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Transcript of Clean Tech Opp US 2010
CONFIDENTIAL
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
STATE OF THE MARKET 34
Cost 35
Output 36
Business Models 38
Financing Structures 39
LCOE 48
FINANCING OPPORTUNITY 48
Financials 49
SOLAR ENERGY 54
MARKET POTENTIAL 54
STATE OF THE MARKET 55
Cost 56
Output 58
Government policies 61
Business Models 66
Financing Structures 67
FINANCING OPPORTUNITY 74
Financials 75
ELECTRICITY 87
MARKET POTENTIAL 87
STATE OF THE MARKET 95
Financing 97
Companies 100
ENERGY EFFICIENCY 102
MARKET POTENTIAL 102
STATE OF THE MARKET 102
Cost 102
Savings 103
Government policies 106
Business Models 109
Financing Structures 110
FINANCING OPPORTUNITY 112
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
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 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.
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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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DRAFT DOCUMENT CONFIDENTIAL 23
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
Source: www.dsireusa.org / March 2010
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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
Source: www.dsireusa.org / February 2010
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
Source: www.dsireusa.org / February 2010
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
Source: www.dsireusa.org / February 2010
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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)
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. 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
Source: www.dsireusa.org / March 2010
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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Source: US PREF (2010)
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Source: US PREF (2010)
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)
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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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Source: Harper et al. (2007)
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Source: Harper et al. (2007)
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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.
Source: Cory & Schwabe (2009)
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.
Source: Cory & Schwabe (2009)
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 46
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:
Source: Harper et al. (2007)
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.
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 47
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.
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 48
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).
FINANCING OPPORTUNITY
Total installed wind capacity in the U.S. today is 35,062 MW; this can grow to more than 300,000 MW by
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.
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, as seen by the cast of tax
equity characters in the table presented above.
Companies in the wind energy space are presented below.
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 49
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
($USDmm)
Coupon
Rate (%)
Coupon
Type
S&P Security
Credit Rating
Ultimate
Parent Name
Private Placement
Features [Issuer]
[Target/Issuer]
Private Placement Features [Ultimate
Parent] [Target/Issuer]
May-11-2007 May-15-2047 Westar Energy,
Inc. (NYSE:WR)
Preferred
Security
Preferred 150.0 150.0 6.1 Fixed BBB+ (Apr-27-
2010)
Westar
Energy, Inc.
(NYSE:WR)
05/10/2002 Private
Placement
(Target/Issuer: Westar
Energy, Inc. (NYSE:WR)) -
Rule 144A
05/10/2002 Private Placement
(Target/Issuer: Westar Energy, Inc.
(NYSE:WR)) - Rule 144A
Jul-08-2002 Jul-01-2042 Northern States
Power (MN)
Preferred
Security
Senior
Unsecured
175.0 - 8.0 Fixed BBB- (Jul-16-
2002)
Xcel Energy
Inc.
(NYSE:XEL)
- 11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Convertible Debt
11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Rule 144A
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 50
Pricing Date Maturity
Date
Issuer Security Type Seniority
Level
Offering
Amount
($USDmm)
Amount
Outstanding
($USDmm)
Coupon
Rate (%)
Coupon
Type
S&P Security
Credit Rating
Ultimate
Parent Name
Private Placement
Features [Issuer]
[Target/Issuer]
Private Placement Features [Ultimate
Parent] [Target/Issuer]
Feb-03-2010 Mar-01-2040 Florida Power &
Light Co.
Corporate
Debentures
Senior
Secured
500.0 500.0 5.69 Fixed A (Feb-5-
2010)
FPL Group
Inc.
(NYSE:FPL)
04/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) -
Regulation S
4/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) - Rule
144A
-
Nov-09-2009 Nov-01-2039 Northern States
Power (MN)
Corporate
Debentures
Senior
Secured
300.0 300.0 5.35 Fixed A (Nov-10-
2009)
Xcel Energy
Inc.
(NYSE:XEL)
- 11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Convertible Debt
11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Rule 144A
Jul-07-2009 Jul-15-2039 Interstate Power
& Light
Company
Corporate
Debentures
Senior
Unsecured
300.0 300.0 6.25 Fixed BBB+ (Jul-7-
2009)
Alliant
Energy
Corporation
(NYSE:LNT)
12/18/2002 Private
Placement
(Target/Issuer: Interstate
Power & Light Company) -
Rule 144A
-
Mar-11-2009 Apr-01-2039 Florida Power &
Light Co.
Corporate
Debentures
Senior
Secured
500.0 500.0 5.96 Fixed A (Apr-21-
2009)
FPL Group
Inc.
