WIND RESOURCES, INC. In July 2005, Mr. Charl.docx

WIND RESOURCES, INC.
In July 2005, Mr. Charles Bittner, chief executive officer of
Wind Resources, Inc. (WRI),
needed to decide how best to capitalize on the company’s
development easement located
in the San Gorgonio Pass near Palm Springs, California. In
1985, WRI had acquired the
easement from the property’s owner, the Bureau of Land
Management (BLM), and
entered into a complex 20-year agreement with private
investors, creditors, and Southern
California Edison to build and operate a 30-megawatt wind
energy facility on the site.
With the original agreement about to expire, Mr. Bittner needed
to decide what to do with
the easement. The site, known as Canyon Wind, was reputed
to be “one of the premier
wind resources in North America,” and with conventional
energy prices rising sharply,
continued use of the site as a wind farm seemed the obvious
choice. Two options
appeared feasible. One was to continue operating the site’s
existing but aging turbines.
Ownership of the turbines and related equipment had recently
reverted to WRI when

private investors had encountered difficulty servicing the debt
originally incurred to
purchase them.
A second option was to sell the easement to new owners who
would most likely
redevelop the site much as WRI had done in 1985 but this time
using new, much larger
turbines. Mr. Bittner sensed that WRI’s principal shareholders
were interested in selling
the easement as soon as possible, but before putting the
easement up for sale or auction,
he needed to estimate its value to new owners. (Exhibit 1
shows the Canyon Wind site
and existing turbines. Exhibit 2 is a graph of natural gas prices
over the past two
decades, and Exhibit 3 records the volatility of gas prices over
different time periods.)
The Industry
Today’s wind energy business is a child of OPEC and Western
governments. Concerned
about American dependence on foreign oil and the
environmental damage caused by use
of fossil fuels, the U.S. Congress passed the Public Utilities
Regulatory Policies Act
(PURPA) in 1978 as part of the National Energy Act. The
legislation encouraged
creation of energy from renewable sources, including wind
power, and given certain
conditions, required utilities to buy the energy at the utilities’
highest “avoided cost.”
Avoided cost is the cost of the energy replaced by the renewable
source.

Professors Rocky Higgins and Robert Keeley prepared this case
for classroom discussion. It describes an
actual situation, although some information has been altered.
We thank Professor Avi Kamara for his help
and advice. All remaining errors are ours. © 2007 University
of Washington Business School
1
Wind Resources, Inc.
Although PURPA is Federal Law, Congress delegated
implementation to the states,
resulting in a variety of regulatory schemes across states and
the absence of any activity
at all in others.
In 2004, California took the lead in PURPA enforcement when
it required all major
investment-grade utilities in the state to acquire one percent
more of their power from
renewable sources each year, so that by 2017 at least 20 percent
of total electric supply is
made up of renewable generation. It also mandated a bidding
process requiring fixed-
price 10 to 20 year contracts known as Power Purchase
Agreements (PPAs) at prices
based on the cost of new conventional generating sources.
California’s actions were
largely in response to the devastating energy crisis it suffered in
2001 and a consequent
desire to diversify supply, increase in-state production, and
reduce reliance on natural

gas-fired power.1
As further stimulus to alternative energy development, wind
energy investors benefit
from two lucrative tax breaks. Federal law allows owners to
depreciate qualifying wind
energy assets at an accelerated rate over a five-year period,
even though the economic life
of wind turbines and towers is closer to 20 years. In 1992
Congress created an annual
Production Tax Credit (PTC) for wind and other renewable
energy technologies. The
credit is proportional to the energy produced and extends over
the first 10 years of project
life. The current PTC is 1.9 cents per kilowatt-hour with a cost
of living adjustment of
2.5 percent a year. The original legislation was for only three
years but has been renewed
in fits and starts since. Current legislation extends the PTC
through at least 2008.2
Wind power economics has improved dramatically over the past
two decades, due
primarily to the use of ever-larger turbines. The energy
produced by a turbine is
proportional to the cube of the wind speed and the square of the
turbine’s blade length.
The gradual migration from turbines with blade diameters of 10
meters in the 1980s to
diameters of 50 meters common in 2000 produced a 55-fold
increase in power output,
partly because the area swept by the blade is 25 times larger and
partly because wind
speed increases with blade altitude. Reflecting additional
benefits of better turbine
design, location, and computerized controls, the cost of wind-

generated power has fallen
some 90 percent in the past 20 years.3
Despite these improvements most wind power sources are still
not competitive on price
with fossil fuel power and may not be for years. According to
data from the International
Energy Agency (IEA) in Paris, the cost of electricity from coal-
fired plants is 2.5 – 4
cents per kilowatt-hour, while the cost from natural-gas-fired
plants is 4 to 6 cents. In
contrast, energy costs from wind power range from 4 to 14 cents
per kilowatt-hour,
depending on size and location.4
1 “Overview of the California Model for Encouraging
Renewable Energy Development,” Thelen Reid
Brown Raysman & Steiner LLP, Oil, Gas and Energy Law
Journal, July 26, 2004.
www.constructionweblinks.com/resources/industry_reports_ne.
2 “Congress Extends Wind Energy Production Tax Credit for an
Additional Year,” American Wind Energy
Association, December 11, 2006.
3 “The Economics of Wind Energy,” American Wind Energy
Association, February 2005. www.awea.org.
4 “Renewable Power May Yet Yield Windfall,” Keith Johnson,
Wall Street Journal, p. A8, March 22, 2007.
2
Wind power accounted for only 0.5 percent of global and U.S.

domestic electricity
production in 2004 according to the IEA. By 2030 the agency
expects this figure to rise
almost 7-fold to 3.4 percent. In the U.S. capital spending on
new wind projects in 2005
was on track to exceed $3 billion up from just $420 million in
2004. This would make
wind power the second largest source of new electrical power
for the year behind natural
gas-fired plants.
Keys to a successful wind farm investment are a great site, an
attractive long-term PPA,
and continued government support of renewable energy
resources. Wind farm
investments require large initial capital outlays, followed by
relatively stable long-term
revenue streams. Because predicting wind velocity is much
easier than predicting
where new oil or gas reserves will be found, wind investments
are considered safer
technologically than conventional energy investments. The
chief cost of a wind farm
investment is the initial capital outlay, while the chief risks
involve securing a favorable
PPA and meeting a myriad of regulatory and permitting
requirements, often including the
placating of restive neighbors.
An experienced alternative energy entrepreneur founded WRI in
1985 to develop and
market the Canyon Wind site located on BLM land. He
designed the project to take full
advantage of the liberal tax provisions available to qualifying

renewable energy
investments. As sponsor, WRI identified the site, negotiated a
long-term, renewable
development easement with the BLM, designed the wind farm,
guided the project
through a complex permitting process, secured a 20 year, fixed-
price PPA with Southern
California Edison, negotiated project financing, and identified a
group of potential equity
investors. With all the pieces in place, WRI then commissioned
construction of the wind
farm and sold the capital equipment and equity cash flow rights
for a period of twenty
years to investors. (At the time target investors were wealthy
individuals interested in
available tax credits and shields. Tax laws changes in 1986
prohibited individuals from
using tax shields generated on one activity to reduce tax
obligations generated on another,
so today’s wind farm investors tend to be profitable
corporations, such as General
Electric, anxious to reduce taxes.)
WRI structured the equity transaction as an installment sale on
the expectation that
projected project cash flows to equity investors would be
sufficient to service the
installment debt. One hundred percent debt financing was quite
attractive to equity
investors because it eliminated any initial investment on their
part, guaranteeing they
would be cash flow positive from day one. At worst, equity
investors might default on
the debt and have to walk away without the anticipated tax
shields and profits, while on
the upside, they would capture the anticipated tax benefits and

any residual profits
without any cash outlay.
WRI’s profits would come from a sizeable development fee
incorporated in the project’s
selling price, interest on the installment debt, a share of profits
above a specified level,
and annual fees for managing the facility. WRI also retained
the right to repurchase the
turbines at fair-market value at the end of the project’s life in
2005 and to dispose of the
3
site as they chose. Should they choose not to continue
operating the property as a wind
farm, WRI would incur a site restoration charge of as much as
$2.5 million imposed by
the BLM.
The 1985 Canyon Wind development did not live up to initial
expectations chiefly
because it never delivered more than 75 percent of targeted
capacity. Inaccurate
projections of wind velocity and persistence, combined with
various unanticipated
operating problems, were the chief contributors to the shortfall.
Mr. Bittner was inclined
to attribute these problems to industry growing pains that would
not be repeated in any
future redevelopment of the site.

In the end, equity investors received most of the anticipated tax
shields but little in the
way of profits. The situation was touch and go for a period
when equity investors fell
behind on installment payments to WRI, but they managed to
recoup by the end of the
period, in part by ceding ownership of the turbines and towers
to WRI at the end of their
contract. WRI’s owners did better, receiving anticipated fees
and interest other than
shared profits, while retaining redevelopment rights.
The Alternatives
As the initial 20-year development contract approached
maturity, Charles Bittner needed
to recommend a course of action to his board. Growing
dissention among WRI owners
and financial problems at one inclined Mr. Bittner to rule out
redevelopment by WRI.
The possible imposition of a $2.5 million site restoration fee
made abandoning the
easement appear unattractive as well. Although other strategies
were possible, Mr.
Bittner decided to consider two in detail: continue to operate
the existing turbines, or sell
the BLM easement to another developer at auction.
Continue to Operate Existing Turbines
Exhibit 4 presents Mr. Bittner’s analysis of the first option.
Assuming WRI could keep
the existing turbines operational for another 10 years by
spending an additional $200,000
a year in current dollars on major maintenance, Mr. Bittner
estimated the annual free cash

flow from continued operation would be about $800,000 a year,
for a present value of
just over $4.7 million when discounted at ten percent. Ten
percent reflected Mr. Bittner’s
understanding of industry practice when valuing unlevered wind
energy cash flows.
Sell Easement to another Developer
Mr. Bittner reasoned that the highest price a wind farm
developer would pay for the
Canyon Wind site should equal the profit he could earn by
redeveloping the site much as
WRI had done in 1985. To help estimate the value of the site to
a new developer, Mr.
Bittner turned to MDS Energy Consulting, Inc., an experienced
alternative energy
consultant WRI had used in the past.
In their report, MDS identified seven milestones any
redevelopment must achieve and
briefly discussed the challenges to be addressed in meeting
each.
4
1. Site control. The current BLM easement expires in 2015 and
needs to be
extended before development can commence. MDS noted that
obtaining an

extension was likely but noted that the time, effort and expense
involved could be
“significant.”
2. Wind resource documentation. WRI has twenty years of data
on the strength
and persistence of winds at the site. But use of much larger and
taller turbines
means that additional data will need to be documented and
confirmed as part of
the redevelopment process. Efficiency is measured by a site’s
Net Capacity
Factor (NCF), the ratio of the energy produced per year at a site
divided by the
theoretical maximum possible production.
3. Regulatory and permitting approval. Relevant county
permitting requirements
are some of the most highly developed and specific in the
industry, which makes
the permitting process time consuming, even if third parties do
not oppose the
project. Local residents immediately adjacent to the property
had been quite
vocal and effective in limiting efforts of other projects to
develop nearby sites
with newer and taller turbines. Moreover, because the site is on
Federal property,
significant environmental review might be required, including a
new or updated
Environmental Impact Statement. In MDS’s view
redevelopment permits could

likely be secured but the outcome was not a foregone
conclusion.
4. Interconnection and transmission access. The site has a
working
interconnection with the Southern California Edison grid, and it
is likely this
interconnection can be maintained and enhanced as necessary.
The Federal
Energy Regulatory Commission (FREC) must now approve
applications for
interconnection rights, and while approval appears assured,
costs of enhancing the
interconnection could exceed projections.
5. A long-term power purchase agreement. This is the lynch pin
of any
redevelopment. In order to secure necessary project financing,
a long-term power
purchase agreement with a credit-worthy investment grade
(BBB- or better) buyer
is necessary. MDS noted that the California Public Utilities
Commission (CPUC)
has recently determined that an appropriate price for renewable
energy purchase
under a 15-year PPA starting in 2005 should be $0.0588 per
kWh. And while the
CPUC’s determination does not guaranty this price, it does
provide a good
indication of the potential market.

