F ,aiosrv,r,x.p Jr ErE , tIrq iiX vlf~llfff A r) D Energy Sector Management Assistance Progrartoiit

IndiaWindfw PreIevestment Study

Report No. 150/9

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JOINT UNDP / WORLD BANKENERGY SECTOR MANARGEMENTASSISTANCE PROGRAMME (ESMAP)

PURPOSE

The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) waslaunched in 1983 to complement the EnergyAssessmen. Programme, established three years earlier.ESMAP's original purpose wrs to implement key recommendations of the Energy Assessmentreports and ensure that proposed investments in the energy sector represented the most efficient useof scarce domestic and external resources. In 1990, an international Commission addressedESMAP's role for the 1990s and, noting the vital role of adequate and affordable energy in economicgrowth, concluded that the Programme should intensify its efforts to assist developing countriLs tomanage their energy sectors more effectively. The Commission also recommended that ESMAPconcentrate on making long-term efforts in a smaller number of countries. The Commission's reportwas endorsed at ESMAP's November 1990 Annual Meeting and prompted an extensivereorganination and reorientation of the Programme. Today, ESMAP is conducting EnergyAssessments, performing preinvestment and prefeasibility work, and providing institutional and policyadvice in selected developing countries. Through these efforts, ESMAP aims to assist governments,donors, and potential investors in identifying, funding, and implementing economically andeavironmentally sound energy strategies.

GOVER[VANCE AND OPERATIONS

ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives of theUNDP and World Bank, the governments and institutions providing financial support, andrepresentatives of the recipients of ESMAP's assistance. The ESMAP CG is chaired by the WorldBanks Vice President, Operations and Sector Policy, and advised by a Technical Advisory Group(TAG) of independent energy experts that reviews the Programme's strategic agenda, its workprogram, and other issues. The Manager of ESMAP, who reports to the World Bank's VicePresident, Operations and Sector Policy, administers the Programme. The Manager is assisted bya Secretariat, headed by an Executive Secretary, which supports the ESMAP CG and the TAG andis responsible for relations with the donors and for securing funding for the Programme's activities.The Manager directs ESMAP's two Divisions: The Strategy and Programs Division advises onselection of countries for assistance, carries out Energy Assessments, prepares relevant programs oftechnical assistance, and supports the Secretariat on funding issues. The Operations Division isresponsible for formulation of subsectoral strategies, preinvestment work, institutional studies,technical assistance, and training within the framework of ESMAP's country assistance programs.

FUNDING

ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nationsagencies, the European Community, Organization of American States (OAS), Latin AmericanEnergy Organization (OLADE), and countries including Australia, Belgium, Canada, Denmark,Germany, Filand, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway,Prtugat Sweden, Switzerland, the United Kingdom, and the United States.

FURTHER INFORMATION

For further information or copies of completed ESMAP reports, contact:

lTe Manager or The Executive SecretaryESMAP ESMAP Consultative GroupThe World Bank The World Bank1818 H Street N.W. 1818 H Street, N.W.Washington, D.C 20433 Washington, D.C. 20433USA USA

INDIA

WINDFAPM PRE-IVESwMENT STUDY

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Abbreviations and Acronyms

a.8 L above ground levelAPS Annual Power Surveybbl barrelCCP combined-ycle plantCEA Central Elericity AuthorityC02 carbon dicoddecr combustion turbineDNES Department of Non-Conventional Energ SourcesESMAP joint UNDP/World Bank Energy Sedor Management Aista ProamFIRR financial internal rate of returnFO furnace oilFOR forced outage rateFYP Five Year PlanGEDA Gujarat Energy Development AgenyGEB Gujarat Electricity BoardGEF Global Environmental FacilityGNP gross national productGOI Govenment of IndiaGWh gigawatt-hourha hectareHSD high speed dieselHT high tensionHz hertzIDA Indian Renewable Enera Development AgencykCal kilocaloriekg kilogmkV kilovoltkVa kilovolt-ampermkW kilowattkWh kilowatt-hourIi literLT low tensionmmtoe million tons of oil equialentMOR maintnanc outae ratem/s meters per secondMY megavoltMVa megavolt-amperesMW megawattMWh megawatt-hourNBPC National Hydroeectric Power CorporationNLC Neyveli Lignite CorporationNTPC National Thermal Power Corporation0CC overnight capital costPFC Power Finance CorporationPSC Power Survey CommitteeREB Regional Electricity BoardREC Rural Electrtion Corporation

RsW rupeesSCM sandard cubic meterSEB State Electicity BoardS04 Standard Offer No. 4S/S substationt metric tonTEDA Tamnl Nadu Energ Development AgenyTNEB Tarl Nadu Eleticity BoardTPS thermal power staionTWh terawatt-hourUNDP United Nations Development ProgramVOC variable operating costsWp peak watt

TABLE OF CONTENTS

EXEC=Rr SUMMARY ............ ........................ , Background and Objectives i ... . ..... *..*....... ... a.****... ISelection of Sites ................. .................. ....... 'iiEconomic and Environmental Evaluation of the Propective Investnent .......... iiIhe Case for Concessional Financing .................................... ivA Framework for Projed Implementation .......... iv

The Role of IREDA . ivThe Role of lTNEB/TBDA ..................... iThe Role of the Private Developer .................. vi

Sunmary of Key Reconunendadons .................. . vi

L DN1lRODUCIION ............................ 1The Power Setor in India .... . ..***. . . .......................... 1

Sectora Overview *...***.........**.*.. *...******..*.*.*****.. 1EIergy Resources ............................................. 2Sectoral Organization . . ..... .. ... .. ... ... . ... .. .. ... .. ... ... 2

Pr6ojc Badcound and Ojectives ...................................... 3The Methodology for P-e-Investment Evaluation ............................ 5

IL SITE SELE)cnON ................... ........ 8Overview of the Methodoloy .......................................... 8Pre-Seecton of Sites................ ... ... . .. .. . .. **s .. . * * 9Economic Screning of Pe-eected Sites ................................. 10

IIm E(CONOMIC EVAILUATION OF SEIECJ.ED SrES .......................... 15Ovaeview of the Methodology ......................................... 15Evaluation Results .......... * * *...................... ....... 15

Inights from the Califomia Expere e ................ ............ 17Sensitivty Anaiysis ................ 2....... ... *.. ... ..... 2

Constucion Lead rTnes .................................. 23The Total Value of Unserved EneV ......................... 24High Envirommental Costs, Better Wind Resources, andTurbine Cost Reductions: An Attractive Wind Scenario........... 24The Effects of Better Load Matching ......................... 25Windfrm and Iurbine Size ................................ 26

TheCostofC02 Abatemnent . ................................ 26

iv. -coNCLUSIONS .......... .. .. *. ........ 29Resuts of the Eonomic Evalution ..................................... 29Ihe Cas for C ncesdonal Fnancing ............................ 30A Framework for Project .neentaon .. 31

Pinciples of sect tDesp ........ 31Projtsm plemena io n .... .................................. 31The Role ofIRE A... ............ ............ ...... 31The Role of TN e 1)ev p .. . ........................... * . 32lhe Role of the Pfibte DbevekX.............. 32

Ove view, .................................... ....................... 1Ste Vk and Assessnent of Grid Connection . ....... . . . ... .. .. . .... 1Sii of W faiirnars ............................... 4...... 2

Ebstination of Windrnm Output ............ ................. 2Estimation of Enery Value of Output ................ ............. SEstimnation of Capacity Value of Output ..................... .0 . . . ... . 5Caoldation ofBenefit/CostRatio ... .............................. 5

ANNEX 2: DATA AND RESULIS OF THE SCREENING ANALYSIS .............. 1Ckmad AbSnptions .................................................. 1

Wind Turbine Cost Esdmates .................. ................. 1Cost Estimate for Electrical Works . ............................... 2Cost Esiimate for Civil Works ............................................ 4Cost Estimate for CRoventional Generation ............. . ........... . 4Experience with Existing Wind&rm in India . ....................... . S

Desaption and Assesment of TannE Nadu Sites ................ O..#**# ... 8Utilit Chaactristics ........................................... 8

GieneralDscription ......................... .... ............ 8Power Demand and Generation Needs ....... ........... 8Calculation of Levelized Costs of Coal TPS .................... 9lTpe and Value of Load Substituted ... ...................... . 10

Iayad Site laracteristics ..................................... 11Wnd Resources .................... *...... . ........... 11Land Avalaity, Soil Conditions, and Site Accessibiity .......... 13Grid System................................ ............ 13Windfi m Size Linitations .............. *.44444444 ......... 1SEnery Output ....... *..................... 15Production Costs and Production Value ......... ...................... 19

Akaapandiyapuram Site Caracterstics ........ .......................... 21MMn Rcssource .. ......................................... 21Land Avabbift, Soe Condition, Site Accessiblity .............. 21Grid ystem ............. .............................. 21W ndfam Size Limitations ................... *..... *........... 21Energy Outut, Producion Cost and Generation Value ........... 21

Tha1ay thu Site Characterstics .... * . .... ........................... 27"nd Resoures ................................ 27

Land Avalablity, Soil Conditions, Site Aocessblity .............. 27Gtid Ssen . .................. ....... #............ 27

nldfrm Size limitations .................444444.4.4 27Enersy Output Production Cot and Generation Value ........... 27

AyakdiSie Charactristbs ....................................... 27escrpton and Assesment of Sites in Gujarat ............................ * * . 32

UtllyCharactertics. . . ..... ............... *.. ........ 32GeneralDescription ..................... ............ ... 32Pbwer IDmand and Generation Needs ............................... . 32Calulation of Levelized Production Costs for a Coal TPS ......... 36lTpe and Vaue of Load Substituted .....4.4 .............. * 36lbe GridSystemin the SaushraAreaof Gujarat ......*4.4..4444 O' 37

laznba/Navdua Site .... ..... .*.*..... ... . .... .. . .. 41lind laEouit .................. . 41Lan d A v a 9 ; ibtS'o'fl'4non ....................... 41WbKlnda Sime lirlatls ....... 41EnrV Output .......................................... 43Production Cost and Pxoducio Value ....................... . 43

Mocha Site s ................................... .. 44

ANNEX 3: THE ECONOMIC EVALUATION MODELS .......................... 1Ihe WindfiunProducton Model ................. *I....... *.......... 1ihe Eonomic Anaysib Moded ................ ......................... 2

Appendix 1: Formuladon of the Wbdfamn Caat auipounitbIty Model ...... . 7Appendix 2: oknputatlnof Houly HydroCheneaton .. ... ................ 8

ANNEX 4: INPISMTO THE ECONOMIC EVALUATION ... ........ ........... 1Jntrhducion ...................................................... o . 1Load Foreca and ystem Expansion .......... a . d- . . .. . . ... . . . . . .1

Systm Load Cuves .......................... ...... o ... . .... ... 4ShortageCost Fstlnates ............................................. 4Conventional Powet Geneadon Tdchoies ............ o.. ... . ........ .. . 6MarWgi Cost of Geneadon lontna irStaios km Th.mal.P.wSto ............ ... . .. 8SANditbi5y:ALClysA ...... OF.C ..A.....Ao... ...C .. . . ... .............. oo. 8

AdNNEX 5: CALUDtLATION OF C02Q AVlBA UEM iTCOSI'S ........................ o. .......... I

EXECUTIVE SUMMARY

BWA-Unmd Bud Objeties

1. Because of continuing high growth In power denmai Pd the inabBity of genmr!apacity additions to keep pace, load shedding has becoma widespreA- in India. Coeturns aLoiu

the local and global enmental imacts of conventional generation tct-ol,ae -navecompounded the predica;ent of India's dronic generation defiit As pail od th, effort to rd'rcssthis situation, the Government of India (001) is exploring the prospeas for non<omsntionl.ienerg technologies to help close the chronic power defcit without the ervmonmental corwequW.Pnesof cnentional technologies.

2. Wind power is a commerialy mature renewable enera technology which could possiblhelp alleviate in numc -us locations throughout the world; total isaled windfm capacity exceeds1,800 MW, with over 1,400 MW in California alone. As a result of this exwIence, 001'sDepartment of Nonconventional Energy Sources (DNES) initiated the Wid Energy Program inthe 1980's to collect wind resource data, conduct research and development, and test anddemonstrate wind energ technology. DNES has subsequently supenised the installation of over32 MW of windfam capacity in India,

3. 'he initial eperpence with windfarms in India has been favorable; the technology hasperformed up to epations, and the lar-scale wind monitoring program established under thewind energy program continuer. to reveal prmising new sites. Despite the progress of the Windergy Progra, site specific pre-investment shtdies are now required if wind power in India is to

move beyond technology demontration to the widespread deployment of commercial-scalewindfarms. DNES requesed this tudy as the first of these pre-investment studies. The objectivesOf the study are:

(a) to identify promising sites for commercialscale, Le. 25 MW or grat, windfirmdevelopment;

(b) to conduct pre-investment evaluations of those sites which could lead to wndfrminvestment in India by the World Bank or other bilateral or multilateral institutionsif it is shown to be justifed, Le, to identify a ankable project padkage;

(c) to identify tp that would help impre indigenous Indian vapabllity for thedevelopment and deployment of wind electric technology as appropriate.

4. The stu begins with the selection of suitable windfam sites for detailed pre-ivestmentealuation Two ies are selected in the state of Tmil Nadu. The study quentl evaluatesdie economic competitdveness and environmental Inpacts of these potential windfarms rdative toconventional generation options I identifies the cnditions under whih the windfarm investmentappes attractive and proposes a framework for project implementaton. The methodology usedthrougbout is intended to be as general as possible to allow simlr evaluation of other sites in Indiaand elsewhere. Moreover, these findhin can help guide the selection of other potential sites inIndia and elucidate the factors which can make rindfirms a competitiv generation option. Fimally,the propoed project framework is put forwrd as a simple model for project development In Indiawhich can be replicated with other winfam or technoloies India.

5. As a precursor to this iudty, DNES com sioned studies in Andhra Pradesh, Oujarat,Karnatuks, and Tamil Nadu whkJah yie!dod a ist o. 28 potentia wiidfarm shit" Seven of these siteswere prlected on the basis of qualiiative critsa regarding the availability of wind rtource data,lane availability, site accessfbility. atd grid iiality. Based on field visits, preiminazy windfarmr4sbPs, and economic screening of thbee sewen sites, the Kayatlar and Tlayuthu bites ;n TamilNadu were idewified as the most proning of the group. Sites which were not selected ace notnecessarily u.swAt-tIe for windfarrn development. In many cases, sites wern dropped from,3mi&ratio bwcatuse their wind resacu' data, althoughb promsint& were of ufdtdurationto dI4w a th,rfj4Fgh wsessmeat4/

s;S > Ev&IaI: L.t1S3 Pro pective Invest

6. 'The Kayathar site, whih ibuts an exitinm winifrms totalling 735 MW, appears to havea potential of 50 MW, while the nearby Thalayutht site offers a potential of 25 MW. The economicevaluation compares this potential 75 MW windfam investment to three other conventionalgeneration options: a coal-fired thermal power station, combustion turbines, and a combined-ycleplant. The evaluation takes into account differences in construction lead times, enironmentaliwpacts, capacity responsibfilty and capacit value, the value and amount of unserved enerydisplaced by these various gneration options, and differences in windfarm size, turbine sze, andthe wind resoure itsef. The following conclusions emerged from the economic evaluation2/

(a) on the basis of standard economic criteria, these windfhrms are not economialyleast.ost when cumpared to conventional generation options, priargy due to the

/ EInformation on which to select sites for the udy was current through October 1991. Theuse of additional data and other stitutional and financial changes since that time(approximately one year) should be considered to verify and/or change specific sites beforetual windrm installation. For example, the economics of a site could be affected by an

additional one year of wind resource data or changes that may have occured in tariffs forconventional power. Other changes in the physical operating environment could affect thesuitablilty of a site, such as a reported power reduction of up to 40% in pat of Gujaratwhich is causing industries to use costly back-up diesel generators, recent improvements ingrid vstem condition, etc.

2/ A 10% discount rate was used to calculate the levelized benefit/cost ratio. Base case fixedenviromental costs for conventional thermal power generation sstems were 8.6% oxovernignt capital costs; variable eironmental c ranged from 4% to 7% of variabeoperatg costs. All oostswere economic rather than fin and the economic costswerestated as border prices, using the official echang rate at the time. Most local costs wereconveed to border prices by using a standard conversion factor of 0.8, but the economiccost of coal, which plays an important role in calulating the energ value of output, wasdetermined using a recent World Bank estimate. [Detai are presented in Ainexes 1through 5.]

medioL're wind resources at the sites considered and the poor match betweenwindfarm output and system load.

(b) 'Under baseline conditins, these sites were characterized by a capacity factor ofapproimately 18%.;/ Windfarms located elwhere have achieved capacityfactors of around 24%. Comparsible sites likely est in southern India. Not taidnginto account the benefits of better load matching, a windfarm at the Tamil Na'iiirites vwhich could deliver an araount of power commensurate with a capacity factorof 24% would be essentially economically viable (i.e., the benefits in terms of theenergy produced is greater than the cos0t incurred) tholzgh stffil not least cost.

(c) Load matching is a critical factor lor the economic viabiity of windfarms,particularly in systems with a high incidence of unserved demand such as in TamilNadu. Load matching can be measured by capacity responsi'bility.4/ Theconventional generation technologies considered here and some windfarms locatedelsewhere in the world offer capacity responsibility on the order of 60% to 80%. Incomparison, the windfurms installed at the Kayathar and Ibalayuthu sites in TamilNadu show a capacity responsibility of only 16%.

(d) Even with a capacity factor of around 18%, unserved energy costs of slightly morethan US$ 021/kWh result in clear economic viability for these windfarms. However,since such unserved eutergy Costs increase the value of conventional generation aswell, higher unserved energy costs do not make these widfams least-cost.

(e) In the sensitivity analyses made, only the case for a low capital cost for windfmsand the case for a high cost of unserved energy (Rs 3.23/kWhl,ie, about US$0213/kWh) resulted in a benefit/ccst ratio greater than 1.

7. In general, better sites and naw e -3chnology will make windfarms more attractive, evenif better load matching does not occur. However, it is clear that the sites proposed in this study

Z/ Capaci%y factor is the ratio of the power actually produced by a power plant during a specif ictime period to the amount of power that could have been produced in that same timeperiod had the power plant been operating at its u rated power.

4/ Cqpacy remsponbli is a measure of a technologs ability to reduce unserved energy, orconversely, to contribute to system capacity and thereby increase reliability.Computationally, it is the ratio of the reduedon in expected unserved energy given actnaloperation of the power unit to the reduction in expected unserved energ that would occurif the generation addition could operate throughout the period in question with a 100%capay factor. For dispatchable technologies, the capacity responsibility would be equalto the availability of the power unit, asuming that forced and planned outages oewrindependently of the incidence of unserved energy in that period. For non-dispatchabletechnologies such as wind power, capacity responsibility depends upon the match betweenwindfarm output and the temporal distribution of expected unserved energy.

IV

would not become competitive with conventional eneration without considering globalenvironmental costs. The study stmtes tbat these windfams could displace C02 for no more thanUS$45/ton, considered subsantialy less than Incremental investnents for deaning up C02emissions in equivalent fo2sil fuel power plants E/.

-Cfonr P'g

8. It iR on the basis of environmental benefits that concessional financing may be arged forwindfus in the immediate term In this context and party based on the findins of the presentstudy, the Government of India (GOI) approached the Global Environmental Facility (GEF) tofund windfam development in the country. Under the nonconventional energy component of theproposed India Renewable Resourcs Development Project, the GEF is providing a grant of US$13 milion towards a US$ 105 milion program to develop 70 MW of windfarm capacity in the fourstates of Andhra Pradesh, Gujarat, Karnataka, and Tamnl Nadu. Other international donors areexpected to contribute US$ 50 million and private investors an additional US$ 26 million. TheIndian Renewable EnerVg Development Agency (RDA) wil contribute US$ 16 milion frominital repayment of loans for windfarm development.

Ag Prsh dwlm nlkg

9. Investiations carried out in the present study provided some insights into optimalapproaches for implementing projects in this somewhat novel area The outlined windfarms projectshould be designed to (i) inirimize the financial burden on the Tamil Nadu Electricity Board(TNEB); (ii) create a framework for project development which can be replicated; (iii) providereturns on a windfarm investment that are constent with the economic value of the energproduced; and (iv) provide inoentives for private sector participation.

10. One possible arrangement for project implementation involves the partciation of threeentities: IREDA, as project financier, ThEB/Tamil Nadu Energ Development Agen (MEDA)as purchaser of power that complies wah esablshed operational and quality requements; and aprivate firm as project developer and operator.

11. De Role of DA The overnight capital cost of this 75 MW project would be aroundUS$ 90 million. IREDA would serve as the principal project financier by providing a loan to theprivate developer for 50% of the requred financing In addition, IREDA would administerconcessonal funds from the GEF to cover an additional 30% of project capital costs. In acordancewith the Indian Altemative Energy Project financin DA would use about US$ 16 mlion inproceeds from iitial repayment of loatB to replenish the credit line.

12. D TJ7B would puruhase power produced by the windfirms, andtogether with TEDA, would help identify pdrvate developers and ensre that their facilities and

E/ In the proposed India Renewable Resources Development Project, the windfirm componentwas estimated to yield a C02 abatement cost of US$30 per ton displaced.

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operation comply with TNEB's requirements. TNEB has issued a brochure entitled: CGuide for theEstablishment of Windfarms in Private Sector.' Among the provisions stipulated arn:

* TNEB will permit private parties to set up wind turbines in windy areas; these windturbines can be connected to the grid, ie., installed as windfbrms.

* TNEB is whAing to "wheel" the power to the location where the power is needed by theindustry. TNEB wil deduct 2% of the energ generated by the windfarm as a "wheelingcharge."

* TNEB wil purchase the surplus power produced by the private windfarms at Rs 1.0 perkWh.

c Interfacing of the windfam with the grid, indluding the cost of tran4ormers, protection,metering, HT lines from the point of generation to the grid's nearest line, etc. will becompleted at the windfarm developeres expense.

* Depending on the cartff-ity of the windfarm, necessary sub-station facilities wil be installedat the developees expense.

* Two separate meters, one for export of wind power to the grid and another for importationfrom the TNEB grid must be inutalled on the HT side at the developers expense.

* Technical requirements on the starting current of the wind turbines, provision ofcapacitors, automatic cut off from the grid, etc. are also defined.

TNEB would seek exressions of interest from private partes, and after identifying qualfied parties,would provide them with financial details and tedhnicl speations. Appimcation for IREDAfinancing would remain the responsibility of the private developer. TNEB/TIEDA would bersponsible for coordinating and reviewing all aspects of project implementation.

