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Established in 1974, the Solar Energy Industries Association® is the national trade association of the U.S. solar energy industry. Through advocacy and education, SEIA® is building a strong solar industry to power America. As the voice of the industry, SEIA works with its 1,000

member companies to champion the use of clean, affordable solar in America by expanding markets, removing market barriers, strengthening the industry and educating the public on the benefits of solar energy. www.seia.org

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Thank you for taking the time to complete the National Solar Database Survey. Your responses will help SEIA as it advocates for policies that will help move the solar industry forward across the country. As a token of our appreciation, attached below is a copy of the U.S. Solar Market Insight 2015 Year in Review full report, published by SEIA and GTM Research. This issue sold for $4,000 when released in March 2016 and now it is yours free of charge. Please do not share this link with anyone outside of your company SEIA and GTM Research release new reports every quarter with the best information available on national and state activity in the US solar energy industry. If you are not already a member of SEIA, please visit our membership page or email [email protected] to learn more about how joining SEIA can help your solar business grow. Best Regards, Justin Baca Vice President, Markets & Research Solar Energy Industries Association

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U.S. SOLAR MARKET INSIGHTFull Report

2015 Year in Review

March 2016


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Contents

U.S. Solar Market Insight March 2016 │ 2

CONTENTS1. Introduction ..............................................................................................................................5

1.1. In Focus: Four Predictions About U.S. Solar in 2016 9

2. Photovoltaics...........................................................................................................................13

2.1. Residential PV 14

2.2. Non-Residential PV 25

2.3. Utility PV 35

2.4. Detailed Installation Figures by State and Market Segment (MWdc) 41

2.5. Number of Installations by State and Market Segment 42

2.6. Detailed Forecast Tables 43

2.7. National System Pricing 472.8. Manufacturing 58

2.9. Component Pricing 62

3. Concentrating Solar Power .....................................................................................................67

3.1. Introduction 67

3.2. Installations and Market Outlook 67

4. Appendix A: Metrics and Conversions ....................................................................................70

4.1. Photovoltaics 70

4.2. Residential Photovoltaic System 70

4.3. Non-Residential Photovoltaic System 70

4.4. Utility Photovoltaic System 70

4.5. Concentrating Solar Power 70

5. Appendix B: Methodology and Data Sources .........................................................................71

5.1. Historical Installations 715.2. Average System Price 71

5.3. Manufacturing Production and Component Pricing 72

Disclaimer of Warranty and Liability ............................................................................................73


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Contents


Ownership Rights

This report ("Report") and all Solar Market Insight® ("SMI")TM reports are jointly owned by GreentechMedia and the Solar Energy Industries Association, Inc. (jointly, "Owners") and are protected byUnited States copyright and trademark laws and international copyright/intellectual property lawsunder applicable treaties and/or conventions. Purchaser of Report or other person obtaining a copylegally ("User") agrees not to export Report into a country that does not have copyright/intellectualproperty laws that will protect rights of Owners therein.

Grant of License Rights

Owners hereby grant User a personal, non-exclusive, non-refundable, non-transferable license touse Report for research purposes only pursuant to the terms and conditions of this license. Useragrees not to permit any unauthorized use, reproduction, distribution, publication or electronictransmission of any report or the information/forecasts therein without the express writtenpermission of either Owner. User purchasing this report may make a report available to otherpersons from his organization at the specific physical site covered by the terms of sale, but areprohibited from distributing the report to people outside the organization, or to persons whoseprincipal work location is a different geographic site within the organization.

Disclaimer of Warranty and Liability

Owners have used best efforts in collecting and preparing each report. Owners, their employees,affiliates, agents, and licensors do not warrant the accuracy, completeness, correctness, non-infringement, merchantability, or fitness for a particular purpose of Report. Owners, their employees,affiliates, agents, or licensors shall not be liable to user or any third party for losses or injury causedin whole or part by our negligence or contingencies beyond Owners' control in compiling, preparingor disseminating Report or for any decision made or action taken by User or any third party in relianceon such information or for any consequential, special, indirect or similar damages, even if one or moreOwners were advised of the possibility of the same. User agrees that the liability of Owners, theiremployees, affiliates, agents and licensors, if any, arising out of any kind of legal claim (whether incontract, tort or otherwise) in connection with its goods/services under this license and sales shallnot exceed the amount User paid to Owners for use of Report.


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About the Authors


ABOUT THE AUTHORSGTM Research | U.S. Research TeamCory Honeyman, Senior Solar AnalystShayle Kann, Senior Vice PresidentMJ Shiao, Director of Solar ResearchAustin Perea, Solar AnalystJade Jones, Senior Solar AnalystColin Smith, Solar Analyst

Solar Energy Industries Association | SEIAJustin Baca, Vice President of Markets & ResearchShawn Rumery, Director of ResearchAaron Holm, Data EngineerKatie O’Brien, Research Associate


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Introduction


1. INTRODUCTION2015 was a momentous year for solar power in the United States. Solar PV deployments reachedan all-time high of 7,260 megawatts direct current (MWdc), up 16% over 2014 and 8.5 times theamount installed five years earlier. Total operating solar PV capacity reached 25.6 GWdc by the endof the year, with over 900,000 individual projects delivering power each day. By the the time thisreport is published in Q1 2016, the U.S. will be approaching its millionth solar PV installation.

Figure 1.1 Annual U.S. Solar PV Installations, 2000-2015

When accounting for all projects (both distributed and centralized), solar made up 29.4% of newelectric generating capacity in the U.S. in 2015, exceeding the total for natural gas for the first time.

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Introduction


Figure 1.2 New U.S. Electricity-Generating Capacity Additions, 2012-2015

Source: GTM Research (solar) FERC (all other technologies)

At the market-segment level, 2015 was largely a continuation of ongoing trends.

Residential solar benefitted from a fourth consecutive year of >50% annual growth, withinstallations reaching 2,099 MWdc.

Non-residential solar was essentially flat for the third year in a row, with 1,011 MWdc ofinstallations. A mixture of market-specific factors and scaling challenges have plagued thesector, but numerous avenues remain for resumed growth over the coming year.

Utility solar remained the largest segment by capacity, with 4,150 MWdc of installations in2015. Even more notable than 2015 installation capacity is the current contracted projectpipeline, which now exceeds 19.8 GWdc.

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Figure 1.3 U.S. PV Installations by Segment, 2005-2015

At the state level, the market remained relatively concentrated. The top 10 states accounted for87% of all PV installations, and the top 20 states made up 96% of the market. But annual growthoccurred in 24 of the 35 states we track individually, and 13 states installed over 100 MWdc of solarin 2015, up from nine in 2014. Six states (AZ, CA, MA, NV, NJ and NC) have surpassed 1 GWdc incumulative solar capacity.

2015 was also a historic year for U.S. solar policy and regulation, with a number of decisions atboth the state and federal level that will determine the trajectory of the market’s future growth.

First, the federal Investment Tax Credit was extended through 2021 in December, and a“commence construction” rule was added, effectively providing the market with policy visibilitythrough 2023. GTM Research estimates that this extension alone will result in more than 50% netgrowth in U.S. solar installations from 2016-2020, an additional 24 GWdc over the five-year period.As a result of this change and other market developments since December, we now anticipate thatcumulative solar photovoltaic installations will reach 97 GWdc by the end of 2020.

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Introduction


Figure 1.4 U.S. PV Installation Forecast, Pre-ITC Extension Figure 1.5 U.S. PV Installation Forecast, Current

At the state level, net energy metering and electricity rate design came to the forefront ofregulatory debates around solar in 2015, and a number of crucial decisions were reached. InCalifornia, the Public Utilities Commission (PUC) reached a final decision on the state’s next waveof net metering (dubbed NEM 2.0), which makes relatively modest modifications for solarcustomers including mandatory time-of-use rates and no more netting out of non-bypassablecharges with solar. This ruling has largely been viewed as favorable for solar, while the opposite istrue of Nevada, where the state PUC issued an order that increases customer fixed charges, lowerssolar export compensation and, most controversially, applies to both existing and prospective solarcustomers. The Nevada decision remains in flux as this report is being published, with a number oflegal challenges pending on both the NEM revisions and the lack of a grandfathering-in provision.

Looking ahead to the rest of 2016, we anticipate another banner year for U.S. solar, which will benefitfrom gigawatts of utility PV that rushed through early stages of development to ensureinterconnection in 2016, in the event that the federal ITC stepped down to 10%. In turn, we forecast16 GWdc of solar PV installations, up 119% over 2015, driven in large part by a utility PV market thatwill add more capacity than all three market segments combined brought on-line in 2015.

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Introduction


1.1. In Focus: Four Predictions About U.S. Solar in 2016Every year, the U.S. solar market can point to a handful of market developments and policy trendsthat shaped the installation outlook for better or for worse. Without question, the extension of thefederal ITC in December ranked as the most important policy development for U.S. solar over thepast decade, let alone 2015. So with long-term certainty regarding the federal ITC, a number ofstate-level market drivers and risks will move to the forefront and play even larger roles in 2016.

Following are four predictions about key trends at the state level that will shape the U.S. solarmarket outlook in 2016.

Time-of-use rate structures will become the next hot topic in debates about the valueof rooftop solar

2015 marked a transition in the policy debate over reforms to net metering and rate design.Reforms proposed by utilities are evolving simply beyond new fixed charges for rooftop solarcustomers, and roping in new peak demand charges and rollbacks to the value of solar exportedthe grid. Meanwhile, debate about the future of rate design for rooftop solar customers is justheating up – with a growing number of utilities seeking to transition DG customers to time-of-use rate structures.

In 2016, this means the rooftop solar economic outlook will depend not only on favorableoutcomes to NEM debates, but also on the rollout of time-of-use (TOU) rates that have peakelectricity price periods that favorably align with peak periods of PV production. For example, inCalifornia, most customers that install rooftop solar when the next version of NEM takes effect willhave to switch to a new rate structure called E-TOU. Meanwhile, customers who have long beenon the more solar-friendly E-6 TOU rate can remain on E-6 through 2022. In turn, while netmetering rules were kept relatively intact under California’s new NEM 2.0 policy, there are bothcustomer-wide and solar-specific rate reforms that impact the savings generated by rooftop solar.

Case in point: in 2017, a typical homeowner in PG&E territory with rooftop solar under NEM 2.0and the new E-TOU rate would save 16% less on his or her annual electricity bill than would ahomeowner with rooftop solar under NEM 1.0 and the more solar-friendly E-6 TOU rate.


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Introduction


Figure 1.6 California PG&E Rooftop Solar Economics in 2017: Pre-Solar Retail Rate, AnnualSavings on E-6 Under NEM 1.0, and Annual Savings on E-TOU Under NEM 2.0

Source: GTM Research Rate Design Model

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Introduction


Community solar’s breakout year is officially 2016, just one year later than expected

The community solar market failed to meet initial expectations for 2015, mainly due to the sluggishrollouts of certain community solar programs (i.e. California’s Green Tariff Shared RenewablesProgram) or dragged-out debates over community solar program design (i.e., the eligibility of large-scale community solar projects in Minnesota).

In addition to policy-driven bottlenecks, certain states have seen slow starts to ambitiouscommunity solar pipelines due to challenges in both the subscriber acquisition process anddevelopers and EPCs scaling the learning curve in terms of how to partner with each other in statessuch as Massachusetts and New York.

But in 2016, we expect Colorado, Massachusetts and Minnesota collectively to drive more than100 MWdc of community solar, supplemented by emerging demand in New York and Maryland, aswell as individual utilities launching their own voluntary community-solar pilot programs.

At least 1 GW of utility-scale solar will be procured by customers that are not utilities

The below chart illustrates the oncoming onslaught of offsite, centralized solar projects beingprocured by retail commercial customers. A majority of that demand is coming from customersthat either leverage direct-access rules in California to procure wholesale electricity outside of theirutility, partner with utilities to procure offsite solar through a green tariff program, or sign financialhedge contracts (i.e., a synthetic or virtual PPA) that provides a utility-scale project with pricecertainty when selling power into a volatile wholesale electricity market.


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Introduction


Figure 1.7 Retail Procurement of Centralized Solar: Operating vs. Pipeline

Source: GTM Research, U.S. Utility PV Market Tracker

While the transaction structures vary, the past 12 months have set the stage for commercialdemand for solar in 2016 to evolve beyond traditional customer-sited net-metered solutions. Withthe extension of the federal ITC, 2016 marks the beginning of the utility-scale PV market beingdriven by both utilities and large C&I customers procuring offsite centralized solar.

Utility-scale solar will pack in projects as if the federal ITC were still scheduled to step down

As mentioned, a majority of the utility PV project pipeline rushed through the development cycleto ensure a 2016 interconnection. The biggest question mark for utility PV in 2016 is the extent towhich developers can renegotiate commercial operation dates to spill ambitious pipelines over into2017. While certain types of projects, such as those landing PPAs under Public Utility RegulatoryPolicies Act (PURPA) rules, will have wiggle room to spill over into 2017, most projects withengineering, procurement and construction (EPC) agreements already in place and/or rigidinterconnection timelines from the utility offtaker or project financier will still come on-line in2016, despite the fact that the federal ITC has been extended.

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Photovoltaics


2. PHOTOVOLTAICSFigure 2.1 Annual State PV Installation Rankings

Rank Installations (MWdc)State 2013 2014 2015 2013 2014 2015

California 1 1 1 2,621 3,549 3,266

North Carolina 3 2 2 335 397 1,134

Nevada 12 3 3 47 349 307

Massachusetts 4 4 4 240 317 286

New York 9 7 5 72 147 241

Arizona 2 5 6 421 247 234

Utah 30 23 7 2 14 231

Georgia 7 16 8 91 45 209

Texas 8 8 9 75 129 207

New Jersey 5 6 10 236 240 181

Maryland 16 11 11 29 80 144

Colorado 10 13 12 56 68 144

Hawaii 6 9 13 144 107 117

Connecticut 15 15 14 37 56 91

Vermont 21 18 15 16 38 43

Florida 18 20 16 26 22 41

New Mexico 13 10 17 45 88 41

Louisiana 35 19 18 1 31 32

Oregon 24 26 19 7 8 30

Washington 23 24 20 9 14 26

Indiana 11 14 21 54 59 24

Missouri 17 12 22 28 73 20

New Hampshire 33 31 23 2 3 15

Pennsylvania 14 25 24 38 10 13

Minnesota 25 29 25 6 6 13

Illinois 34 28 26 2 6 11

Tennessee 19 17 27 25 44 11

Ohio 20 22 28 21 15 10

Virginia 26 30 29 6 6 10

Delaware 22 27 30 9 7 10

Washington, D.C. 31 33 31 2 3 7

Iowa 27 21 32 4 15 6

Wisconsin 29 34 33 3 2 5

Michigan 32 32 34 2 3 4

South Carolina 28 35 35 4 1 3

Source: GTM Research


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Photovoltaics


2.1. Residential PV

National Installations

2,099 MWdc installed in 2015, representing 66% growth over 2014

The residential PV market experienced its largest annual growth rate to date, an impressive featgiven that 2015 marked the fourth consecutive year of greater than 50% annual growth.

Similar to prior years, California served as the primary driver of demand, accounting for nearly 50%of annual residential PV installations. However, the residential market is showing signs ofgeographic demand diversification, with the number of 20 MWdc annual state markets forresidential solar increasing threefold over the past four years.

