Finance Homework

WIND RE SOURCES, I NC. In July 2005, Mr. Charles Bittner, ch ief executiv e officer of W ind Resources, Inc. (WRI), needed to d ecide how best to cap ita lize on the c ompany’s d evelopm ent easem ent lo cated in the San Gorgonio Pass near Palm Springs , California. In 1985, W RI had acquired the easem ent from the property’s owner, the Bureau of Land Management (BLM), and entered in to a com plex 20-year agreem ent with private investors, creditors, and Southern California E dison to build and operate a 30-m egawatt wind energy facility on the site. W ith the original agreem ent about to expire, M r. Bittn er needed to deci de what to do with the easem ent. The site, known as Canyon W ind, was reputed to be “one of the prem ier wind resources in North Am erica,” and with conventional energy pric es rising sharply, continued use of the site as a wind farm seem ed the obvious choice. Two options appeared feasible. One was to con tinue opera ting the s ite ’s existing but aging turbines. Ownership of the turbines and related equi pm ent had rec ently rev erted to W RI when private investors had encountered difficulty servicing the debt or iginally incurred to purchase them. A second option was to sell the easem ent to new owne rs who would m ost likely redevelop the site m uch as W RI had done in 1985 but this tim e using new, m uch la rger turbin es. Mr. Bittne r se nsed that W RI’s princ ipal shareho lders were interested in se lling the easem ent as soon as possible, but before putting the easem ent up for sale or auction, he needed to estim ate its value to new ow ners. (Exhibit 1 shows the Canyon W ind site and existing turbines. Exhibit 2 is a graph of natural gas prices over the past tw o decades, and Exhibit 3 records th e vo latility of gas prices over different tim e periods.) The Industry Today’s wind energy business is a child of OPEC and W estern governments. Concerned about Am erican dependence on foreign oil and the environmental dam age caused by use of fossil fuels, the U.S. Congress passed th e Public Utilities Regulatory Policies Act (PURPA) in 1978 as part of the National E nergy Act. Th e 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. Pro fess ors Rocky Hi ggi ns a nd R obe rt Keel ey pre pare d this case f or cl assr oom di scus sion. It desc ribes an actu al situ atio n, alth oug h so me in form atio n has been altere d. W e tha nk Profess or A vi Kamara for his h elp and ad vice. Al l rem aining er rors are ours. © 2 007 University of Was hington Business Sch ool 1 Wind Resources, Inc.

Although PURPA is Federal Law, Congress de legated implem entation to the states, resulting in a variety of regulatory schem es acr oss states and the absence of any activity at all in others. In 2004, Ca lifornia took the lead in PURPA enforcem ent when it required all major investm ent-grade utilities in the state to acq uire one percent m ore of their power fro m renewable sources each year, so that by 2017 at least 20 percen t of total electric supply is made up of renewable generation. It also m andated a bidding process requiring fixed- price 10 to 20 year contracts known as Power Purchase Agreem ents (PPAs) at prices based on the cost of new conventional gene rating sources. Califor nia’s actions were largely in response to the de vastating energy crisis it suffered in 2001 and a consequent desire to diversify supply, increase in-sta te production, and reduce reliance on natural gas-fired power. 1 As f urther stim ulus to alte rnative e nergy developm ent, wind energy investors benefit from two lucrative tax breaks. Federal law allows owners to de preciate qualifying wind energy assets at an accelerated rate o ver a five-year period, ev en though th e econom ic life of wind turbines and towers is closer to 20 years. In 1992 Congress created an annual Production Tax Credit (PTC) for wind and ot her renewable energy technologies. The credit is pro portion al to the energy p roduced an d extends over the first 10 years of project life. The current PTC is 1.9 cents per kilowatt -hour with a cost of living adjustm ent of 2.5 percent a year. The original legislation was for only three years but has been renewed in fits and starts since. Current legi slation extends the PTC through at least 2008. 2 W ind power econom ics has im proved dram atic ally ov er the past two decades, due prim arily to the use of ever -la rger turb ines. The energy produced by a turbin e is proportional to the cube of the wind speed and the square of the turbine’s blade length. The gradual m igration f rom turbines with bl ade diam eters of 10 m eters in the 1980s to diam eters of 50 m eters common in 2000 produ ced a 55-fold increase in power output, partly becau se the area swept by the blade is 2 5 tim es larger and partly because wind speed in creases with b lade altitud e. Reflec ting additional benefi ts of better tu rbine design, location, and computerized controls, th e cost of wind-generated power has fallen som e 90 per cent in the past 20 years. 3 Despite these im prove ments m ost wind power s ources are s till not competitive on price with fossil f uel power and m ay not be for years. According to data from the In tern ational Energy Agency (IEA) in Paris, the cost of el ectricity f rom coal-f ired plants is 2. 5 – 4 cents per kilowatt-hour, while the cost from natu ral-gas-fired plants is 4 to 6 cents. In contrast, energy costs f rom wind power range from 4 to 14 cents per kilowatt-hour, depending on size and location. 4 1 “O ver view of the C alifornia Model for E ncouraging R enewabl e Ene rgy Devel opm ent ,” Thel en Reid Br ow n Raysman & Stein er LLP, Oil, Gas an d En erg y Law Jo urn al, Ju ly 26 , 20 04 . ww w.c onst ruct ionwebl inks.co m/resou rces/ indust ry_report s_ne . 2 “Con gress Ex tends Wind En erg y Pro duction Tax Cred it for an Ad dition al Year,” Americ an W ind En ergy Ass ociation , Decem ber 11 , 20 06 . 3 “Th e Econo mics of Wind Ener gy,” American Wind E nergy Ass ociation , Febr uary 200 5. ww w.aw ea.org . 4 “Ren ewab le Po wer May Yet Yield Wind fall ,” Keith Jo hn son, Wall Street Jou rnal, p. A8, March 22 , 20 07 .

