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1 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 membership@seia.org 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 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. SEIA

2 U.S. SOLAR MARKET INSIGHT Full Report 2015 Year in Review March 2016

3 Contents CONTENTS 1. Introduction In Focus: Four Predictions About U.S. Solar in Photovoltaics Residential PV Non-Residential PV Utility PV Detailed Installation Figures by State and Market Segment (MW dc) Number of Installations by State and Market Segment Detailed Forecast Tables National System Pricing Manufacturing Component Pricing Concentrating Solar Power Introduction Installations and Market Outlook Appendix A: Metrics and Conversions Photovoltaics Residential Photovoltaic System Non-Residential Photovoltaic System Utility Photovoltaic System Concentrating Solar Power Appendix B: Methodology and Data Sources Historical Installations Average System Price Manufacturing Production and Component Pricing 72 Disclaimer of Warranty and Liability...73 U.S. Solar Market Insight March

4 Contents Ownership Rights This report ("Report") and all Solar Market Insight ("SMI") TM reports are jointly owned by Greentech Media and the Solar Energy Industries Association, Inc. (jointly, "Owners") and are protected by United States copyright and trademark laws and international copyright/intellectual property laws under applicable treaties and/or conventions. Purchaser of Report or other person obtaining a copy legally ("User") agrees not to export Report into a country that does not have copyright/intellectual property 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 to use Report for research purposes only pursuant to the terms and conditions of this license. User agrees not to permit any unauthorized use, reproduction, distribution, publication or electronic transmission of any report or the information/forecasts therein without the express written permission of either Owner. User purchasing this report may make a report available to other persons from his organization at the specific physical site covered by the terms of sale, but are prohibited from distributing the report to people outside the organization, or to persons whose principal 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, noninfringement, 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 caused in whole or part by our negligence or contingencies beyond Owners' control in compiling, preparing or disseminating Report or for any decision made or action taken by User or any third party in reliance on such information or for any consequential, special, indirect or similar damages, even if one or more Owners were advised of the possibility of the same. User agrees that the liability of Owners, 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 license and sales shall not exceed the amount User paid to Owners for use of Report. U.S. Solar Market Insight March

5 About the Authors ABOUT THE AUTHORS GTM Research U.S. Research Team Cory Honeyman, Senior Solar Analyst Shayle Kann, Senior Vice President MJ Shiao, Director of Solar Research Austin Perea, Solar Analyst Jade Jones, Senior Solar Analyst Colin Smith, Solar Analyst Solar Energy Industries Association SEIA Justin Baca, Vice President of Markets & Research Shawn Rumery, Director of Research Aaron Holm, Data Engineer Katie O Brien, Research Associate U.S. Solar Market Insight March

6 Introduction 1. INTRODUCTION Figure 1.1 Annual U.S. Solar PV Installations, was a momentous year for solar power in the United States. Solar PV deployments reached an all-time high of 7,260 megawatts direct current (MWdc), up 16% over 2014 and 8.5 times the amount installed five years earlier. Total operating solar PV capacity reached 25.6 GWdc by the end of the year, with over 900,000 individual projects delivering power each day. By the the time this report is published in Q1 2016, the U.S. will be approaching its millionth solar PV installation. PV Installations (MWdc) 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,925 3,372 4,761 6,247 7,260 1, Residential Non-Residential Utility Total Installations When accounting for all projects (both distributed and centralized), solar made up 29.4% of new electric generating capacity in the U.S. in 2015, exceeding the total for natural gas for the first time. U.S. Solar Market Insight March

7 Introduction Figure 1.2 New U.S. Electricity-Generating Capacity Additions, % 90% 80% 70% 4% 3% 4% 24% 29% 41% 10% 32% 16% 36% 51% 31% 9% 4% 3% 7% 23% 10% 39% 1% 47% 41% 29.0% 27% 32% 29.4% Share of New Capacity Additions (%) 60% 50% 40% 30% 20% 10% 0% 4% 8% 9% Solar Natural Gas Coal Wind Other 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, with installations reaching 2,099 MWdc. Non-residential solar was essentially flat for the third year in a row, with 1,011 MWdc of installations. A mixture of market-specific factors and scaling challenges have plagued the sector, 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 in Even more notable than 2015 installation capacity is the current contracted project pipeline, which now exceeds 19.8 GWdc. U.S. Solar Market Insight March

8 Introduction Figure 1.3 U.S. PV Installations by Segment, ,500 4,000 Annual PV Installations (MWdc) 3,500 3,000 2,500 2,000 1,500 1, Residential Non-Residential Utility At the state level, the market remained relatively concentrated. The top 10 states accounted for 87% of all PV installations, and the top 20 states made up 96% of the market. But annual growth occurred in 24 of the 35 states we track individually, and 13 states installed over 100 MWdc of solar in 2015, up from nine in Six states (AZ, CA, MA, NV, NJ and NC) have surpassed 1 GWdc in cumulative solar capacity was also a historic year for U.S. solar policy and regulation, with a number of decisions at both 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 visibility through GTM Research estimates that this extension alone will result in more than 50% net growth in U.S. solar installations from , an additional 24 GWdc over the five-year period. As a result of this change and other market developments since December, we now anticipate that cumulative solar photovoltaic installations will reach 97 GWdc by the end of U.S. Solar Market Insight March

9 Introduction Figure 1.4 U.S. PV Installation Forecast, Pre-ITC Extension Figure 1.5 U.S. PV Installation Forecast, Current 18,000 16,000 18,000 16,000 Installed Capacity (MWdc) 14,000 12,000 10,000 8,000 6,000 4,000 2, E 2017E 2018E 2019E 2020E Residential PV Non-Residential PV Utility PV Installed Capacity (MWdc) 14,000 12,000 10,000 8,000 6,000 4,000 2, E 2017E 2018E 2019E 2020E Residential PV Non-Residential PV Utility PV At the state level, net energy metering and electricity rate design came to the forefront of regulatory debates around solar in 2015, and a number of crucial decisions were reached. In California, the Public Utilities Commission (PUC) reached a final decision on the state s next wave of net metering (dubbed NEM 2.0), which makes relatively modest modifications for solar customers including mandatory time-of-use rates and no more netting out of non-bypassable charges with solar. This ruling has largely been viewed as favorable for solar, while the opposite is true of Nevada, where the state PUC issued an order that increases customer fixed charges, lowers solar export compensation and, most controversially, applies to both existing and prospective solar customers. The Nevada decision remains in flux as this report is being published, with a number of legal 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 benefit from gigawatts of utility PV that rushed through early stages of development to ensure interconnection in 2016, in the event that the federal ITC stepped down to 10%. In turn, we forecast 16 GWdc of solar PV installations, up 119% over 2015, driven in large part by a utility PV market that will add more capacity than all three market segments combined brought on-line in U.S. Solar Market Insight March

10 Introduction 1.1. In Focus: Four Predictions About U.S. Solar in 2016 Every year, the U.S. solar market can point to a handful of market developments and policy trends that shaped the installation outlook for better or for worse. Without question, the extension of the federal ITC in December ranked as the most important policy development for U.S. solar over the past decade, let alone So with long-term certainty regarding the federal ITC, a number of state-level market drivers and risks will move to the forefront and play even larger roles in Following are four predictions about key trends at the state level that will shape the U.S. solar market outlook in Time-of-use rate structures will become the next hot topic in debates about the value of 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 solar customers, and roping in new peak demand charges and rollbacks to the value of solar exported the grid. Meanwhile, debate about the future of rate design for rooftop solar customers is just heating up with a growing number of utilities seeking to transition DG customers to time-ofuse rate structures. In 2016, this means the rooftop solar economic outlook will depend not only on favorable outcomes to NEM debates, but also on the rollout of time-of-use (TOU) rates that have peak electricity price periods that favorably align with peak periods of PV production. For example, in California, most customers that install rooftop solar when the next version of NEM takes effect will have to switch to a new rate structure called E-TOU. Meanwhile, customers who have long been on the more solar-friendly E-6 TOU rate can remain on E-6 through In turn, while net metering rules were kept relatively intact under California s new NEM 2.0 policy, there are both customer-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 2.0 and the new E-TOU rate would save 16% less on his or her annual electricity bill than would a homeowner with rooftop solar under NEM 1.0 and the more solar-friendly E-6 TOU rate. U.S. Solar Market Insight March

11 Introduction Figure 1.6 California PG&E Rooftop Solar Economics in 2017: Pre-Solar Retail Rate, Annual Savings on E-6 Under NEM 1.0, and Annual Savings on E-TOU Under NEM 2.0 $0.25 $0.223 $0.236 $0.20 $0.198 $/kwh $0.15 $0.10 $0.05 $0.00 Pre Solar Retail Rate (E-1) Solar Savings on E-6 Solar Savings on E-TOU Source: GTM Research Rate Design Model U.S. Solar Market Insight March

12 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 sluggish rollouts of certain community solar programs (i.e. California s Green Tariff Shared Renewables Program) or dragged-out debates over community solar program design (i.e., the eligibility of largescale community solar projects in Minnesota). In addition to policy-driven bottlenecks, certain states have seen slow starts to ambitious community solar pipelines due to challenges in both the subscriber acquisition process and developers and EPCs scaling the learning curve in terms of how to partner with each other in states such as Massachusetts and New York. But in 2016, we expect Colorado, Massachusetts and Minnesota collectively to drive more than 100 MWdc of community solar, supplemented by emerging demand in New York and Maryland, as well 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 being procured by retail commercial customers. A majority of that demand is coming from customers that either leverage direct-access rules in California to procure wholesale electricity outside of their utility, partner with utilities to procure offsite solar through a green tariff program, or sign financial hedge contracts (i.e., a synthetic or virtual PPA) that provides a utility-scale project with price certainty when selling power into a volatile wholesale electricity market. U.S. Solar Market Insight March

