clean tech opp us 2010

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DRAFT DOCUMENT CONFIDENTIAL 1

THE U.S. CLEANTECH FINANCING OPPORTUNITY

EXECUTIVE SUMMARY While traditional debt capital requirements are in the billions, across the four segments discussed in this

report, there is a compelling need for structured finance.

According to goals set by the Waxman-Markey bill, passed in the U.S. Senate in 2009, which calls

for a 15% Federal Renewable Portfolio Standard (RPS), required investment would be $32 Bn per

year until 2020 ($356 Bn in total - U.S. Partnership for Renewable Energy Finance (US PREF),

2010).

Using a 60:40 debt to equity ratio, about $214 Bn will be required in debt capital and $142.4 in

equity to build up renewable energy generation capacity, develop transmission infrastructure,

and reduce energy demand through efficiency measures.

The complexity of the landscape makes the case for the opportunity for financial institutions expertise –

particularly those with expertise in creating financing structures that exploit this multitude of tax,

compliance, and credit rules.

Economic drivers in clean energy and energy efficiency are multi-layered: e.g. government

regulation, incentives, and compliance-based tradable certificates.

The above hints at the jurisdiction-specific nature of clean energy: laws on Federal, State, and

local levels all affect project economics. To expand this analysis to a global scale would have been

beyond possibility, given the time frame.

Key challenges to date include an absence of scale and growth capital for projects. The timeline,

complexity, small scale, and high capex of projects have been unfamiliar for equity investors. If only a

small portion of the projected installed capacity were to come online, billions of dollars would be

required, with anywhere upwards of 40% from debt capital sources. Meanwhile, debt has been slow at

the project level due to the unfamiliarity of lenders and debt investors with technology risk.

Structures which invite equity and hybrid investors to invest in projects at adequate

compensation are necessary; a way to entice these investors may be to organize take out in the

form of securitization.

Energy

Renewable energy is generally more expensive than energy produced by non-renewable sources. The

higher cost derives from the efficiency of conversion technologies, transmission issues, and high up-front

capital costs (partly balanced by low operation and maintenance costs: renewable power plants often

have low to zero need for fuel inputs and low- to zero emissions).

The government is not the only significant actor, however; many clean technologies require seed, angel,

venture, and private equity capital in order to achieve scale and minimize costs. With costs lower,

government subsidies can push some technologies into price-competitiveness, while others still require

government regulation before becoming mainstream. Due to concerns about efficiency, emissions, and

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energy security, the government has created regulation and incentives to drive investment into clean

technology. Highlights include tax credits, cash grants, and compliance-based tradable certificates.

With regulation, subsidies, and incentives, renewable energy has grown at a 5% CAGR from 1995-2009,

exclusive of hydroelectric energy. Wind was the fastest growing renewable energy source, with a growth

rate of 61% in 2008 and 28% in 2009. Solar was second in 2008 at 41% growth, but last in 2009 with a -6%

growth rate. Geothermal and biomass each grew at 2% in 2009 while biofuels experienced slightly less

negative growth in 2009 (-3%) than in 2008 (-4%).

Wind

Total installed wind capacity in the U.S. today is 35,062 MW; this can grow to more than 300,000 MW by

2030. The total investment required would be $464 Bn. Assuming 60% leverage, $278 Bn would be

required in debt capital.

A typical farm costs approximately $210 MM. Average debt requirements are between $115-126 MM, as

detailed in the body of this report.

Given the scale of the opportunity, wind is an area that should be tracked; however, the average size of

the debt need per project has driven a plethora of financiers into the industry. There may be untapped

opportunity in securitizing land leases from utility scale projects and or PPAs and RECs from community

or small wind projects. One company in this space is American Wind Power Capital: a company owned

by Barclays Natural Resource Investments and NGP Energy Technologies Partners. Small wind is still a

nascent market segment and as such even more dependent on government policies and related

developments in the electric grid that enable distributed generation. Securitization of existing project

cashflows may provide a near-term opportunity to develop a structure which can then be rolled out to

distributed projects over time.

Solar

According to the DOE, the aggregate amount of money needed for financing solar PV projects and build-

up of manufacturing capacity is $1.4 trillion from debt investors and $0.15 trillion from equity (Cory,

2009). While wind is cost competitive in most regions (after government incentives), solar PV is not. Costs

have come down over the past few years, as certain PV technologies have achieved scale; however, the

cost in 2009 was still $5.5/W for large-scale systems (See diagram below from SEIA, 2010). Government

regulation is consequently essential to the development of solar PV. Federal and State governments have

created a number of solar-specific policies, which have driven local markets. The fragmented nature of

the market creates a strong need for structured finance – and an even more interesting opportunity for

securitization; however, due to the complexity of the market, the securitization opportunity is easily a

year out.

Electric Grid

At present, the US electrical grid serves 335 MM customers with nearly 3,765 Billion kWh of electricity in

a year (2007 figures, EIA). In part to meet this demand and the annual 1% growth in consumer demand

for electricity, government entities, investors, and business owners have invested in renewable energy

power generation.

As renewable capacity grows, so do pressures on the electric grid. To accommodate the growth in

renewable and distributed generation while maintaining electric-grid reliability, investment is required

across the spectrum of transmission, distribution, management, and use.

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The hottest sector of the smart grid in 2009 was information and communications technology. According

to GTM research, VC funding in the first half of 2009 was $37.5 MM and $461 MM in 2008. Much of these

plays have low capital needs, as they are IT companies.

A second segment of the smart grid that is in need of capital is physical transmission. According to a

report published by Edison Electric Institute (EEI) the United States needs to invest at least $880 billion in

transmission and distribution systems between 2010 and 2030 to maintain reliable service. Multi-billion

dollar funds have been established by major financial institutions to serve this need. Consequently, a

more strategic area of focus may be in energy efficiency and securitization.

Energy Efficiency

The buildings sector accounts for 62% of total investment in energy efficiency, according to Ehrhardt-

Martinez and Laitner (Ehrhardt-Martinez & Laitner, 2008). Non-residential building energy efficiency

was a $51.3 billion in 2004 and demand has only grown (Ehrhardt-Martinez & Laitner, 2008).

Due to the small size of individual projects and the early stage of development of the market,

securitization of the cashflows from a number of energy efficiency projects can yield significant

opportunity: Hannon Armstrong purportedly securitized $1.5 billion in energy efficiency project

cashflows from 2006-2008 (The Economist, 2008). Hannon Armstrong proves that the industry segment

harbors opportunity; however, that company’s work focused on Federal agencies. In the commercial

building space, significant leg work must be done to create turnkey contracts and solutions.

CONCLUSION The clean energy sector offers significant room for financial innovation, particularly with regard to

structured products. To leverage the multi-layered economic drivers for clean energy projects – e.g.

government regulation, incentives, and compliance-based tradable certificates –unique structures are

required. While traditional debt capital requirements are in the billions, across the four segments

discussed in this report, there is a compelling case for pioneering the securitization of project-based

cashflows. Still, without scale, time spent in structuring take-out is unlikely to have a near-term pay-off;

there may be a more tangible opportunity to entice debt investors to finance projects by introducing the

idea of take-out earlier. Secondly, opportunities to raise debt capital for clean tech companies – helping

them to prove their technologies and achieve economies of scale – should be pursued.

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TABLE OF CONTENTS

EXECUTIVE SUMMARY 1

ENERGY 5

MARKET POTENTIAL 5

STATE OF THE MARKET 6

Cost of Renewable

Electricity 10

GOVERNMENT POLICIES 12

Federal Policies 15

State Policies 23

FINANCING OPPORTUNITY 30

WIND ENERGY 33

MARKET POTENTIAL 33


Cost 35

Output 36

Business Models 38

Financing Structures 39

LCOE 48


Financials 49

SOLAR ENERGY 54

MARKET POTENTIAL 54


Cost 56

Output 58

Government policies 61

Business Models 66



Financials 75

ELECTRICITY 87

MARKET POTENTIAL 87


Financing 97

Companies 100

ENERGY EFFICIENCY 102

MARKET POTENTIAL 102


Cost 102

Savings 103

Government policies 106

Business Models 109



CONCLUSION 113

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ENERGY

MARKET POTENTIAL

Government, organizations, and agencies have created renewable energy goals with varying projections

and required amounts of investment. According to goals set by the Waxman-Markey bill, passed in the

U.S. Senate in 2009, which calls for a 15% Federal Renewable Portfolio Standard (RPS), required

investment would be $32 Bn per year until 2020 ($356 Bn in total - U.S. Partnership for Renewable Energy

Finance (US PREF), 2010)i.

At its peak in 2007, investment into renewable energy assets totaled $14.2 Bn. (US PREF and New Energy

Finance).

Using a 60:40 debt to equity ratio, about $214 Bn will be required in debt capital and 142.4 in equity to

build up renewable energy generation capacity, develop transmission infrastructure, and reduce energy

demand through efficiency measures. US PREF assumes loan-loss reserve rates of 5% for conventional

renewables and 10% for innovative renewable, and estimates that $140-180 Bn will be required from

investors other than the Federal government (via the DOE Loan Guarantee program – described on page

21).

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STATE OF THE MARKET

Renewable energy accounts for 4.9 QBtu of productionii and 7% of consumption, as seen in the diagrams below.

Source: EIA (2009)

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Currently, installed capacity is 141,115 MW, excluding hydroelectric energy (EIA). The largest share of

U.S. renewable energy is comprised of hydroelectric power, though virtually all exploitable and

economical hydroelectric sites have already been developed (EIA, 1998). Hydroelectric has, in fact, had a

negative CAGR from 1995 to 2009, as shown in the following table.

Excluding hydroelectric, renewable energy generation in the U.S. grew at a CAGR of 5% over the same

period, from 1995-2009.

Source: EIA data

U.S. Net Generation from Renewables

(Thousand Megawatthours)

YEAR WIND SOLAR GEOTHERMAL BIOMASS BIOFUELS HYDRO TOTAL

1995 3,164 497 13,378 20,405 36,521 310,833 384,798

1996 3,234 521 14,329 20,911 36,800 347,162 422,957

1997 3,288 511 14,726 21,709 36,948 356,453 433,635

1998 3,026 502 14,774 22,448 36,338 323,336 400,424

1999 4,488 495 14,827 22,572 37,041 319,536 398,959

2000 5,593 493 14,093 23,131 37,595 275,573 356,478

2001 6,737 543 13,741 14,548 35,200 216,961 287,730

2002 10,354 555 14,491 15,044 38,665 264,329 343,438

2003 11,187 534 14,424 15,812 37,529 275,806 355,292

2004 14,144 575 14,811 15,421 38,117 268,417 351,485

2005 17,811 550 14,692 15,420 38,856 270,321 357,650

2006 26,589 508 14,568 16,099 38,762 289,246 385,772

2007 34,450 612 14,637 16,525 39,014 247,510 352,748

2008 55,363 864 14,951 17,734 37,300 254,831 381,043

2009 70,761 808 15,210 18,093 36,243 272,131 413,246

CAGR 26% 4% 1% -0.14% 0.01% -0.33% 1.0%

U.S. Net Generation from non-hyrdo Renewables

(Thousand Megawatthours)

YEAR WIND SOLAR GEOTHERMAL BIOMASS BIOFUELS TOTAL

1995 3,164 497 13,378 20,405 36,521 73,965

1996 3,234 521 14,329 20,911 36,800 75,795

1997 3,288 511 14,726 21,709 36,948 77,182

1998 3,026 502 14,774 22,448 36,338 77,088

1999 4,488 495 14,827 22,572 37,041 79,423

2000 5,593 493 14,093 23,131 37,595 80,905

2001 6,737 543 13,741 14,548 35,200 70,769

2002 10,354 555 14,491 15,044 38,665 79,109

2003 11,187 534 14,424 15,812 37,529 79,486

2004 14,144 575 14,811 15,421 38,117 83,068

2005 17,811 550 14,692 15,420 38,856 87,329

2006 26,589 508 14,568 16,099 38,762 96,526

2007 34,450 612 14,637 16,525 39,014 105,238

2008 55,363 864 14,951 17,734 37,300 126,212

2009 70,761 808 15,210 18,093 36,243 141,115

CAGR 26% 4% 1% -0.14% 0.01% 5.0%

Source: EIA data

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Over the last 33 years, total renewable supply grew at an annual rate of 2.3% while overall primary energy supply grew at 2.2%. Renewable energy has

consequently met incremental demand, while displacing only a minute portion of fossil fuel-based generation; however, renewable resource potential is far

greater than has been developed to date, as illustrated in the map below.

Due to concerns about efficiency, emissionsiii, and energy securityiv the installed capacity of renewable energy in the U.S. is expected to be 46,625 MW by 2020

(Ertel, 2010).

Resource Solar PV/CSP) Wind Geothermal Water Power Biopower

Theoretical

Potential

206,000 GW

(PV)

11,100GW

(CSP)

8,000 GW

(onshore)

2,200 GW

(offshore to

50 nm)

39 GW

(conventional)

520 GW

(EGS)

4 GW

(co-produced)

140 GW 78 GW

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The projected installed capacity factors in locational issues such as the need for access to transmission lines in resource-rich areas. The map below illustrates the

location of the best renewable resources and availability of existing transmission lines.

Transmission lines contribute to development times, cost, and efficiency. As such, the electric grid is detailed later in this report.

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The present state of development is illustrated by the map and tables below. The map shows existing

electric power plants by resource and location.

As shown in the previous map, on page 9, there are significant untapped renewable resources, waiting

for development of new transmission lines and upgrades to the electric grid. These are just 2 of the factors

that inflate the cost of renewable resource exploitation.

Cost of Renewable Electricity




have low to zero need for fuel inputs and low- to zero emissionsv). In order to compare costs from

resources with different characteristics, analysts use a levelized costvi metric. This is presented below for

U.S.-based fossil fuel and renewable energy generation plants.

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Lower opex makes renewable energy power plants attractive in the long run but current deregulationvii of

the electric industry heavily biases the short-term. Additionally, the 2008 downturn in the market has

slowed investment into renewable energy generation, as seen in the graph and table below.

*Please see pages 15-23 for explanations of the Federal programs mentioned above.

Source: Schwabe, Cory, & Newcomb (2009)

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Source: Schwabe, Cory, & Newcomb (2009)

Consequently, government support is critical. To meet increasing demand for electricity, limit pollution

emissions, and achieve a modicum of energy security, the government has created policies both at the

Federal and State levels, additionally enhanced by utility and non-profit programs.

GOVERNMENT POLICIES

Before detailing existing policies, it should be noted that much is being discussed in Congress today. The

timeline shows climate- and energy-related bills introduced into the House and Senate in 2009.

Source: Lack (2010)

Each of the bills above has minimum quotas for renewable energy generation in each state. These

requirements are pictured in the chart below.

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Source: Sjardin (2010)

The renewable energy quotas indicate required supply by 2030 and imply a market for renewable energy

credits (RECs – please see page 23 for an explanation of renewable portfolio standards and RECs) as quotas can

be met through direct investment or purchase of RECs.

To support investment in supply, the bills have included proposals for a Green Bank (also known as the

Clean Energy Bank and Clean Energy Investment Bank) and Clean Energy Deployment Administration

(CEDA). The table below shows the three proposals for Federal financing that are currently being

considered.

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Source: US PREF (2010)

A fairly comprehensive list of existing Federal and State regulations and incentives is presented in the next section.

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It should be noted, that independent of the Congressional discussions, the EPA has taken actions,

illustrated in the timeline below.

Source: Lack (2010)

In sum, developments in Congress, DOE, EPA, USDA, and state agencies have a significant effect on the

renewable energy industry and must be tracked on an on-going basis.

Federal Policies

There are a number of existing incentives, grants, and low- or zero-interest financing programs available

for both renewable energy generation and energy conservation.

Federal Tax Credits

Production Tax Credit (PTC): The PTC was established under EPACT92 in 1992. The original

PTC was only for wind and closed-loop biomass and provided a $0.015 / kWh tax credit for the

first 10 years of the qualifying facilities’ operation. The PTC has always had 1-2 year expiration

dates. The program has been extended a number of times and expanded to additional

technologies and different tax credit amounts. After American Recovery and Reinvestment Act

(ARRA) modifications in 2009, the PTC was made available for wind, closed-loopviii biomass,

open-loop biomass, geothermal energy, municipal solid waste, qualified hydropower and marine

and hydrokinetic renewable energy. The current PTC tax credit schedule is pictured below.

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Source: Lips (2009)

Solar technologies are not eligible for the PTC.

ARRA extended placed in serviceix dates from between 2008 and 2009 to 20012 and 2013 – for

example, wind facilities must be placed in service by December 31, 2012 while all other facilities

have until December 31, 2013.

Renewable Energy Production Incentive (REPI): The REPI was designed to complement the PTC,

as it is only available to businesses that pay federal corporate taxes. It provides incentive

payments for electricity generated and sold by new qualifying renewable energy facilities

including solar PV, solar thermal, wind, biomass, geothermal electric, landfill gas, anaerobic

digestion, tidal energy, wave energy, and ocean thermal. Eligible electric production facilities

include not-for-profit electrical cooperatives, public utilities, state governments and political

subdivisions thereof, commonwealths, territories and possessions of the United States, the

District of Columbia, Indian tribal governments or political subdivisions thereof, and Native

Corporations.

Qualifying systems are eligible for annual incentive payments of 2.1¢/kWh. Appropriations have

been authorized for fiscal years 2006 through fiscal year 2026; however, program funding is

determined each year as part of the U.S. Department of Energy budget process. The production

payment applies only to the electricity sold to another entity and generated from an eligible

facility first used before October 1, 2016.

Investment Tax Credit (ITC): The ITC covers 30% of system cost, inclusive of installation costs,

without any cap for solar PV, solar water heat, wind systems less that 100 kW, fuel cells, and

residential geothermal heat pumps. For commercial geothermal, microturbines, and combined

heat and power (CHP), the ITC covers 10%. Despite that, under Section 1102 of ARRA,

geothermal can elect a 30% ITC (Bolinger, Wiser, Cory, & James, 2009). Fuel cells and

microturbines are subject to dollar caps.

Resource Type In-Service Deadline Credit Amount

Wind December 31, 2012 2.1¢/kWh

Closed-Loop BiomassDecember 31, 2013

2.1¢/kWh

Open-Loop Biomass December 31, 2013 1.0¢/kWh

Geothermal Energy December 31, 2013 2.1¢/kWh

Landfill Gas December 31, 2013 1.0¢/kWh

Municipal Solid Waste December 31, 2013 1.0¢/kWh

Qualified Hydroelectric December 31, 2013 1.0¢/kWh

Marine and Hydrokinetic (150 kW or larger)** December 31, 2013 1.0¢/kWh

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The ITC is realized in the year in which the project begins commercial operations, but vests

linearly over a 5-year period. It is currently available to qualified projects that are placed in

service prior to the end of 2016. There is no expiration date for the geothermal credit. The solar

credit will revert to 10% at the end of 2016.

The ITC can be used to offset both regular and alternative minimum taxes (AMT).

Qualified facilities and public utilities are eligible.

Department of Treasury Grants: US Department of Treasury grants are available under Section

1603 or the ARRA, in lieu of the Federal ITC, for businesses unable to take advantage of tax

credits – for example, due to negative revenues. The cash grant program requires that

commercial property be installed in 2009 and 2010. In some cases, if construction begins in 2010,

the grant can be claimed for energy investment credit property placed in service through 2016.

Applications must be reviewed and payments made within 60 days of the later application date

or facility’s placed in service date.

For properties not placed in service in 2009 or 2010, applications must be submitted after

construction commences but before October 1, 2011, and the properties must be placed in service

before a specified ‚credit termination date‛. The schedule of credit termination dates is below.

*Geothermal Property that meets the definitions of qualified property in both § 45 (the Internal Revenue Code’s Income Tax Credits

for Renewable Energy) and § 48 (the Advanced Energy Manufacturing Tax Credit) is allowed either the 30% credit or the 10% credit

but not both.

** For fuel cell property the maximum amount of the payment may not exceed an amount equal to $1,500 for each 0.5 kilowatt of

capacity.

*** For microturbine property the maximum amount of the payment may not exceed an amount equal to $200 for each kilowatt of

capacity.

Source: U.S. Treasury Department (2009)

The definition of construction having begun is that the applicant has incurred or paid at least 5%

of the total cost of the property, excluding land and preliminary planning activities, as stated

under the Safe Harbor clause in Section 1603 of the American Recovery and Reinvestment Act.

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However, there has been a demontrated lack of clarity around this definition; according to Power

Finance & Risk from its April 19, 2010 newsletter, the Treasury is reviewing applications case-by-

case to determine whether individual projects qualify as having begun construction. Treasury

will review applications and notify applicants if eligibility requirements have been met. Within

90 days after the property is actually placed in service, applicants must submit supplemental

information to Treasury for a final decision. Treasury will then review the application and, within

60 days after submission after the supplemental information is received, make payment to

qualified applicants.

Multiple units of property that are parts of a single, larger unit of property, can be included in a

single application. The definition of the single larger unit is that the smaller units must be

functionally interdependent – i.e. the placement in service of one unit requires the placement in

service of another unit.

The depreciable basis of the property must be reduced by one-half of the grant amount (i.e.

assuming the grant amount is 30% of total project costs, the depreciable basis for the project

becomes 85% of total project costs). Additionally, the grant is not subject to passive credit

limitations, as it is not even a credit (Bolinger, 2010).

The cash grant is excluded from gross income.

The program had awarded companies $1 billion as of September 2009.

Businesses can choose to claim either the PTC or the ITC/cash grant but cannot claim both for the

same facility. When choosing, it is important to consider ancillary benefits (outlined below).

Source: Bolinger (2009)

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According to the Lawrence Berkeley Lab, ancillary benefits can be worth even more to certain

types of projects than the expected value of the PTC, ITC, or cash grant, alone.

