Solar fundamentals vol 2

Solar Fundamentals Volume 2: Markets Authors: Ryan Edge

Research Analyst Erika H. Myers

Senior Manager, Research

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Acknowledgements: Ted Davidovich for data and analysis; Himali Shah and Cynthia Hunt Jaehne for photo contributions.

Disclaimer: This material is based upon work supported by the U.S. Department of Energy under Award Number DE-EE0003525. The report was produced by the Solar Electric Power Association (SEPA) with the support of the following organizations as part of the SunShot Solar Outreach Partnership: ICLEI-Local Governments for Sustainability; International City/County Management Association (ICMA); North Carolina Clean Energy Technology Center; Meister Consultants Group, Inc.; Interstate Renewable Energy Council, Inc. (IREC); The Solar Foundation (TSF); American Planning Association (APA); and National Association of Regional Councils (NARC).

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

All units in this report are expressed in grid-compatible alternating current (AC).

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TABLE OF CONTENTS Introduction..............................................................................................................4 Solar Deployment Overview...............................................................................5 Capacity...................................................................................................................5 Interconnected systems...........................................................................................5 Distribution...............................................................................................................5 Primary Drivers.......................................................................................................7 Solar market potential...............................................................................................7

Pricing Basics.........................................................................................................9 Installed costs..........................................................................................................9 Component costs.....................................................................................................9 Levelized cost of energy..........................................................................................10 Power purchase agreement pricing.........................................................................11 Enabling Policies...................................................................................................13 Renewable portfolio standards................................................................................13 Federal investment tax credit...................................................................................13 Net metering...........................................................................................................13 Public Utility Regulatory Policies Act of 1978...........................................................15 Solar renewable energy credits................................................................................16 Market Dynamics..................................................................................................17 Economies of scale.................................................................................................17 Cost competitiveness..............................................................................................17 Third-party leasing...................................................................................................19 Appendix 1: Common terms............................................................................. 21 Appendix 2: Third-party power business models map.............................. 23

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Introduction This report serves as one component of a multi-part series of publications that the Solar Electric Power Association (SEPA) plans to produce throughout 2015. The purpose of this effort is to provide a broad introduction to several facets of the solar industry, including a discussion of different drivers influencing the U.S. solar market, an update on the current state of the U.S. market, a summary of project financing options, and an overview of some of the solar integration challenges that utilities are encountering (or soon will be).

SEPA undertook this effort to assist in educating those seeking to become more familiar with the solar industry. Whether you are reading this publication as a new utility regulator seeking information to better inform your decision-making process or as a student researching potential career paths, the goal of this series is to distill information into short publications that any individual can use to gain practical knowledge of the industry.

This report in the series introduces solar markets, including the amount of solar built to date, how the solar is currently distributed, and factors contributing to the growth that has occurred over the past several years.

Solar has catapulted from a minor energy resource to the fastest growing energy resource in the U.S. in a very short time so considerable attention will be given to the factors that catalyzed this tremendous growth in recent years. As solar becomes more cost-competitive, SEPA anticipates this trend will continue into the future.

2015 SEPA Utility Solar Conference solar tour

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Where are we now?

Solar deployment overview Capacity The solar market in the United States surpassed 16,000 megawatts (MW) of installed capacity at the end of 2014. The market grew 23 percent year-overyear adding nearly 5,500 MW. Over the past seven years, solar has developed from a niche industry with nominal grid penetration to approximately 1 percent of U.S. generating capacity. It is now the fastest growing energy resource, averaging 56 percent year-over-year growth for the past five years. Solar power now closely competes with natural gas in annual capacity growth—growth that is accelerating as more capacity is added each year than the one before.

The total installed capacity consists of 92 percent photovoltaic (PV) technologies and 8 percent concentrating solar power (CSP).1 This gap is forecast to widen with time because CSP plants are more expensive to build and are suitable for only a specific geographic area in the southwestern United States. CSP plants are generally central-station, utility-scale generators each rated at a few hundred megawatts (with a few exceptions), but PV system deployments vary widely because they do not have CSP’s geographic limitations and can also be deployed as distributed generation. Currently there are 1,707 MW of CSP in the U.S. compared to 14,690 MW of PV. The solar market is often categorized according to three distinct segments based on system capacity: utility-scale, commercial, and residential.

The utility-scale segment, at 8,367 MW, makes up the largest share—51 percent. These generators

are 5 MW and larger2 and are almost exclusively ground mounted. The largest example of these plants, Southern California’s Solar Star, is rated at 579 MW and uses more than 1.7 million PV modules.