13 Introduction Figure 1.7 Retail Procurement of Centralized Solar: Operating vs. Pipeline 2,500 2,000 1,972 Capacity (MWdc) 1,500 1, Operating (MWdc) In Development (MWdc) Source: GTM Research, U.S. Utility PV Market Tracker While the transaction structures vary, the past 12 months have set the stage for commercial demand for solar in 2016 to evolve beyond traditional customer-sited net-metered solutions. With the extension of the federal ITC, 2016 marks the beginning of the utility-scale PV market being driven 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 cycle to ensure a 2016 interconnection. The biggest question mark for utility PV in 2016 is the extent to which developers can renegotiate commercial operation dates to spill ambitious pipelines over into While certain types of projects, such as those landing PPAs under Public Utility Regulatory Policies Act (PURPA) rules, will have wiggle room to spill over into 2017, most projects with engineering, procurement and construction (EPC) agreements already in place and/or rigid interconnection timelines from the utility offtaker or project financier will still come on-line in 2016, despite the fact that the federal ITC has been extended. U.S. Solar Market Insight March

14 2. PHOTOVOLTAICS Figure 2.1 Annual State PV Installation Rankings Rank Installations (MWdc) State California ,621 3,549 3,266 North Carolina ,134 Nevada Massachusetts New York Arizona Utah Georgia Texas New Jersey Maryland Colorado Hawaii Connecticut Vermont Florida New Mexico Louisiana Oregon Washington Indiana Missouri New Hampshire Pennsylvania Minnesota Illinois Tennessee Ohio Virginia Delaware Washington, D.C Iowa Wisconsin Michigan South Carolina Source: GTM Research U.S. Solar Market Insight March

15 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 feat given 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 of geographic demand diversification, with the number of 20 MWdc annual state markets for residential solar increasing threefold over the past four years. Figure 2.2 Annual Residential PV Installations vs. Number of 20 MWdc Annual State Markets 2, PV Installations (MWdc) 2,000 1,500 1, Number of States Annual Residential PV Installations 20 MW+ Annual State Markets 0 But while a growing number of state markets are picking up steam, an even larger number of states are considering reforms to net metering rules that threaten the market s ability to maintain a hockey-stick growth trajectory. Most recently, net energy metering (NEM) reforms approved in Nevada are expected to drop the state from being the fifth-largest residential PV market in 2015 (based on annual installations) to the rank of 31 st in U.S. Solar Market Insight March

16 Quarterly Installations by State Figure 2.3 Quarterly Residential PV Installations by State (MWdc), Q Q State 2012 Q Q Q Q Q Q1 Arizona California Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina Ohio Oregon Pennsylvania South Carolina Tennessee Texas Utah Vermont Virginia Washington Washington, D.C Wisconsin Other Total Q Q Q Q Q Q Q4 U.S. Solar Market Insight March

17 Trends in Third-Party Ownership Figure 2.4 Percentage of New Residential Installations Owned by a Third Party in Major State Markets, Q Q % 90% TPO Residential Market Share 80% 70% 60% 50% 40% 30% 20% 10% 0% Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q California Arizona Colorado Massachusetts New Jersey New York Nevada Q Q Q Q Q Q Q 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% Source: GTM Research Q Q Q Q Q Q Q In most mature state markets, third-party-owned (TPO) residential PV systems continue to be an attractive option for many homeowners. However, Arizona, California, Colorado and New York all experienced a declining TPO market share in By this point, almost all major TPO providers have introduced a loan product, and there are a number of new pure-play loan providers that have U.S. Solar Market Insight March

18 entered the market. Many of the new loans offered by these companies provide the same benefits as 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 or take out short-term home equity loans. California and Colorado in particular show how quickly the TPO 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 over the recent quarters, although Massachusetts did regain ground in Q New Jersey continues to see the highest share of third-party-owned systems out of all major residential markets. The volatility of SREC prices in the state may have contributed to this trend, since consumers often prefer to avoid SREC price risk, even though SREC incentives make New Jersey an attractive market for customerowned solar. In Massachusetts, national solar companies that dominate the market continue to primarily 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 s Department 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-party ownership. Most notably, Georgia in Q legalized third-party ownership, and a ballot initiative is underway to put third-party ownership of solar to a statewide vote in Florida. Legislation is also being considered in North Carolina to legalize TPO, in addition to Pennsylvania, where a bill is being considered that would introduce property-assessed clean energy (PACE) financing programs that would allow third-party leases and PPAs for eligible projects. The ascent of Nevada s residential PV market in 2015 was accompanied and partly driven by a stark increase in the share of TPO. However, given the recent NEM ruling and the resulting projected decline of the Nevada market, 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 who have gone solar thus far, leaving an enormous opportunity for growth, and no single strategy to deliver systems to residential rooftops has yet proven dominant. In the near term, we expect that TPO PV systems will continue to drive the residential market. Cash and loan deals may play a smaller role than originally forecasted given the extension of ITC, which provides more benefits for customer-owned systems. On the regulatory and legislative front, select states and utilities have designed incentive programs and issued rules that aim to ramp direct-owned residential PV systems. For example, Xcel s Solar*Rewards rebate program in Colorado offers higher incentive rates for direct-owned systems than for TPO systems; Massachusetts launched a $30 million loan program in 2015 for residential solar; and in 2014, Arizona s Department of Revenue ruled that TPO systems are no longer exempt from property taxes. For these reasons, GTM Research expects the relative share of residential TPO systems to decline in U.S. Solar Market Insight March

19 State Market Analysis Figure 2.5 Top 10 Residential PV State Markets from 2015: Key Installation Figures Installations (MWdc) Q Q Q Q Q Q Q California New York Massachusetts Arizona Nevada New Jersey Maryland Hawaii Connecticut Colorado Source: GTM Research U.S. Solar Market Insight March

20 Figure 2.6 Residential PV Market Outlook: Top 10 State Markets Based on 2015 Installations Top 10 States in 2015 State-Level Market Outlook California Strong: The CPUC s final decision regarding NEM 2.0 largely leaves the initial decision intact with retailrate remuneration for exported excess generation. The most significant revisions include non-bypassable charges levied on gross grid consumption, a one-time interconnection fee, and a mandatory, yet-to-bedetermined TOU rate schedule for all NEM 2.0 systems. While the effects of TOU rate design on residential PV remains up for debate, California remains well positioned to be one of the top 5 states for rooftop solar economics between now and New York Strong: After seeing a minor downturn in growth in Q3 2015, New York residential has regained its previous position thanks in part to a record quarter in PSEG Long Island territory. In Q4 2015, New York s rooftop solar market landed a major policy win, with the Public Service Commission lifting the aggregate capacity limits on NEM, ruling that utilities must continue to enroll PV systems under the NEM program until a value of DER process initiated by REV is complete. The PSC plans to finalize a methodology on a value-of-der tariff by the end of 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 shaping the long-term outlook. Massachusetts Neutral: In January 2016, the state s Department of Energy Resources set aside a 120 MWdc carve-out of the remaining SREC II program for systems below 25 kw due to heavy subscription by commercial developers. As such, the near-term outlook remains stable due to sufficient additional SREC II-eligible capacity. However, the outlook toward the end of 2017 into 2018 will hinge on the state legislature establishing a successor incentive program after SREC II. Such legislation, however, would come either after or in tandem with ongoing efforts to extend the net-metering cap, which has frozen a majority of new development for commercial solar. Arizona Neutral: In the second half of 2015, residential installations in Salt River Project s utility service territory experienced a stark downturn, given the rollout of new NEM rules (including a new peak demand charge for solar customers and revised compensation for solar exported to the grid). In turn, demand shifted back to Arizona Public Service (APS) territory, with the utility driving a growing share of state-wide demand, enabling Arizona s residential market to post its second-largest quarter ever in Q In 2016, the NEM debate is shifting gears to include a few other utilities, namely, Tucson Electric Power, APS and UNS. TEP and UNS are both seeking to lower NEM compensation, increase fixed charges, and add a demand 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, combined with an unprecedented provision to prohibit grandfathering in of existing solar systems, has been a devastating blow to the market. Nevada s rapid ascendency to being a top ten state market in 2015 will be short-lived due to this decision, which will severely hamper growth in 2016 and beyond as economics plummet. Major national installers have already fled the state, and we expect 93% less residential solar installations in Nevada in 2016 than previously projected. U.S. Solar Market Insight March