6. Project financing. Once the redevelopment project has
sufficiently documented
its wind resource and secured site control, permits, an
interconnection and a
viable PPA, it must be financed. Under the current wind
industry paradigm, the
wind project owner must have a substantial appetite for tax
credits. Leveraged
after-tax internal rates of return (IRRs) in the current market
were typically in the
mid-teens, while unleveraged IRRs were in the range of 10
percent. Interest costs
5
on debt financing were 1.5% to 2.5% over 3-month LIBOR, and
the first-year
interest-coverage ratio had to equal at least 1.7 times.
7. Project construction. The Canyon site has several
characteristics that make it a
challenging site for a modern wind energy development,
including difficult terrain
and access to the site. Hauling new, large turbines up and down
the winding
access roads may present a challenge. Ironically, another
challenge may be the
strong winds characteristic of the site, which may force delays
and increase

installation costs.
Exhibit 5 summarizes MDS’s analysis. It envisions that a
developer will purchase the
Canyon Wind easement from WRI and immediately redevelop
the property for sale to
equity investors. The projected redevelopment includes
replacing existing turbines with
20 new General Electric 1.5 megawatt models sporting 77-meter
rotor diameters on 65-
meter towers. It also anticipates negotiating a new 15-year,
fixed-price PPA with
Southern California Edison at 0.0588 $/kWh, and a minimum
first-year interest coverage
of 1.75 times. Other assumptions are that the site’s NCF will
equal 43.74 percent, the
salvage value of existing turbines will about equal the cost of
removal, and interest rates
on project debt will range between 6.5 and 7.0 percent.
The analysis indicates that the total value of the Canyon Wind
Project at a PPA of
$0.0588/kWh is $65.9 million. This number is driven by two
key requirements: that
equity investors see a prospective 15 percent IRR and that first-
year interest coverage
equals 1.75 times. Given these requirements, the spreadsheet in
Exhibit 5 solves
iteratively for total project value by calculating available debt
financing and adding the
present value of residual cash flows to equity. The project
employs senior debt and PTC
debt in a 2 to 1 ratio. Because creditors perceive PTC cash
flows to be less risky than
operating cash flows, the interest rate on a loan secured by PTC

cash flows is lower than
the rate available on senior debt.
With total development costs estimated to be $52.8 million and
total project value equal
to $65.9 million, the implied developer profit is $13.0 million,
well above the present
value from continued operation of existing turbines. For
comparison, MDS had assigned
a value of $7.7 million to redevelopment of the same site in late
2003. Most of the
increase was attributable to a 24 percent increase in the PPA as
the result of rising natural
gas prices.
MDS also prepared the matrix in Exhibit 6 showing the
sensitivity of developer profit to
5 percent changes in the PPA price and the NCF. Exhibit 7
presents representative
interest rates in July 2005.
The Decision
Two remaining issues puzzled Mr. Bittner as he reviewed
MDS’s report. Would a buyer
pay the full developer profit calculated in Exhibit 5 to purchase
the Canyon Wind
easement, or in view of the risks surrounding redevelopment,
would he only pay some
fraction of this amount? And if so, what fraction should WRI
expect? Redevelopment of
6

the site certainly involved risk, but Mr. Bittner knew that due to
the benefits of
diversification only systematic, or nondiversifiable, risk should
affect price. To his eyes
most of the risks associated with redeveloping the Canyon Wind
easement appeared
unsystematic.
In light of energy price volatility, Mr. Bittner also wondered if
the ability to postpone
redevelopment for at least three years might somehow
contribute to the project’s value in
a way not captured in MDS’s valuation. If so, MDS’s estimated
developer profit might
understate true project value. Mr. Bittner thought in terms of a
three-year horizon
because the production tax credit was presently set to expire in
three years, although
Congress had repeatedly renewed the credit since 1992. Time
was running short for a
decision, and Mr. Bittner was anxious to get on with enjoying
his summer.
7
Exhibit 1
Canyon Wind Farm Existing Turbines
8

9
Natural Gas Prices Monthly Feb. 1985 - July 2005
-
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
Nov-1984 Aug-1987 May-1990 Jan-1993 Oct-1995 Jul-1998
Apr-2001 Jan-2004
Exhibit 2
Cents/kWh

Exhibit 3
Volatility of Natural Gas Prices
Annualized Standard Deviation of Monthly Returns on US
Natural Gas Wellhead
Prices
Date Number of Observations Volatility (%)
March 1985 – July 2005 245 35.1
Jan. 1995 – July 2005 127 41.7
Jan. 2000 – July 2005 67 44.1
Jan. 2003 – July 2005 31 43.0
Source: U.S. Department of Energy, Energy Information
Administration.
http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
10
11
Price of electricity (per kW h) 0.0588$
Output (kW h/yr) 55,500,000
Investm ent in substation 400,000$

Net scrap value of a turbine in 2006 1,200$
Gross scrap value of turbine in 2016 256$
Inflation rate 2.5%
Discount rate 10%
Period 1 2 3 4 5 6 7 8
2006 2007 2008 2009 2010 2011 2012 2013
Revenue 3,344,985 3,428,610 3,514,325 3,602,183 3,692,238
3,784,544 3,879,157 3,976,136
Costs
Operations & Routine Maint. 1,107,500 1,135,188 1,163,567
1,192,656 1,222,473 1,253,035 1,284,360 1,316,469
Plant, substation & Edison fees 190,500 195,263 200,144
205,148 210,276 215,533 220,922 226,445
Land Rent 87,000 89,175 91,404 93,689 96,032 98,433
100,893 103,416
Insurance 240,000 246,000 252,150 258,454 264,915 271,538
278,326 285,285
Property tax 134,800 138,170 141,624 145,165 148,794
152,514 156,327 160,235
Managem ent 106,100 108,753 111,471 114,258 117,115
120,042 123,043 126,120
Depreciation 200,000 200,000 200,000 200,000 200,000
200,000 200,000 200,000
Total 2,065,900 2,112,548 2,160,361 2,209,370 2,259,604
2,311,095 2,363,872 2,417,969
Pretax profit 1,279,085 1,316,062 1,353,964 1,392,813
1,432,633 1,473,449 1,515,285 1,558,167
Tax @ 40.7% 520,588 535,637 551,063 566,875 583,082
599,694 616,721 634,174
After tax profit 758,497 780,425 802,900 825,938 849,551
873,755 898,564 923,993
Depreciation 200,000 200,000 200,000 200,000 200,000

200,000 200,000 200,000
Cash flow from operations 958,497 980,425 1,002,900
1,025,938 1,049,551 1,073,755 1,098,564 1,123,993
Annual turbine overhaul 205,000 210,125 215,378 220,763
226,282 231,939 237,737 243,681
Free cash flow 753,497 770,300 787,522 805,175 823,270
841,817 860,827 880,313
Salvage value of turbines (after tax)
Land restoration cost (after tax)
Total free cash flow 753,497 770,300 787,522 805,175 823,270
841,817 860,827 880,313
Present value (discounted at 10%) $4,715,520
Assum ptions:
1. Output rem ains at 2005 level, provided $200,000 increasing
at inflation rate is spent annually for m ajor m aintenance of
turbines, in addition to
routine m aintenance.
2. Tax rates are 35% federal and 8.84% state (40.7% com
bined).
3. Restoration cost includes rem oval of substation and rem oval
of old turbines, but not land restoration. Land restoration costs
of about $1 m illion
are deferred until the site is abandoned (perhaps in 2033).
Turbine rem oval costs $2000 per unit. Net scrap value is the
value after rem oval (i.e.
Gross scrap value m inus $2000).
Exhibit 4
Analysis of Continued Operation using Existing Turbines

12
August 18, 2005
Site developed in 2006 with 20 Geneal Electric 1.5 megawatt
SLE model turbines with 77 meter rotor diameters on
65 meter towers.
Assumptions and Results ($ in thousands)
Capacity Financing
Turbine capacity (mw) 1.5 Minimum IRR to equity 15%
Number of turbines 20 1st year interest coverage (times) 1.75
(Op. income/interest)
Total capacity (mw) 30 1st year interest expense 2,669
Hours per year 8,760 Debt sources
Gross production/yr (mWh/yr) 262,800 Rate Term (yrs) % Total
debt
Rated capacity factor 49.0% Senior debt 7.0% 15 67%
Production before site adjustments 128,722 PTC debt 6.5% 10
33%
Site adjustments 13,768 Weighted-average interest rate 6.835%
Net adjusted annual production 114,954 Maximum debt 39,043$
Net capacity factor 43.74% Senior debt 26,159
Development costs PTC debt 12,884
Equipment life (yr.s) 20 Compensating balance reqm't 2,366
Salvage value in 20 yrs. - Tax rate (federal & state)
40.7%
Cost per turbine & tower delivered 1,843 Depreciation 5 year
MACRS
Total turbine & tower cost 36,860 Production tax credit
(cents/kwh) 1.90
Installation costs 8,060 PTC COLA 2.05%
Fees & expenses 7,921