Commercial PV systems come next with 4,761 MW installed—29 percent. These are often built by businesses subject to commercial rates, hence the classification “commercial”. These systems range from a few kilowatts (kW) up to 5 MW and may be installed on rooftops, parking canopies, or at ground level. Small utility plants, including many allocated to community solar programs, usually fall in this capacity range and would be classified in this category on the basis of installed cost per Watt and system capacity.

Residential installations make up the final 20 percent of the solar market with 3,263 MW. These systems are only a few kilowatts—10 kW maximum in most cases—and are almost exclusively situated on residential customers’ rooftops.

Interconnected systems In total there were more than 675,000 solar electric generating installations in operation in the U.S. at the end of 2014. Of these, CSP plants accounted for just 20 installations. The largest market segment for PV installations is residential with 92 percent, followed by commercial and utility-scale with 7 and 0.06 percent respectively.

Distribution It is widely known that the most active solar region in the U.S. is the arid and sunny Southwest due

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For an introduction to solar technologies, refer to SEPA’s Solar Fundamentals: Technology report.

2

Definitions of utility-scale vary with some as small as 1 MW.

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to the abundance of sunshine. California and Arizona are the two leading states for installed capacity. CSP and mega-scale PV plants are almost entirely located in this region.

Solar penetration, or the portion of generating capacity provided by solar resources, is actually highest in Hawaii where solar contributes 6 percent of the energy resource mix.3 In contrast to the Southwest’s large, centralized solar power plants, solar power in Hawaii is driven by residential installations. These generators interconnect at the street-level low voltage distribution system, unlike utility-scale generators that interconnect at high voltages on the transmission and sub-transmission networks.

Less commonly known, yet very active, solar markets are found on the East Coast with New Jersey and Massachusetts leading in the Northeast and North Carolina in the Southeast. These states have renewable portfolio standards (RPS) mandating that utilities use a certain amount of renewable energy resources. New Jersey and Massachusetts also have robust markets for Solar Renewable Energy Credits (SRECs) that add a secondary revenue stream for investments in solar plants. [See page 16 for more on SREC markets.] In North Carolina, a state boasting the fourth highest solar capacity, a combination of federal and state incentives, adequate solar irradiance, and a relatively high avoided cost rate makes utility-scale projects attractive investments.

How much solar has been installed?

Capacity in megawatts 20,000 16,295

15,000

10,000

5,000

5,314

2010

2011

2014

800,000 675,520

600,000

400,000

200,000 182,262

2011 Cumulative Annual

Hawaii Energy Facts & Figures. May 2015. Hawaii State Energy Office. http://energy.hawaii.gov/wp-content/uploads/2011/10/HSEO_FF_May2015.pdf

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2013

Number of installations

2010

3

2012

2012

2013

2014

What makes solar grow in some areas and not others?

Primary drivers Three primary characteristics drive a solar market: solar irradiance, retail electricity rates, and incentives and policies. The combination of these three for any given location dictates its level of solar adoption on the customer side of the meter. RPS requirements (discussed in greater detail below) can have an overriding influence on utility procurement.

Each state varies according to geography, policy, and other factors, leading to uneven solar development across the country. For example, California

has high rates, ample sunshine, and numerous incentives, all of which made solar cost-effective years ago when solar installation costs were significantly higher. New Jersey, on the other hand, does not have the solar resource of California, but its retail rates and incentives supported the installation of more than 1.2 GW to become the third largest solar market in the nation. Florida, on the other hand, has abundant sunshine, but its average retail rates and below average incentives put it in the lower half of solar market potential. Policy can change rapidly,

Residential solar market potential based on composite factors of solar capacity, retail rates, and incentives and policies

Highest potential market

AK

Lowest potential market

Source: SEPA, 2015

Actual solar installations vary slightly from this map, but it is a close approximation of state potential for increased solar deployment.

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however, which could unlock the state for aggressive solar development.

The map on page 7 ranks states from highest to lowest based on scores assigned using a combination of these three contributing factors. Actual solar installations vary slightly from this map, but it is a close approximation of how states range in their respective solar deployment. SEPA developed a scoring process by assigning a high, medium, and low score to capacity factor, retail rates, and in-state incentives and policies (which included the presence of a renewable portfolio standard, third party solar leasing, a feed-in tariff, and residential

solar tax credits) within each state. The scores were weighted differently with the most weight assigned to the residential retail rate. Additional points were assigned to states with an SREC market.

State average retail rates was sourced from the Energy Information Administration, state average solar irradiance was provided by the National Renewable Energy Laboratory, and state incentive program analysis was developed by SEPA. The solar resource was calculated with the latitude and average solar irradiance at ground level for each state to construct a normalized capacity factor4 for solar installations.