Figure 2.2 Annual Residential PV Installations vs. Number of 20 MWdc Annual State Markets

But while a growing number of state markets are picking up steam, an even larger number of statesare considering reforms to net metering rules that threaten the market’s ability to maintain ahockey-stick growth trajectory. Most recently, net energy metering (NEM) reforms approved inNevada are expected to drop the state from being the fifth-largest residential PV market in 2015(based on annual installations) to the rank of 31st in 2016.

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Photovoltaics


Quarterly Installations by State

Figure 2.3 Quarterly Residential PV Installations by State (MWdc), Q4 2012-Q4 2015

State 2012Q4

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Arizona 18.2 16.6 15.2 16.9 24.0 23.0 19.1 22.2 29.9 26.8 30.8 21.5 30.7

California 56.1 78.6 84.9 104.6 141.8 131.9 142.8 158.8 181.3 231.7 231.3 264.8 283.0

Colorado 6.1 8.3 6.7 5.5 7.7 10.5 9.2 9.2 12.9 10.3 11.5 8.6 9.8

Connecticut 2.6 1.7 2.0 2.2 1.4 1.4 4.2 7.4 10.3 10.3 12.2 16.8 15.8

Delaware 0.2 0.2 0.2 0.5 0.3 0.6 0.6 0.4 0.6 0.9 0.7 1.7 1.9

Florida 1.2 2.7 1.7 1.4 1.6 3.1 1.9 2.2 2.5 3.1 6.5 3.3 4.1

Georgia 0.2 0.1 0.1 0.2 0.0 0.0 1.0 0.1 0.1 0.2 0.1 0.3 0.4

Hawaii 22.4 22.8 18.8 16.1 25.6 17.7 13.6 9.8 19.6 16.4 15.4 16.7 17.0

Illinois 0.2 0.1 0.2 0.1 0.2 0.1 0.1 0.2 0.3 0.4 0.4 0.4 0.4

Indiana - 0.0 0.2 0.1 0.1 0.1 0.1 0.2 0.3 0.2 0.4 0.4 0.4

Iowa 0.2 0.1 0.2 0.4 0.8 0.6 0.8 1.6 1.9 0.5 0.5 0.2 0.4

Louisiana - - - - - 6.9 8.0 9.8 5.1 5.8 8.6 10.7 6.2

Maryland 1.2 0.4 3.4 2.9 2.6 4.7 7.7 10.1 20.9 17.8 23.5 22.8 17.8

Massachusetts 5.5 6.4 7.0 8.0 8.6 7.7 14.2 19.4 25.8 23.5 35.1 41.1 41.1

Michigan 0.3 0.3 0.2 0.3 0.4 0.2 0.3 0.7 1.0 0.3 0.4 0.5 1.1

Minnesota 0.3 - 0.0 0.2 0.2 0.1 0.0 0.5 0.8 0.8 0.7 1.2 1.0

Missouri 1.4 2.5 2.9 4.4 4.6 4.8 7.2 6.5 1.9 1.3 1.6 2.1 1.9

Nevada 0.0 0.2 0.1 0.4 0.4 0.8 1.6 3.5 5.7 10.5 14.7 36.6 33.7

New Hampshire - 0.2 0.3 0.4 0.3 0.3 0.4 0.8 0.9 0.8 1.8 2.4 5.5

New Jersey 9.8 11.1 11.3 6.2 9.2 11.6 12.8 17.4 18.8 18.4 22.6 23.5 27.0

New Mexico 1.0 0.9 0.7 1.1 1.6 1.2 1.2 1.3 1.5 1.8 1.3 2.3 2.8

New York 5.9 3.0 5.1 6.1 13.2 9.1 15.9 22.7 41.6 40.5 43.1 37.5 41.9

North Carolina 0.1 0.4 0.6 0.6 0.7 0.7 0.9 1.2 1.6 1.2 1.6 2.7 3.5

Ohio 0.3 0.2 0.5 0.5 1.3 0.1 0.2 0.5 0.4 0.4 0.6 0.7 0.7

Oregon 1.0 1.7 0.9 1.2 1.8 1.0 1.5 1.3 2.7 2.9 2.1 2.4 3.7

Pennsylvania 0.9 3.3 0.5 4.5 1.8 0.5 0.5 0.5 0.4 0.2 0.4 1.3 1.9

South Carolina 0.0 0.0 0.0 0.1 0.1 0.2 0.2 0.3 0.2 0.3 0.3 0.4 0.8

Tennessee 1.2 1.3 0.4 0.4 0.2 0.1 0.3 0.7 0.5 0.3 0.5 0.6 0.6

Texas 2.5 1.5 1.7 2.8 3.2 2.7 2.8 4.7 4.4 4.3 5.7 8.1 7.2

Utah 0.2 0.0 0.0 0.2 0.4 0.6 1.7 2.3 3.5 3.4 4.5 6.5 8.4

Vermont 0.5 0.9 1.0 0.9 1.8 1.8 1.0 1.5 2.1 1.7 5.1 4.5 4.6

Virginia - 0.4 0.4 0.5 0.3 0.3 0.4 0.7 0.7 1.7 1.0 1.3 1.9

Washington 1.1 1.3 2.4 2.0 2.1 1.8 2.7 3.6 3.9 4.3 6.0 6.3 7.1

Washington, D.C. 0.5 0.0 0.1 0.7 0.5 0.6 0.4 0.5 0.4 0.6 1.2 0.8 0.8

Wisconsin 0.3 0.2 0.1 0.3 0.4 0.1 0.2 0.4 0.6 0.1 0.3 0.5 0.8

Other 6.2 1.2 1.7 2.8 2.1 1.9 3.5 4.2 4.5 4.6 5.8 9.6 5.8

Total 148 169 171 195 261 249 279 327 410 448 498 561 591


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Photovoltaics


Trends in Third-Party Ownership

Figure 2.4 Percentage of New Residential Installations Owned by a Third Party in Major State Markets, Q4 2011-Q4-2015

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CA 67% 71% 73% 75% 69% 71% 72% 68% 64% 59% 52% 53% 47%

AZ 90% 89% 85% 86% 78% 78% 75% 79% 82% 80% 78% 77% 75%

CO 83% 91% 89% 82% 85% 82% 95% 78% 79% 63% 51% 41% 38%

MA 64% 65% 59% 59% 52% 47% 68% 70% 72% 72% 69% 69% 76%

NJ 89% 89% 93% 92% 95% 92% 89% 92% 89% 90% 92% 91% 90%

NY 62% 58% 57% 57% 59% 57% 61% 67% 72% 68% 59% 53% 47%

NV 16% 6% 0% 4% 10% 4% 21% 6% 53% 75% 81% 92% 88%


In most mature state markets, third-party-owned (TPO) residential PV systems continue to be anattractive option for many homeowners. However, Arizona, California, Colorado and New York allexperienced a declining TPO market share in 2015. By this point, almost all major TPO providershave introduced a loan product, and there are a number of new pure-play loan providers that have

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Photovoltaics


entered the market. Many of the new loans offered by these companies provide the same benefitsas TPO solar, such as long-term tenors that allow for upfront savings and include maintenance.Additionally, the cost of solar has fallen enough that more customers can afford to pay in cash ortake out short-term home equity loans. California and Colorado in particular show how quickly theTPO share can decline as a result of national companies beginning to offer loans.

On the other hand, TPO market share in Massachusetts and New Jersey has generally flat-lined overthe recent quarters, although Massachusetts did regain ground in Q4 2015. New Jersey continues tosee the highest share of third-party-owned systems out of all major residential markets. The volatilityof SREC prices in the state may have contributed to this trend, since consumers often prefer to avoidSREC price risk, even though SREC incentives make New Jersey an attractive market for customer-owned solar. In Massachusetts, national solar companies that dominate the market continue toprimarily offer TPO, although local installers generally focus more on cash sales and loans.Additionally, the introduction of a state-backed solar loan program administered by the state’sDepartment of Energy Resources has yet to have much of an effect on TPO uptake.

Across the landscape of emerging state markets, a number of states have addressed third-partyownership. Most notably, Georgia in Q1 2015 legalized third-party ownership, and a ballotinitiative is underway to put third-party ownership of solar to a statewide vote in Florida. Legislationis also being considered in North Carolina to legalize TPO, in addition to Pennsylvania, where a bill isbeing considered that would introduce property-assessed clean energy (PACE) financing programsthat would allow third-party leases and PPAs for eligible projects. The ascent of Nevada’sresidential PV market in 2015 was accompanied and partly driven by a stark increase in the shareof TPO. However, given the recent NEM ruling and the resulting projected decline of the Nevadamarket, it’s unlikely that the state will continue to be a stronghold for TPO.

The addressable residential market is still massive compared to the number of customers whohave gone solar thus far, leaving an enormous opportunity for growth, and no single strategy todeliver systems to residential rooftops has yet proven dominant. In the near term, we expectthat TPO PV systems will continue to drive the residential market. Cash and loan deals may playa smaller role than originally forecasted given the extension of ITC, which provides more benefitsfor customer-owned systems. On the regulatory and legislative front, select states and utilitieshave designed incentive programs and issued rules that aim to ramp direct-owned residentialPV systems. For example, Xcel’s Solar*Rewards rebate program in Colorado offers higherincentive rates for direct-owned systems than for TPO systems; Massachusetts launched a $30million loan program in 2015 for residential solar; and in 2014, Arizona’s Department of Revenueruled that TPO systems are no longer exempt from property taxes. For these reasons, GTMResearch expects the relative share of residential TPO systems to decline in 2016.


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State Market Analysis

Figure 2.5 Top 10 Residential PV State Markets from 2015: Key Installation Figures

Installations(MWdc) Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

California 142.8 158.8 181.3 231.7 231.3 264.8 283.0

New York 15.9 22.7 41.6 40.5 43.1 37.5 41.9

Massachusetts 14.2 19.4 25.8 23.5 35.1 41.1 41.1

Arizona 19.1 22.2 29.9 26.8 30.8 21.5 30.7

Nevada 1.6 3.5 5.7 10.5 14.7 36.6 33.7

New Jersey 12.8 17.4 18.8 18.4 22.6 23.5 27.0

Maryland 7.7 10.1 20.9 17.8 23.5 22.8 17.8

Hawaii 13.6 9.8 19.6 16.4 15.4 16.7 17.0

Connecticut 4.2 7.4 10.3 10.3 12.2 16.8 15.8

Colorado 9.2 9.2 12.9 10.3 11.5 8.6 9.8



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Figure 2.6 Residential PV Market Outlook: Top 10 State Markets Based on 2015 Installations

Top 10 Statesin 2015 State-Level Market Outlook

California

Strong: The CPUC’s final decision regarding NEM 2.0 largely leaves the initial decision intact with retail-rate remuneration for exported excess generation. The most significant revisions include non-bypassablecharges levied on gross grid consumption, a one-time interconnection fee, and a mandatory, yet-to-be-determined TOU rate schedule for all NEM 2.0 systems. While the effects of TOU rate design onresidential PV remains up for debate, California remains well positioned to be one of the top 5 states forrooftop solar economics between now and 2020.

New York

Strong: After seeing a minor downturn in growth in Q3 2015, New York residential has regained itsprevious position thanks in part to a record quarter in PSEG Long Island territory. In Q4 2015, NewYork’s rooftop solar market landed a major policy win, with the Public Service Commission lifting theaggregate capacity limits on NEM, ruling that utilities must continue to enroll PV systems under theNEM program until a “value of DER” process initiated by REV is complete. The PSC plans to finalize amethodology on a value-of-DER tariff by the end of 2016. The scope of reforms in that proceeding,as well as the timeline for transitioning out of current NEM rules, will play a primary role in shapingthe long-term outlook.

Massachusetts

Neutral: In January 2016, the state’s Department of Energy Resources set aside a 120 MWdc carve-out ofthe remaining SREC II program for systems below 25 kW due to heavy subscription by commercialdevelopers. As such, the near-term outlook remains stable due to sufficient additional SREC II-eligiblecapacity. However, the outlook toward the end of 2017 into 2018 will hinge on the state legislatureestablishing a successor incentive program after SREC II. Such legislation, however, would come eitherafter or in tandem with ongoing efforts to extend the net-metering cap, which has frozen a majority ofnew development for commercial solar.

Arizona

Neutral: In the second half of 2015, residential installations in Salt River Project’s utility service territoryexperienced a stark downturn, given the rollout of new NEM rules (including a new peak demand chargefor solar customers and revised compensation for solar exported to the grid). In turn, demand shiftedback to Arizona Public Service (APS) territory, with the utility driving a growing share of state-widedemand, enabling Arizona’s residential market to post its second-largest quarter ever in Q4 2015. In 2016,the NEM debate is shifting gears to include a few other utilities, namely, Tucson Electric Power, APS andUNS. TEP and UNS are both seeking to lower NEM compensation, increase fixed charges, and add ademand charge. Meanwhile, the Arizona Corporation Commission has to rule on a value-of-solar decision,with hearings set to begin at the end of April.

Nevada

Weak: The recent decision by Nevada’s PUC to lower NEM compensation to the wholesale rate, combinedwith an unprecedented provision to prohibit grandfathering in of existing solar systems, has been adevastating blow to the market. Nevada’s rapid ascendency to being a top ten state market in 2015 willbe short-lived due to this decision, which will severely hamper growth in 2016 and beyond as economicsplummet. Major national installers have already fled the state, and we expect 93% less residential solarinstallations in Nevada in 2016 than previously projected.


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Figure 2.7 Residential PV Market Outlook: Top 10 State Markets Based on 2015 Installations

Remaining Top 10States in 2015 State-Level Market Outlook

New JerseyStrong: While New Jersey’s commercial market floundered in 2015, the residential market has been on anupward trajectory despite persistent SREC oversupply. As predicted, for the first time, New Jersey’sresidential market outpaced commercial solar by a significant margin, one that will only continue to widen.

Maryland

Strong: After a record year in which Maryland saw 82 MWdc of solar PV installed (almost double its 2014total), 2015 marked its first year breaking into a top 10 state market ranking. The state’s recent growthis a function of an above-average consolidated installer landscape. The long-term plans of a small numberof national installers will remain drivers of residential solar growth within the state.

Hawaii

Weak: Rounding out one of the three major NEM battles of 2015, Hawaii’s residential market hassuffered a blow with the PUC decision to lower NEM compensation down to the peak demand avoided-cost rate. While the market stayed flat in the second half of 2015, conversations with installers suggestthat new sales have severely suffered as a result of the decision. While 2016 will benefit from a backlogof projects grandfathered in under old NEM rules, the tail end of the year will be supported by the firstwave of projects under interim NEM rules. On one hand, the economics under interim NEM are stillviable, but installers are struggling to close deals with homeowners because NEM rules in two yearsfrom now remain undetermined.

Connecticut

Strong: The Connecticut Green Bank’s performance-based incentives (PBIs) for third-party ownership andrebates for direct ownership are expected to remain available throughout the year, before transitioningto a new PBI that is not based on ownership type. While the state is viewed as a market with a sluggishincentive approval process, national installers have achieved scale in Connecticut, bringing projects on-line despite what is sometimes a six month lag before an incentive is awarded.