Total development costs 52,841$ Project Valuation
Power selling prices Equity financing 26,828
Purchase power agreement (yrs.) 15 Senior debt financing
26,159
PPA price ($/kWh) 0.0588 PTC debt financing 12,884
Sales in yrs. 16-20 at market Total project value 65,871
Increase in market price per year 2.5% Developer profit 13,030$
Exhibit 5
Valuation of Canyon Wind Project Redevelopment by RHK
Energy Consulting, Inc.
Exhibit 5 (Continued)
Cash flows to equity 0 1 2 3 4 5 6 7 8 9 10
Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
2016
Net production (MW) 114,949 114,949 114,949 114,949
114,949 114,949 114,949 114,949 114,949 114,949
PPA sales price ($/kWh) 0.0588 0.0588 0.0588 0.0588 0.0588
0.0588 0.0588 0.0588 0.0588 0.0588
Operating revenue ($ millions) 6,759 6,759 6,759 6,759 6,759
6,759 6,759 6,759 6,759 6,759
Other revenues 152 152 152 152 152 152 152 152 152 152
Total revenue 6,911 6,911 6,911 6,911 6,911 6,911 6,911 6,911
6,911 6,911
Total operating expenses 2,241 2,243 2,529 2,545 2,559 2,352
2,350 2,350 2,347 2,348
Operating income 4,670 4,668 4,382 4,366 4,352 4,559 4,561
4,561 4,564 4,563
Debt service 4,664 4,664 4,664 4,664 4,664 4,664 4,664 4,664
4,664 4,664

Pretax cash flow to equity 6 4 (282) (298) (312) (105) (103)
(103) (100) (101)
Tax calculation
Operating income 4,670 4,668 4,382 4,366 4,352 4,559 4,561
4,561 4,564 4,563
Depreciation & Amort. 26,704 13,673 8,267 5,021 5,021 2,596
159 159 159 159
Interest expense 2,669 2,534 2,390 2,236 2,072 1,896 1,709
1,509 1,296 1,068
Taxable income (24,702) (11,538) (6,275) (2,891) (2,741) 67
2,693 2,893 3,110 3,337
Tax (10,054) (4,696) (2,554) (1,177) (1,116) 27 1,096 1,178
1,266 1,358
Production tax credit 2,184 2,229 2,274 2,321 2,369 2,417
2,467 2,517 2,569 2,622
FCF to equity* 12,244 6,929 4,546 3,199 3,172 2,285 1,267
1,237 1,203 1,162
Equity investment for 15% IRR (26,828)$
Depreciation calculations
Asset basis 60,329 60,329 60,329 60,329 60,329 60,329 60,329
MACRS depreciation rate 44.00% 22.40% 13.44% 8.06% 8.06%
4.04%
Depreciation 26,545 13,514 8,108 4,863 4,863 2,437 0
Amortizaztion calculations
Asset basis 3,175 3,175 3,175 3,175 3,175 3,175 3,175 3,175
3,175 3,175
20 yr. SL amort. 159 159 159 159 159 159 159 159 159 159
Debt service calculations
Sr. Debt interest 1,831 1,758 1,680 1,597 1,508 1,412 1,310
1,200 1,083 958
Sr. Debt principal pmt. 1,041 1,114 1,192 1,275 1,364 1,460

1,562 1,672 1,789 1,914
Sr. Debt Service 2,872 2,872 2,872 2,872 2,872 2,872 2,872
2,872 2,872 2,872
Ending Sr. Debt Principal 25,118 24,004 22,812 21,537 20,172
18,712 17,150 15,478 13,690 11,776
PTC Debt interest 837 775 709 639 564 484 399 309 212 109
PTC Debt principal pmt. 955 1,017 1,083 1,153 1,228 1,308
1,393 1,484 1,580 1,683
PTC Debt Service 1,792 1,792 1,792 1,792 1,792 1,792 1,792
1,792 1,792 1,792
Ending PTC Debt Principal 11,929 10,912 9,830 8,676 7,448
6,140 4,747 3,263 1,683 (0)
Production tax credit calculations
Tax credit rate (cents/kWh) 1.9000 1.9390 1.9787 2.0193
2.0607 2.1029 2.1460 2.1900 2.2349 2.2807
Tax credit 2,184 2,229 2,274 2,321 2,369 2,417 2,467 2,517
2,569 2,622
*FCF to equity = Operating income after tax + Tax shields on
depreciation and interest + production tax credit - debt service
13
14
E x h ib it 5 (C o n tin u e d )
C a s h flo w s to e q u ity
Y e a r 1 1 1 2 1 3 1 4 1 5 1 6 1 7 1 8 1 9 2 0
N e t p ro d u c tio n (M W ) 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0

2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6
P P A s a le s p ric e ($ /k W h ) 1 1 4 ,9 4 9 1 1 4 ,9 4 9 1 1 4
,9 4 9 1 1 4 ,9 4 9 1 1 4 ,9 4 9 1 1 4 ,9 4 9 1 1 4 ,9 4 9 1 1 4 ,9 4
9 1 1 4 ,9 4 9 1 1 4 ,9 4 9
O p e ra tin g re v e n u e ($ m illio n s ) 0 .0 5 8 8 0 .0 5 8 8
0 .0 5 8 8 0 .0 5 8 8 0 .0 5 8 8 0 .0 8 5 2 0 .0 8 7 3 0 .0 8 9 5 0
.0 9 1 7 0 .0 9 4 0
O th e r re v e n u e s 6 ,7 5 9 6 ,7 5 9 6 ,7 5 9 6 ,7 5 9 6 ,7 5 9 9
,7 8 9 1 0 ,0 3 4 1 0 ,2 8 5 1 0 ,5 4 2 1 0 ,8 0 5
T o ta l re v e n u e 1 1 1 1 1 1 1 1 1 1 1 1 1 0 0 3 4 3 4 3 4 3 4
3 4
T o ta l o p e ra tin g e x p e n s e s 6 ,8 7 0 6 ,8 7 0 6 ,8 7 0 6
,8 7 0 6 ,8 5 9 9 ,8 2 3 1 0 ,0 6 8 1 0 ,3 1 9 1 0 ,5 7 6 1 0 ,8 3 9
O p e ra tin g in c o m e 2 ,2 8 5 2 ,2 8 3 2 ,2 8 0 2 ,2 7 8 2 ,2 7
6 2 ,3 9 0 2 ,4 2 6 2 ,4 6 2 2 ,4 9 9 2 ,5 3 7
D e b t s e rv ic e 4 ,5 8 5 4 ,5 8 7 4 ,5 9 0 4 ,5 9 2 4 ,5 8 3 7 ,4
3 3 7 ,6 4 2 7 ,8 5 7 8 ,0 7 7 8 ,3 0 2
P re ta x c a s h flo w to e q u ity 2 ,8 7 2 2 ,8 7 2 2 ,8 7 2 2
,8 7 2 2 ,8 7 2 0
1 ,7 1 3 1 ,7 1 5 1 ,7 1 8 1 ,7 2 0 1 ,7 1 1 7 ,4 3 3 7 ,6 4 2 7 ,8 5
7 8 ,0 7 7 8 ,3 0 2
T a x c a lc u la tio n
O p e ra tin g in c o m e
D e p re c ia tio n & A m o rt. 4 ,5 8 5 4 ,5 8 7 4 ,5 9 0 4 ,5 9
2 4 ,5 8 3 7 ,4 3 3 7 ,6 4 2 7 ,8 5 7 8 ,0 7 7 8 ,3 0 2
In te re s t e x p e n s e 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9
1 5 9 1 5 9 1 5 9
T a x a b le in c o m e 8 2 4 6 8 1 5 2 8 3 6 3 1 8 8 0 0 0 0 0
T a x 3 ,6 0 2 3 ,7 4 7 3 ,9 0 4 4 ,0 7 0 4 ,2 3 6 7 ,2 7 4 7 ,4 8
3 7 ,6 9 8 7 ,9 1 8 8 ,1 4 3
P ro d u c tio n ta x c re d it 1 ,4 6 6 1 ,5 2 5 1 ,5 8 9 1 ,6 5
6 1 ,7 2 4 2 ,9 6 1 3 ,0 4 6 3 ,1 3 3 3 ,2 2 3 3 ,3 1 4
F C F to e q u ity 0 0 0 0 0 0 0 0 0 0
E q u ity in v e s tm e n t fo r 1 5 % IR R 2 4 7 1 9 0 1 2 9 6 4
(1 3 ) 4 ,4 7 2 4 ,5 9 6 4 ,7 2 4 4 ,8 5 4 4 ,9 8 8

D e p re c ia tio n c a lc u la tio n s
A s s e t b a s is
M A C R S d e p re c ia tio n ra te
D e p re c ia tio n
A m o rtiza ztio n c a lc u la tio n s
A s s e t b a s is
2 0 yr. S L a m o rt. 3 ,1 7 5 3 ,1 7 5 3 ,1 7 5 3 ,1 7 5 3 ,1 7 5 3
,1 7 5 3 ,1 7 5 3 ,1 7 5 3 ,1 7 5 3 ,1 7 5
1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9 1 5 9
D e b t s e rv ic e c a lc u la tio n s
S r. D e b t in te re s t
S r. D e b t p rin c ip a l p m t. 8 2 4 6 8 1 5 2 8 3 6 3 1 8 8
S r. D e b t S e rv ic e 2 ,0 4 8 2 ,1 9 1 2 ,3 4 4 2 ,5 0 9 2 ,6
8 4
E n d in g S r. D e b t P rin c ip a l 2 ,8 7 2 2 ,8 7 2 2 ,8 7 2 2
,8 7 2 2 ,8 7 2
9 ,7 2 8 7 ,5 3 7 5 ,1 9 3 2 ,6 8 4 0
P T C D e b t in te re s t
P T C D e b t p rin c ip a l p m t.
P T C D e b t S e rv ic e
E n d in g P T C D e b t P rin c ip a l
P ro d u c tio n ta x c re d it c a lc u la tio n s
T a x c re d it ra te (c e n ts /k W h )
T a x c re d it
Exhibit 5 (Continued)
Discussion

Site adjustments. Efficiency adjustments to account for limited
availability, electrical losses, wake and
array losses, turbulence/high wind cut-out, blade contamination,
icing, and grid outages.
Fees & expenses. Includes development expenses, capitalized
interest during construction, capitalized
term debt service reserve, lender’s fee, lender’s transaction
costs, and borrower’s counsel.
Purchase power agreement (PPA). A 15-year, fixed price power
sales agreement we expect can
presently be negotiated with Southern California Edison. The
contact price depends primarily on the
utility’s highest power cost avoided by the contract, which for
Southern California Edison is the cost of
natural gas. We believe a contract can be negotiated today at
0.0588 $/kWh.
Sales in years 16-20. After 15 years, we assume power can be
sold at a variable market price, which we
estimate will increase with inflation at 2.5 percent a year.
Required IRR to equity. Based on our experience, we believe
equity investors can be attracted to wind
energy projects in today’s markets that promise internal rates of
returns of at least 15 percent.
Production tax credit rate (PTC). Congress offers production
tax credits to encourage development of
alternative energy. The current rate, recently extended for three
years, is 1.90 percent of revenues
increasing at 2.05 percent a year for 10 years.
Minimum equity/total capital. Based on experience and our
market contacts we are confident this project

can support a first-year interest coverage ratio as low as 1.75
times, with one-third of the debt secured by
PTC cash flows. Because PTC cash flows depend only on
revenue generation, lenders perceive them to be
safer than operating cash flows and demand a lower interest
rate. We estimate interest rate on the
remaining debt to be 2 percent over 3-month LIBOR, or 7
percent.
Compensating balance requirement. Lenders demand that
approximately one year’s interest expense be
held in reserve as a non-interest bearing deposit.
Depreciation. In addition to production tax credits Congress
also allows rapid depreciation of wind energy
projects. Even though the turbines have a 20-year life
expectancy, ninety-five percent of total project
value, less the compensating balance, qualifies for modified
accelerated cost recovery (MACRS)
depreciation over five years. The remaining 5 percent can be
amortized on a straight-line basis over 20
years.
Developer profit. Equals the difference between Total project
value and Total development costs.
Total operating expenses. Includes land lease payments,
administrative expenses, property taxes,
interconnection/wheeling expenses, insurance, and development
royalties equal to 1.50 percent of gross
revenue.
Equity investment for 15% IRR. Present value of free cash
flows to equity through 2026 discounted at
15 percent.