Volunteers install solar panels for low income residents in Baltimore.

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Capacity factor is the ratio of a power plant’s actual production to its ideal maximum production. This term applies to all generators regardless of fuel source. Capacity factor for wind and solar plants is usually limited by the available wind or solar resource, but with fossil fuel plants, maintenance, electricity demand or economic factors such as fuel prices warrant reducing a plant’s output thereby reducing its capacity factor. Baseload nuclear power plants designed to constantly operate at maximum output average around 90 percent capacity factor, while solar power plants average less than 20 percent.

Isn’t solar expensive?

Pricing basics Installed costs Installation category

Capacity

Installed cost-per-Watt

Concentrating Solar Power

100 MW and larger

$4.50 to $6.00

Residential

3 kW - 10 kW

$3.00 to $4.50

Commercial

10 kW - 1 MW

$2.25 to $3.50

Utility-Scale

1 MW - 10 MW

$1.75 to $2.50

Large Utility-Scale

10 MW and larger

$1.40 to $1.75 Source: SEPA, 2015

As of 2015, residential systems can be installed at a national average just under $4.00 per Watt. For commercial and industrial projects, the cost falls as low as $2.25 per Watt. Utility-scale power plants can be installed under $1.50 per Watt.

As referenced above, CSP plants are rare compared to PV plants. Their high cost per Watt and siting constraints have limited the growth of CSP relative to PV technology. The quoted range of installed costs includes a power plant with thermal energy storage that marginally increases cost while adding an even greater measure of dispatchability.

CSP plants exhibit different operating characteristics from PV plants such as smoother ramp rates5, a degree of dispatchability6 and reactive power7 output, all of which ease grid integration. These ancillary services are noteworthy because they are more valuable to grid operators as the share of intermittent renewables on the grid continues to rise.

Based on installed costs alone, solar is among the most expensive resources: combined cycle natural gas plants and simple cycle gas turbines can be installed for $0.94 per Watt and $0.92 per Watt8, respectively. However, solar installed costs are only one consideration for choosing among available generating technologies.

Component Costs The installed cost of PV systems includes the following cost categories: modules, inverters, balance of system (BOS), and soft costs. The most recognizable system components are PV modules, also referred to as solar panels. Inverters are electronic devices that convert module output in direct current (DC) to grid-compatible alternating current (AC).

BOS includes all other hardware such as racking, wiring, fasteners, etc. that are required to complete a PV installation. (See examples below for PV

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Ramp rate is the rate at which a power plant can increase or decrease its power output. PV can ramp nearly instantaneously while CSP ramps more gradually. High ramp rates without dispatchability challenge resource integration on the grid.

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Dispatchability allows the operator to control the power plant’s output. PV has a very limited dispatchability because it is fully reliant upon sunlight; spinning generators including coal, natural gas, hydro and nuclear are dispatchable by controlling the amount of fuel driving the turbine.

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Reactive power is essential for the delivery of electricity because it enables the reliable flow of electricity. Spinning generators inherently supply reactive power, but PV generators supply only real power unless a specific setting on the inverter enables it to also deliver reactive power.

8

EIA Table 8.2. Cost and performance characteristics of new central station electricity generating technologies. http://www.eia.gov/forecasts/aeo/assumptions/pdf/table_8.2.pdf

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system component cost comparison across different market sectors.)

Modules are the single largest cost component of a PV system. Module prices (for all semiconductor types9) have fallen dramatically since they were first developed for grid applications in the 1970s.

Inverter and BOS costs have also fallen in recent years, parallelling the uptake in solar technologies, but not to the same extent. Part of the reason for the relatively smaller decline is these hardware components are also used in other industries and applications. The price of wiring, for example, is determined more by the market price of raw materials, copper or aluminum, than economies of scale in the solar industry.

Finally, soft costs refer to expenses incurred in project development that are not intrinsic to a PV system yet are real project costs. The most identifiable soft costs are directly related to the installation of hardware, including permitting, interconnection, inspections, labor, and customer acquisition and service. Other

value-added soft costs include installer and integrator profit margins, legal fees, professional fees, financing transactional costs, operations and maintenance costs, production guarantees, reserves, and warranty costs.

Soft costs have come down marginally in recent years in the U.S., but they remain a barrier to greater solar adoption. By comparison, soft costs in Germany are minimal, while in the U.S. they account for up to 20 percent of a residential installation. See the chart on page 11 for Rocky Mountain Institute’s soft cost breakdown between the U.S. and Germany.