21 Figure 2.7 Remaining Top 10 States in 2015 Residential PV Market Outlook: Top 10 State Markets Based on 2015 Installations State-Level Market Outlook New Jersey Maryland Strong: While New Jersey s commercial market floundered in 2015, the residential market has been on an upward trajectory despite persistent SREC oversupply. As predicted, for the first time, New Jersey s residential market outpaced commercial solar by a significant margin, one that will only continue to widen. Strong: After a record year in which Maryland saw 82 MWdc of solar PV installed (almost double its 2014 total), 2015 marked its first year breaking into a top 10 state market ranking. The state s recent growth is a function of an above-average consolidated installer landscape. The long-term plans of a small number of 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 has suffered a blow with the PUC decision to lower NEM compensation down to the peak demand avoidedcost rate. While the market stayed flat in the second half of 2015, conversations with installers suggest that new sales have severely suffered as a result of the decision. While 2016 will benefit from a backlog of projects grandfathered in under old NEM rules, the tail end of the year will be supported by the first wave of projects under interim NEM rules. On one hand, the economics under interim NEM are still viable, but installers are struggling to close deals with homeowners because NEM rules in two years from now remain undetermined. Connecticut Strong: The Connecticut Green Bank s performance-based incentives (PBIs) for third-party ownership and rebates for direct ownership are expected to remain available throughout the year, before transitioning to a new PBI that is not based on ownership type. While the state is viewed as a market with a sluggish incentive approval process, national installers have achieved scale in Connecticut, bringing projects online 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, in addition to 2015 projects awarded through Xcel s Solar*Rewards incentive program. In 2016, we similarly expect the market to be driven by both a mix of 2016 incentive-funded projects and a spillover of 2015 incentive-funded projects. Another source of demand will likely also influence 2016 volumes, as we believe that the recent PUC ruling in favor of maintaining retail-rate NEM will likely inspire the first wave of non-incentive-funded, NEM-only systems coming on-line in the latter half of the year. In addition, RPS program design for community-based solar and a receptive utility in Xcel Energy may siphon some residential customers that would have enrolled in a traditional rooftop PV program. Source: GTM Research U.S. Solar Market Insight March

22 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 Q to Q primarily due to a backlog of installations from Q that were interconnected in Q growth flat-lined in Q2 before regaining steam in the second half of the year. California once again beat its own record for the most residential PV installed in a single quarter in Q4 2015, in addition to being the first state to install over a gigawatt of residential solar in a year. Though its share of quarterly installations fluctuated quarter-overquarter, California still accounted for nearly 50% of residential PV demand in the U.S in has been an eventful year for policy, as the national ITC debate has been resolved and action has shifted to state PUCs across the U.S. that are addressing vital questions regarding NEM and rate design. California has been no exception to this rule, as the state s ability to maintain its status as the top residential and commercial PV market remains dependent on the outcome of the CPUC s NEM 2.0 decision. With retail-rate compensation in place, most of the components of the initial NEM decision will be kept 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 have been introduced and will have some modest negative impacts estimates suggest ~10% on residential economics that will likely affect volumes in the second half of Non-bypassable Charges: Under previous NEM rules, certain non-bypassable charges were levied on the net kilowatt-hours consumed from the grid. NEM 2.0 stipulates that solar customers 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 are estimated to be $75 to $150. Time-of-Use Rates: The NEM 2.0 regime requires all new solar customers to be placed on a new TOU rate schedule that is yet to be released. Outside of the NEM decision, 2015 also saw the CPUC approve changes applying to all customers in which electricity rates gradually flatten from four to two tiers over the next few years. The tiered rate proposal, along with a transition to the aforementioned TOU rates (current NEM customers may stay on their existing rate plans, while NEM 2.0 customers will be required to take on TOU rates) will move customer classes to a 25% cost differential between high-usage and low-usage tiers by As the tiers flatten, the value proposition will improve for low-energy-usage U.S. Solar Market Insight March

23 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 uncertainty about the structure of the TOU schedule. Looking forward, the outlook to 2019 for residential PV in California looks fairly favorable due to a number of policy considerations that provide stability to an otherwise volatile industry. While the NEM 2.0 decision isn t the best-case scenario for solar, retaining retail-rate compensation for PV is a 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 outcome of the TOU rate schedule remains an important variable affecting medium- and long-term installation volumes. However, the outlook past 2019 looks murky, as the CPUC is set to revisit the NEM 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 national residential PV market outlook. Over a 12-month span, two key factors accelerated Nevada s transition from a niche market to a leading market. First, with sufficiently attractive economics, the market greatly benefited from the entrance of national residential solar companies, which leveraged their strong salesforces and third-party financing solutions to accelerate quarterly installation volumes. Well over 75% of annual residential installations 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 achieve near-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 cap from 3% of peak load to 235 MWdc. Even with that short-term extension, NEM applications reached the cap on August 20, 2015, well before utility projections. But in January 2016, the state PUC approved unprecedented reforms to NEM rules within the state that 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 for excess solar sold to the grid from full retail to wholesale avoided costs over the next 12 years. While the reforms themselves rank as one of the starkest reductions to rooftop solar compensation, the more unprecedented decision was to apply these reforms to customers who have already installed rooftop solar. In every other state where NEM reforms have been approved, existing solar customers have been grandfathered in under prior NEM rules indefinitely or for a certain number of years from installation date. U.S. Solar Market Insight March

24 Figure 2.8 Levelized Rooftop PV Savings: New vs. Old Nevada NEM Rules Applied to a 2016 Installation $0.300 $0.250 Levelized Solar Savings: New NEM Rules Levelized Solar Savings: Old NEM Rules $0.246 Rooftop Solar Savings ($/kwh) $0.200 $0.150 $0.100 $0.050 $0.113 $0.046 $0.051 $0.130 $0.057 $0.152 $0.063 $0.177 $0.072 $0.208 $0.081 $ % 1% 2% 3% 4% 5% Average Annual % Increase to NV Energy Revenue Requirements 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 metering webpage, net metering rates are subject to quarterly adjustments. As the above figure reveals, in 2016, customers considering rooftop solar would need a fixed PPA rate anywhere between 4 cents and 8 cents/kwh to ensure some level of savings under the revised NEM rules. As such, the recent NEM reforms essentially erase the once-bullish outlook for residential PV in Nevada, confining demand to customers willing to accept 20+ year payback periods or greater on cash 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 five years. We forecast 34% annual growth in 2016, followed by 25% growth and 3.5 GWdc installed in 2017 thanks to the extension of the federal ITC. In 2016, we expect that 16 states will each install over 20 MW dc of residential solar, four of which will add more than 100 MWdc for the second straight year (California, Massachusetts, New Jersey and New York). U.S. Solar Market Insight March

25 Through 2016, the strong near-term outlook is pegged to favorable outcomes in net-metering and rate-design debates that have allowed residential solar economics to remain unchanged or be 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. This reality is best evidenced by recently approved reforms to net metering in Nevada, which will result 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 three key trends. First, as the cost of solar continues to decline, by 2020 we expect direct-owned systems to drive a growing share of residential installations, as loan product offerings support a higher share of growth. Second, a minor but growing share of residential PV installations will be paired with storage, especially in states where reforms to net metering incentivize higher levels of self-consumption. Lastly, as states such as California, New York and Texas explore the future of DER aggregation, the next five years will shed light on the extent to which potential lost revenue from net metering reforms can be mitigated by residential (and non-residential) solar being compensated for particular grid services. Figure 2.9 Annual Residential PV Installation Forecast, E 7,000 Residential PV Installations (MWdc) 6,000 5,000 4,000 3,000 2,000 1, ,163 5,487 4,876 4,064 3,508 2,804 2,099 1, E 2017E 2018E 2019E 2020E 2021E Source: GTM Research U.S. Solar Market Insight March

26 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-residential PV market s theme of flat demand. The continued stagnation in non-residential solar demand stems from states with either weak incentive funding or constrained development opportunities for 1+ MWdc projects. Amidst sluggish demand in most major state markets, the non-residential solar market became increasingly dependent on California, which experienced growth independent of state incentive funding thanks to solar-friendly rate structures and new development opportunities for 1+ MWdc projects. Looking ahead, the 2016 rebound in non-residential PV demand will be supported by a triple-digitmegawatt pipeline of community solar projects, plus continued dependence on California to support nearly one-third of annual demand. Figure 2.10 U.S. Non-Residential PV Installations, Installations (MWdc) Source: GTM Research U.S. Solar Market Insight March

27 Quarterly Installations by State Figure 2.11 Quarterly Non-Residential PV Installations by State (MWdc), Q Q State 2012 Q Q Q Q Q Q1 Arizona California Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina Ohio Oregon Pennsylvania South Carolina Tennessee Texas Utah Vermont Virginia Washington Washington, D.C Wisconsin Other Total Q Q Q Q Q Q Q4 U.S. Solar Market Insight March

28 Non-Residential Market Trends: Large-Scale C&I Procurement Despite the tremendous growth of available capital for non-residential solar projects over the last five years, financing and developing small to mid-sized projects has often proven to be prohibitively difficult. Some of the most prominent problems include lack of standardization (e.g., varying contract terms, power purchasers that lack credit ratings or easily assessed creditworthiness, and onerous site-specific project requirements) and relatively high costs (the transaction costs of smaller commercial projects are often comparable to those for much larger deals, but lack the benefit of scale). These difficulties have generally led developers to focus their attention on larger commercial 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 MW dc in size, jumping to approximately 60% of annual installed capacity. On one hand, the uptick in market share for small and medium-sized commercial solar systems has been driven by increased demand in California, where solar-friendly rate structures with expanded or lifted customer participation caps have spurred growth independent of state incentive funding. And since the NEM system-size cap under current NEM rules is set at 1 MWac, the market s growth is primarily driven by sub-1 MWdc project development. Figure % National Non-Residential PV Installations by System Size Share of Non-Residential Installed Capacity (%) 90% 80% 70% 60% 50% 40% 30% 20% 10% 27% 73% 37% 34% 63% 66% 43% 57% 51% 49% 40% 60% 0% Sub 1 MW 1 MW+ Source: GTM Research U.S. Solar Market Insight March