15
0.0559 0.0588 0.0617
41.55% 6.0 9.2 12.5
43.74% 9.6 13.0 16.5
45.93% 13.2 16.8 20.4
M DS E nergy Cons ulting, Inc .
Exhibit 6 C anyon Wind Project Sensitivity Analysis
PPA Price ($/k W h)
N
et
C
ap
ac
it
y
Fa
ct
o
r

Estimated D eveloper Profit ($ million)
5% P erturbations in P P A and NCF
16
17
Exhibit 7 Representative Interest Rates in July 2005
Instrument Interest Rate (%)
1-month Treasury Bill 3.10
1-year Treasury 3.64
5-year Treasury Inflation-Indexed 1.67
30-year Conventional Mortgage 5.70
BAA Corporate Bond Yield 6.25

WIND RESOURCES, INC.(The IndustryThe AlternativesSell
Easement to another DeveloperThe DecisionExhibit 1Volatility
of Natural Gas PricesInstrument
Exhibit 4Exhibit 4Analysis of Continued Operation using
Existing TurbinesPrice of electricity (per kWh)$ 0.0588Output
(kWh/yr)55,500,000Investment in substation$ 400,000Net
scrap value of a turbine in 2006$ 1,200Gross scrap value of
turbine in 2016$ 256Inflation rate2.50%Discount
rate10%Period12345678910200620072008200920102011201220
1320142015Revenue3,344,9853,428,6103,514,3253,602,1833,69
2,2383,784,5443,879,1573,976,1364,075,5394,177,428CostsOpe
rations & Routine
Maint.1,107,5001,135,1881,163,5671,192,6561,222,4731,253,03
51,284,3601,316,4691,349,3811,383,116Plant, substation &
Edison
fees190,500195,262200,144205,148210,276215,533220,922226,
445232,106237,908Land
Rent87,00089,17591,40493,68996,03298,433100,893103,41610
6,001108,651Insurance240,000246,000252,150258,454264,9152
71,538278,326285,285292,417299,727Property
tax134,800138,170141,624145,165148,794152,514156,327160,2
35164,241168,347Management106,100108,752111,471114,2581
17,115120,042123,043126,120129,273132,504Depreciation200,
000200,000200,000200,000200,000200,000200,000200,000200,
000200,000Total2,065,9002,112,5482,160,3612,209,3702,259,6
042,311,0952,363,8722,417,9692,473,4182,530,253Pretax
Profit1,279,0851,316,0621,353,9641,392,8131,432,6331,473,44
91,515,2851,558,1671,602,1211,647,174Tax
@40.7%520,588535,637551,063566,875583,082599,694616,721
634,174652,063670,400After tax
profit758,497780,425802,900825,938849,551873,755898,56492
3,993950,058976,774Depreciation200,000200,000200,000200,0
00200,000200,000200,000200,000200,000200,000Cash flows

from
operations958,497980,4251,002,9001,025,9381,049,5511,073,7
551,098,5641,123,9931,150,0581,176,774Annual turbine
overhaul205,000210,125215,378220,763226,282231,939237,737
243,681249,773256,017Free cash
flow753,497770,300787,522805,175823,270841,817860,827880
,313900,285920,758Salvage value of turbines (after
tax)69,836Land restoration cost (after tax)(908,378)Total free
cash
flow753,497770,300787,522805,175823,270841,817860,827880
,313900,28582,216Present value (discounted at
10%)$4,715,520.36
Exhibit 5Exhibit 5Valuation of Canyon Wind Project
Redevelopment by RHK Energy Consulting, Inc.Site developed
in 2006 with 20 Geneal Electric 1.5 megawatt SLE model
turbines with 77 meter rotor diameters on 65 meter
towers.Assumptions and Results($ in
thousands)CapacityFinancingTurbine capacity
(mw)1.5Minimum IRR to equity15%Number of turbines201st
year interest coverage (times)1.75 (Op. income/interest)Total
capacity (mw)301st year interest expense2,669Hours per
year8,760Debt sourcesGross production/yr
(mWh/yr)262,800RateTerm (yrs)% Total debtRated capacity
factor49.0%Senior debt7.0%1567%Production before site
adjustments128,772PTC debt6.5%1033%Site
adjustments13,818Weighted-average interest rate6.835%Net
adjusted annual production114,954Maximum debt$ 39,043Net
capacity factor43.74%Senior debt26,159Development costsPTC
debt12,884Equipment life (yr.s)20Compensating balance
reqm't2,366Salvage value in 20 yrs.- 0Tax rate (federal &
state)40.7%Cost per turbine & tower
delivered1,843Depreciation5 year MACRSTotal turbine & tower
cost 36,860Production tax credit (cents/kwh)1.90Installation
costs8,060PTC COLA2.05%Fees & expenses7,921Total
development costs$ 52,841Project ValuationPower selling
pricesEquity financing26,828Purchase power agreement

(yrs.)15Senior debt financing26,159PPA price
($/kWh)0.0588PTC debt financing12,884Sales in yrs. 16-20 at
market Total project value65,871Increase in market price per
year2.5%Developer profit $ 13,030Cash flows to
equity01234567891011121314151617181920Year200620072008
20092010201120122013201420152016201720182019202020212
0222023202420252026Net production
(MW)114,949114,949114,949114,949114,949114,949114,94911
4,949114,949114,949114,949114,949114,949114,949114,94911
4,949114,949114,949114,949114,949PPA sales price
($/kWh)0.05880.05880.05880.05880.05880.05880.05880.05880.
05880.05880.05880.05880.05880.05880.05880.08520.08730.089
50.09170.0940Operating revenue ($
millions)6,7596,7596,7596,7596,7596,7596,7596,7596,7596,759
6,7596,7596,7596,7596,7599,78910,03410,28510,54210,805Oth
er
revenues152152152152152152152152152152111111111111100
3434343434Total
revenue6,9116,9116,9116,9116,9116,9116,9116,9116,9116,9116
,8706,8706,8706,8706,8599,82310,06810,31910,57610,839Total
operating
expenses2,2412,2432,5292,5452,5592,3522,3502,3502,3472,348
2,2852,2832,2802,2782,2762,3902,4262,4622,4992,537Operatin
g
income4,6704,6684,3824,3664,3524,5594,5614,5614,5644,5634,
5854,5874,5904,5924,5837,4337,6427,8578,0778,302Debt
service4,6644,6644,6644,6644,6644,6644,6644,6644,6644,6642,
8722,8722,8722,8722,8720 Pretax cash flow to
equity64(282)(298)(312)(105)(103)(103)(100)(101)1,7131,7151,
7181,7201,7117,4337,6427,8578,0778,302Tax calculation
Operating
income4,6704,6684,3824,3664,3524,5594,5614,5614,5644,5634,
5854,5874,5904,5924,5837,4337,6427,8578,0778,302
Depreciation &
Amort.26,70413,6738,2675,0215,0212,59615915915915915915
9159159159159159159159159 Interest

expense2,6692,5342,3902,2362,0721,8961,7091,5091,2961,068
82468152836318800000 Taxable
income(24,702)(11,538)(6,275)(2,891)(2,741)672,6932,8933,11
03,3373,6023,7473,9044,0704,2367,2747,4837,6987,9188,143
Tax(10,054)(4,696)(2,554)(1,177)(1,116)271,0961,1781,2661,3
581,4661,5251,5891,6561,7242,9613,0463,1333,2233,314
Production tax
credit2,1842,2292,2742,3212,3692,4172,4672,5172,5692,62200
00000000FCF to
equity12,2446,9294,5463,1993,1722,2851,2671,2371,2031,1622
4719012964(13)4,4724,5964,7244,8544,988Equity investment
for 15% IRR$ (26,828)Depreciation calculationsAsset
basis60,32960,32960,32960,32960,32960,32960,329MACRS
depreciation
rate44.00%22.40%13.44%8.06%8.06%4.04%Depreciation26,545
13,5148,1084,8634,8632,4370Amortizaztion calculationsAsset
basis3,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753,1
753,1753,1753,1753,1753,1753,1753,1753,1753,17520 yr. SL
amort.15915915915915915915915915915915915915915915915
9159159159159Tax shield with
incentives10,8685,5653,3652,0442,0441,0576565656565656565
656565656565Value of tax shield with incentives18,672Normal
depreciationAsset
basis63,50563,50563,50563,50563,50563,50563,50563,50563,5
0563,50563,50563,50563,50563,50563,50563,50563,50563,5056
3,50563,505dep = 20
yr3,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753
,1753,1753,1753,1753,1753,1753,1753,1753,175Tax shield
without
incentives1,2921,2921,2921,2921,2921,2921,2921,2921,2921,29
21,2921,2921,2921,2921,2921,2921,2921,2921,2921,292Value
of tax shield without incent8,089value from depreciation
incentive10,58339%value to Equity26,828Debt service
calculations Sr. Debt
interest1,8311,7581,6801,5971,5081,4121,3101,2001,08395882
4681528363188 Sr. Debt principal

pmt.1,0411,1141,1921,2751,3641,4601,5621,6721,7891,9142,04
82,1912,3442,5092,684 Sr. Debt
Service2,8722,8722,8722,8722,8722,8722,8722,8722,8722,8722
,8722,8722,8722,8722,872 Ending Sr. Debt
Principal25,11824,00422,81221,53720,17218,71217,15015,4781
3,69011,7769,7287,5375,1932,684(0) PTC Debt
interest837775709639564484399309212109 PTC Debt
principal
pmt.9551,0171,0831,1531,2281,3081,3931,4841,5801,683
PTC Debt
Service1,7921,7921,7921,7921,7921,7921,7921,7921,7921,792
Ending PTC Debt
Principal11,92910,9129,8308,6767,4486,1404,7473,2631,6830P
roduction tax credit calculations Tax credit rate
(cents/kWh)1.90001.93901.97872.01932.06072.10292.14602.19
002.23492.2807 Tax
credit2,1842,2292,2742,3212,3692,4172,4672,5172,5692,622val
ue from PTC11,75844%83%Value to Equity26,828PPA
Price13.030.05590.05880.061741.55%5.28.511.843.74%9.513.0
16.545.93%13.917.521.2
NPV without incentivesExhibit 5Valuation of Canyon Wind
Project Redevelopment by RHK Energy Consulting, Inc.Site
developed in 2006 with 20 Geneal Electric 1.5 megawatt SLE
model turbines with 77 meter rotor diameters on 65 meter
towers.Assumptions and Results($ in
thousands)CapacityFinancingTurbine capacity
(mw)1.5Minimum IRR to equity15%Number of turbines201st
year interest coverage (times)1.75 (Op. income/interest)Total
capacity (mw)301st year interest expense2,669Hours per
year8,760Debt sourcesGross production/yr
(mWh/yr)262,800RateTerm (yrs)% Total debtRated capacity
factor49.0%Senior debt7.0%1567%Production before site
adjustments128,772PTC debt6.5%1033%Site
adjustments13,818Weighted-average interest rate6.835%Net
adjusted annual production114,954Maximum debt$ 39,043Net
capacity factor43.74%Senior debt26,159Development costsPTC

