Financing Renewable Energy Projects in the United States:

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Financing Renewable Energy Projects in the United
States Theory Practice energyinvest The
International Energy Investment Symposium Vienna,
Austria Thursday, October 8, 2009 Daniel
Englander Senior Energy Analyst GTM Research
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About GTM Research
GTM Research provides economic analysis for the
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deliver critical intelligence and strategic
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Research is valued for our objective stance,
integrated economic analysis, and flexibility in
responding to client needs. We conduct
traditional market research, multiclient studies,
strategic consulting, and timely advisory for
leading technology vendors, investors, utilities,
and government bodies. With specific expertise in
solar power, the Smart Grid, and enterprise
energy use, GTM Research stands at the forefront
of the renewable energy industry.  
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Three Important Considerations for Understanding
U.S. RE Finance
Regulation Electricity is regulated
predominantly at the state level, but also
locally and federally. Incentives RE
incentives are designed to push new generation
technologies onto the market. Taxes
Americans hate paying them. This is important.
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There are 51 Distinct Electricity Markets in the
United States

• Each state has a public utilities commission
  responsible for regulating networkutilities in
  that state. This includes
• Setting electricity rates
• Ruling on the composition of utility portfolios
• Enforcing the renewable portfolio standard, if
  one exists

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Renewable Portfolio Standards Are a Primary
Market Driver

• A renewable portfolio standard (RPS) is a
  regulation requiring utilities and/or
  electricity providers to obtain a certain
  percentage of their supply from renewableenergy
  sources by a certain date.
• RPSs create two revenue streams for project
  owners and investors
• Electricity
• Renewable Energy Credits (RECs)

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Renewable Portfolio Standards Are a Primary
Market Driver
WA 15 by 2020
ME 30 by 2000 New RE 10 by 2017
VT (1) RE meets any increase in retail sales by
2012 (2) 20 RE CHP by 2017
MN 25 by 2025 (Xcel 30 by 2020)
MT 15 by 2015

• NH 23.8 by 2025

ND 10 by 2015
MI 10 1,100 MW by 2015

• MA 15 by 2020 1 annual increase(Class I
  Renewables)

• OR 25 by 2025 (large utilities)
• 5 - 10 by 2025 (smaller utilities)

SD 10 by 2015
WI Varies by utility 10 by 2015 goal

• NY 24 by 2013

RI 16 by 2020
CT 23 by 2020

• NV 25 by 2025

IA 105 MW

• OH 25 by 2025

• CO 20 by 2020 (IOUs)
• 10 by 2020 (co-ops large munis)

• PA 18 by 2020

WV 25 by 2025

• IL 25 by 2025

• NJ 22.5 by 2021

CA 33 by 2020
UT 20 by 2025
KS 20 by 2020
VA 15 by 2025

• MD 20 by 2022

• MO 15 by 2021

• AZ 15 by 2025

• DE 20 by 2019

• NC 12.5 by 2021 (IOUs)
• 10 by 2018 (co-ops munis)

• DC 20 by 2020

• NM 20 by 2020 (IOUs)
• 10 by 2020 (co-ops)

TX 5,880 MW by 2015
29 states DC have an RPS 6 states have goals
HI 40 by 2030

State renewable portfolio standard
Minimum solar or customer-sited requirement

State renewable portfolio goal
Extra credit for solar or customer-sited
renewables

Solar water heating eligible
Includes non-renewable alternative resources
Source DSIRE
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Solar Carve-Outs Drive Utility Demand, For Example
California 1,893 MW of PPA projectsplanned
through 2014.
Source GTM Research
Most of these states require their utilities to
fulfill some of their RPS specificallywith solar
PV. This means, generally, REC prices for solar
electricity are higher thanstandard REC prices.
Where solar REC prices are higher, we tend to see
morelarge-scale project development.
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Most States Have RE Incentives, Some Are Better
Than Others
RE incentives in the U.S. are designed to reduce
the cost of the project, not necessarily to
increase its price. This is a fundamental
difference between the U.S. and Europe and one
that impacts financing of projects to a great
extent.
The impact of combined federaland state
incentives in Californiareduces the levelized
cost ofelectricity for solar PV by as muchas
0.20/kWh.
Source GTM Research
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State Level Incentives Focus Mostly on DG

• RE in the U.S. is divided into two broad
  categories
• Distributed Generation Customer sited, customer
  serving
• System/Utility Sided Electricity flows directly
  into the grid
• Net metering bridges this gap, allowing excess DG
  to flow into the grid.