MACRs: A 5-year MACRs schedule applies to solar PV, solar thermal, geothermal electricity,

direct-use geothermal and geothermal heat pumps, wind (small –100 kW or less– and large), fuel

cells, microturbines, combined heat and power, and solar hybrid lighting.

For certain biomass property, 7-year MACRs is applicable. This generally applies to assets used

to convert biomass to heat or to a solid, liquid, or gaseous fuel, and to equipment used to receive

handle collect, and process biomass in a waterwall, combustion system or refuse-driven fuel

system to create hot water, gas, steam, and electricity (DSIRE, 2010).

Energy-Efficient Commercial Buildings Tax Deduction: Corporate deductions of $0.30-$1.80 per

square foot are available for equipment insulation, water heaters, lighting, lighting controls and

sensors, chillers , furnaces , boilers, heat pumps, central air conditioners, caulking and weather-

stripping, duct and air sealing, building insulation, windows, doors, siding, roofs, comprehensive

measures and whole building retrofits - depending on technology and amount of energy

reduction. Eligible sectors are commercial, construction and State and Federal government.

Utility Depreciation: Utilities can accelerate depreciation on smart grid and metering

technologies (Ungar, 2009).

Residential Energy Conservation Subsidy Exclusion (Corporate): Energy conservation is achieved

through energy conservation measures (ECMs), such as installing or modifying building

equipment to reduce electricity or natural gas consumption and/or improve energy management.

Energy conservation subsidies provided by public utilities, directly or indirectly, are non-taxable.

This strongly indicates that utility rebates for residential solar-thermal projects and solar-electric

systems and energy conservation programs that reduce rates may be nontaxable. However, the

IRS has not ruled definitively on this issue.

Residential and multi-family buildings are eligible.

Federal Grants

Department of Energy Grants: The DOE provides funding out of three offices, the Advanced

Research Projects Agency Energy (ARPA-E), Office of Energy Efficiency & Renewable Energy

(EERE), and Office of Science.

Advanced Research Projects Agency-Energy (ARPA-E): ARPA-E is a $400 million

funding program, established within the U.S. Department of Energy (DOE) under the

2007 America Competes Act. The program provides grants to large businesses, small

businesses, universities, and non-profits to develop ‚transformational technologies‛ that

foster energy security and reduction of emissions, and/or achieve energy efficiency.

Grants are for ‚high risk, high payoff concepts‛ in energy generation, storage and

utilization (ARPA-E, 2010). To date, the program has awarded $151 MM to 37 projects

with the following technological breakdown.

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Energy Efficiency Technologies 22%

Biotech 22%

Vehicle Technologies 19%

Conventional Energy Technologies 16%

Grid Modernization Technologies 14%

Solar Technologies 8%

Energy Efficiency & Renewable Energy (EERE): There are a number of different EERE

programs funded through ARRA, including High-Efficiency Solid-State Lighting

Development & Manufacturing ($37 MM), Information and Communications Technology

– e.g. for data centers, ($47 MM), Industrial Energy Efficiency Projects ($155 MM),

Community Renewable Energy Deployment ($20.5 MM), Advanced Biofuels Research

and Fueling Infrastructure ($80 MM), Advanced Biorefinery Projects ($564 MM),

Enhanced Geothermal Systems R&D ($338 MM), Fuel Cell Market Transformation ($41.9

MM), Early Stage Solar Technologies ($10 MM), Solar Technologies Deployment ($50

MM), Solar Energy Grid Integration Systems ($5 MM), Hydropower Infrastructure ($30.6

MM), Wind Turbine Design Facility ($45 MM), and Wind Technology Development

($12.8 MM).x

Office of Science: The Office of Science provides funding for colleges and universities,

non-profit organizations, for-profit commercial organizations, state and local

governments, and unaffiliated individuals for basic and applied research.

A clean technology-specific listing of programs funded by ARRA is viewable at:

http://www.energy.gov/recovery/funding.htm. The list is updated on an on-going basis.

Department of Treasury Grants: See section above on Federal Tax Credits for full explanation.

Energy Efficiency and Conservation Block Grant (EECBG): The government additionally offers

grants to government entities state, local, Indian tribal governments, etc. for energy efficiency

under a program called the EECBG. The $3.2 billion program was funded by ARRA. $2.7 billion

of this amount is being funded through formula grants while the remaining $454 MM is being

funded through competitive grants. The application requires that applicants design mechanisms

that maximize capital availability for energy efficiency retrofits in residential and commercial

buildings in their regions. Consequently, many applicants have designed revolving loan

programs and partnerships with private sector or capital markets actors to win funds from the

EECBG.

U.S. Department of Agriculture Rural Energy for America Program (REAP) Grants: REAP

provides grants and loan guarantees for energy efficiency improvements and renewable energy

systems, and grants for energy audits and renewable energy development assistance to

agricultural producers and rural small businesses The congressionally approved budget for the

program is $60 million for FY 2010, $70 million for FY 2011, and $70 million for FY 2012. Ninety-

six percent of this funding is for grants and loan guarantees for improvements and feasibility

studies. Eligible renewable energy projects include wind, solar, biomass and geothermal; and

hydrogen derived from biomass or water using wind, solar or geothermal energy sources. Grants

are limited to 25% of proposed project cost. Loan guarantees may not exceed $25 million or 75%

of eligible project costs. Combined support cannot exceed 75% of project cost.

http://www.energy.gov/recovery/funding.htm

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Federal Loans

Clean Renewable Energy Bonds (CREBs) and Qualified Energy Conservation Bonds (QECBs):

The Federal government has two programs, CREBs and QECBs, which enable electric

cooperatives, and government entities to issue tax free bonds. Both CREBs and QECBs are bonds

are issued at zero interest by coops and governments. Borrowers repay the bond principals;

bondholders, in the meantime, receive federal tax credits in lieu of interest. These tax-free bonds

can be issued in the ARRA.

The CREB program is $2.4 billion program, one-third of which is allocated for state, local, and

tribal governments, one-third of which is for public power providers, and one-third of which is

for electric coops to generate electricity from renewable sources. CREBs must be issued within 3

years after a given applicant is informed of approval. $2.2 Bn of the total was allocated as of

October 2009.

The QECB program is a $3.2 billion program all of which is targeted to reduce greenhouse gas

emissions and conserve energy. These bonds are not subject to a Department Treasury

application and approval process; instead, bonds are allocated to states on the basis of their

population as of July 1, 2008. States allocate parts of their QECBs to large local governments

(municipalities and counties with >100,000 people each). Since March 18, 2010, bond issuers have

the option to get direct payments from the Department of Treasury in the form of refundable tax

credits in lieu of bondholders getting non-refundable tax credits.

Department of Energy Loan Guarantees: In total, DOE has allocated approximately $30 billion for

loan guarantees to projects that ‚avoid, reduce or sequester air pollutants or anthropogenic

emissions of greenhouse gases; and employ new or significantly improved technologies as

compared to commercial technologies,‛ including energy efficiency, renewable energy, and

advanced transmission and distribution, advanced nuclear power, advanced coal-based power,

and carbon capture and sequestration technologies. The current program was re-vamped in the

2009 ARRA, and so is defined in two acts: EPACT 2005, Title XVII, Section 1703 and EPACT,

Section 1705, added by ARRA. Section 1705 appropriated $6 billion to the loan guarantee

program.

The table below details the Loan Guarantee Program and Sections 1703 and 1705.

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Source: DOE (2010)

Section 1705 is limited to renewable energy installations and manufacturing facilities for

renewable energy components, electric power transmission systems, and advanced biofuel

projects and is targeted toward projects at the commercialization stage (though new or earlier

stage technologies are still eligible). Projects must commence construction by September 30, 2011.

If projects cost more than $25 MM, they must have minimum credit ratings of BB. According to

Fitch Ratings, a private letter rating is acceptable.

DOE guarantees up to 80% of total project costs and requires a significant equity contribution by

project owners. The lender is the Federal Financing Bank (FFB)xi. Tenor is the lesser of 30 years or

90% of expected useful life. DOE gets first lien on all project assets and requires additional

collateral for any project debt; the guarantee will not finance tax-exempt debt. A credit subsidy

equaling the net present value of the guarantee after accounting for estimated payments to cover

defaults, estimated receipts from fees, penalties, and recoveries. The DOE pays the cost of credit

subsidies, required up-front payments equal to about 10% of a loan guarantee's value, up to a

total of $4 billion. Upon default, loans will be accelerated.

There are two open solicitations, the first for "new or significantly improved" energy efficiency,

renewable energy, and advanced transmission and distribution technologies. If projects are

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eligible for Section 1703 but not Section 1705, they may secure loan guarantees, but not the credit

subsidy costs.

The second solicitation is for large transmission infrastructure projects using commercial

technologies. The authority for the second solicitation is only given under Section 1705, so all

projects under this solicitation must commence construction by September 30, 2011.

Since inception under EPACT 2005, the loan guarantee program has approved only 6 loan

guarantees, out of which , only one seems to have been finalized (as of April 19, 2010). Lead times

are reportedly 2 years, which DOE is trying to get down to 1.

USDA - Rural Energy for America Program (REAP) Loan Guarantees: See USDA REAP Grant,

above.

State Policies

On the state level there are renewable energy and energy conservation regulations as well as tax credits,

grants, and incentives.

Renewable Portfolio Standards (RPS): RPS require a certain percentage of total energy generation

or consumption in a region to come from renewable sources. The map below, from the Database

of State Incentives for Renewables & Efficiency (DSIRE), illustrates the 29 states and 1 district

with RPS.

For every unit of electricity power plant operators produce from renewable sources, they earn

renewable energy certificates (RECs) xii. A REC represents the environmental benefits of 1 MWh

of electricity generated from renewable sources. RECs can be sold to electric distribution

companies (EDCs); EDCs use the certificates for compliance, at which point the RECs are retired.

RECs can also be sold to electricity suppliers (load serving entities), power marketers

State renewable portfolio standard

State renewable portfolio goal

Solar water heating eligible *† Extra credit for solar or customer-sited renewables

Includes non-renewable alternative resources

WA: 15% x 2020*

CA:33% x 2020

NV: 25% x 2025*

AZ: 15% x 2025

NM: 20% x 2020 (IOUs)

10% x 2020 (co-ops)

HI: 40% x 2030

Minimum solar or customer-sited requirement

TX: 5,880 MW x 2015

UT: 20% by 2025*

CO: 20% by 2020 (IOUs)10% by 2020 (co-ops & large munis)*

MT: 15% x 2015

ND: 10% x 2015

SD: 10% x 2015

IA: 105 MW

MN: 25% x 2025

(Xcel: 30% x 2020)

MO: 15% x 2021

WI: Varies by utility;

10% x 2015 statewide

MI:10% + 1,100 MW x

2015*

OH: 25% x 2025†

ME: 30% x 2000New RE: 10% x 2017

NH: 23.8% x 2025

MA: 22.1% x 2020 New RE: 15% x 2020

(+1% annually thereafter)

RI: 16% x 2020

CT: 23% x 2020

NY: 29% x 2015

NJ: 22.5% x 2021

PA: 18% x 2021†

MD: 20% x 2022

DE: 20% x 2020*

DC: 20% x 2020

VA: 15% x 2025*

NC: 12.5% x 2021 (IOUs)

10% x 2018 (co-ops & munis)

VT: (1) RE meets any increase in retail sales x 2012;

(2) 20% RE & CHP x 2017

KS: 20% x 2020

OR: 25% x 2025 (large utilities)*

5% - 10% x 2025 (smaller utilities)

IL: 25% x 2025 WV: 25% x 2025*†

29 states + DC

have an RPS(6 states have goals)

DC

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(aggregators and marketers), commercial businesses, and individuals. These groups generally

buy for the purpose of re-selling, arbitraging the market, or PR reasons (e.g. to offset their

pollution emissions and position themselves as green). Sellers include project developers,

financial institutions, power and renewable energy marketers, brokers and aggregators, and

building or home owners.

RPS requirements vary from state to state; there is no federal policyxiii. States define schedules for

compliance-based penalties, fungibility, cross-border sale-ability, date (vintage),

bundling/unbundling rules, and more.

Compliance-based penalties refer to schedules published by regulators (e.g. the Board of

Public Utilities) that charge EDCs fees for failing to meet RPS quotas. EDCs weigh the

cost of the penalty against the cost of RECs and/or cost to develop renewable energy

power plants. Leaving aside the development of generation capacity for now, the choice

becomes purchasing RECs or incurring penalties. Consequently, REC prices are often

capped by compliance-based penalties.

Fungibility is defined by states and refers to renewable resource, vintage, etc.

Cross-border refers to the opportunity of, for example, New Jersey EDCs to purchase

RECs originated in Pennsylvania, etc.

Date refers to vintage – or the time at which the REC was produced (i.e. the MWh was

generated) as renewable MWhs produced in one year may have been much more rare

than those produced in another.

Bundling means that states require sale of RECs to be conducted in tandem with sale of

electricity. This may mean the two products must be sold to a single buyer or it may

mean that the REC can be sold to one buyer as long as the electricity was sold in the

regional transmission organization (RTO) or independent system operator (ISO).

Unbundling means RECs can be sold separate from the electricity.

All of these factors affect supply and demand. Consequently, REC prices vary greatly. The graph

below shows REC prices from Jan ’09-Jan ’10 and the table after it shows solar REC (a.k.a. SREC)

prices as of 4/19/10.

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The graph below maps $/MWh from January 1, 2009 to April 27, 2010 for Connecticut (EMSCT19), Washington DC (EMSDC19), Delaware (EMSDEN9), Maryland

(EMSMD29), Maine (EMSME19), New Hampshire (EMSNH19), and Rhode Island (EMSRIN9). Solar-specific RECs are not pictured here.

Source: Bloomberg (2010)

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Solar-specific RECs prices are listed in the table below.

SREC Market Bid Offer Settlement

Delaware $0 $0 $275

Maryland $275 $380 $380

Massachusetts open for trading

New Jersey $667.25 $670 $670

Ohio $300 n/a $300

Pennsylvania $285 $340 $340

Washington DC $405 n/a $405

New Jersey Class I RECs $0 $0 n/a

Regional Greenhouse Gas Initiativexiv $0 $0 n/a Source: Flett Exchange (2010)

The DOE’s office of Energy Efficiency & Renewable Energy (EERE) publishes a list of REC

marketers, brokers, and exchangesxv. Despite the wealth of firms listed, most RECs are sold via

bilateral contracts (Siegel, 2010). In other words, debt and equity investors finance renewable

energy projects in exchange for ownership of RECs for compliance or re-sale in direct, non-public

negotiations and agreements.

Public Benefits Funds (PBF) and Systems Benefit Charge (SBC): PBFs are fees included in the cost

of electricity to all consumers, paid for by users of distribution lines, whether generators or

consumers. The bill pictured below shows the PBF marked by the letter (d).

PBF revenues are usually funneled to a state, quasi-state, or non-profit entity. A well-known

example is the New York State Energy Research and Development Authority (NYSERDA) in

New York, a quasi-state entity funded by the PBF. PBF administrators design and administer

public benefits funds for renewable energy and energy efficiency projects in their respective

states. The map below from DSIRE shows the 16 states and 1 district with PBFs.

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Net Metering: Net metering enables power generators to sell electricity beyond that used for

internal load requirements back to the electric grid to offset consumption. There are occasionally

capacity restrictions and fuel restrictions. Net metering conceptually enables ‚banking‛ or in

other words, use of the grid to ‚store‛ energy produced at one time and consumed at another.

This concept is particularly useful for facilities that use electricity according to one pattern (e.g.

from 9am – 5pm) and produce electricity by another (e.g. when the wind blows or sun shines).

The map below shows the 43 states, 1 district, and 1 territory with net metering rules.

State PBF supported by voluntary contributions

* Fund does not have a specified expiration date

** The Oregon Energy Trust is scheduled to expire in 2025

RI: $2.2M in 2009$38M from 1997-2017*

MA: $25M in FY2009$524M from 1998-2017*

NJ: $78.3M in FY2009$647M from 2001-2012

DE: $3.4M in 2009$48M from 1999-2017*

CT: $28M in FY2009$444M from 2000-2017*

VT: $5.2M in FY2009$33M from 2004-2011

PA: $950,000 in 2009$63M from 1999-2010

IL: $3.3M in FY2009$97M from 1998-2015

NY: $15.7M in FY2009$114M from 1999-2011

WI: $7.9M in 2009$90M from 2001-2017*

MN: $19.5M in 2009$327M from 1999-2017*

MT: $750,000 in 2009$14M from 1999-2017*

OH: $3.2M in 2009$63M from 2001-2010

MI: $6.7M in FY2009$27M from 2001-2017*

ME: 2009 funding TBD$580,300 from 2002-2009

DC: $2M in FY2009$8.8M from 2004-2012

DC

OR: $13.8M in 2009 $191M from 2001-2017**

CA: $363.7M in 2009$4,566M from 1998-2016

State PBF

16 states + DC have

public benefits funds ($7.3 billion by 2017)

ME has a voluntary PBF

Source: www.dsireusa.org / May 2009

State policy

Voluntary utility program(s) only

State policy applies to certain utility types only (e.g., investor-owned utilities)

WA: 100

OR: 25/2,000*

CA: 1,000*

MT: 50*

NV: 1,000*

UT: 25/2,000*

AZ: no limit*

ND: 100*

NM: 80,000*

WY: 25*

HI: 100KIUC: 50

CO: no limitco-ops & munis: 10/25

OK: 100*

MN: 40

LA: 25/300

AR: 25/300

MI: 150*WI: 20*

MO: 100

IA:

500*

IN: 10*

IL: 40*

FL: 2,000*

KY: 30*

OH: no limit*

GA: 10/100

WV: 25

NC: 1,000*

VT: 250

VA: 20/500*

NH: 100

MA: 60/1,000/2,000*

RI: 1,650/2,250/3,500*

CT: 2,000*

NY: 10/ 25/500/2,000*

PA: 50/3,000/5,000*

NJ: 2,000*

DE: 25/500/2,000*

MD: 2,000

DC: 1,000

Note: Numbers indicate individual system capacity limit in kW. Some limits vary by customer type, technology and/or application. Other limits might also apply.

NE: 25

KS: 25/200*

ME: 660co-ops & munis: 100

PR: 25/1,000

AK: 25*

43 states + DC & PR have adopted a net

metering policy

DC

Source: www.dsireusa.org / March 2010

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Utility commissions differ on how to regulate net metering facilities and rates to pay. Some states

require utilities to credit facilities for electricity supplied to the grid at retail rates while others use

an avoided cost calculationxvi.

Interconnection Standards: Interconnection standards are the technical and legal procedures that

enable power producers to physically connect their facilities to the electric grid. Utilities define

these processes. Lack of policy can mean that a facility gets built but cannot sell its electricity. The

map below shows the 38 states, 1 district, and 1 territory with interconnection policies.

Interconnection costs depend on whether or not interconnection infrastructure exists at the plant

location, type of equipment, and specific insurance, fees, permits, and redundant safety measures.

For example, new wind plants, which are mostly in remote locations, require transmission line

extensions; this makes interconnection costs for wind plants higher than for many other types of

power plants. Furthermore, costs will depend on the existence of policy and the details of the

policy. Finally, the number of facilities in the interconnection queue will dictate how quickly

interconnection can be implemented.

In 2008, 356 generators with an aggregate of 16,947 MW in nameplate capacity were connected to

the grid.

Grants, rebates, and state tax credits: The diagrams below illustrate states with grants, rebates,

and tax credits for renewable energy.

State policy

*Standard only applies to net-metered systems

WA: 20,000

OR: 10,000

CA: no limit

MT: 50*

NV: 20,000

UT: 25/2,000*

NM: 80,000

WY: 25*

HI: no limit

CO: 10,000

MN: 10,000

LA: 25/300*

AR: 25/300*

MI: no limit

WI: 15,000

MO: 100*

IN: no limit

IL: 10,000

FL: 2,000*

KY: 30*

OH: 20,000

NC: no limit

VT: no limit

NH: 100*

MA: no limit

Notes: Numbers indicate system capacity limit in kW. Some state limits vary by customer type (e.g., residential/non -residential).“No limit” means that there is no stated maximum size for individual systems. Other limits may apply. Generally, state interconnection standards apply only to investo r-owned utilities.

CT: 20,000

PA: 5,000*NJ: no limit

DC: 10,000

MD: 10,000

NY: 2,000

SC: 20/100

GA: 10/100*

PR: no limit

TX: 10,000

NE: 25*

KS: 25/200*

SD: 10,000

ME: no limit

38 States + DC

& PR have adopted an interconnection

policy

DC

VA: 20,000


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Grant Programs Rebate Programs

State Income Tax Credits State Sales Tax Credits

Utility, local, or private program(s) only

State program(s) + utility, local, and/or private program(s)

Notes: This map only addresses grant programs for end-users. It does not address grants programs that support R&D, nor does it include grants for geothermal heat pumps or other efficiency technologies. The Virgin Islands also offers a grant program for certain renewable energy projects.

State program(s) only

Puerto Rico

DC

23 states offer grant

programs for renewables

Source: www.dsireusa.org / February 2010

Utility and/or local program(s) only

State program(s) + utility and/or local program(s)

State program(s) only Puerto Rico

DC

19 states + DC & PR

offer rebates

for renewables


Corporate tax credit(s) only

Personal + corporate tax credit(s)

Personal tax credit(s) only Puerto Rico

DC

22 states + PR offer tax

credits for

renewables


Notes: This map does not include sales tax incentives that apply only to geothermal heat pumps or other energy efficiency technologies.

State exemption + local governments (option) authorized to offer exemption or deduction

State exemption or deduction

Puerto Rico 26 states +

PR offer sales tax incentives

for renewables

DC


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State Property Tax Credits

FINANCING OPPORTUNITY

Due to all of the regulation, subsidies, and incentives detailed above, renewable energy has grown at a

5% CAGR from 1995-2009, exclusive of hydroelectric energy. Wind was the fastest growing renewable

energy source, with a growth rate of 61% in 2008 and 28% in 2009. Solar was second in 2008 at 41%

growth, but last in 2009 with a -6% growth rate. Geothermal and biomass each grew at 2% in 2009 while

biofuels experienced slightly less negative growth in 2009 (-3%) than in 2008 (-4%).