Levelized cost of energy Unlike fossil fuel generators, solar plants have zero fuel costs, far lower operations and maintenance costs, zero emissions requirements, minimal water usage, and no waste products requiring disposal— all factors that give solar power a distinct advantage in dispatch costs. Levelized cost of energy (LCOE) fairly compares power plants, even among those with different fuel sources, by including not only the

PV Systems Prices by Market Sector 2009 - 2013, $ per Watt.10 (Image: NREL)

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For an introduction to solar technologies, refer to SEPA’s Solar Fundamentals: Technology report

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Note rooftop-model system sizes chosen for comparison: residential: 5 kW in Q4 2009 through Q4 2013; commercial: 202 kW in Q4 2009 to 223 kW in Q4 2012 (200 kW in Q4 2013); utility-scale: 175 MW in Q4 2009 to 185 MW to Q4 2013. Standard crystalline silicon modules (13.5% efficiency in Q4 2009 to 15.0% in Q4 2013).

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Soft costs are the major driver of cost differences between the U.S. and Germany. (Image: Rocky Mountain Institute)

installed cost of the plant but also the operating costs required to generate energy. LCOE calculations omit non-monetized values such as greenhouse gas emissions and grid reliability characteristics such as dispatchability. [See chart on page 12 for comparison of LCOE among generating resources.]

On the basis of LCOE, energy efficiency and wind power are the least cost resources followed by utility-scale solar PV and combined cycle natural gas, which is the most thermally efficient fossil fuel technology.

Power purchase agreements When utilities buy solar power, in most cases they do not own the power plant but instead enter long-

term contracts called power purchase agreements (PPA) that govern the sale of generated electricity.

Utility offtakers buy the output of a power plant at a specified rate, and solar developers own, operate, and maintain the plant.

PPA prices range from highs around $150 per megawatt-hour (MWh) to lows under $40 per MWh, and prices under $75 per MWh are now considered commonplace. PPA prices can vary widely based on system capacity and available solar resource among other factors. They originate in one of two ways: utilities issue requests for proposals (RFP) for large-scale solar procurement or developers apply for interconnection as qualifying facilities (QF) under the Public Utilities Regulatory Policy Act of 1978 (PURPA). [See page 15 for more about PURPA.]

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Levelized cost of energy comparison Solar legend 30% ITC

overlap

10% ITC

Solar (1-10MW) Solar (>10 MW) Wind Coal Combined cycle natural gas Simple cycle natural gas

$0

$50

$100

$150

$200

Source: SEPA analysis of 2014 integrated resource plans for western utilities

Modules, inverters, and balance of system make up PV system hardware.

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LCOE $/MWh

$250

What else is pushing solar adoption?

Enabling policies Economies of scale in manufacturing has had a tremendous effect lowering the installed cost of solar.

The convergence of positive economics and supportive policies, including incentives, has propelled solar technology into the mainstream.

Renewable Portfolio Standards In the U.S., one of the most important policies furthering solar deployment is the RPS. These state-level mandates compel utilities to generate a portion of their electricity from renewable resources.

California was among the earliest states to enact such a policy—33 percent renewable generating mix by 2020—and the state now leads the nation in solar capacity. In June 2015, Hawaii enacted a 100 percent RPS to be met by 2045. In total 29 states have binding RPS requirements, while another eight have set non-binding renewable energy goals. [See map on page 14.]

Some states set aside “carve-outs” requiring a certain percentage of the RPS compliance to be achieved with solar. New Jersey, for example, has a 20.38 percent RPS requirement for 2021 with a 4.1 percent solar carve-out to be met by 2028.

Solar carve-outs in some states have given rise to SREC markets that enable utilities to meet RPS compliance through the environmental attributes of non-utility generators. [See page 16 for more information on SREC markets.]

Investment Tax Credit (ITC) The federal ITC is another critical policy spurring solar deployment. Congress enacted the Energy Policy Act of 2005 that included the nonrefundable tax credit valued at 30 percent of the installed cost of a solar generator. The credit applies to solar electric systems, ranging from small residential installations to utility-scale power plants producing hundreds of megawatts. The current policy is scheduled to

change on December 31, 2016, at which point it steps down to a 10 percent credit for corporate entities and expires for individuals. This incentive has made the economics of solar power much more competitive, and the deadline has hastened project development and construction ahead of the year end 2016.

Net Metering Net metering is a billing mechanism for electric utility customers with grid-connected distributed generation. It facilitates use of the electric utility system, allowing customers to virtually “bank” generation not used immediately, in exchange for kilowatt-hour (kWh) and/or financial credits. Those customers subsequently may draw on their credits at other times to offset consumption and/or charges when the system is not meeting their full energy needs, up to the total amount they have banked within the applicable period (often 12 months). Specific utility net metering policies dictate how any credits remaining at the end of the period are “rolled over” to future periods, compensated or retired. Furthermore, somewhat independent of the billing arrangement, distributed generation customers displace energy usage directly, which has important ramifications within rate discussions, utility cost recovery, and customer perceptions of bill savings.