The Customer Side
The Utility Side
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Federal Incentives are a Primary Driver of System
Side Projects

• The Federal Government provides two primary
  incentives. Both are designed to reduce project
  capital cost and encourage project investment.
• Federal Investment Tax Credit Provides 30
  reduction in capital cost of generating
  equipment
• Equipment must be placed in service before ITC
  is received
• 1 year carryback, 20 year carryforward
• 5 year recapture period
• Domestic use/ownership requirement
• Tax exempt entities do not qualify
• Production tax credit is similar, providing
  0.02/kWh for tax reduction
• Accelerated Depreciation Tax basis of project
  reduced by 50 of ITC
• Uses 5 Year Modified Accelerated Cost Recovery
  System (20, 32, 19.2, 11.52, 11.52, 5.76)
• Bonus Depreciation available for projects placed
  in service in 2009 additional 50 reduction
  in first year
• Requires tax appetite
• Combined, these reduce project costs by as much
  as 60.

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Unlike a Fixed-Price Feed-in Tariff, Nothing Here
is Guaranteed

• Fixed-price Feed-in Tariffs (Germany, Spain,
  Italy, Greece, Austria, etc.) and must-take
  obligation substantially reduce project risk,
  i.e., traditional project financeis much easier
  to come by in Europe.
• In the U.S., equity investment plays a much
  larger role.
• This is good because Tax equity draws in
  institutions with tax appetite insurance
  companies, hedge funds, investment banks
  allowing for larger
• pools of capital and larger projects.
• This is bad because The project markets only
  work where tax appetites exist
• Typically, only large institutions with
  substantial tax burdens can monetize
• MACRS and the ITC efficiently. But, when tax
  burdens are reduced in a recession, for
  example this money disappears and project
• development slows.
• Necessitates complex project finance and equity
  structures to ensure capital is deployed
  efficiently, and return requirements are met.

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Most Large Projects are Structured Around PPAs

• A power purchase agreement is a bilateral,
  long-term contract between a utilityand an
  exempt wholesale generator, independent power
  producer, or qualifying facility. Exists for all
  generation capacity, not just renewables.
• Utilities will purchase both the electricity and
  the RECs from a renewable energy facility in
  order to fulfill their RPS requirements.
• The structure underlying a PPA depends on the
  technology, the project cost, itslocation, REC
  prices, utility avoided cost, among other things
• There are two primary PPA structures
• Partnership Flip
• Sale/Leaseback

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PPA Projects Require Coordination Among Numerous
Entities
Source GTM Research
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A Sale/Leaseback Allows for 100 Financing, ITC
Split
Tax Investor
Equity
Leasback
PPA
Developer
Utility
SPV
Sale

• Equity investor (through SPV) pays full market
  value for the project
• Developer benefits through reduced lease
  payments to SPV
• Either lessor or lessee can take tax benefits
• In return, lessee grants lessor collateral
  benefit of PPA and REC sales
• Must be true lease, with lease limited to 80
  of expected project life
• S/L more risky for tax investor, more expensive
  for developer

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The Partnership Flip Lets Tax Investors Monetize
ITC Directly
Tax Investor
Developer
99 Pre-flip, 4.95 Post-flip
1 Pre-flip, 95.05 Post-flip
Utility
Partnership
PPA