Colorado

Neutral: In 2015, Colorado’s residential demand was heavily driven by a backlog of projects from 2014, inaddition to 2015 projects awarded through Xcel’s Solar*Rewards incentive program. In 2016, we similarlyexpect the market to be driven by both a mix of 2016 incentive-funded projects and a spillover of 2015incentive-funded projects. Another source of demand will likely also influence 2016 volumes, as webelieve that the recent PUC ruling in favor of maintaining retail-rate NEM will likely inspire the first waveof non-incentive-funded, NEM-only systems coming on-line in the latter half of the year. In addition, RPSprogram design for community-based solar and a receptive utility in Xcel Energy may siphon someresidential customers that would have enrolled in a traditional rooftop PV program.



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2.2. Residential PV State Market Spotlights

California 1,011 MWdc installed in 2015

Up 64% over 2014

In 2015, California once again proved to be the most vital market for residential solar in the U.S.With a strong showing from Q4 2014 to Q1 2015 – primarily due to a backlog of installations fromQ4 2014 that were interconnected in Q1 2015 – growth flat-lined in Q2 before regaining steam inthe second half of the year. California once again beat its own record for the most residential PVinstalled in a single quarter in Q4 2015, in addition to being the first state to install over a gigawattof residential solar in a year. Though its share of quarterly installations fluctuated quarter-over-quarter, California still accounted for nearly 50% of residential PV demand in the U.S in 2015.

2015 has been an eventful year for policy, as the national ITC debate has been resolved andaction has shifted to state PUCs across the U.S. that are addressing vital questions regardingNEM and rate design. California has been no exception to this rule, as the state’s ability tomaintain its status as the top residential and commercial PV market remains dependent on theoutcome of the CPUC’s NEM 2.0 decision.

With retail-rate compensation in place, most of the components of the initial NEM decision will bekept intact in the successor tariff. However, a few changes in the form of non-bypassable charges,new interconnection fees, and a mandatory time-of-use rate schedule for NEM 2.0 system havebeen introduced and will have some modest negative impacts – estimates suggest ~10% – onresidential economics that will likely affect volumes in the second half of 2016.

Non-bypassable Charges: Under previous NEM rules, certain non-bypassable charges werelevied on the net kilowatt-hours consumed from the grid. NEM 2.0 stipulates that solarcustomers must pay these charges on gross grid consumption, which will add approximately$.02 to $.03/kWh to electricity bills.

Interconnection Fees: One-time interconnection fees will apply to new systems and areestimated to be $75 to $150.

Time-of-Use Rates: The NEM 2.0 regime requires all new solar customers to be placed on anew TOU rate schedule that is yet to be released.

Outside of the NEM decision, 2015 also saw the CPUC approve changes applying to all customersin which electricity rates gradually flatten from four to two tiers over the next few years. The tieredrate proposal, along with a transition to the aforementioned TOU rates (current NEM customersmay stay on their existing rate plans, while NEM 2.0 customers will be required to take on TOUrates) will move customer classes to a 25% cost differential between high-usage and low-usagetiers by 2019. As the tiers flatten, the value proposition will improve for low-energy-usage


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customers and worsen, but not erase, that value for higher-energy-usage customers. However,TOU rates remain a policy question mark in regard to their effect on rooftop PV, given uncertaintyabout the structure of the TOU schedule.

Looking forward, the outlook to 2019 for residential PV in California looks fairly favorable due to anumber of policy considerations that provide stability to an otherwise volatile industry. While theNEM 2.0 decision isn’t the best-case scenario for solar, retaining retail-rate compensation for PV isa huge boon to the industry, despite the imposition of additional charges and fees. Additionally,while the flattening of the rate tiers may result in a modest net gain for rooftop solar, the outcomeof the TOU rate schedule remains an important variable affecting medium- and long-terminstallation volumes. However, the outlook past 2019 looks murky, as the CPUC is set to revisit theNEM debate once again in that timeframe.

Nevada 95 MWdc installed in 2015

Up 720% over 2014

In 2015, Nevada represented a microcosm of the policy drivers and risks that underlie the nationalresidential PV market outlook.

Over a 12-month span, two key factors accelerated Nevada’s transition from a niche market to aleading market. First, with sufficiently attractive economics, the market greatly benefited from theentrance of national residential solar companies, which leveraged their strong salesforces and third-partyfinancing solutions to accelerate quarterly installation volumes. Well over 75% of annual residentialinstallations were third-party owned in 2015, a record market share for TPO systems in the state.

Second, legislative decisions in the summer of 2015 allowed Nevada’s residential market to achievenear-term growth above and beyond the pre-existing net metering capacity limit. Back in May 2015,NV Energy and solar industry advocates arrived at a stopgap solution that extended the NEM capfrom 3% of peak load to 235 MWdc. Even with that short-term extension, NEM applications reachedthe cap on August 20, 2015, well before utility projections.

But in January 2016, the state PUC approved unprecedented reforms to NEM rules within the statethat are being applied both to future and existing rooftop solar customers. After extensive debate,the final decision is to gradually phase in increased fixed charges, and reduce compensation forexcess solar sold to the grid from full retail to wholesale avoided costs over the next 12 years. Whilethe reforms themselves rank as one of the starkest reductions to rooftop solar compensation, themore unprecedented decision was to apply these reforms to customers who have already installedrooftop solar. In every other state where NEM reforms have been approved, existing solarcustomers have been grandfathered in under prior NEM rules indefinitely or for a certain numberof years from installation date.


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Figure 2.8 Levelized Rooftop PV Savings: New vs. Old Nevada NEM Rules Applied toa 2016 Installation

Source: NV Energy, GTM Research Rate Design Model

Note: 30 year levelized solar savings projection for a customer in Southern Nevada. As noted on NV Energy’s net meteringwebpage, net metering rates are subject to quarterly adjustments.

As the above figure reveals, in 2016, customers considering rooftop solar would need a fixed PPA rateanywhere between 4 cents and 8 cents/kWh to ensure some level of savings under the revised NEMrules. As such, the recent NEM reforms essentially erase the once-bullish outlook for residential PVin Nevada, confining demand to customers willing to accept 20+ year payback periods or greater oncash sales, as third-party PPAs no longer pencil out economically.

Residential PV Market Outlook

GTM Research maintains a bullish outlook for the residential solar market over the next fiveyears. We forecast 34% annual growth in 2016, followed by 25% growth and 3.5 GWdc installedin 2017 thanks to the extension of the federal ITC. In 2016, we expect that 16 states will eachinstall over 20 MWdc of residential solar, four of which will add more than 100 MWdc for thesecond straight year (California, Massachusetts, New Jersey and New York).

$0.046 $0.051 $0.057 $0.063$0.072

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Levelized Solar Savings:New NEM Rules

Levelized Solar Savings:Old NEM RulesFOR NSD RESPONDENTS ONLY

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Through 2016, the strong near-term outlook is pegged to favorable outcomes in net-meteringand rate-design debates that have allowed residential solar economics to remain unchanged orbe marginally impacted to sustain demand.

But it would be imprudent to assume that as distributed PV penetration continues to grow,that net metering at the full retail rate will remain the policy paradigm of the future. Thisreality is best evidenced by recently approved reforms to net metering in Nevada, which willresult in the state’s residential market falling 95% on annual basis in 2016, after growing 720%in 2015 on an annual basis.

With that in mind, continued growth, especially in major state markets, is pegged in part to threekey trends. First, as the cost of solar continues to decline, by 2020 we expect direct-ownedsystems to drive a growing share of residential installations, as loan product offerings support ahigher share of growth. Second, a minor but growing share of residential PV installations will bepaired with storage, especially in states where reforms to net metering incentivize higher levelsof self-consumption. Lastly, as states such as California, New York and Texas explore the futureof DER aggregation, the next five years will shed light on the extent to which potential lostrevenue from net metering reforms can be mitigated by residential (and non-residential) solarbeing compensated for particular grid services.

Figure 2.9 Annual Residential PV Installation Forecast, 2010-2021E


246 305494

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2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E 2021E

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2.3. Non-Residential PV

National Installations

1,011 MWdc installed in 2015, representing a 4% dip compared to 2014

While residential solar’s impressive growth storyline continued in 2015, so did the non-residentialPV market’s theme of flat demand. The continued stagnation in non-residential solar demandstems from states with either weak incentive funding or constrained development opportunitiesfor 1+ MWdc projects. Amidst sluggish demand in most major state markets, the non-residentialsolar market became increasingly dependent on California, which experienced growthindependent of state incentive funding thanks to solar-friendly rate structures and newdevelopment opportunities for 1+ MWdc projects.

Looking ahead, the 2016 rebound in non-residential PV demand will be supported by a triple-digit-megawatt pipeline of community solar projects, plus continued dependence on California tosupport nearly one-third of annual demand.

Figure 2.10 U.S. Non-Residential PV Installations, 2010-2015


63 6494

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Figure 2.11 Quarterly Non-Residential PV Installations by State (MWdc), Q4 2012-Q4 2015

State 2012Q4

2013Q1

2013Q2

2013Q3

2013Q4

2014Q1

2014Q2

2014Q3

2014Q4

2015Q1

2015Q2

2015Q3

2015Q4

Arizona 34.1 7.7 5.3 23.5 21.7 28.5 5.2 6.7 9.5 5.5 4.9 4.2 4.2

California 98.0 58.9 64.3 83.9 85.6 60.5 68.0 53.9 124.2 87.6 67.2 109.5 133.4

Colorado 4.6 4.9 6.7 7.0 9.1 6.4 5.4 9.1 5.0 2.6 6.4 8.2 4.2

Connecticut 1.7 4.1 5.8 7.4 5.4 3.4 10.0 4.9 7.2 7.0 5.6 12.4 11.1

Delaware 0.4 0.2 0.3 0.3 0.6 2.5 1.8 0.4 0.6 0.4 2.6 0.2 1.4

Florida 2.5 7.2 4.4 2.0 5.4 2.4 2.8 4.2 2.4 2.2 5.2 4.1 4.7

Georgia 3.5 3.0 0.7 0.3 0.3 0.8 1.3 0.0 0.0 0.1 0.0 0.8 0.1

Hawaii 17.6 15.2 10.9 8.7 14.2 9.4 7.3 5.4 10.0 9.4 8.5 9.4 9.8

Illinois 0.2 0.1 0.1 0.1 0.6 3.2 0.9 0.5 0.4 0.2 0.2 0.3 6.9

Indiana - 0.0 1.6 0.9 0.2 0.0 1.5 0.5 0.4 0.4 0.1 0.1 0.8

Iowa 0.1 0.7 0.2 0.4 1.1 1.5 2.0 3.7 3.1 0.7 1.1 1.8 1.3

Louisiana - - - - - 0.1 0.1 0.4 0.2 0.0 0.0 0.0 0.1

Maryland 10.3 1.9 5.5 2.3 9.8 9.1 8.5 4.0 14.9 11.7 11.2 11.6 10.2

Massachusetts 40.4 21.8 17.5 37.6 93.9 19.1 94.0 67.6 49.1 38.2 34.2 37.9 34.8

Michigan 0.1 0.3 0.3 0.1 0.2 0.1 0.3 0.2 0.3 0.2 0.2 0.3 0.2

Minnesota 0.9 2.2 0.1 0.1 1.0 0.7 0.3 2.1 1.4 1.4 1.0 1.5 5.1

Missouri 1.7 4.2 2.6 2.7 4.4 5.3 12.1 14.7 4.4 2.1 4.3 2.6 0.7

Nevada 2.7 0.5 3.7 0.3 3.4 2.4 3.5 4.9 7.9 0.9 0.8 2.9 1.1

New Hampshire 0.1 0.2 0.1 0.4 0.3 0.0 0.1 0.4 0.3 0.3 1.4 3.0

New Jersey 43.1 57.4 56.0 20.6 54.8 41.1 30.8 10.9 19.5 13.7 6.5 10.0 17.3

New Mexico 2.0 0.5 2.0 4.3 7.7 2.7 5.8 5.5 2.4 2.7 0.5 0.7 1.2

New York 17.4 3.1 5.7 6.7 27.0 11.8 9.7 10.8 16.5 15.2 22.7 13.2 15.6

North Carolina 23.2 2.8 0.0 31.0 1.1 0.5 0.5 0.6 1.4 1.6 1.7 5.9

Ohio 3.3 5.8 5.7 1.8 3.9 3.3 2.3 4.7 2.9 1.6 0.9 0.4 5.0

Oregon 4.7 0.2 0.4 0.4 0.6 0.1 0.3 0.8 0.5 1.2 0.7 1.1 2.8

Pennsylvania 4.0 4.9 9.4 5.9 8.1 1.7 2.5 2.5 1.6 2.2 0.9 0.6 5.3

South Carolina 0.0 0.0 0.1 - - 0.1 - 0.0 0.1 0.1 0.0 0.5 1.1

Tennessee 1.2 15.4 1.6 0.7 0.4 0.7 0.2 0.9 0.4 1.2 0.5 5.9 0.2

Texas 1.4 0.8 2.5 1.2 2.0 4.1 2.0 2.8 6.6 3.0 2.8 8.2 2.4

Utah 0.1 0.1 0.9 0.0 0.8 4.3 0.7 0.8 0.2 2.6 1.8 2.2 7.5

Vermont 0.6 1.1 0.5 0.3 0.2 0.2 0.1 0.6 3.3 3.0 2.8 3.9 3.0

Virginia 0.1 0.1 0.1 3.7 1.8 0.1 0.4 0.1 1.4 0.1 0.8 0.7

Washington 0.2 0.3 0.1 0.2 0.3 0.9 0.3 0.5 0.2 0.2 0.4 1.0 0.4

Washington, D.C. 0.0 0.1 0.0 0.1 0.7 0.2 0.3 0.1 0.2 2.8 0.7 0.1 0.3

Wisconsin 0.0 0.7 0.0 0.2 0.2 0.1 0.3 0.4 0.4 0.4 0.1 0.5 1.8

Other 8.2 2.5 8.5 8.5 6.8 4.0 6.8 7.2 9.7 7.2 8.9 7.1 4.6

Total 305 249 226 228 405 234 288 233 306 230 206 267 308


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Non-Residential Market Trends: Large-Scale C&I Procurement

Despite the tremendous growth of available capital for non-residential solar projects over the lastfive years, financing and developing small to mid-sized projects has often proven to be prohibitivelydifficult. Some of the most prominent problems include lack of standardization (e.g., varyingcontract terms, power purchasers that lack credit ratings or easily assessed creditworthiness, andonerous site-specific project requirements) and relatively high costs (the transaction costs ofsmaller commercial projects are often comparable to those for much larger deals, but lack thebenefit of scale). These difficulties have generally led developers to focus their attention on largercommercial projects (or portfolios of projects), particularly those 1 MWdc or larger.

However, 2015 saw an impressive uptick in the share of systems less than 1 MWdc in size,jumping to approximately 60% of annual installed capacity. On one hand, the uptick in marketshare for small and medium-sized commercial solar systems has been driven by increaseddemand in California, where solar-friendly rate structures with expanded or lifted customerparticipation caps have spurred growth independent of state incentive funding. And since theNEM system-size cap under current NEM rules is set at 1 MWac, the market’s growth is primarilydriven by sub-1 MWdc project development.

Figure 2.12 National Non-Residential PV Installations by System Size


73%63% 66%

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In 2016, however, we expect the 1+ MWdc segment to account for a larger share of the non-residential PV market. Factors including co-located community solar in Minnesota, managed-growth sector and community solar projects in Massachusetts, and self-consumption developmentin California will play leading roles in fueling a reboot in large-scale demand in 2016.

