52% 2.76% -5.60% 5.40% 7.72% -0.01% 12.62% 3.13%

Alaska 0.29% 1.24% 1.47% 6.00% -4.60% -0.06% -0.06% -0.06%

Arizona 15.82% -0.81% -11.04% 10.69% 7.24% 0.59% 15.48% 0.78%

Arkansas

-9.78% -1.38% -2.97% -0.75% 0.52% -1.03% 14.80% -8.39%

California 12.04% -4.70% -13.04% 9.91% 7.64% -0.43% 14.75% 1.90%

Colorado 11.25% -6.09% -14.80% 9.68% 6.84% -1.90% 13.77% 1.93%

Connecticut 8.85% -1.09% -8.47% 5.95% 7.73% 0.67% 13.70% -4.63%

Delaware 11.99% -3.40% -7.53% 6.48% 6.56% 5.80% 14.99% -3.38%

Florida 11.73% 1.73% -11.50% 6.79% 4.32% -1.18% 8.53% -0.02%

Georgia

-9.03% -0.92% -4.26% 0.82% 0.68% 0.20% 14.29% -7.25%

Hawaii

-0.32% 5.07% -0.06% -0.06% -0.06% -0.06% -0.06% -0.06%

Idaho 12.08% -5.85% -12.46% 5.00% 5.01% -0.59% 13.71% 2.41%

90

Illinois

-1.78% 6.41% -8.77% -6.77% -1.18% 2.17% 12.53% 9.08%

Indiana

-1.36% 6.51% -7.83% -7.13% -1.18% 3.15% 11.95% 8.23%

Iowa

-11.84% 2.76% 6.04% -1.85% -1.44% -1.39% 12.66% -8.97%

Kansas

-11.16% -2.55% -2.04% -1.02% 0.94% -0.71% 17.98% -7.99%

Kentucky 13.52% 2.76% -5.60% 5.40% 7.72% -0.01% 12.62% 3.13%

Louisiana

-9.78% -1.38% -2.97% -0.75% 0.52% -1.03% 14.80% -8.39%

Maine 8.38% -2.95% -10.57% 5.68% 7.17% 1.11% 13.29% -3.26%

Maryland 11.99% -3.40% -7.53% 6.48% 6.56% 5.80% 14.99% -3.38%

Massachusetts 9.03% -3.71% -5.91% 5.89% 7.94% 0.49% 13.85% -5.00%

Michigan

-9.73% -0.06% -2.73% 2.14% 0.44% 4.84% 13.77% -6.53%

Minnesota

-11.84% 2.76% 6.04% -1.85% -1.44% -1.39% 12.66% -8.97%

Mississippi 13.52% 2.76% -5.60% 5.40% 7.72% -0.01% 12.62% 3.13%

Missouri

-11.84% 2.76% 2.01% -1.92% -1.50% -1.44% 13.19% -9.30%

Montana 11.35% -5.48% -12.17% 8.99% 5.32% -0.03% 12.58% 1.90%

Nebraska

-11.84% 2.76% 6.04% -1.85% -1.44% -1.39% 12.66% -8.97%

Nevada 15.82% -0.81% -11.04% 10.69% 7.24% 0.59% 15.48% 0.78%

New Hampshire 10.81% -4.02% -9.85% 5.67% 7.16% 0.51% 15.68% -6.59%

New Jersey 11.99% -3.40% -7.53% 10.17% 6.34% 2.47% 14.99% -3.38%

New Mexico 15.82% -0.81% -11.04% 10.69% 7.24% 0.59% 15.48% 0.78%

New York 9.57% -9.02% -12.07% 4.35% 7.21% 0.51% 14.12% -4.78%

North Carolina

-9.90% 0.22% -3.46% 1.33% 0.93% 0.79% 14.20% -6.54%

North Dakota

-11.84% 2.76% 6.04% -1.85% -1.44% -1.39% 12.66% -8.97%

Ohio

-1.36% 6.51% -7.83% -7.13% -1.18% 3.15% 11.95% 8.23%

Oklahoma

-11.16% -2.55% -2.04% -1.02% 0.94% -0.71% 17.98% -7.99%

Oregon 11.35% -5.48% -12.17% 5.42% 5.51% -0.03% 12.98% 1.96%

Pennsylvania 12.55% 2.41% -4.69% 6.27% 7.25% 4.90% 13.63% 2.89%

Rhode Island 7.87% -3.17% -8.44% 5.50% 8.06% 1.14% 13.67% -4.49%

South Carolina

-9.90% 0.22% -3.46% 1.33% 0.93% 0.79% 14.20% -6.54%

South Dakota

-11.84% 2.76% 6.04% -1.85% -1.44% -1.39% 12.66% -8.97%

Tennessee 13.52% 2.76% -5.60% 5.40% 7.72% -0.01% 12.62% 3.13%

Texas

-3.56% -1.87% -12.18% -10.19% -8.05% -7.65% 11.91% 9.54%

Utah 12.93% -4.06% -13.01% 10.20% 7.08% -0.16% 14.33% 1.57%

Vermont 9.80% -2.65% -9.85% 3.30% 8.53% 0.51% 14.68% -4.95%

Virginia 11.99% -3.40% -7.53% 6.48% 6.56% 2.55% 15.47% -3.47%

Washington 11.35% -5.48% -12.17% 5.42% 5.51% -0.03% 12.98% 1.96%

Washington, DC 11.99% -3.40% -7.53% 6.48% 6.56% 5.80% 14.99% -3.38%

West Virginia 12.55% 2.41% -4.69% 6.27% 7.25% 4.90% 13.63% 2.89%

Wisconsin

-11.09% 0.22% 1.52% -0.20% 0.39% 0.12% 13.22% -8.58%

Wyoming 11.35% -5.48% -12.17% 8.99% 5.32% -0.03% 12.58% 1.90%

91

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February 2008 Subcontract report

4. TITLE AND SUBTITLE 5a. CONTRACT NUMBER Rooftop Photovoltaics Market Penetration Scenarios DE-AC36-99-GO10337 5b. GRANT NUMBER 5c. PROGRAM ELEMENT NUMBER

6. AUTHOR(S) 5d. PROJECT NUMBER J. Paidipati, L. Frantzis, H. Sawyer, and A. Kurrasch NREL/SR-581-42306 5e. TASK NUMBER PVB7.6401 5f. WORK UNIT NUMBER

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13. SUPPLEMENTARY NOTES NREL Technical Monitor: Robert Margolis

14. ABSTRACT (Maximum 200 Words)

The goal of this study was to model the market penetration of rooftop photovoltaics (PV) in the United States under a variety of scenarios, on a state-by-state basis, from 2007 to 2015.

15. SUBJECT TERMS photovoltaics; PV; PV market penetration; market penetration modeling; rooftop PV systems; solar energy; net metering; interconnection; federal solar energy tax credits; renewable systems interconnection; Navigant Consulting; National Renewable Energy Laboratory; NREL

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