Source: EIA data (2010)



compliance, and credit rules. The set of diagrams below illustrates this complexity quite succinctly and

highlights the opportunity for structured finance in renewable energy projects.

State exemption or special assessment + local government option

Puerto Rico

Local governments authorized to offer exemption (no state exemption or assessment)

State exemption or special assessment only

32 States + PR

offer property tax incentives for renewables

DC


Net Generation by Renewables 1995-2009

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Year

Th

ou

san

d M

Wh

WIND

SOLAR

GEOTHERMAL

BIOMASS

BIOFUELS

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The next 2 sections will outline the opportunity for debt and asset backed securities in the wind and solar industries. Section three contextualizes growth in

renewable energy generation capacity within the U.S. electric power system and the goals of efficiency, emissions reductions, and energy security. Section four

outlines the opportunity for debt and asset backed securities in the energy efficiency market.

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WIND ENERGY

MARKET POTENTIAL

Total installed wind capacity in the U.S. today is 35,062 MW (AWEA, April 8, 2010). According to the DOE, wind energy can feasibly grow to more than 300,000

MW by 2030.

Source: www.windpoweringamerica.gov (2010)

http://www.windpoweringamerica.gov/

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STATE OF THE MARKET

Installed wind capacity as of 12/31/2009 is shown by state in the table below and accompanying diagram.

Source: AWEA (2010)

State Existing Capacity

(a/o 12/31/09)

Under

Construction

Texas 9,405 302

Iowa 3,670 200

California 2,723 121

Washington 1,908 170

Oregon 1,821 337

Minnesota 1,796 60

Illinois 1,547 539

New York 1,274 21

Colorado 1,246 51

North Dakota 1,203 76

Oklahoma 1,130 152

Wyoming 1,101 311

Indiana 1,036 99

Kansas 1,014 13

Pennsylvania 748 0

New Mexico 597 0

Wisconsin 449 0

Montana 375 0

West Virginia 330 101

South Dakota 313 99

Missiouri 309 150

Utah 223 202

Maine 175 92

Nebraska 153 42

Idaho 147 16

Michigan 143 20

State Existing Capacity

(a/o 12/31/09)

Under

Construction

Hawaii 63 0

Arizona 63 0

Tennessee 29 0

New Hampshire 26 0

Massachusetts 15 15

Alaska 8 0

New Jersey 8 0

Ohio 7 0

Vermont 6 0

Rhode Island 1 0

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The levelized cost of energy (LCOE) is derived from costs, output, business models, and financing

structures, all of which also illustrate the total investment required in the wind sector from now till 2030.

Each of these topics is detailed and then the total investment required is calculated.

Cost

The largest factor is plant development (DOE 2009). The diagram at

right shows all of the steps in developing a wind farm.

Siting is an important element of plant development costs, as, on the

one hand, there are permitting and environmental issues, and on the

other, there can be a trade-off between availability of wind resources

and accessibility of transmission lines. Many wind farms require new

and upgraded transmission lines, pushing up development costs.

Additionally, transmission interconnection backlogs can elongate the

timeline to get a plant up and running. In 2008, there were nearly 300

GW of wind projects in transmission interconnection queues, as shown

in the graph below.

Source: Wiser and Bolinger (2009)

Other development costs include wind turbine prices (which are in turn affected by shortages and

underlying raw material costs like copper and steel as well as the exchange rate of the US$),

transportation (which are affected by the cost of fuel), balance-of-plantxvii, and construction. Turbines are

by far the largest cost factor in project development; they can equal up to 75% of total investment costs

(Wind-Energy-The-Facts.org, 2010). The diagram below shows the proportion of installed costs accounted

for by each of these factors.

Source: NREL (1998)

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Source: Minister of Natural Resources, Canada (2004)

Variable costs include operations and maintenance (O&M) which are, in turn, driven by quality and age

of employed technologies, layout of arrays, and installation. These feed into the cost of insurance. The

figure below illustrate potential early failures in dashed lines and expected repairs that are likely

unavoidable in solid lines.

Source: DOE (2008)

It should be noted that wind farms have zero on-going fuel costs.

Output

Energy produced from a wind turbine is calculated as the cube of wind speed; consequently, increases in

rotor diameters yield exponential increases in electricity output. Today’s commercial turbines have three-

bladed rotors with diameters between 70-80 meters. As wind speed generally increases with height, the

rotors are mounted on top of 60-80 meter towers. According to the DOE’s latest survey, most turbine

designers expect maximum turbine size to be ~100 meters in diameter with nameplate capacity of 3-5 MW

per turbine, as otherwise, transportation and construction become overly-complicated.

0% 20% 40% 60% 80%

Balance of plant

Turbines

Engineering

Development

Feasibility Study

Portion of Installed Costs

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Source: DOE (2008)

A typical wind farm has arrays of

30-150 turbines, each with a

nameplate capacityxviii of ~2 MW.

As a turbine can use, at maximum,

only the amount of power for

which its electrical system has

been designed, power output

must be controlled by managing

blade direction and speed (pitch),

and turbine speed. Blade pitch is

managed by rotating the turbine’s

blades in concert with the wind

direction, while the blades spin

around rotors. At the back of rotor

hubs are nacelles. Wind sensors

direct the nacelles to communicate

with yaw controllers. Yaw

controllers point turbines in

different directions. Sensors along the nacelle, generator, and drive train communicate to control blade

pitch and rotor speed to output power within the limits of the turbine’s electrical system. Each turbine

typically has a capacity factorxix of 25-40%.

Source: DOE (2008)

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*COD stands for Commercial Operation Dates. LBNL notes that older wind farms, due to older technologies, are less productive

and efficient than newer ones. This fact is borne out by data in the table.

Source: DOE (2009)

With these land area, number of turbines, nameplate capacity, capacity factor, and costs and replacement

requirements for electrical components, one calculate the output from the given wind farm.

Business Models

Independent Power Producer (IPP) ownership is currently the most dominant ownership structure.

* Publicly-owned electric utilities are nonprofit government companies, owned locally or at the State level. As public organizations,

POUs raise caiptal from general obligation and revenue bonds secured by proceeds from the sale of electricity. POUs accounted for

61% of the 3,273 utilities in the U.S. in 2007, according to the EIA.

Investor-owned electric utilities are privately-owned. They accounted for 6% of U.S. utilities in 2007.

The remaining 33% of utilities are comprised of cooperative and Federal utilities, cogeneration, industrial, and qualifying facilities,

and retail power marketers.

Source: Cory, Coughlin, Jenkin, Pater, & Swezey (2008)

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Power is the dominant factor in a wind farm’s revenues, as opposed to renewable energy certificates or

other credits.

Under the IPP model, independent plant owners produce and sell electricity under long-term contracts

with utilities, known as Power Purchase Agreements (PPAs). In a typical PPA, buyers purchase some or

all of a plant or farm’s electricity output, usually at a fixed price, with or without escalation schedule over

time. In 2008, it became popular for IPPs to employ a merchant model. Merchant models included 100%

spot electricity sales, partially contracted and partially spot traded electricity, 100% contracted for a

period of time (e.g. 5 years potentially to match the terms of company or project debt) with a 100% flip to

merchant sales after that point. Merchant plants are currently experiencing significant competitive

difficulties due to the decline in natural gas prices.

Source: Cory et al. (2008)

When the shift towards spot sales took place, energy derivatives came into play. In particular, contracts

for differences began to be used. Other hedging options include using electricity markets or natural gas

put options and creating collars by also selling call options on the power produced by the plant. This can

be attractive if project owners expect revenue from within the band of the collar to be higher than that

from fixed-price PPAs.

The forward market goes out 7 years for wind but is most active around 2 years (NREL, 2008).

Finally, in states with RPS, power plants can sell RECs either in forward markets or on merchant bases.

One REC equals the environmental attributes of 1 MWh of renewably-generated electricity. REC markets

are fragmented and volatile, but, depending on state-by-state legislation, can be a significant revenue

driver. For more on RECs, please see page 23 and/or endnote xii.

Financing Structures

Complex contract structures and partnerships are typically used in order to exploit the full value of

Federal tax credits. These are outlined and diagrammed below.

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Source: Harper, Karcher, & Bolinger (2007)

Schematics from LBNL of each structure are provided below.

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Source: Harper et al. (2007)

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*The below is partially excerpted from Harper et al. (2007).

Returns are pictured below for each scenario other than Pay-Go (To date, Pay-Go has only been used for

refinancing).

*Corp = corporate; SIF = strategic investor flip; IIF = institutional investor flip; BL = back leveraged; Cash Lev = cash leveraged; Cash

& PTC Lev = cash & PTC leveraged

Source: Cory & Schwabe (2009)

Assumptions for each case are pictured in the table below.


The below shows the effect of capacity factors, installed costs, operation and maintenance costs, and

target IRRs on the levelized cost of wind energy, by financing structure.


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As seen, financing structure affects the levelized cost of energy – and consequently, the overall cost of the

project. Despite this, project developers choose deal structures based on the set of factors pictured in the

table below, rather than simply choosing the lowest cost option:


From 1998—2002, the primary deal structure was equity by a strategic investors – e.g. unregulated

subsidiaries of utilities or others with power sector experience, who could take an active management

role (Harper, 2007). Few projects used debt and there were only a small number of debt providers

interested in the sector. A few deals included PTC loan monetizations in which a bank would lend

against future PTCs. These deals required project owners receiving the PTCs to commit to make periodic

equity contributions for the term of the PTC loan to support debt service.

In 2003, as projects became larger, equity by institutional investors in exchange for tax benefits was the

primary investment structure. Tax equity investors, from 2007 to the present, are pictured below.

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Source: Schwabe (2009); Hudson Clean Energy Partners (2009); New Energy Finance, GreenTechMedia, JPMorgan (2009)

In 2003, commercial banks began offering bridge loans – e.g. turbine supply and construction loans– to

compete for term-lending opportunities (Harper et al. 2007). Debt arrangers devised different loan

facilities to enable single projects to attract capital from both commercial banks and institutional lenders

(e.g., insurance companies).

Utility ownership became popular in ’07-’08 as a result of this fact, and that the utilities could put the

development or purchase of the wind farm into the rate base, use balance sheet financing, or finance

portfolios using bank loans. Portfolios effectively decrease risk via geographical and turbine

diversification. Different turbine types reduce the risk of simultaneous design faults and geographical

diversity evens out access to wind resources (see diagram below).

Source: Marco et al. 2007

2003 was the first year for debt financing for a portfolio of wind projects, though, to this day, it can be a

good refinancing strategy and/or new investment strategy (e.g. for a wind-focused REIT).

The number of institutions providing debt financing of all types, as well as the average size of loan

transactions, rose over the course of the wind industry’s development. Transaction loan commitment

amounts in 2006 were in the hundreds of millions of dollars; one developer secured $1 billion in

construction loan facilities to support a portfolio of projects.

The typical loan term (or duration) remains a function of the length of the underlying power and REC

purchase agreements. For projects with long-term power purchase agreements (e.g., twenty years) with

creditworthy utility buyers, commercial bank lenders are willing to extend loans with a term of up to

fifteen years. Institutional lenders, e.g., insurance companies, have been willing to go as long as nineteen

years for comparable transactions. For projects involving shorter term power purchase agreements

(‚PPAs‛) or utilizing power marketing contracts in lieu of power purchase agreements, loan terms are

shorter and/or involve mandatory prepayments using any excess cash flow.

The debt service coverage ratio (DSCR) was 1.4x in 1998/99 but had widened to 1.45x by the mid- to late-

00’s.

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European commercial banks dominated lending activity in the U.S. wind sector.

LCOE: The LCOE from project development choices is subsidized by governmental programsxx like the

2.1 ₡/kWh production tax credit and/or the 30% investment tax credit/cash grant and 5-year accelerated

depreciation (MACRs).

Net of costs and subsidies is a delivered cost of wind electricity between $0.049/kWh -0.079/kWh (DOE,

2008).

After including REC sales, the cumulative capacity-weighted average wind price is approximately

$40/MWh or $0.04/kWh (LBNL, 2008).



2030. According to www.windustry.org, an average 2 MW turbinexxi costs $3.5 MM installed (DOE, 2008),

or in other words, inclusive of equipment, siting, business model, and financing structure choices. Using

this price, the total investment required would be $464 Bn. $278 Bn of this amount would be required in

debt capital.

Typical wind farms range from a few megawatts to hundreds of megawatts in capacity. They are

modular as they consist of discrete turbines which can be scaled as necessary. The most economical

application of wind electric turbines is in groups of large machines (660 kW and up) (DOE, 2008). Using

that figure and 55 turbines (the mid-point between the average array sizes of 30-150 noted by the DOE)xxii

a typical farm would cost $210 MM in initial investment costs and on-going operations.xxiii Average debt

requirements would be between $115-126 MM.


the debt need per project has driven a plethora of financiers into the industry, as seen by the cast of tax

equity characters in the table presented above.

Companies in the wind energy space are presented below.

http://www.windustry.org/

CONFIDENTIAL


Top Wind Power Owners (2009)

Source: AWEA (2009) & Capital IQ (2010)

Wind Debt (2007-present)

Company Name MW under

"managing

ownership"*

Market

Capitalization

Latest

Total Debt

LTM

Net Debt

LTM

Total Enterprise

Value Latest

Total

Revenue

LTM

EBITDA

LTM

TEV/LTM

Total Rev

TEV/LTM

EBITDA

Total Debt

/ Mkt Cap

Total Debt /

EBITDA

FPL Group Inc. (NYSE:FPL) 6,290.1 20,733 18,889 18,651 39,384 15,643 4,598 2.52x 8.57x 0.90x 4.11x

Iberdrola Renovables SA (CATS:IBR) 2,063.4 16,224 4,262 20,630 2,666 1,757 7.74x 11.74x 0.26x 0.00x

MidAmerican Energy Company 1,939.5 - 2,865 2,778 - 3,693 803 - - - 3.57x

Horizon Wind Energy, LLC 1,872.7 - - - - - - - - - -

Invenergy Wind LLC 1,276.5 - - - - - - - - - -

Babcock & Brow n Limited 1,118.8 105 8,839 7,691 - 3,367 1,289 73.29x 6.86x

Edison Mission Group, Inc. 959.9 - 11,358 - - - - - - - -

The AES Corporation (NYSE:AES) 956.7 9,263 20,312 16,855 30,383 14,119 4,133 2.15x 7.35x 1.82x 4.91x

E.ON Climate & Renew ables North America, Inc. 726.9 - - - - - - - - - -

John Deere Renew ables LLc 527.3 - - - - - - - - - -

enXco, Inc. 527.0 - - - - - - - - - -

Shell Wind Energy Ltd. 449.0 - - - - - - - - - -

Puget Sound Energy Inc. 385.2 - 3,383 3,305 - 3,329 740 - - - 4.57x

Duke Energy Corporation (NYSE:DUK) 321.5 20,982 17,015 15,418 36,536 12,455 4,479 2.93x 8.16x 0.73x 3.80x

American Electric Pow er Co., Inc. (NYSE:AEP) 310.5 15,953 17,941 17,088 33,102 13,489 4,431 2.45x 7.47x 1.07x 4.05x

Eurus Energy America Corporation 296.6 - - - - - - - - - -

Noble Environmental Pow er, LLC 282.0 - 1,214 1,189 - (30) (83) - - - -14.67x

Enel North America, Inc. 249.3 - 83 70 - 57 28 - - - 2.99x

Pricing Date Maturity

Date

Issuer Security Type Seniority

Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]

Private Placement Features [Ultimate

Parent] [Target/Issuer]

May-11-2007 May-15-2047 Westar Energy,

Inc. (NYSE:WR)

Preferred

Security

Preferred 150.0 150.0 6.1 Fixed BBB+ (Apr-27-

2010)

Westar

Energy, Inc.

(NYSE:WR)

05/10/2002 Private

Placement

(Target/Issuer: Westar

Energy, Inc. (NYSE:WR)) -

Rule 144A

05/10/2002 Private Placement

(Target/Issuer: Westar Energy, Inc.

(NYSE:WR)) - Rule 144A

Jul-08-2002 Jul-01-2042 Northern States

Power (MN)

Preferred

Security

Senior

Unsecured

175.0 - 8.0 Fixed BBB- (Jul-16-

2002)

Xcel Energy

Inc.

(NYSE:XEL)

- 11/18/2002 Private Placement

(Target/Issuer: Xcel Energy Inc.

(NYSE:XEL)) - Convertible Debt



(NYSE:XEL)) - Rule 144A

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Feb-03-2010 Mar-01-2040 Florida Power &

Light Co.

Corporate

Debentures

Senior

Secured

500.0 500.0 5.69 Fixed A (Feb-5-

2010)

FPL Group

Inc.

(NYSE:FPL)

04/24/2006 Private

Placement

(Target/Issuer: Florida

Power & Light Co.) -

Regulation S

4/24/2006 Private

Placement


Power & Light Co.) - Rule

144A

-

Nov-09-2009 Nov-01-2039 Northern States

Power (MN)

Corporate

Debentures

Senior

Secured

300.0 300.0 5.35 Fixed A (Nov-10-

2009)

Xcel Energy

Inc.

(NYSE:XEL)







Jul-07-2009 Jul-15-2039 Interstate Power

& Light

Company

Corporate

Debentures

Senior

Unsecured

300.0 300.0 6.25 Fixed BBB+ (Jul-7-

2009)

Alliant

Energy

Corporation

(NYSE:LNT)

12/18/2002 Private

Placement

(Target/Issuer: Interstate

Power & Light Company) -

Rule 144A

-

Mar-11-2009 Apr-01-2039 Florida Power &

Light Co.

Corporate

Debentures

Senior

Secured

500.0 500.0 5.96 Fixed A (Apr-21-

2009)

FPL Group

Inc.

(NYSE:FPL)

04/24/2006 Private

Placement



Regulation S

4/24/2006 Private

Placement



144A

-

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Jan-05-2009 Jan-15-2039 PacifiCorp Corporate

Debentures

Senior

Secured

650.0 650.0 6.0 Fixed A (Mar-27-

2009)

MidAmerican

Energy

Holdings

Company


(Target/Issuer: MidAmerican Energy

Holdings Company) - Rule 144A



Holdings Company) - Equity Line

Aug-06-2008 Aug-01-2038 Public Service

Co. of Colorado

Corporate

Debentures

Senior

Secured

300.0 300.0 6.5 Fixed A (Aug-15-

2008)

Xcel Energy

Inc.

(NYSE:XEL)







Jul-14-2008 Jul-15-2038 PacifiCorp Corporate

Debentures

Senior

Secured

300.0 300.0 6.35 Fixed A (Mar-27-

2009)

MidAmerican

Energy

Holdings

Company







Jan-10-2008 Feb-01-2038 Florida Power &

Light Co.

Corporate

Debentures

Senior

Secured

600.0 600.0 5.95 Fixed A (Jan-15-

2008)

FPL Group

Inc.

(NYSE:FPL)

04/24/2006 Private

Placement



Regulation S

4/24/2006 Private

Placement



144A

-

Aug-14-2007 Dec-15-2037 Kansas Gas and

Electric

Company

Corporate

Debentures

Senior

Secured

175.0 175.0 6.53 Fixed - Westar

Energy, Inc.

(NYSE:WR)




CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Oct-15-2007 Dec-15-2037 Kansas Gas and

Electric

Company

Corporate

Debentures

Senior

Unsecured

1.0 75.0 6.53 Fixed - Westar

Energy, Inc.

(NYSE:WR)




Sep-28-2007 Oct-15-2037 PacifiCorp Corporate

Debentures

Senior

Secured

600.0 600.0 6.25 Fixed A (Mar-27-

2009)

MidAmerican

Energy

Holdings

Company







Aug-08-2007 Sep-01-2037 Public Service

Co. of Colorado

Corporate

Debentures

Senior

Secured

350.0 350.0 6.25 Fixed A (Oct-16-

2007)

Xcel Energy

Inc.

(NYSE:XEL)







Jun-19-2007 Jul-01-2037 Northern States

Power (MN)

Corporate

Debentures

Senior

Secured

350.0 350.0 6.2 Fixed A (Oct-16-

2007)

Xcel Energy

Inc.

(NYSE:XEL)







Apr-12-2007 May-01-2037 Florida Power &

Light Co.

Corporate

Debentures

Senior

Secured

300.0 300.0 5.85 Fixed A (Apr-16-

2007)

FPL Group

Inc.

(NYSE:FPL)

04/24/2006 Private

Placement



Regulation S

4/24/2006 Private

Placement



144A

-

CONFIDENTIAL


Source: Capital IQ (2010)

There may be untapped opportunity in securitizing land leases from utility scale projects and or PPAs and RECs from community or small wind projects. One

company in this space is American Wind Power Capital: a company owned by Barclays Natural Resource Investments and NGP Energy Technologies Partners.

Small wind is still a nascent market segment and as such even more dependent on government policies and related developments in the electric grid that enable

distributed generation. Securitization of existing project cashflows may provide a near-term opportunity to develop a structure which can then be rolled out to



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Mar-09-2007 Apr-01-2037 PacifiCorp Corporate

Debentures

Senior

Unsecured

1.0 20.0 5.75 Fixed - MidAmerican

Energy

Holdings

Company








Debentures

Senior

Secured

600.0 600.0 5.75 Fixed A (Mar-27-

2009)

MidAmerican

Energy

Holdings

Company








Debentures

Senior

Unsecured

28.0 28.0 5.75 Fixed A (Mar-27-

2009)

MidAmerican

Energy

Holdings

Company







CONFIDENTIAL


SOLAR ENERGY

MARKET POTENTIAL

Total installed PV capacity in the U.S. is currently over 2,000 MW (SEIA, 2010). Theoretically, the U.S. market can grow to 206,000 GW of installed PV capacity.