2 Wind Resources, Inc.

W ind power accounted for only 0.5 percent of global and U.S. dom estic electricity production in 2004 according to the IEA. By 20 30 the agency expects this figure to rise alm ost 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 u p from just $420 m illio n in 2004. This would m ake wind power the second largest so urce of new electrical power for the year behind natural gas-fired plants.

Keys to a successful wind far m investm ent ar e a great site, an attr active long-term PPA, and continued governm ent support of rene wable energy resources. W ind fa rm investm ents require large ini tial capital outlays, followed by relatively stable long-ter m revenue stream s. Be cause predicting wi nd velocity is much easier than predicting where new oil or gas reserves will be found, wind investm ents are considered safer technologically than conventi onal energy investm ents. The chief cost of a wind farm investm ent is the initial capital outlay, while the chief risks involve securing a favorable PPA and m eeting a m yriad of regulatory and perm itting requirem ents, of ten including the placating of restive neighbors. Wind Resources, Inc.

An experienced alternative energy entrep reneur founded WRI in 1985 to develop and market the Canyon W ind site located on BLM land. He designed the project to take full advantage of the liberal tax provisions ava ilab le to qualif ying renewable energy investm ents. As sponsor, WRI identified the site, negotiated a long-term , renewable developm ent easem ent with the BLM, designed the wind far m, gui ded the project through a complex permitting process, secured a 20 year, fixed-price PPA with Southern California E dison, negotiated project financing, and identified a group of potential equity investo rs. W ith all the pieces in place, WRI then comm issi oned construction of the wind far m and sold the capital equipm ent and equ ity cash flow rights for a period of twenty years to inv estors. (At the tim e tar get inve stors were wealthy indi vidu als in ter este d in available tax credits an d shields. T ax laws changes in 1986 prohibited individuals fro m using tax shields generated on one activity to reduce tax obligations generated on another, so today’s wind far m investors tend to be profitable corporations , such as General Electric, anx ious to redu ce taxes.) WRI structured the eq uity transaction as an installm ent sale on the expecta tion that projected project cash flows to equity i nvestors would be sufficient to service the installm ent debt. One hundred percent debt financing was quite attractiv e to equity investo rs b ecause it elim inated any initia l investm ent on their part , g uaranteeing they would be cash flow positive from day one. At worst, equity inve stors m ight default on the debt and have to walk away without th e antic ipated tax shield s and profits, while on the ups ide, they would captu re th e anticip ated tax benefits and any residual profits without any cash outlay. WRI’s profits would co me from a sizeab le d eve lopm ent fee incorporated in the p roject’s selling price, interest on the installm ent debt, a share of pr ofits above a specified level, and annual fees for m anaging the facility. W RI also retained the right to repurchase the turbines at f air-m arket value at the end of the pr oject’s life in 2005 and to dispose of the 3 Wind Resources, Inc.