13. TNEB should pay no more than the economic value of wind power, which under baselineconditions is only Rs 1.07/kWh in constant 1990 terms. Currently, TNEB pays Rs 125/kWh forwind power, although this rate was established as a promotional measure. However, in keepingwiththe principle that the project should not financially burden TNEB, TNEBs' relatively low tarmffs limitthe power purchase price to below economic value. The study tentatively recommends a powerpurchase price on the order of Rs 0.90/kWh in constant 1990 termsfi/

£/ The study assumed that 16% of windfarm output allows additional TNEB sales to industrialcustomers at an average industial riff of Rs 1.05/kWh. The remaining 84% is valued atTNE'"s average tarff of Rs 0.87/kWh. A weighted average of the two rates results in apurchase price of about Rs 0.90/kWh. As stated in paragraph 12, the TNEB brochure thatpruvides a *Terms of Licensew for development of windfarms stipulates the purchase ofurplus power at Rs 1.0/kWh.

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14. Given eapected growth in TNEB load relative to increases in the availability of NationalThermal Power Corporation (NTPC) power, other sources of energ besides the NTPC must beengaged if TNEB is to avoid increased load shedding. The cost of energy from these additionalsources, such as these prospective windfarms, may indeed be more expensive than NTPC power(ie., Rs 0.90/kWh for windfarms versus Rs 0.60/kWh for NTPC power) but it is cheaper than thecost of unserved demand.

15. The Role of the Private Devloe. In this scenario, the private developer would carry a20% equity share in the project and would be responsible for the construction and operation of thewindfarm (the Indian Alternate Energy Project suggests about 25% as an equity share) . It wouldalso be responsible for application and repayment of the IREDA loan. A simplified cash flowanalsis reflecting base case conditions regarding windfarm generation, costs, etc., but which doesnot taking into account the tax effects of such a project, reveals a nomnal financial internal rateof return (FIRR) of 13.6% under these conditions. With higher inflation, the spread between theFIRR and inflation rate increases because debt is repaid with cheaper money while revenues remainconstant in real terms. If TNEB could pay the economic value of windpower, FIRR would increaseto 187% under base case conditions. Similarly, any increase in capacity factor would likewiseincrease FIRR. For example, even with a power purcha&e price of Rs 0.90/kWh and 10% inflation,a 24% capacity fctor would result in a FIRR of 19.5%.

16. It of course remains to b- seen whether private developers would be attracted by thesereturns. Several Indian firms have already formed joint ventures with foreign wind turbinemanufacturers and have participated in the construction of existing windfarms in India. Given theprospects for the identification of better sites, likely reductions in technology costs, and theopportunity to get in on the 'ground floor', these firms may find these returns adequate. One mustkeep in mind as weli that the base case for the wind resource is derived from only three years ofwind data. One of those years is acknowledged as period of 'wind drought'; indeed, averagewindspeed for Kayathar in 1988 was only 5.7 m/s. Although this highlights the risk associated withdepending on the wind for sustaining a cash flow, it also suggests that the base case assumptionsmay be quite conservative.

MM= of tKe Recommendations

17. There are three main findings in this report:

(a) The two potential windfarms sites that have been evaluated are not economicallyleast cot Further wind monitoring and site prospecting should be caried out toidentify sites where higher capacity factors and better load matching occur.Improvements and secally cost reductions in the techmology should also becontinually monitored.

(b) Given the present capital constraints on investments in the Indian power sector, anduntil better windfarm sites are identified, windfarms should most likely be accordeda low priority for immediate development in India.

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(c) Environmental considerations appear to provide the only argument for immediateinvestments in windfarms in the investigated sites and in the technology in generalin India. When global C0 2 reduction is an objective, windfarms could favorablycompare with alte- %ative projects on the basis of CO2 abatements costs. Alternativeenerg projects to -:onsider that have environmental objectives should include notonly supply side investments but demand side efficiency improvements, as welL

L INTRODUCrION 2/

lhe Power Sector in India 8/

Sectora vevd

1.1 Power generation capacity has risen dramatically in India over the last several decades,from 1,712 MW in 1950 to around 62,000 MW in 1990 - an annual growth rate of about 9.5percent and sigficntly higher than the GNP growth rate. Despite this steady increase in capacty,several factors including lenient electricity tariffs, population growth, agricultural expansion,industrial development, and more intensive use of electricity in all sectors have boosted demandbeyond installed capacity. At present, there is a 27% shortage in generating capacity. TheGovermnent of India (GOI) foresees a need for as much as an additional 80,000 MW of capacityby the year 2000.

12 Given the inability of electricity supply to keep pace with demand growth over the lasseveral years, loadahedIg has become commonplace in India. Over the 1980-1985 period, it isestimated that supp fell short of electricity requirements by 13 percent nationwide, with even moreacute shortages in indlized states such as Gujarat. More recently, nationwide shortagesequivalent to 20% of peak power demand and 10% of electric energy demand have emerged. In theindustrial sector, the Federation of Indian Chambers of Commerce and Industry estimated in 1988that a 10 percent power shortage results in a production loss of about Rs 70 billion (US$ 6 billion).Supply constraInts also induce consumers to install costly back-up generating capacity. Theeconomic costs of loadshedding and unreliable supply have been compounded by end-useinefficiency.

1.3 The GOrs power sector objectives through the year 2000 include meeting a higherproportion of demand and improving the quality of supply through system xpansion and moreeffient use of generating capacity. Key constraints to acbieving these aims are the dividedresponsibility between the center (federal level) and the states for power development, politicalinterference in the operations of the State Electicity Boards (SEBs) and the weak financialstructure of the sector.

1A Under the Seventh Plan, GOI has mounted initiatives to overcome these constraints. Thedevelopment of the relatively efficient central utilities, pardcularly the National Thermal PowerCorporation (NPM, has been accelerated. Efforts are being made to bring financial discipline tothe SEBs: the Power Finance corporation (PFC) was formed to mobhie additional resources forSEBs wSing to make needed Istutional reforms. GOI is reviewing its fuel supply policy for the

1/ This report was written by Michael Crosetti of ESMAP with contributions from thefollowing consultants: Andrzej Brones, M.K Deb, Salim Jabbour, Soren Arthur Jensen,Peter Johansen, K Raghavan, Mattheu Stenson, G0plk Tandan, and Kapil ThukraLProject activities were carried out under the coordination of Dr. J. Gururaja and Ajit K.Gupta of DNES, Dr. R. Rao of GEDA, and T.V. Venkataraman of TEDA.

l/ Much of the general discussion of the power sector is drawn from ¶ndia: MahashtBagasse Energy Efficiency Project", ESMAP, December, 1990.

- 2 -

sector; in addition to considering several fuel import options, it has sanctioned more domesticnatural gs for power generation. Finly, GOI is reviewing its policy on private sedor inolvementin power supply and aims to ease reguatoiy and financial impediments to private secorparticpation. he principal chalenge faing GOI under the Eighth Plan Is to ensure that theutilities' institutional development and efficienc improvements keep pace with their physicalexpansion.

BeD= Resoure

1.5 India's modern energy resources comprise coal, oil, gas, hydro electricity and nuclearenergy. In terms of generation mix, approximately 70% of capacity is coal-fired, 25% is hydroelectricand 5% is oil-fired, gas-fired, and nuclear. Coal reserves have been estimated at over 125 billiontones, of which 60 billion tones are considered economically recoverable. However, coal quali isgeneraly poor (with ash contents up to 50%) and is getting worse Recently GOI has bepg toconsider importing coaL Proven and probable oil and gas reserves are estimated at 580 mmtoe,sufficient for only 20 years pply at present consumption rates. With the recent completion oflarge gas pipelines, gas is now becming an important fuel for power generation. Overall, howeer,oil products continue to have limited use in thermal power generation, being confined primarily tostabilizng combustion in coal-fired stations and to fuelling captie gerating plants.

1.6 Idia's hydroelectic potential is equivalent to about 100,000 MW. The development status(as of June 1992) at a 60% load fctor is as follows:

Potential Assessed: 84,044.00 MegawattsPotential Developed: 12,142.38 MegawattsPotential Under Development: 5,669.38 Megawtts.

Due to inadequate financial resources m states with the greatest hydro potental, lengthy disputesover water rights and environmental issues, and limited techncal resources for the preparation ofWV lghydro projects, the pace of India's hydroelectric development has slowed over the past decade.Projects to develop mini-hydroelectric sites, particularly on irrigation canals, have recently beeninitiated.

1.7 Biomass nonetheless remains the predominant energ source in India, accounting for about41% of total enery supply 2/. Until now biomass has not been developed as a fuel for electricitygeneration, but biomass energy projects such as bagasse cogeneration have been recently introduced.Other renewable resources, such as wind and solar enery, are abundant but have not yet beenexploited. The Tata Energy Research Institute estimates that the potential exits for wind powerto reach 20,000 MW and photovoltaics to provide 1.75 TWh/yr within the next few decades.

Sectorad Or8hantion

1.8 Responsibility for electrict suppl I8 shared between 001 and the States 001 controls

2/ SEnerg in Developing Countries', U.S. Congress Office of Technolog Assessment, OTA-E-486, January, 1991.

. 3-

the Central Electricity Authority (CEA), NTPC, the National Hydroelectric Power Corporation(NHPC), the Rural Eleci cation Corporation (REC), and, through CEA, the Regional ElectricityBoards (REBs). The states control the SEBs and the dayto-day operatons of the REBs.Apprmately 75% of total supplies are provided by the SEBs and 20% by GOI-owned utilities,principally NTPC and NHPC Private utilities currently provide somewhat les than 5% of publicsuppy. Private captive generation, which has not been included in the above statistics, is equaltto 15% of public supplies.

1.5 CEA was created in 1950 to formulate national power policy and coordaWe utilities. CEAis part of the Department of Power, which is within the Ministy of Energy. NTPC, NBPC, andREC Are public corporations reporting to the Department of Power. NTPC and NBPC wereformed in 1975 to couct and operate large power stations and tan on facetis and to sellbulk power to the SEBs. REC was formed in 1969 to coordfiate rural electrfication and providefiancial and tedhnical pertise for SEB schemes REC finances more dtan 70% of runrelecticaton investments

1.6 SEBs were insdtuted under the Electi (Supply) Act of 1948 to promote powerdevelopment and to regulate private generation licensees. Although SEBs are supposed to beautonomous, in practice they are under the control of state governments in matters such as capitalinvestment, tariff, borrowings, and personnel poliies. As a first sep towards integrting powerspply nabnally, SEBs have been grouped in five regional stems, ea coordinated by an REB.Actvities coordinated regionall include state generation schedules and overhaul and maintenancePrograms, power tranders and concomitant tariffs

1.7 OI formed the Power Finance Corpoation (PFC) to moblize additional resources forsectoral development and to pursue institutional reform of sector entities, particulary the SEBsThe Corporation's lending operations are focused on completing prioity rehablitation anddistibution projects implemented by the SEBs

1.8 The Department of Non-conventional Energy Sources (DNES) was establed in 1982 andoperates under the Ministry of Energy. It conducts progams for the development of solar, biomass,wid, and other non-conventional energy sources. It is assisted on the state level by "nodal agenciessuch as the Tamil Nadu Enrergy Development Agenc (TEDA), which coordinate activities with thelocal SEE's and commercial interests. DNES also adminisr the Indian Renewale EnergyDevelopment Agency REDA), which was set up in 1987 to provide financing for the commercialdevelopment and deployment of non-conventional energy technologies

Poect Bwacoud and Obetives

1.9 In response to the pressing need for additional sources of affordable electricity generationand the continuing desire for sef-suiency in electricity supply, GOI has cmmitted substantialresources to develop both conventional and non-conventional energy sources As noted above,DNES implements progams to develop non-conventional energy sources, including wind power.Wind turbines are a mature power generation technology, approxmatel 1,800 MW of large groupsof grid-connected wind turbines, ie. windfarms, have been instlled to date worldwde, with over1,400 MW of windfim capacity in California alone. Turbines used in commerca id-connectedapplications are typicaly on the order of 100 kW to 300 kW each. Windarims, which are

-4

charactrzed by relatively short conrucon lead times and modular design, may have a role insatisfying India's unmet demand for electicity. Furthermore, windfarms in remote areas may helpreduce transmission losses in areas surrounding the windfarm site.

1.10 India appears to hold considerable potential for the development of windfarms. Estimatesby the GOI suggest a potential of as much as 20,000 MW 1Q/. A 1987 study by the World Bankand the United States Department of Energy indicates that Ind is among the most promisingcountries for wind power development 1/. Many sites have already been identified with meanannual wind speeds exceeding 6 m/s.

1.11 A recent study carried out by the joint UNDP/World Bank Energy Sector ManagementAsistance Program (ESMAP) 12/ confirms that windfarms may be a viable generation optionunder conditions expected in certain parts of India. ITe study recommends detailed, project-oriented pre-investment -tudies as well as additional efforts to resolve outstanding non-technicalisues which affect windfarm commercialiation. This study responds to those rewmmendations.

1.12 The Government of India has demonstrated a strong commitment to the development ofwind power. The DNES Wind Enerff Program includes wind resource data collection, engineeringresearch and development (particularly with respect to turbines), field testing, and demonstrationprojects, and is supported by an annual budget of apprmately US$4 million. Approxiately 32MW of windfarms had been installed in India by the end of 1990, esceeding the Seventh Five YearPlan goal of 25 MW. Ths installed capacity includes a 10 MW windfarm at Lamba in coastlGt4arat, a 5 MW windfarm at Muppandal in Tamil Nadu, and a 8 MW windfarm at Kayathar inTamil Nadu. Given the inidal success of the program, several hundred MW are anticipated duringthe Eighth Plan period.

1.13 Despite the progress of the Wind Energy Program, site specific pre-investment studies arenow required if the program is to move beyond technology demonstration to the widespreaddeployment of commerc-sa windfrms that may help reduce the chronic generation deficit ilIndia. DNES requested ESMAP to carry out the fit of these studies. The objectives of this studyare:

(a) to identify promising sites for commercial-scale, iLe. 25 MW or greater, windfarmdevelopment;

(b) to conduct pre-investment evaluations of those sites which could lead to windfarminvestment in India by the World Bank or other bilateral or multilateral institutionsif it is shown to be justified, ie., to identify a "bankable' project package;

IQ/ Department of Non-conventional Energy Sources Annual Report, 1988489.

11/ "Study of the Potential for Wind Tulrines in Developing Countries: Phase I Report, SolarEner Research Isitute, Report No. SERI/STR-217-3219, September, 1987.

2Z/ 'India: Opportunities for Commercialization of Non-Conventional Energy Systems', ESMAPActivity Completion Report No. 091/88, November, 1988.

(c) to identify steps that would help improve indigenous Indian capability for thedevelopment and deployment of wind electric technology as appropriate.

lhe Methodolo'p fo - - kyestment Evaluation

1.14 Ihe study comprises two parts, site selection and economic evaluation. The site selectionanablsis compares sites to identify the most promising ones; in the economic evaluation, selectedsites are economically compared to conventional generation options to determine whether windfarminvestments at those sites are jutified. An ESMAP site selection miion vited India in May,1989, and a economic evaluation mission followed in April, 1990. Site selection is described indetail in Section 2 of this report, and the economic evaluation is described in Section 3.

1.15 DNES provided ESMAP with a list of 28 potential windfarm sites located in the states ofTamil Nadu, Gujarat, Andhra Pradesh, and Karnataka. ESMAP pre-elected seven sites from thislist on the basis of wind energy resource data availability, land availability, site accessibility, andproximity and quality of the nearest grid. These sites were economically creened, and Kayatharand Thalayuthu in Tamil Nadu were selected as the most promising of the group. It was estimatedthat Kayathar could accommodate a 50 MW windfiam, whfle Thalayuthu could accommodate a 25MW windfarm. The benefits and cost of possible windfarms at these sites were then compared tothe benefits and cost of conventional generation technologies using a modified production costingapproach. Figure 1.1 provides an overview of the analys.

1.16 All analysis was conducted in economic, rather than financial, terms so that technologiescould be compared on the basis of their national economic impacts This is a critical first step indetermining whether these particular projects warrant further GOI suppor Windfarm andconirentional technologies alike were evaluated and compared on the basis of benefit-cost ratiosderived from the real levelized benefit, or value, of each kWh produced and the real levelizedproduction cost of each kWh. A distinction is made between whether a technolog is economicallyviable, ie. that its benefit-cost ratio is 1 or greater, or least cost, ie. that it has the highest beneit-cost ratio among all technologies.

1.17 To ensure that the analysis captured the unique characteristies of windfarms, theassessment eWplicitly took into account the following

(a) the fuel and capital costs, as well as annual energy production, of the twosystems, iLe. the windfarm and the conventional generation alternative;

(b) the capacity value or effective load carrying capability of the technologies;

(c) the value of unserved energy,

(d) the economic effects of differences in construction lead times;

(e) the additional transmission impacts and costs associated with each option;

(f) the economies of scale achieved with larger windfarm sizes;

- 6 *

(g) the environmental impacts of windfaums vis a vis conventional generationtechnologies;

(h) the size of individual wind turbines used, eg. 100 kW, 225 kW or 450 kW;and

(i) the wind resource, in terms of average hourly, daily, or seasonal windspeeds.

1.18 Although the World Bank has previously published guidelines for asessing wind powerpotential I2/, this is the first site-specific pre-investment study for windfarim conducted withpotential Bank lending in mind. Although this analysis has been carried out for two specific sitesin India, the methodology is suitable for the assessment of other sites and generation technologies.Through the use of sensitivity analysis, this report not only identifies the major parameters whichinfluence the economic attractiveness of windfarms regardless of their location, but also providesgeneral insights into the conditions under which windfarms may be promising investments elewhere.

W Ouidelmies for Assessing Wind Energy Potential', Energ Department Paper No. 34, lheWorld Bank, August, 1986.

- 7 -

Figure 1.1: Overview of Analysis

Identification of 28potental sites by DNES

.(Chpter 2)

Pre-selection of 7 sitesbased an qualitative

site parameters(Chapter 2)

Selection of Kayathar andThalayuthu sites based on

economuc comparison betweenall pre-selected sites

(Chapter 2)

Econosmic valuation ofKayathar and Thalayuthu sites

based on comparison to conventionalgeneration alternatives

(Chapter3)

-8-

II SITE SELECIrION

-Overview of theMehdlg

2.1 Paragraph 1.14 cited DNES estimates of enormous wind power potential In India. India,however, is a vast country with varied terrai and climate. Site selection is a crtical step inwindfarm development which, if the countlys entire potential is to be considered, requires animmense database of wind energy resources. DNES has prudently implemented and continues toexpand an extensive wind monitoring program which facilitated this analysis.

2.2 The selection of sites for firther detailed economic eraluation involves considerably more,however, than sinply selecting the sites with the highest windspeeds. In this evaluation, siteselection entailed the following steps:

(a) pre-selection of sites to be visited by the site selection mission; and

(b) economic and technical screening of the pre-selected sites to identify those suitablefor detailed pre-investment evaluation. Screening entailed the following steps:

(i) thorough discussions with relevant SEBs to determine technical andmanagerial concerns with respect to grid interconnection of windfams;

(ii) field studies of pre-selected sites, including evaluation of local gridsubsations;

(i) windfarm sizing and estiation of annual energy production at the pre-selec-ted sites, including seasonal and diumal variations;

(iv) assessment of the intallation cost for windfams at the pre-eected sites;

(v) caculation of the levelized generation cost for each windfarm;

(vi) estimation of the capacity and energy values of windfarm output at each site;and;

(vii) ranking of sites acording to their lielihood of providing cost-oompetitivepower.

23 Sites which were not pre-selected are not necessarily nsif y. In many cases, siteswere withdrawn due to sfficient wind resource data. Prelimimay data from some of these sitesappear quite promising, but were of infficient duration to facilitate economic evaluation.

-9

2.4 DNES commissioned site identification studies through the nodal agendes in the swates ofTamil Nadu, Gujarat, Karnatala, and Andhra Pradesh 1/. A total of 28 sites were identifiedand subsequently evaluated on the basis of wind enerV resources at the site, land avaiabflit, siteaccesbility and grid pimty and quality. Thre sites were conidered in Andhra Pradesh, 16 InGujarat, 2 in Karnatak, and 7 in Tamil Nadu. .ho caiteria for pre-selectlon are descrbed in Tabl2.1.

Iable 2.1: Criteria for Pre-Selection

Item Criteria

Wind Energy Resources Te criteria for wind energ resource Is fufillued if theenergy content of the wind at 30 m above ground level (agl)h more than 1500 kWh/m/yr.

Land Avaiabity The cteria for land avaibility is fulfMed if 25 MW or moreof wind turbine capacity can be instaled. It i asumed thatthe required area is 10 ha per MW instaled.

Accessibilit The criteria for accessibility to the sites is that onl limitedroad consuction work is rired

Grid sstem Te criter for the grid estem is that the disnce from thesite to an isting substation is less than 30 km.

Each she was graded on each of these criteria using the following system:

14/ ?refeasibilit Study and Site Selection of 50 MW imdfiuam in Gujarate, Gujarat EnerWDevelopment Agenqy, November, 1988M; 'o (enerate Electricity Using Wimd Turbines frmLow HIill L1i Anatapur Distict of Andhra PradeWsh, Non-conventional EnerVy DevelopmentCorporation of AP., November, 1988; 1Eotential for Pbwer Generation Using Windmills onSome of the Hills of Karataka", Karnat State Indusial nvestment and DeoelpmntCorporation Ltd, August, 1988; Feasibty Report for Two or lTree Wind ofCapates up to 50 MW in Tamil Nadu under the UNDP/Word Bank ESMAPProgramme", Tam Nadu Energ Development Agency.

- 10 *

+ criteria fulfilled based on given informationO cannot be evaluated due to insufficient data- criteria not fulfilled based on given information

Sites were subsequently classified according to the following ranking system:

QM ~~~~~~Criteria

A All four criteria in Table 2.1 are 0+0.

B At least one of the criteria in Table 2.1 is marked ¶',;the rest are marked "+".

C At least one of the criteria in Table 2.1 is marked '-;the rest are marked '+I or "0'.

2.5 Tne evaluation of each site is presented in Table 2.2. All sites clasified in class A werepreselected and visited by the site selection mision. Sites classified in class B may be consideredfor future large scale windfarm installations, but further wind resource data is required. Sitesdassified in dlass C cannot be recommended for large scale windfarm installations based on thegiven information. Only sites with sufficient data have been considered as cla A sites; withoutsuch data, the implementation of large commercial-scale windfarms based on insufficent data wouldbe emwes*e1y risky.

2.6 Based on the results of Table 22, seven sites were pre-selected. These are:

Gujarat: NavdaraLambaMocha

Tamil Nadu: KayatharAlagiapandiyapuramTalayuthuAyakudi

No sites in Andhra Pradesh and Karnataka have been pre-selected, primarily due to insufficientlong term wind data. However, these sites could be considered for future windfirm sitting.