Net metering applies to the vast majority of U.S. solar installations. It is a simpler mechanism for utility billing than alternatives, such as feed-in tariffs. The practice has supported solar growth on the customer side of the meter by providing a repayment mechanism for energy supplied to the grid by a PV system.

Many countries in Europe and some utility territories in the U.S. use an alternative known as a feed-in tariff. Under a this structure, solar customers sell 100 percent of the energy they generate to the util-

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Renewable Portfolio Standard Policies

DC

AK Renewable portfolio standard Source: North Carolina Clean Energy Technology Center

Renewable portfolio goal

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Total RPS

Deadline

Solar/DG Carve-Out

State Total RPS

Deadline

AZ

15

2025

4.5% DG by 2025

ND*

10

2015

CA

33

2020

NH

24.8

2025

0.3% by 2014

CO

30

2020

NJ

20.38

2020

4.1% by 2028

NM

20

2020

4%, 0.6% DG by 2020

NV

25

2025

1.5% by 2025

NY

29

2015

0.58% customer sited by 2015

OH

12.5

2026

0.5% by 2027

OK*

15

2015

OR

25

2025

20MW PV by 2020 0.5% PV by 2021

3% DG, 1.5% customer-sited by 2020

Solar/DG Carve-Out

CT

27

2020

DC

20

2020

2.5% by 2023

DE

25

2026

3.5% PV by 2026

HI

100

2045

IA

105 MW

IL

25

2026

IN*

10

2025

PA

18

2021

KS*

20

2020

RI

14.5

2019

MA

2020 15 (new) 6.03 (existing) 2016

400 MW PV by 2020

SC*

2

2021

SD*

10

2015

MD

20

2022

2% by 2020

TX

5,880 MW

2015

ME

40

2017

UT*

20

2025

MI

10

2015

VA*

15

2025

MN

26.5

2025

1.5%, 0.15% DGPV by 2020

VT

75

2032

MO 15

2021

0.3% by 2021

1% DG by 2017 + 0.6% per year until 2032

MT

15

2015

WA

15

2020

2 MW DG

NC

12.5

2021

WI

10

2015

Source: SEPA, 2015

1.5% PV, 0.25% DG by 2026

0.2% by 2018

*non-binding

0.25% DG by 2021

DG = distributed generation

ity and pay the utility for 100 percent of the energy they consume. This policy creates two discrete transactions between the utility and its solar customer that can be valued at separate rates. Feed-in tariffs can be set at a high rate to incentivize distributed solar or a low rate that aligns with the utility’s avoided fuel cost.

Another kind of tariff is the value of solar tariff that prices the solar rate based on its value to the grid including energy, time of delivery, locational factors, and incentives. Value of solar tariff methodology attempts to calculate a value-based rate for solar energy in a similar manner to how retail electricity rates are based on a fair allocation of the cost of service.

Public Utility Regulatory Policies Act of 1978 The last major policy affecting the solar market at the national level is PURPA. It was initially designed to support non-utility generators as alternatives to imported oil and natural gas that had experienced price spikes and supply disruptions in the 1970s when the law originated. The pressure from the natural gas market has since subsided, but PURPA continues to provide a mechanism for renewable energy development in many states.

The PURPA provision most applicable to solar generators requires utilities to interconnect qualifying generators to the grid and purchase electricity from them at a rate not to exceed the utility’s avoided cost. Avoided cost rate is what a utility would pay to purchase 1 MWh of energy.

Enabling policies support a rapidly growing solar market.

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SREC Markets Solar Renewable Energy Credits (SRECs) are an accounting device used to quantify and trade the clean energy benefits of solar energy. One SREC is generated for every 1 MWh of electricity produced by a given solar system. SRECs differ from other renewable energy credits because they apply only to solar generators. This attribute is important for RPS compliance in states with specific solar carve-outs.

SRECs are tradable, therefore they can be sold to generate a secondary revenue source for a solar power installation that is not obligated to supply bundled energy.11 Utilities purchase SRECs to comply with RPS requirements, but corporations often buy SRECs to support renewable energy and claim the environmental benefits as an offset to their own operations.

Although RECs may be sold nationwide, SREC markets are all located in Mid-Atlantic and Northeastern states. New Jersey and Massachusetts have the most active SREC markets with the highest prices—up to $680 per SREC in the past. Only SRECs generated by solar power plants in these states qualify for the respective markets. Ohio and Pennsylvania are two states with open SREC markets, which means that SRECs generated outside of that state may participate in the market. Ohio requires half of the SRECs used for compliance with the RPS originate in the state.