Map of US Solar Photovoltaic Resources

CONFIDENTIAL


After factoring in costs, the speed at which upgrades to the electric grid are occurring, and the location of

transmission networks, Bloomberg New Energy Finance estimates that 20 GW of energy will come from

solar PV by 2030.

STATE OF THE MARKET

Installed PV capacity in the U.S. by state is shown in the diagram below. States with the most MW of PV

generation capacity are California, NJ, Nevada, and Colorado.

Source: SEIA data (2010)

The figure at right from SEIA shows annual capacity growth for both PV and solar thermal. According to

the same source, there is currently 6,470

MW of solar capacity under

development, and an additional 67 MW

under construction.

LCOE is affected most significantly by

panel costs, though attention must also

be paid to inverters, installation, and on-

going maintenance activities.

Additionally, it must be noted that solar

PV is a distributed generation

technology. While wind generates a

large amount of power in a centralized,

large-scale farm and sends it out to the grid, solar is installed in small units at what is typically the point

0

200

400

600

800

1000

1200

Cumulative Installed Capacity of U.S. Grid-

Connected PV a/o 2009 (MW)

CONFIDENTIAL


of use for electricity. Utility-scale PV farms do exist, yet much of the demonstrated growth in the solar PV

sector has come from residential applications – i.e. small-scale, distributed power plants (see diagram at

right for proportion of growth from utility-scale, residential, and non-residential projects (SEIA, 2010).)

Consequently, upgrades to the electric grid are necessary for solar to be useful on a wide scale. The

electric grid is discussed in detail in the section that follows this one on solar PV.

Costs, output, business models, and financing structures are detailed here and then the total investment

required is calculated.

Cost

While wind is cost competitive in most regions (after government incentives), solar PV is not. Costs have

come down over the past few years, as certain PV technologies have achieved scale; however, the cost in

2009 was still $5.5/W for large-scale systems (See diagram below from SEIA, 2010).

The largest cost factor in a solar PV project is the panels themselves (a.k.a. modules). This is shown in the

diagram below.

Source: Solar Choice, n.d.

CONFIDENTIAL


Modules typically account for 50% of installed system costs (DOE, 2010). This is true for all sizes of

installations, as seen in the diagram below.

Source: Wiser (2009)

As module costs have decreased, system sizes have increased. In both residential and commercial grid-

connected PV, the solar system size has been growing. The average size of a residential installation was

4.8 kW in 2008, up from 2.5 kW in 1999. While the average size of non-residential systems was 106 kW in

2008, systems larger than 500 kW accounted for 46% of annual installations in 2008, up from 19% in 2005.

According to the DOE, overhead, profit, and regulatory compliance (e.g., permitting, interconnection,

rebate application – see diagram below for an outline of the steps involved in setting up a solar project) comprise

a larger percentage of total installed costs for smaller residential systems than larger non-residential

systems. In other words, economies of scale are not linear: they are greatest for systems smaller than 5

kW and larger than 250 kW (DOE, 2010).

Source: Feo & Tracy (2009)

CONFIDENTIAL


Siting is important as there may be permitting, environmental, and transmission issues. Solar thermal, in

particular, has faced hurdles: solar resources are strongest in the deserts of Arizona and its environs yet

deserts lack water and contain endangered species. Solar thermal generally requires significant amounts

of water, while both it and solar PV developers seek to situate their projects in areas where unique species

will be disturbedxxiv. Sites also determine the spectrum of components required in a solar PV system: to

capture the maximum incident solar radiation, panels may need to be mounted at a tilt or rotated to track

the sun. This is discussed further below.

Output

Energy produced from solar photovoltaic resources is a function of insolationxxv (inclusive of seasonal

variation). U.S. solar insolation generally ranges from 1,350–2,500 kWh/m2/year.

PV is commonly measured as kilowatt hours per year per kilowatt peak ratingxxvi.

Solar cell type, module type, system design (layout of array, storage, voltage control, inverters, etc.) and

installation, module reliability, and operations and maintenance all factor into system outputxxvii. The

diagrams below describe PV cells, modules, systems, and efficiencies.

PV cells technologies that are most common include crystalline silicon and thin film. Crystalline silicon

category includes monocrystalline and multicrystalline, which account for ~84% of all PV produced

globally in 2008 (Bartlett et al. 2009). Crystalline silicon cells produce electricity via semiconductor

material, which is itself made of highly refined polysilicon feedstock. Thin-film cells produce electricity

via thin layers of a variety of semiconductor materials, including amorphous silicon (a-Si), copper indium

diselenide (CIS), copper indium gallium diselenide (CIGS), and cadmium telluride (CdTe). Multi-junction

thin film cells use multiple layers of semiconductor materials to absorb and convert more of the solar

spectrum into electricity than that converted by single-junction cells (DOE, 2010).

Source: University of Michigan (2008)

Average efficiencies for the primary commercially-used solar cell technologies from 1999-2008 are

pictured below.

Photovoltaic Technologies

Flat Plate Concentrators

Thin Films Single Crystal Polycrystalline Spheral

Amorphous Si licon

MultijunctionSingle Junction Multijunction (mechanical contact)

CIS, CdTe, other

Photovoltaic Technologies

CONFIDENTIAL


Source: DOE (2010)

PV systems are comprised cells, modules, and arrays placed in or on buildings or on grounds and wired

together to capture the DC electricity produced by the modules. Siting is important as there may be

permitting, environmental, and transmission issues – as well as need for tilted or tracking systems.


Higher-efficiency modules typically require less installation area per watt of electricity production and

incur lower balance-of-systems costs (i.e., wiring, racking, and other system installation costs) per watt

than lower-efficiency modules (DOE, 2010). The table below shows prices, manufacturing costs, and

conversion efficiencies for a variety of solar PV technologies.

Photovoltaic Building Blocks

Cell

Module

Array

System

Includes storage,voltage regulation,

inverters, etc.

CONFIDENTIAL


Source: DOE (2010)

Fixed-tilt capacity factors xxviii for solar PV systems range from 14–24%, depending on geographical

location. 1- and 2-axis tracking systems’ capacity factors range from 18-33%. The diagram below shows

capacity factors for different tilts and tracking systems in 7 U.S. locations.

Source: DOE (2010)

Inverterxxix efficiency is the next critical factor: maximum inverter efficiency was 95.5% in 2008 (Knoll and

Kreutzmann 2008). Inverter warranties have increased from 1-3 years to now cover 5 on average (DOE,

2010). In the meantime, module reliability has increased, as evidenced by real world experience with

long-term panel output. The DOE states that real world experience has shown energy output of a 25-year

old system to be at least 80% of rated output, which is the standard specification in manufacturer

warranties.

It should be noted that PV farms have zero on-going fuel costs.

The range of levelized costs of solar PV energy is $0.20–$0.80 per kWh for residential rooftop PV,

exclusive of government incentives (REN21 2008). Due to average system size and economies of scale, the

LCOE for utility-scale systems is lower than this.

CONFIDENTIAL


Despite this, much of the growth in solar capacity has been in residential systems. Given the cost of solar

PV, the pace of growth in capacity is far lower than that required to equal 20 GW by 2030 (see diagram

below).

Source: SEIA (2010)

Government Policies

Government subsidy is consequently essential to the development of solar PV. As such, Federal and State

governments have created a number of solar-specific policies, which are outlined below.

Federal policies:

On the Federal level, government incentives subsidize the cost of installation with 30% investment tax

credit or cash grant in its place and cost of production with 5-year accelerated depreciation (MACRs).

Solar qualifies for 5-year, double, declining-balance depreciation. In most cases, 100% of the cost of a PV

project –after having been reduced by the amount of non-taxable cash incentives and one-half of the

value of the investment tax credit, if claimed– can be depreciated according to the accelerated schedule

(Bolinger, 2009).

State policies:

State policies are even more significant drivers of solar PV – though this also implies that market

forecasting and strategic planning for this renewable energy sector are more complex than for others.

Renewable Portfolio Standards: A number of states have renewable portfolio standards (RPS)

with solar-specific carve-outs. These are illustrated below.

CONFIDENTIAL


SRECs: New Jersey and Colorado are two markets that employ Solar-specific Renewable Energy

Credits (SRECs) to incentivize installation of PV generation capacity and on-going production

One SREC represents 1,000 kWh (or 1 MWh) of solar electric production. SRECs can account for

as much as 40-80% of the revenues of a solar project funded by third-parties (DOE, 2010).

In Colorado, 10 kW-100 kW non-residential systems receive a $2/Watt capacity-based incentive

(CBI) as well as a 20-year SREC contract priced at $0.115/kWh. In New Jersey, non-residential

systems compete for 15-year solar REC contracts with the electric distribution companies. 2010

SREC prices are:

Source: Flett Exchange (2010)

Interconnection: A number of states have clarified rules for interconnection of small generation

systems. Some states require developers to purchase additional liability insurance when

connecting to the grid, while others do not; levels of insurance required vary with system size.

Additional regulatory measures: A number of cities have revised planning and permitting

policies to simplify the process for solar PV development (DOE, 2009). Thirty-one states have

State renewable portfolio standard with solar / distributed generation (DG) provision

State renewable portfolio goal with solar / distributed generation provision

Source: www.dsireusa.org / March 2010Solar water heating counts toward solar provision

WA: double credit for DG

NV: 1.5% solar x 2025;

2.4 - 2.45 multiplier for PV

UT: 2.4 multiplier

for solar-electric

AZ: 4.5% DG x 2025

NM: 4% solar-electric x 2020 0.6%

DG by 2020

TX: double credit for non-wind

(non-wind goal: 500 MW)

CO: 0.8% solar-electric

x 2020

MO: 0.3% solar-

electric x 2021

MI: triple credit for solar-

electric

OH: 0.5% solar-

electric x 2025

NC: 0.2% solar

x 2018MD: 2% solar-electric x 2022

DC: 0.4% solar x 2020

NY: 0.1312% customer-

sited x 2013

DE: 2.005% PV x 2019;

triple credit for PV

NH: 0.3% solar-

electric x 2014

NJ: 5,316 GWh solar-

electric x 2026

PA: 0.5% PV x 2020

MA: 400 MW PV x 2020OR: 20 MW solar PV x 2020;

double credit for PV

IL: 1.5% PV

x 2025 WV: various multipliers

16 states + DC

have an RPS with solar/DG

provisions

DC

NJ $664.75

PA $300.00

MD $387.50

OH $300.00

DC $400.00

DE No trading

MA Began trading February 2010

2010 SREC Prices

CONFIDENTIAL


solar easements that allow for the rights to existing solar access on the part of one property owner

to be secured from another property owner whose property could be developed in such a way as

to restrict the solar resource. These easements transfer with property titles.

Source: Barnes (2009)

Feed-in tariffs (FITs): FITs require utilities to purchase electricity from eligible renewable

systems at a guaranteed price over a fixed period. The tariff price can consist of a fixed or

variable premium to the market price of electricity. This mechanism has been used

extensively in Europe and is beginning to gain traction in the US. At present, five states,

including, California, Hawaii, Maine, and Vermont, and 2 municipal utilities (Gainesville

and SMUD), have adopted FITs.

Property-Assessed Clean Energy bonds (PACE): Some local governments are using

special property tax assessments to enable municipal or third-party financing for solar

and energy efficiency projects on private property. Local governments first create special

tax districts. Building owners then apply for financing via the program for their PV

projects. After approval, construction is executed and financing dispensed. Building

owners re-pay the micro-loans via a new line item on property tax bills. This program

eliminates the burden the high upfront costs of PV installation and reduces pressure for

quick payback, as the tax assessment transfers to new owners upon sale of the building,

until the loan amount is repaid. Rules regarding acceleration of the assessment in the

event of bankruptcy or sale are set on a local level.

DC

Solar Easements Provision Solar Rights Provision Solar Easements and Solar Rights Provisions

CONFIDENTIAL


Tax Credits: At the state level, there are ITCs, PTCs, sales tax, and property tax credits. The

diagram below illustrates states offering PV-specific tax incentives.

Grants, Rebates, and Performance-Based cash Incentives (PBIs): Twenty states now have rebates

and/or performance-based cash incentives for solar PV for a fixed number of years (e.g., 3-5

years) after start of commercial operations.

PACE financing authorized

CA: 2008

NM: 2009

CO: 2008

WI: 2009

VT: 2009

MD: 2009

VA: 2009

OK: 2009

TX: 2009 LA: 2009

IL: 2009OH: 2009NV: 2009

OR: 2009NY: 2009

NC: 2009

FL: Existing

Authority*

HI: Existing

Authority*

18 states authorize PACE (16 states have passed legislation and 2 states permit it

based on existing law)

DC


CONFIDENTIAL


Under Step 5 of the California Solar Initiative incentive schedule, California has a 5-year PBI of

$0.22/kWh that reduces the amount of other revenue required by almost $0.09/kWh on a 20-year

levelized basis according to analysis by the Lawrence Berkeley National Laboratory in 2009. A

higher PBI of $0.32/kWh is available for tax-exempt system owners.

The net of costs and subsidies is a nationwide average installed cost for commercial PV systems of

between $4-8 per WDC, as shown in the chart below.

NOTE: Assumptions include that all systems >10 kW are commercial (unless identified otherwise) and that state/utility cash

incentives for commercial systems are taxed at a Federal corporate tax rate of 35% plus the prevailing state corporate tax rate,

without reducing the basis of the Federal ITC.

Source: Wiser, Barbose, Peterman, & Darghouth (2009)

More specifically, average net installed costs range from $3.1 -5.7 per watt, across different states, as

shown in the chart below.

State Rebates & PBIs for PVwww.dsireusa.org May 2009

• 20 state rebate (+ DC)

program & PBIs*

• 26 state grant

programs (not shown

on map)

• 31 non-state PBIs

(not shown on map)

• 77 utility rebate

programs (not shown

on map)

DE: ≤35%

$4/W

VT: $1.75-3.50/W

MD: $2.50/W

$2-2.25/W

50%,

$3k max

≤35%

30%

NY: $2-5/W

$2-3/W

≤$3.50/W

$2.30-4.60/W

ME: $2K max

NH: $3/W

NJ: $1-1.75/W

SRECs: ~$0.46/kWh

CT: $2.50-4/W

MA: $1-4.40/W

* Includes RPS-inspired utility rebate programs in AZ, CO & NV

15 - 54¢/kWh

$1-2.25/W

≤$3.25/W

≤50¢/kWh, 5 yrs.

DC: $1-3/W

CONFIDENTIAL


Assumptions include that all systems >10 kW are commercial (unless identified otherwise) and that state/utility cash incentives for

commercial systems are taxed at a Federal corporate tax rate of 35% plus the prevailing state corporate tax rate, without reducing

the basis of the Federal ITC.

Source: Wiser et al. (2009)

Business Models

Business models include IPP (merchant or PPA) and utility-owned. SRECs are sold both in forward

contracts and on the spot market. The most prominent model uses a PPA (pictured below for a residential

installation).

Source: NREL (2009)

According to Greentech Media, approximately 80% of the commercial market used PPAs in 2008. With

this structure, commercial businesses ‚host‛ PV systems without purchasing them. Solar developers own

and operate them, securing the up-front investment capital and maintaining their performance over time.

CONFIDENTIAL


Developers can own the systems in partnership with tax equity investors, as described in the wind energy

section above; in these cases, developers essentially lease the systems from the tax equity investors until

the partnership flip point.

Utilities sign PPAs for the electricity generated by the system with developers. Possession of such a long-

term off take agreement enables developers to obtain lower-cost financing, which, ideally, is passed on to

the consumer through relatively lower power prices (DOE, 2010). Generally, payments are made for plant

capacity and energy production typically over a 20 year period from the start of commercial operation.

PPA prices generally escalate by 1-5%, annually (Bolinger, 2009). Some developers prefer to use floating

PPA rates that reference utility prices (e.g. 5% discount to the given market rate). The floating rate

method eliminates ability of site hosts to hedge prices.

Project owners own and sell SRECs along with electricity to utilities or third parties. Depth of the SREC

market varies according to the interconnect region and utility regulations in the given state; in New

Jersey the anecdotal evidence points to a three-year forward market which is used more frequently than

pure merchant sales of SRECs.

After year six, when the project’s tax benefits are typically exhausted, PPA deals usually enable site hosts

to purchase the solar systems at fair market value. PPA prices are sometimes structured to step up

significantly after year 6 to encourage early buyout.


Incentives – e.g. ITC, grant, SREC, etc. – affect financing structures. The primary forms of financing

structures include balance sheet financing, operating leases, and 3rd party ownership with PPAs and

partnership flips (See wind energy section for more information on partnership flip structures), and property

assessed clean energy (PACE) bonds.

Balance sheet financing: Project-level debt may support balance sheet financing but the evidence points

more heavily to projects simply being capitalized on site hosts’ balance sheets, using an internal mix of

corporate-level debt and equity.

Solar leasing: To exploit federal tax incentives, third-party lessors finance and own PV systems, hosted, as

above, by commercial businesses. Business owners pay to use the equipment, not to purchase the

electricity; in other words, the lease payment stays the same irrespective of fluctuations in system output.

Lease payment amounts depend on project tenor and residual value as well as cash or tax incentives and

implicit interest rates. A sale-leaseback structure is pictured below.

CONFIDENTIAL



According to the Lawrence Berkeley National Laboratory, lease tenors range from 7-15 years. Residual

values are as high as 30% (Bolinger, 2009). Payments can be scheduled to step up or down over the course

of the contract; for instance, lease payments can be scheduled to increase when a 3-5 year performance-

based incentives (PBI) ends.

Excess generation can be net metered, earning commercial business owners credits on their companies’

electricity bills.

The challenges of this model include the lack of incentive by the solar developer to maintain optimal

performance (as the customer’s payments are unrelated to performance) as well as potential regulatory

challenges to producing power without first qualifying the generation facility.

A second lease structure is the lease pass-through. This is pictured below.

CONFIDENTIAL



In this structure, there must be an election to treat lessees as owners of panels for tax credit purposes in

accord with IRC Section 48(d)(1) / Treasury Regulation 1.48-4(f). Ownership of system and depreciation

deductions can only be with lessors. Flexible ownership of lessors is defined by master tenant LP Lessees

are required to recognize income equal to 50% of the tax credits in accord with IRC Section 48(d)(5).

Investors earn an annual preferred return on capital –1-5% and do not have to absorb 99% of losses.

Investors are allowed a write-off of capital account (capital loss) upon disposition of ownership interest in

Master Tenant. Ownership interest may flip down to approximately 5% after 5-year recapture period. In

this structure, exist is through partnership flip (see below), developers exercising buy out rights to

purchase ownership from investors for fair market value of partnership (i.e. call option), or investors

exercising options requiring developers to make small payments to buyout investors (i.e. a put option), or

early buy out options. Put/call cash payments equal to the greater of FMV of ownership interest (after

flip) or amount of cash typically enable the project to achieve desired IRR.

Third-party ownership with PPAs and partnership flips: The primary challenges to third-party

ownership include: incentive levels declining faster than system costs; credit quality of the third-party

owner; and legality. The last challenge involves the question of whether or not third-party-owned

systems should be allowed to net meter and whether third-parties should be regulated as utilities since

they sell power to one or more ratepayers (Bolinger, 2009).

PPAs: PPAs are generally 10-20 years in length for distributed systems and 20-30 years for utility-scale

projects. They can have renewal clauses. Electricity prices are generally fixed and escalated at a stated

rate, though they can be variable or based on a discount from retail electricity prices in distributed

CONFIDENTIAL


projects and wholesale prices in utility-scale projects. Unanticipated price changes can be negotiated case-

by-case.

Ownership of SRECs is also defined in the PPA. Utility-scale projects often sell electricity and SRECs in a

bundle.

In some PPAs, systems are subject to performance tests. Utility-scale projects typically have a set of

completion tests and milestones.

At the end of the term, the system owner can remove the systems, host’s can purchase the systems after 5

years or at the end of the agreement with the price defined as fair market value (FMV) at the time of

purchase, or the greater of the FMV and a stipulated price.

Utility-scale projects typically guarantee a minimum volume of electricity delivery while distributed

generation projects only promise delivery of the electricity produced by the system – no matter what the

amount. Still, as the PPA promises delivery of the electricity produced, system owners have

responsibility to ensure system operations. The precise details of O&M are stipulated in the PPA.

Force majeure is outlined in the PPA with a non-standard, negotiated agreement on the bearer of

responsibility in the event of significant damage.

Hosts’ responsibilities include giving system owners access to the site and system, helping to obtain

permits, not putting liens on the system, and not blocking sunlight. Hosts must explicitly state their lack

of title to the system. Finally, if the customer moves or goes out of business, they must typically provide

an alternate location for the system, pay for its relocation, and continue with the PPA at the new location.

Relocation siting parameters must be outlined in detail – e.g. minimum insolation, approval rights, etc.

Compensation for lost revenue to system owners can be negotiated. An alternative to relocation is for the

system owner to transfer the PPA to the new occupant of the original site; this is subject to investor

approval as mush of the financing of the project relies on the credit quality of the host.

Both project developer and host are required to insure the system.

Partnership Flips: The motivation for a partnership flip structure is to exploit tax credits. Applicable

projects costs upon which to calculate the ITC and cash grant, include the equipment – solar panels,

mounts, racks, wiring, inverters, etc. – hard construction costs, and direct and indirect installation costs.

Costs that generally cannot be capitalized or otherwise ineligible for inclusion include: construction

interest, permanent loan fees, syndication costs, organizational costs, costs allocated to the host buildings,

solar property or roof repair, parking garage/car port installations, transmission lines to grid costs funded

by certain subsidies (Section136) (Feo & Tracy, 2009).

A diagram of a partnership flip structure is pictured below.

CONFIDENTIAL



Tax credits can only be monetized to offset losses against passive income and, for closely-held c-

corporations, ‚net active income‛. The definition of ‚active‛ is spending 500 hours a year on a given

activity. According to Novogradac and Milbank, rental activities are passive by definition and PPAs,

leases and service contracts may be considered rental activities (Reg. Section 1.469-1T(e)(3)). Losses a

partner can deduct are limited to the amount at-risk, defined as capital contributions plus partner loans.