Ec mic Sre-eninslected

2.7 A simple economic screening procedure was established to rank the sites relative to eachother and thereby identify the most promising ones. The highest ranked sites were subsequentlyevaluated in detal relaie to conventional generation technologies

2.8 It is inffcient to screen sites simply on the basi of generation production costs since thevalue of wndfrm output wil depend on utlit characterics, such as coincidence with peak loadsand the type of conventional fuel displaced. Therefore, the screening methodology comprise a

* 11 *

dmplified mament of both wndfam cos and benefits. Ithe cost sessment entails the szigand costing of each potental windfarm and the caclation of its leveized energy produtio costs.The benefi of each windfarm are sed in rdation to the conventional eneration they displace.The marginal centional generation unit Is Identified for each two hour period of a dayrepresenting each month of the year. During peak periods, the wlndfim benefit is esmated asthe levelized production cost, Including both capadty and energy comonents, of the marginaconventional unit. During non-peak periods, the benefit is limited to only the leveizd enerV cosof the marginal unit. Because the scrwening analys i intended only for comparison between stes,it uses wind data from only one year, and the benefits of shorter construction lead times are notconsidered. The screening methodoloV Is described in further dead In Annex 1, and the analysisis presented in Annex 2.

IklLZ2: Pre-selection Evaluation of 28 Proective Windfar Ses

-- o- -

f O -0 + 0 ao 0 + + 0 a

onsomw 0 -0 + 0 a

NM 0 + + 0 S_"o 0 + 0 0 o

isdo ~0 + + 0 _ o - + 0 0_tU.i o _ + o a

o _ + o e+ pt . + + + 0

Iled + _ F O e

+ + 0

+ + + + A_&MO + _ + 0 0

V_ + am + 0 0L_ + + 4 4 + A

apupo _ . ' + O O UI 0 O. 0 0 5

4. + + 4 A

,_au 0 O + 0 a

0 _ + O 03 ~~~~~0 0 4.

_ph + + + + A- - ~~+ + + + Aa llf ++ + I+ +

- 12-

2.9 Although Mocha in Gujarat was pre-selected, field visits revealed that the site was limitedto between 150 ha and 200 ha, which would adow a windfm of only 15 to 20 MW. Given that thisstudy sought potentia projecs of greater than 25 MW, Mocha was dropped from furtherconsideration. The sites at Lamba and Navdara were consolidated due to their proimity. Thelocation of these sites is indicated in Figure 2.1. The results of the screening analysi are presentedin Table 2.3. The low benefit,cost ratios camot be construed to mean that these windfarms are noteconomically viable since this screening anabsis is intended only to permit a comparison betweensites. It does not take into account factors which would increase windfarm benefits, such as the highcost of unserved enerW, short construction lead times, environmental considerations, etc.

Ial 23: Economic Screening Results

Benefit Assessment

Powr Soard Peak Unit Levelized Non-Peak LevellzedCosts Rs/kWh Unit Costs Ws/MdA

an coal Ps 1.19 Coal TPS 0.65Tun Cost TPS 1.28 Coal TPS 0.74

C^t Asesment and BenetlfUCost Ratfos

sfto state Size Windfarm Energy Ave- FAnofft/NU Production raged Bone- Cost

Cost Rs/kWh fit Rs/kUh Ratio

1. Kayethar Tamit Nadu S0.0 1.20 0.91 0.762. Thslayethu amil teadu 25.0 1.20 0.91 0.763. Alaspura Tamil tadu 63.0 1.24 0.91 0.734. Navdara Gujarat 59.4 1.44 0.86 0.60

Notes: GEB is Gujarat Electricity Board; TOED Is Tonil Madu Electricity loard;

TN is thermal power station.

Iaic Assationa Wfndfa Cosat Fred TP

Lifetih 20 years 20 yearsCapital Costs (Financial) TN: Rs 18,810/W (a) As 17.250/kW

0: Rs 20,520/kV (b)Capital Costs (Economie) TN: Rs 17.450/kV As 15.000/kU

0: Rs 19,000/kVQunual O Cnots 2X of capital costs2.5X of capftal costs

R As 70/k/yetrFual Costs (Financil*) Rs 700/tFetl Costs (Economic) TN: As 967/t Cc)

0: ns 838/t (c)Specific Fuel Consueption 0.65 kg/k1A generatedCapacity Factor as 23X 55X

TN: 24XDiscount Rats 10X 10Standard Coewersion 0.8 0.8fator (finencil-economic)

(a) Includes land andelectrical and civil works, estiated at Rs 3,500/W0 for Kayethar; atThalayuthu, thfs cost la estimated at Rs 3900/kV.

() Includes land and electrical and civil works, estnated at As 4,400/AV, end extra corrosionprotectfon, estimated at As 1,125/kW.

tc) Sesod on a cost of Rs 193/t o Rs 0.43/t-kmi Gujarat transport distanc:s 1500 km, Tait Nadu1im bD.

13 -

EM uro k1 0sting Windm in India and Sites Selected for Economic S:reenig

Pa Sa

5N ~~~~~~~~~~~h

Deogsarb o;7 Hy_ _gs xitn in ubn

/ 4wNe D£;K Nepal W /-e Cmercal

Okh~~~~~~~~~~~~~3AagffyapendhilyO hpa uram

~~~~~~~~~~~~4 Talaythf ur\

U ̂4'^ S aytha Farms

TrivoWind f arms

* 14 *

2.10 Tho anaWs suggesto Kayatar and Tnalayuthu in Tamfl Nadu as the two most promisingsie Alaglyapandlypuram Is slightl less attractive due to a somewhat higher line losses. Theanual wlndfm output, includig line losses, at the Tami Nadu sites is 4% to 9% hiher than atthe Navdar/Lamba site. Capital costs at the Navdara/Lambda site are higher due to extracorrosion protedon of the trbines and higher costs for eleticl and civil works, particulary theuWade of the grid nterconnctio substation. As a result of these differences, the generation costper kWh is estimated to be 15% to 18% iger In Gujarat than at the Taml Nadu sites.Furthermore, marginal convendonal generation costs are slightly lower in Gujarat Both lower costsand higher benefts of Kayathar and Thalayuthu dtes give them the edge on the other sitesconddered

- 15 -

III ECONOMIC EVALUATION OF SELECED SITES

. Oxedm f th etBhodoloy

3.1 In the preceding section, Kayathar and Thalayuthu were ranked as the most promising sitesrelative to all others identified by DNES. The windfarm investment decision rests on whether thesewindfarms would be more attractive than investment in conventional generation capacity. In thissection, windfrms at Kayathar and Thalayuthu are economically compared to other conventionalgeneration options, ie. combustion turbines, combined cycle plants and coal-fired thermal powerstations. Constuction of windarms at the two sites Is considered a single project; therefore, thetwo windfarms are evaluated jointly.

32 Three models were developed for this economic evaluation following work previousycarried out in the United States II/. They are:

(a) The windfirm production modeL which estimates monthly production froma windfarm;

(b) The windfam capacity responsibility model, which estimates the effectivecapacity of a windfrm given the wind resource and system load and dispatchconditions; and

(c) Tne economic anabsis modeL which evaluates the relative economics of awindfam vis-a-vis other generating technologies. This model calculateslevelized production cos and levelized benefits (in terms of displacedgeneration and unserved energy costs), and derives a benefit/cost ratio asthe figure of merit.

Fiure 3.1 presents the analsis flowchart and ilustrates the relationships between the three models.These models are descrilbed in Annex 3.

E§valuation Results

Ihe Base Qe

3.3 The base case analysis reflects conditions likely to prevail: technology performance and costare based on actual emperience, utlity parameters, such as growth in load and installed capacity, arebased on projections provided by Tamil Nadu Electric Board (TNEB), and wind resources areevauated at the average of site wind logger data over the period September, 1986, throughDecember, 1989. Most of this information is more detailed than that used in the screening analysisBase cas assumptions and baound information are given in detail in Annex 4.

jW VanKuiken, J.C. et al., 'Reliability, Energy and Cost Effects of Wind-Powered GenerationIntegrated with a Conventional Generating System", Repo. , ANL/AA-17, Argonne NationalLaboratory, January, 1980.

- 16 -

E1g13JI: Oveview of the Economic Evaluation Methodology

Analysis Flowchart

lWlrdOaa WietnProducoMo aa

Load Daba -WhmC

-tEmmda of _

BC Ratis i Tehnolos

3.4 It would have been preferable to inhlude several more year of wind resource data in theevaluation. Howeer, wiind logs were not intalled at these sites until September, 1986, forKytharsnd Aqpst4 1988, for alayuthu. Wimd data for Thalayuthu was ted back toSeptember, 1986, by scaling the Kaathar data for the September, 1986 to August, 1988, period bythe ratio of Thalayuthu to Kathar windpeds over the perid that Thalayuthu wid data wasavlable. Efforts were made to exrapolate both Kayahr and Thalayuthu data over several yeasprior to 1986 by scaling wind data from the met logical station at Tutcorin Harbor. Howeer,it appears that the Thicorin anemometer has not provided consistent readingp over this period,pehaps due to equment changes, deterioratlon, or fallures.

3.5 Table 3.1 presents the base case results. Under these conditions, the windfm appear tobe neither econa least cost nor viale; the conventional technologies ar far more attaivCal-flred thembal ranks as the most cost effective technology.

Table 31: Base Case Results

Iletizd Lent f Denfit toEnergy Sanefit Energy Cost Cost Ratio(1990 I) (1990 eWM)

Vn IV 1.07 1.4 0.7Cordutlon TurbifwW 1.43 1.02 1.4Combined Cysle Turb. W 1.41 0.09 1.6Cosal-fired lbelt W 1.36 0.69 2.0

f Assc a caf ity factor of 17.= bas an the results of the uiendfar prodction model.MAsum a capacity factor of MO.

* 17 *

3.6 Because TNB's capacity shortage is like to persist well into the future, generationbenefits are driven by the cost of unserved energy. In this analysis, unserved energy is characterizedas the most costly "energy". For dispatchable generation technologies, the lower the capacity factor,the greater the percentage of total annual generation which is used to meet demand which wouldotherwise be unserved, since it is assumed that generation is first dispatched in periods with thehighest energy cost. The benefits of wind power, however, depend on the match between the windresource and the temporal distrbution of unserved energy. As the low value of windfarm benefitssuggests, conventional generation options are far more effective on a per kWh basis at meetingdemand that would be otherwise unserved. Large amounts of windpower are generated duringperiods where additional capacity is unnecessary, so that the value of the windpower is reduced tothe variable (energy only) cost of the marginal unit whkh is displaced

3.7 TNEB typically will reduce system frequency, sometimes to under 48.5 Hz, to minimizeloadshedding. Throughout this analysis, it is assmed that the amount of unserved energy in anyperiod is proportional to tl , difference between actual load and frequency corrected load. AsFigure 32 indicates, windfarm output is greatest in the months where this difference is least;omnsequently, relative to conventional generation options, the windfarms are not able to displaceas much unserved energy on a seasonal basis, hence windfarm benefits are relatively lower. Figure3.3 suggests that the windfims are also relatively ineffective in relieving system shortfills on adurnal basi On an annual basi the windfarms considered here increase effective system capacityby only about 16% of their nominal capacity, far less than the 60% to 80% effective capacity valuexpeted with conventional generation.

3.8 Because of the poor ability of these windfrms to reduce TNEB's unserved demand relativeto conventional generation options, the benefit/cost ratio for these windfarms is significantly lowerthan for the conventional options Whie windpower is not a bargain at Rs 1.44/kWh (US$0.085/kWh at the thne of this analysi), it is not terribly expensive. This production cost iscomparable to windfrm costs in California for sites with simiar capacity factors. A look atwindfam experience in California hilights the shortomings of these prospective IndianwindfarmL

Jl"sht from the California Xerienc

3.9 Windfrm development in California has been successful for the following reasons:

(a) In the early 1980's windfams received sutantial tax benefits which stimulatedcr,nstruction.

(b) any windfarms are able to sell power to the lol utflit under a contract knownLS a Standard Offer No. 4 (S04), whih tied the power purchase pe to the utfflity'slong-run marginal cost as it was estimated in the early 1980Ws, when fuel costs wereexpected to remain relatively high. SG4 contracts now pay about US$0.07S/kWh,which is about 2.5 times more than current avoided costs.

a m~~~~~~~~~~~~~~Monthly System Load and Windfarm Output [July 1989 - June 1990Wndarm Output, MWh System Load, GWh35, - - -

~~~~~~~~~~~~~~~- 2,500g30,000

30,00: \ _ - ~~~~~~~~~~~~~~~~2,000825,000

20A00 -,w

16.000 1,000

101,000

0 ~~~~~~~~~~~~~~~~~00

Jan Feb Mar Apr May Jun Jtd Aug Sep Oct Nov Dec

- Wlndfaim Ouf - Conected Load

B- U -- Load

System Load and Windfarm OutputTNEB System, Base Case Wind Resources

Jty 189 *Aug 1989_m Output fts%m LOW toA )asiono OftW tA1_Low_ O

4 oo " .. . *141S.... 0o soo _ o

ilm ~ ~ ~ ~

o 2 4 0 S 10 U 0 18 20 2o 0 t 4 X so06 a is *So iNM owf ONDa tHi ofVW Da*>Whibm~pW _ssb _ wad -~mdd Bad &wbusS swsrd Lad -0aW- Lad

8 vplt11@, 89 O¢b*W 1989 t~~0 mm &pftm Lo0SYod 0* 8p _ LowOA"

b - _~~.4 -no_e _ _ i Zllel0.@

System Load and Windfarm OutputTNEB System, Base Case Wind Resources

November 1989 Deceme 1989

u ~SWI ~OSuSew* L Sd _ hI_ Ou " bu &m 4 LOW SW

t ' S ~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~P

If.~~~~~~~~~~~~~~~~a

0 8 4 Januar 199U0 2t Feabruary 1990s o

.~~~: _ __ _ t l _ __ _ __ _. _ _ __ _

Hos Of Om Hour of Day

-- Wbpt_i h -0-o1m u 1 Ld -O-tsdbmo op 8 L oo

&9 1s0@ eo . two~~~FWxmy 99

"at i w H ofneeWlbOe __Dz 9| tei0b

System Load and Windfarm OutputTNEB System, Base Case Wind Resources

Mvch 1990 *r 1990

How of Day mad.t D ay of a"