debt12,884Equipment life (yr.s)20Compensating balance
reqm't2,366RE15%WE40.73%Salvage value in 20 yrs.- 0Tax
rate (federal & state)40.7%Cost per turbine & tower
delivered1,843Depreciation5 year
MACRSRD6.84%WD59.27%Total turbine & tower cost
36,860Production tax credit (cents/kwh)1.90Installation
costs8,060PTC COLA2.05%WACC8.51%Fees &
expenses7,921Total development costs$ 52,841Project
ValuationPower selling pricesEquity financing26,828Purchase
power agreement (yrs.)15Senior debt financing26,159PPA price
($/kWh)0.0588PTC debt financing12,884Sales in yrs. 16-20 at
market Total project value65,871Increase in market price per
year2.5%Developer profit $ 13,030Cash flows to
equity01234567891011121314151617181920Year200620072008
20092010201120122013201420152016201720182019202020212
0222023202420252026Net production
(MW)114,949114,949114,949114,949114,949114,949114,94911
4,949114,949114,949114,949114,949114,949114,949114,94911
4,949114,949114,949114,949114,949PPA sales price
($/kWh)0.05880.05880.05880.05880.05880.05880.05880.05880.
05880.05880.05880.05880.05880.05880.05880.08520.08730.089
50.09170.0940Operating revenue ($
millions)6,7596,7596,7596,7596,7596,7596,7596,7596,7596,759
6,7596,7596,7596,7596,7599,78910,03410,28510,54210,805Oth
er
revenues152152152152152152152152152152111111111111100
3434343434Total
revenue6,9116,9116,9116,9116,9116,9116,9116,9116,9116,9116
,8706,8706,8706,8706,8599,82310,06810,31910,57610,839Total
operating
expenses2,2412,2432,5292,5452,5592,3522,3502,3502,3472,348
2,2852,2832,2802,2782,2762,3902,4262,4622,4992,537Operatin
g
income4,6704,6684,3824,3664,3524,5594,5614,5614,5644,5634,
5854,5874,5904,5924,5837,4337,6427,8578,0778,302Depreciati
on3,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753,175

3,1753,1753,1753,1753,1753,1753,1753,1753,175Earnings
before
taxes1,4951,4931,2071,1911,1771,3841,3861,3861,3891,3881,4
101,4121,4151,4171,4084,2584,4674,6814,9015,127Taxes60860
84914854795635645645655655745755765775731,7331,8181,90
51,9952,087NI8868857167066988218228228248238368378398
408352,5252,6492,7762,9073,040OCF4,0624,0603,8913,8813,8
733,9963,9973,9973,9993,9984,0114,0124,0144,0154,0105,700
5,8245,9516,0826,216Development costs52,841NPV of
FCF(12,915.3570519149)Depreciation calculationsAsset
basis60,32960,32960,32960,32960,32960,32960,329Amortizazti
on calculationsAsset
basis3,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753,1
753,1753,1753,1753,1753,1753,1753,1753,1753,175Normal
depreciationAsset
basis63,50563,50563,50563,50563,50563,50563,50563,50563,5
0563,50563,50563,50563,50563,50563,50563,50563,50563,5056
3,50563,505dep = 20
yr3,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753,1753
,1753,1753,1753,1753,1753,1753,1753,1753,175
amortization scheduleN N15r7%Loan
amount26,159.00PMT$2,872.12yearbeginning
PMTinterestamortizationbalance
end126,159.00$2,872.121,831.13$1,040.9925,118.01225,118.01
$2,872.121,758.26$1,113.8624,004.16324,004.16$2,872.121,68
0.29$1,191.8322,812.33422,812.33$2,872.121,596.86$1,275.25
21,537.07521,537.07$2,872.121,507.60$1,364.5220,172.55620,
172.55$2,872.121,412.08$1,460.0418,712.51718,712.51$2,872.
121,309.88$1,562.2417,150.27817,150.27$2,872.121,200.52$1,
671.6015,478.67915,478.67$2,872.121,083.51$1,788.6113,690.
061013,690.06$2,872.12958.30$1,913.8111,776.251111,776.25
$2,872.12824.34$2,047.789,728.47129,728.47$2,872.12680.99$
2,191.127,537.34137,537.34$2,872.12527.61$2,344.505,192.84
145,192.84$2,872.12363.50$2,508.622,684.22152,684.22$2,872
.12187.90$2,684.22(0.00)

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This document is authorized for use only by Gavin Bodkin
([email protected]). Copying or posting is an infringement of
copyright. Please contact [email protected]
or 800-988-0886 for additional copies.
810-129 The Fox Islands Wind Project (A)
2
online with three 1.5MW GE turbines capable of generating
approximately 11,600 MWh per year.2
With the Fox Islands Wind project complete, Baker began to
consider whether to pursue similar
projects elsewhere in Maine and the United States more broadly.
The Fox Islands
In 1603, Captain Martin Pring of Bristol, England named two
islands off the coast of what is now
Maine the Fox Islands for the silver-grey foxes he observed
there. The one mile-wide straight that
separates the islands is still known as the Fox Islands
Thoroughfare; however, the northern island is
known today as North Haven and the southern island as

Vinalhaven. The islands are approximately
12 miles east of Rockland, Maine in Penobscot Bay (see Exhibit
1 for a map of the Fox Islands).3
Today, North Haven is still best known for its sizable summer
colony of prominent business and
political leaders from Boston, New York, and other major cities.
The economy of Vinalhaven today is
most dependent on the lobster industry while North Haven is
dominated by maintaining its summer
resort community.4 According to the 2000 U.S. Census, North
Haven and Vinalhaven had 381 and
1,235 inhabitants, respectively, with a total combined land area
of 37 square miles (23,648 acres).5
With no bridge connection to the mainland, residents rely on the
approximately one hour and fifteen
minute ferry rides from Rockland as the primary method to
transport goods and people to the island.
The Energy Challenge on Fox Islands
In 2008, the residents of the Fox Islands faced some of the
highest electricity prices in the U.S. with
recent prices three times the national average. In addition to
other economic and social factors, the
high cost of electricity threatened the sustainability of the year-
round community on the island. In
Maine, year-round island communities had declined from over
200 to just 15 in 2008. Solving the Fox
Islands’ electricity problems was a crucial step in bolstering the
sustainability of the community.
The total electrical costs on the Fox Islands were approximately
$0.29/kWh in 2008. This price was
determined by two components, an energy charge and a delivery
charge. The energy charge

represented the cost of electricity generation and was variable.
Energy charges over the past five
years on the Fox Islands were approximately $0.11/kWh.
Energy charges varied across the U.S.
depending on the fuel source used to generate electricity; for
example, Kentucky and West Virginia
had low energy charges because electricity was generated using
inexpensive coal (see Exhibit 2 for a
comparison of energy charges across the U.S.). In regions that
relied on gas or nuclear power, energy
charges were higher. The second electricity price component,
delivery charge, is a cost to consumers
that covers the cost of electricity transmission and distribution
(T&D). Recent delivery charges on the
Fox Islands were approximately $0.18/kWh. The high delivery
charges were the result of the few
(approximately 2,000) customers on the islands relative to the
high fixed cost of the necessary T&D
equipment, which included a 10-mile umbilical cable from the
mainland, power lines on the island
and maintenance and repair costs. With only 2,000 customers to
cover these fixed expenses T&D costs
represented a significant component of electricity prices.
2 11,600 MWh per year calculated assuming three 1.5MW
turbines and average yearly utilization of 29% (3 x 1.5MW x
8760
hours per year x 29%) = 11,600 MWh per year. George Baker’s
utilization estimate was based on seasonal wind conditions and
equipment scheduled maintenance requirements as well as the
ability to sell excess power to the grid.
3 Town of North Haven, Maine, “A Brief History of North
Haven,”
http://www.northhavenmaine.org/content/4099/Brief_History/,

accessed April 2010.
4 Ibid. and Vinalhaven Chamber of Commerce. “History,”
http://vinalhaven.org/history, accessed April 2010.
5 U.S. Census Bureau website, “Census 2000 Data for the State
of Maine,”
http://factfinder.census.gov/servlet/GCTTable?_bm=y&-
geo_id=04000US23&-_box_head_nbr=GCT-PH1&-
ds_name=DEC_2000_SF1_U&-format=ST-7, accessed March
2010.
The Fox Islands Wind Project (A) 810-129
3
Consumers on the islands purchased electricity from Fox Islands
Electric Cooperative (FIEC, the
Coop), a community owned T&D co-op established in 1974 with
the purchase of Vinalhaven Light
and Power. In 1976, with the help of a loan from the Rural
Electrification Administration (REA), the
new co-op laid a 10-mile submarine electric cable between
North Haven and Central Maine Power
Company’s lines at Rockport, on the mainland. The cable was
energized in 1977. As a T&D company,
FIEC did not generate electricity, but only engaged in
transmission as a regulated monopoly.
Historically, T&D and generation had been separated and

regulated by government mandate in
Maine with fixed prices set by the government. In 2000, to
increase competition and keep electricity
prices low for consumers, the industry was deregulated to allow
competition set prices for
generation. In 2005, the old submarine cable was replaced with
a new one. The co-op purchased all of
its electricity directly from the New England Grid.
Another unique feature of electricity on the Fox Islands was the
seasonality of demand, with
consumption spiking in the summer months of July and August
(see Exhibit 3 for energy usage
patterns on the island). Electricity in the summer was not driven
by air conditioning usage, as few
people on the Fox Islands used air conditioning, but rather by
summer residents who arrived and
began using electricity. Seasonal residents and year-round
residents typically had different
viewpoints on the electricity challenge on Fox Islands. For
seasonal residents, the high cost of
electricity was not a major concern as they were typically
wealthy and only used electricity for a
couple months a year. Year-round residents on the other hand
had to bear the costs of high electricity
all year and were typically more sensitive to prices than their
wealthier seasonal neighbors.
The Genesis of the Fox Islands Wind Project
The wind project on the Fox Islands was the result of nearly
eight years of research and planning
(see Exhibit 4 for a timeline of events). Dave Folce, the General
Manager of the Fox Islands Electric
Cooperative began exploring the idea of wind power on the
island in 2001 as a potential method of

mitigating high energy prices for island residents. Later that
year, he also persuaded the University of
Massachusetts Renewable Energy Research Laboratory to begin
a three-year study measuring wind
speeds near an abandoned quarry on Vinalhaven. Over the
course of the three-year study,
comprehensive data was gathered on the average wind speed,
direction, and frequency of wind from
a 40 meter high tower 40 located at the quarry site.
The UMass study confirmed that the quarry site on Vinalhaven
would serve as a “good, but not
great” site for windmill placement and three years of data was
very helpful for moving the project
forward. However, in 2005, the submarine electric cable
connecting the Fox Islands with the
mainland failed and made the future of wind energy on the
islands uncertain. FIEC was forced to
borrow $4.0 million to replace the cable to make the necessary
improvements to establish a good
connection with the mainland grid. While this event put the
wind project on hold, ultimately it would
serve as a critical catalyst for the project. A secure and reliable
connection with the mainland grid was
essential for a wind project on the island as the project would
require power to be imported from and
exported to the grid.
By 2007, the overall increase in global energy prices coupled
with a pro-wind political climate in
Maine paved the way for the development of the Fox Islands
Wind project. In early 2008, the Fox
Islands Electric Cooperative formally requested assistance with
the project from the Island Institute
and George Baker was introduced to the project.