• Maximizes tax benefit by allocating ITC/MACRS
  directly to tax investor through partnership
  pass through
• Partnership rules allocates 99 of tax benefits
  to tax investor until the tax investor hits its
  required IRR typically occurs in first 7-10
  years of project
• After this, the PPA REC revenues, and
  remaining tax benefits, flip to developer
• Pship Flips are more risky for developer, less
  risky for tax investor because of duration of
  residual ownership

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These are Complicated Necessary, But Only With
Tax Equity
What happens when there is no tax equity? At the
market top in mid-2008, 24 tax investors had
deployed roughly 6 billion in capital in the
previous 12 months. Of those 24, only three or
four are active today.
Source GTM Research
To address this shortfall, Congress included an
option to apply for and receivea 30 cash grant
in lieu of the ITC in the ARRA.
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Removal of Utility Exemption Opens Doors to
Direct Ownership

• In October 2008, Congress extended the ITC for
  another eight years and removedthe utility
  exemption from the ITC. This allowed utilities,
  which have fairly large and stable tax burdens,
  to consider building and owning their own
  renewable energy projects.
• The exemption removal also brought to light a
  number of issues relating to the consideration
  of RE as an included generation technology.
• How to account for resource variability in
  long-term portfolio planning?
• Does PPA-based procurement strategy make sense
  from a risk perspective
• Power delivery risk
• Customer cost risk
• How willing are state regulators to accept
  utilities owning and operating their own RE
  projects?
• What rules and frameworks need to be in place
  for this to happen?

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Four Primary Benefits of Direct Ownership to a
Utility

• RPS Compliance Removes some risk of REC
  shortfall from PPA projects and means the
  utility may not need to turn to the open REC
  market to meet compliance goals.
• Debt Equivalence Power Purchase Agreements are
  treated as debt on utility balance sheet,
  without equivalent equity contribution.
  Overreliance on PPAs may weaken utility credit
  rating and financial health.
• Customer-Owned Distributed Generation
  Increasing DG penetration cuts into short-term
  marginal revenues, leaving other customers to
  bear higher share of long-term marginal costs.
• Natural Gas and CO2 Price Risk PV output
  profile at high effective load carrying
  capability may displace marginal natural gas
  plants, limiting utility exposure to gas price
  volatility and CO2 price uncertainty.

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UOG Projects Are Simpler and Involve Fewer
Parties than PPAs
Source GTM Research
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UOG is Big Step Towards RE Competing with Brown
Power
Source GTM Research

• Solar PV attains highest energy yield at times
  coincident with peak load.
• In the U.S., peak load is typically satisfied by
  natural gas generators, whose prices are
  determined primarily (gt50) by the price of
  natural gas.

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Carbon Prices Do Not Need to Be High to Make RE
Competitive
Source GTM Research
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Progress of UOG Will be Determined on a
State-by-State Basis
Ultimately, the decision to move forward with
utility ownership lies withthe state utility
commissions and the utilities themselves. If
there is a future for this market segment, a much
larger door will openfor traditional energy
companies, EPCs, and manufacturers than has
existed previously.
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In Conclusion

• Financing renewable energy projects in the
  United States is a complex process determined by
  technology, risk appetite of investors and
  lenders, location, regulations, available
  incentives, and a host of other issues.
• The market push mechanisms in the U.S. make
  project development there a an extremely
  cost-competitive market with lower vendor margins
  requiring significantly more financial
  engineering than in Europe.
• This market condition does not lend itself to
  fast growth, but it does create the conditions
  for sustainable, long-term growth.
• In the absence of climate legislation, fuel cost
  risk will emerge as the primary economic driver
  of large-scale project development in the U.S.
  This may not be enough to allow the U.S. to
  reach its climate goals.
• With climate legislation, however, dual market
  pressure will force the power industry into
  taking a much harder, much closer look at RE than
  it is currently.

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Thank You! Daniel Englander Senior Energy
Analyst GTM Research 576 Sacramento St., 2nd
Floor San Francisco, CA 94115 englander_at_gtmresear
ch.com 1 617-417-8925