May 1990 Jura 1990

~~~~~~~~~~0 1 0 S SII1 I S 0*

Z~~ W sow Lo LOW

so is" o*_

a * 9. sa le u 14 Iso n tt 0 * leI s St

How of Day How of DayVm0-vnnwwnowm -ooq,,wdt -_o oh_m_ i

- 22 -

(c) Ihere is a far better match between system load and the wind resource at manywindfarms in California, which increases the economic benefit of windpower. Somewindfarms offer effective capacities equivalent to 75% to 80% of nominal ratingThese vindfarms carry a sgnificant proportion of system peak loads If/.

(d) Many California windfams offer relatively high capacity factors, which reduceproduction costs. Although the statewide average capacity factor is around 18%,which is comparable to the Indian windfrms considered here, the average forwindfrms Installed during the past three years (since tax credits expired) is around24%. This can result in as much as a 25% decrease in energy production costs.California capact factors are higher than for the windfarms considered hereprimarily due to a better wind resource. Annual average windspeeds at Californiawindfarms are on the order of 6.5 m/s to 8 m/s, compared to approximately 6 m/sunder baseline conditions for the sites considered here tZ/. Given that enerDin the wind is proportional to the cube of the windspeed, small differences inwindspeed can result in large differences in energy.

(e) There is evidence that the inter-annual variation in windspeed is less at Californiasites than at the sites considered here, which makes the sites considered here morerisky. Data for 1987 suggest that average annual wind energy was 42% greater forKayathar and 66% greater for lhalayuthu than in 1988. Taking data for AltamountPass, Califomia, over the period 1985 to 1988, the highest wind energy year offeredabout 24% more energy than the lowest year. Interannual risk is not explicitly takeninto account in this evaluation; sensitvity analysis is instead used to determine theeffects of changes in wind resources on economic viability.

3.10 Although items (a) and (b) above do not directly affect windfarm economics, they helpaccount for the aarent success of California windfarms. Items (c), (d) and (e); however, explainwhy windfiam development at the sites selected here may not be as promising as experience inCalfonia may suggest

3.11 Sensitivy analsis was carried out to help identify the fictors which affect windfrmviabWii and to determine the conditions under which windfarms would be competitive withconventionl generation in India. Each case is discussed in Annex 4.

3.12 The results of the sensitivity analysis are shown in Table 3.2. The benefit/cost ratios for

J/ D. Smith and M. Ilyin, VWind Enery Evaluation by PO&E", Pacific Gas & BlectrcResearch and Development.

17/ Smith and fyin, op. cit., point out that average, annual wind speed may not be sufficient toestimate the energy in the wind. They relate the report of a windfim operator that a sitewith a mean annual windspeed of 7.1 m/s had more energy than a site with a meanwindspeed of 8 m/s due to differences in air density and the shape of the windspeeddbbuttion.

-23-

the windfarms reman below 1 accept in the cases of low windfarm capital costs and high uervedenergy coSt, and conventional generation costs remain above I in all cases Tbis analysis suggeststhat the base case results are robut, and that on basis of standard economic analysis alone, theproposed windfams at lbalayuthu and Kayadtr are not competitive with conventional generationoptions.

Table 32: Sensitivity Analysi Results

Case CT CC Coal lrndenfflt/Cost Ratio

EBae 1.40 1.59 1.98 0.74High capital cost for conewntional tecologies 1.37 1.48 1.83 0.77Low capital cost for windfarm 1.40 1.59 1.96 1.00Long lead tioms for all technolo81es 1.51 1.71 2.31 0.79Short lead ties for all technologies 1.29 1.47 1.71 o.7High escalation of variable tosts of cowv. technologies 1.38 1.62 1.97 0.8?tow escalatton of variable costs of cow. technologfes 1.41 1.57 1.97 0.70High local awirow ental costs of conv. technologies 1.33 1.48 1.82 0.74High lobal environmental costs of coa. technologes 1.00 1.41 1.34 0.78No envirornental costs of cow. technologies 1.48 1.70 2.16 0.74High t&D losses 1.33 1.50 1.87 0.72Low T&D loses 1.48 1.67 2.09 0.77High cost of umserved energy 2.85 3.23 4.12 1.25Low cost of unserved energy 1.24 1.40 1.74 0.69nigh load growth 1.44 1.63 2.03 0.92Low load growth 1.01 1.14 1.39 0.61High capacity accessed by TNEB 1.03 1.17 1.43 0.61Low capacity ae_ ssd by WNE 1.42 1.61 2.00 0.87Low discount rate 1.38 1.40 1.95 0.81High wind 1.40 1.59 1.98 0.97Low wind 1.40 1.59 1.98 0.64High avaflability of grid and wind turbines 1.40 1.59 1.98 0.79Low availability of grid end wind turbines 1.40 1.59 1.98 0.67Large wind turbines (450 kMI 1.40 1.59 1.98 0.67Small wind turbines (100 kW) 1.40 1.59 1.98 0.61ball farm (225 kV turbfneri) 1.40 1.9 1.98 0.75

Note: B/C ratios of CT, CC, end Cosl are at 60X apacity factor.

3.13 aonstrction lead sim Proponents of wind technology have often cited the relativelyshort constuction lead tines for windfams as a sigicant advantage of the technology. Thi ispartcularly relevarnt in capacity-constrained sytems such as TNEB, since generation capacity whichcan be added quidky will displace costly unserved energy sooner than generation technologies withlonger lead times Often this argument overlooks the scale of deployment and generationcharacteristics of the technologies being compared. With rgard to generation characteristc, forexample, a 100 MW windfirm is not equivalent to a 100 MW combustion turbine, neither in termsof capacity factor nor in terms of effective load carrying capability. With respect to the scale ofdeployment, it is certainly true that some windfarm capacity can be installed more rapidly than afulsied conventional plast, but it is arguable whether a windfarm with equgiaet gbnmi

cm nicte4ieicsas a full-sized conventional plant can be instaled any sooner.

3.14 Tbis analyis sidestep the isue of scale by consWering the costs and benefits of the varioustechnologies on a per unit energy bas Generation c a are, however, addessed directlysince ener production is valued taking into account the cost of the energy (or as the case may be

-24-

in certain periods, unseved energy) displaced. Tis entails, in effect, an evaluation of thetechnologs contribution to the ability of the system to meet load.

3.15 The base case analysis indicated that even on a per unit energy basi the load carrigcapabiity of the windfiars under consideration is not adequate to make them competitive withconventional generation options. Even though the longer lead time of the conventional generationtechnology allows a greater incidence of unserved energy to occur in the near term, its ability toserve demand which would otherwise been unmet later is so superior to the windfarms that itremains economicaly more attractive.

3.16 Rather surprisingly perhaps, the sensitivity analysis suggests that the longer the constructionlead time, the higher the benefit-cost ratio. his may lead one to suspect that the treatment of leadtimes in the analysis is flawed. In fict, this is a consequence of discounting future expenses.Because capital costs are phased over the construction period and not paid immediately, the longerthe construction period the lower the present value of capital costs. Similarly, since energy isproduced later, its value is discounted as well, which decreases benefits. Longer construction leadtimes increase benefit-cost ratios because the present value of costs fails faster than the presentvalue of benefits. The condusion which should be drawn is not that one should put off power plantconstruction for as long as possible, but rather that doing so does not make windfarms any moreattractive relative to conventional plants.

3.17 The Total Value of Unserved Ey. Constuction lead time differenca betweentechnologies are relevant to the economic evaluation in that they can help determine when unservedenergy is reduced. Another consideration, of course, is how much unserved energy is reduced. Onone hand, the coincidence of plant output with periods of otherwise unmet demand increasa thevalue of that plant. As noted above, the windfarms under consideration are not very effective onthis count. On the other hand, any factor which increases the total cost of unserved energy, suchas a higher estimate of the unit cost of unserved energy, lower estimates of the growth of lNEB'saccess to electrity imports, or higher estiates of TNEB load growth, will increase the total valueof demand that would otherwie be unmet if additional generation were not avaiable.

3.18 All of these factors increase the attractiveness of windfarms. A higher estimate of the unitcost of unserved energy even yields an attactive benefit-cost ratio for the windfarms -althoughthe benefit-cost ratios of conventional technologies likewise increase under these conditions. Ihehigh case for unserved energy costs, Le. Rs 3.23/kWh or US$ 0213/kWh at the xhange rate usedat the time the analyi was done, i arguably a better estimate of average outage cost than thebase case of Rs 1.44/kWh. The high case is derived from low utEization (500 hrs/yr) of captivegeneration, whereas the base case represents higher utWNzation of 2000 hrs/yr, which perhaps bestserves as a lower bound on outage costs With the as on of igher unserved energy costs, thewindfarms become economically viable but not least-cost Other factor, such as environmentalconcerns, may motivate the support of economiay viable technologies which are not least cost

3.19 High Environmental Cos. Better Wid Resources. and Turbine Cost Reductions: AnMimctiy.t.WindiScndg. A more rigorous treatment of the envronmental dimension of thisinvestment decision entails the qutification of envionmental coss Te base case added costof abatement of local environmental impacts, such as recamation of strip mines and dust control,

-25 -

derived from a detailed study carried out in India 11/. The 'no cost case omitted these costs,while the high global cost case included estmates of gobal environmental costs, indluding estimatedhIpacts of gsobal warming, for these technologies, as estimated in the United States 12/.

3.20 Thi cvaluation of global envonmental costs reduces the benefit-cost ratios ofconvendonaltechnologies to the range of 1.0 to 1.4. Ite windfarm benefit-cost ratio Inproves moderately,approaching 0.8 as a result of diplacing generation made more epensive by the inclusion ofemvironmental costs. Even with the inclusion of these environmental costs, windpower still does notemerge as the least-cost technology.

3.21 However, when environmental costs are considered along with the prospects for furthercost reductions in the technology, these windfm appear far more attractive. The low windfrmcapital cost case reflects a 25% reduction in windfarm capital costs, which is a reasonableepecation of near term cost reductions in turbine technology 22/. At the base case capacityfictor of 17.8%, this results in a windfarm benefit-cost ratio of 1.0. With a better wind resource andcurrent technology (comparable to the most recent California isallations), capacity factors couldreach 24%, which together with the windfm capital cost reduction and evaluation of globalenviromnental costs would result in a benefit-cost ratio of just over 12. Ihis compares quitefavorably to the benefit-cost ratios of the comentional technologies under the same conditions,which are in the range of 1.0 to 1.4. Under these conditions, windfarm levelzed production costswould approach Rs 0.88/kWh (US$ 0.058/kWh).

3.22 The Effct of Better Lod Load matching can be measured by capacityresonsibility, which is defined in Annex 3. The capacity responsibility of these windfrms is onlyabout 16%, far less than the 70% to 80% found with the best California windf l4 and the 60%to 80% found with the conventional technologies considered here. Better load matching would

improve further the economic competitiveness of the Kayathar and Thalayuthu wind&armAlthough some increase in windfarm benefit-cost ratios would accrue through a higher wndfarmcapacity alue, the main benefit in a system characterized by a high incideice of unserved energysuch as TNEB would be a futher reduction in costly unserved energy, which is reflected as energyvalue. Even if the windfarm capacity factor remained the same, better load matching would meanthat a higher proportion of windfrm generation would displace unserved energy, thus significantly

ceasing the value of windfarm output Coversely, while total windfarm output and capacityfactor wil change from year to year depending on wind resources, capacity responsiblity wil likelyvary much less, since it is to a large axent a function of the shape and temporal coincidence of dailyand seasonal load and wlndfarm ouput curves. Although the scale of wind resource curves wilchange between years eperience elsewbhere indicates their shape will vary far less.

If/ 'A Study on Cost of Electricity Generadon and Environmental Aspects', Metaplanners andManagement Consultants, Patna, submitted to DNES, September, 1989.

12/ 'vironmental Costs of Electricity', Pace University Center for Environmental LeglStudies, for the New York State EnerD Resarch and Development Authorty and theUnited States Dept of Energy, Septembe, 1990.

2Q/ 'Status and Potential of Wind Energy Technology', R. Lynette & Assoc, Redmond,WashIngton, 1990.

- 26 -

3.23 Sensitivity analysis of load matching would require formulation of new temporal profilesof windfirm output Because of the complexity of doing so, and because the results would be velysite specific and therefore could not be generalized, sensitivity analysis of load matching was notcarried out. It nonetheless remains a critical factor in the economic evaluation of a windfarm.

3.24 Energy storage could improve windfarm load matching. However, studies carried out inthe United States have indicated that the additional capital costs of storage technologies, even suchas pumped storage, makes such schemes economically infeasible.

325 Windfarm and Turbine Size. Because windfrms consist of modular units of a singledesign, it is often thought that windpower technology offers significant economies of scale.Certainly this may be true for wind turbine manufacturing but not for turbine deployment. Tbisanalysis suggests that larger windfarms are no more attractive than smaller ones. Althoughconstruction mobilization costs may fall on a per unit basis for a larger windfirm, (i) total costs forturbines and civil works remain proportional to windfarm size; (ii) larger windfarms may requireproportionally higher electrical interconnection costs because of the need for more costy highvoltage step-up facilities; and (iii) array efficiency may decrease with windfarm size. On the otherhand, economic viability is somewhat more sensitive to turbine size. At the current time, mid-sizedturbines of around 225 kW each appear to be the most economically attractive, although future costreductions in larger turbines due to increased manuri output and falling unit costs ofmanufacturing could change this.

The Cost of CO% Abatement

3.26 The assessment of global environmental costs, resulting from phenomena such as globalwarming, is subject to considerable debate. Not only are the economic impacts of globalenvironmental phenomena difficult to quantify, the very nature and scope of these phenomena arepoorly understood. An alternative means of quantifying environmental value is to consider the costof abatement. Given that the major global enviromental concern associated with power generationis production of 'greenhouse gases", most notably CO 2 as a by-product of fossil fuel combustion, thecost of C0 2 abatement using windfarms is calculated below.

3.27 Abatement costs are determined here by subtracing the levelized production cost ofconventional generation, in this case a coal-fired thermal power station, from the levelizedproduction cost of windpower generation, and dividing this result by the amount of CO2 producedby the comventional plant per kWh. hi, in effect, gives the cost of displacing a kg of CO2 usingwind technology. The conventional plant is taken to be a coal-fired thermal power station because(i) it is the least-cost generation source, as suggested in the analysi above, and (ii) it is thedominant type of fossfl fuel generation in the TNEB system Given the poor coincidence ofwmndfarm output with periods of peak load, wind power would displace mostly coal-fired generationrather than captive generation. Annex 5 discuses the details of calculating levelized C02abatement costs.

3.28 Table 3.3 beJow illustrates C02 abatement costs under different conditions. The first caseaumes that windpower displaces only coal generation. Two azamples of coal generation areconsidered, representing a new, more efficient coal plant and an older, less efficient plant.Production costs for the new plant include both capital and operating costs, since the plant has not

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yet been built. The older plant on the other hand, is characterized only by its operating costs, sincethe capital cost is a sunk cost In the second case, it is assumed that 16% of windfarm generatondislaces captve generation evaluated at the base case cost of unserved ener; the remaining 84%of windfarm output displaces coal generation. The proportion of coal and captive powerdisplacement is consistent with te capacity responsibility of the windfarm under base caseconditions. The third case is like the second case except that captive power costs are evaluated atthe high cost of unserved energ.

3.29 Base case windfarm cost and performance result in C02 abatement costs ranging betweenUS$28/t of C02 and US$45/t of C02, depending on assunptions about the cost of energy displacedand specific C02 producton asomciated with that energy. Given a better wind resource and anreduced capital costs for the windfams, abatement costs range from negative (indicating that underthose conditions windfams are economically competitive even without considering C02 abatement)to US$11/t of C02.

Table 33: C02 Abatement Costs for Windfams(US$/ton of C02)

Ca"eI Coo 2 Caw 3De Case Ennore Base Case Enoroae Casefnnore

kg of Co 1.10/ 1.2nW 1.03W,/ 1.55 1.03WJ 1.55 gpr,oduced per klh

Levelized production 0.69 ,/ 0.64 V 0.81 a/ 0.77? / 1.10 1/ 1.06 1/cost (1990 Is/kih)

B case 45 30 40 28 22 16vi ndfam >I

Paverable 11 9 4 5 (14) (7)Windfarm I/

a Assumes 0.6 kg of col per kWh and SOX carbon content.W 1Assues 0.94 kg of coal per kIh (1989 actual cosAption for Rmoe) and 50Z carbon content.L' WAssume 84X of enrgy displaced f8 as In IV above an 16X is produced by captfve generation

characterized by 0.25 li/kldiesel d tcons ion and 90X carbon content.AssUmes 84S of erg dfsplaced Is as In above a 162 is produd by captive gnwationcharacterized by 0.25 ti/kl dieal consuiption end 902 carbon content.

I, Bas case result for coal PS; includes capital and operating costs.I/ Actual verialte operating coset for Ermore coal TPS based on 1989 data.a, Assum 84X of enrgy displaced is as fn a, aboe and 162 coma from captive nration at the bae

csme unved energy cost of ts 1.44tkh.J/ Assums 84X of nerg displaced is as in V/ above and 16X es from captive gnration at the ba

case unsrved eergy cost of Rg 1.4/IkAh.1/ As in a,. but winf a captive eerastin cost of ts 3.23/klth consistent with the higbh unrv enersg

cost case.I/ As in b/, but wfth en captive geration cost of Re 3.23/kA, onistent with the bigh wasrved erg

cost cas.Assune base case windfarm energy production costs.Assum 24X windfarm capectty factor and 25X reduction in overnight capitel costs.

330 The 002 abatement costs associated with windfarms are itended to be compared with theabatement costs of other options. Some projects, such as generation efficiency projects or thoe

-28-

which divert nawal gas from flaring to productive uses, ma; offer abatement cost on the orderof a few US cents per t of C00 Other renewable generation technologies, such as phot ,are cbaracterized by abatement costs in aexss of USS 200/t of CO, 21/. A wmprso ofwindfarm C02 abatement costs to the abatement costs of other electricity generation or deinq

pidnm is bqond the scope of this study but would be a necessay step fthewindfam Investmentwere to be consiered on the bass of global envonmental benefits

21/ Asuming a plant capital cost of US$ 7/Wp insalled, 30 year lifetime, 12% discount rateand 30% capacity factor, co l energ production cost of Rs 0.69/kWh (US$0.045/kWh) and C0 p of 13 kg/kWb.

a 29 -

IV. CONCLUSIONS

4.1 EoomIc evaWuation of the proposed windlirms at Kayathar and lhalayuthu reveals the

(a) On the basi of standard economic cteria, these windfam do not offer aneconomicall least-cost source of electriyit when compared to coentionalgeneration options;

(b) 'Me priazy reasons for this result are the mediocre wind resourc at the sitesconsidered and the poor match between windfam output and system load;

(c) Under basline conditions, these sites were charaizd by a capaciy factor ofapproximae 18%. Windfrms located eewhere have achieved capacity factorsof around 24%. Comparabe sites likely exst in southern India. Not takin intoaccount the benefits of better load matching a windfam which could deliver smilarperformance would be nearly ecoomiclly viable though still not least cost.

(d) Evenwith a capacity futor of around 18%, a more Lbenl aement of unservedenerV costs, which i perhaps more realstic, resl in dear economic viabilty forthese windfarms. However, since such unserved ener costs increase the value ofonvtional generation as well higher unserved enae costs do not make these

widfuams least-cost.

(e) Althouh cmmeriaDy matu, windpower technology Is still evolvig Anicipatednear-term reductions in the capital cost of windpower would enable the prposedKayathar and Thalyuthu to bem economicall viable under baseline windonditions and unserved energy costs.

(M) If one takes into account global ental coss of fossil fuel power generation,the eoonomic gp between comentional generation sources and windfrms narrowsconsiderably. In fact asuming near-term reduction in windfiam capital cons andidentificion of more producti sites along with global environmental cost

nsiderations, windfrms are economica comparable to the least-costconventional generadon tenoo es, and less costy most

(g) Because of the uctainty urrounding estes of the global environmental costsof fossil fuel power generatdon, one may wish to evate t* envonmental benefitsof these windfarms in terms of the C02 abatement cost which they offer. Thesecosts tange from negative under the most fvorbe windam conditions to aboutUSS 45/t of C02 under baselie conditions.

42 Better sites and newer technolo wmi make windfarns more att even If better loadmahing does not occr. And given that windfarms in Tamin Nadu would help to meet at least

* 30 -

some demand which would be otherwise unserved, the higher the assesed cost of unserved energy(or, likewise, the more unserved energy which windfarms can meet), the greater the economicviability of windfams. Although these factors may result in the economic viability of windfarms,the proposed sites do not become competitive with conventional generation until one considersglobal environmental costs.

The Cm fgr Conoessional Financing

43 Although these windfarms are not least-ost in standard economic terms, they may beattractbe candidates for financing on conessional terms because of their environmental

acteristics. Some funding sources, such as the Global Environmental Facilit (GEF), areintended to finance projects which yield global environmental benefits but which would nototherwise be financed because of inadequate economic returns. These windfarms may beappropriate candidates for this type of financing for the following reasons:

(a) Asuming a cost of unserved energy of Rs 3.23/kWh (US$ 0213/kWh), thesewindfurms are already economically viable, Le. their benefits in terms of the valueof energ produced is greater than their costs. Nonetheless, because they are notleast cost under current circumstances, they would most likely not receive financingdespite their local and global enironmental benefits.

(b) Tle prospects for furffier Improvemen in windfarm economics are goodcnsidering the potential for better site selection and near-term cost reductions inthe technology. Financing a commercial scale windfarm at this point may helpstimulate those cost reductions and accelerate the search for better sites.

(c) f global environmental costs are incuded in the evaluation along with better windresources and improved tecinology, these windfarms are competitive withconventional tochnologies

(d) In terms of 002 abatement costs, these windfarms woud displace C02 for no morethan US$45/t, and substantialy less under more favorable conditions Althoughdetaged comparisons with the abatement costs of other generation technologies isbeyond the scope of this report, these appear to be attractive abatement costs vis avis other electrict generation technologies. Central station photovoltaic plants, forexample would probably offer abatement costs of more than USS 200/t

(e) An institutional envirment is emerging in India which may filitate the furtherdisemination of the technology without substantial burden on SEBs. For ince,IREDA has been established to provide financing to the private sector for renewabetechnologies such as windpower. Enery wheeling and banking arrangements withprivate power producers have become commonplace throughout India, and havebeen implemented in Tamfl Nadu. A suwessdful commercial scale demonstration wMihelp establish a framework for the replication of windpower projects, both withinand outside of India. W-idespread replication would yield sinificnt environmentalbenefits. In this sense, this project could be seen as leveraging more extensivedissemination of environmental benign generation technologies.

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A Framework for Project Implementation

4.4 Whether this project receives concessional financing depends on whether GOI and bilateraland/or multilateral agencies agree that (i) concessional funds should be used to fine renewableenergy projects which would displace C02 emissions from conventional power plants, even thoughthese projects may be economicaly viable but not least cost; and (ii) that the investment in thesewindfarms would be the best use of such funds. Thi, of course, would require the assessment ofCO2 abatement costs of other generation options.

E£ngULgLs aoect Desi

4.5 If such an agreement is reached, the project should be implemented with the followingprinciples in mind:

(a) MInmie demands on TNEB. The project should neither rely on financing fromTNEB nor consume a disproportionate amount of TNEB manpower.

0b) Create a replHable framework Although this particular project wil involveconcessionai financing a framework should be established which can be used whensuch financing is unavailable or when inproved sites and technology are availablewhich wil obviate the need for such financing These arrangements will serve asa model for the further dissemination of the technology.

(c) Pay no more for windpower ta what It is worth. The returns on a widfrminvestment should be consistent with the economic value of the energ produced bythe windfarms.

(d) Provide Incentives for private sector partldpaon. The returns on a windfarminvestment should be sufficient to attract private sector investment Tapping privatesector resources will help leverage concessional financing and wil help ensure thatthis project does not compete with limited public sector funds allocated for powersector development.

4.6 One possible arrangement for project implementation involves the participation of threeentities: IREDA, as project financier; TNEB/TIEDA as regulator and power consumer, and aprivate fim as project developer and operator.

4.7 The Role of IREflA The overnight capital cost of this 75 MW project would be aroundUS$ 90 million. IREPA would serve as the principal project financier and would provide a conduitfor concesional financin& IREDA limits its exposure on loan for renewable energ projects to50% of the required investment. It currently offers loans at 12.5% interest rate, a 2 year graceperid and a 10 year repayment term. In addition, IREDA could administer the concessionalfinancing provided by a source such as the GEF. ypicaly, the GEF would provide no more than30% of the project capital costs for a power project offering global warming mitigation; in this case,