29 In 2016, however, we expect the 1+ MWdc segment to account for a larger share of the nonresidential PV market. Factors including co-located community solar in Minnesota, managedgrowth sector and community solar projects in Massachusetts, and self-consumption development in California will play leading roles in fueling a reboot in large-scale demand in But looking ahead to 2017 and beyond, it is expected that there will be a gradual reversal in the share of 1+ MWdc development, as increased attention is paid to the non-investment-grade small commercial segment, which has been a secondary focus for most developers in leading state markets 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) Q Q Q Q Q Q Q California Massachusetts New York New Jersey Maryland Hawaii Connecticut Colorado Arizona Texas Source: GTM Research U.S. Solar Market Insight March

30 Figure 2.14 Top 10 States in 2015 Non-Residential PV Market Outlook: Top 10 State Markets Based on 2015 Installations State-Level Market Outlook California Strong: In addition to solar-friendly rate structures such as Option R in PG&E and SCE territory, the lifting of the 1 MWdc system-size cap under NEM 2.0 opens up another avenue for commercial development in California. While this will likely spur an increase in larger projects, conversations with installers suggest development will focus on systems less than 5 MWdc due to siting constraints for most customers and interconnection costs related to Rule 21. Paired with incrementally growing demand for selfconsumption projects, the outlook for 2016 looks strong and likely to be increasingly defined by largescale projects greater than 1 MWdc. Massachusetts Neutral: Greenfield origination has mostly frozen, given that the NEM caps have been hit in National Grid 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. Amidst NEM cap uncertainty, SREC II capacity available for non-residential projects greater than 25 KW has been fully subscribed by early-stage projects will benefit from a combination of projects under the pre-existing NEM cap and SREC II. But beyond 2016, especially from the second half of 2017 onward, the market faces long-term questions about greenfield origination opportunities for new development amidst no progress toward extending the NEM cap, particularly with post-srec II planning still in its infancy. New York Neutral: In absolute MW terms, New York had a strong year in 2015, installing 18 MWdc more than its 2014 total. However, mixed views remain on the long-term viability of the non-residential market. As of February 1, all 120 MWdc of NYSERDA s C&I MW Block 1 is fully subscribed (Block 2 has since awarded over 15 MWdc of incentives), which bodes well for the 2016 pipeline. However, much of this has been grandfathered 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 Con Ed territory will be challenging, and a growing portion of development activity within the state is shifting gears 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 was outpaced by its residential counterpart. While there may be a rebound in 2016 due to projects tendered under the higher SREC pricing environment, the growing disconnect between build rates and SREC prices suggests 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. With favorable market design rules for community solar projects can be sized up to 2 MWdc, with individual subscribers 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. Source: GTM Research U.S. Solar Market Insight March

31 Figure 2.15 Near-Term Non-Residential PV Market Outlook: Top 10 State Markets Remaining Top 10 States 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 of commercial solar projects finally being built out, it faces the same grid saturation challenges and interconnection bottlenecks that residential faces. In spite of that uncertainty, the military is emerging as a growing source of demand within the state, with more than 10 MW currently in development. Connecticut Colorado Strong: Connecticut had another record year for non-residential solar, installing 10 MWdc more than Boasting a favorable policy environment with a relatively high eligible system-size cap of 2 MWdc for standard NEM and 3 MWdc for virtual NEM, combined with no aggregate capacity limits and a pilot community solar program, Connecticut is on the list of states poised to continue to take a higher share of the non-residential market going forward. Strong: Over the next six months, Colorado will continue to benefit from a large pipeline of community solar projects, primarily part of Xcel Energy s Solar*Rewards program. In summer 2015, the utility conducted a competitive solicitation for its 2015 community solar program, and developers noted a wave of unprecedented competitive pricing, including negative REC prices submitted. As a result, Xcel Energy procured 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 installed less than half of what it installed in With a value-of-solar proceeding currently underway, the outlook is somewhat uncertain as to where net metering stands in the future. A proposal from Tucson Electric Power could potentially establish a utility-backed community solar program that, if successful, could bolster non-residential demand going forward. Texas Neutral: Texas remains a fragmented market, with demand fueled by a patchwork of utility-led incentive programs and one-off projects with corporate entities. Oncor, CPS and Austin Energy remain the key hotspots of development activity, as is the case for residential solar in Texas as well. Source: GTM Research U.S. Solar Market Insight March

32 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 PV demand, accounting for nearly one-third of annual installation volumes. As mentioned in previous editions of this report, California s non-residential demand in 2015 was largely a function of both a pipeline of projects awarded through California Solar Initiative (CSI) funding and solar-friendly rates like Option R in PG&E and SCE territory. Developers and installers will likely subsist on this pipeline throughout 2016, but looking forward, California s non-residential growth will be driven by diversification of project types. Along those lines, the recent NEM 2.0 decision resulted in a lifting of the 1 MWdc project-size cap for net-metered systems, although it still requires developers to incur additional interconnection fees under Rule 21. Conversations with installers suggest that the industry maintains a tempered look on development of 1+ MWdc systems, given siting challenges and uncertain project economics related to additional interconnection costs. Self-consumption projects brought on-line via non-export tariffs will also continue to be a projecttype driver to watch, along with small-scale community solar. While sluggish progress on the finalization of program rules hindered community solar development in 2015, the utilities have officially launched their respective community solar programs, although subscriber participation remains in question, particularly given that most customers will have to pay a premium on their bill to sign up for community solar. Looking beyond 2016, the policy certainty provided by the NEM 2.0 decision will be a net positive for California s non-residential PV market, with the market benefiting from a growing volume of projects greater in size than 1 MWdc. However, when the CPUC re-evaluates NEM rules again in 2019, the introduction of additional charges or rollbacks to the value of solar exported to the grid pose downside risk to one of the few states with attractive economics for non-residential solar independent 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, the state still fell on a year-over-year basis. Non-residential PV growing pains in Massachusetts were U.S. Solar Market Insight March

33 primarily attributed to the revised SREC incentive landscape under SREC II, which sets annual caps on most 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 substantial additional 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 disagreement remains over the future of net-metering compensation policies and incentive program design once the 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 current NEM cap, developers recently rushed a number of early-stage projects into the SREC queue (even if on the NEM cap waiting list) after the DOER announced in early January 2016 that 370 MW of capacity remained under SREC II, with a 120 MW set-aside for small generators (25 kw or less). By early February, the Department of Energy Resources announced that it had received applications for 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 Community Shared Solar Managed Growth Affordable Housing Capacity (MWdc) Landfill Building Mounted Market Subsector Ground Mounted Brownfield Solar Canopy Source: Massachusetts Department of Energy Resources This SREC application gold rush, while unprecedented, should be viewed with some skepticism, as it is almost certain that not all of the projects will come on-line; developers likely submitted applications anticipating a longer approval process or simply rushed through any projects with an interconnection agreement regardless of the stage of development. Nevertheless, the above figure reveals that the near-term outlook for non-residential solar will be driven by a diverse array of projects, beyond virtual NEM, managed-growth projects that have U.S. Solar Market Insight March

34 driven the majority of non-residential PV demand to date. Two project development types that are on our radar include community solar and affordable housing: Community Shared Solar: As mentioned in previous reports, GTM Research maintains a strong outlook for community solar in Massachusetts, a position solidified by the SREC II-generated pipeline. However, in a reversal of the forecast in last quarter s report, community solar has supplanted the managed-growth sector as the primary predicted driver of non-residential projects, with over twice the capacity of managed growth anticipated in The sharp increase in the sector s attractiveness is likely due to its favorable SREC factor of 1.0, paired with a cap on the managed-growth sector that has incentivized many developers to transition projects originally intended for managed growth. Affordable Housing: The affordable-housing subsector has likely also benefited from the managed-growth cap, as the absence of system-size limits and a 1.0 SREC factor allow commercial developers to easily transition these projects. With the SREC II cap on development of projects larger than 25 kw already hit, and no progress yet made on extending the NEM caps, the long-term outlook hinges on progress made at the state level to roll out legislation that at the very least lifts the NEM caps, and second, decides on a successor incentive program after SREC II. Progress made on both NEM caps and the next state incentive program will play critical roles in ensuring renewed growth in 2018 after the pipeline of NEM 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 market in Q4 2015, the market is down a considerable amount on the year and has been handily surpassed by New York, which installed nearly 20 MWdc more non-residential solar than New Jersey marked New Jersey s third consecutive down year a function of the oft-discussed oversupply in its SREC market. Though SREC prices have gradually recovered reaching a four-year high in January 2016 conversations with installers suggest that much of the low-hanging fruit has already 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 placed an effective cap on commercial SREC-eligible projects, it s clear that a considerable disconnect exists 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 installs in 2016 as the supply-demand imbalance trends toward equilibrium and the recently originated projects begin to come on-line. Additionally, though still in early stages, the legislation that would establish a Neighborhood Solar Energy Investment Program should be a cause for some tempered U.S. Solar Market Insight March

35 optimism. If the bill moves forward, New Jersey would become one of the growing number of states that 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 major state 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 Building off a strong 2015, California is expected to support nearly one-third of annual installations in 2016, continuing to benefit from a combination 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 NEM cap. On top of that, community solar s disappointing showing in 2015 (especially in Minnesota) is 2016 s gain, as policy uncertainty and sluggish program implementation at the state level is expected to spill over much of the forecasted demand from 2015 into Beyond 2016, the federal ITC extension is expected to spur an additional 4 GWdc of non-residential solar through 2020, with non-residential solar economics more reliant on the federal ITC than is the case in the residential space, given rate design. Long-term growth will increasingly be pegged to the sub-1 MWdc non-residential PV market, as third-party financing solutions expand into the small and medium-sized commercial customer bases. Figure 2.17 Annual Non-Residential PV Installation Forecast, E 4,000 Non-Residential PV Installations (MWdc) 3,500 3,000 2,500 2,000 1,500 1, ,075 1,110 1,061 1,011 1,314 1,568 1,917 2,410 2,978 3, E 2017E 2018E 2019E 2020E 2021E Source: GTM Research U.S. Solar Market Insight March