site as they chose. Sho uld they cho ose not to continue operating the property as a wind far m, W RI would incu r a s ite restoration char ge of as m uch as $2.5 m illion im posed by the BLM. The 1985 Canyon W ind developm ent did not live up to initial expectations chiefly because it never deliv ered m ore than 75 p ercent of targeted capac ity. Inaccu rate projections of wind ve locity and persistence, com bined with various unanticipated operating problem s, wer e the chief contributors to the shortf all. Mr. Bittner was inclined to attribute these problem s to industry growi ng pains that would not be repeated in any future redevelopm ent of the site. In the end, equity inv estors receiv ed m ost of the anticipated tax shield s but little in the way of profits. The situation was touch and go for a pe riod whe n equit y inve stors fe ll behind on installm ent paym ents to WRI, but they m anaged to recoup by the end of the period, in part by ceding ownership of the turbin es and towers to WRI at the end of their contract. WRI’s owners did be tter, rec eivin g antic ipate d fees and inte rest o the r than shared profits, while retaining redevelopm ent rights. The Alternatives As the in itia l 20-ye ar d evelopm ent contrac t app roached m aturity, Charle s Bittn er n eeded to recomm end a course of action to his boa rd. Growing dissenti on am ong W RI owners and financial problem s at one inclined Mr. Bi ttner to ru le out re developm ent by WRI . The possib le im positio n of a $2.5 m illion s ite res toratio n fee m ade abandonin g the easem ent appear unattractiv e as well. Although other stra tegies were possible, Mr. Bittne r decided to consider two in d etail: con tin ue to opera te the existin g turbine s, o r sell the BLM easem ent to anot her developer at auction. Continue to Operate Existing Turbines Exhibit 4 pr esents Mr. Bittne r’s an alysis of the first option. Assum ing W RI could keep the existing turbines operati onal for another 10 years by spending an additional $200,000 a year in current dolla rs on major m aintenance, Mr. Bitt ner estim ated the annual free cash flow from continued operation would be about $800,000 a year, for a present value of just ov er $4. 7 m illion wh en dis counted at ten pe rcent. Ten percent re flected Mr. B ittn er’s understanding of industry practice w hen va luing unlevered wind energy cash flows. Sell Easem ent to another Developer Mr. Bittne r reasoned th at the highe st price a wind f arm developer would pay f or the Canyon W ind site should equal the profit he c ould earn by redeveloping the site much as WRI had done in 1985. To help estim ate the value of the site to a new developer, Mr. Bittner turn ed to MDS Energy Consulting, Inc., an exp erien ced alternative en ergy consultant WRI had used in the past. In their r eport, MDS identif ied sev en m ilest ones any redevelopm ent must achieve and briefly discussed the ch allenges to be addre ssed in m eeting each. 4 Wind Resources, Inc.