(NYSE:FPL)
04/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) -
Regulation S
4/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) - Rule
144A
-
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 51
Pricing Date Maturity
Date
Issuer Security Type Seniority
Level
Offering
Amount
($USDmm)
Amount
Outstanding
($USDmm)
Coupon
Rate (%)
Coupon
Type
S&P Security
Credit Rating
Ultimate
Parent Name
Private Placement
Features [Issuer]
[Target/Issuer]
Private Placement Features [Ultimate
Parent] [Target/Issuer]
Jan-05-2009 Jan-15-2039 PacifiCorp Corporate
Debentures
Senior
Secured
650.0 650.0 6.0 Fixed A (Mar-27-
2009)
MidAmerican
Energy
Holdings
Company
- 03/21/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Rule 144A
3/1/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Equity Line
Aug-06-2008 Aug-01-2038 Public Service
Co. of Colorado
Corporate
Debentures
Senior
Secured
300.0 300.0 6.5 Fixed A (Aug-15-
2008)
Xcel Energy
Inc.
(NYSE:XEL)
- 11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Convertible Debt
11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Rule 144A
Jul-14-2008 Jul-15-2038 PacifiCorp Corporate
Debentures
Senior
Secured
300.0 300.0 6.35 Fixed A (Mar-27-
2009)
MidAmerican
Energy
Holdings
Company
- 03/21/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Rule 144A
3/1/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Equity Line
Jan-10-2008 Feb-01-2038 Florida Power &
Light Co.
Corporate
Debentures
Senior
Secured
600.0 600.0 5.95 Fixed A (Jan-15-
2008)
FPL Group
Inc.
(NYSE:FPL)
04/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) -
Regulation S
4/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) - Rule
144A
-
Aug-14-2007 Dec-15-2037 Kansas Gas and
Electric
Company
Corporate
Debentures
Senior
Secured
175.0 175.0 6.53 Fixed - Westar
Energy, Inc.
(NYSE:WR)
- 05/10/2002 Private Placement
(Target/Issuer: Westar Energy, Inc.
(NYSE:WR)) - Rule 144A
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 52
Pricing Date Maturity
Date
Issuer Security Type Seniority
Level
Offering
Amount
($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]
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)
- 05/10/2002 Private Placement
(Target/Issuer: Westar Energy, Inc.
(NYSE:WR)) - Rule 144A
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
- 03/21/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Rule 144A
3/1/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Equity Line
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)
- 11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Convertible Debt
11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Rule 144A
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)
- 11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Convertible Debt
11/18/2002 Private Placement
(Target/Issuer: Xcel Energy Inc.
(NYSE:XEL)) - Rule 144A
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
(Target/Issuer: Florida
Power & Light Co.) -
Regulation S
4/24/2006 Private
Placement
(Target/Issuer: Florida
Power & Light Co.) - Rule
144A
-
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 53
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
distributed projects over time.
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]
Mar-09-2007 Apr-01-2037 PacifiCorp Corporate
Debentures
Senior
Unsecured
1.0 20.0 5.75 Fixed - MidAmerican
Energy
Holdings
Company
- 03/21/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Rule 144A
3/1/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Equity Line
Mar-09-2007 Apr-01-2037 PacifiCorp Corporate
Debentures
Senior
Secured
600.0 600.0 5.75 Fixed A (Mar-27-
2009)
MidAmerican
Energy
Holdings
Company
- 03/21/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Rule 144A
3/1/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Equity Line
Mar-09-2007 Apr-01-2037 PacifiCorp Corporate
Debentures
Senior
Unsecured
28.0 28.0 5.75 Fixed A (Mar-27-
2009)
MidAmerican
Energy
Holdings
Company
- 03/21/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Rule 144A
3/1/2006 Private Placement
(Target/Issuer: MidAmerican Energy
Holdings Company) - Equity Line
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 54
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
DRAFT DOCUMENT CONFIDENTIAL 55
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
DRAFT DOCUMENT CONFIDENTIAL 56
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
DRAFT DOCUMENT CONFIDENTIAL 57
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
DRAFT DOCUMENT CONFIDENTIAL 58
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
DRAFT DOCUMENT CONFIDENTIAL 59
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.
Source: University of Michigan (2008)
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
DRAFT DOCUMENT CONFIDENTIAL 60
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
DRAFT DOCUMENT CONFIDENTIAL 61
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
DRAFT DOCUMENT CONFIDENTIAL 62
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
DRAFT DOCUMENT CONFIDENTIAL 63
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
DRAFT DOCUMENT CONFIDENTIAL 64
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
Source: www.dsireusa.org / March 2010
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 65
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
DRAFT DOCUMENT CONFIDENTIAL 66
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
DRAFT DOCUMENT CONFIDENTIAL 67
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.
Financing Structures
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.