36 2.5. Utility PV Operating Capacity vs. Project Pipeline Key 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. solar market, accounting for 57% of capacity installed in Similar to prior years, demand was packed into the fourth quarter, with more utility PV capacity installed in Q than the total U.S. solar installed in any prior quarter to date. This year, the Q4 boom was supported by developers in North Carolina rushing to complete projects ahead of an expiring in-state tax credit. In 2015, North Carolina became the 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 Given a 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 of demand, 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 a renewable portfolio standard (RPS) obligation. On top of RPS-driven demand, centralized PV is proving to be an economically competitive resource to meet utilities peak power needs. This is especially true in regions like Texas and the Southeast, where utilities are retiring their aging coal fleets and replacing them with utility PV alongside combined-cycle natural-gas plants. Figure 2.18 U.S. Utility PV Pipeline 30,000 25,000 U.S Utility Capacity (MWdc) 20,000 15,000 10,000 5,324 27,014 5,000 13,745 14,629 0 Operating Contracted (PPA Signed) Announced (Pre-Contract) Source: GTM Research, U.S. Utility PV Market Tracker In Construction U.S. Solar Market Insight March

37 Quarterly Installations by State Figure 2.19 Quarterly Utility PV Installations by State (MWdc), Q Q State 2012 Q Q Q Q Q Q1 Arizona California Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina Ohio Oregon Pennsylvania South Carolina Tennessee Texas Utah Vermont Virginia Washington Washington, D.C Wisconsin Other Total , , , Q Q Q Q Q Q Q4 U.S. Solar Market Insight March

38 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. In 2013, the utility market installed 2,855 MWdc of capacity and accounted for 60% of the overall solar market up from just 58 MWdc and 13% in But while installations expanded, the project pipeline defined as projects with a utility PPA or equivalent contract began to stagnate. Virtually all utility procurement had been enabled by state RPS requirements, and utilities in key Western states including California, Arizona and Colorado had signed up enough capacity to meet their near-term requirements. As a result, new procurement dried up, and developers were left with stranded assets. That procurement valley resulted in hard times for a number of project developers and fostered M&A activity that involved both companies and projects. But 2014 deviated from a longstanding lull in procurement, as utilities ramped up procurement opportunities to optimize the number of projects eligible to come on-line before the federal ITC was scheduled to drop at the end of 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 have now been procured outside of RPS obligations based on solar s competitiveness with natural gas and other sources of electricity generation. And in 2016, for the first time ever, GTM Research expects that 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, with the recent extension of the federal ITC, the case for utility PV as a cost-competitive hedge against natural-gas price volatility has grown stronger. Conversely, legal battles about the eligibility and timeline for rolling out the EPA s Clean Power Plan are expected to encourage some utilities to pause procurement of centralized PV until they have more certainty about to what extent, if at all, they will be faced with mandated carbon-emission reduction targets. Despite that, according to the EIA, more than 20 GWac of additional mid-peak or peak generating capacity is expected to retire across the U.S. between 2016 and With a number of utilities with plans to retire aging coal fleets, many of which are being retired ahead of schedule due to other EPA regulations, we maintain a bullish outlook on non-rps-driven procurement over the remainder of this decade. U.S. Solar Market Insight March

39 Figure 2.20 Utility PV Contracted Pipeline, Q Q Capacity (GWdc) Q Q Q Q Q Q Q Q Q Q Q Q Source: GTM Research, U.S. Utility PV Market Tracker U.S. Solar Market Insight March

40 Utility PV Market Outlook As mentioned, a majority of the 20 GWdc utility PV project pipeline rushed through the development cycle in 2015, amidst uncertainty about whether the federal ITC would be extended. Given a significant number of late-stage projects with EPC agreements in place, in addition to the more than 5 GWdc already under construction, the wheels are already in motion for nearly 12 GWdc to come online 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 the unprecedented contracted project pipeline, there remains strong upside potential for the utility PV market in Conversely, the largest downside risks to the near-term utility PV outlook remain constraints on the bandwidth (in particular, labor) of engineering, procurement and construction providers and project buyers becoming pickier about which assets they finance over the next three to six months. Beyond 2016, the federal ITC extension is expected to benefit the utility PV market segment the most, increasing installations by more than 50% between 2016 and 2020 over a no-extension scenario. In 2017, the market will benefit from a portion of the current project pipeline with flexible commercial operation dates and EPC agreements that can spill over from 2016 into next year. However, the pipeline of projects originated in Q with 2017 commercial operation dates 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 from state markets without RPS obligations. As the ceiling on competitive PPA pricing dips below $60/MWh and then $50/MWh, offsite corporate, PURPA-driven, and voluntary utility procurement are expected to 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) by September 2016, or they could request a two-year extension to submit their SIP. But in February 2016, the U.S. Supreme Court placed a stay on the implementation of the Clean Power Plan. A federal appeals 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 utility PV procurement will be via the Clean Energy Incentive Program, which will allow operational solar projects in 2020 and 2021 to generate early-adopter carbon emission credits ahead of the first compliance year (2022). Given continued uncertainty surrounding the timing and scope of states implementation plans, the market outlook through 2021 is primarily pegged to the roles of the aforementioned non-rps procurement, plus waning RPS-driven demand. In 2020 and 2021, a portion of the utility PV market will 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 U.S. Solar Market Insight March

41 Figure 2.21 Annual Utility PV Installation Forecast, E 14,000 11,867 12,415 Utility PV Installations (MWdc) 12,000 10,000 8,000 6,000 4,000 2, ,803 2,855 3,922 4,150 5,287 5,760 7,794 9, E 2017E 2018E 2019E 2020E 2021E U.S. Solar Market Insight March

42 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 ,286 2,020 California 1, ,858 3,266 2,709 2,048 7,230 11,987 Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts ,037 Michigan Minnesota Missouri Nevada ,042 New Hampshire New Jersey , ,632 New Mexico New York North Carolina ,114 1, ,954 2,087 Ohio Oregon Pennsylvania South Carolina Tennessee Texas Utah Vermont Virginia Washington Washington, D.C Wisconsin Other Total 2,099 1,011 4,150 7,286 5,605 6,113 13,882 25,599 U.S. Solar Market Insight March

43 2.7. Number of Installations by State and Market Segment 2015 Cumulative State Res. Non-Res. Utility Total Res. Non-Res. Utility Total Arizona 12, ,116 58,230 2, ,556 California 159,631 3, , ,036 16, ,950 Colorado 6, ,119 29,229 1, ,036 Connecticut 7, ,398 12, ,514 Delaware , ,172 Florida 2, ,627 9,177 1, ,724 Georgia ,264 Hawaii 9, ,371 59,678 2, ,609 Illinois , ,448 Indiana Iowa ,499 Louisiana 3, ,608 12, ,981 Maryland 8, ,603 17,078 1, ,101 Massachusetts 19, ,138 38,636 2, ,096 Michigan , ,760 Minnesota , ,765 Missouri ,006 2, ,554 Nevada 13, ,550 17, ,971 New Hampshire 1, ,340 1, ,140 New Jersey 11, ,660 39,371 5, ,345 New Mexico 1, ,617 5, ,392 New York 20, ,077 42,898 3, ,703 North Carolina 1, ,686 3, ,632 Ohio , ,610 Oregon 1, ,079 9, ,703 Pennsylvania ,561 2, ,079 South Carolina Tennessee ,639 Texas 4, ,328 11,629 1, ,668 Utah 2, ,068 4, ,763 Vermont 1, ,541 3, ,281 Virginia ,052 1, ,785 Washington 3, ,415 8, ,093 Washington, D.C , ,405 Wisconsin , ,386 Other 3, ,969 14,910 1, ,515 Total 302,710 8, , ,194 54,449 1, ,119 U.S. Solar Market Insight March

44 2.8. Detailed Forecast Tables Figure 2.22 National PV Installation Forecast for All Market Segments (MWdc), E State E 2017E 2018E 2019E 2020E 2021E Arizona California ,046 2,621 3,549 3,266 6,110 3,541 3,723 4,934 5,333 5,717 Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina ,134 1, Ohio Oregon Pennsylvania South Carolina Tennessee Texas , ,420 2,097 Utah Vermont Virginia Washington Washington, D.C Wisconsin Other ,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 U.S. Solar Market Insight March

45 Figure 2.23 Residential PV Installation Forecast (MWdc), E State E 2017E 2018E 2019E 2020E 2021E Arizona California ,011 1,457 1,800 2,040 2,476 2,700 2,915 Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina Ohio Oregon Pennsylvania South Carolina Tennessee Texas Utah Vermont Virginia Washington Washington, D.C Wisconsin Other Total ,264 2,099 2,804 3,508 4,064 4,876 5,487 6,163 U.S. Solar Market Insight March

46 Figure 2.24 Non-Residential PV Installation Forecast (MWdc), E State E 2017E 2018E 2019E 2020E 2021E Arizona California Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina Ohio Oregon Pennsylvania South Carolina Tennessee Texas Utah Vermont Virginia Washington Washington, D.C Wisconsin Other Total ,075 1,110 1,061 1,011 1,314 1,568 1,917 2,410 2,978 3,565 U.S. Solar Market Insight March