1. Site control . The current BLM easem ent expires in 2015 and needs to be extended before developm ent can commen ce. MDS noted that ob taining an extension was likely but noted that the tim e, effort and expense involved could be “significant.” 2. Wind resource documentation . WRI has twenty years of data on th e strength and persis tence of winds at the site. But use of m uch larger and taller turbin es means that additional data will need to be docum ented and confirm ed as part of the redevelopm ent pro cess. Efficiency is m easured by a site’s Net Capacity Factor (NC F), the ratio of the energy pr oduced per year at a site divided by the theoretical m aximum possible production. 3. Regulatory and permitting approval . Relev ant county perm itting requ irem ents are som e of the m ost highly developed and specific in the industry, which m akes the perm itting process tim e consuming, ev en if third parties do not oppose the project. Lo cal res idents imm ediately ad jacen t to the prop erty h ad been quit e vocal and effective in lim iting efforts of other projects to develop nearby sites with newer and taller tu rbines. Moreover, becau se the site is on Federal property, significant environm ental review m ight be required, including a new or updated Environm ental Im pact Statem ent. In MDS’s view redevelo pm ent permits cou ld likely be secured but the outcom e wa s not a foregone conclusion. 4. Interconnection and transmissio n access . The site has a working interconnection with the Sout hern California Edison grid , and it is likely this interconnection can be m aintained and enhanced as necessary. The Federal Energy Regulatory Commission (FREC) m ust now approve applications for interconnection rights, and while approval appears assured, costs of enhancing the interconnection could ex ceed pro jections. 5. A long-term pow er purchase agreemen t. This is the lynch pin of any redevelopment. In order to secure n ecessary pro ject financing, a long-term power purchase agreem ent with a credit-worthy investment grade (B BB- or better) buyer is neces sary. MDS noted that th e Califor nia Public Utilities Comm ission (CPUC) has recen tly determ ined that an app ropr iate price for renewable ene rgy purchas e under a 15-year PPA starti ng in 2005 should be $0.0588 per kWh. And while the CPUC’s determ ination does not guaranty this price, it does provide a good indication of the potential m arket. 6. Project financing . Once the redevelopm ent project has sufficiently docum ented its wind resource and secure d site control, perm its, an interconnection and a viable PPA, it m ust be financed. Under the current wind industry paradigm , the wind project owner m ust have a substantia l ap petite f or ta x credits. Leveraged after-tax internal ra tes of return (IR Rs) in the c urrent m arket were typ ically in the mid-teens, while unlev eraged IRRs were in the range of 10 percent. Interest costs 5 Wind Resources, Inc. on debt financing were 1.5% to 2.5% ove r 3-m onth LIBOR, and the first-year interest-coverage ratio had to equal at least 1.7 tim es. 7. Project con struction . The Canyon site has several characteristics th at m ake it a challenging site for a m odern wind energy developm ent, including difficult terrain and access to the site. Hauling new, large turbines up and down the win\ ding access road s m ay presen t a challeng e. Ir onically, another challeng e m ay be the strong winds characteristic of the site, which m ay force delays and increase insta lla tion costs. Exhibit 5 su mmarizes MDS’s analysis. I t en visions that a develope r will purch ase the Canyon W ind easem ent from WRI and imm ediatel y redevelop the prop erty for sale to equity investors. The projected redevelopm ent includes r eplacing ex isting turbine s with 20 new General Electric 1.5 m egawatt m odels sporting 77-m eter rotor diam eters on 65- meter tower s. I t a lso antic ipates nego tia ting a new 15-y ear, f ixed -price PPA with Southern California Edison at 0.0588 $/kW h, and a m inim um first-year interest coverage of 1.75 tim es. Other as sum ptions are that th e s ite’s NCF will equal 43. 74 percen t, the salvage value of existing turbines will about e qual the cost of rem oval, 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 W ind Project at a PPA of $0.0588/kWh is $65.9 m illion. This num ber is driven by two key requirem ents: that equity inves tors s ee a p rospective 1 5 percen t IRR and that first-y ear interes t cov erage equals 1.75 tim es. Given these requirem ents, the spreadsheet in E xhibit 5 solves ite ratively for to tal project va lue by calcu lating available debt fina ncing and adding the present valu e of residu al cash flows to equity. T he project employs senior debt and PTC debt in a 2 to 1 ratio. Because creditors pe rceive 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. W ith total developm ent costs es tim ated to be $5 2.8 m illion and tota l project value equal to $65.9 m illion, the implied developer p rofit is $13.0 m illion, well above the p resen t value from continued operation of existing tu rbines. For comparison, MDS had assigned a value of $7.7 m illion to redevelo pm ent of th e sam e site in late 200 3. Most of th e incre ase was attr ibutab le to a 24 perc ent inc rease in the PPA as the resu lt o f rising natu ral gas prices.

MDS also p repared th e m atrix in Ex hibit 6 s how ing the sensitivity of developer profit to 5 percent changes in the PPA price and the NCF. Exhibit 7 pres en ts represen tative inte rest rates in July 200 5. The Decisio n Two re maining issues p uzzled Mr. Bittner as he reviewed MDS’s report. W ould a buyer pay the full developer prof it calculated in Exhibit 5 to purchase the Canyon W ind easem ent, or in view of the risks surroundi ng redevelopm ent, would he only pay som e fraction of this am ount? And if so, what fr action should W RI expect ? Redevelopment of 6 Wind Resources, Inc.

the site certainly involved risk, but Mr. B ittner knew that due to the benefits of diversification only system atic, or nondiversifiable, risk should affect price. To his eyes most of the risks associated with rede veloping the Canyon W ind easem ent appeared unsystem atic. In light of energy price volat ility, Mr. Bittner also wondere d if the ability to postpone redeve lopment f or at lea st th ree years m ight somehow contribut e to the p rojec t’s v alue in a way not captured in MDS’s valuation. If so, MDS’s estim ated developer profit m ight understate true project value. Mr. Bittner tho ught in term s of a three-year horizon because th e production tax cred it was presentl y set to ex pire in three years, although Congress had repeatedly rene wed the credit sinc e 1992. Tim e was running short for a decision, and Mr. Bittner was anxious to get on w ith enjoying his summ er. 7 Wind Resources, Inc.

Exhibit 1 Canyon W ind Farm Exis ting Turbines 8 Wind Resources, Inc. 9 Natural G as P rices M ont hly Fe b. 1985 - Jul y 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 Ex hibit 2 Cents/kW h Wind Resources, Inc.