- 32 -

the amount would be around US$ 27 miion. IREDA would therefore admiister financing for80% of proJect costs, or about US$ 72 millon.

4.8 mm RoliafI /IA TNEB would purchase power produced by the windfarms, andtogether with TEDA, would help Identify private developers and ensure that their facilities andoperation comply with NEB's requhements. They would seek expressions of interest from privatepardes, and after identifying qualified parties, would provide them with financial details andtechnical specificatons. Application for IREDA financing would remain the responsibility of theprivate developer. Land which TNEB/TEDA holds and which is suitable for windpowerdevelopment at these sites could be offered for sale to the private developer, or leased if the projectwas to be implemented as a build-operate-transfer project. TNEB/TEDA would be responsible forcoordinating and reviewing all aspects of project implementation. Their past experience withwindfirm construction and operation leaves them well placed for such a function.

4.9 TNEB should pay no more than the ecnomic value of wind power, which under baselineconditons is only Rs 1.07/kWh in constant 1990 terms. Currently, TNEB pays Rs 125 forwindpower, although this rate was establied as a promotional measure. However, in keeping wththe principal that the project should not financially burden 1NEB, TNEB's relatively low t limitthe power purhs price to below ecnomic value. It is assumed that 16% of windfarm outputalows additional TNEB sales to industial customers which would not have taken place otherwisedue to loadsheddng Tbis proportion is consistent with the effective capcity of the windfarms, andsce most windfarm output ocu in the afternoon, when indusrial demand dominates systemload, this power could be sold at an avage industrW tarff of around Rs 1.05/kWh Iheremainin 84% of windfarm output is valued at TNEB's average tariff of Rs 0.87/klW A weightedaverage of this two rates results in a purchase price on the order of Rs 0.90/kWh in constant 1990terms. A power purchase agreement could allow for inflation by including a price escalation clauseig price increases to some more general cost indeL

4.10 Although a power purchase prie of Rs 0.90/kWh is much higher than price of about Rs0.60/kWh for NWPC power, it is avaiable. Given expected growth in TNEB load relative towreases in the availabilit of NTPC power, other sources of energ besides NTPC must be engagedi TNEB is to avoid incrased load shedding. The additional sources, such as these prosecXvewindfarms, may indeed be more exensive than NTPC power but are cheaper than e cost ofunserved demand.

4.11 The Role of the Private Devel. In this scenario, the private developer would cany a20% equity share in the project and would be responsible for the constion and operation of thewindfrm It would also be responible for appication and repayment of the IREDA loa Asimplified cash flow statement for the prvate developer is shown in Table 4.1. Tbis statementreflects base a condions regrding windfam generation, costs, etc, but does not take intoaccount the tax effects of such a projet. he financial internal rate of return (FIRR) under theseconditions is 13.6%. Figure 4.1 shows how the FIRR varies with changes in infation, capafactor, and power purchase price. With higher inflation, the spread between the FIRR and inflationrate increaV because debt is repaid with cheaper money while revenues remain constant in realtems. f TNEB could pay the economic value of windpower, FIRR would increase to 18.7% underbase case conditions. Simirly, any increase in capacity factor would likewise :ncrease FIRR. Forexample, even with a power purchase price of Rs 0.90/kWh and 10% inflation, a 24% capacityfactor would result in a FIRR of 19.5%.

Tabte #.1: Siqtlified Awtwal Cash Flos Statement for a Privfte Windfarm Dweloper under lase Case Condftion.........

fxEwge Rat., 1sAIS 15.2Total PJol. Cost, .00 Rsl,368.000IIEDA Lem Ant., 9000 to 684 000IREDA Loan Interet 12.5XInfLation 10.0%Teor 0 08K Cost, ftAWh 0.20Capity Fctor 18%Powr Price. Its/kUh 0.90Salvage Vatue Factor 2mZE"Aty sae 20%

All vatlus expressed In curret year Is, thousanck

VYe O Year Ieen Year2 Year3 Year4 Year S Yesr 6 Veer 7 Year 8 Year 9 Yeerl1Tear 11 Year e2 Year 13 eTr 14 Vesr 15

Unlts Gitgted, NAb 118,260 118.260 118,260 118,260 118.260 118,260 118,260 118,260 118,260 118,260 118,260 118,260 118,260

EXPENSE

Cah Contribution 273,600IRDA Len Repayment 123,S45 123,545 123,545 123,545 123,545 123,545 123,545 123,545 123,545 123,545

0 & n 0 0 0 31.481 34,629 38,092 41,901 46,091 SO.700 55.770 61,347 67,482 74,230 81,653 89,818 98,00:Depreciation 68,400 68 400 68,400 68.400 68,400 68,400 68,400 68,400 68,400 68,400 68.2168,400Totat 2n,600 0 0 #23,426 226,574 230,037 233,846 238,036 242,645 247.715 253,292 259,427 266.175 l400053 1 0S,218 167,200

REVENUES

Poer saes 0 0 0 141,664 1S5,830 171,413 188,SS4 207,410 228,151 250,966 276.062 303,669 334,035 367,439 404,183 444,601 *Salvage

NET CMSH FLt (273,600) 0 0 (81,?62)(70,744)(58,624)(45,292)30,627)(14,495) 3,250 22,7M0 44,241 67.860 217,386 245,95 277,401

Year 16 Year 17 Toar 18 Year 19 Year 20 Year 21 Year 22

UIfts Generated, NWA 118,260 118,260 118,260 118,260 118,260 118,260 118,260

EXPSES

Csh ContributionIRDA Lamn Repayment0 & N 108,680 119,54 131t,503 146,653 159,119 175,031 192,534Depreciation 68,400 68,400 68,400 68,400 68.400 68,400 68,400Total 177,080 187,948 199,903 213,053 227,519 243,431 260,934

REVES

Power Sates 489,061 537,967 591,764 650,941 716,03S 787,638 866,402Satlvge 273,600

SET CAS FLOW 311,981 350,019 391,861 437,887 488,516 544,207 879,068

FIRt 13.6%

- 34 .

Figure 4.1: FIRR Sensitivity Analysis10% Inflation

FIRR (nominal)

25%

20%_

10%16%

10% . .. I--.....................

0.70 0.80 0.90 t.00 1.10 1.20Power Purchase Price (1990 Rs/kWh)

- t8S Capacity Factor - 20% Capacity Factor

- 22% Capacity Factor 1 24% Capacity Factor

15% Inflation

FIRR (nominal)40%

30%

20% ---

I% .

10%0.70 0.80 0.90 too 110 .20

Power Purchase Price (1990 Rs/kWh)

- % Capacity Factor - 20% Capaclty F*otor

- 22% Capaecty Fatort 24% Capaclty Factor

O&M costs and power purchase priceincrease at rate of Inflation.

- 35 -

4.12 It of course remains to be seen whether private developers would be atracted by thesereturns. Several Indian firms have already formed joint ventures with foreign wind turbinemanufactures and have participated in the construction of exsting windfarms in India. Given theprospects for the identification of better sites, likely reductions in technology costs, and theopportunity to get in on the "ground floor", these firms may find these returns adequate. One mustkeep in mind as well that the base case for the wind resource is derived from only three years ofwind data. One of those years is acknowledged as perod of "wind drought"; indeed, averagewindspeed for Kayathar in 1988 was only 5.7 m/s. Although this highlights the risk asociated withdepending on the wind for sustaining a cash flow, it also suggests that the base case assumptionsmay be quite conservative.

4.13 Other financial factors also may be signficant. For instance, the proposed frameworkrequires the private firm to carry a debt-equity ratio of 2.5 for the project; this degree of leveragemay be unacceptable. As mentioned above, tax consequences also need to be considered.

4.14 Figure 4.1 also suggests that macoconomic factors have a considerable effect on financialviability. As noted above, higher inflation makes the project more attractive, assuming the financingterms remain the same. In addition, general energy poLicies, such as sibsidies which surpress fuelcosts and tariffs, diminish the financial returns, even though a project may be economicalydesirable. Like any private power scheme in India, private sector windfarm development wbuld beimpeded by the the price distortions which pervade the energy sector. The fact that thesewindfarms are even somewhat finaancially attractive under these conditions suggests that wind poweris indeed a commercially mature technology when global envronmental objectives are taken intoacoount.

4.15 Several variations of this proposal are possible. As suggested above, it could be strucuredas a build-own-operate scheme with eventual sale or transfer of facilities to TNEB. If the privatedeveloper is already a major consumer of TNEB power, the project could be viewed as energywheeling or bankdng arrangement. However, when all economic aspects are taken into account,wheeling and banking are less advantageous to certain parties than the strightforward powerpurc!ase arrangement described above. For instance, under a wheeling arrangement, TNEB wouldforego revenues charged at the hier industrial rate by allowing an indusil consumer to in effectproduce its own power. Wheeling would be revenue neutral for TNEB if it charged sometransmssion fee, and if the power it would have sold to that industrial consumer could be sold toanother at the same price. During periods of suffcient capacity (which is when these windfarmsproduce most power), though, it is unlikely that this power can be sold for that price. Rather, theonly savings TNEB would realize would be reduced operating costs at the margin. Furthermore,it is not clear what happens during periods of load shedding; even if windfarms continue to operate,it may be difficult for TNEB to ensure continued supply to the industral firm through the system.

4.16 Banking presents an even more difficult issue since the value of generation varies with thetime it is produced. Clearly, it woud be at TNBs expense if it allowed producers to providepower during off-peak periods and consume power during peak periods without paying capacitycharges. If time value is taken into acoount, the result is essentially a power purchase agreementin which the utility wi buy power, Le. credit the producer, at a certain price at a certain time, andwil sel power, ie. debit the consumer, a different price at a different time.

. 36 -

4.17 Implemening the prqject Is the above manner would be consistent with the principlesoutlined above. Specll, her woud be no financial demands on TNEB, and onl limitedmanpower demands, restited primai to the project design phase The firmework would berepliable in that as better sites were found and technology costs fell, the grant componentadministered by IREDA could be reduced and eventually withdraw in future projects All the sameentities would remain in place with virtually the same roles. Fin*, windpower is pricedappropriately and the rate of return to private deelope is ilow, but lielyk sufficient to attract theirparticipation.

Pag 1 of 5

ANNEX 1: THE ECONOMIC SCREENING MEMODOLOGY

Oveniew

1. Site screening conssted of the following ste:

(a) vising the site, including assement of the grid comnetion;

(b) sizing of the windfarm;

(c) derivation of co estimates;

(d) estimation of windfarm output;

(e) estimation of eneqy value of output;

(f) estimation of capacity value of output; and

(g) calclation of benefit/cost ratio.

Site Visit and AssSSM=n of Grid Connectio

2. Ihe windfirm sitting mission vited each preselected site to estimate the potential sze ofa wndfarm at the site, assess local grid facilities, soil conditions, access, etc.

3. To ensure that the windam can operate properly and not cause gr failures, windfarmsmust be interconnected with a gid charcterized by the foaLowng;

(a) frequency betweon 47 to 52 Hz;

(b) voltage variations at the point of connection with other conmers withn I 15%,whether or not the windfarm,is connected;

(c) voltage increase at each wind turbine below 13% of the rated voltage; and

(d) a short ciut level at the common coupling point with other conumers not less than5 to 10 times maximum power output of the windfarm.

Each prospective windfarm site was evaluated on these criteria as the wel as the avalbili of thegrid and the condition of tn sn and ditibution lines.

4. Confiuration of the axisting grid and the power conat subtations near thecommon coupling point of the wlndfim and conumers wa also taken Into awcount. The fllowingcriteria were applied:

knnlPage 2 of S

(a) al wind turbines are provided with a start current limiting devties I(start) < 13I(rated);

(b) all wind turbines are provided with a capacitor bank for full compensation of the idlerunning reactive power consumption; and

(c) all wind turbines are designed for a frequency range of 47 to 52 Hz.

5. Windfarm sizig was determined by land availability and grid connection capacity. Whileland availability is a stright forward analysis of the terrain regarding suitabflity for windfarminsation, alternative uses and ownership, grid connection capacity was a limiting facor for thetotal wind power capacity to be installed in certain areas.

6. The land requirements for a windfarm were calcuated assuming that the turbines wereto be erected in rows with a betwten-row distance of 7 times rotor diameter and a between-turbinedistance of 5 times rotor diameter. The rows would be aligned perpendicular to the prevailing winddirection. Assuming turbines with a 25 m rotor diameter, ie. turbines of around 200 kW,approximately 10 ha are required for each MW installed. Only 5% to 10% of this area is directrequired for foundations, roads, and facilities.

CostEtnae

7. After sizing the potential windfarm at each site, the total cost of establishing a windfarmat the candidate site was estimated. The cost estimate includes:

(a) Wind turbines including control systems, panels, environmental protection, capacitorbanks, assembly and erection;

(b) Electrical works including all necessary cables, new trnion lines and substations;and

(c) ivil works Including foundations, roads, buiding, fencing etc. as well as the cost ofland acquisition.

EDstiatio of Windfarm Outpt

8. The annual energy output per MW installed capacity at the candidate sites have beenestimated in order to rank the sites. The output is based on wind data measured during two years,1987 and 1988. It has not been evaluated how weJl the wind energy resources durng these two yearscorrespond to the long term average wind energy resources at the sites. Consequently, the outputesimations given in this report, while suitable for comparisons between sites, may be a misleadingbas for caculation of long term windfarm energy production costs

Page 3 of 5

9. The following assumptions have been made to estimate wlndfarm output:

(a) Wind ener resore

The rsources at the selected sites in Gujarat and in Tamil Nadu are calculated by usingthe wind data measured at Harshad and Kayathar, respectively. The wind regime at theselocations is considered to be representative for the wind regimes at the candidate sites inGujarat and Tamil Nadu.

Measurements of wind speed and wind directon have been carried out at the two sitessince 1987. The measurements are made both at 10 m and 20 m above ground leveL Themeteorological standard for wind measurements is 10 m above ground level Thehubheight for the turbines considered for the analis in this report is 30 m, and the datameasured at standard level (10 m) are ued as basis for the wind resource estiations. Inorder to calculate the output of the tubines based on the power cutev it is necessay toestinate the wind speed frequency distribution at the hubheight (30 m). To do so, thewind speed proffe in the bounday layer is assumed to be logarithnic and a function ofthe roughness length of the terrain, and the wind speed frequenqy distribution is assumedto be a WeibuR ditbution Z/. The wind turbine output is then calclated from thewindspeed at hubheight and the power curve.

(b) FroCurve

A typical power curve for a 200 kW pitch regulated wind turbine has been used for alsites. The curve is given in Figure 1. Standard air density of 1.225 kg/im is assumed.

The availabilt of the turbines is assumed to be 90%. Tlis means that the turines aretechnically ready for operation and the grid is avae for 90% of the time. Forcomparison, the availability during the first year of operation of the existing windfarms inthe areas where the candidate sites are located, was on the order of 95%, including gridfailures. In gHt of this, the aviability used in the analyss in this study is on theconservative side.

(d) A=y EMd=ing

Arry fficieny is multiplied by the sum of the output of aR individual turbines to givethe output of the entire windfarm It accounts for the wake effects and subsequent powerloss caused by the placement of upwind turbmines. The offidency used for the screeningcalcuations is 95%. The array efficency for a wlndfarm depends on the confgrtion ofthe farm, local tpogamphy, and the fbm orientaion relative to the wind direction distibution The array efficeny estimate wM likly& change after the final layout of the

22/ EL Petersen, et al., Wind Atlas for Denmark, RISO, January, 1981.

Page 4 of 5

windfams have been made at the different sites. More detafled modelig carried outduring the economic evaluation indicated that annual average array effiiency would be79% for Kayathar and 78% for lbalayuthu. Tis explains to a large extent the differencebetween the windfarm capacity factors estiated in the sceeening analysis and economicevaluation.

EFU1: Ihe Wind Turbine Power Curve

200

100 1

00 5 10 15 20 25

Wind speed, mWa Hubhtght

0i* kW___

8 i.0 0.1D ~~~Oa

8.0 11230.0 24A7.0 Su.OA O

Sas S4210D0 1U/J911.0 146SJ11. 1712

14J =016.0 100.0

17.0

11.0 . 109au 0

auaauD nu

Page 5 of 5

nawdonsf Ene alue of Otu

10. The energ value of output from a windfrm was deried from the value of the fueldisplaced by wind power generation Windfarm generation was calcuated for each 2-hour intevaltbroughout the year, but assuming the same daily pattern of production witin each month A 12x 12 production matrix was then set up with 12 months and 12 2-hour intervals. A correponding12 x 12 demand matrix was also constucted, which dis ed between different load periods,ie. peak load, medium load, and off-peak load, for each monthly 2-hour inter b ThMevai oost(mainly fuel costs) of the units displaced by wind onerVy in each of the differt load periods weredetermined. A value of displaced energy was thereby assiged to each load period and thus to eachcel in the demand matri. By multiplying the two matri and smming the values for the entireyear the total annual value was computed By dividing ths figur with annual output the avereneg value of 1 kWh supplied to the grid was computed.

tiond of CapY Value of gm

11. Although the production from a windfm b unpeditae and the apacit installed isnot firm capaciy, eectricity produced by a windfarm, a durig peak load periods, icesystem reliability and contributes to total system capacity. As a rough estimate, capacity value was

asined to elecicity produced by the windfarm in peak hous This value corrsponds to the level-ized cost of the most likely conventional capacity addition to be dilfaced. Off-peak production wasnot assigned any capacity value, while production during shoulder periods was assigned a capacityvalue equal to 50% of that of ieak production. ihe caluation method ib basically the same as forthe calulation of enery value of output.

ahLB feetCtatio

12. The ratio between benefits epressed as the average value of output (1990 Rs/kWh) andcosts expressed as levelized production costs (1990 Rs/kWh) was selected as the figure of merit formpring sites. Levelized production costs were calculated as the single prie one could charge

for electicity produced by windfarm over its lifetime so that life cyde costs would be entirelyreoovered. The windfarms were assumed to have a lifetime of 20 yeas A 10% discount rate wasused for these calculations.

13. All costs are eoonomic rather than financial, and the economic costs are stated as borderprices, usg the officWial exhange rate. Most local costs are coverted to border prices by using astandard conversion factor of O.8, but the economic cost of coal, which plays an important role incalculting the energy value of output, is detemined using a roeet World Bank estiate 2/.

23/ "Maharashtra Power Project', World Bank Appral Report May, 1989. -

Page 1 of 48

ANNEX 2: DATA AND RESULTS OF THE SCREENING ANALYSIS

1. All costs used in the screening analysis are given in 1989 terms and a 10% real discountrate was used for all economic calculations. The economic evaluation, disussed in Annexes 3 and4, states costs in 1990 terms and uses a 12% discount rate. The difference in these basicassumptions between the screening and evaluation analyses is a result of the delay between the twomissions which carried out these analyses.

Wind Turbine Cost Estitnates

2. It is assumed that the turbines are supplied by a turn-key contractor and the cost estimateincludes towers, control systems, low tension panels, capacitor banks, environmental protection,assembly and erection as well as 5 years supply of spare parts and a two year warranty period. Thecost estimate is based on the tenders for a 10 MW and two S MW windfanns in Gujarat and TamilNadu financed in 1988 by a Danida grant. These prices were reduced by 20% for the followingreasons:

(a) Prices of 200 kW to 250 kW wind turbines had been reduced 20 to 30%during 1988-1989 because of the commercial introduction of 300 kW to 400kW turbines.

(b) International and not national competitive bidding is assumed.

(c) Possibilities for a large-scale discount because of the larger windfarm size areincreased.

(d) Ihe Danida project contained a component of basic training and verycomprehensive after-sales service which is not assumed to be induded in thisprojecLt

3. It is assumed that the unit size of the wind turbines wil be around 200 kW and thatturbines to be erected at coastal areas (ie. in Gujarat) wil require extra corrosion protection at anadditional cost of USS 75/kW. In 1989 financial prices, the turn-key turbine supply is estimated atUS$ 1,075/kW in Gujarat and US$1,000/kW in Tamil Nadu.

4. This price does not take into account the effects of local manufacture of some oamponents.However, a possibe reduction in labor and transport costs resulting from local manuf maybe offset by less effcient production and more costly quality assurance.

5. For the purpose of converting the above financial costs to economic costs it is assumedthat 80% of turbine cost is for imported components and that 20% are manufactured locally. Local

Pare 2 of 48

cost components include towers, assembly, and erection. Asmuming a standard converdon factor of0.8, the economic turbine costs become USS 1,032/kW in Gujarat and US$ 960/kW in Taml Nadu.

Cost EsmLaf Electrical k

6. It is assumed that all elea installations for connection of the wind turbines to the gridwil be carried out by local electricity boards. Therefored, the cost estimate is based on local Indiancost for supply and erection of substations and networks and includes connection to the overalltransmsion grid. Tbe costs vay from US$160/kW for the site in Gujarat to US$98/kW,US$69/kW and US$60/kW for the three sites in Tamil Nadu. Detailed costs of electicalinstaations at the candidate sites are given in Table 1.

Table 1: Cost Estimate for Electrical Installations

LambaNaybdaa Windfarm

Total No. of Turbines at Navdara: 132 nos x 200 kW = 25 MWTotal No. of Turbines at Lamba-Ul: 132 nos x 200 kW - 2M

50 MW

item Description Oty. Unft Cost Total Costsmitlion ft million Re

* LT Cablesize 3 1/2 x 400 sc 30 km 0.44 13.2

- 33/0.4 WY, 1 NVATransformr $/S 66 nos 0.55 36.011 kV Line 20 In 0.06 1.2

- 66/33 , 10 NATransforer S/S withprotection on both side 8 nos 3.9 30.8

- 66 kW Line 60 km 0.17 9.9* 220/66 W, 80 WVA S/

with protetion on bothsides I no 30.2 0.

Total 121.3

(or approximtely USS.1 millton)

Cost per Ma 160 US$/kW

Note: Compared to sites in Tauil Nadu, slightly smaler turbfnes re used at thls site as a result of gridlimitatons.

Page 3 of 48

Total No. of Turbines : illrnos x 22S kW = 25 MW

item D"ecriptin Oty. Unit Cost Total Costsmfllfn I milIton RaS

* Traraformr 1 VA 33/0.4 kV 28 nos. 0.3 8.4* Cable 0.4 k, 4000 AL

(125 U per wind turbine) 14 km 0.S 7.033kV O.H. Line Loperd 11 km 0.08 0.933 kV swftch fused SS 4 nos. 0.1 0.4

* 33 kV switch for traf.'s 28 nos. 0.1 2.8* 110/33SIO k/S I n. 2.1 2.1- 110 kV O.N. 0.2 km 0.45 0.1* other costs 2.5- 110/33 kW, 2 WVA Traform. 2.0 nos. 6.5

Total 37.2(or approximtety U$ 2.4 million)

Coat per kwt US$k/WU

Total No. of Turbines : 222nos x 22S W a 5O MW

Item Descripton 0-ty Unit Cost Total costsmillion R mllion R

- Tranformer I WA 33/0.4 kY S6 ns. 0.3 16.8* Cable 0.4 W, 4000 AL

(125 m per wind turbine) 28 km 0.5 14.033 kV O.H. LLne 19 km 0.08 1.5

* 33 kV switch fusad /8 4 nos. 0.1 0.4* 33 kV switch for trsf.'s S6 nos. 0.05 2.8- 110 k 0.11. Line 2-circuit 0.2 km 0.45 0.1- other costs 5.0- 110/33 kW, 50 WA Tranfom. 2.0 nsa. 5.8 ATotal 52.2

(or approx mately U$83.4 fIllifn)Coat per KY:il 69 USS;/KY

Page 4 of 48

Total No. of Turbines : 280 nos x 225 kW = 63 MW

Item hecription Oty. Unit Cost Total Costsmlifon o mitllion fs

- Tref. I WVA 33/0.4 kV 70 nos. 0.3 2.1- Cable 0.4 kW,

(125 per wind turbIne) 35 km 0.5 17.533 kV O.H. Lfne(5 x 3.5 km) 17.5 km 0.08 .1.4

* 33 kV switc;i fuse(33 kV 8/8) S nos. 0.1 0.5

- 33 kV swtch fused(for tref.0s) 70 nos. 0.1 7.0

/33 kV S/S, 2x40 A I nos. 2.1 2.1- 66 kV O.N. Line,

2-circults 20 km 0.21 4.2- 86 tkV N.O.C.3. at

Kavether $IS 2 nos. 0.3 0.6- 466 kV bus, 1sotator

switches etc. at Koyathar I noe. 0.5 0.5- Other costs 6.0- 663 kV, 40 NVA Transform. 2.0 nos. 8.0 16.0

Total 57.9(or appxl ttely U 3.8 mliton)

Cost per kV: US$60/kV

St Etimte f Cvl Works

6. The cos of cil works depend on the local conditions, but based on eimates firomGEDA and TEDA a standard unit cost of Rs 1.75 million/MW (115 US$/kW) wa selected tocover construction of foundations, roads, buildings etcq but ihuding the acqubition of landAccording to TEDA, the price of land in Tamil Nadu wll be between Rs 0.50 million/MW and 0.75million/MW istalled Rs 0.75 mMion/MW (50 US$/kW) has been chosen to remain on theconservative side. In Gujarat the relevant land is waste land of litte value, and some of the landis already government owned This has made it diffiult to estimate an economic price of land, butas an estimate it has been chosen to use 50% of the price in Tamil Nadu, Le. Rs 0375 million/MW(US$25/kW).

7. Tne capital cost of conventional thermal power generation (including grd oonnection) hasbeen estimated at Rs 15 million/kW, consistent with the apprasal report for the World Bank-financed Talcher Ihermal Power Project, May 1987.

8. Ihe specific coal co_numptis b estimated at 0.65 kg/kWh genaered (source: Wold BankTalcher Ihermal Power Project). 'Te coal cost is estimated at Rs 193/tone + Rs 0.43/tone.km(source: Wod Bank Power Proect May 1989).

Page 5 of 48

9. The average dtanc from the mine mouth to the power plants in Gujarat and TamilNadu respectively have been difficult to assess, because the coal comes from a number of differentsoures AcCording to information received from the SEBs the most probable place of origin wouldbe Bihar or mines dose to that state. Accordingly, average distances have been estimated to be 1500km for Oujarat and 1800 km for Tamil Nadu.

ftnzimn vit 1 Windfann inIndia

10. Seven windfaims were in operation in India as of Aprd, 1989. The locations of the farmsare indicated on the map in Figure 2.1 of the main text A summary of the power performance foreach farm is given in Table 2.

Table 2: Summary of Power Performance of Existng Windfarms in India.

F|art PeriedlOutput, MAh, (IH6MW)

tart-up date 1966 1907 1908 1989

NhnidOv1 Jan-b.c 7 sJa-c Jan-Oct1.10 NW 1737 1714 148186.01.16 (1579) (1S58) (1289)

Tuticorin I Jan-Dec JanrDec Jan-Oct0.55 NW 800 798 56786.01.18 (145S) (14S1) (1031)

0kb Nor-Dec JmnDec Jan-Oct0.55 NW 865 830 42986.03.08 (1573) (1509) (780)

pwur r-ec jan-Dec Jan-Oct0.55 NWl 201 449 24086.05.01 (365) (816) (436)

Dec Jan-oDc Jan-Oct0712 ;r sn~~52 407

86.05.23 (607) (951) (740)

Tuticorin It Nov-DOec jan-Dec JanOct0.331 KM2 47186.11.21 (218) (1427)