47 Figure 2.25 Utility PV Installation Forecast (MWdc), E State E 2017E 2018E 2019E 2020E 2021E Arizona California ,918 2,628 1,858 4,237 1,237 1,138 1,832 1,963 2,107 Colorado Connecticut Delaware Florida Georgia Hawaii Illinois Indiana Iowa Louisiana Maryland Massachusetts Michigan Minnesota Missouri Nevada New Hampshire New Jersey New Mexico New York North Carolina , Ohio Oregon Pennsylvania South Carolina Tennessee Texas , ,238 1,875 Utah Vermont Virginia Washington Washington, D.C Wisconsin Other ,324 1,414 1,618 1,663 2,048 Total ,803 2,855 3,922 4,150 11,867 5,287 5,760 7,794 9,446 12,415 U.S. Solar Market Insight March

48 2.9. National System Pricing National Reported System Pricing We utilize a bottom-up modeling methodology to capture and report national average PV system pricing for the major market segments. Though we continue to solicit weighted-average system pricing directly from utility and state incentive programs, we believe that this data no longer accurately reflects the current state of system pricing, as more systems are foregoing local incentives, and data from these sources often represents pricing quoted well prior to the installation and connection date. Our bottom-up methodology is based on tracked wholesale pricing of major solar components and data collected from interviews with major installers and supplemented by data collected from utility 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 render the 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 and other 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 to the installation date Pricing for systems installed outside of state and utility incentive programs are not accounted for As such, we have supplemented this reported data with more formal inquiries on system pricing with major PV system installers and investors. With this data, we have built a bottom-up model of residential, non-residential rooftop, ground-mount fixed-tilt and ground-mount tracking PV system costs that better elucidates component and categorical costs for PV systems built during the quarter. Due to the data sources for this information, these costs are more reflective of turnkey pricing 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, with the largest declines in the ground-mount PV space. On a quarterly basis, pricing continues to trend downward, with some leveling-off in the residential sector due to increasing customer acquisition costs. In the non-residential and utility sectors, we see declines of 10% to 17%, reflecting continued aggressive cost reductions in national system pricing on an aggregate basis. Markets with a large footprint, such as California, continue to have a disproportionate effect on overall national average pricing, despite individual state system prices varying by as much as 20%. U.S. Solar Market Insight March

49 Figure 2.26 Modeled U.S. National Average PV System Pricing by Market Segment, Q4 2014, Q3 2015, and Q $4.00 $3.50 $3.00 Turnkey Installed Costs ($/Wdc) $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Q Q Q Residential Non-Residential Utility Fixed Tilt Utility Tracking National Average Turnkey PV Installation / EPC Price ($/Wdc) Q Q Q 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 U.S. Solar Market Insight March

50 Modeled National Residential PV System Pricing Modeled national residential PV system pricing in Q fell just 1% relative to Q Compared with Q3 2015, which saw a modest increase in system pricing from the previous quarter, Q system pricing decreased by 1.5% to $3.50/Wdc. Overall, 2015 saw relatively flat residential 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 price decreases in the residential module and inverter markets had a significant impact on system costs a combined $0.16/Wdc cost reduction in Similarly, from Q to Q4 2015, pricing pressure 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 customer acquisition and overhead costs and static installation labor costs. Despite intense focus from installers and hardware manufacturers to reduce costs, installation labor remained 10% of systems cost over the past two years. Some business model advances, including implementation of smart design 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 of the 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 installation companies, and the dynamics of local markets. In regions with high retail electricity rates, overall system pricing may be higher despite similar hardware costs. In terms of hardware costs, three major factors drive estimated differences: Premium PV module-based systems, including high-efficiency modules, that can command a 25% to 35% premium over standard efficiency crystalline silicon modules Microinverters, which lead to a premium on the overall system cost due to additional hardware costs Structural balance-of-system requirements, especially in high-wind-zone areas or on clay tile roofs, which can drive the cost of racking materials and mounting hardware up by 50% U.S. Solar Market Insight March

51 Figure 2.27 Modeled Residential Turnkey EPC Installed Costs with Breakdown, Q Q $4.00 $3.50 $3.54 $3.59 $3.50 $3.55 $3.50 Turnkey Installed Cost ($/Wdc) $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Residential Installed Costs Q Q Q Q Q Modules $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 PII 1 $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, microinverter and DC optimizer Q Q Q Q Q PV Module Inverter Electrical BOS Structural BOS Direct Labor Engineering and PII Supply Chain, Overhead, Margin 1 PII: Permitting, Interconnection, and Inspection U.S. Solar Market Insight March

52 Modeled National Non-Residential PV System Pricing In the non-residential sector, reported pricing from major EPCs, integrators and developers indicates that standard construction costs for the market within the quarter were lower than what was 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 larger EPCs and integrators that likely have better-than-average pricing relative to the industry mean. In order to ensure our bottom-up model reflects industry trends going forward, we have standardized around a minimalist flat-roof non-residential system, with the caveat that commonplace issues such as roof obstructions can significantly affect system costs. Our bottom-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 volume markups 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 Q In Q4 2015, all non-residential systems 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 just over 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-overyear, while soft costs saw a modest decrease of 6%. Soft costs can be even higher for projects in areas with strict labor requirements and particularly in jurisdictions with stringent permitting and interconnection requirements. In order to continue reducing costs, developers and EPCs are looking to squeeze additional power density for commercial sites and amortize fixed costs U.S. Solar Market Insight March

53 over more power output, therefore reducing costs on a dollar-per-watt and dollar-per-kwh basis. Some strategies have included: More aggressive shading assumptions that reduce row-to-row spacing or offsets from rooftop obstructions East-west racking systems that can squeeze more power density out of more densely populated rooftops Packaging rooftop systems with PV carports, ground-mount and other system types to generate more overall output for the same customer Figure 2.28 Modeled Non-Residential Turnkey System Pricing with Breakdown, Q Q Turnkey Installed Costs ($/Wdc) $2.50 $2.00 $1.50 $1.00 $0.50 $2.25 $2.19 $2.13 $2.07 $2.03 $0.00 Q Q Q Q Q PV Module PV Inverter Electrical BOS Structural BOS Direct Labor Design, Engineering, Permitting Supply Chain, Overhead, Margin Non-Residential Q Q Q Q Q PV 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 U.S. Solar Market Insight March

54 Modeled National Utility PV System Pricing In 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 previous quarter s $1.38/Wdc pricing. Hardware pricing pressure continued as the competition for new business remained fierce. Hardware costs fell 4% quarter-over-quarter and a substantial 15% on a year-over-year basis. Fixed-utility soft costs saw a decrease of 3% in Q4 2015, and 2015 saw a remarkable 37% decrease in soft costs for the year, driven by increased efficiency in installation labor and business operations. In addition, EPCs have been reducing their margins in order to offer more competitive bids. Yet even with considerable soft-cost reductions, unlike residential and nonresidential systems, fixed-tilt utility soft costs represent less than a third of total system cost. As such, opportunities to reduce costs will come through changes in hardware markets, technologies and design. Though the rate of hardware cost declines may be slowing, there still are several approaches to reduce hardware balance-of-system costs: 1,500-volt systems that allow for 40% shorter string lengths, which reduces the number of combiner boxes, home-run wiring, trenching and conduit. Higher-power three-phase string inverter products (pushing toward 50 kw to 70 kw from traditional 20 kw to 40 kw commercial levels), where appropriate, will eliminate DC components 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, tracking systems continue to be the dominant racking technology in the utility ground-mount space. U.S. Solar Market Insight March

55 Figure 2.29 Modeled Utility Turnkey Fixed-Tilt PV System Pricing With Cost Breakdown, Q Q $2.00 $1.80 $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $1.61 $1.58 Turnkey Installed Costs ($/Wdc) $1.49 $1.38 $1.33 $0.00 Q Q Q Q Q PV Module PV Inverter and AC Subsystem DC Electrical BOS Structural BOS Direct Labor Design, Engineering, Permitting Logistics, Misc., Overhead and Markup U.S. Fixed-Tilt PV Modeled Costs ($/Wdc) Q Q Q Q Q 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., Overhead and Margin $0.28 $0.28 $0.26 $0.21 $0.21 Turnkey Installed Costs $1.61 $1.58 $1.49 $1.38 $1.33 U.S. Solar Market Insight March

56 Figure 2.30 Modeled Utility Turnkey One-Axis Tracking PV System Pricing with Cost Breakdown, Q Q Turnkey Installed Costs ($/Wdc) $2.25 $2.00 $1.75 $1.50 $1.25 $1.00 $0.75 $0.50 $0.25 U.S. One-Axis Tracking PV Modeled Costs ($/Wdc) Q Q Q Q Q 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 Logistics, Misc., Overhead and Margin $1.84 $1.80 $1.69 $1.59 $1.54 $0.00 Q Q Q Q Q PV Module PV Inverter and AC Subsystem Electrical BOS Structural BOS Direct Labor Design, Engineering, Permitting Logistics, Misc., Overhead and Markup $0.05 $0.05 $0.05 $0.05 $0.04 $0.34 $0.34 $0.32 $0.29 $0.29 Turnkey Installed Costs $1.84 $1.84 $1.69 $1.59 $1.54 U.S. Solar Market Insight March