Exhibit 3 Volatility o f Natural Ga s Prices Annuali zed Standard Deviation of Monthl y Returns on US Natural Gas Wellhead Prices Date Number of Observatio ns 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 So urce: U.S. Depa rtment of Ener gy , Ene rgy In form ation Adm inistrat ion. http ://to nto.eia.d oe.gov /dn av/ng/ng_p ri_sum_dcu_ nu s_m.htm 10 Wind Resources, Inc. 11 Price o f electricity (per kWh) 0.058 8 $ Output (kWh/yr) 55, 500 ,000 Investment in subst ation 400 ,000 $ Net scrap value of a t urbi ne in 2006 1,20 0 $ Gross scrap value of t urbine in 20 16 25 6 $ Inflation rate 2.5% Discount rate 10% Pe riod 1 234 5 6 7 8 200 6 200 7 2008 20 09 201 0 201 1 2012 2013 Revenue 3,344 ,985 3,42 8,610 3,514,325 3,602 ,183 3,692, 23 8 3,784,544 3,879 ,157 3,976,13 6 Co sts O per ations & Routine Maint.

1,107,50 0 1,135,188 1,16 3,567 1,192 ,656 1,222, 47 3 1,253,035 1,284 ,360 1,316,46 9 Plant , sub station & Edison fees 190,50 0 195,263 20 0,144 205 ,148 210, 27 6 215,533 220 ,922 226,44 5 Lan d R ent 87 ,000 89,175 91,404 93 ,689 96, 032 98,433 100 ,893 103,41 6 Insu rance 240 ,000 24 6,000 252,150 258 ,454 264, 91 5 271,538 278 ,326 285,28 5 Prope rty tax 134 ,800 13 8,170 141,624 145 ,165 148, 79 4 152,514 156 ,327 160,23 5 Manag em en t 106 ,100 10 8,753 111,471 114 ,258 117, 11 5 120,042 123 ,043 126,12 0 Depreci ation 200,00 0 200,000 20 0,000 200 ,000 200, 00 0 200,000 200 ,000 200,00 0 Total 2,065 ,900 2,11 2,548 2,160,361 2,209 ,370 2,259, 60 4 2,311,095 2,363 ,872 2,417,96 9 Pretax p rofit 1,279,08 5 1,316,062 1,35 3,964 1,392 ,813 1,432, 63 3 1,473,449 1,515 ,285 1,558,16 7 Tax @ 40 .7% 520 ,588 53 5,637 551,063 566 ,875 583, 08 2 599,694 616 ,721 634,17 4 After tax pr ofit 758,49 7 780,425 80 2,900 825 ,938 849, 55 1 873,755 898 ,564 923,99 3 Depreciation 200,00 0 200,000 20 0,000 200 ,000 200, 00 0 200,000 200 ,000 200,00 0 Cash flow f rom ope ration s 958 ,497 98 0,425 1,002,900 1,025 ,938 1,049, 55 1 1,073,755 1,098 ,564 1,123,99 3 Annua l turbine o verha ul 205,00 0 210,125 21 5,378 220 ,763 226, 28 2 231,939 237 ,737 243,68 1 Free cash f low 753,49 7 770,300 78 7,522 805 ,175 823, 27 0 841,817 860 ,827 880,31 3 Salvage value of tu rbines (after ta x) La nd restoration cost (after tax) Total free cash flow 753,49 7 770,300 78 7,522 805 ,175 823, 27 0 841,817 860 ,827 880,31 3 Present value (discounted at 10 %) $4, 715 ,520 Assu mption s: 1. O utput remains at 2005 level, pr ovided $20 0,000 increa sing at inflation rate is spe nt annually for major m aintena nce of turbines, in addition to routine m aintenance. 2. Tax r ates a re 35% fede ral an d 8 .84 % st ate (40.7% co mbined ). 3. Restoration cost includes removal of subst ation an d removal of old turbines, but no t land restoration. Land restoration co sts of ab ou t $1 m illion are d eferred until the si te is ab and on ed (perha ps i n 20 33) . Turbine removal cost s $ 2000 pe r unit. Net scr ap value is the v alue after removal (i.e. Gross scr ap value m inus $2 000 ). Exhi bi t 4 Analysis of C ont inued O per at ion usi ng E xisting Tur bi nes Wind Resources, Inc. 12 Augus t 18, 200 5 Site dev elope d in 20 06 w ith 20 Gen eal Electric 1.5 m egaw att SLE model turbine s with 77 meter rotor dia meters on 65 meter to wers. Assumptions an d Results ($ in thous ands) Ca pacity Financing Turbine capacit y (m w) 1.5 Minim um IRR to equi ty 15% Nu mber of turbines 20 1st year interest coverage (times) 1.75 (Op. inc ome/inter est) Total c apac ity (mw) 30 1st year interest ex pense 2,66 9 Ho urs per year 8,760 Debt sources Gross produ ction/y r (mWh/yr) 262 ,800 Rate Term (yrs)% Total deb t Ra ted c apa city factor 49.0% Seni or deb t 7.0% 15 67% Production before sit e adjustments 128 ,722 PTC deb t 6.5% 10 33% Site adj ustments 13,768 Weig hted- average inter est rate 6.835 % Ne t ad justed ann ual produ ction 114 ,954 Maximum deb t 39,04 3 $ Ne t capacity factor 43.74% Seni or deb t 26,15 9 De velop ment cost s PTC deb t 12,88 4 Equi pm ent lif e (yr.s) 20 Com pensating bal ance r eqm 't 2,36 6 Salvage v alue in 20 yrs. - Tax rate ( feder al & s tate) 40.7% Co st per turbine & tow er delivered 1,843 Depreciation 5 year MACR S Total turbine & tower co st 36,860 Production tax cre dit (ce nts/kwh) 1.90 Installa tion c osts 8,060 PTC COLA 2.05 % Fees & ex pens es 7,921 Total de velopm ent cos ts 52,841 $ Project Va luation Power selli ng p rices Equi ty financing 26,82 8 Purchase power ag reement (yrs.) 15 Seni or deb t financ ing 26,15 9 PPA price ($/kWh) 0.0588 PTC debt financing 12,884 Sales in yrs. 16- 20 at market Total pr oject value 65,87 1 Increase in market price per year 2.5% Dev eloper prof it 13,03 0 $ Ex hibit 5 Va luation of Can yon Wi nd Pr oje ct Re de velopme nt by RHK Ene rgy Cons ulting, Inc. Wind Resources, Inc. Exhibit 5 (Con tinu ed) Cash flow s to eq uity 0 1 234567 89 10 Ye ar 2006 2007 2008 2009 2010 201 1 201 2 2013 2014 2015 2016 Net production (MW) 114,94 9 114,94 9 114,9 49 114,949 114 ,949 114,949 114,949 114,94 9 114,94 9 114,9 49 PP A s ales pric e ($/kWh) 0.0588 0.058 8 0.05 88 0.05 88 0.05 88 0.0588 0.0588 0.058 8 0.058 8 0.05 88 Operating reven ue ($ millions) 6,75 9 6,75 9 6,759 6,759 6,759 6,759 6,759 6,75 9 6,75 9 6,7 59 Other revenu es 152 152 152 152 152 152 152 152 152 152 Total reven ue 6,91 1 6,91 1 6,911 6,911 6,911 6,911 6,911 6,91 1 6,91 1 6,9 11 Total ope rati ng ex pen ses 2,24 1 2,24 3 2,529 2,545 2,559 2,352 2,350 2,35 0 2,34 7 2,3 48 Operating income 4,67 0 4,66 8 4,3 82 4,366 4,352 4,559 4,561 4,56 1 4,56 4 4,5 63 Debt s ervice 4,66 4 4,66 4 4,664 4,664 4,664 4,664 4,664 4,66 4 4,66 4 4,6 64 Pretax cash flow to equity 6 4 (282) (298) (312) (105 ) (103) (10 3) (100) (101) Tax calculation Opera ting income 4,67 0 4,66 8 4,3 82 4,366 4,352 4,559 4,561 4,56 1 4,56 4 4,5 63 Depreciation & A mort.