But looking ahead to 2017 and beyond, it is expected that there will be a gradual reversal in theshare of 1+ MWdc development, as increased attention is paid to the non-investment-grade smallcommercial segment, which has been a secondary focus for most developers in leading statemarkets with virtual NEM or NEM rules with high system-size caps.

State Market Analysis

Figure 2.13 Top 10 Non-Residential PV State Markets from 2015: Key Installation Figures

Installations(MWdc) Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

California 68.0 53.9 124.2 87.6 67.2 109.5 133.4

Massachusetts 94.0 67.6 49.1 38.2 34.2 37.9 34.8

New York 9.7 10.8 16.5 15.2 22.7 13.2 15.6

New Jersey 30.8 10.9 19.5 13.7 6.5 10.0 17.3

Maryland 8.5 4.0 14.9 11.7 11.2 11.6 10.2

Hawaii 7.3 5.4 10.0 9.4 8.5 9.4 9.8

Connecticut 10.0 4.9 7.2 7.0 5.6 12.4 11.1

Colorado 5.4 9.1 5.0 2.6 6.4 8.2 4.2

Arizona 5.2 6.7 9.5 5.5 4.9 4.2 4.2

Texas 2.0 2.8 6.6 3.0 2.8 8.2 2.4



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Figure 2.14 Non-Residential PV Market Outlook: Top 10 State Markets Based on 2015 Installations

Top 10 Statesin 2015 State-Level Market Outlook

California

Strong: In addition to solar-friendly rate structures such as Option R in PG&E and SCE territory, the liftingof the 1 MWdc system-size cap under NEM 2.0 opens up another avenue for commercial development inCalifornia. While this will likely spur an increase in larger projects, conversations with installers suggestdevelopment will focus on systems less than 5 MWdc due to siting constraints for most customers andinterconnection costs related to Rule 21. Paired with incrementally growing demand for self-consumption projects, the outlook for 2016 looks strong and likely to be increasingly defined by large-scale projects greater than 1 MWdc.

Massachusetts

Neutral: Greenfield origination has mostly frozen, given that the NEM caps have been hit in NationalGrid territory. With the failure to extend the NEM caps before the end of the 2015 legislative session,growth in 2016 will stem from the backlog of projects that made it under the current NEM caps. AmidstNEM cap uncertainty, SREC II capacity available for non-residential projects greater than 25 KW hasbeen fully subscribed by early-stage projects. 2016 will benefit from a combination of projects underthe pre-existing NEM cap and SREC II. But beyond 2016, especially from the second half of 2017onward, the market faces long-term questions about greenfield origination opportunities for newdevelopment amidst no progress toward extending the NEM cap, particularly with post-SREC IIplanning still in its infancy.

New York

Neutral: In absolute MW terms, New York had a strong year in 2015, installing 18 MWdc more than its2014 total. However, mixed views remain on the long-term viability of the non-residential market. As ofFebruary 1, all 120 MWdc of NYSERDA’s C&I MW Block 1 is fully subscribed (Block 2 has since awardedover 15 MWdc of incentives), which bodes well for the 2016 pipeline. However, much of this has beengrandfathered in under old remote NEM rules that credited remote offtakers at a much higher rate.Conversations with developers suggest that looking forward, commercial solar economics outside of ConEd territory will be challenging, and a growing portion of development activity within the state is shiftinggears to community solar, with economics tied to higher residential retail rates.

New Jersey

Weak: After years of consistent SREC oversupply, 2015 marked the first year that non-residential PV wasoutpaced by its residential counterpart. While there may be a rebound in 2016 due to projects tenderedunder the higher SREC pricing environment, the growing disconnect between build rates and SREC pricessuggests that optimism should be restrained.

Maryland

Strong: Though the SREC market has recently seen a precipitous decline from $160/MWh to $120/MWh,the near-term outlook remains strong, even in a slightly more depressed SREC price environment. Withfavorable market design rules for community solar – projects can be sized up to 2 MWdc, with individualsubscribers accounting for up to 60% of capacity – and pending legislation to expand the current program,community solar could provide additional development avenues for commercial installers.



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Figure 2.15 Near-Term Non-Residential PV Market Outlook: Top 10 State Markets

Remaining Top 10States in 2015 State-Level Market Outlook

Hawaii

Weak: Though Hawaii’s non-residential PV market had a better year than in 2014 due to a backlog ofcommercial solar projects finally being built out, it faces the same grid saturation challenges andinterconnection bottlenecks that residential faces. In spite of that uncertainty, the military is emerging asa growing source of demand within the state, with more than 10 MW currently in development.

Connecticut

Strong: Connecticut had another record year for non-residential solar, installing 10 MWdc more than 2014.Boasting a favorable policy environment with a relatively high eligible system-size cap of 2 MWdc forstandard NEM and 3 MWdc for virtual NEM, combined with no aggregate capacity limits and a pilotcommunity solar program, Connecticut is on the list of states poised to continue to take a higher shareof the non-residential market going forward.

Colorado

Strong: Over the next six months, Colorado will continue to benefit from a large pipeline of communitysolar projects, primarily part of Xcel Energy’s Solar*Rewards program. In summer 2015, the utilityconducted a competitive solicitation for its 2015 community solar program, and developers noted a waveof unprecedented competitive pricing, including negative REC prices submitted. As a result, Xcel Energyprocured nearly 30 MWdc of additional community solar.

Arizona

Weak: Despite its inclusion in the top 10, 2015 was a fairly slow year for Arizona, as the market installedless than half of what it installed in 2014. With a value-of-solar proceeding currently underway, theoutlook is somewhat uncertain as to where net metering stands in the future. A proposal from TucsonElectric Power could potentially establish a utility-backed community solar program that, if successful,could bolster non-residential demand going forward.

TexasNeutral: Texas remains a fragmented market, with demand fueled by a patchwork of utility-ledincentive programs and one-off projects with corporate entities. Oncor, CPS and Austin Energy remainthe key hotspots of development activity, as is the case for residential solar in Texas as well.



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2.4. Non-Residential PV State Market Spotlights

California 398 MWdc installed in 2015

Up 30% over 2014

For the second consecutive year, California ranked as the largest driver of non-residential PVdemand, accounting for nearly one-third of annual installation volumes. As mentioned in previouseditions of this report, California’s non-residential demand in 2015 was largely a function of botha pipeline of projects awarded through California Solar Initiative (CSI) funding and solar-friendlyrates like Option R in PG&E and SCE territory. Developers and installers will likely subsist on thispipeline throughout 2016, but looking forward, California’s non-residential growth will be drivenby diversification of project types.

Along those lines, the recent NEM 2.0 decision resulted in a lifting of the 1 MWdc project-size capfor net-metered systems, although it still requires developers to incur additional interconnectionfees under Rule 21. Conversations with installers suggest that the industry maintains a temperedlook on development of 1+ MWdc systems, given siting challenges and uncertain project economicsrelated to additional interconnection costs.

Self-consumption projects brought on-line via non-export tariffs will also continue to be a project-type driver to watch, along with small-scale community solar. While sluggish progress on thefinalization of program rules hindered community solar development in 2015, the utilities haveofficially launched their respective community solar programs, although subscriber participationremains in question, particularly given that most customers will have to pay a premium on theirbill to sign up for community solar.

Looking beyond 2016, the policy certainty provided by the NEM 2.0 decision will be a net positivefor California’s non-residential PV market, with the market benefiting from a growing volume ofprojects greater in size than 1 MWdc. However, when the CPUC re-evaluates NEM rules again in2019, the introduction of additional charges or rollbacks to the value of solar exported to the gridpose downside risk to one of the few states with attractive economics for non-residential solarindependent of state incentive funding.

Massachusetts 145 MWdc installed in 2015

Down 35% over 2014

While Massachusetts maintained its position as a top-two state market for non-residential solar, thestate still fell on a year-over-year basis. Non-residential PV growing pains in Massachusetts were


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primarily attributed to the revised SREC incentive landscape under SREC II, which sets annual caps onmost 1+ MW virtual NEM projects (which typically fall under SREC’s managed growth sector).

In 2016, we expect Massachusetts to remain flat compared to 2015, but the market has substantialadditional demand that remains constrained due to NEM capacity limits. Back in November 2015,the state failed to pass legislation that would have extended the NEM caps, as disagreementremains over the future of net-metering compensation policies and incentive program design oncethe SREC II installation target of 1.6 GWdc is reached.

With that in mind, while 2016 will benefit from the backlog of projects eligible under the currentNEM cap, developers recently rushed a number of early-stage projects into the SREC queue (evenif on the NEM cap waiting list) after the DOER announced in early January 2016 that 370 MW ofcapacity remained under SREC II, with a 120 MW set-aside for small generators (25 kW or less). Byearly February, the Department of Energy Resources announced that it had received applicationsfor 854 MW, exceeding the large generator SREC II project cap of 660 MW.

Figure 2.16 SREC II Pipeline: Non-Residential PV Capacity in Development by Project Type

Source: Massachusetts Department of Energy Resources

This SREC application gold rush, while unprecedented, should be viewed with some skepticism, asit is almost certain that not all of the projects will come on-line; developers likely submittedapplications anticipating a longer approval process or simply rushed through any projects with aninterconnection agreement regardless of the stage of development.

Nevertheless, the above figure reveals that the near-term outlook for non-residential solar will bedriven by a diverse array of projects, beyond virtual NEM, managed-growth projects that have

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driven the majority of non-residential PV demand to date. Two project development types that areon our radar include community solar and affordable housing:

Community Shared Solar: As mentioned in previous reports, GTM Research maintains a strongoutlook for community solar in Massachusetts, a position solidified by the SREC II-generatedpipeline. However, in a reversal of the forecast in last quarter’s report, community solar hassupplanted the managed-growth sector as the primary predicted driver of non-residentialprojects, with over twice the capacity of managed growth anticipated in 2016. The sharpincrease in the sector’s attractiveness is likely due to its favorable SREC factor of 1.0, pairedwith a cap on the managed-growth sector that has incentivized many developers to transitionprojects originally intended for managed growth.

Affordable Housing: The affordable-housing subsector has likely also benefited from themanaged-growth cap, as the absence of system-size limits and a 1.0 SREC factor allowcommercial developers to easily transition these projects.

With the SREC II cap on development of projects larger than 25 kW already hit, and no progressyet made on extending the NEM caps, the long-term outlook hinges on progress made at the statelevel to roll out legislation that at the very least lifts the NEM caps, and second, decides on asuccessor incentive program after SREC II. Progress made on both NEM caps and the next stateincentive program will play critical roles in ensuring renewed growth in 2018 after the pipeline ofNEM and SREC II-eligible projects are built out.

New Jersey 48 MWdc installed in 2015

Down 54% over 2014

Despite New Jersey narrowly maintaining its position as the third-largest non-residential PV marketin Q4 2015, the market is down a considerable amount on the year and has been handily surpassedby New York, which installed nearly 20 MWdc more non-residential solar than New Jersey.

2015 marked New Jersey’s third consecutive down year – a function of the oft-discussedoversupply in its SREC market. Though SREC prices have gradually recovered – reaching a four-yearhigh in January 2016 —conversations with installers suggest that much of the low-hanging fruit hasalready been picked in the state. In considerable contrast to the SREC market in Massachusetts,which was heavily oversubscribed in January 2016 due to a small generator carve-out that placedan effective cap on commercial SREC-eligible projects, it’s clear that a considerable disconnectexists between SREC prices and the build rate in New Jersey.

Despite this disconnect, the rise in SREC prices will likely result in a rebound in non-residential installsin 2016 as the supply-demand imbalance trends toward equilibrium and the recently originatedprojects begin to come on-line. Additionally, though still in early stages, the legislation that wouldestablish a “Neighborhood Solar Energy Investment Program” should be a cause for some tempered


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optimism. If the bill moves forward, New Jersey would become one of the growing number of statesthat is diversifying the non-residential customer base through a community solar program.

Non-Residential Market Outlook

For the second straight year, non-residential solar dipped slightly on an annual basis, as majorstate markets remained constrained by sensitivity to incentive reductions, and in some cases,NEM cap uncertainty.

However, there is still the potential for a rebound in 2016. Building off a strong 2015, California isexpected to support nearly one-third of annual installations in 2016, continuing to benefit from acombination of solar-friendly rate structures and one-off large-scale self-consumption projects.Meanwhile, Massachusetts will ride off a dwindling pipeline of large-scale projects under the NEMcap. On top of that, community solar’s disappointing showing in 2015 (especially in Minnesota) is2016’s gain, as policy uncertainty and sluggish program implementation at the state level isexpected to spill over much of the forecasted demand from 2015 into 2016.

Beyond 2016, the federal ITC extension is expected to spur an additional 4 GWdc of non-residentialsolar through 2020, with non-residential solar economics more reliant on the federal ITC than isthe case in the residential space, given rate design. Long-term growth will increasingly be peggedto the sub-1 MWdc non-residential PV market, as third-party financing solutions expand into thesmall and medium-sized commercial customer bases.

Figure 2.17 Annual Non-Residential PV Installation Forecast, 2010-2021E


339

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2.5. Utility PV

Operating Capacity vs. Project PipelineKey Figures

4,150 MWdc installed in 2015, representing 6% growth over 2014

Contracted utility PV pipeline currently totals 19.8 GWdc

The utility PV market continues to serve as the bedrock driver of installation growth in the U.S. solarmarket, accounting for 57% of capacity installed in 2015. Similar to prior years, demand was packed intothe fourth quarter, with more utility PV capacity installed in Q4 2015 than the total U.S. solar installedin any prior quarter to date. This year, the Q4 boom was supported by developers in North Carolinarushing to complete projects ahead of an expiring in-state tax credit. In 2015, North Carolina becamethe first state besides California to add more than 1 GWdc of utility PV installations on an annual basis.

In 2016, the utility PV market is expected to nearly triple the number of installations in 2015. Givena significant number of late-stage projects with EPC agreements in place, in addition to the 5 GWdc

already under construction, the utility PV market is expected to experience a sizable pull-in ofdemand, despite the extension of the federal ITC.

With power-purchase agreement (PPA) prices for utility-scale solar already ranging between$35/MWh and $60/MWh, utility PV’s value proposition is evolving beyond simply meeting arenewable portfolio standard (RPS) obligation. On top of RPS-driven demand, centralized PV isproving to be an economically competitive resource to meet utilities’ peak power needs. This isespecially true in regions like Texas and the Southeast, where utilities are retiring their aging coalfleets and replacing them with utility PV alongside combined-cycle natural-gas plants.

