Finance Homework

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

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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.

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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.

Wind Resources, Inc.

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

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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.

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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

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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

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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.

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Exhibit 1 Canyon Wind Farm Existing Turbines

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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

Wind Resources, Inc.

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

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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

Wind Resources, Inc.

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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.

Wind Resources, 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

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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

Wind Resources, Inc.

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

Wind Resources, Inc.

17

Exhibit 7 Representative Interest Rates in July 2005

Instrument Interest Rate (%)

1-month Treasury Bill 3.10

3-month Treasury Bill 3.22 6-month Treasury Bill 3.28

1-year Treasury 3.64 3-year Treasury 3.91

5-year Treasury 3.98 10-year Treasury 4.18

20-year Treasury 4.48

5-year Treasury Inflation-Indexed 1.67

30-year Conventional Mortgage 5.70 BAA Corporate Bond Yield 6.25