26,70 4 13,67 3 8,267 5,021 5,021 2,596 159 159 159 159 Intere st ex pen se 2,66 9 2,53 4 2,3 90 2,236 2,072 1,896 1,709 1,50 9 1,29 6 1,0 68 Taxable income (24,70 2) (11,53 8) (6,2 75) (2,891) (2,741) 67 2,693 2,89 3 3,11 0 3,3 37 Tax (10,05 4) (4,69 6) (2,5 54) (1,177) (1,116) 27 1,096 1,17 8 1,26 6 1,3 58 Production tax credit 2,18 4 2,22 9 2,2 74 2,321 2,369 2,417 2,467 2,51 7 2,56 9 2,6 22 FC F to equ ity* 12,24 4 6,92 9 4,546 3,199 3,172 2,285 1,267 1,23 7 1,20 3 1,1 62 Eq uity inv estm ent fo r 15 % IRR (26,828) $ Depre ciati on calculations Asset basis 60,32 9 60,32 9 60,3 29 60,329 60,329 60,329 60,329 MACRS depr eciation rate 44.00 % 22.40 % 13.4 4% 8.06% 8.06% 4.04% Depre ciation 26,54 5 13,51 4 8,108 4,863 4,863 2,437 0 Am orti zaztion calculations Asset basis 3,17 5 3,17 5 3,175 3,175 3,175 3,175 3,175 3,17 5 3,17 5 3,1 75 20 y r. SL am ort.