Ks!Ithar I gD -Narlw Va ~~~~~~~~~~13088.04.07 (150) (92)

11. Th'e highet output per MW nstalled capacity is obtained by the fams installed in Gujarat(Mandvi and Okha) and Tamil Nadu (Kayatbar and Tutiorin). The monthly energ output for eachfium is given in more detail inTable 3.

Page 6 of 48

Table 3: Power Performance of Windfarms in hIdia

Farm Mandvi Tutf I Okha Purf Deogarh Tuti It Iyathar IStart (16.1.86) (18.1.86) (8.3.86) (1.5.86) (23.5.86) (21.11.86)/(15.1.88) (7.4.88)Cap. 1.1 m SOkU 550 kW 550 kW 550 kW 330 kW / 220 kW 1,35 NW

Month kWh kWh kWh kWh kWh kWh kIh......................................................................................................

Jan 86 14,760 42,345Feb 57,958 53,271Mar 77,m 54,285 66,210Apr 168,700 30,855 101,540Nay 238,980 40,159 166,830 55,258 43,540Jun 213,500 105,387 107,590 62,212 102,640Jul 347,340 137,493 130,940 14,956 58,940Aug 280,390 96,333 112,007 32,016 69,410Sep 168,580 90,254 43,673 19,793 12,960Oct 91,780 24,621 25,880 5,992 6,720Nov 35,780 39,092 31,140 2,728 10,840 19,628Dec 41,200 85,737 79,400 8,432 28,964 52,166

.... ............ ......... ............... ......... ............... ......... ......................... .

Total 1,736,745 799,832 865,210 201,387 334,014 71,794......... .............. ......... .............. ......... ................... .............................

Jan 87 34,600 109,876 65,990 9,902 14,500 54,456Feb 43,380 62,309 39,710 8,604 29,520 35,104Nar 76,100 53,666 48,800 63,467 27,560 26,307Apr 160,640 41,115 80,110 55,468 35,240 23,329Nay 191,600 40,384 94,410 70,661 37,460 24,543Jun 233,100 120,356 96,570 46,484 73,960 77,418Jul 387,380 123,191 122,750 62,402 152,800 75,184Aug 304,360 106,896 99,910 58,736 71,220 68,339Sep 194,460 61,183 64,880 44,114 25,920 36,284Oct 31,920 23,789 32,770 9,561 21,080 13,657Nov 25,480 13,362 32,380 12,016 13,120 9,732Dec 30,920 42,198 51,370 7,945 20,920 26,471

= ............. ......... .............. ......... .............. ......... .............................

Total 1,713,940 798,325 829,650 449,360 523,300 470,824......... .............. ......... .............. ......... ................... .............................

Jan 88 30,340 78,319 49,634 2,539 17,420 66,326Feb S8,440 36,750 49,514 14,484 33,980 37,503Nar 100,500 29,436 52,146 38,933 52,260 30,561Apr 115,600 18,619 56,547 42,425 32,760 20,742 9,750Nay 291,520 41,887 116,960 36,371 53,452 48,089 301,823Jun 225,800 75,200 56,247 22,721 39,832 78,745 455,906Jul 335,140 114,177 47,981 36,180 83,963 126,646 416,009Aug 186,020 82,342 28,933 55,032 87,044 358,101Sep 75,260 61,199 17,357 38,276 63,559 335,212Oct 62,700 29,070 32,004 81,504Nov 25,190Dec 51,176

, , .................. ......... . ........ ................. .........Total 1,481,320 566,999 429,029 239,943 406,9?5 59,219 2,034,6?1

..... ........................................... ......... .............. ......... .............. ......... ............... ....

Page 7 of 48

12. The avalbility of the eistig windftrms, located in the same areas as the preselectedsites, has been evaluated. Availability is defined as the portion of the year during which the grid isavailable and the turbine is tecbnica ready for operation. In Gujaram, the Okha windfarm islocated at the sea shore apprtel 80 km northwest of the Lamba/Navdara site. The farmconsists of 10 x 55 kW turbines with a hubheight of 24 m. It was commissioned in March 1986. Theannual output in 1987 was 830 MWh (1510 MWh/MW), corresonding to a capacity factor of 0.17.The operation time of tho Okba wlndfiwm during a period of 10 months is given in Table 4. Theforced outage rate for that period was 4.7%.

Table 4: Operation time for Okha windfinrm from July 1986 to April 1987

Total Period Nechine fault bintflrance arid Faflures TotalIhours hr X hr X hr X hr X

7200 68 0.9 1) 270 3.8 338 4.7

1) Not specffied

swrj Gujarat Energy Daveloq=nt Ageny. "Okha ndfarm: A Status Report April * t909.

13. The Kayathar I windfairm is located between 10 and 30 km from the candidate sites inTamil Nadu. The fam consists of 1S x 90 kW turbines with hubheights of 24 m, and wascommisioned in Apri, 1988. Annual output (from April, I88, to March, 1989) was 2164 MWb(1603 MWh/MW) corresponding to a capacity factor of 0.18. The summay of the operation timefor the Kayathar windfarim is given in Table .. The periods are the sum for all turbines. Thetechnical availabilit during the period was 927%.

Tabl 5: Operation time for Kayathar widfarm during Apri, 1988, to March, 1989

Total Period Nacfin faut Neintaurnce 6rid Fafiures TotaHlour hr X hr X hr X hr X

15 x 9240 758 0.5 105 0.1 9260 6.7 10123 7.3

IS : Imil Ibdu Eneg Develomt Agecy, $'An Appraisal 2eport an 50 W Windfarm ProjectIn Tamf l Nadu", 198.

14. Ihe capacy factors for the exiting farms in Incdia are low compared to the estimatedcapacity fators for the windfms at the candidate sites in India. This is due to inreased hubheightfor the turbines (from 24 m to 30 m), and because of higher efficency of the larger turbines (200-300 kW) compared to the efficiency of the small turbines (55-110 kW). Furthermore, the estatesused in the screning analsis for array effidency are higher than what more detailed site modelinghas revealed in the economic evaluation.

Page 8 of 48

Desriti on and AWent of Iami Nadu Sites

UtivCharacteristics

15. goeeral DeTtion. he Tamil Nadu Electicity Board (INEB) is responsible for thesupply of electricity in Tamil Nadu. Basic generation statistic for TNEB is given in Table 6 for1987-1988. In principle TNEB is autonomous, but in practice such matters as capital investments,tars, borrowing and personnel polcies are under the control of Tamifl Nadu State GovermmentTNEB colaborates closely with the Tamil Nadu Energy Development Agency (TEDA), which ischarged with research, development, and demonstration activities for renewable energy technology,including wind power.

16. TNEB has instituted energy wheeling and banling in which entities other than the utility canproduce electricity for the grid and at one location or time and consume electricity at a differentlocation or time to the extent that it balances their production. As a promotional measure, TNEBalso pays up to Rs 1.25/kWh for windfarm generation.

Iabl: Installed Capaciy and Gross Energy Production inTamil Nadu

Installed Capacity Gross energy(NeU) production

(GIA)

Therml (cost) 1,S00 n.a.Hydropower 1.799 n.a.Share from central

station 1,258 n.s.

Total 4,558 16,318 1)

1) Energy enerated 9,346 6UAEnergy purchased nd imported: 6,972 GMh

Source: "THIS Statistics at a Glance, 197-88".

17. Power Demand and Generation Needs. The composition of demand on the TNEB systemis given in Table 7. The high load season in Tamil Nadu is from February to June while the lowseason is from August to December. During the high season the daily load curve is almost flat withvery few variations as all capacity is fu1y utilied. Load shedding is common during this period.In the low season the diurnal load curve is more varied with pronounced peaks around 6 am. and7 pm. Typical load curves are shown in Figures 3.2 and 3.3 in the main tezx

18. TNEB typically reduces system frequency by substantial amounts as a first step tominimize load shedding. lbis reduces the effective voltage level instead of cutting off consumerm

A2naPage 9 of 48

Consequently, system frequency varies throughout the year between 49 Hz and 50 Hz but duringhigh season it occasionally drops to 48.5 Hz or lower. As a second step, TNEB limits the maimiamount of power industrial consumers may draw. A permanent power cut of 40% of the initialconnection application has been in effect for all industrial high tension (HT) consumers sinceJanuary 1, 1987. During April, 1989, this power cut was temporarily increased to 60% because ofan abnormal early depletion of the states hydropower resources.

Ial 7: Composition of TNEB Demand

cor- Indu- Agri^Type of corsurption Domestic ciel strfat cutt. Others Total

X of total consuaption 10 8 49 26 7 100

Sorc: "TiES Statistics at a Glance, 1987-88".

19. Captive generation is common in Tamil Nadu. According to TNEB, 2,845 generator setswere registered with HT consumers with a total installed capaci.y of 755 MVA and 3,997 setsregistered with low tension (LT) consumers with a total installed capacity of 203 MVA as of March31, 1987. The total installed captive generating capacity is thus equivalent to approximately 20% ofthe total installed capacity at the disposal of TNEB.

20. There are no data available on the total production from these captive sets, but accordingto Tata Energy Research Institute, which conducted a field survey on non-utility generation in 1985,the average annual usage of captive sets in two states with power shortages (Haryana and UttarPradesh) was between 1,500 and 3,500 hours/year. On the assumption of a power factor of 0.8 andan annual utilization of 2,000 hours of full load for captive sets in Tamil Nadu these figures suggestthat captive generating sets account for 1,533 MWh which is equivalent to approximately 1V% ofthe energy supplied to the TNEB grid.

21. Table 8 presents the power prospects of future generation and demand in Tamil Nadu.Sanctioned projects comprise primarily coal-fired thermal power stations. Projects which are underinvestigation or pending clearance are listed in Table 9.

22. Since coal-fired TPS is the dominant generation technology for TNEB both currently andin the future, the screening analysi evaluates wind power benefits relative to the amount of coal-fired generation it would displace. During off-peak periods, wind power is valued at the variablecost of coal-fired generadon, which comprises mostly the cost of fueL During peak load periods,wind power is valued at the sum of these variable costs plus the levelized fixed (mostly capital) costper kWh of a new coal fired TPS.

23. Calculation of Levelized Costs of Coal TPS. Based on the assumptions stated above andin Table 2.3 of the main tet, the fixed and variable costs of a coal-fired TPS are given in Table 10below.

AnncO Page 10 of 48

Table 8: Power Prospect in Tamil Nadu

1990 1905 _ 2000

Cap. Prod. Cap. Prod. Cop. Prod.NW BA NW am NW BIA

Projected dennd 3,954 20,414 S,792 30,614 8,558 44,982

Avallabitity:___

Existing TWES 1,92S 11,639 1,925 11,882 1,925 11.882

Existing centralsector 830 6,095 830 6,168 830 6,168

Saetfoned projectsTNks 397 84S 1,122 7,035 1,372 7,429

Sanctioned projects,entral 150 S11 455 2,865 SS2 3,202

Subtotal 3,302 19,090 4,332 27,950 4,679 28,681

Defifit 6S2 j 1,324 1,460 2,664 3,879 16.301

SaurceG: TNEB Statistics at a Glance, 1987-88".

Table 9 Generation schemes pending clearance and under investigationin Tamil Nadu

Pending Clearance Under investigation

Hydro projects 294 NW 816 NW

IPS projects 630 NW 1,130 NW

Ga turbifn 120 NW

Total 1,044 NWi 1,946 NW

Source: THES.

24. 3ye and Value of Load Substituted Based on the analysis of load cwes provided by1NEB, Table 11 classifies system load during each two hour period of a typical day reresentngeach month of the year into base load (B), shoulder (M4 medium), or peak (P). Base loadproduction is valued at variable costs alone, peak load at total levelized costs (both fixed andvariable), and shoulder load as the arithmetic average of peak and base values. This matrix of loadsubstution values was multiplied by the matrices of windfarm production per MW of instaedcapacity for the same periods to determine the total value of windfarm output W-ndfmproduction matrices are given later in this Annex on a site by site basis.

Anne@-2Page 11 of 48

Table1: Production Cost from 1 MW Coal Fired TPS in Taml Nadu

Financial Econe1c Aiul Financial Ecnomicmillion Re million fe Iam Rs/kWhR bIkWh

Total IlUstMt 17.25 15.00

Lvelized Invest. 2.03 1.76Fixed OUN 0.26 0.23

Total Fixed 2.2 1.:w 3859 0.59 0.51

Variable O&N 0.17 0.15Fuel 2.19 3.03

Total Variable 2.36 3.18 3859 0.61 0.82

Total Fixed + Variabe ; 5.1T 3859 1.20 1.34

I1le 1lTpe of Load Subituted in the TNEB System by lime of Day (Base, Medium, Peak)

0 - 2 2 - 4 4 - 6 6 - 8 8 - 10 10 - 12 12 - 14 14 - 16 16 - 18 18 - 20 20 - 22 22-'24

Jan 8 B I N 11 B 1N N N B 8Fab S B 8 N P N B N N P N SNor B 8 N P P P N P N P P Npr a 3 N P P 1N N r P P 1N

Nay B a N P P N P P N P N BJun B 8 N P p N N N N N N 8Jul t B N. N N N 8 N N N Aug B 8 8 8 a B 8 8 B 8 8 BSp B B 8 B B 8 B I 8 8 B 8Oct B B 8 8 S 8 3 B 8 8 8 BNov B 8 8 B a 8 8 a B B B 8Oec B 8 B 8 8 a B a 8 a 8 8

TamIt Nadu Biuear Vatue........... v....... ........................

B is vriabte eosts of coal fired TPS 0.82 Rs/kWhN is average of B and p 1.08 Rs/kWP is total costs of cosl fired tK 1.34 RO/M

Kayat-bar Site teadiistics

25. Wind Resources.MThe wind resource at the site is esdmated on the bass of wind datameasured at the Kayathar I site. The site is located approximately 3 to 4 km from the mast, and itis assumed that the wind regime at the site is identical to the regime measured by the masL Themonthly mean wind speed and power density is based on data measured during 1988, as shown inFigure 1. The high windspeed period is May to September. Monthly power density of the wind iscalculated based on the estimated wind speed fequency diibutios for each month. The averageannual power density is 226 W/m2 and the average windspeed is 5.3 r/s at 10 m agL 1988 wasconsidered to suffer from a 'wind drought! but since the sreening analysis only compares sites wvithsites, and since al sites faced the same 'drought' conditions, the sreening rests remain val

Anna2Page 12 of 48

FiWre 1: Wind Resources for Sites in Tamfl Nadu

10 -1000

9 PowdenX*~ ~ Pwrltl 900

8 Soo f82

*j~7 700

S00

1 4 400

3 ~ ~ ~~~~1300

#2 I *200

1 . t . - 100

0 .«JA FE-'A:AP;MA JNIJL'AU'SEIX NOdDE 0

Month, 1988

Monthly nean wind speed and power density, 10 a a.g.l. atthe candidate sites in Tamil Nadu.(alagiyapandlyapurams Kayathar, Talayathu).Based on data aeasmred at Kayathar during 1988.

Page 13 of 48

26. land Availability. Soil ConditionW and Site c b. Available land around hieeisting windfarm at Kayathar was identified. About eight plots were found on the northern sideof the existing 135 MW windfarm out of which two sites are about 10 km away. These sites wouldnot be suitable for large windfarms due to their small size. Moreover, there were agrctural landsboth inside and in dose proximity to these sites. One plot was also identified touching the 6 MWwindfarm under construction, but this was also too smalL

27. An area of approximately 500 ha was identified southeast of the 6 MW windfarn, asshown in Figure 2. TEDA confirmed availability of the desired amount of land. The area under con-sideration is barren and there was no evidence of agricultural activities. The area is mosdy own byprivate individuals. Since it is not vety useful, the price of land is low. For the 6 MW Kayathar [windfarm TEDA had recently purchased land at a cost varying from Rs 4,000 to Rs 5,000 per ha.Given that the desired land would be used for windfarms, the land would probably be purchasedat a cost of Rs 6,000 to Rs 8,000 per ha, since the owner would be in a strong position fornegotiations due to the site specific nature of windfarm siting. The collector and the local revenueofficials assured support and help with procurement of land, if necessaty.

28. The soil conditions are the same as those of the 6 MW windfarm under constrction. Alldesired soil tests have already been carried out for designing the foundations for the 200 kW windturbines at the Kayathar I site.

29. The proposed site is located approximately 5 km from Kayathar on the Kayathar -Devarkulam Road. A part of the site is adjacent to the metalled road. The soil is sufficiently hard,so that the approach road inside the windfann can be easily construted.

30. Odd SYikm. TNEB has a major load distribution and tanmiion sub-station atKayathar, including 230 kV/110 kV/66 kV/33 kV/11 kV transfonners and capable sta The gidthere has a capacity of more than 500 MVA, and there is the possibility for wheeling power to theKerala and Andhra Pradesh grids. The load voltage variation and short-circuit level at differentvoltages are indicated in Table 12 below.

Table 12: Short Circuit Voltage and Load Voltage Variation at Kayathar Substation

Voltage Short-Cfrcuit Voltate fn kV Load in NWIn NVA Mlaxma Minima

220 IcY 6320 235 210 S60 N

110 kV 2535 117 102 75 NW (tCans-ftwmr)

66 W 895 70 63 8 N1 (trans-forwr)

The transformer ratings are as follows: Three 50 MVA 230/1 10 kV; Ihree 25 MVA 110/66 kV; andtwo S MVA 66/1 kV.

Page 14 of 48

Piguro : Location of the Kayathar Site N

No.58 *. .L B O I NOV L * TnTrnu C anZ . K evIlPATTI

- i9 . 21 t 22 23 24 2S a 26 27 28 t29 p

.Xv .

*2I

M : )teorologLcal Mast

Map shoving the Kayathar site. Scale 1:65000 (approximately)

Page 15 of 48

31. The substation receives power from:

(a) 230 kV line from Tuticorin Thermal Plant (3 x 210 MW)

(b) 110 kV line from Periyar & Surliyar Hyde Plant (4 x 3S MW + 1 x 35 MW)

(c) 110 kV line from Kodiyar I & Hydel Plants (I x 60 MW + I x 40 MW)

(d) 66 kV line from Papanamm Hydel plant.

32. The 230 kV double circuit line to Madurai crosses through one corner of the proposed site.The 110 kV line to Madurai is about 2 km away on the eastern side and the 110 kV line to KodiyarHydel Station is about 2 km away on the southern side. The nearest tapping point for the windfarmon either of these 110 kV feeders is about 4 km away from Kayathar substation. Given the adequatefcilites at the Kayathar sub-station and the relaively short distance to the nearest 110 kV lines,energy losses and the risk of voltage variations wil be smaLl

33. Windfarm Size ligni The rough calculations of the voltage fluctuations on the 110kV bus of the site substation show that a 100 MW windfrm wil not provide an unacoeptabevoltage quality. The limitation of the windfarm capacity is the avaibility of land, Le. SOC ha or 50MW. A preliminary layout of the windfarm is given in Figure 3. The single line diagam forconnection of the windfarm to the grid is given in Figure 4. Wind turbines would be dustered intogroups of four, and each group would be connected to a 33/0.4 kV, 1 MVA trandormer. Internalpower distribution between clusters within the windfarm would be at 33 kV, and two 110/33 kV,50 MVA transformers would be used to sum cluster output for interfacing with the 110 kV line.

34. Energy Output. The monthly energy output per MW installed capacity is shown in Figure5. The output is calculated on the basis of the wind speed frequency distribution measured during1987/1988, and the turbine power curve given in Annex 1. AvaIlability and array efficiency were alsospecified in Annex 1. Total annual output is 2120 MWh/MW, eduding line losses A oimately88% of the annual energW output is generated during the months May to September. Under theseassumptions, the annual output corresponds to a capacity factor of 0.24. Diurnal output is givenin Table 13. Peak output is during the afternoon and early evenin&

Table 13: Estimated Diumal Output as a Percentage of Monthly Outputfor the 50 MW Kayathar Windfium

0-2 2-4 4-6 6-8 8.10 10-12 12-14 14-16 16-18 18-20 20-22 22-24

Jan 3 3 3 3 13 16 13 13 14 9 5 4Feb 2 3 3 3 6 6 6 9 30 24 6 2Nar 4 5 6 6 6 3 4 10 31 19 4 2Apr 4 4 3 3 3 2 3 8 28 25 13 6Nay 7 7 6 5 5 5 5 10 20 13 10 8Jun 5 5 5 5 8 10 11 14 14 10 8 6Jul 7 7 6 5 7 7 9 12 1S 11 9 7Aug 6 6 5 5 6 7 10 14 15 10 9 aSep 7 6 5 5 5 5 8 13 1? 12 10 8Oct 8 8 6 4 4 4 6 15 18 10 9 9Nov 4 5 4 4 9 1S 13 14 14 9 5 4Dec 4 5 5 S 14 16 12 10 11 8 5 4

Page 16 of 48

Eigure 3: Proposed Layout of the 50 MW Kayathr Windfiarm

t'

II<IIIIIIIIII

IIIII1.1

Ik I !II104

0I~~

ftw~~~~~~~~~~~~~20

An2-Pap 17 of 48

Ei;r 4: Line Diagram of the 50 MW Kayatha Windfarm

KAYATHAR S/S

220 kV

3 x 50 HVASk - 2535 MVA 220/110 kV

a.L... - I - - 110 kV

I 110 kV Overhead-lineWolfL- 12 km

- 110 kV

2x.:501VA.110/33 kV

- - ~33 kV.11 1~33 kV Overhead-linet eopard

0.4 kVWind farm 3Kayathar

I IIVA33/0.4 kV

_ .............. 4 zc 200 kVVT

Page 18 of 48

Eigure : Monthly Energy Production per MW instaled, Exduding Line Loessfor Sites in Tamil Nadu

500I

400

1 300

I.@ 200-d

100

0 JA' FE' MA AP' MA JN'JL AU 8E'OC NO DE

Month, 87/88

Monthly energy output per MW Installed wind turbinecapacity. excl. line losses at the sites In Tamll Nadu.

Assumptions: 200 kW turbines. bubhight 30 aAvailability: 0.90Array efficientyv: 0.95

Page 19 of 48

35. uction Costs and Production Assumptions on the cost and performance of thewindfarms are ummarized in Table 23 of the main text Line losses are included at this stage ofthe analysis to yield production ensts at the busbar, they are assimed to be 5% of total windfrmgeneration at Kayathar. Table 14 summarizes the production costs per MW of instaled capacityfor the Kayathar site.

Table 14: Production Cost per MW for the Kayathar Windfrm

Fi1nnc1al Economic Anral Ffnarncal Econrmicmillion Rs. mittlln Rs Prad. Nli Rs/klh Its/kilh

Turbinas 15.00 14.40Electrfeal lorks 1.31 1.05Civil Works 1.75 1.40Lard Acqusitfon 0.75 0.60

Total Capital 18.81 17.45

Lwtelfsd Copital 2.21 2.05 2014 1.10 1.02

Arnal Naintenac 0.33 0.31Anual Ues 0.07 0.06

Total Awtl 6I5 0.40 0.36 2014 0.20 0.18

Total Lavelnzed 2.61 2.41 2014 1.29 1.20

36. Table 15 shows windfarm generation per MW of capaciy for each two hour period of theyear, not induding line losses The same output is assmed for all sta in Tamni Nadu. Thegeneration benefits of each Tamil Nadu site are determined by multipying this matrix with Table11, the value of generation, and then subtracting line losses from each two-hourly value. Summingall values and divdn by total annual output yieds the benefit per kWh of production. Theseresults are given for the Kayatwar site in Table 16.

Table 1I: Production by Two Hour Interval of the Day in Tamil Nadu, MWh/MW

0-2 2-4 4.6 6-8 8-10 10-12 12-14 14-16 16-18 18-20 20-22 22-24.. .. ....... ..... .. ....... ... ..... .................. ... ...... . ....... ..... . ...... .....

Jin 0.03 0.03 0.03 0.04 0.12 O.15 0.12 0.12 0.13 0.09 0.05 0.04Feb 0.02 0.03 0.03 0.03 0.06 0.06 0.06 0.09 0.30 0.24 0.06 0.02

war 0.03 0.04 0.05 0.05 0.02 0.02 0.03 0.06 0.25 0.16 0.0 0.02Apr 0.03 0.03 0.02 0.02 0.02 0.02 0.06 0.22 0.02 0.19 0.10 0.05Nay 0.80 0.80 0.69 0.57 0.57 0.57 0.57 1.15 2.30 1.49 1.15 0.92Jim 0.71 0.71 0.71 0.71 1.14 1.43 1.57 2.00 2.00 1.43 1.14 0.86Jut 0.89 0.89 0.76 0.63 0.89 0.89 1.14 1.52 1.90 1.39 1.14 0.89Aug 0.65 0.65 0.54 0.54 0.65 0.76 1.09 1.51 1.62 1.08 0.97 0.86Sep 0.80 0.69 0.57 0.57 0.57 0.57 0.92 1.49 1.95 1.37 1.14 0.92Oct 0.21 0.21 0.16 0.10 0.10 0.10 0.16 0.39 0.47 0.26 0.23 0.23ow 0.04 0.05 0.04 0.04 0.10 0.16 0.14 0.15 0.15 0.10 0.05 0.04

beD 0.06 0.07 o.o0 0.07 0.20 0.23 0.17 0.14 0.16 0.11 0.07 0.06

6nuur2'Page 20 of 48

TmI t Nueb, Gwwration,,,*.......................

Dafly Total Nonthty Total, WH/NU..................... ....................

Jan 0.96 30Feb 0.98 28Nar 0.82 25Apr 0.78 23Nay 11.49 356Jun 14.27 428Jul 12.65 392AUS 10.81 335Sep 11.45 343Oct 2.45 81Nov 1.06 32Dec 1.64 45

Anunsl Total 2120

Table 16: Value of Power Supplied, Kayabr

0-2 2-4 4-6 6-8 8-10 10-12 12-14 14-16 16-18 18-20 20-22 22-24... ... .... ..... ..... ..... ..... ..... ..... .....

Jan 0.02 0.02 0.02 0.04 0.13 0.16 0.10 0.13 0.14 0.09 0.04 0.03Feb 0.02 0.02 0.02 0.03 0.08 0.06 0.05 0.09 0.30 0.30 0.06 0.02Nar 0.03 0.03 0.05 0.06 0.06 0.03 0.03 0.10 0.26 0.20 0.04 0.02Apr 0.02 0.02 0.02 0.03 0.03 0.02 0.02 0.08 0.28 0.25 0.10 0.04Nay 0.63 043 0.7 0.73 0.73 0.59 0.73 1.46 2.36 1.90 1.18 0.72Jun 0.56 0.56 0.73 0.91 1.45 1.4 1.61 2.05 2.05 1.82 1.17 0.67Jul 0.69 0.69 0.78 0.65 0.91 0.91 1.89 1.56 1.95 1.43 1.17 0.69Aug 0.51 0.51 0.42 0.42 0.51 0.59 0.84 1.18 1.26 0.84 0.76 0.67SeW 0.62 0.54 0.45 0.45 0.45 0.45 0.71 1.16 1.52 1.07 0.89 0.71Oct 0.16 0.16 0.12 0.08 0.08 0.08 0.12 0.30 0.36 0.20 0.18 0.18Nov 0.03 0.04 0.03 0.03 0.07 0.12 0.11 0.12 0.12 0.07 0.04 0.03Dec 0.04 0.06 0.06 0.06 0.16 0.18 0.13 0.11 0.12 0.09 0.06 0.04

Dally Total Naothly Total, p000 Rs/kU

Jan 0.91 28Feb 1.04 29Nor 0.92 29Apr 0.92 27May 12.36 383Jun 15.04 451Jul 12.30 381Aug 8.50 264Sep 9.01 270Oct 2.01 63Nov 0.83 25Dec 1.11 34

Annual Total 1985 keufts Re/Wi 0.985.... .... u.a_

AnmeZ2Page 21 of 48

do=dblMm Site aracteid

37. Wind A wind monitoring mast was erected at the site in mid-July, 1988.Wind data covering the period from July, 1988, to Februaiy, 1989, were avaiable for this analyisComparing the data with the corresponding data from the Kaathar mast, which is approimatel25 km from the Alagiyapandiyapuram site, it was found that the Kayatbar wind data (see Figure1) could be used as representative for the wind regime at the site. A comparison between themonthly mean wind speeds measured at Kayathar and Alagypandyapuram is shown in Figure 6.For more detailed analysi of the wind resources at the site, more wind data measured by the mastat Alagiyapandiyapuram should be used.

38. .AndATifht Soil ConditiopL Site 'Te site is located on a hfllock atAlagiyapandiyapuram as indicated on the map in Figure 7. The site is approimate 25 kn fromKayathar on metaled Kayathar - Devarkulam road. TBDA indicated availability of about 550 haof land for a windfarm. Without any source of water, the land has remained unused. The ForestDepartment has taken r.p tree plantations under a social forestry project on some portions of thehill With the help and support of the local Admintration and the Revenue Department it wouldbe possible to acquire the desired amount of land at a price of aprtely Rs 5,000per ha.Since the site and oi conditions are vitually the same as at Kayathar, the cost of foundations forwind turbines and approach roads is asumed to be the same.

39. GridSystm. Devarkulam is connected to the Kayathar sub-station through a 66 kVdouble circuit line. It is located approximately 16 kn away from the Kayathar sustation. The 6MW Kayathar II wndfarm is connected to this feeder. Since the distance between Kayathar andDevarkulam is not far, and since alae windfarm can be eposed to a relatively high load atKayathar, the electical grid system is considered suitable. In addition, TNEB has a long term planto gadualy upgrade this 66 kV tansmiion system to 110 kV. The sub-station at Kayathar hasbeen desiged and constrmted for easy change over from 66 kV to 110 kV. The tap connection tothe Kayatbar II windfirm is provided through a line suitable for 110 kV although it is currentlycharged at 66 kV. Stability will improve once this line is upgraded to 110 kV.

40. windfarm Size Limitions. Suitable land is avaflable for installation of approximatel55 MW of wind turbine capacity. A prliminary lay-out of the farm is shown in Figure 8. Acalculation of the voltage fluctuations carried out for a 55 MW windfarm connected to the existing66 kV bus at Kayathar substation indicates that the windfarm would operate within acceptablevoltage limits. This windfirm could be connected to the Kayathar substation through a double circuit66 kV overhead line; aluminum Leopard conductor could be used. Connection to the existing 66kV bus at Kayathar substation wil demand a minor extension of the 66 kV bus and constuctionof two incoming feeder arrangements. The single line diagram is given in Figure 9.

41. EAnerg Output Production Cost and Generation Value. Tne energ output atAlagiyapandiyapuram is assumed to be identical to the output at Kayathar (see Table 15). Inaddition, a line loss of 9% is assumed. Production costs and generation value are calulated in thesame way as for Kayathar. Results of the cost caulaion are given in Table 17, and results of thevalue calculation are given in Table 18.

Pap 22 of 48

Eig=6: Comparison on Average Monthly Windspceds:Kayathar, Alagiyapandiyapuranit and Thaiayuthu

10 K:iay- w

_Ta l--ThI * ~~~ : Aisgape*Wndynua

. -

U~~~~~~~~4 _ e_

°JL AU SE OC NO DE JA FE MA AP MA JNI1I 19#l

Pap 23 of 48

Eip 7: Locaton of the Abgyaandiyapuram Site

I 2

.'VAWIKOWA. ' *

:.~~~~~~~~~-~4

(3 bteorologica llast

Hap shrgU site at AUlagyapanlyspuram. Scale 1:75000 (approxlately)

U0091 -

tKxx x- W x xxx

X.XX.X X~~~> >X X

X-8 t X X< Xl

.X X< X X., IX X X. l

'x x x xxl.X X X< X

IX X X X< XlI , X X Xm

uzngpu. umesdsk,puledio6,fflr qal joi Inoirl &MuMqpid 1

et 10 te as8d

xxxxx~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

Pap 25 of 48

Eig 9: Line for the Ar Widfn