George Baker
George Baker became involved in the Fox Islands Wind project
through the Island Institute, where
he served as the Vice President for Community Wind. Baker had
taken sabbatical from teaching at
Harvard Business School during which he studied the potential
for wind projects. In 2008, Baker
4
went on leave from HBS to become CEO of Fox Islands Wind
LLC and pursue the project full-time. In
addition to his duties at Fox Islands Wind, he serves on the
Maine Governor's Task Force on Ocean
Energy, and is a member of the Advisory Board of Neptune
Wind, an offshore wind development
company (see Exhibit 5 for biographies of Baker and other key
stakeholders).
Building Community Support for the Project
In addition to evaluating the economic viability of wind energy,
Baker needed to determine
whether the community would support the construction of three
large wind turbines on the island
and build enthusiasm for doing so. As Baker evaluated the

situation, he believed that strong
community support would be critical to the success of the
project. Without support from the
community, opponents of the project would have a series of
levers at their disposal to delay or
potentially halt the project. For instance, critics of the project
could pressure public officials to block
the project or deter potential investors by causing them to think
it would not succeed.
Risk of Concern from the Community
Unfortunately, problems launching several other notable wind
energy development projects
suggested to Baker that community support might be difficult to
obtain. Most famously, the Cape
Wind project, an offshore wind development off of Cape Cod,
had drawn strong criticism from
people and groups in the Cape Cod area. These groups had
banded together and, with the help of
powerful political connections, sought to stymie the project.
Residents claimed, for example, that the
wind turbines would obstruct their views of Nantucket Sound,
that bird species would be harmed by
the rotors of the wind turbines, that the turbines would interfere
with airport activity and that fishing
would be harmed. Opponents of Cape Wind had delayed the
construction of the wind turbines for
nearly a decade, despite the project’s being supported by most
of the key decision makers in the state
government. The delays had imposed huge costs on the
developers of Cape Wind.6
News reports also suggested that community concerns about
wind turbines were becoming more
significant. Robert Bryce, an energy journalist wrote: “Lawsuits

that focus on noise pollution are now
pending in Maine, Pennsylvania, and New Zealand. In New
Zealand, more than 750 complaints have
been lodged against a large wind project near Makara since it
began operating last April. The
European Platform Against Windfarms lists 388 groups in 20
European countries. Canada has more
than two-dozen anti-wind groups. In the U.S. there are about
100 such groups, and state legislators in
Vermont recently introduced a bill that will require wind
turbines be located no closer than 1.25 miles
from any residence.”7
Baker hoped to avoid a situation similar to Cape Wind on the
Fox Islands. On the contrary, he
wanted to move forward with widespread community support.
As he assessed the situation, Baker
believed there were two distinct groups to whom he needed to
appeal. The first group was full-time
residents of the islands. For many in this group, their electric
bill was a significant expenditure, and
they were involved in the life of the islands throughout the year.
Many would likely be focused on
finding ways to reduce their electric bill and would perceive
this as largely an economic issue. The
second group was summer residents of the islands. This group
was likely to be less concerned with
their electric bill as it was a relatively smaller expenditure for
them. On the other hand, Baker
believed, many in this group would find the sustainability
element of the project appealing.
6 Richard Vietor, “Cape Wind: Offshore Wind Energy in the
USA,” HBS No. 9-708-022 (Boston: Harvard Business School
Publishing, 2008).

7 Robert Bryce, “The Brewing Tempest Over Wind Power,”
Wall Street Journal, March 1, 2010.
5
Initial Steps to Build Support
From the time that the project was in the initial planning stages
(spring 2008), Baker focused on
developing community support from both groups. The primary
means by which he planned to do
this was through frequent and open communication with the
island residents. In Baker’s view, it was
vitally important that he, as the team leader, and others be
accessible to island residents, especially
those who had concerns about the project. In other
developments that had run into problems with
local communities, a key issue had often been that the island
residents viewed the developers of the
project as outsiders coming in to exploit the resources (in this
case wind) that the area offered. Baker
resolved not to allow this to happen in the Fox Islands
development.
From the outset, the project had the support of several key
“opinion leaders” in the community.

One was State Representative Hannah Pingree of North Haven.
In 2007, she had voiced strong
support for the project in meetings with other community
leaders and advocated for it in the
statehouse to the extent that state support was needed. In
particular, Pingree convened a meeting of
island electric cooperatives and addressed an element of the
state’s electricity deregulation law that
prohibited a T&D company such as FIEC from engaging in
generation activity as contemplated in the
Fox Islands plan. Eventually, a special law was passed to permit
the FIEC to operate wind turbines.
Baker’s principal means of building support in the community
more broadly was through hosting
town hall meetings on the subject with both year-round and
summer residents to communicate
directly with them and to ensure that the nature and details of
the project were effectively presented.
Baker held more than a dozen town hall meetings beginning in
the spring of 2008. By the time the
summer residents arrived that year, the backing of the year-
round residents had been secured.
During the course of these meetings, residents expressed several
concerns. One was that the
project was financially risky. With the cooperative already
heavily indebted, some residents thought
that the debt needed to develop the wind project would be more
than the cooperative could support
and lead to higher electricity prices. A second concern involved
the blinking red lights required on
top of the turbines for aviation safety. Third, some residents
were concerned that construction would
be disruptive. Very few people expressed concerns about the
aesthetics of the turbines or about noise.

For his part, Baker tried to address each of these concerns by
explaining how the project would
work and what steps were being taken to mitigate potential
problems. Baker also focused attention
on the benefits of the project, chiefly lower electricity rates and
making the community a model for
using renewable sources of energy, something that many island
residents took pride in. The
important thing for residents was that they would be the primary
consumers of the energy produced
by the turbines and that they would realize an economic benefit
from them. By emphasizing the local
nature of his efforts, Baker blunted the objection to developers
swooping into communities that had
been raised in other communities.
Baker said that the town hall meetings helped him to develop a
rapport with many of the Fox
Islands residents and made it easier to deal with objections that
arose. The Fox Islands project was
not free of negative rumors in the community regarding such
issues as financing andconstruction
problems. However, Baker had established credibility in the
community and people were either
willing to come directly to him with concerns, or people who
heard rumors were willing to talk to
Baker directly, which enabled him to proactively allay concerns
before the rumors spread.
A Vote of Cooperative Members
By the summer of 2008, Baker and his team were ready to
proceed with the project and start
making significant development expenditures. Before
continuing, the wind project needed the

approval of FIEC to confirm the alliance between the two.
Although the board of FIEC had the
authority to approve the project on its own, they were mindful
of the importance of the community’s
6
support and decided that their approval alone would not be
sufficient. Instead, the Coop arranged for
the proposed wind development to be submitted to a vote of all
cooperative members, essentially all
residents of the island. This would afford the community a
formal opportunity to express its view on
the project. The vote was held in August 2008 and cooperative
members approved the project by a
vote of 384 to 5.
According to Baker, the vote was “hugely important.” The
margin of the vote helped to cement
public enthusiasm and enabled Baker and others to show
vendors and regulators that the project had
the people’s support. Before the vote, Baker had avoided
making announcements about the project
off the islands. “There are a bunch of anti-wind people in
Maine, and we didn’t want to fire them
up,” Baker said. Once the cooperative members’ support had
been secured, however, they put out a

press release announcing the results and that they needed
turbines to proceed.
Anxious to proceed quickly lest public support wane, Baker
focused on four key tasks. First was
working with the Vinalhaven Planning Committee to revise an
ordinance governing wind power on
the islands. The ordinance had been written to make it difficult
to build wind turbines on the islands
as a means of giving the community leverage against any
possible for-profit wind developer.
However, given the structure of the wind project and the strong
support within the community, the
Planning Committee began working on changes to the
ordinance. Second, Baker and his team needed
to work to finalize the financing for the much larger
construction and completion phase of the project.
Third, Baker had to work to satisfy both the new town ordinance
and the Maine Department of
Environmental Protection’s (DEP) permitting process. The Fox
Islands Wind project was the first to
be reviewed under the Department’s Small Wind Certification
process, which focused on safety, the
amount of shadow flicker produced by the rotor blades and the
sound emitted by the turbines. After
review, the DEP approved the project.
Fourth, Baker worked to locate the wind turbines themselves. At
the time, there was a three-year
waiting list for turbines. In the aftermath of the vote, EOS
Ventures, a firm that provides design and
construction services for renewable energy projects, began
working with Baker and helped him to
persuade GE to deliver turbines by the summer of 2009, far
sooner than the waiting list suggested
was possible. Getting the turbines quickly was essential to

maintaining momentum for the project in
the community. The show of community support for the project
was helpful in engaging EOS and GE
in the effort to procure turbines.
Managing Community Relations Through the Construction
Phase
By the spring and summer of 2009, construction on the wind
turbines was progressing quickly.
According to Baker, the community “could have [had] lots of
issues” with the disruptions caused by
the construction process. For instance, as a result of material
deliveries to the site, the main
North/South artery on Vinalhaven was frequently obstructed for
“weeks on end.” However, the
construction and logistics team made a concerted effort to
educate residents about the project
beforehand so that they were prepared for the process. “We put
in a lot of work so there would be no
surprises,” Baker said.
Several examples demonstrate the degree of support the project
received from the community.
Approximately 200 people gathered when the barge carrying the
rotor blades arrived and cheered the
truck as it pulled onto the island. One resident who lived on a
sharp corner around which
construction vehicles were having a hard time turning agreed to
have the road temporarily expanded
into his yard. Perhaps most memorably, according to Baker,
when a truck became stuck on the main
road one day and it took several hours to arrange to have it
moved, traffic began to build up on either
side of the road. Eventually, islanders on one side of the truck
began trading vehicles with islanders