159 159 159 159 159 159 159 159 159 159 Debt s ervice c alculations Sr. Debt interes t 1,83 1 1,75 8 1,6 80 1,597 1,508 1,412 1,310 1,20 0 1,08 3 958 Sr. Debt principal pm t.

1,04 1 1,11 4 1,1 92 1,275 1,364 1,460 1,562 1,67 2 1,78 9 1,9 14 Sr. D ebt Se rvice 2,87 2 2,87 2 2,872 2,872 2,872 2,872 2,872 2,87 2 2,87 2 2,8 72 Ending S r. Debt Principal 25,11 8 24,00 4 22,8 12 21,537 20,172 18,712 17,150 15,47 8 13,69 0 11,7 76 PTC Debt i ntere st 837 775 709 639 564 484 399 309 212 109 PTC Debt pri ncipal pmt.

955 1,01 7 1,0 83 1,153 1,228 1,308 1,393 1,48 4 1,58 0 1,6 83 PTC Debt Service 1,79 2 1,79 2 1,792 1,792 1,792 1,792 1,792 1,79 2 1,79 2 1,7 92 Ending P TC Debt Princ ipal 11,92 9 10,91 2 9,830 8,676 7,448 6,140 4,747 3,26 3 1,68 3 (0) Pro duc tion tax credit calculati ons Tax credit rate (cents/kWh) 1.9000 1.939 0 1.97 87 2.01 93 2.06 07 2.1029 2.1460 2.190 0 2.234 9 2.28 07 Tax credit 2,18 4 2,22 9 2,2 74 2,321 2,369 2,417 2,467 2,51 7 2,56 9 2,6 22 *FCF to equity = O pera ting income after tax + Tax shields on depre ciati on and interes t + pro duc tion tax credit - deb t servic e 13 Wind Resources, Inc. 14 Exhi bi t 5(Cont inued) Cash flows to eq uity Yea r 11 12 13 14 15 16 17 18 19 20 Net produc tion (MW) 2017 2018 201 9 2020 202 1 2022 2023 2024 2025 20 26 PPA sales pr ice ( $/kWh) 114 ,949 11 4,949 114, 949 11 4,94 9 114, 949 114 ,949 114, 949 114 ,949 114, 949 114, 949 Oper ating r evenue ($ m illio ns) 0.0588 0.0588 0.0588 0.058 8 0.0588 0.085 2 0.0873 0.0895 0.0917 0.0940 Othe r revenues 6,75 9 6,759 6,759 6,75 9 6,759 9,78 9 10, 034 10 ,285 10, 542 10, 805 Total revenue 11 1 111 111 11 1 100 34 34 34 34 34 Total oper ating expen ses 6,870 6,870 6,870 6,87 0 6,859 9,82 3 10, 068 10 ,319 10, 576 10, 839 Oper ating i ncome 2,28 5 2,283 2,280 2,27 8 2,276 2,39 0 2,426 2,462 2,499 2,537 Debt ser vice 4,585 4,587 4,590 4,59 2 4,583 7,43 3 7,642 7,857 8,077 8,302 Pretax c ash flow to equ ity 2,872 2,872 2,872 2,87 2 2,872 0 1,71 3 1,715 1,718 1,72 0 1,711 7,43 3 7,642 7,857 8,077 8,302 Tax calculation Oper ating i ncome Depreciation & Amort.

4,58 5 4,587 4,590 4,59 2 4,583 7,43 3 7,642 7,857 8,077 8,302 Interest ex pe nse 159 159 159 15 9 159 15 9 159 159 159 159 T axable income 82 4 681 528 36 3 188 0 0 0 0 0 T ax 3,602 3,747 3,904 4,07 0 4,236 7,27 4 7,483 7,698 7,918 8,143 P roduc tion t ax c redi t 1,466 1,525 1,589 1,65 6 1,724 2,96 1 3,046 3,133 3,223 3,314 FCF to equity 0 0 0 0 0 000 00 Equity invest ment for 15% IRR 24 7 190 129 64 (13) 4,47 2 4,596 4,724 4,854 4,988 Depr eci ation calculations Asse t basis MACRS de preciation rate Depr eciation Amortizaztion calculations Asse t basis 20 y r. SL am ort.