KAYATHAR S/S

110 kV

3 a 25 WVASk 895 MVA

-_.,'-6- 66 kV

66kV Overheed-lneLeopardL - 20 km

66 kV

2 x 40 IVA66/33 kV

-; 'f-I33kV

1 1iLeopard

Wind farm 0.4 kVAlalyapmdiyapura_

3;°0 N^1V _

4 X 200 kVVT

PA26 Of 48

IabIA :17 Production Cost per MW for the Alag*yapandyapum W idfam

Fi1nacfil Econoi c Anl Fincald beiwuemillion Rs. million Rs Prod. NA WkWh fsIdih

turbines 1S.00 14.40Elctrical Works 1.03 0.82Civil llorks 1.75 1.40Lawd Aclqaistion 0.75 0.60

Total Capftal 18S 17.22

Lelizto Capital 2.18 2.02 1929 1.13 1.05

Am,aal aintnawce 0.32 0.30Aiwil Wae 0.07 0.06

Total Annua1 0W 1.9W 0.36 29 0.20 0.19

Total LOvelized = T2.38 1929 1.3 1.5

TabIe I& Value of Generation from Alagipandyapam, 000 Rs/MW

0-2 2-4 4-6 6-8 8-10 10-12 12-14 14-16 16-18 18-20 2WU22 22-24... ... ... ....... ... ....... . .*0* ..... . . . . . .. .. ..... ......... ..... ..... ..... * ....

Jan 0.02 0.02 0.02 0.04 0.12 0.15 0.09 0.12 0.13 0.05 0.04 0.03Feb 0.01 0.02 0.02 0.03 0.07 0.06 0.04 0.09 0.29 0.29 0.0 0.01Nar 0.02 0.03 O.OS 0.06 0.06 0.03 0.03 0.10 0.25 0.19 0.04 0.02Apr 0.02 0.02 0.02 0.03 0.03 0.02. 0.02 0.08 0.2V 0.24 0.10 0.03Way 0.60 0.60 0.68 0.70 0.70 0.56 0.70 1.40 2.26 1.J2 1.13 0.69Jun 0.53 0.53 C.¢ 0.87 . 1.39 1.40 1.54 1.96 1.96 1.74 1.12 0.4Jut O."6 0.66 0.Th 0.62 0.87 0.87 0.85 1.49 1.8T 1.37 1.12 0.46Aug 0.48 0.48 0.40 0.40 0.48 O.S6 0.81 1.13 1.21 0.81 0.73 0.45tep 0.60 0.51 0.43 0.43 0.43 0.43 0.68 1.11 1.45 1.05 0.85 0.68Oct 0.16 0.16 0.12 0.08 0.08 0.08 0.12 0.29 0.35 O.19 0.17 0.17Nov 0.03 0.04 0.03 0.03 0.07 0.12 0.10 0.11 0.11 0.07 0.04 0.03Dec 0.04 0.05 O.OS 0.05 0.15 0.17 0.13 0.11 0.12 0.09 0.05 0.04

Dally Total Monthly Total, '000 1s.U........................ *....... .......................

Jan 0.87 27Feb 1.00 28Nar 0.88 27Apr 0.88 26May 11.84 367Jun 14.41 432Jul 11.78 365Aug 8.14 252Sep 8.63 259Oct 1.96 61Now 0.79 24Der. 1.06 33

Abnuol Total 1902 wfts t/Wh 0.985

Ama2Page 27 of 48

Thalayqt Site Characteristics

42. Wi esou . Wind measurements have been made on the site since mid-July 1988.Since one full year of data was not avaflable at the time this analysis was carried oui, the wind datameasured at Kayathar are used. A comparison between Kayathar and Thalayuthu data was madefor the months in which data were available from both; this comparison is shown in Figure 6.

43. Land Ailability. Soil Conditions. Site Accesibilift. The site is located approimately10 kn on the northern side of Tirunelveli town. About 250 ha of land is available. The site isindicated on the map in Figure 10. Tne area is flat and virtually barren. A large part of the landis held by the Revenue Department The soil characteristics are similar to those of Kayathar.

44. Gid Systm. A 110 kV double cicuit line from the Kayathar sub-station to KodiyarHydel Plant passes along the boundary of the proposed site. lhis 110 kV line from Kayatharcrosses through the 110/33-11 kV substation at Thalayuthu. There are two 25 MVA 110/11 kVtransformers and one 10 MVA 110/33 kV transformer at the substation. The maximum loads are120 A at 110 kV, 100 A at 33 kV, and 820 A at 11 kV. The short circuit level at 110 kV is 812MVA. The 110 kV line is of Wolf conductor and has a total length of 80 km. lhalayuthu sub-station and Madhavkurechi site are about 10 km and 20 kn from Kayathar sub-station reepectively.The close proximity to a double circuit 110 kV line and the short distance to the main Kayatharsubstations provide a sound electrical grid condition for a large windfarm.

45. Windfatm Size Limitations. Land availability would limit windfarm size to approximately25 MW. Connection of a 25 MW windfarm would result in acceptable voltage quality at the 110 kVbus at the Kayathar substation. The proposed connection of tb, windfarm to the existing doublecircuit 110 kV line would ensure reliable power transmsion. A prelininay site layout is shownin Fiture 11.

46. The internal ditribution of the windfarm would be through 33 kV line, with one 33/0.4kV, 1 MVA transformer for every cluster of four wind turbines. The total output of these clusterswould then be stepped up through two 110/33 kV, 25 MVA transformers and connected to the 110kV grid. A single line diagram for the proposed windfbrm is given in Figure 12.

47. Ener=y Output Production Cost and Generation Value. The windfarm productivity perMW is assumed to be the same as for Kayathar and Alagiyapandiyapuram As with Kayathar, line

osses are assumed to be 5%. Results of the production cost calcation are shown in Table 19;the value of generation is shown in Table 20.

AnAykd Site Characteristcs

48. This site is located near Tenkasi in the foothills of the Western Ohats. It is belowShengottah Pass, through which winds are funnelled to create a high windspeed region in the plainsaround Kayatbar. There are some small hillocks in this area which were observed to be quitewindy. However, there was insufficient land available for a windfarm of more than 25 MW.Furthermore, it is a relatively complex terrain site. In the absence of additional wind data and moredetafled studies, it is difficult to evaluate the site. On the basis of these factors, this site was notconsidered further.

Page 28 of 48

Eire 10: Location of the Thalayuthu Site

N

m Meteorological mast

Map s1hov±ng, site at Talayathua. Scale 1:.65000 (approxluately)

Ppv 29 of48

* EpMJI: PfmibrY Layout for Ihe Shu Wb P29

N

'4~~ /

I~~~~~~~~~~N\' ' /~~

IF I F"

Pap 30 of 48

Eu 12: Lhn Dlgm for the hlayuthu Windfm

KAMATHAR S/S

220 V

3 x 50 EVA220/110 kV

Sk 2535 EVA

-* - - ,iiiii...~iii - 110 kV,

I 110 kV Overhead-lineWolf, double circuitL IS kmb

_ L .-- , I I110 kV

Q <; >2 x US XVA\ PJ\ }110/33 kLV

5 f .r R ~~33 kV

|33 lcV Overt"-lissI operd

1io f a 0.4 lcVTala.ystb J

1.0 NVA

4 X 200 kVWT

Anncu2Page 31 of 48

Table 19: Production Cost per MW for the Thalayuthu Windfarm

Fifnncial Economic Annal Financisl Economcmillion Rs. million Rs Prod. NWh Rs/kWh RO/MA

Turbfnes 15.00 14.40Electrical Vorks 1.3? 1.10Civil Works 1.75 1.40Land Acquisition 0.75 0.60

Total CapitaL 18.87 17.50

Levelized Capital 2.22 2.05 2014 1.10 1.02

Anmual Maintenance 0.33 0.31Anual Waes 0.0? 0.06

Total Annal OIN -- O7i4F 0.37 2014 0.20 0.18

Total Levetized 2.61 2.42 2014 1.30 1.2

Table 20: Value of Generation from Tlayuthu, 000 Rs/MW

0-2 2-4 4-6 6-8 8-10 10-12 12-14 14-16 16-18 18-20 20-22 22-24-- .. .. __.. .. ... ... ..... ....

Jan 0.02 0.02 0.02 0.13 0.16 0.10 0.13 0.14 0.09 0.04 0.04 0.03Feb 0.02 0.02 0.02 0.03 0.08 0.06 0.05 0.09 0.30 0.30 0.06 0.02Mar 0.03 0.03 0.02 0.06 0.06 0.03 0.03 0.10 0.26 0.20 0.04 0.02Apr 0.02 0.02 0.02 0.03 0.03 0.02 0.02 0.08 0.28 0.25 0.10 0.04May 0.63 0.63 0.71 0.73 0.73 0.59 0.73 1.46 2.36 1.90 1.18 1.72Jun O.S6 O.S6 0.73 0.91 1.45 1.46 1.61 2.5 2.05 1.82 1.17 0.67Jut 0.69 0.69 0.78 0.65 0.91 0.91 ? 89 1.56 1.95 1.43 1.17 1.69Aug 0.51 O.S1 0.42 0.42 0.51 0.59 U.84 1.18 1.26 0.84 0.76 0.67Sep 0.62 0.54 0.45 0.45 0.45 0.45 0.71 1.16 1.52 1.0? 0.89 0.71Oct 0.16 0.16 0.12 0.08 0.08 0.08 0.12 0.30 0.36 0.20 0.18 0.18Nov 0.03 0.04 0.03 0.03 0.07 0.12 0.11 0.12 0.12 0.07 0.04 0.04Dec 0.04 0.06 0.06 0.06 0.16 0.18 0.13 0.11 0.12 0.09 0.06 0.04

Da1tX Ttetl, Monthl Total. '000 Rs/1WJan 0.91 28Feb 1.04 29Mar 0.92 29Apr 0.92 27May 12.36 383Jun 1S.04 451Jul 12.03 381Aug 8.50 264Sep 9.01 270Oct 2.04 63Nov 0.83 25Dec 1.11 34

Total Veer 1985 Benf It Re kWh 0.985

Page 32 of 48

DOM WAMio and AssessmetO Sites in Xja=

Utlitv C halcteri8dsts

49. eneral. The Gujarat Electricity Board (GEB) is reponsible for the supplyof electricity in Gujarat In principle GEB is autonomous, but in practice such matters as capitalinvestments, tarffs, borrowmg and personnel policies are under the control of Gujarat StateGovernment GEB has cofLaborates closely with the Gujarat Eiergy Development Agency (GEDA),which is charged with research, development, and demonstradon activities within the field ofrenewable energy, including wind energy, at the state leveL

50. Table 21 shows the GEB's capacity and production by generation source in 1987-1988.Over 11 MW of windfarm capacity is operating in Gujarat. GEB purchases all electricity producedby Gujarat Windfarms Ltd. at a price of Rs L25/kWh as a promotional measure.

Table21: InstaLled Capacity and Gross Energy Productio in Gujarat Elercity Board.

_1987-1988 1990-1 991

Installed Capacity Gross Energy Ingsta"d Capacity Gross EneYI_____ (MW) Prodcn (GWh) (MW) FPodcon (GWh)

Thermal 2501 11371 260 12581(Coal)_ ______

Thermal 655.5 3398 773 337(Oil/Gas) . .

Hydro 305 357 425 .2power__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Share from 27r 251t 702 48SCentral _

Total 3738. 17638 4580 2ZM

Ener. puraed from Centr Stao and ohe oui sores

1) Energy geeated. 125 GWhEnergy purhased and impored. 2,3!1 GWh

51. Power cuts of 5% to 40% are often imposed on all industrial high tension consumersduring the peak season. More recently, an active load m emt has been initated to leIvlindustrial load and shift peak demand off-peak periods without affecting total consumption.

52. Power Demand and Generaion NIeds. here are basicy two load seasons in Gujarat.The high season is fron October to June whfle the low season is from July to September. During

Pap 33 of 48

the high season the daily load curve Is almost flat with veiy few variations, as in Tamil Nadu. in thelow season the diurall load curie is more varied with pronounced peals around 7 am. and 7 pmIhe frequenrc varies around 50 Hz but at peak hours it drops to 49 Hz. 1pical load curves for thetwo seasons are shown in Figure 13.

hmm2Np 34 of 48

ig= 13: TypiW Lod Curves and Windfarm 0m fo Gujar

GUJARAT SITE

- :Ls"oad mid

51 .2500

50 -

489

2000-L,_ _- -wO15001481

300

tOOO - 0___ _ 0 2 4 6 8 10 12 14 16 18 20 22 24

Hour

Obw irMdaofnd *squncyatWh on (mand bws_non

IJy.Daw w.O hnuld ofpAdun ach.d

Ann2Page 35 of 48

8

53. A total of 1,687 captive diesel generating sets with a total capacity of 384 MVA and 66small coal fired steam turbines with a total capacity of 731 MVA are installed in Oujarat by privateindustries. There are no data available on the total production from these captive sets, butaccording to Tata Energy Research Institute (TERI), which has conducted a field survey on non-utility generation in 1985, the average annual usage of captive sets in two other states with powershortages (HAtyana and Uttar Pradesh) was between 1,500 and 3,500 hours/year. On theasumption of a power factor of 0.8 and an annual utlizaton of 2,000 hours of full load for captivesets in Gujarat these figures suggest that diesd captive generating sets account for 614 MWh whichis equivalent to approximatel 5% of the energy supplied to the GEB grid.

54. The current composition of demand is given in Table 22. In Table 23 future generationand demand prospects in Gujarat are presented. Planned additions to generation are disaggregatedby fuel tpe in Table 24. As this table shows, plans for new generation are based on coal fired TPS.GEB is uncertain, however, whether enough coal wdi be avaiable to fil these plans. As aconsequence, GEB has all new schemes in the 8th Five Year Plan (1990-95) based on natural gas.However, authorities with CEA in New Delhi give ssurances that despite of the present shortageof coat it wi remain the most important fuel for power generation in the futue, evea in GujarSt

able: Pattern of Blecticity Consumption in the Area Supplied by the Gujarat Elecity Board

ibe of Commer- Indus. Agri-C nsumption Domestic cial trial cultuil Others Total

% of Total~ Consumption 9 2 40 35 14 100

Yujz~: Oujarat Blectriity Board

Iabz 23: Power Prospects in Gujarat

. _~~~~~"NW NWl

ProJteiod d_Xd 5.40 7,000

l :i*L 2,655 2,250

Exfsting centratsector 817 81t

0nooW r _emGEl 470 800

Istotal 3,942 4,351

Deffcit 1,498 2,449

Sour: Ga.

Page 36 of 48

Table 2: Generation Schemes Under Implementation and New Schemes Planned in Gujarat

Undr MaM hMelplem.ntation Plvnd

Hydro projects 240 NW 3 NW

Lignfte TPS 140NW NWo

Coal TPS 420 NW 2,750 NW

Combinod Cyclelatural asn 123 NV

Natural Gas TPS 1,440 NW

DIetl Cen-Sets 77 NW

Total 800 NV 4,463 NV

55. CallIn of Lvelied Production Costs for a Coal TM. Based on the aboveinformation, coal-fired IW was taken for comparism wt wind power. The assumptions for thecakulation of levelized production costs for a Cal fred TPS are the same as for Tamil Nadu andare given in Table 23 of the main text. Table 25 presents the results of these calculati

56. M= and Vaue of Load SLbgub4. Based on an analysis of GEB load cres, each twohour interval of a tpical day represenig each month of the year is labeUled as B (Base Load), M(Medium Load), or P (Peak Load). These results are given in Table 26. Following the calcuationscarried out for Tamil Nadu, the value of the base load production is valued at variable cos, peakload at total levelized cost and medium load as the arithmetic average of the two.

Table 25: Production Cost from 1 MW Coal Fired TPS in Giuarat

Financial Econom c Anutal Ffnancfal Economicmillion Rs mittfon Rs NPU Rs/kWh is/kWh

Total Investment 17.25 15.00

Levelfaed Invest. 2.03 1.76Fixed 0CA 0.26 0.23

Total Fixed 2:.2 1.w 3859 0.59 0.51

Variable 0ON 0.17 0.15Fuel 2.19 2.62

Total Variable 2.36 2.77 3859 0.61 o.7

Total Fixed + Variable 45 3859 1.2 15

AnxPage 37 of 48

I1 6: 26Tpe of Load Substituted in the GEB System by rme of Day (Base, Medium, Peak)

0-2 2-4 4-6 6-8 8-10 10-12 12-14 14-16 16-18 18-20 20-22 22-24... ... .;.. .... .. . .... .. ..... .... .... ..... ..................................... .. .... ..

Jan B B e N P p N N p p N BFeb 5 a 8 N P P N P P p p NNor B B B p p p N p p p p NApr B B B P P p N P p p p NNOy N N N P P p N N P p N SJun 8 a B N P P N N P P N BJul 0 3 3 3 a 8 3 a 3 8 a 8Aug S 8 8 B B 3 8 3 8 8 8 8sep S B B B 3 S B B 8 B B BOct B a 8 p p p N P p p N 8Nov 3 B a p P p N P P p N 8De¢ S B B p p N N P p P B

GuJarat Dusber Vatus....... ............. .......................

S is variabte costs of cost tired TPS 0.72 Rs/AUhN Is avarae of A sn C 0.97 J/UAhP is total costs of cost fread TPS 1.23 Rs/kWh

57. Mm Grid WeM In th Saurashrm Area of GWarat The main source of power in theSauraia region of Gjarat is from the 400 kV gd substation at Asaj. The power is received atthe 315 MVA 400/220 kV trasormer sbstaion in !etpur. Two 220 kV lines emanate from theJetpur station whih evtualy join to form a rin The ring is interconnected at 220 kV, 132 kV,nd 66 kV. lhe 220 kV line runs in one dieton from Jetpw to Ranavar and the to the Bbatiabsatidon. In the other direction it connects with Gondal and thereafter Limdi Iimdi is not

presently connected with the Asaj substation, but wM be connected through a separate 400 kV lineduring the 8th Pan. From Llmdi a 132 kV line i taken out to Wankaner and rom there toJamnaar. Jamnaar is connected with the Bhatia subtation through a 132 kV line via Sikka. Themajor portion of thsline i insulated for 132 kVbut is currently dcged at 66 kV. A stand-by 220kV line .s also provided between Asaj and Gondal, and Jetpur. Thi feeder comes into operationonl when problems in the 400 kV line to Jetpur occur. During such situations, however, there isa W drep in line voltage, e.& at Ranavar only 170 kV wU be available on the 220 kV line. TbecOmplete transmiiobn is shown in Figure 14.

58. A thermal power plant was commissioned at Sildma in Marcb, 1988, and becme fulyfunctional in Octobe, 1988. The 120 MW output is fed party to Jama_r substation and partly toWananer substation through a 132 kV double circuit line. Besides this plant, a small amount ofpower of about 3 to 4 MW is ocasionally fed to the 66 kV line between Bhatia and Mithapur fromthe captie power plant of Tata chemicals located at Mihapur.

59. The Saurash region has two principa industries There are a number of cement plmtsin this region, each with a power requirement about 10-15 MW. There are also some large chemicalplants in the region.

S. a - -tf

Sv~~~~~~~~~~~~~~~~~~~~~~~~~~~W0" - N s-.''* S>!v > ; r r 1+\es Mh . fi ..OWER MA

ON 5 4"4^R^t *ttt 1' ;r , 2i+ 1-

Annex-2Page 39 of 48

60. As in much of the rest of lndis, Gujarat s tantly short of power, and there arefrequent power cuts, often as high as 40% of their connection application, imposed on industries.Given this situation, a number of private industries have set up their own captive power plants atsizes of 5 to 10 MW. It b estimated that as of 1989, the peak demand in the Saurashra region wasaround 400 MW and but the maximum supply was only around 250 MW. During the agriculturalsaason the most severe power cuts are imposed on industries to meet the requirements for deepwell pumps. It is felt that if the requirement of 100,000 more pump sets and new proposals forcement industries are to be considered, the total power requirement in the Saurashra region wouldbe about 700 MW.

61. A major part of the line s on the coasal area and several earth faults ocur when themoisture content and saliity in the air increases during the months of April, May, and June. Duringthis period shut-downs are taken at reglar inteivals to wash the line insulators The total ring mainsystem in the Saurash region cannot be considered stable in view of three different voltage levelsof transmission e.g. 220 kV, 132 kV, and 66 kV. In case of filure of the 220 kV line, the entirepower requirement cannot be met through the 132 kV and the 66 kV lines.

62. To pardaly overcome the problems of insulation failures, GEB proposes to charge the lineat half the voltage for which insulation has been provided. GEB has also used a slight overinsulationin coastal areas to compensate for saline deposition. Reduction of the charging voltage means that220 kV lineswMl be charged at 132 kV and 132 kVlineswMl be dged at 66 kV. Thiswould meanthat the tnsion voltage would be maximum 132 kV which would in turn increase the powerloss and create high voltWe drops. In addition, tap changers are manually operated and steadyvoltage levels cannot be maintained. In major load centers the voltage at 220 kV and 132 kV lvelvaries from + 10 % to -30 % due to the cumulative effect of these factors.

63. Ihe nearest substation to the two sites is Bhatia The Bhatia sbstation is connected withthe Ranavav 220kV substation on one end through a single circuit 132 kV line (insulated for220kV). A 20 MVA 132/66 kV transformer i installed at Bhatia The average peak load is 9MWon the Bhatia substation. Ihe present maxmum and minimum load on the 20 MVA transformerare 12 MW and 8 MW respectively. Voltage of the 132kV sytem at Bhatia vary between 140kVand 108kV. During the night when the load is less, the voltage through the 220 kV feeder increasessubstantially. To correct this situation, the 220 kV feeder is disconnected, and the swpply at Bhatiais received from Jamnagar through the Khambalia feeder.

64. Most of the measuring instruments of the control panels of sub-station were not operatingproperly at the time of the mission's visit. The manual on-load tap changer (OLTC) for the 20MVA trandormer (out of order at the time of the mission's visit) is now working satisfa ily.

63. Four 66 kV feeders emanate from the low voltage side of the Bhatia substation. Ihesefeeders are connected as follows:

(a) Feeder to Veraval and Dwarka:

This feeder is also connected to the factoy of Tata chemicals, who has a captivepower plant and occasionally supplies 3 to 4 MW of power to the grid. The

Annem2Page 40 of 48

maximum load on this feeder is about 2 MW without Tata chemicals

(b) Feeder to Khambalia, Slkka and Jamnagar:

The major portion of the feeder is a 132 kV line, though now charged at 66 kV. Themaxdmum load on this feeder Is about 10 MW, out of which 6 MW is the local loadat Khambalia and 2 MW for GSFC factory near Slkka.

(c) Local Bhatia Feeder

This feeds the local load near Bhatia through a 5 MVA, 66/11 kV transormer. Themaximum load on this trnsformer is about 2 MW. Thi transformer will also beconnected to 1.8 MW Okha windfarm. TIis windfarm is likely to have another 1.3MW added soon.

(d) Feeder to the edisting 10 MW Lamba windfarm.

66. In view of frequent earth-fault trippings during the humid season, GEB proposes to feedBhatia sub-station at 132 kV instad of 220 kV from Ranavav, and given the lower load, maydownsize the S0 MVA transformer to 20 MVA. Constuction actiities are going on to completethe 132 kV line work between Slkka and Jamnapr on the Khambalia feeder, and once this workIs completed, Bhatia sub-tation wil be connected with Ska generating station and JamnagarSubstation trough a 132 kV line. (Note: As indicated in pam. 63, this work has been completed.)

67. In conclusion, the grid in the Saurashra region is quite unstable and may net be suitablefor interconnection with larger windams Hih voltage drops, manual voltage boost-uparrangements, frequent power shortages, and, at other times, inufficient load, are not favoableconditions for feeding large scle windpower into the grid.

68 A second 120 MW thermal power plant has already been approved at Slkka, and planningis underway to install two additional 210 MW thermal plantL A 600 MW thermal power plant isalso under consideration. Furthermore, new cement plants have been proposed, and by supplyingpower to 100,000 agriciutural pump set, the load in this region wil increase. Once these capacityincreases take place and load grows, conditons will be far more favorable for the interconnectionof this grid with a large windfarm.

69. In the meantime, since the system load of 250 MW is being distributed from Jetpursbstation, any windfarm additons should be fed as directly as possible to the Jetpur substation.Rather ta connecting with the Bhatia substation, the deign of the Iamba/Navdara windfaminludes the consbtuction of a 220/66 kV 80 MVA substation which wM allow the windfarminterconnecion to by-pass the Bhatia sbation and connect directly to the 220 kV line at theRanavav substation.

Annex-Page 41 of 48

Lamba/Navdarm site -Characteristics

70. The two sites, Lamba and Navdara, are adjacent to each other and located along thecoasdine of the Arabian Sea. Because of their proximity to each other, the two sites are assessedjointly.

71. Wind Resource. Wind resources estimates are based on wird data measured at ameteorologcal mast at Harshadt approximately 15 km southeast of the site. In general the terrainsurrounding the mast is simiar to the terrain at the site. Wind data for two full yearst 1987 and1988, have been used for the estimation of the annual energy resources. It has not been verifiedwhether the estimated wind resources correspond to an 'average year'. The monthy mean windspeed and power density have been based on data measured in 1988, and are shown in Figure 15.The high wind speed period is from March to August. The annual mean windspeed for that yearis 5.4 m/s at 10 m agl

72. and Avdabit Soi Condition and At Lamba a 10 MW windfarm hasbeen consructed as part of a Danida-funded project. An extra 400 ha of land has already beenprocured by GEDA beside the 10 MW windfarm. Some parts of this area are low-lying and not suit-able for wind turbine placement. Ihis ara is on the southern side of the 10 MW farm and facingthe sea on the west. Tne 10 MW farm begins from the boundary between Lamba and Navdara Vil-lages.

73. Navdara village is on the northern side of Lamba. Ihe Navdara site is a stretch of land7 km long and 1 kn wide facing the Arabian Sea. The 35 m high Navdara light house is locatedabout 4 km from the northern side of Lamba site. Te 7 km setch is partally ging land andparially Govt waste land. The waste land area is adjacent to Lamba village. A 2.5 km long stretchfrom Lamba towards Navdara light house would be ideally suited for windfirm siting withoutdisturbing the light house and also without encoching on the grazing land.

74. The approach road to Lamba windfarm is off of the Porbandar-Dwarka Hwway. Thesame road can be used for the combined Lamba/ Navdara site. Detailed soil tests have beenconducted at Lamba for thc foundations of 200 kW wind turbines, and the resuts have indiatthat the soil is itable. The same soil conditions are expected for the combined Lamba/Navdarasite.

75. WindfannrSize Limitad To avoid unnecessary line losses and further t on gridcomplications, a new 220/66 kV substtion would be established at Lamba to %cilitate connectionof the present 10 MW farm as well as the proposed farm. The voltage drop calculations indicatethat maimum 57 MVA (approimately 50 MW) of windfim power can be fed on the 220 kVfeeder from Ranavav resulting in a voltage drop of less than 15%. A voltage drop of more than 15%could cause further deterioration of tan on grid performance Under normal conditions this50 MW of windfarm power will be consumed by the Bhatia and Ranavav sbstations, and underlocal low load conditions would suppF Jetpur. CanTying windfarm power in 66 kV lines up toBhatia wM mean unnecesay line 1as in the 20 km run; therefore a new 220/66 kV substationwith a 80 MVA transformer is proposed at Lamba as part of the prospective windfirm. In athe foLlowing conditions should be fulied:

An=2Pop. 42 of 48

lIgu= IS: MoL*y Widapeeds and Wind Powe Desty at Hudhd

I0 -1000

-- 2 !-- '--_Powe. fty

d7 700

.5~~~~~~~~~~~~~~Go

t2 ,..200

I ~~~~~~I100

JA FE MA AP' MA JN'JL'AU'SE 0C NO'DE

Month, 1988

Anna 2Page 43 of 48

(a) the voltage regulator for the 400 kV Jetpur substation must function properly.Voltage drops of more than 15% would be unacceptable in such an important trans-mission line;

(b) the quality of worL and materials on tWe existing unsmission lines should baimproved to avoid faults and break downs;

(c) the 132 kV voltage level should not be reduced to 66 kV because it wil limit theshort-circuit levels and increase losss; and

(d) the dbtribution system in Saurashra should be evaluated to identify an improvedmain distrbution system, voltage levels, and means for control of voltagefluctuations.

76. Given that suitable land is available at each site for a 25 MW windfarm, a combined totalof 50 MW is proposed. A preliiunry site layout is given in Figure 16, and a line diagram of theelecical works is given in Figure 17. A total of 250 200 kW turbines are proposed, dvided evenlybetween the two sites.

77. E Qneg51nutp Monthly enery output per MW installed is shown in Figure 18. Theseasonl peak output is during the period from May to AugusL Total annual enerr output is 2010MWh/MW, ecluding line losses, which corresponds to a capacity facor of 0.23. Table 27 indicatesthe distribution of each month's output by two-hour period of the day. Peak output is in theafternoon.

Table 27 Diural Output by Two-Hourly Period as a Perentage of Total Monthly Output

0-2 2-4 4-6 648 8-10 10-12 12-14 14-16 16-18 18-20 20-22 22-24

Jan II 12 12 10 10 10 7 4 4 5 7 8Fab 10 12 10 a 7 5 5 6 8 11 10 10Nor 11 11 8 6 5 4 5 8 11 II 9 9Apr 7 fi 6 5 5 6 8 12 14 13 10 8Nay 7 7 6 5 6 7 9 11 12 12 10 8Jun 6 6 5 5 7 8 11 13 14 12 7 .iJul 7 7 8 8 8 8 9 10 10 9 8 8Aug 8 8 8 8 P 8 8 10 10 9 8 7Uep 6 8 8 7I 8 8 10 12 11 8 7Oct 8 7 7 5 4 S 7 11 14 12 11 9Nov 10 8 6 10 10 10 9 6 6 7 9 9De 9 5 5 6 15 16 12 7 5 5 6 9

78. Production Cos and ProducionVa. For Lamba/Navdara, a line loss of 8% is assumed.Based on the assumptions noted above and in Table 23 of the main test, production cost reultsare presented in TabMe 28. Table 29 shows energ production in MWh per MW of instaled cactyby two-hour period. Mliplying Xt matrix by Table 26, the ype and cost of load displaced, the

Page 4 of 48

benefit of the Lamba/Navdara windfanm X derived.

Mocha site haraceriti

79. The Mocha site is located approximatey. 50 km southeast of Porbandar and 2 km fxom thecoastine. The area at the site islimited to between 1SO and 200 ha, correpondingto 15 to 20 MWinstalled capacity. Discussion with the local people indicated that it would be difficult to acquirethe land as it is used for grazing. Due to the these circunm ces this site was dropped from furtherconsideration.

Pge 45 of 48

!ig 6: P6elimay Site Layout for LaibaNavda

X X XiI Xllxxx X x*xlx x xxxIxxxl Ixx XJ XX x x >X

Ix x x' x x

Jx x xI xIxI x xl

NAVDARA LAMBA

Page 46 of 48

MIauz41: LXna Diam of Electic Works at Lamba/Navdara

TO RANAVAV S/S

TO BHATIA S/S

220 kV

80 MVA

220/66 kV

- - - - - 66 kVY

66 kVY 66 IcV 56 kV 66 kV Wind farm'Lamba 11132 VT

10 3 o A 0 loWA 10 WVA O310 A pi 26.4 NW

1 11 kV 11 IcV 1T k 1k11 kV