Non-recourse debt generally provides no At-Risk basis: the credit base is typically reduced by the amount

of ‚non-qualified‛ non-recourse debt financing in a project. Qualified Commercial Financing counts, on

the other hand, counts towards the at-risk basis. Projects typically require 20% equity so that the LTV

ratio does not exceed 80% (Feo & Tracy, 2009).

Risks include change in ownership within the 5 years (i.e. sale or foreclosure) or cessation of energy

production. Investors must have greater than a 66 2/3% ownership share of the qualified solar electric

facility at the time of its being placed in service to receive the tax credits. After being placed in service, the

investor must maintain a greater than 33 1/3% percent interest in the property, based on the value of the

property in the year during which it was placed in service (Feo & Tracy, 2009).

PACE: www.pacenow.org, defines the structure as follows: ‚Property owners borrow money from a

newly established ‘municipal financing district’ to finance energy retrofits (efficiency measures and micro

renewable energy) and repay over 20 years through annual special tax on property tax bill‛. In this way,

the upfront cost of a solar energy system is distributed across the life of the system and can be transferred

to new property owners.

The goal of private-sector PACE advocates is to create a new asset class of securitized cashflows.

Government, on the other hand, is seeking to incentivize people to limit pressures on the electric grid

http://www.pacenow.org/

CONFIDENTIAL


through investment in on-site electricity generation and energy efficiency retrofits. The government’s

support is widespread: the Waxman Markey Bill has language that provides DOE guarantees for PACE

loans.

The PACE model is still in its infancy. One issue that arose in the past half year is anticipated backlash by

existing lenders who become subordinate to the new tax assessment, which takes first lien on a given

property. PACE advocates state only past due tax liens become due in the event of default, and this

amount typically equals less than 1% of mortgage/home value. Due to the early stage of the model’s

development, the volume of capital that has been distributed since the autumn of 2008 using this model is

on the order of $10-$20MM.

The choice of financing structure can be diagrammed as:


Since the 2009 ARRA enabled utilities to claim the Federal ITC, there has been increasing direct

investment and ownership by utilities.

The table below shows IRRs and assumptions for the three main forms of financing structures - balance

sheet, operating lease, and third-party PPA.

CONFIDENTIAL



According to NREL, debt capital is just beginning to support the growth of the solar industry. Despite an

absence of observed project-level debt, the Lawrence Berkeley National Laboratory estimates that projects

can achieve 30-46% leverage with a 1.4x DSCR and a 7% coupon. Novogradac and Millbank uses 28%

leverage for a permanent loan with a 15-year term and 8% coupon. Year-on-year DSCRs range from 1.54x

in year 1 to 2.03 by year 7 (Feo & Tracy, 2009).

CONFIDENTIAL



Systems larger than 500 kW make up a significant proportion of non-residential installations. Average

capital costs for solar PV is between $3,500-4,000/kW (Lazard, 2008). Taking the median between the two,

an average 500 kW project should cost $3.23 million in 2010 dollar termsxxx. All told, according to the DOE,

the aggregate amount of money needed for financing solar PV projects and build-up of manufacturing

capacity in the U.S. is $1.4 trillion from debt investors and $0.15 trillion from equity (Cory, 2009).

Companies in the solar energy space are presented below.

Example of Typical Financing Terms

One finacing company active in wind and solar projects would structure a deal using a flip

agreement. Both project developer and financier would invest capital at a given proportion –

e.g. 90%:10%. The financier would receive cash distributions in proportion with the amount

of equity invested (e.g. 90%) and almost all the income distributed by the proejct (99%) until

all tax credits were exhausted).

After an agreed-upon IRR (e.g. 7-10%) were achieved, mostly likely in 8-12 years from COD,

the cash distribution would change to a new ratio (e.g. 30/70 cash share). Income distribution

would stay the same. Deals would be underwritten for a 20-25 year life.

Developers would be expected to stay on and operate the projects receiving an annual

management fee.

According to the financier ‚Specific accounting rules to make sure that tax and book basis

were made whole at deal end were tricky and involved Minimum Gain/Loss, 704 (a) and

704(c) treatment, bonus depreciation,‛ among others.

The financing company would internally lever the projects using corporate bond/debt raises.

The perceived gap in the market was the lack of long tenored financing (>10yrs) that would

allow for infrastructure funds to get adequate returns of 15-20%. (R. Pryor, personal

communication, April 9, 2010).

CONFIDENTIAL


Top Utility-Scale Solar Power Owners (a/o 2/25/10)

Source: SEIA (2010) & Capital IQ (2010)

Company Name MW* Market

Capitalization

Latest

Total Debt

LTM

Net Debt

LTM

Total

Enterprise

Value Latest

Total

Revenue

LTM

EBITDA

LTM

TEV/LTM

Total Rev

TEV/LTM

EBITDA

Total Debt /

Market Cap

Total Debt /

EBITDA

Needle Mountain Power Authority 1,200

First Solar 1,173 12,280.2 162.5 (608.7) 11,671.5 2,066.2 831.7 5.65x 14.03x 0.01x 0.20x

Nextlight Renewable Power 1,077 - - - - - - - - - -

Fotowatio / MMA 595 - - - - - - - - - -

Solargen 420 149.6 - (1.0) 152.8 - (2.6) - -58.75x - -

Solar Energy Initiatives, Inc. 400 6.2 0.4 (0.2) 6.5 5.3 (3.1) 1.23x -2.10x 0.06x -0.13x

Corporacion Gestamp / GA Solar 300 - - - - - - - - - -

SunPower 277 149.6 785.5 169.5 1,786.3 1,524.3 164.6 1.17x 10.85x 5.25x 4.77x

Pacific Solar Investments 150 - - - - - - - - - -

Solar Project Solutions 130 - - - - - - - - - -

FPL Group Inc. (NYSE:FPL) 110 20,733 18,889 18,651 39,384 15,643 4,598 2.52x 8.57x 0.90x 4.11x

Vidler Water Co. 100 - - - - - - - - - -

PowerWorks 80 - - - - - - - - - -

Teanaway Solar Reserve, LLC 75 - - - - - - - - - -

SunEdison 66 - - 364.9 - 105.4 (47.1) - - - -

BP Solar 59 - - - - - - - - - -

First Solar / Sempra 58 - - - - - - - - - -

Recurrent Energy 55 - - - - - - - - - -

Chevron Energy Solutions 45 - - - - - - - - - -

juwi solar, Inc. 39 - - - - - - - - - -

American Capital Energy 25 - - - - - - - - - -

Energy 5.0 25 - - - - - - - - - -

Acciona 20 - - - - - - - - - -

Green Energy Capital Partners 20 - - - - - - - - - -

CONFIDENTIAL


Solar Debt (2009-present)


Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Apr-27-2010 Apr-26-2030 Electricite de

France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 1,990.0 1,992.69 4.625 Fixed A+ (Apr-28-

2010)

Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement

(Target/Issuer: Electricite

de France SA

(ENXTPA:EDF)) - Rule

144A


(Target/Issuer: Electricite de France SA

(ENXTPA:EDF)) - Rule 144A

Mar-29-2010 Sep-29-2017 Electricite de

France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 376.5 370.85 2.25 Fixed - Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Mar-23-2010 Mar-23-2020 Iberdrola

Finanzas S.A.U.

Corporate DebenturesSenior Unsecured 676.6 664.23 4.125 Fixed A- (Mar-16-

2010)

Iberdrola SA

(CATS:IBE)


(Target/Issuer: Iberdrola SA

(CATS:IBE)) - Cross-Border






(CATS:IBE)) - Cross-Bord

Jan-26-2010 Jan-27-2020 Electricite de

France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 1,400.0 1,400.0 4.6 Fixed - Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jan-21-2010 Jan-21-2013 Iberdrola

Finanzas S.A.U.

Corporate DebenturesSenior Unsecured 100.0 100.0 0.905 Variable - Iberdrola SA

(CATS:IBE)











France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]




France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Nov-21-2009 Nov-21-2014 Tata Pow er Co.

Ltd.

(BSE:500400)

Corporate ConvertibleSubordinate 250.0 250.0 1.75 Fixed - Tata Pow er

Co. Ltd.

(BSE:500400)

04/30/2007 Private

Placement

(Target/Issuer: Tata Pow er

Co. Ltd. (BSE:500400)) -

Warrants


(Target/Issuer: Tata Pow er Co. Ltd.

(BSE:500400)) - Warrants

Nov-12-2009 Nov-11-2016 EDF Energy

Netw orks Ltd.

Corporate DebenturesSenior Unsecured 495.9 459.1 5.125 Fixed A (Nov-13-

2009)

Electricite de

France SA

(ENXTPA:EDF)





Netw orks Ltd.


2009)

Electricite de

France SA

(ENXTPA:EDF)





Netw orks Ltd.


2009)

Electricite de

France SA

(ENXTPA:EDF)




Nov-02-2009 Nov-02-2018 Southern Gas

Netw orks plc

Corporate DebenturesSenior Unsecured 489.6 459.1 5.125 Fixed BBB (Oct-23-

2009)

Scottish &

Southern

Energy plc

(LSE:SSE)


(Target/Issuer: Scottish & Southern

Energy plc (LSE:SSE)) - Subsequent

Direct Listing

Sep-30-2009 Oct-01-2018 Scottish &

Southern Energy

plc (LSE:SSE)

Corporate DebenturesSenior Unsecured 799.7 765.17 5.0 Fixed A- (Sep-24-

2009)

Scottish &

Southern

Energy plc

(LSE:SSE)

01/07/2009 Private

Placement

(Target/Issuer: Scottish &

Southern Energy plc

(LSE:SSE)) - Subsequent

Direct Listing




Direct Listing

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Sep-29-2009 Sep-30-2024 E.On International

Finance B.V.

Corporate DebenturesSenior Unsecured 132.3 132.02 3.94 Fixed - E.ON AG

(DB:EOAN)

04/15/2008 Private

Placement

(Target/Issuer: E.On

International Finance B.V.) -

Regulation S

4/15/2008 Private

Placement



Rule 144A

-

Sep-11-2009 Sep-11-2024 Electricite de

France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 3,648.3 3,321.16 4.625 Fixed A+ (Sep-10-

2009)

Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jul-17-2009 Jul-17-2014 Electricite de

France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 4,613.5 4,342.64 4.5 Fixed A+ (Jul-17-

2009)

Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jul-09-2009 Oct-09-2014 Electricite de

France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jul-09-2009 Oct-09-2014 Electricite de

France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 53.9 53.12 0 Variable - Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]




France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jul-07-2009 Jul-07-2015 EnBW

International

Finance B.V.

Corporate DebenturesSenior Unsecured 1,047.3 996.35 4.125 Fixed A- (Jul-23-

2009)

EnBW Energie

Baden-

Wuerttemberg

AG (DB:EBK)

- 1/2001 Private Placement

(Target/Issuer: EnBW Energie Baden-

Wuerttemberg AG (DB:EBK)) - Cross-

Border

Jul-07-2009 Jul-07-2039 EnBW

International

Finance B.V.

Corporate DebenturesSenior Unsecured 837.8 797.08 6.125 Fixed A- (Jul-23-

2009)

EnBW Energie

Baden-

Wuerttemberg

AG (DB:EBK)




Border

Jul-01-2009 Jul-01-2022 Iberdrola

Finanzas S.A.U.

Corporate DebenturesSenior Unsecured 329.8 306.07 6.0 Fixed - Iberdrola SA

(CATS:IBE)










Jun-24-2009 Jul-15-2019 Rochester Gas

and Electric

Corp.

Corporate DebenturesSenior Secured 150.0 150.0 5.9 Fixed A- (Jul-8-

2009)

Iberdrola SA

(CATS:IBE)










CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]




France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jul-07-2009 Jul-07-2015 EnBW

International

Finance B.V.

Corporate DebenturesSenior Unsecured 1,047.3 996.35 4.125 Fixed A- (Jul-23-

2009)

EnBW Energie

Baden-

Wuerttemberg

AG (DB:EBK)




Border

Jul-07-2009 Jul-07-2039 EnBW

International

Finance B.V.

Corporate DebenturesSenior Unsecured 837.8 797.08 6.125 Fixed A- (Jul-23-

2009)

EnBW Energie

Baden-

Wuerttemberg

AG (DB:EBK)




Border

Jul-01-2009 Jul-01-2022 Iberdrola

Finanzas S.A.U.


(CATS:IBE)










Jun-24-2009 Jul-15-2019 Rochester Gas

and Electric

Corp.

Corporate DebenturesSenior Secured 150.0 150.0 5.9 Fixed A- (Jul-8-

2009)

Iberdrola SA

(CATS:IBE)










Jun-22-2009 Jun-22-2012 E.On International

Finance B.V.


(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Jun-19-2009 Jun-19-2019 Iberdrola SA

(CATS:IBE)


(CATS:IBE)

06/16/2009 Private

Placement

(Target/Issuer: Iberdrola

SA (CATS:IBE)) - Cross-

Border

6/27/2007 Private

Placement



Border

12/8/2005 Private

Placement



Bord










Jun-02-2009 Jun-02-2034 Electricite de

France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Jun-02-2009 Jun-02-2034 Electricite de

France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




May-29-2009 May-29-2014 E.On International

Finance B.V.


(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



May-27-2009 Nov-30-2011 E.On International

Finance B.V.

Corporate DebenturesSenior Unsecured 1,043.6 996.35 2.5 Fixed A (Jun-4-

2009)

E.ON AG

(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

May-18-2009 Jun-01-2019 Central Maine

Pow er Company

Corporate DebenturesSenior Secured 150.0 150.0 5.7 Fixed A (Sep-16-

2009)

Iberdrola SA

(CATS:IBE)










Mar-27-2009 Mar-27-2012 Electricite de

France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Mar-27-2009 Mar-27-2017 Electricite de

France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




Mar-26-2009 Mar-26-2013 E.On International

Finance B.V.

Corporate DebenturesSenior Unsecured 1,017.8 996.35 4.125 Fixed A (Apr-1-

2009)

E.ON AG

(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Mar-04-2009 Mar-04-2014 Iberdrola

Finanzas S.A.U.

Corporate DebenturesSenior Unsecured 1,888.6 1,992.69 4.875 Fixed A- (Feb-27-

2009)

Iberdrola SA

(CATS:IBE)










Feb-25-2009 Feb-25-2011 E.On International

Finance B.V.


(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

Feb-11-2009 Feb-11-2014 E.On International

Finance B.V.


(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

Feb-05-2009 Feb-05-2014 Scottish &

Southern Energy

plc (LSE:SSE)

Corporate DebenturesSenior Unsecured 1,026.6 1,071.24 5.75 Fixed A- (Aug-21-

2009)

Scottish &

Southern

Energy plc

(LSE:SSE)

01/07/2009 Private

Placement

(Target/Issuer: Scottish &

Southern Energy plc

(LSE:SSE)) - Subsequent

Direct Listing




Direct Listing

CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]



Jan-29-2009 Jan-29-2024 Iberdrola

Finanzas S.A.U.


(CATS:IBE)










Jan-28-2009 Jan-28-2014 E.On International

Finance B.V.

Corporate DebenturesSenior Unsecured 2,318.3 2,324.81 4.875 Fixed A (Feb-2-

2009)

E.ON AG

(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-


France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




CONFIDENTIAL



Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]




Finance B.V.


(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-


France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 2,566.9 2,656.92 5.125 Fixed A+ (Jan-23-

2009)

Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





France SA

(ENXTPA:EDF)

Corporate DebenturesSenior Unsecured 2,566.9 2,656.92 6.25 Fixed A+ (Jan-23-

2009)

Electricite de

France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





Finance B.V.

Corporate DebenturesSenior Unsecured 960.0 1,071.24 6.75 Fixed - E.ON AG

(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-


France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A




CONFIDENTIAL


Source: Capital IQ (2010)

Due to the small-scale distributed nature of solar PV, there are opportunities, again, in securitizing cashflows from existing projects – whether financed through a

lease, PPA, or PACE structure. The challenge will be in detailing the economic drivers, many of which are legislated and subject to political shifts, and accurately

gauging risk over time. The complexity of this challenge necessitates significant due diligence, inflating the cost of development of this new asset class; however, if

the projections for installed capacity and concurrent debt capital requirements of $1.4 trillion between now and 2030 are to be believed, the opportunity for

financial innovators is significant.

Being a distributed generation technology, the solar industry’s development depends on upgrades to the transmission grid. This is discussed in the next section.


Date


Level

Offering

Amount

($USDmm)

Amount

Outstanding

($USDmm)

Coupon

Rate (%)

Coupon

Type

S&P Security

Credit Rating

Ultimate

Parent Name

Private Placement

Features [Issuer]

[Target/Issuer]




France SA

(ENXTPA:EDF)


France SA

(ENXTPA:EDF)

01/22/2010 Private

Placement


de France SA


144A





Finance B.V.

Corporate DebenturesSenior Unsecured 1,968.1 1,992.69 5.5 Fixed A (Jan-21-

2009)

E.ON AG

(DB:EOAN)

04/15/2008 Private

Placement



Regulation S

4/15/2008 Private

Placement



Rule 144A

-

Jan-08-2009 Dec-16-2013 Connecticut

Natural Gas

Corporation

Corporate MTN Senior Unsecured 20.0 20.0 6.5 Fixed - Iberdrola SA

(CATS:IBE)










CONFIDENTIAL


ELECTRICITY

MARKET POTENTIAL

As renewable capacity grows, so do pressures on the electric grid. At present, the US electrical grid serves

335 MM customers with nearly 3,765 Billion kWh of electricity in a year (2007 figures, EIA). In part to

meet this demand and the annual 1% growth in consumer demand for electricity, government entities,

investors, and business owners have invested in renewable energy power generation, as detailed in the

previous sections.

Firstly, renewable energy has specific characteristics, such as intermittency and distributability, which

necessitate additional equipment such as storage and bi-directional meters, in addition to new

transmission lines. For example, solar can produce electricity in a decentralized, or distributed, fashion at

peak use times, but not at night. The current electric grid, built as it was, on the idea of one-directional

flows from large-scale generating stations to customers, is unable to exploit generation from distributed

sites without technology upgrades.

Source: NREL (2010)

To accommodate the growth in renewable and distributed generation while maintaining electric-grid

reliability, investment is required across the spectrum of transmission, distribution, management, and use

(see schematic below).

CONFIDENTIAL


Source: EIA (2010)

Secondly, many of the best renewable resources (e.g. strong and reliable wind, high solar insolation, etc.)

are in remote areas. Power plants in those regions require investment in new transmission lines; however,

existing transmission & distribution (T&D) technologies waste energy. The illustration below shows

renewable resources in the US and existing transmission lines; the diagram that follows it shows energy

and electricity flows in the U.S. inclusive of system losses.

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U.S. Renewable Resource Potential and Existing Transmission Network

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The diagram shows that energy production must exceed energy consumption in order to account for

system losses – i.e. those that occur across the entire spectrum of resource extraction, processing, storage,

and delivery, to secondary energy source conversion, storage, and delivery – not to mention usage and

wastage by end-consumer equipment, appliances, and processes. Each of these processes has caused

electricity to become the largest contributor to emissions in the U.S., at 32.4% of total U.S. emissions.

The diagrams below show energy and electricity flows with greenhouse gas emissions by gross sector

and detailed activity/segment.

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Efficiency can be improved through a variety of supply-side and demand-side measures. While module,

turbine, and system efficiencies have been discussed above, transmission and distribution upgrades can

also eliminate waste – at present, 9% of the energy produced is lost during transmission (EIA, 2008).

The electric T&D and management system was developed in the 60’s and enables transmission and

distribution companies to pass capital expenditures to rate-payersxxxi, via a bureaucratic process.

The process has spawned complexity that has hindered investment into infrastructure upgrades. Seventy

percent of transmission and power transformers are more than twenty-five years old; sixty percent of

circuit breakers are more than thirty years old. While industry analysts expects investments in high

voltage transmission technology, including composite conductors, flexible AC transmission systems

(FACTS), high voltage DC (HVDC), and high temperature super conductors (HTS) in the next few years,

grid development expenditure has increased by only 3.5% since 1998. Moreover, maintenance

expenditure has been decreasing by 1% per year since 1992 (Frost & Sullivan, 2009).

Source: EIA (2010)

According to a report published by Edison Electric Institute (EEI) the United States needs to invest at

least $880 billion in transmission and distribution systems between 2010 and 2030 to maintain reliable

service. Many firms like Goldman Sachs (GS Infrastructure Investment Group - $7.75 Bn), Citi (Citi

Infrastructure Investors - $4 Bn), KKR (KKR Infrastructure Fund - $4 Bn), JPMorgan (JP Morgan Asset

CONFIDENTIAL


Management - $3.1Bn), Alinda (Alinda Capital Partners - $3 Bn) and Morgan Stanley (Morgan Stanley

Infrastructure Partners - $1.4 Bn), and more have recently created infrastructure funds to serve this need.

STATE OF THE MARKET

Despite this, under-investment and ageing equipment has led to the increasing frequency of blackouts

and brownouts: there have been five massive blackouts over the past 40 years, three of which have

occurred in the past nine years (EIA, 2010). Many of these events have occurred due to slow response

times of mechanical switches, a lack of automated analytics, and lack of accurate, real-time access to data.

Better physical management of electricity, better information and communication –internally, across

utility commissions, and with end-consumers– and programs that incentivize end-consumers to reduce

their consumption all represent ways for utilities to meet the goal of providing reliable access to

electricity. As such, these energy efficiency measures must compete against other potential investments

that could achieve the same goal – for example, investment in new or upgraded T&D infrastructure,

additions of generation capacity, etc. on ageing infrastructure. To compare the costs and benefits of these

various investment opportunities, utilities use a levelized cost calculation, but this time energy saved. The

National Action Plan on Energy Efficiency projection for energy saved in 2011 by energy efficiency

investment in 2005 is presented belowxxxii.