Figure 2.18 U.S. Utility PV Pipeline


13,745 14,629

27,014

5,324

0

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Figure 2.19 Quarterly Utility PV Installations by State (MWdc), Q4 2012-Q4 2015

State 2012Q4

2013Q1

2013Q2

2013Q3

2013Q4

2014Q1

2014Q2

2014Q3

2014Q4

2015Q1

2015Q2

2015Q3

2015Q4

Arizona 212 15 69 129 77 1 - 1 101 - 6 41 58

California 331 277 390 279 973 769 553 432 874 399 541 239 678

Colorado - - - - - - - - - - - - 82

Connecticut - - - - 7 - - - 7 - - - -

Delaware 15 - - 5 2 - - - - - - - -

Florida 1 - - - - - - - - - - 8 -

Georgia - - 3 4 79 12 7 3 20 19 24 6 158

Hawaii 14 6 - - 6 - - 14 - - - 15 -

Illinois 2 - - - - 1 - - - - - 1 1

Indiana - - - 5 45 11 15 8 22 - - 6 15

Iowa - - - - - - - - - - - - -

Louisiana - - - - - - - - - - - - -

Maryland 30 - - - - - - - - - 4 13 -

Massachusetts 3 6 12 3 17 - 20 - - - - - -

Michigan - - - - - - - - - - - 1 -

Minnesota - 2 - - - - - - - - - - -

Missouri - - - - - - 10 - 6 - - 4 -

Nevada 106 38 23 171 124 91 36 26 53

New Hampshire - - - - - - - - - - - - -

New Jersey 21 8 1 11 12 10 44 6 6 16 14

New Mexico - - 3 3 20 - 65 - 2 26 1 - -

New York 9 - - - 2 2 1 6 1 1 - 11

North Carolina 66 18 53 68 137 41 34 101 213 56 91 154 814

Ohio 5 1 - - - - - - - - - - -

Oregon 6 - - - - - - - - - 9 - 4

Pennsylvania 12 - - - - - - - - - - - -

South Carolina - - - - 3 - - - - - - - -

Tennessee - - 3 1 - 0 - - 40 - 1 0 -

Texas - - - - 60 6 - 74 19 42 - 3 121

Utah - - - - - - - - - - - 23 171

Vermont 5 3 4 2 3 13 11 5 5 5 -

Virginia - - - - - - - 0 1 - - 1 -

Washington - - - - - - - - - - - - -

Washington, D.C. - - - - - - - - - - - - -

Wisconsin - - - - 1 - - - - - - - -

Other 24 - 1 - 12 1 3 0 5 - - 4 35

Total 861 328 543 540 1,444 880 719 835 1,488 644 725 565 2,215


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Trends in Utility PV Procurement

In 2012 and 2013, the U.S. utility PV market experienced two divergent trends. On one hand,installations were growing at a rapid clip, outpacing the also-growing distributed PV market. In2013, the utility market installed 2,855 MWdc of capacity and accounted for 60% of the overallsolar market – up from just 58 MWdc and 13% in 2009. But while installations expanded, theproject pipeline – defined as projects with a utility PPA or equivalent contract – began tostagnate. Virtually all utility procurement had been enabled by state RPS requirements, andutilities in key Western states including California, Arizona and Colorado had signed up enoughcapacity to meet their near-term requirements. As a result, new procurement dried up, anddevelopers were left with stranded assets.

That procurement valley resulted in hard times for a number of project developers and fosteredM&A activity that involved both companies and projects.

But 2014 deviated from a longstanding lull in procurement, as utilities ramped up procurementopportunities to optimize the number of projects eligible to come on-line before the federal ITCwas scheduled to drop at the end of 2016.

As the costs of solar further decline, utility-scale PV’s economic competitiveness continues to grow.While RPS obligations still drove the majority of utility PV installations in 2015, nearly 10 GWdc havenow been procured outside of RPS obligations based on solar’s competitiveness with natural gas andother sources of electricity generation. And in 2016, for the first time ever, GTM Research expectsthat more than 50% of annual installations will come from projects built outside of RPS obligations.

Looking ahead, the near-term utility PV procurement outlook is at a crossroads. On one hand, withthe recent extension of the federal ITC, the case for utility PV as a cost-competitive hedge againstnatural-gas price volatility has grown stronger. Conversely, legal battles about the eligibility andtimeline for rolling out the EPA’s Clean Power Plan are expected to encourage some utilities to pauseprocurement of centralized PV until they have more certainty about to what extent, if at all, they willbe faced with mandated carbon-emission reduction targets. Despite that, according to the EIA, morethan 20 GWac of additional mid-peak or peak generating capacity is expected to retire across the U.S.between 2016 and 2021. With a number of utilities with plans to retire aging coal fleets, many ofwhich are being retired ahead of schedule due to other EPA regulations, we maintain a bullish outlookon non-RPS-driven procurement over the remainder of this decade.


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Figure 2.20 Utility PV Contracted Pipeline, Q1 2013-Q4 2015


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Utility PV Market Outlook

As mentioned, a majority of the 20 GWdc utility PV project pipeline rushed through the developmentcycle in 2015, amidst uncertainty about whether the federal ITC would be extended. Given asignificant number of late-stage projects with EPC agreements in place, in addition to the more than5 GWdc already under construction, the wheels are already in motion for nearly 12 GWdc to come on-line in 2016 in spite of the extended timeline that was afforded by the ITC extension.

But even with the recent upward revision to the 2016 market outlook, as evidenced by theunprecedented contracted project pipeline, there remains strong upside potential for the utilityPV market in 2016. Conversely, the largest downside risks to the near-term utility PV outlookremain constraints on the bandwidth (in particular, labor) of engineering, procurement andconstruction providers and project buyers becoming pickier about which assets they finance overthe next three to six months.

Beyond 2016, the federal ITC extension is expected to benefit the utility PV market segment themost, increasing installations by more than 50% between 2016 and 2020 over a no-extensionscenario. In 2017, the market will benefit from a portion of the current project pipeline withflexible commercial operation dates and EPC agreements that can spill over from 2016 into nextyear. However, the pipeline of projects originated in Q1 2016 with 2017 commercial operationdates is beginning to emerge, especially in the Pacific Northwest, Texas and the Southeast.

Between 2018 and 2020, the federal ITC extension will play a critical role in expanding demand fromstate markets without RPS obligations. As the ceiling on competitive PPA pricing dips below $60/MWhand then $50/MWh, offsite corporate, PURPA-driven, and voluntary utility procurement are expectedto collectively drive a larger share of pipeline replenishment than will RPS-driven demand. However,the federal Clean Power Plan poses both upside and downside risks to the utility PV market outlook.Under original rules, states were scheduled to submit state implementation plans (SIPs) bySeptember 2016, or they could request a two-year extension to submit their SIP. But in February2016, the U.S. Supreme Court placed a stay on the implementation of the Clean Power Plan. A federalappeals court in Washington, D.C. is currently reviewing the CPP’s legality.

Assuming the CPP is not rejected by the federal appeals court, the CPP’s initial impact on utilityPV procurement will be via the Clean Energy Incentive Program, which will allow operationalsolar projects in 2020 and 2021 to generate early-adopter carbon emission credits ahead of thefirst compliance year (2022).

Given continued uncertainty surrounding the timing and scope of states’ implementation plans, themarket outlook through 2021 is primarily pegged to the roles of the aforementioned non-RPSprocurement, plus waning RPS-driven demand. In 2020 and 2021, a portion of the utility PV marketwill benefit from projects that commence construction in the year prior to claim a larger tax credit,as the federal ITC phases down from 30% to 26% in 2020 and 22% in 2021.


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Figure 2.21 Annual Utility PV Installation Forecast, 2010-2020E

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2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E 2021E

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2.6. Detailed Installation Figures by State and Market Segment (MWdc)2015 Cumulative

State Res. Non-Res. Utility Total Res. Non-Res. Utility Total

Arizona 110 19 106 234 426 308 1,286 2,020

California 1,011 398 1,858 3,266 2,709 2,048 7,230 11,987

Colorado 40 21 82 144 176 177 189 542

Connecticut 55 36 - 91 104 103 14 221

Delaware 5 5 - 10 13 24 33 70

Florida 17 16 8 41 47 78 75 200

Georgia 1 1 207 209 4 27 339 370

Hawaii 65 37 15 117 304 198 56 557

Illinois 1 7 2 11 6 21 39 65

Indiana 1 1 21 24 3 6 127 136

Iowa 2 5 - 6 9 19 - 27

Louisiana 31 0 - 32 82 2 - 84

Maryland 82 45 17 144 153 166 47 366

Massachusetts 141 145 - 286 264 696 78 1,037

Michigan 2 1 1 4 11 7 1 19

Minnesota 4 9 - 13 8 23 2 33

Missouri 7 10 4 20 45 67 19 131

Nevada 95 6 206 307 115 69 857 1,042

New Hampshire 10 5 - 15 15 8 - 23

New Jersey 91 48 42 181 317 1,032 282 1,632

New Mexico 8 5 28 41 30 50 285 365

New York 163 67 12 241 326 238 74 638

North Carolina 9 11 1,114 1,160 23 110 1,954 2,087

Ohio 2 8 - 10 9 80 24 113

Oregon 11 6 13 30 43 43 29 114

Pennsylvania 4 9 - 13 56 180 22 258

South Carolina 2 2 - 3 3 5 4 12

Tennessee 2 8 1 11 11 59 59 129

Texas 25 16 165 207 69 58 410 537

Utah 23 14 194 231 32 22 194 249

Vermont 16 13 15 43 30 24 59 113

Virginia 6 3 1 10 10 9 2 21

Washington 24 2 - 26 53 11 - 64

Washington, D.C. 3 4 - 7 10 7 - 17

Wisconsin 2 3 - 5 9 14 1 25

Other 26 28 39 93 82 123 90 295

Total 2,099 1,011 4,150 7,286 5,605 6,113 13,882 25,599


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2.7. Number of Installations by State and Market Segment2015 Cumulative

State Res. Non-Res. Utility Total Res. Non-Res. Utility Total

Arizona 12,925 187 4 13,116 58,230 2,219 107 60,556

California 159,631 3,034 73 162,738 475,036 16,614 300 491,950

Colorado 6,051 65 3 6,119 29,229 1,797 10 31,036

Connecticut 7,172 226 0 7,398 12,847 664 3 13,514

Delaware 580 26 0 606 1,917 251 4 2,172

Florida 2,462 163 2 2,627 9,177 1,538 9 10,724

Georgia 178 37 120 335 641 318 305 1,264

Hawaii 9,861 509 1 10,371 59,678 2,921 10 62,609

Illinois 248 31 3 282 1,204 236 8 1,448

Indiana 148 21 9 178 326 89 41 456

Iowa 182 132 0 314 858 641 0 1,499

Louisiana 3,597 11 0 3,608 12,919 62 0 12,981

Maryland 8,348 253 2 8,603 17,078 1,019 4 18,101

Massachusetts 19,683 455 0 20,138 38,636 2,432 28 41,096

Michigan 297 40 1 338 1,462 289 9 1,760

Minnesota 524 174 0 698 1,197 567 1 1,765

Missouri 560 339 1 900 4,006 2,544 4 6,554

Nevada 13,480 64 6 13,550 17,148 804 19 17,971

New Hampshire 1,264 76 0 1,340 1,948 192 0 2,140

New Jersey 11,461 191 8 11,660 39,371 5,880 94 45,345

New Mexico 1,541 72 4 1,617 5,929 435 28 6,392

New York 20,552 517 8 21,077 42,898 3,757 48 46,703

North Carolina 1,463 105 118 1,686 3,925 391 316 4,632

Ohio 222 33 0 255 1,194 410 6 1,610

Oregon 1,964 113 2 2,079 9,905 790 8 10,703

Pennsylvania 494 107 0 601 7,561 2,514 4 10,079

South Carolina 253 25 0 278 475 48 1 524

Tennessee 194 57 3 254 957 668 14 1,639

Texas 4,192 133 3 4,328 11,629 1,014 25 12,668

Utah 2,913 145 10 3,068 4,503 250 10 4,763

Vermont 1,440 96 5 1,541 3,876 380 25 4,281

Virginia 989 62 1 1,052 1,673 107 5 1,785

Washington 3,341 74 0 3,415 8,725 368 0 9,093

Washington, D.C. 538 35 0 573 1,326 79 0 1,405

Wisconsin 357 74 0 431 1,800 585 1 2,386

Other 3,605 359 5 3,969 14,910 1,576 29 16,515

Total 302,710 8,041 392 311,143 904,194 54,449 1,476 960,119


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2.8. Detailed Forecast TablesFigure 2.22 National PV Installation Forecast for All Market Segments (MWdc), 2010-2021E

State 2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E 2021EArizona 63 290 719 421 247 234 333 240 300 551 711 923

California 216 577 1,046 2,621 3,549 3,266 6,110 3,541 3,723 4,934 5,333 5,717

Colorado 54 92 76 56 68 144 289 191 232 334 452 630

Connecticut 5 4 11 37 56 91 133 150 191 248 305 361

Delaware 2 20 18 9 7 10 19 34 49 70 98 140

Florida 35 14 24 26 22 41 425 245 327 309 441 628

Georgia 4 10 11 91 45 209 762 159 184 161 190 226

Hawaii 16 40 109 144 107 117 278 153 194 257 289 320

Illinois 11 1 30 2 6 11 20 25 41 82 128 210

Indiana - - - 54 59 24 99 28 40 51 84 145

Iowa - 0 1 4 15 6 29 19 28 49 66 90

Louisiana - - - 1 31 32 45 41 34 43 52 91

Maryland 8 22 79 29 80 144 284 271 330 376 461 545

Massachusetts 22 31 134 240 317 286 364 391 474 571 606 636

Michigan - 3 3 2 3 4 102 27 44 124 187 289

Minnesota 2 2 4 6 6 13 295 181 231 169 279 550

Missouri - 3 7 28 73 20 38 39 54 97 106 118

Nevada 61 44 198 47 349 307 995 188 234 331 326 326

New Hampshire - - 1 2 3 15 21 31 45 64 73 85

New Jersey 132 313 419 236 240 181 291 274 348 452 625 842

New Mexico 43 123 24 45 88 41 296 187 253 383 544 781

New York 23 60 63 72 147 241 398 457 549 660 807 960

North Carolina 31 55 124 335 397 1,134 1,022 521 314 384 463 559

Ohio 19 21 25 21 15 10 15 25 43 160 169 186

Oregon 11 18 27 7 8 30 213 177 272 325 361 408

Pennsylvania 47 88 54 38 10 13 22 38 65 89 116 156

South Carolina - 3 0 4 1 3 127 201 112 92 164 319

Tennessee 3 18 27 25 44 11 17 26 52 79 133 246

Texas 23 44 51 75 129 207 1,223 531 687 971 1,420 2,097

Utah - 0 1 2 14 231 450 280 304 390 436 493

Vermont - 5 12 16 38 43 87 84 125 124 158 206

Virginia - - - 6 6 10 250 99 169 192 247 321

Washington 3 5 4 9 14 26 34 44 98 102 106 111

Washington, D.C. 1 2 1 2 3 7 15 19 26 34 42 57

Wisconsin 3 5 1 3 2 5 14 18 25 40 49 62

Other 15 13 69 47 51 93 868 1,427 1,542 1,783 1,883 2,309

Total 851 1,925 3,372 4,761 6,247 7,260 15,984 10,363 11,740 15,081 17,910 22,143


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Figure 2.23 Residential PV Installation Forecast (MWdc), 2010-2021EState 2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E 2021EArizona 32 32 62 73 94 110 79 92 104 116 124 131