3,17 5 3,175 3,175 3,17 5 3,175 3,17 5 3,175 3,175 3,175 3,175 15 9 159 159 15 9 159 15 9 159 159 159 159 Debt ser vice c alculations Sr. D ebt interest Sr. Debt principal pm t.

82 4 681 528 36 3 188 Sr. Debt Service 2,048 2,191 2,344 2,50 9 2,684 Endi ng S r. Debt Principa l 2,872 2,872 2,872 2,87 2 2,872 9,72 8 7,537 5,193 2,68 4 0 PTC De bt interest PTC Debt pr incipal pmt.

P TC Debt Service Endi ng P TC Debt Principal Produc tion tax cr edit calculations Tax credi t rate (cent s/kWh) Tax cr edit Exhibit 5 (Continued ) Discussion Site ad jus tme nts. Efficie ncy adjustm ents to acco unt for li mited availabilit y, electrical losses, wake and array losses, turbu lence/ high wind cu t-o ut, blad e con tam inatio n, icing , an d grid ou tag es. Fees & expenses. Includes devel opm ent expe nses , capit alized in terest during co nstructio n, cap italized term debt ser vice rese rve , len der’s fee, le nde r’s t ransaction costs, a nd bo rrowe r’s counsel . Purchase power agreeme nt (PPA). A 15-year, fixe d price power sales agre ement we e xpect can prese ntly be negot iated wi th So uthern C alifor nia E dison. The c ontact pri ce depe nds pri mari ly on t he utility’s h ighest p ower co st av oided by th e contract, wh ich fo r So uthern Califo rnia Ediso n is t he cost o f nat ural gas . We bel ieve a c ontract can be negot iated t oday at 0. 05 88 $/kWh. Sal es in years 16 -20. A fter 15 y ears, we a ssum e powe r can be sol d at a vari able m arket pri ce, whi ch we esti mate will i ncrease with infl atio n at 2.5 percen t a year. Required I RR to equity . B ased o n our expe rience , we bel ieve equi ty invest ors can be at tract ed t o wi nd energy projects in today’s m arkets that promise in tern al rates of retu rns of at least 1 5 percen t. Production tax credit r ate (PTC). Cong ress of fer s production t ax cre dits to enco ura ge devel opm ent of alternative ene rgy. The c urrent ra te, rece ntly extende d for three year s, i s 1. 90 percent o f re ven ues increasing at 2.05 pe rce nt a ye ar for 10 years. Minimum equity/total capital. Based o n expe rience a nd ou r m arket co ntacts we are confi dent this project can s upport a first -year i nterest cove rage rat io as l ow as 1.75 t imes, wi th one -third of the de bt sec ured by PTC cas h flow s. Beca use PT C cash fl ows d epen d only on reve nue gene ration, lend ers p ercei ve them to be safer t han operating ca sh flows an d dem and a lower i nterest rate. We estim ate i nterest rate on th e rem aining de bt to be 2 perce nt ove r 3-m ont h LIB OR, or 7 percent . Com pens ating balance requirement. Le nde rs dem and that ap proxi mately one y ear ’s interest ex pense be held i n reserve as a non-i ntere st beari ng de posit. Depreciation. In add itio n to product ion t ax credi ts Congress al so al lows rapid depreci ation of wi nd energy project s. Eve n though t he t urbines have a 20 -year l ife expect ancy, ni nety-five pe rce nt of t otal project value, less the com pensating balance , qualifies for m odified accelerated cost recove ry (MACRS) dep reci ation over five y ears . The rem aining 5 pe rce nt can be am ort ized o n a st rai ght-line basi s ove r 2 0 years.

Devel oper profit . Equal s the diffe rence bet ween Total pr oject val ue a nd Tot al de vel opment cost s. Total operati ng e xpenses . Includes land lease payments, adm inistrat ive e xpe nses, propert y taxes, interco nnect ion/wheel ing expen ses, i nsurance, a nd devel opm ent royalties eq ual to 1.50 pe rce nt of gross reve nue. Equity investment for 15 % IRR . Pr esen t value o f free cash flow s to equity th rough 2 026 discou nted at 15 pe rce nt. 15 Wind Resources, Inc. 0.05 59 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 MDS E nergy Co nsulting , Inc. Exhibit 6 C anyon W ind P roject S ensitivity A nal ysi s PPA Pr ice ($ /kW h) Net Capaci ty Factor Estimat ed D evel oper P rofit ($ m illion) 5% Pe rturbations in PPA and N CF 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