Small power producers—100 kW up to a maximum of 80 MW—and combined heat and power plants that qualify for this provision are classified as “qualifying facilities” (QFs), and the Act charges states with setting the actual rate QFs are paid.

PURPA implementation varies among states. Some compensate QFs at an avoided cost rate that is a very attractive to developers while other states base their rate on only the avoided cost of fuel, which makes for a considerably lower rate. The Energy Policy Act of 2005 provided an exemption to the “must purchase” aspect of PURPA for utilities served by a competitive power market such as those administered by regional transmission organizations (RTO).12 This is not to say that utilities subject to restructuring are exempt from PURPA, but they may file a request for exemption with their regulators.

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Small renewable generators under 80 MW can be qualifying facilities under PURPA.

Bundled energy describes an energy transaction that includes not only the kWhs but also all other benefits including environmental attributes.

PURPA Title II Compliance Manual. 2015. National Rural Electric Cooperative Association.

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So solar is becoming cost competitive; what does that mean for the market?

Market dynamics Japan and parts of Europe started going solar in a big way around the midpoint of the last decade, spurring international manufacturing capacity to meet the new demand. Growth in module manufacturing capacity lowered unit costs through economies of scale in a similar fashion as what happened in consumer electronics. According to economies of scale, the more demand grows and manufacturers produce overall, the cheaper each unit can be produced. The early adopters set the solar market in motion for the rest of the world.

Many utilities in the U.S. began considering solar a few years later after economics became more favorable and states instituted RPS requirements.

These laws compelled utilities to procure renewable energy, which at the time had an associated cost premium over traditional resources. Many utilities subject to these requirements initially pursued wind power and biomass. Solar was an option, but it was more expensive. It offered better coincidence with peak electricity demand than wind, minimal water consumption (for PV and some CSP technologies), and zero variable costs for fuel, but utilities still had to balance these attributes with the cost of solar and the needs of their customers.

The ITC took effect in 2006 granting a 30 percent tax credit for solar generators. This paved the way for third-party leasing (discussed below) and PPAs in states with high electricity rates. Competition among firms combined with the consistent growth in manufacturing capacity worldwide, among other factors, put downward pressure on prices.

A virtuous cycle took shape in which falling prices spurred worldwide demand. Higher demand drove investments in greater supply-side capacity, which in turn caused prices to continue to fall. Photovoltaic systems use semiconductors (modules) and solid state electronics (inverters); economies of scale for

manufacturing both technologies continue to yield returns for the supply side of the solar market.

Installed costs continued downward to the point where developers could build projects that were profitable at utilities’ avoided cost rates. At this price point, developers secured PPAs with utilities by applying as QFs under PURPA. States with more generous calculations for avoided cost and not served by RTOs were the first to see this.

North Carolina QF projects under 5 MW can secure standard offer PPAs for 15-year terms at a fairly generous avoided cost rate. Utah has low retail rates and minimal incentives, but adequate irradiance coupled with a sufficiently high avoided cost rate has opened the state to several hundred megawatts of QF projects that are scheduled to come online in 2015 and 2016.

Parity with the avoided cost rate is an important threshold for the utility-scale solar market because it signifies the moment where solar becomes economically viable for utilities. At this point, in terms of its cost to ratepayers, policy mandates can take a backseat to other benefits, including lower operations and maintenance costs, hedging fuel cost volatility for coal and natural gas, negligible water use for PV installations, no fuel transportation costs, no coal ash requiring disposal, and zero emissions including greenhouse gases. Parity with avoided costs also means that solar is no greater burden on ratepayers than traditional resources.

When utilities can secure PPAs for solar at or below their avoided cost rate, solar is cost-competitive with traditional energy resources. This is apparent in the restructured markets where merchant solar power plants now compete with wholesale generators. In New Jersey and Massachusetts, developers have built projects that pencil out on the basis of monetizing both wholesale energy output and

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SRECs. This business model is not yet widespread.

PPAs remain the dominant utility procurement vehicle, but merchant solar power is a significant development that allows developers to save on customer acquisition costs and PPA contracting.

Texas, on the other hand, does not have an SREC market, but it does have a merchant solar power plant employing a business model similar to those in New Jersey and Massachusetts. Using the ample solar resource in Texas, the ERCOT wholesale market, and clever siting west of major load centers to maximize on-peak energy production, Barilla Solar Project is a demonstration of solar’s cost-competitiveness. This plant competes openly in the market with traditional generators selling its wholesale power at the prevailing market rate.