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DRAFT DOCUMENT CONFIDENTIAL 68
Source: Feo & Tracy (2009)
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
DRAFT DOCUMENT CONFIDENTIAL 69
Source: Feo & Tracy (2009)
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
DRAFT DOCUMENT CONFIDENTIAL 70
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
DRAFT DOCUMENT CONFIDENTIAL 71
Source: Feo & Tracy (2009)
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
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 72
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:
Source: Bolinger (2009)
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
DRAFT DOCUMENT CONFIDENTIAL 73
Source: Bolinger (2009)
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
DRAFT DOCUMENT CONFIDENTIAL 74
FINANCING OPPORTUNITY
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
DRAFT DOCUMENT CONFIDENTIAL 75
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
DRAFT DOCUMENT CONFIDENTIAL 76
Solar Debt (2009-present)
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]
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
01/22/2010 Private Placement
(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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
Jan-21-2010 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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 77
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]
Jan-21-2010 Jan-27-2040 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 850.0 850.0 5.6 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-21-2010 Jan-27-2040 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 850.0 850.0 5.6 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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
04/30/2007 Private Placement
(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)
- 01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Nov-12-2009 Nov-12-2031 EDF Energy
Netw orks Ltd.
Corporate DebenturesSenior Unsecured 495.9 459.1 6.125 Fixed A (Nov-13-
2009)
Electricite de
France SA
(ENXTPA:EDF)
- 01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Nov-12-2009 Nov-12-2036 EDF Energy
Netw orks Ltd.
Corporate DebenturesSenior Unsecured 578.6 535.62 6.0 Fixed A (Nov-13-
2009)
Electricite de
France SA
(ENXTPA:EDF)
- 01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
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)
- 01/07/2009 Private Placement
(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
01/07/2009 Private Placement
(Target/Issuer: Scottish & Southern
Energy plc (LSE:SSE)) - Subsequent
Direct Listing
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 78
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]
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
(Target/Issuer: E.On
International Finance B.V.) -
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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jul-09-2009 Jul-09-2012 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 175.7 173.17 1.24 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jul-09-2009 Oct-09-2014 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 485.1 478.09 1.63 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 79
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]
Jul-09-2009 Jul-08-2016 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 475.4 468.53 2.0 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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)
- 1/2001 Private Placement
(Target/Issuer: EnBW Energie Baden-
Wuerttemberg AG (DB:EBK)) - Cross-
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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 80
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]
Jul-09-2009 Jul-08-2016 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 475.4 468.53 2.0 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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)
- 1/2001 Private Placement
(Target/Issuer: EnBW Energie Baden-
Wuerttemberg AG (DB:EBK)) - Cross-
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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
Jun-22-2009 Jun-22-2012 E.On International
Finance B.V.
Corporate DebenturesSenior Unsecured 300.0 300.0 3.125 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
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 81
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]
Jun-19-2009 Jun-19-2019 Iberdrola SA
(CATS:IBE)
Corporate DebenturesSenior Unsecured 20.9 19.93 5.65 Fixed - Iberdrola SA
(CATS:IBE)
06/16/2009 Private
Placement
(Target/Issuer: Iberdrola
SA (CATS:IBE)) - Cross-
Border
6/27/2007 Private
Placement
(Target/Issuer: Iberdrola
SA (CATS:IBE)) - Cross-
Border
12/8/2005 Private
Placement
(Target/Issuer: Iberdrola
SA (CATS:IBE)) - Cross-
Bord
06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
Jun-02-2009 Jun-02-2034 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 2,480.0 2,295.51 6.125 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jun-02-2009 Jun-02-2034 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 2,480.0 2,295.51 6.125 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
May-29-2009 May-29-2014 E.On International
Finance B.V.
Corporate DebenturesSenior Unsecured 104.8 106.24 1.83 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
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 82
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-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
(Target/Issuer: E.On
International Finance B.V.) -
Regulation S
4/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
Mar-27-2009 Mar-27-2012 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 261.5 324.49 2.0 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Mar-27-2009 Mar-27-2017 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 261.5 278.14 4.0 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 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
(Target/Issuer: E.On
International Finance B.V.) -
Regulation S
4/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 83
Pricing Date Maturity
Date
Issuer Security Type Seniority
Level
Offering
Amount
($USDmm)
Amount
Outstanding
($USDmm)
Coupon
Rate (%)
Coupon
Type
S&P Security
Credit Rating
Ultimate
Parent Name
Private Placement
Features [Issuer]
[Target/Issuer]
Private Placement Features [Ultimate
Parent] [Target/Issuer]
Mar-04-2009 Mar-04-2014 Iberdrola
Finanzas S.A.U.