Levelized Cost ($/kWh Saved)

Source: NAPEE (2005)

The table below shows the levelized cost of electricity and natural gas efficiency from four regions.

CONFIDENTIAL


Source: NAPEE (2005)

For utilities in many regions, the low levelized cost of energy savings is a major driver for utility

investment in energy efficiency measures. These measures, from the utility perspective, are comprised of

products, services, and programs that reduce pressure on the electric grid. In other words, rebate

programs that foster investment in electricity production at the point of use, also known as distributed

generationxxxiii systems and/or reduce consumption at the point of use are equally relevant.

Distributed generation technologies include roof-top and building-integrated PVxxxiv, small-scale windxxxv,

co-generation and combined heat and power (CHP)xxxvi, and fuel cellsxxxvii. Electricity from distributed

resources is used via islanded, grid-connected, or micro-gridxxxviii systems.

Currently, most cogenerationxxxix and fuel cell applications are for emergency capacity in hospitals and

communication networks or for district heating by municipalities. In other words, the market is still

becoming commercial.

Utilities achieve reductions in end-used consumption at specific times by signing participants in demand

response programs. These programs authorize utilities to cut off participants’ power at critical points in

time – e.g. when demand is coming close to overloading the electric system – in exchange for a fee. Other

products and services include advanced metering infrastructure, network and connectivity infrastructure,

and rebate or loan programs to entice end-consumers to upgrade appliances and equipment.

Due to redoubled policy support, low capex, and a familiarity with IT-related IP, venture capitalists have

funneled money into the energy-related information and communications technologies (ICT) sector that

is comprised by advanced metering infrastructure, demand response programs, and network and

connectivity infrastructure.

CONFIDENTIAL


Financing

GridPoint, Silver Spring Networks, and Tendril all raised multiple rounds of venture financing in ’08, by

focusing their products and services on improving transmission and distribution efficiency, as seen in the

table below. According to GTM research, VC funding in the first half of 2009 was $37.5 MM and 461 MM

in 2008.

Source: Greentech Media (2010)

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CONFIDENTIAL



GE, Cisco, Google, and Microsoft have all also been active, via both M&A and R&D, in improving T&D

efficiency as well as end-user energy management systems. Energy management systems include

thermostats, light switches, and voltage monitors as well as building automation controls. The table

below shows ’08 and ’09 M&A activity in energy-related ICT.

CONFIDENTIAL


The table below is indicative of companies in the smart grid space.

SAP Advanced Control Systems

Echelon Advanced Metering; AMI Networking Nasdaq ELON

Elster Advanced Metering; AMI Networking

GE Advanced Metering; AMI Networking

Itron Advanced Metering; AMI Networking

Landis+Gyr Advanced Metering; AMI Networking

Sensus Advanced Metering; AMI Networking

Ambient AMI Networking

Arcadian Networks AMI Networking

BPL Global AMI Networking

Current Group AMI Networking

Eka Systems AMI Networking

Silver Spring AMI Networking

SmartSynch AMI Networking

Trilliant AMI Networking

Cisco AMI networking / Distribution Automation / Energy

Management Systems

Oracle AMI Networking / Grid Optimization / Distribution

Automation / Demand Response

Areva Demand Response

Comverge Demand Response Nasdaq COMV

Cpower Demand Response

EnerNOC Demand Response Nasdaq ENOC

Sequentric Demand Response

CONFIDENTIAL


Cooper Power Systems Grid Optimization / Distribution Automation

Johnson Controls Grid Optimization / Distribution Automation

Microplanet Grid Optimization / Distribution Automation

Sensortran Grid Optimization / Distribution Automation

Siemens Grid Optimization / Distribution Automation

Telvent Grid Optimization / Distribution Automation

Tollgrade Grid Optimization / Distribution Automation

ABB Grid Optimization / Distribution Automation

SEL Grid Optimization / Distribution Automation

4Home Home Area Networks

Agilewaves Home Area Networks

AlertMe Home Area Networks

Energate Home Area Networks

EnergyHub Home Area Networks

Honeywell Home Area Networks

Intel Home Area Networks

Positive Energy Home Area Networks

Outsmart Power Systems Home Area Networks and Building Area Networks

Control4 Home Area Networks and Energy Management Systems

Ember Home Area Networks and Energy Management Systems

GainSpan Home Area Networks and Energy Management Systems

Google (PowerMeter) Home Area Networks and Energy Management Systems

Greenbox Home Area Networks and Energy Management Systems

Microsoft Home Area Networks and Energy Management Systems

Onzo Home Area Networks and Energy Management Systems

Tendril Home Area Networks and Energy Management Systems

Aclara Software Software, Solutions, and Applications

EcoLogic Analytics Software, Solutions, and Applications

eMeter Software, Solutions, and Applications

GridNet Software, Solutions, and Applications

GridPoint Software, Solutions, and Applications

OSIsoft Software, Solutions, and Applications

Ventyx Software, Solutions, and Applications

IBM

Software, Solutions, and Applications / Demand

Response / Home Area Networks plus systems

architecture, software, and applications for PHEV /

Distrbuted Generation and Storage

Enenex System Integration

HP System Integration

Logica System Integration

Point-of-use energy management is comprised of ICT as well as all the hardware and processes with

which the information and communications systems interact. Given the minimal capital requirements for

ICT companies, a more relevant segment of the smart grid for debt financing and securitization may be

energy efficiency: consequently, the next section focuses on energy system design, upgrades, and

management at the point of use, specifically, focusing on commercial buildings.

CONFIDENTIAL


ENERGY EFFICIENCY

MARKET POTENTIAL

Energy use in buildings accounts for 35 percent of total primary energy consumption in the U.S. (Kreith &

West, 1997). The Lawrence Berkeley National Laboratory (LBNL) estimates potential cumulative energy

savings from the buildings sector alone to be $170 billion in 2030 (Biermayer et al., 2008), if investments

totaling $440 billion were made from 2010 and 2030. In other words, investments with a simple payback

of 2 1/2 years and a benefit-cost ratio of 3.5 (Brown et al., 2008) could net $170 billion in savings on energy

expenses in 2030.

According to Johnson Controls, the market potential for commercial building retrofits in the U.S. is $180-

190 billion over the next ten years, or roughly $18 billion annually. In Johnson Controls’ analysis, annual

energy expenditure for 72 billion square feet of commercial building stock in 2003 was $93+ billion. This

equates to annual expenditure of $1.40/sq.ft. Consequently, 2009 energy expenditure can be calculated to

have been $100 Bn.

Achievable energy savings potential for all commercial building stock in the U.S. is 22%. At a single site

achievable energy savings potential ranges from 5-60%.

The average retrofit cost for an ESCO project is $2.50/sq. ft (8:1 cost/savings ratio).

Typically, projects take 10 years to achieve 100% of their projected savings goals.

Given $100 Bn opportunity with 22% achievable savings potential and an 8:1 cost/savings ratio over a 10

year life, the size of the commercial building energy efficiency retrofit opportunity is $17.6 billion/year.

Alternatively, 72 billion ft2, at $2.50/ft2 over 10 years yields an $18.0 billion/year opportunity.

STATE OF THE MARKET

Total investment in the building efficiency sector, exclusive of appliances and electronics, was $90 billion

in 2004. Roughly 13.6 billion of this value represented an ‚efficiency premium‛, or additional cost for

energy efficiency relative to standard equipment, materials, and services (Ehrhardt-Martinez & Laitner,

2008).

More recently, in 2008, energy efficiency services earned $12.79 billion. That same year, government and

utility EE spending was $3.74 billion. The sector’s growth is between 18.5-22 percent annually.

ESCO revenues were $12.79 billion in 2008 (Frost & Sullivan, 2008)

The industry CAGR for the period 2008-2013 is estimated at 18.5 % (Frost & Sullivan, 2008)

Cost

According to self-reported data on the DOE’s Building Technologies Program website, the median

investment from 2001 to 2007 in non-residential building energy efficiency was $5.75MM (Author’s

calculation based on data from DOE website; DOE, n.d.). Average investment was been $21.41MM

(Author’s calculation based on data from DOE website; DOE, n.d.).

A Johnson Controls survey in 2007, of 1249 executives and managers, found that 57 percent and 80

percent of those surveyed expected to invest 8 percent of their 2008 capital budgets and 6 percent of their

CONFIDENTIAL


2008 operating budgets in energy efficiency projects, respectively (Nesler, 2008). The average maximum

payback they expected was 4.3 years (Nesler, 2008), though recent interviews conducted by the author of

this report found payback requirements of 1-2 years more typical.

Projects that meet customer’s minimum simple payback criteria (generally 1-3 years), bear limited hidden

costs (e.g. implications for product performance, reliability, or quality, increased managerial or

administrative costs, and opportunity costs of disrupted or foregone production), and do not involve

processes that are extremely delicate or critical for a given firm are considered viable.

Savings

Energy flows within buildings and consequently, there are interactions between equipment and

processes; consequently, energy savings depends upon building design and orientation, ventilation and

lighting systems, thermal integrity (which is dependent on insulation, windows, and doors), construction

methods, and HVAC, lighting, and building controls equipment and processes (Govindarajalu, Levin,

Meyer, Taylor, and Ward, 2008). In other words, location, business activity, and building orientation,

matter as much as materials and equipment. Project developers – whether energy service companies

(ESCOs) or other – are in the best position to effect building energy efficiency.

The diagram below shows energy savings potential from electricity-based equipment, appliances, and

processes in a typical commercial building.

Source: LBNL (2008)

Other savings can be achieved through measures that consume natural gas; these are pictured below.

CONFIDENTIAL


Source: LBNL (2008)

For viable projects energy conservation measures (ECMs) become NPV-positive when the value of energy

cost savings is included in the calculation. The tables and chart illustrate this below.

Input Assumptions

Estimated Cost and Benefits for Commercial Building EE Measures

through 2030

CONFIDENTIAL


The project development process is diagrammed below.

Source: CCI & BOMA

Installation of more efficient machines should save energy; however, the machines’ energy use is

dependent on interactions with other equipment in day-to-day business processes. Consequently,

installation alone does not achieve savings. Energy savings require continual monitoring and

management of equipment and their interactions with each other, as illustrated below.

NPV of Commercial Measures Mid-Range Input Assumptions and 3% discount rate

CONFIDENTIAL


Consequently, on-going monitoring and verification (M&V) is necessary: there are a number of

techniques and methodologies for monitoring and verifying savings, all of which assess energy use

relative to a specified baseline. The baseline itself can be contentious, as can be the methodologies and

techniques. As a result, energy efficiency projects which tie revenue to energy savings performance

require substantial technical diligence and contractual support.

Government Policies

Due to the complexity of building energy efficiency, there are a number of impediments to demand,

despite the projects being NPV positive. Consequently, energy efficiency, like other clean technology

segments, is driven by government regulation and incentives.

Federal policies:

Federal regulation and incentives, subsidies, and grants were outlined at the outset of this report. Not

included there is in-progress legislation. The ‚American Clean Energy and Security Act‛ (‚Waxman-

Markey‛), which passed the House on June 26, 2009, proposes national minimum electric savings. Large

utilities, defined by retail sales volume, would be regulated vis-à-vis energy efficiency. Cumulative

Savings would ramp from 1.5% in 2012 to 5% in 2020. States with difficulty meeting the Federal RPS also

proposed in the legislation would be able to petition FERC to increase their EE target to 8%. This is

because investment in energy efficiency reduces the aggregate energy volume in a given state; renewable

portfolio standards require a percent of that total to come from renewable sources. As energy

consumption decreases, the number of megawatts required to meet the RPS would also come down.

State policies:

State- and local-level regulations are even more critical as these are the levels at which building codes are

set.

Source: REEEP (2005)

Calculating

Energy Use

and Savings

CONFIDENTIAL


Commercial building codes with varying requirements for meeting American Society of Heating,

Refrigerating, and Air-Conditioning Engineers (ASHRAE) standards are pictured below.

Source: http://bcap-ocean.org/code-status-map-commercial

A number of states have energy efficiency resource/portfolio standards (EERS/EEPS) to reduce or flatten

electric and gas load growth by requires distribution utilities to achieve scheduled annual savings levels.

Savings levels are specified in base-load MWh or therms, peak demand MWs, or both. State-level EERS

are illustrated below.

http://bcap-ocean.org/code-status-map-commercial

CONFIDENTIAL


Decoupling: Utility profits are currently tied to the volume of electricity each organization sells.

Decoupling separates volume from profits, in the hopes of incentivizing energy efficiency. States with

electric decoupling include CA, CT, MD, and WI. Nine additional states, KS, MA, MI, MT, NY, OH, OK,

OR, and WA, are currently considering decoupling in individual rate cases.

White certificates, the energy efficiency parallel of renewable energy certificates, represent a certain

reduction of energy consumption. The market for white certificates comes from a compliance-based

regime in which electricity, gas, and/or oil producers, suppliers or distributors are required to reduce

energy consumption by a pre-defined percentage of their annual energy deliverance. As with RPS and

RECs, there is a penalty for non-compliance. This drives demand for white certificates as a tradable

commodity and influences their price. The white certificate market is quite small at present, due in part to

the newness of state EERS.

There are innumerable additional incentive, rebate, and grant programs on the local level.

The net of the major costs and subsidies is an investment cost of $2.31 per square foot for energy

efficiency retrofits in commercial buildings.

CONFIDENTIAL


Source: The Energy Group and Econergy, n.d.

It must be noted that this number (# investment / sq. ft.) is heavily dependent on the mix of energy

conservation measures (ECMs) considered, age, location, and direction of a specific building, brand/price

of replacement equipment, and business activity taking place within the building (as this last may

necessitate certain types of replacement equipment).

According to self-reported data on the DOE’s Building Technologies Program website, the median

investment from 2001 to 2007 in non‐residential building energy efficiency was $5.75MM (Author’s

calculation based on data from DOE website; DOE, n.d.). Average investment was been $21.41MM

(Author’s calculation based on data from DOE website; DOE, n.d.).

Business Models

Most energy efficiency investments involve up-front balance sheet financing for equipment and

construction; however, as many energy service companies and project developers perceive the relative

size of the upfront investment to be a barrier to investment, new business models have evolved. The

simplest is equipment leasing – e.g. commercial leases, master lease agreements, and, where applicable,

tax-exempt lease purchase

agreements. After that, structures in

which project costs are amortized

over a 7-15 year life and paid for

through steady payments over that

period have been designed. Most of

these structures tie cashflows to

achievement of energy savings. The

table at right shows dominant

project structures.

Debt has been difficult to get in an

energy efficiency project as they lack collateral: energy efficiency assets (boilers, chillers, renewable

energy systems, etc.) are legally owned by the ESCO or an SPV rather than by the owners of the facilities.

In an energy savings agreement (ESA), customers agree to pay for the savings generated by the

equipment, rather than for the equipment itself. The asset owner gains the tax credit, if any, associated

with the assets and is responsible for system performance.

Commercial Energy Efficiency – NOI, Asset Value, & Payback Times Building

100,000 sq. ft. Investment /

sq. ft. Rate of Energy Savings

$ Savings / sq. ft. / year

Increase to NOI Asset Value Increase

Simple Payback

Janitorial Services $0.01 5% $0.14 $13,500.00 $135,000.00 Immediate Operations & Maintenance $0.05 9% $0.20 $19,800.00 $198,000.00 4 months

Lighting $1.04 16% $0.36 $36,000.00 $360,000.00 3 years

HVAC $1.21 9% $0.21 $20,700.00 $207,000.00 6 years

All Measures $2.31 39% $0.90 $90,000.00 $900,000.00 2.5 years

Source: Duke et al. (2008) .

CONFIDENTIAL


Types of agreements include fast payout - wherein ESCOs receive all energy savings for a specified

period or until the project cost has been recouped -, energy savings - wherein building owners pay

monthly flat fees for energy as specified in contracts with the ESCO keeping all of the upside if savings

are greater than expected, or bearing all of the downside if they are less (Goldberger, 2002).

There two models main performance contracting structures are shared and guaranteed savings.

Shared savings: ESCOs organize the financing for project installation and earn a specified percentage of

actual savings, usually at a set price for energy (International Institute for Energy Conservation and

Export Council for Energy Efficiency, December 1998). The cost of capital is based on the customers’

creditworthiness; while customers do not get access to cheaper financing, they do get limited recourse to

ESCOs for contract performance.

Source: Govindarajalu, Levin, Meyer, Taylor, & Ward (2008)

Guaranteed savings: ESCOs are paid on the basis of verified energy savings. The ESCO administers the

loan repayment and may need to guarantee payments to financiers, but even if not, financiers have

recourse to EE project customers’ balance sheets. The customers, in turn, have recourse to ESCOs through

the performance guarantee.

Source: Govindarajalu et al. (2008)

These structures reinforce the critical nature of on-going monitoring and verification (M&V). As

discussed above, much of the methodology around estimating baselines and savings are works in

progress. Consequently, debt from third party sources has been slow to enter the space.


CONFIDENTIAL


Most energy efficiency projects to date have been financed individually (as opposed to on a portfolio

basis). Energy efficiency deals are mostly financed on balance sheet or off, via operating leases. With

customer and government interest focused on achieving verifiable and on-going energy savings,

performance contracts have become fashionable.

In a paid-from-savings contract, ESCOs bring financing, or finance with internal capital, and purchase

equipment. They install this equipment at customer sites and maintain ownership; however, most of the

equipment has little stand-alone or resale value, and so, the equipment is near-impossible for ESCOs to

collateralize. Financing terms are consequently based on customers’ creditworthiness (Boyle et al., 2008;

Econergy, n.d.). Customers bear exposure to potential downgrading of their credit ratings during the

project – a significant concern for most (Sundaram, 2009).

Paid-from-savings deal structures have made limited headway into the commercial building sector.

Performance contracting costs, on the whole, account for 13-15% of overall financing costs (Goldberger,

2002). The typical cost of capitalizing performance risk via a performance guarantee is 8 percent of a

project’s total financing costs. Figure 16 diagrams the details flows of work and capital in a typical

performance contract.

Project costs and risks can be minimized through a variety of on-balance sheet measures, if the customers’

or ESCOs’ credit rating is high enough. Components of successful financing can include:

Coordinating loan repayment schedules with energy savings cash flows

Depositing energy savings into escrow accounts from which loans are repaid

Leveraging utility partners to collect loan repayments

Employing chauffage agreementsxl

New structures include Property Assessed Clean Energy (PACE) bonds (see page 71) and on-bill financing

(OBF).

CONFIDENTIAL


In OBF, utilities, governments, or third-parties can issue loans to consumers and get repaid via utility

bills – either through a tariff or volumetric charge (Forrester, 2008). Like with PACE (property assessed

clean energy bonds) the advantage of OBF is that it ties loan repayment to the property in which the EE

measure was executed, rather than to the customer. This minimizes the mismatch between long payback

times and short occupancy cycles; moreover, because payment is tied to properties rather than customers,

OBF enables current occupants to move without taking EE investment liabilities with them.

Other benefits of OBF are that the programs simplify loan application processes, can be approved based

on customers’ utility bill payment histories, can utilize actual energy-use data from meters, and can be

cash flow neutral (Ryan, 2008). As most people pay their utility bills on time, OBF can bring down default

rates. In California, OBF programs have been designed by most of the state’s utilities and generally offer

non-residential customers 0% financing for approximately five years via OBF (Ryan, 2008; Skinner, n.d.).

The main issue with OBF is that third party financiers remain subordinate to the utilities as utilities

collect customer payments and subtract their costs before passing the balance to financers. One way

around this issue is through Tariffed Installation Programs (TIPs). In TIPs, utilities employ their billing

systems to collect payments on behalf of project financiers. These funds are collected via a separate tariff

and are managed separate from customer bill payments. Like OBF, this mechanism ties loan repayment

to the property in which the EE measure was executed, rather than to the customer. Typically, the tariff

amount is less than expected energy savings and shorter-term than the EE project (Fuller, 2008).

According to analysis by Neil Peretz at the Department of Justice, the cost of equity capital should be

~19.4%. The cost of debt should be between 8.7-10.1%.

Source: Peretz (2009)











CONFIDENTIAL


CONCLUSION

While traditional debt capital requirements are in the billions, across the four segments discussed in this

report, there is a compelling need for structured finance.

According to goals set by the Waxman-Markey bill, passed in the U.S. Senate in 2009, which calls

for a 15% Federal Renewable Portfolio Standard (RPS), required investment would be $32 Bn per

year until 2020 ($356 Bn in total - U.S. Partnership for Renewable Energy Finance (US PREF),

2010).

Using a 60:40 debt to equity ratio, about $214 Bn will be required in debt capital and $142.4 in

equity to build up renewable energy generation capacity, develop transmission infrastructure,

and reduce energy demand through efficiency measures.



compliance, and credit rules.

Economic drivers in clean energy and energy efficiency are multi-layered: e.g. government

regulation, incentives, and compliance-based tradable certificates.

The above hints at the jurisdiction-specific nature of clean energy: laws on Federal, State, and

local levels all affect project economics. To expand this analysis to a global scale would have been

beyond possibility, given the time frame.

Key challenges to date include an absence of scale and growth capital for projects. The timeline,

complexity, small scale, and high capex of projects have been unfamiliar for equity investors. If only a

small portion of the projected installed capacity were to come online, billions of dollars would be

required, with anywhere upwards of 40% from debt capital sources. Meanwhile, debt has been slow at

the project level due to the unfamiliarity of lenders and debt investors with technology risk.

Structures which invite equity and hybrid investors to invest in projects at adequate

compensation are necessary; a way to entice these investors may be to organize take out in the

form of securitization.

Energy




have low to zero need for fuel inputs and low- to zero emissions).

The government is not the only significant actor, however; many clean technologies require seed, angel,

venture, and private equity capital in order to achieve scale and minimize costs. With costs lower,

government subsidies can push some technologies into price-competitiveness, while others still require

government regulation before becoming mainstream. Due to concerns about efficiency, emissions, and

energy security, the government has created regulation and incentives to drive investment into clean

technology. Highlights include tax credits, cash grants, and compliance-based tradable certificates.