Continued installed cost declines have motivated large corporations’ demand for solar. Many have imposed operational goals on themselves to mitigate or eliminate their contribution to climate change. In recent years they have sought and acquired renewable energy resources to cut emis-

sions and many have saved money in the process.

Competitive pricing and third-party PPAs have made solar the resource of choice for these companies in recent years.

IKEA and Walmart are significant examples of companies that install, own, and operate rooftop systems on their premises. Walmart has nearly 300 solar generators, producing approximately 100 MW, and IKEA has 40 MW installed across 41 locations.

Amazon, Google, Apple, and Kaiser Permanente are recent examples of companies entering longterm PPAs with solar developers.

Both groups leverage the dual nature of solar deployment: it can be installed behind the customer meter, and it can compete with utilities for retail customers. As a result, some utilities are engaging directly with their key accounts (large commercial and industrial customers with high electricity demand) to competitively supply them with renewable energy. A prime example is the U.S. Department of Defense, which has partnered with numerous utilities nationwide to build and operate

Businesses are increasingly interested in buying renewable energy.

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Net metering has supported tremendous growth in distributed PV installations. solar power plants sited on military bases. As the customer, the military base gets the renewable energy it demands, and the utility retains the customer and its load.

Like corporations buying cost-competitive largescale solar power, residential customers also go solar as the economics pencil out. Distributed solar proliferation tends to parallel retail electricity prices and is influenced to varying degrees by state policies. Retail electricity prices have risen by at least as much as inflation while solar’s costs have trended steadily downward. Adoption rates for solar increase as these prices approach one another— when retail rates equal the cost of solar energy, it is referred to as grid parity.13 Solar is a hedge against utility rate hikes for customers in much the same way it can hedge fuel costs for utilities.

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Where it is permitted by law, third-party PPAs have allowed distributed solar markets to thrive; where forbidden, adoption rates generally suffer. Leases lower barriers to solar adoption for customers by reducing or eliminating upfront costs. In contrast, customers who own their systems outright bear very significant upfront costs, but their investment payback is greater. [See Appendix 2 for details.]

GreenTech Media previously estimated that thirdparty-owned systems would peak in 2014 at 72 percent of the market.14 Financing and installed costs have improved, allowing developers to offer competitive alternatives for residential customers.

Owned PV systems are viewed more favorably than lease agreements during real estate transactions, and they earn the homeowner greater financial payback over the life of the system.

Grid parity is when the cost of energy produced by a solar generator equals the cost of the same quantity of grid energy.

14

GreenTech Media. 2015. http://www.greentechmedia.com/articles/read/Better-Cheaper-Loans-Challenging-the-Solar-Leasing-Model

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Financing and installed costs have improved making solar power attractive for residential customers.

Appendix 1 Common terms Alternating Current (AC): A type of electrical current, the direction of which is reversed at regular intervals or cycles; in the U.S. the standard is 120 reversals or 60 cycles per second; typically abbreviated as AC. Balance of System: Racking systems, tracking systems, fasteners, wiring, combiner boxes, DC optimizers, transformers, and other physical components of a solar PV system behind the point of common coupling with the utility grid but excluding modules and inverters.

Bundled Energy: An energy transaction that includes not only the kWhs but also all other related benefits including environmental attributes (RECs).

Capacity: The load that a power generation unit or other electrical apparatus or heating unit is rated by the manufacturer to be able to meet or supply.

Concentrated Photovoltaics (CPV): A photovoltaic technology that generates electricity from sunlight using lenses and curved mirrors to focus sunlight onto small, but highly efficient, multi-junction solar cells.

Concentrated Solar Power (CSP): A system that generates solar power by using mirrors or lenses to concentrate a large area of sunlight, or solar thermal energy, onto a small area. Electricity is generated when the concentrated light is converted to heat, which drives a heat engine (usually a steam turbine) connected to an electrical power generator.

Derating: The production of energy by a system or appliance at a level less than its design or nominal capacity.

Direct Current (DC): A type of electricity transmission and distribution by which electricity flows in one direction through the conductor; usually relatively low voltage and high current; typically abbreviated as DC. Dispatchability: The capacity for a generator to be controlled by a grid operator. Solar and wind technologies are considered to have limited dispatchability because they are fully reliant upon intermittent and naturally occurring sunlight or wind; spinning generators including coal, natural gas, hydro and nuclear are

dispatchable by controlling the amount of energy that drives the turbine.

Distributed Generation (DG): Small power generators installed on the distribution network at lower voltages, often owned and operated by utility customers.

Efficiency: Under the First Law of Thermodynamics, efficiency is the ratio of work or energy output to work or energy input, and cannot exceed 100 percent.