Corporate DebenturesSenior Unsecured 1,888.6 1,992.69 4.875 Fixed A- (Feb-27-
2009)
Iberdrola SA
(CATS:IBE)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
Feb-25-2009 Feb-25-2011 E.On International
Finance B.V.
Corporate DebenturesSenior Unsecured 365.0 463.56 2.0 Fixed - E.ON AG
(DB:EOAN)
04/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
Regulation S
4/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
Feb-11-2009 Feb-11-2014 E.On International
Finance B.V.
Corporate DebenturesSenior Unsecured 345.3 486.74 3.375 Fixed - E.ON AG
(DB:EOAN)
04/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
Regulation S
4/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
Feb-05-2009 Feb-05-2014 Scottish &
Southern Energy
plc (LSE:SSE)
Corporate DebenturesSenior Unsecured 1,026.6 1,071.24 5.75 Fixed A- (Aug-21-
2009)
Scottish &
Southern
Energy plc
(LSE:SSE)
01/07/2009 Private
Placement
(Target/Issuer: Scottish &
Southern Energy plc
(LSE:SSE)) - Subsequent
Direct Listing
01/07/2009 Private Placement
(Target/Issuer: Scottish & Southern
Energy plc (LSE:SSE)) - Subsequent
Direct Listing
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 84
Pricing Date Maturity
Date
Issuer Security Type Seniority
Level
Offering
Amount
($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]
Jan-29-2009 Jan-29-2024 Iberdrola
Finanzas S.A.U.
Corporate DebenturesSenior Unsecured 716.1 765.17 7.375 Fixed - Iberdrola SA
(CATS:IBE)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
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
(Target/Issuer: E.On
International Finance B.V.) -
Regulation S
4/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
Jan-26-2009 Jan-26-2014 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 1,250.0 1,250.0 5.5 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-26-2009 Jan-26-2019 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 2,000.0 2,000.0 6.5 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-26-2009 Jan-26-2039 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 1,750.0 1,750.0 6.95 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 85
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]
Jan-23-2009 Jan-27-2014 E.On International
Finance B.V.
Corporate DebenturesSenior Unsecured 480.0 535.62 5.125 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
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
Jan-23-2009 Jan-23-2015 Electricite de
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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-23-2009 Jan-25-2021 Electricite de
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
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-23-2009 Jan-27-2039 E.On International
Finance B.V.
Corporate DebenturesSenior Unsecured 960.0 1,071.24 6.75 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
(Target/Issuer: E.On
International Finance B.V.) -
Rule 144A
-
Jan-21-2009 Jan-26-2014 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 1,250.0 1,250.0 5.5 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-21-2009 Jan-26-2019 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 2,000.0 2,000.0 6.5 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
CONFIDENTIAL
DRAFT DOCUMENT CONFIDENTIAL 86
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 $1.4 trillion between now and 2030 are to be believed, the opportunity for
financial innovators is significant.
Being a distributed generation technology, the solar industry’s development depends on upgrades to the transmission grid. This is discussed in the next section.
Pricing Date Maturity
Date
Issuer Security Type Seniority
Level
Offering
Amount
($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]
Jan-21-2009 Jan-26-2039 Electricite de
France SA
(ENXTPA:EDF)
Corporate DebenturesSenior Unsecured 1,750.0 1,750.0 6.95 Fixed - Electricite de
France SA
(ENXTPA:EDF)
01/22/2010 Private
Placement
(Target/Issuer: Electricite
de France SA
(ENXTPA:EDF)) - Rule
144A
01/22/2010 Private Placement
(Target/Issuer: Electricite de France SA
(ENXTPA:EDF)) - Rule 144A
Jan-19-2009 Jan-19-2016 E.On International
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
(Target/Issuer: E.On
International Finance B.V.) -
Regulation S
4/15/2008 Private
Placement
(Target/Issuer: E.On
International Finance B.V.) -
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)
- 06/16/2009 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
6/27/2007 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Border
12/8/2005 Private Placement
(Target/Issuer: Iberdrola SA
(CATS:IBE)) - Cross-Bord
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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).
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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
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DRAFT DOCUMENT CONFIDENTIAL 95
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.
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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.
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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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Source: Greentech Media (2010)
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Source: Greentech Media (2010)
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.
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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
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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.
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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
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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.
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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
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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
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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
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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.
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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.
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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) .
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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.
Financing Structures
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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).
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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)
FINANCING OPPORTUNITY
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.
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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.
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
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.
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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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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.
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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.
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Source: University of Michigan (2008)
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.
Source: University of Michigan (2008)
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
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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.
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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.
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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
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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
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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.
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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.
Source: Bolinger (2008)
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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.
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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).
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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.
Source: University of Michigan (2008)
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).
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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.