57 Photovoltaics National Reported System Pricing Figure 2.31 Reported Capacity-Weighted Average Residential System Prices, Q Q R FO In Q4 2015, reported residential system pricing from state and utility incentive programs averaged to $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). $10.00 N $9.00 $7.00 O D Reported System Prices ($/Wdc) LY N O TS E EN UT D N RIB PO IST ES D R T O SD N $8.00 $6.00 $5.00 $5.46 $5.88 $5.04 $5.23 $4.00 $4.75 $4.91 $4.61 $4.74 $4.51 $4.55 $4.61 $4.52 $4.22 $4.53 $4.43 $4.30 $3.00 $2.00 $1.00 $0.00 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q Maximum Minimum National Weighted Average Tracking non-residential system pricing presents an even bigger challenge than with residential systems due to the large variation of system sizes, customer types, and system types within the non-residential sector. As one might expect, a 10 kw carport system for a small elementary school in Arizona will have a much different price point than a 5 MW ground-mount project on abandoned land in Massachusetts. Nevertheless, in Q4 2015, reported system pricing from state and utility incentive programs averaged to $2.92/W dc on a capacity-weighted basis an 8% increase from last quarter s $2.69/W dc. Reported weighted average system pricing in the major non-residential markets of California and Massachusetts came in at $2.95/W dc, and $2.56/Wdc, respectively. Florida ($2.21/Wdc), Massachusetts ($2.56/W dc) and Colorado ($2.63/W dc) were the lowest-priced markets, whereas Arizona ($4.51/W dc), Minnesota ($4.33/ W dc) and Oregon ($3.56/W dc) appeared as high-priced markets. Note that in commercial markets, states with low volumes and incentive programs that limit the size of commercial projects will show higher-than-average commercial pricing. U.S. Solar Market Insight March

58 Photovoltaics Figure 2.32 Reported Capacity-Weighted Average Non-Residential System Prices, Q Q $9.00 R FO Reported System Prices ($/Wdc) $8.00 $7.00 $6.00 $5.00 $4.00 N $3.00 $4.67 LY N O TS E EN UT D N RIB PO IST ES D R T O SD N $4.23 $4.01 $3.96 $3.70 $4.43 $4.27 $3.34 $3.23 $3.82 $2.92 $3.57 $2.69 $3.31 $3.43 $3.13 $2.00 O D $1.00 $0.00 Q Q Q Q Q Q Q Q Maximum Minimum National Weighted Average 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 where available, as well as input from utility developers and EPCs. National weighted-average system pricing for utility systems in Q came in at $1.50/Wdc, a modest 1% decrease from Q and a year-over-year decline of 16.2%. Figure 2.33 Capacity-Weighted Average Utility PV System Prices, Q Q Estimated System Prices ($/Wdc) $3.50 $2.90 $3.00 $2.60 $2.40 $2.50 $2.27 $2.14$2.10 $2.04 $1.96 $1.85$1.81$1.88$1.79 $2.00 $1.72$1.65 $1.53$1.50 $1.50 $1.00 $0.50 $0.00 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q U.S. Solar Market Insight March

59 2.10. Manufacturing Polysilicon The global solar polysilicon industry is highly consolidated. This applies to the U.S. as well, where there were only three major facilities of note in 2015: Hemlock, SunEdison and REC Silicon. Together, these three facilities were responsible for 6,023 MT of solar polysilicon production in Q This represented a 10 percent decrease over production in Q3 2015, and a 43 percent decrease over production in Q The significant quarter-over-quarter and year-over-year decrease can be attributed to decreased utilization rates for the firms. In January 2014, China applied final antidumping duty rates of up to 57 percent on polysilicon produced by U.S. manufacturers. The duties are effective for five years. Following this, producers looked to import polysilicon under so-called processing trade rules. In the case of solar, processing trade rules enable polysilicon used in domestic manufacturing to be exempt from import duties if the finished products solar cells are then exported. In August 2014, China s Ministry of Commerce declared that it would suspend applications from solar companies looking to import polysilicon under the processing trade rules. This had a disproportionate effect on U.S. polysilicon producers, since import duties on their products are much steeper than duties 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, with plans to resume around June 2016). Looking forward, U.S. polysilicon production growth will likely be limited due to low polysilicon prices, import tariffs, and limited sales markets outside of China. Figure 2.34 U.S. Polysilicon Production, Q Q Polysilicon (Metric Tons) Q Q Q Q Q Quarterly Capacity 13,103 13,553 13,553 13,553 13,553 Production 11,918 11,317 9,091 7,600 6,845 Source: GTM Research U.S. Solar Market Insight March

60 Wafers A total of 7 MW of wafers were produced in the U.S. in Q4 2015, flat compared to Q Presently, there remains only one active wafer manufacturing facility in the U.S. SunEdison s 60 MW monocrystalline plant in Oregon. Channel checks indicate that utilization levels at this plant 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 U.S. wafer production will halt in 2016 as SunEdison consolidates its Oregon facility into an R&D and technology demonstration and training center for future licensees of the company s Continuous Czochralski Process silicon ingot technology. Figure 2.35 U.S. Wafer Production, Q Q Wafer (MW) Q Q Q Q Q Quarterly Capacity Production Source: GTM Research Cells Note: In this report series, thin film facilities producing modules through monolithic integration are not defined as producing cells. U.S. crystalline silicon cell production was 183 MW in Q4 2015, representing a 12 percent increase quarter-over-quarter and a 62 percent increase year-over-year. Total annual U.S. cell capacity increased 39 percent year-over-year, reaching 835 MW in Q U.S. production growth in 2015 was driven by strong domestic demand. Looking forward, strong local demand will likely provide an upside for additional capacity investment. Figure 2.36 U.S. Cell Production, Q Q Cell (MW) Q Q Q Q Q Quarterly Capacity Production Source: GTM Research U.S. Solar Market Insight March

61 Modules U.S. PV module production grew 9 percent quarter-over-quarter and 37 percent year-over-year, reaching 375 MW in Q The year-over-year uptick was primarily due to healthier supplydemand balance in the global market, as well as trade litigation relating to imports of Chinese and/or Taiwanese produced cells and modules, which diverted a meaningful portion of sales to the best-positioned U.S. producers. In terms of technology trends, the majority of modules produced in the U.S. in Q were crystalline silicon (58 percent). With regard to thin-film technologies, cadmium telluride (all First Solar) 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 higher than the global average (estimated at 9 percent in 2015). Figure 2.37 U.S. Module Production by Technology, Q Q Module (MWp) Q Q Q Q Capacity Production Capacity Production Capacity Production Capacity Production Crystalline Si CdTe CIGS a-si Total Source: GTM Research U.S. Solar Market Insight March

62 Inverters Year-end inverter manufacturing capacity rose in 2015 for the first time since The market has consolidated around a limited number of strong manufacturers, ending the long trend of struggling vendors exiting the manufacturing market in the U.S. Facility closures were offset by increases in capacity from foreign manufacturers aiming for growth in the U.S. market. The overall result 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 of utility inverters from Europe and commercial string inverters from China. Continued growth of Asian-produced microinverters and DC optimizers in the residential market have limited overall growth in domestic inverter production. Nearly two-thirds of the inverters installed in the U.S. in 2015 were also manufactured in the United States, holding constant relative to Figure 2.38 Annual U.S. Inverter Production Capacity (MWac), Shipments (MWac), and Installations (MWdc) MW 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, Quarterly Inverter Production Capacity (MWac) Inverter Shipments (MWac) U.S. Installations (MWdc) Inverter Production Capacity (MWac) ,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) ,925 3,372 4,761 6,247 7,260 U.S. Solar Market Insight March

63 2.11. Component Pricing Polysilicon, Wafers, Cells and Modules While a tight supply-demand market environment and stronger demand pull-in helped push wafer and cell prices up in Q4 2015, polysilicon and module prices continued to be affected by aggressive price strategies. For polysilicon, prices fell 4% to $14.46/kg in Q Inventory levels and aggressive end-ofyear 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, which reduced U.S. producers addressable market. Wafer prices were impacted by strong demand pull-in and a tighter supply environment. This pushed wafer prices up 3% quarter-over-quarter to $0.21/W in Q Cells prices also saw an uptick due to demand pull-in and a tighter supply environment, with prices growing 11% quarter-over-quarter to $0.33/W in Q U.S. module prices are largely driven by antidumping and countervailing duties on Chinese suppliers. In July 2015, the U.S. Department of Commerce filed its final review of the import tariffs on Chinese cells into the U.S. market. The final ruling set the cumulative duty at 30.61% for most major suppliers (21.70% for Yingli). During the fourth quarter, the average delivered price for Chinese modules ranged from $0.63/W on the low side (corresponding to order volumes greater than 10 MW for less established firms) to $0.65/W on the high side (established, bankable firms; order volumes of less than 1 MW). It should be noted that there is some price risk for producers that continue to ship all-chinese products to the U.S. in 2016, as the tariff on Chinese cells may change again. There is no assurance that the final decision in the case will resemble the preliminary results (anti-dumping duties: 4.53% to 11.47%; countervailing duties: 19.62%). Figure 2.39 U.S. Polysilicon, Wafer, Cell, and Module Prices, Q Q Q Q Q Q Q Polysilicon ($/kg) $21.04 $18.94 $15.53 $ $ 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 Source: GTM Research U.S. Solar Market Insight March

64 Inverter Pricing Factory-gate inverter pricing has continued to fall steadily with no suggestion of upcoming price-pressure alleviation. Over 2015, utility inverter pricing fell most sharply; average sale prices 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 and lower 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 manufacturing capabilities resulted in average prices falling 24 percent over the course of The market exit of Advanced Energy, which commanded a small premium for its products, additionally contributed to overall average cost declines. A majority of distributed solar inverters installed in the U.S. market are already manufactured in low-cost regions, and as a result, vendors are increasingly focused on product simplification and integration with additional balance-of-system components as a means of cost reduction and value addition. These steps most often include decreasing total part counts and integration of DC disconnects and combiner equipment. In Q4 2015, microinverter pricing fell most among all inverter types quarter-over-quarter, as Enphase Energy began implementation of its aggressive price-reduction strategy. Microinverter prices were down 10 percent quarter-over-quarter as a result. U.S. Solar Market Insight March