California 104 128 196 410 615 1,011 1,457 1,800 2,040 2,476 2,700 2,915

Colorado 19 14 18 28 42 40 47 49 51 57 66 77

Connecticut 3 3 6 7 23 55 73 82 98 114 130 144

Delaware 1 2 1 1 2 5 10 20 29 42 57 79

Florida 3 1 5 7 10 17 34 52 74 103 136 169

Georgia 0 1 1 0 1 1 3 6 8 10 12 16

Hawaii 8 21 57 83 61 65 77 61 72 88 104 118

Illinois 0 1 1 1 1 1 4 7 11 21 31 47

Indiana - - - 0 1 1 3 8 10 13 15 18

Iowa - 0 0 2 5 2 7 9 11 14 17 21

Louisiana - - - - 30 31 42 39 30 27 20 25

Maryland 2 6 8 9 43 82 93 127 133 138 143 147

Massachusetts 2 5 15 30 67 141 188 211 231 250 267 281

Michigan - 2 1 1 2 2 4 6 9 21 39 74

Minnesota 1 0 1 0 1 4 9 13 16 20 24 28

Missouri - - 3 14 20 7 13 15 17 20 22 25

Nevada 1 1 0 1 12 95 5 1 2 2 5 11

New Hampshire - - - 1 2 10 14 20 27 35 41 49

New Jersey 20 35 43 38 60 91 136 166 196 227 261 296

New Mexico 3 5 4 4 5 8 16 28 43 64 89 127

New York 12 8 15 27 89 163 244 319 367 417 463 502

North Carolina 0 2 1 2 4 9 13 22 29 36 44 55

Ohio 0 1 1 2 1 2 6 10 14 23 30 40

Oregon 4 4 6 6 7 11 23 35 41 47 53 61

Pennsylvania 14 17 7 10 2 4 9 20 39 51 65 85

South Carolina - - 0 0 1 2 5 12 18 26 36 50

Tennessee - 1 3 2 2 2 5 10 12 14 16 19

Texas 3 5 8 9 15 25 39 59 77 98 120 141

Utah - 0 0 1 8 23 25 41 51 62 73 88

Vermont - 2 2 5 6 16 25 38 49 62 76 94

Virginia - - - 2 2 6 11 18 24 30 37 45

Washington 2 3 3 8 12 24 29 34 37 39 41 44

Washington, D.C. 1 1 1 1 2 3 7 10 13 16 19 22

Wisconsin 1 2 0 1 1 2 6 10 12 13 14 16

Other 7 5 21 8 14 26 46 58 70 83 95 106

Total 246 305 494 796 1,264 2,099 2,804 3,508 4,064 4,876 5,487 6,163


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Figure 2.24 Non-Residential PV Installation Forecast (MWdc), 2010-2021EState 2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E 2021EArizona 22 76 64 58 50 19 21 23 26 32 41 50

California 90 216 307 293 307 398 416 504 545 625 670 695

Colorado 16 33 24 28 26 21 48 49 53 57 66 74

Connecticut 2 2 5 23 26 36 43 57 75 101 138 176

Delaware 2 8 2 1 5 5 9 14 20 28 41 61

Florida 5 5 14 19 12 16 19 24 32 43 59 73

Georgia 4 7 9 4 2 1 3 3 4 6 9 13

Hawaii 7 18 38 49 32 37 41 47 57 70 77 83

Illinois 0 1 4 1 5 7 16 18 20 23 27 32

Indiana - - - 3 2 1 5 11 14 20 31 48

Iowa - 0 1 2 10 5 9 10 12 15 19 24

Louisiana - - - 1 1 0 2 3 4 6 9 15

Maryland 5 16 41 20 37 45 56 73 97 117 134 115

Massachusetts 14 23 108 171 230 145 147 166 221 272 302 327

Michigan - 1 2 1 1 1 4 10 15 18 25 35

Minnesota 1 1 3 3 4 9 60 72 79 85 94 105

Missouri - 3 4 14 36 10 12 10 13 17 23 32

Nevada 5 18 7 8 19 6 11 12 15 19 25 33

New Hampshire - - 1 1 1 5 8 11 16 24 27 31

New Jersey 89 226 300 189 102 48 62 67 107 173 287 430

New Mexico 5 4 4 14 16 5 12 18 25 34 47 65

New York 10 15 34 42 49 67 101 122 158 216 303 394

North Carolina 4 26 2 57 3 11 30 10 16 25 31 36

Ohio 7 20 13 17 13 8 7 10 15 24 29 39

Oregon 5 10 11 2 2 6 11 15 20 28 33 41

Pennsylvania 32 70 30 28 8 9 13 19 21 23 26 29

South Carolina - 3 0 0 0 2 12 12 14 17 20 24

Tennessee 3 12 15 18 2 8 10 16 20 25 29 31

Texas 3 5 7 6 16 16 24 33 39 49 62 81

Utah - 0 0 2 6 14 18 25 29 33 37 44

Vermont - 3 2 2 4 13 15 22 29 38 47 59

Virginia - - - 4 2 3 12 12 16 21 27 36

Washington 0 2 1 1 2 2 6 9 12 15 19 25

Washington, D.C. 0 1 0 1 1 4 8 9 13 19 24 35

Wisconsin 2 3 1 1 1 3 7 7 8 12 15 19

Other 6 6 23 26 28 28 36 44 58 82 124 155

Total 339 835 1,075 1,110 1,061 1,011 1,314 1,568 1,917 2,410 2,978 3,565


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Figure 2.25 Utility PV Installation Forecast (MWdc), 2010-2021EState 2010 2011 2012 2013 2014 2015 2016E 2017E 2018E 2019E 2020E 2021EArizona 9 182 592 290 103 106 233 126 170 404 546 742

California 22 233 542 1,918 2,628 1,858 4,237 1,237 1,138 1,832 1,963 2,107

Colorado 19 45 34 - - 82 195 93 128 221 320 479

Connecticut - - - 7 7 - 17 11 18 33 37 42

Delaware 11 15 7 - - - - - - - -

Florida 27 8 5 - - 8 372 170 221 163 247 386

Georgia - 2 1 86 42 207 757 150 172 145 169 198

Hawaii 1 1 14 11 14 15 161 45 65 99 108 119

Illinois 10 - 26 - 1 2 - - 10 38 70 132

Indiana - - - 51 55 21 91 9 16 18 38 79

Iowa - - - - - - 13 - 5 20 30 45

Louisiana - - - - - - 1 0 0 10 23 51

Maryland - - 30 - - 17 135 71 100 121 184 283

Massachusetts 5 3 11 39 20 - 28 14 22 49 37 28

Michigan - - - - - 1 94 12 20 85 123 180

Minnesota - - - 2 - - 227 96 135 64 161 417

Missouri - - - - 16 4 13 14 24 60 60 61

Nevada 55 24 191 38 318 206 979 175 218 310 296 282

New Hampshire - - - - - - - - 3 5 5 5

New Jersey 24 52 76 9 77 42 93 40 45 52 77 116

New Mexico 35 114 15 26 67 28 268 140 185 286 408 589

New York - 37 14 2 9 12 52 16 24 26 41 64

North Carolina 26 27 121 276 390 1,114 979 488 269 323 388 468

Ohio 12 - 11 1 - - 2 5 15 113 110 107

Oregon 2 3 10 - - 13 179 127 211 249 275 306

Pennsylvania 1 - 18 - - - - - 5 15 25 42

South Carolina - 0 - 3 - - 111 177 80 49 108 245

Tennessee - 5 9 5 40 1 1 - 20 40 88 196

Texas 16 34 36 60 99 165 1,160 439 572 825 1,238 1,875

Utah - - - - - 194 407 213 225 295 325 361

Vermont - - 8 9 27 15 48 24 47 24 36 53

Virginia - - - - 1 1 227 68 130 142 184 240

Washington - - - - - - - - 50 48 45 42

Washington, D.C. - - - - - - - - - - - -

Wisconsin - - - 1 - - 1 1 5 15 20 27

Other 2 3 25 13 9 39 786 1,324 1,414 1,618 1,663 2,048

Total 267 784 1,803 2,855 3,922 4,150 11,867 5,287 5,760 7,794 9,446 12,415


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2.9. National System Pricing

National Reported System Pricing

We utilize a bottom-up modeling methodology to capture and report national average PV systempricing for the major market segments. Though we continue to solicit weighted-average systempricing directly from utility and state incentive programs, we believe that this data no longeraccurately reflects the current state of system pricing, as more systems are foregoing localincentives, and data from these sources often represents pricing quoted well prior to theinstallation and connection date.

Our bottom-up methodology is based on tracked wholesale pricing of major solar components anddata collected from interviews with major installers and supplemented by data collected fromutility and state programs.

Modeled National PV Installed Price Estimates with Component Costs

Figures reported by state and utility agencies are subject to a number of factors that renderthe analysis insufficient for determining the actual industry costs during the quarter reported.These include:

Various definitions of “cost” that may or may not be inclusive of fair market valuation andother components that do not necessarily reflect the true cost of solar installations

Dated reporting of system pricing, reflecting quotes from as much as a year prior tothe installation date

Pricing for systems installed outside of state and utility incentive programs arenot accounted for

As such, we have supplemented this reported data with more formal inquiries on system pricingwith major PV system installers and investors. With this data, we have built a bottom-up model ofresidential, non-residential rooftop, ground-mount fixed-tilt and ground-mount tracking PV systemcosts that better elucidates component and categorical costs for PV systems built during thequarter. Due to the data sources for this information, these costs are more reflective of turnkeypricing on standard systems for medium-sized and large installation and EPC firms.

Year-over-year, system pricing has fallen by 1% to 17%, depending on the market segment, withthe largest declines in the ground-mount PV space. On a quarterly basis, pricing continues to trenddownward, with some leveling-off in the residential sector due to increasing customer acquisitioncosts. In the non-residential and utility sectors, we see declines of 10% to 17%, reflecting continuedaggressive cost reductions in national system pricing on an aggregate basis. Markets with a largefootprint, such as California, continue to have a disproportionate effect on overall national averagepricing, despite individual state system prices varying by as much as 20%.


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Figure 2.26 Modeled U.S. National Average PV System Pricing by Market Segment, Q4 2014,Q3 2015, and Q4 2015

National Average Turnkey PVInstallation / EPC Price ($/Wdc) Q4 2014 Q3 2015 Q4 2015

Residential $3.54 $3.55 $3.50

Non-Residential $2.25 $2.07 $2.03

Utility Fixed Tilt $1.61 $1.38 $1.33

Utility Tracking $1.84 $1.59 $1.54

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

Q4 2014 Q3 2015 Q4 2015

Turn

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alle

d Co

sts

($/W

dc)

Residential Non-Residential Utility Fixed Tilt Utility Tracking


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Modeled National Residential PV System PricingModeled national residential PV system pricing in Q4 2015 fell just 1% relative to Q4 2014.Compared with Q3 2015, which saw a modest increase in system pricing from the previous quarter,Q4 2015 system pricing decreased by 1.5% to $3.50/Wdc. Overall, 2015 saw relatively flatresidential system pricing, with Q2 and Q4 pricing level at $3.50/Wdc.

In the past year, overall hardware pricing has fallen by 16%, falling 5% in the past quarter. The pricedecreases in the residential module and inverter markets had a significant impact on system costs– a combined $0.16/Wdc cost reduction in 2015. Similarly, from Q4 2014 to Q4 2015, pricingpressure and hardware innovation have reduced structural balance-of-system costs by 64%.However, these declines were paralleled by a 7% and 1% overall system pricing in 2015 and in Q4,respectively. The increase year-over-year and quarter-over-quarter reflects rising customeracquisition and overhead costs and static installation labor costs. Despite intense focus frominstallers and hardware manufacturers to reduce costs, installation labor remained 10% of systemscost over the past two years. Some business model advances, including implementation of smartdesign software tools and advanced data analytics, may reduce some logistics costs in the long run.However, at present, the rising investment in customer acquisition reflects the dynamic nature ofthe residential market, where competition for market share remains aggressive.

Note that large disparities in system pricing exist due to the size of projects, differences in installationcompanies, and the dynamics of local markets. In regions with high retail electricity rates, overallsystem pricing may be higher despite similar hardware costs. In terms of hardware costs, three majorfactors drive estimated differences:

Premium PV module-based systems, including high-efficiency modules, that can commanda 25% to 35% premium over standard efficiency crystalline silicon modules

Microinverters, which lead to a premium on the overall system cost due to additionalhardware costs

Structural balance-of-system requirements, especially in high-wind-zone areas or on claytile roofs, which can drive the cost of racking materials and mounting hardware up by 50%


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Figure 2.27 Modeled Residential Turnkey EPC Installed Costs with Breakdown,Q4 2014-Q4 2015

Residential Installed Costs Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015Modules $0.77 $0.75 $0.73 $0.68 $0.65

Inverter $0.30 $0.29 $0.27 $0.29 $0.27

Electrical BOS $0.19 $0.21 $0.21 $0.21 $0.21

Structural BOS $0.18 $0.14 $0.12 $0.12 $0.11

Direct Labor $0.35 $0.35 $0.35 $0.34 $0.33

Engineering and PII1 $0.26 $0.25 $0.24 $0.23 $0.23

Supply Chain, Overhead, Margin $1.49 $1.59 $1.58 $1.68 $1.70

National Average Turnkey Pricing $3.54 $3.59 $3.50 $3.55 $3.50

National Average Reported Pricing $4.61 $4.43 $4.22 $4.53 $4.30

Note: Assumes a 5-10 kWdc rooftop system, standard crystalline silicon modules, blended string, microinverterand DC optimizer

1 PII: Permitting, Interconnection, and Inspection

$3.54 $3.59 $3.50 $3.55 $3.50

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Turn

key

Inst

alle

d Co

st ($

/Wdc

)

PV Module Inverter Electrical BOSStructural BOS Direct Labor Engineering and PIISupply Chain, Overhead, Margin


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Modeled National Non-Residential PV System Pricing

In the non-residential sector, reported pricing from major EPCs, integrators and developersindicates that standard construction costs for the market within the quarter were lower than whatwas ultimately reported by state and utility agencies.