CONFIDENTIAL


With regulation, subsidies, and incentives, renewable energy has grown at a 5% CAGR from 1995-2009,

exclusive of hydroelectric energy. Wind was the fastest growing renewable energy source, with a growth

rate of 61% in 2008 and 28% in 2009. Solar was second in 2008 at 41% growth, but last in 2009 with a -6%

growth rate. Geothermal and biomass each grew at 2% in 2009 while biofuels experienced slightly less

negative growth in 2009 (-3%) than in 2008 (-4%).

Wind


2030. The total investment required would be $464 Bn. Assuming 60% leverage, $278 Bn would be

required in debt capital.

A typical farm costs approximately $210 MM. Average debt requirements are between $115-126 MM, as

detailed in the body of this report.


the debt need per project has driven a plethora of financiers into the industry. There may be untapped

opportunity in securitizing land leases from utility scale projects and or PPAs and RECs from community

or small wind projects. One company in this space is American Wind Power Capital: a company owned

by Barclays Natural Resource Investments and NGP Energy Technologies Partners. Small wind is still a

nascent market segment and as such even more dependent on government policies and related

developments in the electric grid that enable distributed generation. Securitization of existing project

cashflows may provide a near-term opportunity to develop a structure which can then be rolled out to


Solar

According to the DOE, the aggregate amount of money needed for financing solar PV projects and build-

up of manufacturing capacity is $1.4 trillion from debt investors and $0.15 trillion from equity (Cory,

2009). While wind is cost competitive in most regions (after government incentives), solar PV is not. Costs

have come down over the past few years, as certain PV technologies have achieved scale; however, the

cost in 2009 was still $5.5/W for large-scale systems (See diagram below from SEIA, 2010). Government

regulation is consequently essential to the development of solar PV. Federal and State governments have

created a number of solar-specific policies, which have driven local markets. The fragmented nature of

the market creates a strong need for structured finance – and an even more interesting opportunity for

securitization; however, due to the complexity of the market, the securitization opportunity is easily a

year out.

Electric Grid

At present, the US electrical grid serves 335 MM customers with nearly 3,765 Billion kWh of electricity in

a year (2007 figures, EIA). In part to meet this demand and the annual 1% growth in consumer demand

for electricity, government entities, investors, and business owners have invested in renewable energy

power generation.

As renewable capacity grows, so do pressures on the electric grid. To accommodate the growth in

renewable and distributed generation while maintaining electric-grid reliability, investment is required

across the spectrum of transmission, distribution, management, and use.

CONFIDENTIAL


The hottest sector of the smart grid in 2009 was information and communications technology. According

to GTM research, VC funding in the first half of 2009 was $37.5 MM and $461 MM in 2008. Much of these

plays have low capital needs, as they are IT companies.

A second segment of the smart grid that is in need of capital is physical transmission. According to a

report published by Edison Electric Institute (EEI) the United States needs to invest at least $880 billion in

transmission and distribution systems between 2010 and 2030 to maintain reliable service. Multi-billion

dollar funds have been established by major financial institutions to serve this need. Consequently, a

more strategic area of focus may be in energy efficiency and securitization.

Energy Efficiency










CONCLUSION The clean energy sector offers significant room for financial innovation, particularly with regard to

structured products. To leverage the multi-layered economic drivers for clean energy projects – e.g.

government regulation, incentives, and compliance-based tradable certificates –unique structures are

required. While traditional debt capital requirements are in the billions, across the four segments

discussed in this report, there is a compelling case for pioneering the securitization of project-based

cashflows. Still, without scale, time spent in structuring take-out is unlikely to have a near-term pay-off;

there may be a more tangible opportunity to entice debt investors to finance projects by introducing the

idea of take-out earlier. Secondly, opportunities to raise debt capital for clean tech companies – helping

them to prove their technologies and achieve economies of scale – should be pursued.

CONFIDENTIAL


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Cory, K., & Schwabe, P. (2009). Wind Levelized Cost of Energy: A Comparison of Technical and Financing Input Variables. National

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Ehrhardt-Martinez, K. & Laitner, J. A. (2008). The Size of the U.S. Energy Efficiency Market: Generating a More Complete Picture.

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Flett Exchange, LLC. Untitled. Presentation at the Wall Street Green Trading Summit. New York, NY. March 23, 2010.

CONFIDENTIAL


Feo, E., & Tracy, S. (2009). Commercial Finance: The Dark Arts of Leverage, Tax Equity, Leases and More. Presentation at Solar Power

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Forrester, J. P. (2008). Securitization, Mach II. Public Utilities Fortnightly.

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Jennings, C., Margolis, R., & Barlett, J. (2008). A Historical Analysis of Investment in Solar Energy Technologies (2000-2007). National

Renewable Energy Laboratory. (NREL/TP-6A2-43602).

Kelly, S. (2010). The Mechanics of REC Trading. Presentation at the Wall Street Green Trading Summit. New York, NY. March 23, 2010.

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2010.

Leeds, D. J. (2009). The Smart Grid in 2010: Market Segments, Applications, and Industry Players. Greentech Media Research.

Lips, B. (2009). Update on Federal Tax Incentives. Presentation at North Carolina Sustainable Energy Conference. April 15, 2009.

Morgan Stanley (2009). Analysis of Project Finance Requirements Implicit in Existing State and Proposed Federal Renewable Energy

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NREL (2010). Solar Power and the Electric Grid.

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Schwabe, P., Cory, K., & Newcomb, J. (2009). Renewable Energy Project Financing: Impacts of the Financial Crisis and Federal Legislation.

National Renewable Energy Laboratory. (NREL-TP-6A2-44930).

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March 23, 2010.

Solar Energy Industries Association (2010). US Solar Industry: Year in Review 2009.

Sundaram, A. (2009). Energy Efficiency: Opportunities, Challenges, and Potential Solutions.

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http://www.nrel.gov/analysis/costs.html

CONFIDENTIAL


U.S. Partnership for Renewable Energy Finance (2009). Renewable Energy Finance Fundamentals.

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Reinvestment Act of 2009.

Wiser, R., Barbose, G., Peterman, C., & Darghouth, N. (2009). Tracking the Sun II: The Installed Cost of Photovoltaics in the U.S. from

1998-2008. Lawrence Berkeley National Laboratory. LBNL-2674E.

Wiser, R. & Bolinger, M. (2008). Annual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 2007. DOE/Lawrence

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Hudson Clean Energy Partners & U.S. Partnership for Renewable Energy Finance.

i The U.S. Partnership for Renewable Energy Finance (US PREF) is a program run by the American Council on Renewable Energy

(ACORE). Partners in the US PREF include Google, Bank of America, Merrill Lynch, Citi, Credit Suisse, Deutsche Bank, GE

Energy Financial Services, Hudson Clean Energy Partners, Madison Dearborn Capital Partners, Morgan Stanley, US Renewables

Group, VantagePoint Venture Partners, Starwood Energy Group, NRG, Skadden, Arps, Slate, Meagher & Flom LLP, Green Order,

SolarCity, Troutman Sanders, Bipartisan Policy Center, Resources for the Future, and the Center for American Progress. ii POWER GENERATION CONCEPTS

Generating capacity is the maximum output that a piece of equipment can supply to system load, adjusted for ambient

conditions (EIA: http://www.eia.doe.gov/glossary/), measured in megawatts (MW).

Nameplate capacity is the maximum rated output of a generator under conditions designated by the manufacturer, measured

in kilovolt-amperes (kVA) or kilowatts (kW).

Capacity factor: The ratio of the electrical energy produced by a generating unit for the period of time considered to the

electrical energy that could have been produced at continuous full power operation during the same period.

Capacity factor = average power / power capacity (maximum power output)

iii GLOBAL WARMING CONCEPTS

Greenhouse gases (GHGs): gases, such as water vapor, carbon dioxide, nitrous oxide, methane, hydrofluorocarbons (HFCs),

perfluorocarbons (PFCs) and sulfur hexafluoride, that are transparent to solar (short-wave) radiation but opaque to long-wave

(infrared) radiation, thus preventing long-wave radiant energy from leaving Earth's atmosphere. Introduction of these gases into

the atmosphere traps absorbed radiation within the Earth’s atmosphere and leads to a tendency to warm the planet's surface.

GHGs are expressed in terms of global warming potential (GWP).

Global warming potential: a metric that expresses how much a given mass of a greenhouse gas is estimated to contribute to

global warming on a scale relative to the same mass of carbon dioxide. Contribution to global warming happens through

absorption of infrared radiation, spectral location of absorbing wavelengths and atmospheric lifetime. The GWP of a gas is

calculated over a specific time interval.

Carbon emissions factors: the mass of carbon (MC) released when a fuel is burned to produce a quantity of energy (Q) – or in

other words, the ratio of MC:Q. It is calculated by dividing the mass fraction of carbon (FC) in a fuel by its high heating value

(HHV).

Carbon emissions factor = FC / HHV

FC is the mass C in fuel divided by the mass of fuel. High heating value is the heat content of the fuel. Another way to define

the carbon emissions factor is by the pounds of carbon dioxide (mass of carbon) emitted per million Btus of energy for various

fuels (HHV). The GWP of CO2 is, by convention, equal to 1.

Carbon equivalents (CO2e,): emissions expressed in carbon terms.

Carbon sequestration: the counterweight to emissions. Preservation of forests and re-forestation offset emissions. Other fossil

fuel products that emit and sequester carbon include liquefied petroleum gas (LPG) and feedstocks for plastics and other

petrochemicals. Asphalt and road oils sequester carbon without emitting CO2. While plastic sequesters carbon, it also emits

significant CO2 when burned to produce electricity in municipal solid waste.

http://www.eia.doe.gov/glossary/

CONFIDENTIAL


Carbon offsets: measure the CO2 equivalent of GHG emissions reductions. All activities that remove or reduce the amount of

GHGs that would have been released into the atmosphere can be qualified as producers of carbon offsets. These offsets can be

bought and sold in commodity exchanges. Carbon sequestration is one way to create offsets, while building renewable energy

plants over those that would burn fossil fuels, increasing energy efficiency (where an energy efficiency-to-carbon conversion

methodology exists), and/or recycling energy (cogeneration) are others.

Offset pricing: certain gases, such as HFCs, have higher or lower global warming potentials. A higher GWP means a higher

value of CO2 equivalents. As the carbon credits market has developed and matured, the underlying gas that is eliminated and the

process by which it was eliminated have become determinants of offset quality and demand Other ways to create offsets include

building renewable energy plants in lieu of plants that would burn fossil fuels, increasing energy efficiency (where an energy

efficiency-to-carbon conversion methodology exists), and recycling energy (cogeneration). Because certain gases, such as HFCs,

have higher or lower global warming potentials, they can earn more carbon credits. When the process to reduce emissions of such

a gas is cheap, many carbon credits are created. Consequently, the underlying gas that is eliminated and the process by which it

was eliminated are both criteria for evaluation by carbon offset buyers. In other words, these factors feed into offset price. The

going price for a forest Voluntary Carbon Standard offset is between $2-3/ton. iv DEVELOPMENT OF RENEWABLE ENERGY IN THE US

(Excerpted from EIA website: http://www.eia.doe.gov/cneaf/electricity/chg_str_fuel/html/chapter5.html)

The electric power industry and its regulators were unprepared for the social, political, and economic upheavals that followed

the oil embargo of 1973. The tripling of oil prices precipitated a need for numerous rate increases by electric utilities because oil

was being used to fuel many power plants. In the wake of the oil embargo, the goal of national energy policy was to foster an

adequate supply of energy at reasonable costs. As a result, interest in renewable energy rose sharply during the 1970s. A strategy

to achieve that goal was to promote a balanced and mixed energy resource system. The development of renewable energy—

which reduces dependence on fossil fuels, does not need to be imported, and generally produces fewer and less toxic pollutants

than fossil fuels—became a national priority.

The oil embargo of 1973 was a catalyst for the proposal and adoption of the National Energy Act of 1978, a compendium of

statutes aimed at restructuring the U.S. energy sector. One objective of the Act was to reduce the Nation's dependence on foreign

oil and its vulnerability to interruptions in oil supply through the development of renewable and alternative energy sources.

The most significant statute in the National Energy Act for the development of commercial markets for renewable energy was

passed into law as the Public Utility Regulatory Policies Act of 1978 (PURPA). Among other things, PURPA encouraged the

development of "nonutility" cogeneration and small-scale renewable-fueled electric power plants designated as "qualifying

facilities."160 Under PURPA, utilities were required to purchase electricity from certain qualifying facilities at the utilities'

avoided costs, that is, the cost to the utility if it had generated or otherwise purchased the power. Some avoided cost purchase

contracts, particularly in California, were very favorable to renewable technologies.

A second major factor influencing the development of renewables was State policies promoting renewable energy. California,

in particular, promoted renewable energy strongly in the 1980s with renewable energy tax credits. By the late 1980s, however,

California's renewable tax credits for wind energy had ended, and competition and pricing policies had begun to evolve in the

electric utility industry. "Competitive bidding" became the predominant approach to defining avoided costs. By the end of the

decade, with declining natural gas prices setting the value of avoided costs, renewable facilities had difficulty competing in

electricity markets on the basis of price alone.

To spur renewable energy development, the Federal Government provided several tax incentives. By 1982, most renewable

energy projects were eligible for a 10-percent investment tax credit, a 15-percent business renewable energy investment tax credit,

a 40-percent residential tax credit for renewables, and a 5-year accelerated depreciation schedule. Taking advantage of these

incentive packages, private industry responded by pioneering new renewable energy technologies and applications. In terms of

Federal research and development budget appropriations, funding for renewables increased dramatically from fiscal year (FY)

1974 through FY 1979, stabilized for 2 years, dropped precipitously in FY 1982, then decreased further each year until rebounding

in FY 1991. Funding increased to $391 million in FY 1995 before dropping to $268 million in FY 1996 and $244 million in FY1997.

The appropriation for FY 1998 [was] $272 million. This pattern of inconsistent funding, as well as the on-again, off-again

availability of some incentives, has created an uncertain investment environment for renewables. v LIFE CYCLE ANALYSIS (LCA) CONCEPTS

Lifecycle analysis is defined as ‚compilation and evaluation of the inputs, outputs and the potential environmental impacts of

a product system throughout its life cycle‛. For energy, analysis can include resource extraction, conversion transport, use, and

recycling. The following further describe the components of each step along the way from resource to recycling.

Primary energy is broken into total fuel cycle energy and material production energy.

Material production energy includes feedstock energy, defined by the energy of material resources like plastics or wood, plus

the total fuel cycle energy of inputs in the conversion of material resources.

Total resource energy, also known as total fuel cycle energy, is all the energy used in extraction, transportation to the power

plant, generation, power plant operation, and transportation to the end consumer.

http://www.eia.doe.gov/cneaf/electricity/chg_str_fuel/html/chapter5.html

CONFIDENTIAL



Power plant efficiency can be measured by the net generation of electricity divided by the fuel energy consumed by plant. This

kind of efficiency can be achieved through improvement of power plant technologies as well as by using more consistent quality

inputs (e.g. smaller Btu range of oil, natural gas, coal, etc.). Life cycle efficiency, on the other hand, can only be achieved through

a systems approach. The term life cycle efficiency has two definitions: life cycle electricity generation efficiency and life cycle

electricity delivered efficiency. Life cycle electricity generation efficiency is electricity generated divided by total fuel cycle energy

(or total resource energy) inputs. Life cycle electricity generation efficiency can be achieved by improving extraction, conversion,

standardization of input resources, and transportation to power plant. Life cycle electricity delivery efficiency is the electricity

delivered to the customer divided by total fuel cycle energy inputs. In both cases, investment up and down the value chain is

required to improve efficiency. Evaluation of the success of these investments occurs over the system’s life cycle. Life cycle

analysis, as can be inferred from the above, measures processes and their efficiencies with reference to the long-term and

downstream processes, as illustrated in the diagram below.


In the case of electricity, the waste product generated during use and service is heat. A lifecycle approach to electricity would

involve capture of waste heat for re-use, for example, through cogeneration or use of combined heat and power technologies. vi LEVELIZED COST OF RENEWABLE ENERGY

When determining the fuel source to use in constructing a new generating plant, "levelized" cost is usually used to determine

which technology and energy source will be least cost. Levelized cost of energy (LCOE) is the ratio of an electricity-generation

system's amortized lifetime costs (all capital, fuel, and lifetime O&M costs) to the system's lifetime electricity generation. The

calculation of LCOE is highly sensitive to installed system cost, O&M costs, location, orientation, financing, and policy. (Excerpted

from DOE. (2010).

The cost of generating electricity is calculated by adding the annualized capital costs with on-going operating & maintenance

costs to get $/kWh. The price of electricity is calculated by:

pelectricity = CRF*K/(8766D) + (HR*pfuel) + O&M

Example of Energy Losses in Providing One Unit of Electrical Energy, Natural Gas-Fired Power Plant

3.61 1.0 final

consumer

0.09 0.12 2.23 0.06 0.11

resource final

energy energy

generationtransportgas fie ld/

separation

of l iqu ids

pwr plant

operationtransport

primary/fuel-

carrier energy

Product Life Cycle

Raw MaterialAcquisition

Ma terialProcessing

Ma nufacture& Assembly

Use &Service

Re tirement& Recovery

TreatmentDisposal

open-loopre cycle

reuse

rema nufacture

clo sed-loop recycle

material and energy inputs for process and distribution

waste (gaseous, liquid, solid) output from product, process and distribution

material flow of product component

M, E

W W W W W

M, E M, E M, E M, EM, E

W

M, E

W

CONFIDENTIAL


K is the unit capital cost $ per kW of capacity (the investment cost of the facility divided by the kW produced when the plant is

operating at full capacity)

D, the fraction of capacity used over a year (8766D = hours a plant is generating electricity in one year)

HR is the fuel consumption per kWh produced

Pfuel is the levelized price of fuel (units = Btu/kWh x $/Btu), inclusive of assumptions for fuel price increases. It is important to

note that most renewable energy technologies do not use fuel on an on-going basis.

Other O&M variable costs per kWh produced are for operation and maintenance. vii THE ELECTRIC POWER INDUSTRY

The goals of the electric grid are to efficiently achieve and maintain reliable and affordable access to people in the U.S. greater

than 99% of the time that they demand electricity. Reliability is defined as customers having power when they want it. The grid

accomplishes reliability through adequacy –supplying to aggregate electrical demand at all times, after accounting for scheduled

and unscheduled outages of system facilities– and security –ensuring that the electric system can withstand sudden disturbances.

Adequacy and security are managed and monitored by local grid operators who coordinate supply and demand for electricity

with each other. Local and operators are part of a network of larger grids – e.g. independent system operators (ISOs) or regional

transmission organizations (RTOs). ISOs and RTOs manage reliability across member states and locations. The North American

Electric Reliability Corporation (NERC) regulates the national grid and interactions with Canada.

Source: EIA (2010)

ISOs operate electricity grids and manage wholesale electricity markets and reliability planning. RTO's do all of the same

functions while also managing transmission networks. Current ISOs and RTOs include:

California ISO (CAISO)

Electric Reliability Council of Texas (ERCOT)

Southwest Power Pool (SPP)

Midwest Independent System Operator (MISO)

Pennsylvania-New Jersey-Maryland (PJM) Interconnection

New York Independent System Operator (NYISO)

ISO-New England

This system was created in the 60’s and paid for by rate-payers in each utility’s district.

To this day, rate-payers pay for utilities to meet and maintain reliability. Utilities create plans to maintain reliability using a

thorough and complex assessment of generating capacity, transmission capacity, and estimates of demand and supply. From this,

they estimate the investment required to meet and maintain electric grid reliability. They take these budgets to the Federal

Energy Regulatory Commission (FERC) and present them in a hearing, called a rate case. FERC reviews the budgets and directs

utilities to make the investments which will pass the least cost to rate-payers, while still maintaining reliability. After choosing

the mix of investments, costs are multiplied by a FERC-approved rate of return and then translated into a $/kWh price. Because of

this system, utility profits are tied to the volume of electricity sold.

There is, however, a new move towards decoupling volume from profits, in the hopes of incentivizing efficiency in

transmission, distribution, and electricity consumption. States with electric decoupling include CA, CT, MD, and WI. Nine

additional states, KS, MA, MI, MT, NY, OH, OK, OR, and WA, are currently considering decoupling in individual rate cases.

CONFIDENTIAL


Timeline

Source: Frost and Sullivan (2009)

viii A "closed-loop" facility one that utilizes biomass grown exclusively for energy production (See endnote v for more information on

closed and open-loop systems). ix ‚Placed in service‛ is defined in U.S. Treasury documents as ‚the property is ready and available for its specific use‛. x For more information, please visit http://www1.eere.energy.gov/recovery/ xi The Federal Financing Bank (FFB) is a government corporation, created by Congress in 1973, and managed by the Secretary of the

Treasury. The FFB was established to centralize and reduce the cost of federal borrowing, as well as federally-assisted borrowing

from the public. The FFB purchases obligations issued, sold, or guaranteed by federal agencies. For more information, please see

www.ustreas.gov/ffb/. xii RENEWABLE ENERGY CREDITS (RECs) a.k.a. RENEWABLE ENERGY CERTIFICATES, RENEWABLE ELECTRICITY

CERTIFICATES, GREEN TAGS, & TRADABLE RENEWABLE CERTIFICATES (TRCs)

A REC represents the avoided CO2 and mercury emissions from production of a MWh of electricity from renewable sources

relative to the fossil-fuel-based electricity that would have been created in the area without environmental legislation (For more on

CO2, CO2 equivalents, and global warming, see endnote iii). REC originators (sellers) are PPA developers, solar finance firms,

renewable energy marketers (brokers and aggregators), commercial property owners, and home-owners.