65 Figure 2.40 Factory-Gate PV inverter Pricing, Q Q $0.60 Factory-Gate Average Selling Price ($/Wac) $0.50 $0.40 $0.30 $0.20 $0.10 $0.00 Q Q Q Q Q National Average Pricing Q Q Q Q Q Microinverters ($/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 $0.08 Source: GTM Research Microinverters ($/W) Commercial Inverter ($/W) Residential Inverter ($/W) Utility Inverters ($/W) U.S. Solar Market Insight March

66 Mounting Structure Pricing We continue to note that factory-gate pricing for PV mounting structures differs significantly depending on market segment, geography, configuration, layout and project size, all of which complicate the calculation of an average cost. For example, in Q4 2015, manufacturers reported racking pricing for residential rooftop systems rang ing anywhere between $0.08/W and $0.19/W. For simplicity s sake, we note that the values reported below reflect the mounting-structureonly 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 areas requiring 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 groundmount system in low wind areas, not including foundation structures Even with these baselines, note that PV mounting structure procurers should consider the full implied cost of individual manufacturers rather than relying on quotes versus the national average. 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 have revised our historical pricing in previous quarters given significant feedback that our values represented higher than market values. U.S. Solar Market Insight March

67 Figure 2.41 Factory-Gate PV Racking Pricing, Q Q $0.25 Factory-Gate Average Selling Price ($/Wdc) $0.20 $0.15 $0.10 $0.05 $0.00 Q Q Q Q Q Residential Racking ($/W) Commercial Rooftop Racking ($/W) Fixed Tilt Racking ($/W) Ground Mount Tracking ($/W) Average Price (National Aggregate) Q Q Q Q Q Residential Racking ($/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 $ Axis Tracking ($/W) $0.23 $0.23 $0.22 $0.21 $0.20 U.S. Solar Market Insight March

68 Concentrating Solar Power 3. CONCENTRATING SOLAR POWER 3.1. Introduction In the U.S., concentrating solar thermal power saw a burst of project activity in California in the 1980s and then remained largely inactive for two decades. Several years ago, procurement of concentrating solar projects was revitalized across the Southwest and West, primarily in California, where investorowned 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, and the past couple of years have seen a number of CSP projects shelved or delayed Installations and Market Outlook Figure 3.1 Concentrating Solar Installations, Capacity Installed by State (MWac) Cumulative Arizona California ,256 Florida Hawaii Nevada Total ,795 Source: GTM Research, U.S. Utility PV Market Tracker U.S. Solar Market Insight March

69 Concentrating Solar Power Figure 3.2 Annual CSP Installations, Source: GTM Research, U.S. Utility PV Market Tracker As shown in Figure 3.2, the concentrating solar industry in the U.S. was effectively dormant from 1992 to In 2007, there was one project of scale: a 64 MWac trough plant in Nevada. Following that was the construction of several small demonstration plants for various technologies, including a 5 MWac compact linear Fresnel reflector (CLFR) plant in California in 2008, a 5 MWac tower plant in California in 2009, and a 1 MWac micro-csp plant in Hawaii in The 75 MWac FP&L Martin Solar plant in Indiantown, Florida came on-line in the fourth quarter of While the 5 MWac Kalaeloa Solar One project was the only concentrating solar power project to come on-line during the first three quarters of 2013, in Q4 the first wave of mega-scale CSP projects began to come on-line, starting with Abengoa s 280 MWac Solana Generating Station and the first 125 MWac phase of NextEra s Genesis solar project. Q built on that momentum, with 517 MWac brought on-line. This includes BrightSource Energy s 392 MWac Ivanpah project and the second and final 125 MWac phase of NextEra s Genesis solar project. U.S. Solar Market Insight March

70 Concentrating Solar Power While Q and Q did not see any CSP project activity, Abengoa finished commissioning its 250 MWac Mojave Solar project in December In turn, 2014 ranked as the 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, achieved commercial operation in November 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 resource for utilities, offering a number of ancillary and resource-adequacy benefits. However, due to extensive permitting hurdles that have confronted CSP project development timelines and federal 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 further progress made toward mitigating early-stage development hurdles, lowering hardware costs, and strengthening the ancillary and capacity benefits provided by CSP paired with storage. U.S. Solar Market Insight March

71 Appendix A: Metrics and Conversions 4. APPENDIX A: METRICS AND CONVERSIONS 4.1. 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 some utility-scale systems are measured in AC watts. Given that, we assume an 87% DC-to-AC derate factor for systems of less than 10 MWac and a 77% DC-to-AC derate factor for systems greater than 10 MWac based on data from existing systems, conversations with installers, and averages from California Solar Initiative data Residential Photovoltaic System A residential PV installation is defined as a project in which the offtaker of the power is a singlefamily household. Any PV system installed on a homeowner's property that participates in a feedin tariff program is considered residential despite the offtaker of the power being a utility Non-Residential Photovoltaic System A non-residential PV installation is defined as a project in which the offtaker of the power is neither a 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 unable to install solar are the typical subscribers to community solar systems, the fact that the system has multiple offtakers of power categorizes community solar as non-residential Utility Photovoltaic System A utility PV installation is a project in which the offtaker of the power is a utility or wholesale power market. This definition also includes any PV system installed on a non-residential customer's property that participates in a feed-in tariff program, in which the system's power is sold to a utility Concentrating Solar Power We report CSP capacity data in watts of alternating current (AC), which is the metric most commonly used in the CSP industry. As a result, capacity comparisons for CSP and PV should not be considered on an apples-to-apples basis. U.S. Solar Market Insight March

72 Appendix B: Methodology and Data Sources 5. APPENDIX B: METHODOLOGY AND DATA SOURCES Please note that data from previous quarters is sometimes updated as a result of improved or changed historical data. Data for this report comes from a variety of sources and differs by data item, technology, and granularity. Below we outline our methodology and sources Historical Installations PV: Quarterly state-by-state data on PV installations is collected primarily from incentive program administrators. These administrators include state agencies, utility companies, and third-party contractors. For larger projects not included in these programs, GTM Research maintains a database that tracks the status of all operating and planned utility PV projects in the United States. In some cases, program administrators report incentive application and award dates rather than installed dates. In these instances, we use the information that most closely approaches the system s likely installed date. For annual and cumulative installations prior to 2010, 2010 data for Other States, and smaller utilities, GTM Research also utilized data collected by Larry Sherwood at the Interstate Renewable Energy Council (IREC). CSP: GTM Research maintains a database that tracks the status of all operating and planned CSP projects in the United States. PV CSP State incentive program administrators, utility companies, state public utilities commissions, PUC filings, GTM Research Utility PV Project Database, Larry Sherwood/IREC GTM Research CSP Project Database, announcement tracking, state public utilities commissions, conversations with developers/manufacturers 5.2. Average System Price PV: Prior to Q1 2014, the methodology used to estimate average system prices was based on weighted-average system pricing received directly from utility and state incentive programs, but GTM Research and SEIA have long felt that the data was not an ideal reflection of the current state of system pricing, as it often represented systems quoted in quarters well prior to the installation and connection date, and much of the reported data was based on fair-market value assessments for TPO systems. U.S. Solar Market Insight March

73 Appendix B: Methodology and Data Sources As of Q1 2014, GTM Research and SEIA have switched to a bottom-up methodology based on tracked wholesale pricing of major solar components and data collected from major installers, with national average pricing supplemented by data collected from utility and state programs. PV GTM 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 the respective breakdown sections Electrical balance of systems (EBOS): Includes all additional electrical components necessary for 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 the PV system structurally, including mounting systems, foundations, ballast, racking, and clamps Direct labor: Includes all the necessary labor related to PV system installation, including site setup/preparation, installation, in-field logistics, and system commissioning Engineering, design, permitting, interconnection, inspection: Includes all labor and fees not directly 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 costs directly associated with the project, including supply-chain costs (distribution markups, volume markups, taxes), logistics (shipping and handling), customer acquisition (direct sales and marketing, site visits), overhead (project-related office costs) and markup (margin) 5.3. Manufacturing Production and Component Pricing GTM Research maintains databases of manufacturing facilities for PV and CSP components. PV CSP GTM Research manufacturing facility databases, announcement monitoring, conversations with manufacturers Announcement monitoring, conversations with manufacturers U.S. Solar Market Insight March

74 Disclaimer of Warranty and Liability DISCLAIMER OF WARRANTY AND LIABILITY Greentech 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 the accuracy, completeness, correctness, non-infringement, merchantability, or fitness for a particular purpose of any reports covered by this agreement. Greentech Media, SEIA, their employees, affiliates, agents, or licensors shall not be liable to user or any third party for losses or injury caused in whole or part by our negligence or contingencies beyond Greentech Media s or SEIA s control in compiling, preparing or disseminating any report or for any decision made or action 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 the possibility 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 exceed the amount you paid to Greentech Media for use of the report in question. U.S. Solar Market Insight March

75 Disclaimer of Warranty and Liability U.S. SOLAR MARKET INSIGHT Full Report 2015 Year-in Review Interested in other reports that we offer, please visit March 2016 U.S. Solar Market Insight March