on the other side of the truck. In general, employees of Cianbro,
the construction company, made a
7
concerted effort to be part of the community while on the
island, which contributed to goodwill in
the community.
By November 2009, the project was complete and ready to be
dedicated and placed into service.
As they had throughout the process, a large portion of the
community rallied behind the wind project
and hundreds of people attended a celebration (see Exhibit 6 for
photos).
Post-construction Community Relations Challenges Emerge
However, after the turbines began to operate, Baker said “within
days, a small number of
neighbors started expressing concerns about the sound [being
produced by the turbines].” These
neighbors claimed that they had been told that they would not
be able to hear any noise from the
turbines. Although the Maine Department of Environmental
Protection had considered and
approved the noise level being emitted by the turbines, sound

had not been a significant concern
expressed by residents during the planning phase. The turbines
were operating within the
parameters of the DEP’s noise requirements (see Exhibit 7 for
the requirements and Exhibit 8 for the
change in noise level by distance from the turbine tower).
According to news reports, “approximately
a half-dozen neighbors say the noise has been so disruptive that
it makes it impossible to live normal
lives – that they can’t sleep at night and that the noise is
harming their health.”8 The concerns created
a challenge for Baker. Although the project was not obligated to
take any steps to address these
concerns, the community ownership model demanded that he
work to understand, communicate and
come to agreement about the best course of action.
Baker began to work immediately. In order to assess the
situation, Baker asked the concerned
neighbors to complete logs of the sounds levels and when it
bothered them in order to understand
the nature of the problem better. Perhaps there were certain
triggers of noise that could be easily
addressed. In addition, he worried about what the reaction to
noise would be in the summer, when
people spent more time outside. Gentler summer breezes would
likely reduce the noise somewhat
but further comments were not inconceivable.
Beginning on February 1, 2010, the cooperative launched a
month-long experiment in which the
turbines will be slowed down randomly at night in order to test
whether that would address
residents’ concerns. The changes in turbine speed would be
varied in order to test reactions to a range
of speeds. Residents were again asked to keep detailed notes

about what kind of noise they heard
and the degree to which it bothered them.9 In addition to
slowing the turbines down, another option
available to Baker was to modify the gearboxes and generators
themselves. Such changes would be
expensive and highly specialized because they involved
equipment that had already been designed,
built and installed, however. They could also compromise the
overall effectiveness of the turbines.
A local journalist reporting on the situation spoke to other
island residents in addition to those
who had commented on the noise. He reported that the town
manager, Marjorie Stratton, “said that
what she hears on the street is that islanders still feel good
about the project and…the project is doing
exactly what it was predicted to do.” Stratton said that it is
important to balance the interests of the
vast majority of customers with those who live close to the
turbines: “We can’t do everything to serve
these 25 customers that are close by. We have to serve all of the
customers.” Furthermore, based on
“conversations with about 20 islanders,” the reporter found that
the vast majority of the people he
spoke with continued to support the project, though they had
some sympathy for those reacting to
the noise.10 One of the people who lived near the turbines,
Cheryl Lindgren, described the noise as a
8 David A. Tyler, “As electric co-op conducts sound
experiment, Vinalhaven residents debate solution to turbine
noise issue,”
The Working Waterfront, February-March 2010.
9 Ibid.

10 Ibid.
8
“repetitive ‘whump, whump.’” Upon hearing the turbines for the
first time, she said, “I can feel this
sound. It’s going right through me. I thought, ‘Is this what it’s
going to be like for the rest of my
life.’”11
With regard to visual pollution, rather than being upset about
the new addition to Vinalhaven’s
topography, island residents were “just ecstatic” about the
turbines, Baker said. They became a
source of pride for many residents. Vinalhaven resident Gery
Torborg told a reporter “This is
fantastic. I think they are beautiful,” as the turbines began to
operate.12
As he reflected on the steps he took to build community support
and the community’s reaction to
the wind project, Baker wondered how to address the concerns
that had been raised and how to
apply what he learned in this project if he were to try to develop
other projects elsewhere. In further
developments, he might be more susceptible to being labeled an
“outsider” than he had been on the

Fox Islands, where he had become well known to much of the
community.
Financing the Project
Capital Costs
In addition to building community support, obtaining the
financing for the Fox Islands Wind
project or for any other wind project was no trivial matter. A
typical onshore wind installation was
estimated to cost approximately $2,000/kW. According to
industry research, the turbines accounted
for 60-65% of the total cost, with transportation costs making
up 5-10% and transmission lines,
interconnect and sub-station construction being responsible for
10-15%. Construction costs generally
accounted for the remaining 15-20%.13
The Fox Islands Wind project’s capital requirements were
expected to be far greater than typical
wind projects (on a per kilowatt basis). A typical project could
be expected to be much larger, with
total generation capacity usually in excess of 100MW. Fox
Islands Wind would be building three
1.5MW turbines for total generation capacity of 4.5MW. The
project would therefore be negatively
impacted by its lack of scale. Additionally, the cost of
installation would be substantially higher due
to its location on a small island unconnected to the mainland.
Baker’s team initially estimated that
total installation costs would be twice the mainland cost. The
economic downturn of 2008-2009 did
bring some relief to price pressure on the turbines, however. At
their peak in 2008, turbine prices had
increased to $1,800/kW with wait times of around 24 months.

By 2009, industry experts estimated
that prices had fallen 30-35% due to the collapse in commodity
prices, limited financing and market
oversupply.14 Baker’s team initially estimated that its turbines
would cost approximately $1,500/kW.
Figure A Initial Fox Islands Wind Capital Cost Estimates
Total Cost Per kW
Turbines $6,750,000 $1,500
Installation 5,850,000 1,300
Total $12,600,000 $2,800
Source: Fox Islands Wind Investor Presentation.
11 “Wind power overpowers its neighbors,”
Letvineyardersdecide.org,
http://letvineyardersdecide.org/wind/index.php/2010/01/wind-
power-overpowers-its-neighbors/, from Kennebec Journal
and Morning Sentinel, January 24, 2010.
12 David A. Tyler, “Islanders awed by wind turbines,” The
Working Waterfront, December 2009-January 2010,
http://www.workingwaterfront.com/articles/Islanders-awed-by-
wind-turbines/13533/.
13 Simmons & Company International, “2009 Alternative
Energy Review,” p. 43.
14 Simmons & Company International, “2009 Alternative
Energy Review,” p. 35.

9
Wind Power Economics
The economics of generating wind power is characterized by
high upfront capital costs and very
low marginal operating costs. While average costs (which
include capital costs) had come down
substantially over time, it was still believed that wind power
was uneconomic when compared to
more conventional hydrocarbon energy sources such as coal or
natural gas (see Exhibit 9 for a
comparison of levelized costs of electricity). To achieve parity
with conventional sources, capital costs
would need to decrease substantially or hydrocarbon pricing
would need to increase, either directly
or through some form of carbon pricing.
As it was unclear when or if wind power could become
economic on a standalone basis, both the
states and the federal government had developed incentives to
promote wind power generation,
primarily in the form of production tax credits (subsidies for
generation) and renewable portfolio
standards (RPS), in which the state mandates a minimum supply
of renewable energy be purchased
by electricity providers. The renewable energy could either be
generated in-state or be purchased
from out-of-state generators through renewable energy credits
(RECs). Renewable energy credits are

tradable commodities that represent proof that one MWh of
electricity was generated from an eligible
renewable energy source.15 This market allows for separation
of the “greenness” from the “energy.”
Baker expected to take advantage of the current renewable
energy production tax credit of
$0.021/kWh. However, production tax credits exhibited some
volatility due to their dependence
upon periodic renewals by Congress. Production tax credits had
been allowed to lapse three times in
recent history: in 1999, 2001, and 2003 (see Exhibit 10 for
impact of PTC lapses on wind installations).
Baker also intended to sell the RECs generated by the project to
further increase the economic
viability of the project, although prices for RECs exhibited high
amounts of price volatility.16
The economic feasibility of the Fox Islands Wind project was
bolstered by the fact that households
on the island paid substantially higher electricity bills than
households on the mainland. A wind
project on the mainland was likely to remain uneconomic in the
near term compared to conventional
power sources there, but island residents had few other
alternatives for reducing their electricity bill.
Traditionally, island communities separated from the grid had
been supplied by standalone diesel
generators, but island residents had found these lacking in the
past. Fuel costs were highly variable,
and the generators were disruptively noisy as well as incredibly
inconvenient.17 Diesel power was
also considerably more expensive. According to a University of
Massachusetts study, diesel
generators on another island produced energy at approximately
$0.39/kWh, a substantial premium

to residents’ already high rates.18 New England’s latitude and
weather likely precluded the
widespread use of solar power. Tidal power held some promise,
but Baker believed the technology
was several years from being viable.
15 Lori Bird, “Overview of Renewable Energy Certificate
(REC) Markets,” National Renewable Energy Laboratory,
January 8,
2008,
http://www.ftc.gov/bcp/workshops/carbonoffsets/presentations/l
bird.pdf, accessed April 17, 2010.
16 According to NREL, REC prices in 2006 ranged from $5 to
$55 per MWh. Lori Bird, “Overview of Renewable Energy
Certificate (REC) Markets,” National Renewable Energy
Laboratory, January 8, 2008,
http://www.ftc.gov/bcp/workshops/carbonoffsets/presentations/l
bird.pdf, accessed April 17, 2010.
17 According to an article in Rural Electrification Magazine,
low voltage generated by the diesel generators was terribly
destructive to many appliances. Additionally, businesses that
needed large amounts of electricity needed to notify the
powerhouse in advance to ensure enough generators were
running. Frank K. Gallant, “A Good Job for Vinalhaven,” Rural
Electricification Magazine, October 1983,
http://www.foxislands.net/aboutfie.htm, accessed March 2010.
18 Gabriel Blanco, James F. Manwell, and Jon G. McGowan, “A
Feasibility Study for Wind/Hybrid Power System Applications
for New England Islands,” Renewable Energy Research
Laboratory, University of Massachusetts, p. 16.