System characteristics that will drastically affect pricing, among others, include:

Geographical differences, in particular,

– Weather-related building codes (e.g., snow and wind loading)

– Labor pricing regulations (e.g., requirements for prevailing wage)

– Site specific topographical challenges (e.g. soil conditions)

System type (i.e., rooftop, carport, ground mount)

Customer type and electricity tariff structure

As with residential PV systems, we performed a bottom-up cost analysis of non-residential PV,specifically focusing on ballasted flat-roof systems. Once again, our inputs come from largerEPCs and integrators that likely have better-than-average pricing relative to the industrymean. In order to ensure our bottom-up model reflects industry trends going forward, wehave standardized around a minimalist flat-roof non-residential system, with the caveat thatcommonplace issues such as roof obstructions can significantly affect system costs. Ourbottom-up model assumes:

300 kW low-slope (“flat”) roof system

Standard multicrystalline silicon PV modules

String inverter-based design topology

Fully ballasted, aluminum-based mounting structure

Rectangular array on membrane roof

PV module and inverters reflect “factory-gate” pricing with distribution and low volumemarkups reflected in the supply chain category

Our model shows flat-roof non-residential system costs at $2.03/Wdc in Q4, representing a 2%decrease quarter-over-quarter and nearly 10% from Q4 2014. In Q4 2015, all non-residentialsystems price decreases came from hardware – total hardware costs fell 5% to $1.04/Wdc.However, we continue to note that hardware costs in non-residential systems account for justover 50% of total installed costs. Quarter-over-quarter, soft costs remained static at $0.99/Wdc.In the non-residential market, soft costs remain a challenge. Hardware costs fell 15% year-over-year, while soft costs saw a modest decrease of 6%. Soft costs can be even higher for projects inareas with strict labor requirements and particularly in jurisdictions with stringent permittingand interconnection requirements. In order to continue reducing costs, developers and EPCsare looking to squeeze additional power density for commercial sites and amortize fixed costs


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over more power output, therefore reducing costs on a dollar-per-watt and dollar-per-kWhbasis. Some strategies have included:

More aggressive shading assumptions that reduce row-to-row spacing or offsets fromrooftop obstructions

East-west racking systems that can squeeze more power density out of more denselypopulated rooftops

Packaging rooftop systems with PV carports, ground-mount and other system types togenerate more overall output for the same customer

Figure 2.28 Modeled Non-Residential Turnkey System Pricing with Breakdown,Q4 2014-Q4 2015

Non-Residential Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015PV Module $0.73 $0.72 $0.70 $0.67 $0.65

PV Inverter $0.15 $0.14 $0.13 $0.13 $0.12

Electrical BOS $0.14 $0.11 $0.11 $0.11 $0.11

Structural BOS $0.18 $0.18 $0.18 $0.18 $0.16

Direct Labor $0.22 $0.22 $0.21 $0.21 $0.21

Design, Engineering, Permitting,Interconnection $0.10 $0.11 $0.10 $0.10 $0.10

Supply Chain, Overhead, Margin $0.73 $0.71 $0.69 $0.68 $0.68

Turnkey Pricing $2.25 $2.19 $2.13 $2.07 $2.03

Reported Pricing $3.43 $3.23 $3.13 $2.69 $2.92

$2.25 $2.19 $2.13 $2.07 $2.03

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Turn

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Inst

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$/W

dc)

PV Module PV Inverter Electrical BOSStructural BOS Direct Labor Design, Engineering, PermittingSupply Chain, Overhead, Margin


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Modeled National Utility PV System PricingIn modeling our utility PV system costs, we employ the following assumptions:

10 MWdc utility system in California

Standard multicrystalline silicon PV modules

1.3 DC-to-AC ratio

Steel-based fixed-tilt system with pile-driven foundations AND horizontal single-axis tracking

Modeled costs of a fixed-tilt utility system fell to $1.33/Wdc in Q4 2015, a drop from the previousquarter’s $1.38/Wdc pricing. Hardware pricing pressure continued as the competition for newbusiness remained fierce. Hardware costs fell 4% quarter-over-quarter and a substantial 15% on ayear-over-year basis. Fixed-utility soft costs saw a decrease of 3% in Q4 2015, and 2015 saw aremarkable 37% decrease in soft costs for the year, driven by increased efficiency in installationlabor and business operations. In addition, EPCs have been reducing their margins in order to offermore competitive bids. Yet even with considerable soft-cost reductions, unlike residential and non-residential systems, fixed-tilt utility soft costs represent less than a third of total system cost. Assuch, opportunities to reduce costs will come through changes in hardware markets, technologiesand design. Though the rate of hardware cost declines may be slowing, there still are severalapproaches to reduce hardware balance-of-system costs:

1,500-volt systems that allow for 40% shorter string lengths, which reduces the number ofcombiner boxes, home-run wiring, trenching and conduit.

Higher-power three-phase string inverter products (pushing toward 50 kW to 70 kW fromtraditional 20 kW to 40 kW commercial levels), where appropriate, will eliminate DCcomponents like combiner boxes and corresponding labor costs.

String-level DC optimization can reduce inverter components and DC wiring costs.

One-axis tracking project costs fell from $1.59/Wdc in Q3 to $1.54/Wdc in Q4 – a 3.3% reduction.While fixed-tilt continues to be a popular option for certain developers and projects, trackingsystems continue to be the dominant racking technology in the utility ground-mount space.


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Figure 2.29 Modeled Utility Turnkey Fixed-Tilt PV System Pricing With Cost Breakdown,Q4 2014-Q4 2015

U.S. Fixed-Tilt PV ModeledCosts ($/Wdc) Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

PV Module $0.71 $0.70 $0.67 $0.66 $0.65

PV Inverter and AC Subsystem $0.16 $0.16 $0.14 $0.13 $0.13

DC Electrical BOS $0.09 $0.08 $0.09 $0.06 $0.06

Structural BOS $0.14 $0.14 $0.14 $0.14 $0.11

Direct Labor $0.19 $0.19 $0.14 $0.14 $0.13

Design, Engineering, Permitting $0.03 $0.03 $0.03 $0.03 $0.03

Logistics, Misc., Overheadand Margin

$0.28 $0.28 $0.26 $0.21 $0.21

Turnkey Installed Costs $1.61 $1.58 $1.49 $1.38 $1.33

$1.61 $1.58$1.49

$1.38 $1.33

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.80

$2.00

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Turn

key

Insta

lled

Costs

($/W

dc)

PV Module PV Inverter and AC SubsystemDC Electrical BOS Structural BOSDirect Labor Design, Engineering, PermittingLogistics, Misc., Overhead and Markup


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Figure 2.30 Modeled Utility Turnkey One-Axis Tracking PV System Pricing with Cost Breakdown,Q4 2014-Q4 2015

U.S. One-Axis Tracking PVModeled Costs ($/Wdc) Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

PV Module $0.71 $0.70 $0.67 $0.66 $0.65

PV Inverter and AC Subsystem $0.18 $0.16 $0.14 $0.13 $0.13

DC Electrical BOS $0.13 $0.13 $0.12 $0.10 $0.08

Structural BOS $0.23 $0.23 $0.23 $0.21 $0.20

Direct Labor $0.20 $0.20 $0.15 $0.15 $0.15

Design, Engineering,Permitting $0.05 $0.05 $0.05 $0.05 $0.04

Logistics, Misc., Overheadand Margin $0.34 $0.34 $0.32 $0.29 $0.29

Turnkey Installed Costs $1.84 $1.84 $1.69 $1.59 $1.54

$1.84 $1.80$1.69

$1.59 $1.54

$0.00

$0.25

$0.50

$0.75

$1.00

$1.25

$1.50

$1.75

$2.00

$2.25

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Turn

key

Inst

alle

d Co

sts (

$/W

dc)

PV Module PV Inverter and AC SubsystemElectrical BOS Structural BOSDirect Labor Design, Engineering, PermittingLogistics, Misc., Overhead and Markup


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National Reported System Pricing

In Q4 2015, reported residential system pricing from state and utility incentive programs averagedto $4.30/Wdc on a capacity-weighted average basis, with major state markets like California,Arizona, Massachusetts and New York reporting figures of $4.50/Wdc, $3.83/Wdc, $4.59 /Wdc and$4.12/Wdc, respectively. The lowest reported pricing came from programs in Florida ($2.75 Wdc)and the highest pricing came from New York ($4.59 /Wdc).

Figure 2.31 Reported Capacity-Weighted Average Residential System Prices, Q1 2012-Q4 2015

Tracking non-residential system pricing presents an even bigger challenge than with residentialsystems due to the large variation of system sizes, customer types, and system types within thenon-residential sector. As one might expect, a 10 kW carport system for a small elementaryschool in Arizona will have a much different price point than a 5 MW ground-mount project onabandoned land in Massachusetts. Nevertheless, in Q4 2015, reported system pricing from stateand utility incentive programs averaged to $2.92/Wdc on a capacity-weighted basis – an 8%increase from last quarter’s $2.69/Wdc.

Reported weighted average system pricing in the major non-residential markets of California andMassachusetts came in at $2.95/Wdc, and $2.56/Wdc, respectively. Florida ($2.21/Wdc),Massachusetts ($2.56/Wdc) and Colorado ($2.63/Wdc) were the lowest-priced markets, whereasArizona ($4.51/Wdc), Minnesota ($4.33/ Wdc) and Oregon ($3.56/Wdc) appeared as high-pricedmarkets. Note that in commercial markets, states with low volumes and incentive programs thatlimit the size of commercial projects will show higher-than-average commercial pricing.

$5.88$5.46

$5.23

$5.04

$4.91

$4.75

$4.74

$4.61

$4.55

$4.51

$4.52

$4.61

$4.43$4.22

$4.53$4.30

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

Q12012

Q22012

Q32012

Q42012

Q12013

Q22013

Q32013

Q42013

Q12014

Q22014

Q32014

Q42014

Q12015

Q22015

Q32015

Q42015

Repo

rted

Syst

em P

rices

($/W

dc)

Maximum Minimum National Weighted Average


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Figure 2.32 Reported Capacity-Weighted Average Non-Residential System Prices,Q1 2012-Q4 2015

Unlike pricing for residential and non-residential systems, utility system pricing is rarely reported.As a result, our national capacity-weighted average incorporates publicly reported pricing whereavailable, as well as input from utility developers and EPCs. National weighted-average systempricing for utility systems in Q4 2015 came in at $1.50/Wdc, a modest 1% decrease from Q3 2015and a year-over-year decline of 16.2%.

Figure 2.33 Capacity-Weighted Average Utility PV System Prices, Q1 2012-Q4 2015

$4.67

$4.43$4.23

$4.27

$3.96

$3.82

$4.01

$3.57

$3.70

$3.31

$3.34

$3.43

$3.23

$3.13$2.69

$2.92

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

Q1 2012 Q3 2012 Q1 2013 Q3 2013 Q1 2014 Q3 2014 Q1 2015 Q3 2015

Repo

rted

Syste

m Pr

ices (

$/W

dc)

Maximum Minimum National Weighted Average

$2.90

$2.60$2.40

$2.27$2.14$2.10$2.04$1.96

$1.85$1.81$1.88$1.79$1.72$1.65

$1.53$1.50

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

Q12012

Q22012

Q32012

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Q12013

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Q12014

Q22014

Q32014

Q42014

Q12015

Q22015

Q32015

Q42015

Estim

ated

Sys

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Pric

es ($

/Wdc


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2.10. Manufacturing

Polysilicon

The global solar polysilicon industry is highly consolidated. This applies to the U.S. as well, where therewere only three major facilities of note in 2015: Hemlock, SunEdison and REC Silicon. Together, thesethree facilities were responsible for 6,023 MT of solar polysilicon production in Q4 2015. Thisrepresented a 10 percent decrease over production in Q3 2015, and a 43 percent decrease overproduction in Q4 2014. The significant quarter-over-quarter and year-over-year decrease can beattributed to decreased utilization rates for the firms.

In January 2014, China applied final antidumping duty rates of up to 57 percent on polysiliconproduced by U.S. manufacturers. The duties are effective for five years. Following this, producerslooked to import polysilicon under so-called processing trade rules. In the case of solar, processingtrade rules enable polysilicon used in domestic manufacturing to be exempt from import duties if thefinished products – solar cells – are then exported.

In August 2014, China’s Ministry of Commerce declared that it would suspend applications from solarcompanies looking to import polysilicon under the processing trade rules. This had a disproportionateeffect on U.S. polysilicon producers, since import duties on their products are much steeper thanduties applied to polysilicon coming from other markets.

In 2016, low polysilicon selling prices and import barriers have already caused the closure of one U.S.fabrication facility (SunEdison) and a temporary halt of another (REC Silicon Moses Lake fab, withplans to resume around June 2016). Looking forward, U.S. polysilicon production growth will likely belimited due to low polysilicon prices, import tariffs, and limited sales markets outside of China.

Figure 2.34 U.S. Polysilicon Production, Q4 2014-Q4 2015

Polysilicon (Metric Tons) Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Quarterly Capacity 13,103 13,553 13,553 13,553 13,553

Production 11,918 11,317 9,091 7,600 6,845



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Wafers

A total of 7 MW of wafers were produced in the U.S. in Q4 2015, flat compared to Q3 2015.Presently, there remains only one active wafer manufacturing facility in the U.S. – SunEdison’s60 MW monocrystalline plant in Oregon. Channel checks indicate that utilization levels at thisplant have been low since 2011, and a large portion of the plant is used for R&D purposes.While SolarWorld maintains a 250 MW integrated ingot-to-module plant (also in Oregon),ingot and wafer production were discontinued, possibly permanently, in mid-2013.

U.S. wafer production will halt in 2016 as SunEdison consolidates its Oregon facility into an R&Dand technology demonstration and training center for future licensees of the company’sContinuous Czochralski Process silicon ingot technology.

Figure 2.35 U.S. Wafer Production, Q4 2014-Q4 2015

Wafer (MW) Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Quarterly Capacity 15 15 15 15 15

Production 7 5 5 7 7


Cells

Note: In this report series, thin film facilities producing modules through monolithic integration are notdefined as producing cells.

U.S. crystalline silicon cell production was 183 MW in Q4 2015, representing a 12 percent increasequarter-over-quarter and a 62 percent increase year-over-year. Total annual U.S. cell capacityincreased 39 percent year-over-year, reaching 835 MW in Q4 2015. U.S. production growth in 2015was driven by strong domestic demand. Looking forward, strong local demand will likely providean upside for additional capacity investment.

Figure 2.36 U.S. Cell Production, Q4 2014-Q4 2015

Cell (MW) Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Quarterly Capacity 144 165 171 177 183

Production 113 131 150 164 183



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Photovoltaics


Modules

U.S. PV module production grew 9 percent quarter-over-quarter and 37 percent year-over-year,reaching 375 MW in Q4 2015. The year-over-year uptick was primarily due to healthier supply-demand balance in the global market, as well as trade litigation relating to imports of Chineseand/or Taiwanese produced cells and modules, which diverted a meaningful portion of sales to thebest-positioned U.S. producers.

In terms of technology trends, the majority of modules produced in the U.S. in Q4 2015 werecrystalline silicon (58 percent). With regard to thin-film technologies, cadmium telluride (all FirstSolar) and CIGS (mostly MiaSolé and Stion) had a production share of 28 percent and 14 percent,respectively. Overall, U.S. thin-film production share stood at 42 percent, which is much higherthan the global average (estimated at 9 percent in 2015).

Figure 2.37 U.S. Module Production by Technology, Q4 2014-Q4 2015

Module (MWp)

Q1 2015 Q2 2015 Q3 2015 Q4 2015

Capacity Production Capacity Production Capacity Production Capacity Production

Crystalline Si 231 160 242 178 254 195 266 218

CdTe 100 80 101 86 103 98 105 105

CIGS 77 49 77 49 77 50 77 53

a-Si 0 0 0 0 0 0 0 0

Total 408 288 420 313 434 343 448 375



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Photovoltaics


Inverters

Year-end inverter manufacturing capacity rose in 2015 for the first time since 2012. The markethas consolidated around a limited number of strong manufacturers, ending the long trend ofstruggling vendors exiting the manufacturing market in the U.S. Facility closures were offset byincreases in capacity from foreign manufacturers aiming for growth in the U.S. market. The overallresult was a modest 8 percent increase in capacity relative to the previous year.

Annual shipments of U.S. manufactured inverters rose 23 percent in 2015, though an influx ofutility inverters from Europe and commercial string inverters from China. Continued growth ofAsian-produced microinverters and DC optimizers in the residential market have limited overallgrowth in domestic inverter production. Nearly two-thirds of the inverters installed in the U.S. in2015 were also manufactured in the United States, holding constant relative to 2014.

Figure 2.38 Annual U.S. Inverter Production Capacity (MWac), Shipments (MWac),and Installations (MWdc)

2009 2010 2011 2012 2013 2014 2015

Inverter ProductionCapacity (MWac) 769 3,508 6,627 7,932 7,432 6,576 7,096

Inverter Shipments (MWac) 271 1,087 1,737 2,699 3,577 4,201 5,155

U.S. Installations (MWdc) 435 852 1,925 3,372 4,761 6,247 7,260

0

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Quarterly Inverter Production Capacity (MWac)Inverter Shipments (MWac)U.S. Installations (MWdc)


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Photovoltaics


2.11. Component Pricing

Polysilicon, Wafers, Cells and Modules

While a tight supply-demand market environment and stronger demand pull-in helped pushwafer and cell prices up in Q4 2015, polysilicon and module prices continued to be affected byaggressive price strategies.