Efficiency under the Second Law of Thermodynamics is determined by the ratio of the theoretical minimum energy that is required to accomplish a task relative to the energy actually consumed to accomplish the task.

Generally, the measured efficiency of a device, as defined by the First Law, will be higher than that defined by the Second Law. Grid Parity: The cost of energy produced by a solar generator equals the cost of retail electricity from the grid.

Installed Costs: The cost of the hardware components of an electric power generator and the labor input to build it.

Interconnection/Interconnect: A connection between two electric systems permitting the transfer of electric energy in either direction. Additionally, an interconnection refers to the facilities that connect a non-utility generator (including a distributed generation facility) to a Control Area or system.

Inverter: A device that converts direct current electricity (from for example a solar photovoltaic module or array) to alternating current for use directly to operate appliances or to supply power to an electricity grid.

Investment Tax Credit (ITC): An incentive mechanism that allows a percentage of the cost of one’s investment to be credited against taxes owed. The federal ITC for solar is currently 30 percent and scheduled to step down at the end of 2016 to 10 percent for corporate investments and 0 for individuals.

Some states offer ITCs as well.

Kilowatt (kW): A standard unit of electrical power equal to one thousand watts, or to the energy con-

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sumption at a rate of 1000 Joules per second. Small and medium-scale solar systems (e.g. residential and small commercial) are typically rated in kilowatts.

Levelized Cost of Energy (LCOE): A standardized price for a unit of energy production that includes the capital cost of the generator, fuel cost, operations and maintenance costs, and other relevant direct costs of generating electricity. LCOE allows for a fair comparison of all types of generators regardless of fuel source.

Megawatt (MW): One thousand kilowatts, or 1 million watts; standard measure of electric power plant generating capacity. Large and utility-scale solar systems are typically rated in megawatts.

Nameplate Rating/Nameplate Capacity: The fullload continuous rating of a generator, prime mover, or other electrical equipment under specified conditions as designated by the manufacturers. It is usually indicated on a nameplate attached mechanically to the individual machine or device.

Net Metering: Also called Net Energy Metering (NEM), is a utility billing practice for qualified renewable generators on the customer side of the meter. The customer is billed for monthly energy consumption net of the energy produced by the customer.

Photovoltaics (PV): Device that produces electrical current by converting light or similar radiation.

Power: Energy that is capable or available for doing work; the time rate at which work is performed, measured in horsepower, Watts, or Btu per hour. Electric power is the product of electric current and electromotive force.

Power Purchase Agreement: A contract between an independent power producer and an offtaker for the output of a power plant that specifies the price to be paid for energy and the term of the arrangement.

Qualifying Facility (QF): A generator, either a small renewable generator under 80 MW or a cogeneration plant, as defined under the Public Utilities Regulatory Policies Act of 1978 (PURPA), that is entitled to special consideration with regard to utility rates and regulations.

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Ramp Rate: The speed at which a power plant can increase or decrease its power output.

Reactive Power: Expressed as vars and sometimes referred to as imaginary power, is a necessary component of electricity delivery. It interacts with capacitive and inductive loads between a generator and the end user. It is the difference between the apparent power supplied to a customer (VA) and the real power used for energy services (W).

Renewable Energy Credit (REC): An accounting construct used to quantify the environmental benefits of renewable power plants for the purpose of RPS compliance. RECs produced by solar installations generate Solar Renewable Energy Credits (SRECs) that can be applied to solar carve-outs for some states’ RPS mandates.

Renewable Portfolio Standard (RPS): A state law that mandates a specified quantity of renewable energy resources in a utility’s generating portfolio. Compliance may vary as a mandate of portfolio percentage, energy sold, or a specific measurement of capacity.

Soft Costs: A category of expenses incurred in permitting, interconnection, inspections, and other requirements that are not intrinsic to a PV system yet are real project costs.

Solar Water Heating (SWH): A system that converts sunlight into renewable energy for water heating using a solar thermal collector.

Thermal Mass: A material’s resistance to change in temperature.

Third-Party Lease: An arrangement between a solar installer and a customer for periodic payments in exchange for use of a solar PV system. Leases may include a power purchase agreement.

Watt (W): The rate of energy transfer equivalent to one ampere under an electrical pressure of one volt.

One watt equals 1/746 horsepower, or one joule per second. It is the product of Voltage and Current (amperage). Watts are commonly used as the unit for the nameplate rating of PV modules.

Appendix 2

Third-party solar PV Power Purchase Agreements (PPA)

DC

AK

No third-party PPAs

Source: North Carolina Clean Energy Technology Center

Third-party PPAs permitted

Unspecified

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