10
Additional Challenges
Baker faced substantial challenges beyond those of financing a
more conventional wind farm.
First, the size of the project was larger than the current size of
the cooperative. With assets of around
$11 million, the Fox Islands Electric Cooperative would be
more than doubling its size with a single
transaction. Securing debt financing for such a large transaction
would likely be difficult, particularly
given how difficult financing was to obtain following the 2008
financial crisis. Second, the
cooperative had very limited resources and obtaining funds to
support the pre-development work
necessary for approval and financing to be obtained presented a
challenge. Finally, the Fox Islands
Electric Cooperative was a non-taxable institution; thus,
production tax credits (PTCs) were worthless
to the project directly, substantially reducing the viability of the
project.
Baker needed to find a tax equity investor willing to fund a
substantial portion of the project. Tax
equity investors were investors, often from unrelated industries,
who would contribute equity to the
project in exchange for the tax benefits associated with the

project. However, the financial crisis had
decimated the tax credit market as corporations often had
substantially less taxable income to be
offset by tax credits. According to industry sources, the
production tax credit market grew from
approximately $600 million in 2005 to more than $5.2 billion in
2007. In 2008, however, the market
declined sharply to $2.5 billion. Never a market with an
abundance of players, the tax credit market
was believed to have only four active participants in 2008,
down from eighteen previously.19
Solving the Pre-development Challenge
Early projections suggested that the project would require
approximately $300,000 of pre-
development work (lawyers, bankers, engineers, consultants,
etc.). In a traditional for-profit project,
the sponsor would fund these costs up front as part of its equity
commitment. However, as a
cooperative, FIEC lacked the resources to begin the pre-
development work. Baker had several options
available to him: because of the cooperative’s community-based
non-profit status and the “green”
nature of the project, he could petition for grant funding from a
foundation or other similarly-minded
institution. Receiving grant funding would likely require
substantial time, and Baker could not be
certain of grant approval. Moreover, a grant conflicted with one
of his motivations; Baker wanted to
establish the viability of supplying wind power to Vinalhaven
without grants. As such, he devised a
creative financial instrument, a “contingent promissory note,”
which promised to pay 10% interest
per annum when the project received permanent financing but
nothing if the project did not proceed.

Baker noted that although the return was probably below-market
for the risk investors were taking,
“These weren’t disinterested private investors; these were island
individuals who were really
interested in doing this. These were foundations that made
investments out of their endowments
because they were interested in us.” There were additional
benefits as well; obtaining financing in
this manner gave Baker speed and flexibility in moving the
project forward. The contingent
promissory notes allowed for smaller amounts to be raised as
needed.
Tax Equity Financing
Tax equity investors received a return on their investments
primarily through two sources. The
first source was through the production tax credits. The PTCs
currently in place allow for a $0.021
production tax credit per kilowatt-hour of generation for the
first ten years of a project’s life. Since the
Fox Islands Wind project was expected to generate
approximately 11,600 MWh annually, this could
be expected to produce a tax credit of around $243,600 per
annum for the equity sponsor.20 The
19 Chadbourne & Park LLP, “Project Finance Newswire,”
January 2009, p. 27. Many tax equity investors were financial
institutions such as Lehman Brothers, AIG, Citibank,
JPMorganChase, Bank of America, MetLife and New York Life,
as well as
institutions such as GE.
20 $0.021 x 1000 (MW/kW) x 11,600 = $243,600.

11
second source was accelerated depreciation. Under IRS
guidelines, the equity investors were allowed
to depreciate most project costs using a five-year, double-
declining-balance depreciation method.21
According to tax experts, this generally allowed 90-95% of the
cost of a wind project being
depreciated within six years.22 Accelerated depreciation
provided value to the tax equity investor by
postponing tax payments for several years.
Because the cooperative did not pay taxes, Baker needed to find
a willing tax equity investor with
taxable income to offset. In exchange for a ten-year stream of
tax deductions, the investor would
provide an upfront equity investment. To accomplish this, Baker
needed to create a taxable entity,
Fox Islands Wind LLC (FIW), to own the project assets. FIW
would be primarily (99%) owned by the
tax equity investor, with the de minimis residual owned by
FIEC (see Exhibit 11 for full corporate
diagram). The tax equity investor would also receive a dividend
of $25,000 per annum. After ten
years, ownership of FIW would “flip,” and the cooperative
would buy out the tax equity investor’s
interest. The tax equity investor would receive no further

economic benefits.
Baker reached out to three well-known institutional tax equity
investors but quickly found them
to be uninterested in financing such a small project. Continuing
his pattern of creating a community
project, Baker met with a local Maine company, Diversified
Communications, a privately-held,
family-owned business that operates in the broadcasting,
exhibition, publishing and emerging-media
industries. The company had strong community ties within
Maine, having been founded by former
Governor Horace A. Hildreth, Sr. in 1949. The company was
enthusiastic about the project and
committed $4.3 million subject to an agreed-upon target rate of
return.
Debt Financing
Baker had several debt financing options. He considered bank
financing, but found interest rates
to be high, in the 8-10% range. There were also government-
sponsored financing programs that could
be investigated. One option was the Clean Renewal Energy
Bond (CREB). The Energy Policy Act of
2005 provided electric cooperatives with the ability to issue
CREBs to finance renewable energy
projects. Under this program, the federal government provides
the purchaser of the bond with a tax
credit in lieu of an interest payment. While a CREB program
was an option, it had two main
drawbacks. First, the program was allocated through a
competitive process; Baker could not be
certain of success, and there was a considerable waiting period.
Second, the CREB could not be issued
by a taxable entity, meaning FIEC would be unable to use tax

credits to induce a tax equity partner.
The second government-sponsored financing option Baker
considered was a loan from the Rural
Utilities Service (RUS), an agency of the United States
Department of Agriculture (USDA).23 The
RUS’s mandate is to bring public utilities to rural areas through
public-private partnerships. The RUS
was already the cooperative’s lender. The RUS was hesitant to
lend to a newly-formed for-profit
subsidiary but was eager to provide financing to a renewable
energy project. By educating the RUS
about the complicated structure and the rationale behind it,
Baker was successful in securing a $9.5
21 Under the five-year, double-declining balance method, 40%
(2 times 100% divided by 5 years) of the book value is
depreciated annually.
22 Patricia G. Hammes, Mitchell E. Menaker and Robert N.
Freedman, “Putting the Wind (Back) to Work,” New York Law
Journal, July 6, 2009,
http://www.law.com/jsp/nylj/PubArticleNY.jsp?id=1202431933
621&slreturn=1&hbxlogin=1.
23 The RUS was originally created as the Rural Electrification
Administration (REA) in 1935. In 1994, the REA was
reorganized
into the RUS. The United States Department of Agriculture,
Rural Development, “The Story of Rural Electrification: 1935 -
Present,”
http://www.rurdev.usda.gov/tx/Legislative%20Seminar/USDA%
20Rural%20Development%20-
%20Rural%20Electrification.pdf, accessed September 3, 2010.

12
million 20-year loan at an expected rate of 4.25% per annum.
The loan was sized at the maximum
allowable under RUS regulations to allow flexibility for cost
overruns.24
Construction Financing
Baker had achieved the permanent financing necessary for the
Fox Islands Wind project, but he
still needed to find bridge financing to cover the cost of
construction as the RUS only lent against
completed projects. Although in theory a bank could look at the
financing commitments lined up, the
large size of the project relative to the cooperative’s existing
assets made banks hesitant to provide
bridge financing. Again, Baker needed to be creative; an
existing privately-owned non-profit called
the National Rural Utilities Cooperative Finance Corporation
(CFC) was dedicated to supplementing
RUS lending, but the CFC only lent to cooperatives. Given the
unfamiliarity of the CFC with this type
of project, Baker again needed to work closely to describe the
details of the project to obtain the $9.0
million construction loan. First, a structure by which the CFC
lent to the cooperative and the

cooperative in turn lent to FIW had to be devised. Second, an
education of the construction process
and required uses of funds prior to construction was required to
convince the CFC to fund the $1.5
million down payment to GE to hold the August 2009 turbine
delivery date.
Subsequent Developments
An unexpected but favorable boon to the project occurred in
February 2009, when President
Obama signed the American Recovery and Reinvestment Act of
2009 (ARRA), which provided the
option of a 30% investment tax credit for developers of clean
energy. The stimulus plan greatly
improved the economics of wind power financing and quickly
increased the availability of wind
financing nationwide.25 The tax credit also greatly improved
the economics for Diversified
Communications, which agreed to increase its equity investment
to $4.8 million initially and $5.0
million by the end of the project.26 Figure B shows the final
all-in costs of the project.
24 The RUS requires a minimum times-interest-earned ratio of
1.05x. Times-interest-earned is defined as (operating income
plus interest) divided by interest.
25 Russell Gold, “Wind Farms Set Wall Street Aflutter,” Wall
Street Journal, August 31, 2009,
http://online.wsj.com/article/SB125167463443070949.html.
26 Because the 30% investment tax credit is based on the
project’s total costs, the return to the tax equity investor

increases with
debt-funded cost overruns. Diversified Communications agreed
to increase its investment by $200,000 to a total of $5.0 million
in order to bring its total return closer to original projections.
13
Figure B Final Fox Islands Wind Project Sources & Uses
Sources (Permanent Financing)
Total Cost Per kW
RUS 4.25% 20 year loan $9,500,000 $2,111
Tax equity contribution 5,000,000 1,111
Total $14,500,000 $3,222
Uses
Total Cost Per kW
Pre-development costs $600,000 $133
GE turbines 7,600,000 1,689
Construction 5,000,000 1,111
Property & escrow 1,300,000 289
Total $14,500,000 $3,222
Source: Fox Islands Wind Presentation to the Gulf of Maine
Research Institute.

Final project costs were higher than expected for several
reasons. First, pricing for turbines turned
out to be higher than budgeted. Although prices fell
dramatically during 2008, Baker had limited
leverage to renegotiate price with GE because it was crucial to
obtain delivery and installation on-
time due to the looming onset of bad weather. Second, the
project incurred approximately $500,000 of
cost overruns due to an error in forecasting the electrical
grounding of the base.
Operating the Project
The completed wind project generated slightly more than half of
the island’s electricity use during
the year. During the winter, when winds blow substantially
stronger and electricity use was lower
(fewer residents), the project produced excess electricity.
During the summer, the island would need
to import energy. To facilitate the efficient management of this
variability, the cooperative entered
into a 20-year power purchase agreement (PPA) with FIW.
Under this agreement, the cooperative
buys power from the FIW in exchange for paying FIW’s
operating and financing costs (see Figure C
below). The cooperative, in turn, entered into a sale and
purchase agreement with the Vermont Public
Power Supply Authority (VPPSA), its historic partner for
electricity purchases, to sell VPPSA its
excess electricity and buy from VPPSA any deficit at wholesale
prices (see Exhibit 11 for a diagram).
Figure C Fox Islands Estimated Annual Operating and
Financing Costs
Total Cost Per kWh

Financing costs $770,000 $0.066
Insurance 50,000 0.004
Operations & maintenance 95,000 0.008
Lease and other payments 30,000 0.003
Total before RECs $945,000 $0.081
REC sales (354,960) (0.031)
Total $590,040 $0.051
Source: Fox Islands Wind estimates. Cost per kWh is equal to
cost divided by expected annual generation of 11,600 MWh.
Totals may not add due to rounding.
An additional source of savings for the island’s residents was
the sale of Renewable Energy
Credits (RECs). Baker negotiated the sale of the project’s RECs
at a five-year fixed rate of $30.60 per
MWh to Cape Light Compact, an energy services organization
serving Cape Cod and Martha’s
Vineyard. As part of the REC sale, FIEC cannot claim that the
energy it produces is “green” as the
14
“greenness” is sold along with the REC, but the community
benefits by a savings of approximately
three cents per kWh for its power generated by the project.

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