For polysilicon, prices fell 4% to $14.46/kg in Q4 2015. Inventory levels and aggressive end-of-year price strategies continued to affect global polysilicon prices. Average selling prices for U.S.producers were driven downward by the closure of the processing loophole in China, whichreduced U.S. producers’ addressable market.

Wafer prices were impacted by strong demand pull-in and a tighter supply environment. Thispushed wafer prices up 3% quarter-over-quarter to $0.21/W in Q4 2015.

Cells prices also saw an uptick due to demand pull-in and a tighter supply environment, withprices growing 11% quarter-over-quarter to $0.33/W in Q4 2015.

U.S. module prices are largely driven by antidumping and countervailing duties on Chinesesuppliers. In July 2015, the U.S. Department of Commerce filed its final review of the import tariffson Chinese cells into the U.S. market. The final ruling set the cumulative duty at 30.61% for mostmajor suppliers (21.70% for Yingli). During the fourth quarter, the average delivered price forChinese modules ranged from $0.63/W on the low side (corresponding to order volumes greaterthan 10 MW for less established firms) to $0.65/W on the high side (established, bankable firms;order volumes of less than 1 MW). It should be noted that there is some price risk for producersthat continue to ship all-Chinese products to the U.S. in 2016, as the tariff on Chinese cells maychange again. There is no assurance that the final decision in the case will resemble the preliminaryresults (anti-dumping duties: 4.53% to 11.47%; countervailing duties: 19.62%).

Figure 2.39 U.S. Polysilicon, Wafer, Cell, and Module Prices, Q4 2014-Q4 2015

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Polysilicon ($/kg) $21.04 $18.94 $15.53 $ 15.06 $ 14.46

Wafer ($/W) $0.22 $0.21 $0.20 $0.20 $ 0.21

Cell ($/W) $0.32 $0.31 $0.29 $0.30 $ 0.33

Module ($/W) $0.73 $0.72 $0.68 $ 0.67 $ 0.65



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Photovoltaics


Inverter Pricing

Factory-gate inverter pricing has continued to fall steadily with no suggestion of upcomingprice-pressure alleviation. Over 2015, utility inverter pricing fell most sharply; average saleprices were 29 percent lower year-over-year. Pricing will continue to be aggressive in 2016,further enabled by increased adoption of 1,500-volt inverters with higher power densities andlower per-watt costs.

Market prices for distributed solar inverters have similarly fallen. In the commercial market,growth of well-capitalized three-phase string inverter vendors with low-cost manufacturingcapabilities resulted in average prices falling 24 percent over the course of 2015. The market exitof Advanced Energy, which commanded a small premium for its products, additionallycontributed to overall average cost declines.

A majority of distributed solar inverters installed in the U.S. market are already manufactured inlow-cost regions, and as a result, vendors are increasingly focused on product simplification andintegration with additional balance-of-system components as a means of cost reduction andvalue addition. These steps most often include decreasing total part counts and integration ofDC disconnects and combiner equipment.

In Q4 2015, microinverter pricing fell most among all inverter types quarter-over-quarter, asEnphase Energy began implementation of its aggressive price-reduction strategy. Microinverterprices were down 10 percent quarter-over-quarter as a result.


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Photovoltaics


Figure 2.40 Factory-Gate PV inverter Pricing, Q4 2014-Q4 2015

National Average Pricing Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Microinverters ($/W) $0.52 $0.51 $0.47 $0.45 $0.40

Residential Inverter ($/W) $0.24 $0.24 $0.20 $0.19 $0.18

Commercial Inverter ($/W) $0.17 $0.17 $0.15 $0.15 $0.14

Utility Inverters ($/W) $0.11 $0.11 $0.10 $0.08 $0.08


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Microinverters ($/W) Residential Inverter ($/W)Commercial Inverter ($/W) Utility Inverters ($/W)


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Photovoltaics


Mounting Structure Pricing

We continue to note that factory-gate pricing for PV mounting structures differs significantlydepending on market segment, geography, configuration, layout and project size, all ofwhich complicate the calculation of an “average” cost. For example, in Q4 2015,manufacturers reported racking pricing for residential rooftop systems rang ing anywherebetween $0.08/W and $0.19/W.

For simplicity’s sake, we note that the values reported below reflect the mounting-structure-only costs of the following system types:

Residential rooftop: 5 kW to 10 kW sloped roof in California using a clamp-and-rail-based system

Commercial rooftop: 100 kW to 500 kW flat-roof ballasted system in low wind areasrequiring no additional structural support

Ground-mount fixed-tilt: 1 MW to 5 MW fixed-tilt ground-mount system in low wind areas,not including foundation structures

Ground-mount one-axis tracking: 1 MW to 5 MW horizontal single axis tracking ground-mount system in low wind areas, not including foundation structures

Even with these baselines, note that PV mounting structure procurers should consider the fullimplied cost of individual manufacturers rather than relying on quotes versus the nationalaverage. Differences in racking materials and design have varied implications for labor costs,grounding requirements and the need for additional structural support. Also note that we haverevised our historical pricing in previous quarters given significant feedback that our valuesrepresented higher than market values.


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Photovoltaics


Figure 2.41 Factory-Gate PV Racking Pricing, Q4 2014-Q4 2015

Average Price(National Aggregate)

Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015

Residential Racking ($/W) $0.18 $0.18 $0.13 $0.13 $0.11

Commercial Rooftop Racking ($/W) $0.15 $0.15 $0.12 $0.12 $0.10

Fixed-Tilt Racking ($/W) $0.14 $0.13 $0.12 $0.11 $0.10

1-Axis Tracking ($/W) $0.23 $0.23 $0.22 $0.21 $0.20

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Concentrating Solar Power


3. CONCENTRATING SOLAR POWER3.1. Introduction

In the U.S., concentrating solar thermal power saw a burst of project activity in California in the 1980sand then remained largely inactive for two decades. Several years ago, procurement of concentratingsolar projects was revitalized across the Southwest and West, primarily in California, where investor-owned utilities launched aggressive procurement plans in response to large RPS obligations.However, concentrating solar has not been immune to the turmoil of the larger solar industry, andthe past couple of years have seen a number of CSP projects shelved or delayed.

3.2. Installations and Market OutlookFigure 3.1 Concentrating Solar Installations, 2010-2015

Capacity Installedby State (MWac) 2010 2011 2012 2013 2014 2015 Cumulative

Arizona 3 - - 280 - - 283

California - - - 125 767 - 1,256

Florida 75 - - - - - 75

Hawaii - - - 5 - - 7

Nevada - - - - - 110 174

Total 77 - - 410 767 - 1,795



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Figure 3.2 Annual CSP Installations, 1982-2015


As shown in Figure 3.2, the concentrating solar industry in the U.S. was effectively dormant from1992 to 2006. In 2007, there was one project of scale: a 64 MWac trough plant in Nevada. Followingthat was the construction of several small demonstration plants for various technologies, includinga 5 MWac compact linear Fresnel reflector (CLFR) plant in California in 2008, a 5 MWac tower plantin California in 2009, and a 1 MWac micro-CSP plant in Hawaii in 2009. The 75 MWac FP&L MartinSolar plant in Indiantown, Florida came on-line in the fourth quarter of 2010.

While the 5 MWac Kalaeloa Solar One project was the only concentrating solar power project tocome on-line during the first three quarters of 2013, in Q4 the first wave of mega-scale CSP projectsbegan to come on-line, starting with Abengoa’s 280 MWac Solana Generating Station and the first125 MWac phase of NextEra’s Genesis solar project. Q1 2014 built on that momentum, with 517MWac brought on-line. This includes BrightSource Energy’s 392 MWac Ivanpah project and thesecond and final 125 MWac phase of NextEra’s Genesis solar project.


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While Q2 2014 and Q3 2014 did not see any CSP project activity, Abengoa finishedcommissioning its 250 MWac Mojave Solar project in December 2014. In turn, 2014 ranked asthe largest year ever for CSP, with 767 MWac brought on-line. In 2015, SolarReserve’s 110 MWac

Crescent Dunes project, which entered the commissioning phase in February 2014, achievedcommercial operation in November 2015.

With Crescent Dunes now on-line, near-term growth prospects for the CSP market in the U.S.are bleak. On one hand, CSP paired with storage represents an attractive generation resourcefor utilities, offering a number of ancillary and resource-adequacy benefits. However, due toextensive permitting hurdles that have confronted CSP project development timelines andfederal ITC uncertainty in 2015, developers had put their CSP pipelines on hold.

Even with the federal ITC extension, the outlook for the CSP market will depend on furtherprogress made toward mitigating early-stage development hurdles, lowering hardware costs,and strengthening the ancillary and capacity benefits provided by CSP paired with storage.


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Appendix A: Metrics and Conversions


4. APPENDIX A: METRICS AND CONVERSIONS4.1. Photovoltaics

We report PV capacity data in watts of direct current (DC) under standard test conditions (STC).This is the metric most commonly used by suppliers, developers and program administrators.However, some program administrators report data in alternating current (AC) watts, and someutility-scale systems are measured in AC watts. Given that, we assume an 87% DC-to-AC deratefactor for systems of less than 10 MWac and a 77% DC-to-AC derate factor for systems greaterthan 10 MWac based on data from existing systems, conversations with installers, and averagesfrom California Solar Initiative data.

4.2. Residential Photovoltaic SystemA residential PV installation is defined as a project in which the offtaker of the power is a single-family household. Any PV system installed on a homeowner's property that participates in a feed-in tariff program is considered residential despite the offtaker of the power being a utility.

4.3. Non-Residential Photovoltaic SystemA non-residential PV installation is defined as a project in which the offtaker of the power is neithera homeowner nor a utility. The spectrum of non-residential offtakers typically includes commercial,industrial, agricultural, school, government and nonprofit customers. Second, a "community solar"system is defined as non-residential as well. Although homeowners and apartment tenants unableto install solar are the typical subscribers to community solar systems, the fact that the system hasmultiple offtakers of power categorizes community solar as non-residential.

4.4. Utility Photovoltaic SystemA utility PV installation is a project in which the offtaker of the power is a utility or wholesale powermarket. This definition also includes any PV system installed on a non-residential customer'sproperty that participates in a feed-in tariff program, in which the system's power is sold to a utility.

4.5. Concentrating Solar PowerWe report CSP capacity data in watts of alternating current (AC), which is the metric mostcommonly used in the CSP industry. As a result, capacity comparisons for CSP and PV should notbe considered on an apples-to-apples basis.


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Appendix B: Methodology and Data Sources


5. APPENDIX B: METHODOLOGY AND DATASOURCESPlease note that data from previous quarters is sometimes updated as a result of improved orchanged historical data.

Data for this report comes from a variety of sources and differs by data item, technology, andgranularity. Below we outline our methodology and sources.

5.1. Historical InstallationsPV: Quarterly state-by-state data on PV installations is collected primarily from incentiveprogram administrators. These administrators include state agencies, utility companies, andthird-party contractors. For larger projects not included in these programs, GTM Researchmaintains a database that tracks the status of all operating and planned utility PV projects in theUnited States. In some cases, program administrators report incentive application and awarddates rather than installed dates. In these instances, we use the information that most closelyapproaches the system’s likely installed date. For annual and cumulative installations prior to2010, 2010 data for “Other States,” and smaller utilities, GTM Research also utilized datacollected by Larry Sherwood at the Interstate Renewable Energy Council (IREC).

CSP: GTM Research maintains a database that tracks the status of all operating and plannedCSP projects in the United States.

PVState incentive program administrators, utility companies, state publicutilities commissions, PUC filings, GTM Research Utility PV Project Database,Larry Sherwood/IREC

CSP GTM Research CSP Project Database, announcement tracking, state public utilitiescommissions, conversations with developers/manufacturers

5.2. Average System PricePV: Prior to Q1 2014, the methodology used to estimate average system prices was based onweighted-average system pricing received directly from utility and state incentive programs, butGTM Research and SEIA have long felt that the data was not an ideal reflection of the currentstate of system pricing, as it often represented systems quoted in quarters well prior to theinstallation and connection date, and much of the reported data was based on fair-market valueassessments for TPO systems.


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Appendix B: Methodology and Data Sources


As of Q1 2014, GTM Research and SEIA have switched to a bottom-up methodology based ontracked wholesale pricing of major solar components and data collected from major installers, withnational average pricing supplemented by data collected from utility and state programs.

PVGTM Research manufacturing facility databases, announcement monitoring,conversations with manufacturers

CSP Announcement monitoring, conversations with manufacturers

Components in the national cost breakdown categories include:

PV module: National average delivered pricing for Chinese crystalline silicon modules

PV inverters: National average factory-gate pricing with product as specified in therespective breakdown sections

Electrical balance of systems (EBOS): Includes all additional electrical components necessaryfor the system, including DC and AC wiring, system and equipment grounding, conduit,disconnects, fuses, circuit breakers, and data monitoring

Structural balance of systems (SBOS): Includes all additional equipment necessary to support thePV system structurally, including mounting systems, foundations, ballast, racking, and clamps

Direct labor: Includes all the necessary labor related to PV system installation, including sitesetup/preparation, installation, in-field logistics, and system commissioning

Engineering, design, permitting, interconnection, inspection: Includes all labor and fees notdirectly related to preparing or installing PV system, including system engineering, design,permitting inspection and fees, interconnection labor and fees, and project management

Supply chain, logistics, customer acquisition, overhead and markup: Includes all other costsdirectly associated with the project, including supply-chain costs (distribution markups,volume markups, taxes), logistics (shipping and handling), customer acquisition (direct salesand marketing, site visits), overhead (project-related office costs) and markup (margin)

5.3. Manufacturing Production and Component PricingGTM Research maintains databases of manufacturing facilities for PV and CSP components.

PVGTM Research manufacturing facility databases, announcement monitoring,conversations with manufacturers

CSP Announcement monitoring, conversations with manufacturers


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DISCLAIMER OF WARRANTY AND LIABILITYGreentech Media and SEIA have used their best efforts in collecting and preparing each report.

GTM Research, SEIA, their employees, affiliates, agents, and licensors do not warrant theaccuracy, completeness, correctness, non-infringement, merchantability, or fitness for aparticular purpose of any reports covered by this agreement. Greentech Media, SEIA, theiremployees, affiliates, agents, or licensors shall not be liable to user or any third party for lossesor injury caused in whole or part by our negligence or contingencies beyond Greentech Media’sor SEIA’s control in compiling, preparing or disseminating any report or for any decision made oraction taken by user or any third party in reliance on such information or for any consequential,special, indirect or similar damages, even if Greentech Media or SEIA was advised of thepossibility of the same. User agrees that the liability of Greentech Media, SEIA, their employees,affiliates, agents and licensors, if any, arising out of any kind of legal claim (whether in contract,tort or otherwise) in connection with its goods/services under this agreement shall not exceedthe amount you paid to Greentech Media for use of the report in question.


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U.S. SOLAR MARKET INSIGHTFull Report

2015 Year-in Review

March 2016

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