Buyers for compliance-based RECs are primarily electric distribution companies (EDCs), though other buyers, such as

renewable energy marketers (brokers and aggregators), commercial businesses, and individuals, do exist. EDCs purchase RECs

and/or RECs bundled with electricity. Some states do not allow unbundled sale (AZ, CA, IA, MN) while others do (CO, CT, DE,

DC, ME, MD, MA, MT, NV, NJ, NM, NY, PA, RI, TX, WA, WI).

Most state RPS programs allow for the electricity providers to recoup the cost of the REC from the rate-payers, up to a certain

amount (NEF, 2010). Many purchases are executed through bilateral agreements without disclosed prices.

There are two types of RECs: compliance-based RECs and voluntary RECs. Compliance-based RECs are used in states with

renewable portfolio standards (RPS). Voluntary RECs are used by corporations looking to be green. For example, the EPA’s

Green Power Purchasing Program is used by Fortune 500 companies, federal, state and local government agencies, and

universities looking to offset their carbon footprints by purchasing RECs.

While RECs relate to RPS issued on a state-by-state basis, they are monitored by IT systems managed by multi-state regional

transmission organizations (RTOs) and independent system operators (ISOs) (See endnote vii for more on the electric industry and

grid). For instance, the Pennsylvania-New Jersey-Maryland Interconnection (PJM) regional transmission organization (RTO),

which consists of 13 member states, uses an IT system called the Generation Attributes Tracking System (GATS) to monitor and

manage all electricity in its region. GATS tracks each megawatt-hour (MWh) of electricity generated in or imported into the PJM

region by creating a unique electronic certificate. This enables RTO operators to tell power producers when and how much

energy to send into the grid and to import and export electricity to neighboring RTOs and ISOs. GATS certificates enable

Renewable Energy Certificates (RECs) to be created – either for compliance purposes or voluntary market use.

A diagram of North American REC tracking systems is below.

http://www1.eere.energy.gov/recovery/

http://www.ustreas.gov/ffb/

CONFIDENTIAL


Source: Environmental Tracking Network of North America (2010)

RECs are maintained in Subscriber User Accounts created by state regulators.

The value of RECs derives, where relevant, from compliance-based penalties published by utility regulators. Other factors

influencing REC prices include, supply, demand, contract terms, location, technology, date (vintage), methodology by which the

REC was created and certified, and trade exchange.

The price of compliance-based RECs varies greatly: For example, Massachusetts Class 1 RECs go for $23.50 and $25.50

(Evolution Markets, February 2009). In the meantime, national voluntary market prices for 2010 were $1.00-1.20/REC ($0.75-

1.25/REC in 2009) and Western Electricity Coordinating Council (WECC) voluntary market prices were $6-9.00/REC in 2010 ($1-

5.00/REC in 2009).

The most active REC spot markets are those where RPS penalty provisions are priced higher than the actual cost to develop

eligible projects. Barriers to REC trading include sealed bids (leading to opacity of pricing), limited cross-border trading, and

perceived legislative risk. xiii As of 4/19/2010, Flett Exchange had the following trades listed.

Date Region Type Price Volume

2/8/2010 n/a Voluntary wind RECs $3.00/REC 560

1/4/2009 WREGIS California voluntary RECs $7.50/REC 2,890

CONFIDENTIAL


xiv Regional Greenhouse Gas Initiative (RGGI) was the first regional mandatory GHG program in the US. It requires the power

sector in ten Northeastern and Mid-Atlantic States to cut its CO2 emissions by 10% by 2018. In the most recent RGGI allowance

auction, an offset went for $2.07/ton. xv DOE Site: http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=2

Active Retail Marketers Active Commercial &/or Wholesale Marketers (cont'd)

3Degrees Reliant Energy

3 Phases Renewables Renewable Choice Energy

Bonneville Environmental Foundation Select Energy

Carbon Solutions Group Sempra Energy Solutions

Choose Renewables Shell Trading

Community Energy Inc. SKY energy, Inc.

Conservation Services Group Sol Systems

Ecoelectrons Renewable Energy Spartan Renewable Energy

Enpalo Spectron Environmental

Good Energy, LP Sterling Planet, Inc.

Green Mountain Energy Company Strategic Energy

Juice Energy SUEZ Energy Resources NA

Maine Interfaith Power & Light Sun Farm Ventures, Inc.

Massachusetts Energy Consumers Alliance (Mass Energy) SunEdison

NativeEnergy TFS Energy

Pacific Gas and Electric Company TXU Energy

Premier Energy Marketing TerraPass Inc.

Renewable Choice Energy Texas Power

SKY energy, Inc. Tradition Energy

Sterling Planet, Inc. Tullett Prebon

TerraPass Inc. Unicoi Energy Services

Village Green Energy Viking Wind Partners, LLC

Waverly Light and Power Village Green Energy

WindCurrent Vision Quest

WindStreet Energy Washington Gas Energy Services

Waste Management

Active Commercial &/or Wholesale Marketers Waverly Light and Power

3Degrees Western Area Power Administration

3 Phases Renewables WindCurrent

Amerex Brokers WindQuest Energy, Inc.

Aquila WindStreet Energy

BP Energy Company World Energy

Basin Electric Power Cooperative

BlueRock Energy Certificate Brokers/Exchanges

Bonneville Environmental Foundation 3 Phases Renewables

Bonneville Power Administration (BPA) Amerex Brokers

Brookfield Renewable Power Cantor Fitzgerald Environmental Brokerage

Calpine Corporation Chicago Climate Exchange

Carbon Solutions Group Clear Energy Brokerage & Consulting

Carbonfund.org Element Markets

Centennial Energy Resources Emission Credit Brokers

Clean Currents Evolution Markets

Clear Energy Brokerage & Consulting GFI Group

Clear Sky Power GT Environmental Finance

ComEd Good Energy, LP

Community Energy Inc. Natsource

Conservation Services Group Neuwing Energy Ventures

Constellation NewEnergy Spectron Energy

Ecoelectrons Renewable Energy TFS Energy

Element Markets Tullett Prebon

Empire District Electric Company World Energy

Endless Energy Corporation

Enpalo Consumer Protection/REC Tracking Systems

http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=2

http://apps3.eere.energy.gov/greenpower/markets/certificates.shtml?page=2&companyid=578


http://www.3phasesrenewables.com/





http://www.semprasolutions.com/

https://www.chooserenewables.com/xcart/home.php?cat=103

http://www.shell.com/home/Framework?siteId=trading-en


http://www.sky-energy.com/


http://www.solsystemscompany.com/



http://www.enpalo.com/portfolios.php

http://www.spectronenvironmental.com/

http://www.goodenergy.com/store/




http://www.juice-inc.com/



http://www.sunfarmnetwork.com/


http://www.sunedison.com/


http://www.tfsbrokers.com/environment/global-emissions-trading/united-states.html



http://premierenergyonline.com/buycredits.php

http://www.terrapass.com/



http://www.sky-energy.com/



http://www.tullettprebon.com/

http://www.terrapass.com/


http://www.villagegreenenergy.com/

http://greenenergy.com/


http://www.villagegreenenergy.com/



http://www.windstreet.com/residential.aspx

http://www.wges.com/page/wind.php







http://www.amerexenergy.com/na_EnvironmentalCommodityMarketsREC.html

http://www.windquestenergy.com/quick-guide.html



http://www.bp.com/

http://www.worldenergy.com/world-green-exchange/green-exchange.cfm


http://www.bluerockenergy.com/




http://www.amerexenergy.com/na_EnvironmentalCommodityMarketsREC.html

http://www.brookfieldpower.com/

http://www.emissionstrading.com/



http://www.carbonsolutionsgroup.com/leed-projects.html

http://clearenergybrokerage.com/

http://www.carbonfund.org/site/pages/buy_green_power/

http://www.elementmarkets.com/

http://www.centennialenergy.com/

http://www.emissioncreditbrokers.com/

http://www.cleancurrents.com/index.php/C-Green-Overview


http://clearenergybrokerage.com/

http://www.gfigroup.com/

http://www.clearskypower.com/

http://www.gtenvfin.com/








http://www.spectrongroup.com/


http://www.tfsbrokers.com/environment/global-emissions-trading/united-states.html

http://www.elementmarkets.com/

http://www.tullettprebon.com/

http://www.empiredistrict.com/

http://www.worldenergy.com/world-green-exchange/green-exchange.cfm


http://www.enpalo.com/portfolios.php

CONFIDENTIAL


Exelon Power Team APX, Inc.

FirstEnergy Solutions Corporation American Carbon Registry

GT Environmental Finance Clean Power Markets, Inc.

Good Energy, LP Climate Action Reserve

Green Mountain Energy Company Electric Reliability Council of Texas (ERCOT)

Green Power 4 Texas Environmental Resources Trust

Hess Energy Federal Trade Commission

Iberdola Renewables Gold Standard Foundation

Integrys Energy Group Green-e TRC Certification

Juice Energy Michigan Independent Power Producers Association

Liberty Power Michigan Renewable Energy Certification System (MIRECS)

Maine Interfaith Power & Light Midwest Renewable Energy Tracking System (M-RETS)

Mainstay Energy NEPOOL General Information System (GIS)

Massachusetts Energy Consumers Alliance (Mass Energy) New York State Energy Research and Development Authority

(NYSERDA)

MidAmerican Energy North American Renewables Registry (NARR)

MotivEarth PJM Generation Attribute Tracking System (PJM-GATS)

NativeEnergy Voluntary Carbon Standard

Neuwing Energy Ventures Western Renewable Energy Generation Information System

Nexant Clean Energy Solutions

NextEra Energy Resources (formerly FPL Energy) Inactive

Old Mill Power Company Big Green Energy

PPL Corporation Burlington Electric Department

PPM Energy Clean and Green

Pacific Renewables Connecticut Energy Cooperative

Peoples Energy Services EAD Environmental (Natsource)

PowerLight Los Angeles Department of Water and Power

Premier Energy Marketing National Energy and Gas Transmission

Premier Power Solutions Navitas Energy

QVINTA, Inc.

xvi Avoided cost is the savings associated with not having to produce additional units of electricity while meeting demand

requirements. The avoided cost analysis compares incremental savings of not producing an additional unit of output through a

given method with supplying the unit through an alternate method. xvii Balance of Plant (BOP) refers to the infrastructure required in a wind farm project, exclusive of the wind turbines. In other words,

the foundations for the turbines, internal electrical system, elements of grid connection, control systems, land, etc., comprise BOP. xviii

Nameplate capacity = maximum rated output of a generator under conditions designated by the manufacturer (kilovolt-

amperes (kVA) or kilowatts (kW) (See endnote ii for more on capacity calculations). xix

Capacity factor = average power / power capacity (maximum power output) (See endnote ii for more explanation). xx Regulation and governmental incentives have had tremendous impact on the growth in installed capacity.

To evaluate which incentive was more valuable in wind projects, LBNL did a study in 2009. For a wind project over a range of

installed costs from $1,500/kW to $2,500/kW, and for capacity factors ranging from 25% to 45%, the PTC provides more value

than the ITC in about two-thirds of all cases analyzed. The results are pictured below.





http://www.gtenvfin.com/





http://www.ercot.com/

http://greenpower4texas.com/








http://www.juice-inc.com/index.html





http://www.mrets.net/


http://www.nepoolgis.com/


http://www.nyserda.org/

http://www.nyserda.org/

http://www.midamericanenergy.com/wind/


http://www.motivearth.com/

http://www.pjm-eis.com/gats/about-gats.html





http://www.nexant.com/services/ces.html


http://www.oldmillpower.com/






http://www.pacificrenewables.com/


http://www.peoplesenergy.net/site.asp


http://www.powerlight.com/


http://premierenergyonline.com/buycredits.php


http://www.premierpowersolutions.com/green.html



CONFIDENTIAL


ASSUMPTIONS: 90% of the project was depreciated using a 5-year MACRS schedule. 5% was depreciated using a 20-year MACRS

schedule. The remaining 5% of installed project costs were not considered depreciable, which also made them ineligible for the ITC. The PTC

was applied as $21/MWh in 2008 and escalated at 2%/year, thereafter.

Source: Bolinger et al. (2009)

The diagram below illustrates the impact of the RPS, ITC, PTC, and MACRs on the U.S. wind industry from 1981-2007.


CONFIDENTIAL


xxi GE is the dominant turbine manufacturer (Wiser and Bolinger, 2009). xxii Average project size is 120 MW, according to the Wiser and Bolinger 2009 report. The calculation here uses 2MW x 55 machines,

or 110 MW for project size. xxiii A project cost calculator by Windustry is freely available for download at: http://www.windustry.org/your-wind-

project/community-wind/community-wind-toolbox/chapter-3-project-planning-and-management/wi. Using this tool and average

insurance and other costs published on that site, the total project cost for a farm comprised of 55 2 MW turbines, would be

$192,500,000. xxiv

See Greentech Media article from February 22, 2010 for more information:

http://www.greentechmedia.com/articles/read/where-will-solar-power-plants-be-built-deserts-or-rooftops/ xxv Insolation stands for incident solar radiation and measures the solar radiation energy (kWh) received on a given surface (m2) in a

given time (year) – i.e. kWh/m2/year. Insolation is greatest when the surface directly faces the sun. As the angle between the

solar PV panel and the incident sunlight approaches 90°, electricity generation is maximized. xxvi Kilowatt peak rating (kWp) is calculated from power output in 1,000 watts/m2. In other words, a 2kWp system would have

power generation (Pgen) capacity of 2 kilowatts, insolation flux (Fsol) of 1,000 watts/ m2/yr and a defined area(A), of, say, 34 m2.

Power generation equals conversion efficiency times insolation flux times area (Pgen = Φ Fsol A), one can calculate the conversion

efficiency of a 2kWp system, 34 m2 in size by Φ = Pgen / (Fsol A). Φ in this case would be 2kW / (1000 w/m2 x 34 m2) = 0.06. xxvii Energy generation is calculated by:

Egen = Pgen tul

Pgen = electric power generation (MJ/yr or kW)

tul = useful life of module (10 yrs)

Pgen = Φ Fsol A

Φ = module conversion efficiency (%)

Fsol = insolation flux (kWh/ m2/yr)

A = area of module (m2) xxviii PV capacity factors can be given in DC or AC volts. DC capacity factors account for inverter and other system losses from

heating. AC capacity factors include all system losses, from connecting solar cells through to converting power to grid-compatible

form.

The relationship between kWp and capacity factor (CF - average power divided by maximum power output) is defined as:

CF = Pactual/Ppeak power rating

Pactual/Ppeak = (Φ AF)actual/( Φ AF)peak = Factual/Fpeak

Fpeak = 1000 w/m2

Factual (kWh/ m2/day) is dependent on the site

xxix An inverter converts DC to AC power in grid-connected systems. xxx This figure assumes a 6% discount rate. xxxi This power system was created through fees authorized and regulated by state regulatory commissions and paid for by utility

customers (EIA, 2010). As described in endnote vii, regulated utility rates are set by FERC in rate case hearings, which take place

annually or every several years. The planning, budgeting, and pricing process ties cost ($) to volume of electricity (kWh). This

process has proven a disincentive to consumer energy efficiency.

At present, regulators are moving towards what is termed ‚decoupling‛. Decoupling refers to separating the volume of

electricity sold from the profits utilities earn – for instance by relating prices to number of customers in a given utility district, or

other such mechanism. States with electric decoupling include CA, CT, MD, and WI. Nine additional states, KS, MA, MI, MT, NY,

OH, OK, OR, and WA, are currently considering decoupling in individual rate cases.

An initial move towards market-based pricing includes time-of-use (TOU) pricing – though, ultimately dynamic pricing that

relates to moment-by-moment supply and demand is the goal. For instance, the electric grid seeks to serve people with electricity

greater than 99% of the time than they demand it.

Timing is critical. At certain times of day, electricity demand is far greater than at others – this is called peak power demand.

The diagram below illustrates types of power load at different times of day.

http://www.windustry.org/your-wind-project/community-wind/community-wind-toolbox/chapter-3-project-planning-and-management/wi

http://www.windustry.org/your-wind-project/community-wind/community-wind-toolbox/chapter-3-project-planning-and-management/wi

http://www.greentechmedia.com/articles/read/where-will-solar-power-plants-be-built-deserts-or-rooftops/

CONFIDENTIAL


Source: NREL (2010)

Along with time of day, demand changes with temperature and seasons.

Supply changes due to planned down-time and unanticipated outages.

To maintain reliability, a buffer, called a capacity margin, must be built into power supply to absorb changes in demand on a

daily, seasonal, and annual basis. The capacity margin is required because electricity must be used when produced. In other

words, it cannot be efficiently stored. The graph below shows the capacity margin required to accommodate changes in seasonal

demand from 1996-2003.

Source: EIA (2010)

Peak-load power is served by peak-load power plants; the component of demand that is consistent throughout a day or year is

served by base-load power plants. Base load plants serve electricity at an essentially constant rate and are operated to maximize

system mechanical and thermal efficiency and minimize system operating costs. Peak load power plants generate electricity only

at times of peak demand, and as such, cannot do the same. Inconsistent demand for the power generated by peaker plants means

that plant operators must purchase fuel on the spot market, exposing generated electricity to higher prices and price volatility.

Moreover, the plants sit idle for much of the year, generating zero revenues. Peaker plants are consequently more expensive to

operate, produce more expensive electricity, and, because they cannot be operated for maximum efficiency, are also more

polluting.

While demand for electricity as whole is increasing by one percent per annum, demand for peak power is projected to increase

by 19% over the next ten years (Source: http://www.larouchepub.com/other/2006/3343power_shortages.html). While the cost of

developing peaker plants would ultimately be borne by consumers, utilities would also have to invest in additional transmission

and distribution lines – an under-taking that would be fought by property owners and dwellers everywhere. Though utilities can

pass the cost of T&D build-up along as well, they are seeking more efficient and cheaper ways to maintain system reliability. The

simplest way would be to curb demand – particularly at peak times. Time-of-use (TOU) pricing would be the strongest

mechanism to do this.

Dynamic and stepped pricing are attempts at demand-side management (DSM). Other DSM programs include utilities offering

rebates to consumers who purchase more efficient appliances and equipment. Additionally, DSM involves utilities controlling

information about electricity and managing physical flows better – for instance by powering off appliances that are drawing

power simply to stay in standby mode (i.e. while they are not actively being used).

http://www.larouchepub.com/other/2006/3343power_shortages.html

CONFIDENTIAL


An alternate mechanism to curb peak demand is Demand Response (DR). DR programs involve utilities signing participants

who volunteer to have their power turned off whenever the utility deems that the system is approaching a critical point – e.g.

imminent overload. In the event of turn-off, participants are paid a fee by utilities. It should be noted that while this curbs

demand on the electric grid, it does not change aggregate demand: participants always have back-up power that switches on

during a utility DR event. Consequently, dynamic pricing and other DSM measures are better methods of curtailing demand. xxxii The specific energy efficiency programs, products, and services into which the investment went were not detailed. xxxiii Generation at the point of use increases efficiency by simply cutting out the 9% losses that occur during transmission and

distribution. xxxiv Building integrated PV (BIPV): photovoltaic materials that replace conventional materials in the building envelope – e.g. roof,

skylights, or facades. Integration of PV materials into the building façade can offset the typical hurdle of high upfront investment

costs for PV systems by eliminating expenditures that would have been spent on building materials and labor. xxxv Small-scale wind turbines are defined as turbines with <100 kW of capacity. A brief list of manufacturers can be found at:

http://www.awea.org/smallwind/smsyslst.html. xxxvi Cogeneration and CHP systems produce electricity of mechanical power and recover waste heat for process use, using diesel or

natural gas engines, steam, gas, or micro-turbines, and fuel cells. System efficiency can be upwards of 90%. The schematic below

shows energy flows for separate heat and power (SHP) and CHP systems.

xxxvii Fuel cells are electrochemical cells that convert the chemical energy in a fuel into electrical current and water. They are

comprised of anodes, electrolytes and cathodes as shown in the diagram below.


At the anode, a catalyst oxidizes the fuel (e.g. hydrogen) and turns it into a positively charged ion and a negatively charged

electron. The ion and electron meet the electrolyte. The electrolyte is a substance specifically designed so ions can pass through it,

but the electrons cannot. Freed electrons travel through a wire creating the electrical current. Ions travel through the electrolyte to

the cathode. Once reaching the cathode, the ions are reunited with the electrons. The ions and electrons react with a third

chemical (e.g. oxygen) to create water or carbon dioxide.

Fuel cells are made using a number of different substances. For all, the costs are still quite high and the demonstrated life-span

is short (e.g. 1 year).

http://www.awea.org/smallwind/smsyslst.html

CONFIDENTIAL


xxxviii Microgrids are ‚electricity and thermal energy delivery systems that include a collection of loads and Distributed Energy

Resources that operate in parallel with a larger power delivery systems‛ (CEC, 2004). Electricity cost reduction and energy

efficiency are the most common benefits delivered by microgrids. Cost components include capital and O&M costs of distributed

generation resources and transmission and distribution. Elements that subsidize costs are retail energy and capacity electric grid

costs as well as standby charges, and cogeneration/RECs. xxxix Cogeneration is a term also used to refer to combined-cycle power plants that use natural gas, fuel oil, and syngas.

Supplementary fuels, like coal and biofuels can be used, but are not in wide use. Next generation power plant developments

include integrated solar combined cycle power plants and nuclear combined cycle power plants. These plants use conventional

centralized designs and produce at scale (e.g. ~500 MW). An example of a new combined cycle plant is the Queens, NY-based

CHP 500MW combined cycle natural gas plant being developed at present by Astoria Energy LLC to serve governmental

customers. xl Chauffage is a system in which building owners purchase supplies of heating, cooling, or electricity from CHP or cogeneration

system rather than the equipment itself, in the same way as one might purchase energy savings from other types of EE projects,

or energy from a power plant. The difference between chauffage and energy savings is that the former has a fixed asset that can

be collateralized.

clean tech opp us 2010

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