~~~~~~~~o m T XWtind farm

*11 kV flavdara'II kV ~~~~~132 VT

PI a 26.4 W

S- 32.0 MVA

1.0 IIVA 166 ° 280.0 A11/0.4 kY

Total P. - 57.6 KW

A2sLPage 47 of 48

able 28: Production Cost per MW for the Lamba/Navdara Windfam

Financial Economie Annual Financial EcoNaircmillion as. million Re Prod. PUh Rs/kWh Ws/idA

Turbines 16.13 15.48Electrical Uorks 2.2? 1.82Civil Works 1.75 1.40LcnJ Acquisition 0.38 0.30

Total Capital 20.52 19.00-

Lwvelized Capital 2.41 2.23 18S0 1.30 1.21

Annual Maintenance 0.37 0.35AnmuaL Ves 0.07 0.06

Total 4nnuat 0&N 0..144 -671- 1850 0.24 0.22

Totat Levelized 2.85 2.63 1850 1.5 1.42

Table29: Producdon by Wo-Hour Intewval of the Day at Imba/Navdara, MWh/MW

0-2 2-4 4-6 6-8 8-10 10-12 12-14 14-16 16-18 18-20 20-22 22-24=... ... ... . .. .... ... .... ........ ..... ....... ..... ..... ... ..... ..................... .. .... ..

Jan 0.36 0.39 0.39 0.32 0.32 0.32 0.23 0.13 0.13 0.16 0.23 0.26Feb 0.44 0.53 0.44 0.35 0.31 0.22 0.22 0.26 0.35 0.48 0.44 0.4"Mar 0.61 0.61 0.45 0.33 0.28 0.22 0.28 0.45 0.61 0.61 0.50 0.50Apr 0.36 0.31 0.31 0.25 0.25 0.31 0.41 0.61 0.71 0.66 0.51 0.41May 0.44 0.44 0.38 0.31 0.38 0.44 0.57 0.69 0.76 0.76 0.63 0.50Jun 0.54 0.54 0.45 0.45 0.63 0.72 0.99 1.17 1.26 1.08 0.63 0.54Jul 0.96 0.96 1.10 1.10 1.10 1.10 1.23 1.37 1.37 1.23 1.10 1.10Aug 0.54 0.54 0.54 0.5' 0.54 0.54 0.54 0.68 0.68 0.61 0.54 0.48Sep 0.28 0.37 0.37 0.32 0.32 0.37 0.37 0.46 0.56 0.51 o.37 0.32Oct 0.22 0.20 0.20 0.14 0.11 0.14 0.20 0.31 0.39 0.33 0.31 0.32Nov 0.25 0.20 0.15 0.25 0.25 0.25 0.22 0.15 0.15 0.17 0.22 0.22Dec 0.18 0.10 0.10 0.12 0.30 0.32 0.24 0.14 0.10 0.10 0.12 0.18

DaiLy TotaL Pbnthty Total, IWA/lw........... .................................

Jan 3.24 101Feb 4.38 123Nar 5.58 173Apr 5.09 153Nay 6.29 1f9Jun 8.98 269Jul 13.69 424Aug 6.81 211Sep 4.63 139Oct 2.79 86Nov 2.48 74Dec 2.01 62

Annual TotaL 2011

Pap 48 of 48

Table 3: Value of Poer Geneated by Lamba/Navdars Windbm, 000 Rs/Mw

0-2 2-4 4-6 6-8 8-10 1012 12-14 14-16 16-18 18-20 20-22 22-24

Jin 0.24 0.26 0.*26 0.29 0.3? 0.3? 0.20 0.12 0.15 0.18 0.20 0.1?Feb 0.29 0.35 0.29 0.31 0.35 0.25 0.20 0.30 0.40 0.55 0.50 0.39Nor 0.41 0.41 0.30 0.38 0.32 0.25 0.25 0.51 0.69 0.69 0.5? 0.45Apr 0.24 0.20 0.20 0.29 0.29 0.35 0.3 0.69 0.81 0,45 0.5 0.3Nay 0.40 0.40 0.34 0.36 0.43 0.50 0.51 0.78 0.85 0.I5 0.71 0.45Jun 0.36 0.36 0.30 0.40 0.71 0.11 0.89 1.05 .4Q 1.22 0.56 0.36Jul 0.63 0.63 0.73 0.73 0.73 0.73 0.82 091 0.9 0.82 0.73 0.73AUO 0.36 0.36 0.36 0.36 0.36 0.36 0.36 0.45 0.45 0.41 0.36 0.32Sep 0.18 0.25 0.25 0.21 0.21 0.25 0.25 0.31 0.3? 0.34 0.25 0.21Oct 0.15 0.13 0.13 0.16 0.13 0.16 0.18 0.35 0."4 0.38 0.28 0.1?Kov 0.16 0.13 0.10 0.28 0.28 0.28 0.20 0.17 0.17 0.20 0.20 0.15Dec 0.12 0.07 0.0? 0.14 0.34 0.29 0.22 0.16 0.11 0.11 0.11 0.12

Daily Total Nonthly Total, '000 ROM.. .... ............ ........................

,an 2.80 87Feb 4.16 11mNor 5.22 162Apr 5.12 154NOy 6.5? 204Jun 8.44 253Jul 9.0? 281Aug 4.S1 140$SP 3.06 92Oct 2.43 aNov 2.32 70Dec 1.05 s?

Ardtl Total 1697 Uerflt no/Mm 0.91?Y _u~

Ann-Page 1 of 8

ANNEX 3: THE ECONOMIC EVALUATION MODELS

1. The economic evaluation utilizes considerably more iformation and takes into accountmany more factors than the screening analysis For instance, hourly windspeed and system loaddata is used, construion lead times are taken into account along with the cost of unserved energy.To handle this additional complexty, three modeb were developed to conduct the economicevaluation:

(a) the windfarm production model, to determine total windfarm output at the busbargiven averae hourly windspeed data by month, orography, windfarm configuration,wind direction, etc.

(b) the windfim capacity responsibility model, to assess the windfarm's contnbution tosystem capacity; and

(c) the economic analyis model, to determine the benefit/cost ratios of bothconventional generation technologies and the windfarm given the performance ofthes units wihin the context of the entire system.

The Windfarm Production Model

2. The windfim producton model calcuates the average hourly production by hour of theday for a windfrm for each mondL To get the annual prodution, the model is run twelve timeswith different sets of monthly average windspeeds. The model giv the combined productionfrom the proposed windfarms at Kayathar and Thalayuthu.

3. Hourly windspeed data are used to calculate the monthly average windspeeds for eachhour of day. Wmdspeeds are not constant over an entire hour, furthermore, windspeeds during thesame hour on different days may differ greatly. Because small variations in windspeed may havelarge effects on power output, the model uses the Weibull distributon to more accrtely moddthe distribution of windspeeds for a given hour during a mnnth. The shape and scale parametersof the distribution are derived from observed windspeed variatons and mean windspeedrespecively. Windpeds are extrapolated to hub-height asuming a logrthmic profile of windsheer which takes surface roughness into consideration.

4. The Weibull wndspeed distrbution and the turbine power curve are used to estimate thegross hourly energy production of a turbine for each hour of one day represeting the month. Arrayefficiency, gid aaiabil, turbine avaiabUity, air density correcdon and power losse are takeninto account to obtain the net hourly production per turbine from the gross production of anindividual turbine. Net turbine production is then multipied by the number of turbines to give netwindfiam producin The monthly average of specific production (MWh/MW) for a pankularhour of the day for both the sitesis then obtained by summing up the net production of the sitesand averaging over the total turbine capacity.

AMMPage 2 of 8

The Wnkdfum CWapi Be Model

5. Capacity resposi*bflity is a measure of a technologys ability to reduce unserved energy,or eonversely, to contribute to system capacity and thereby increase reliablity. For every hour ofthe year there is a non-zero probabiity that because of either generation failures or high load, thereWI be unserved energy. Consequently, expected unser red enegy is non-zero for oach hour of theyear. Capacity responsibility of a generation addition Is defined here as the reduction in expectedunserved energy given actual operation of the unit divided by the reduction in expected unservedenergy that would occur if the generation addition could operate thr'ughout the period in questionwith a 100% capacity factor. For dispatchable technologies, the capacit respons'bility woud beequal to the availability of the unit, assuming that forced and planned outages occur independentlyof the incidence of unsenred energy iv that period. (The capacity responsibility can be greater thanthe capacity factor since it is asswned that even if a unit is not operat'ng at the time a loss of loadoccurs, it can be brought immediately on-line, so long as it is available. ie. not out of sevice as aresult of a forced or planned outage. f the unit is operating, but not at its nominal rating, whena loss of load occurs, it is assumed that it can be brought up to its '-Jl nominal output imMediately).

6. For non-dispatchable technologies such as wind power, capacity responslt dependsupon the match between windfarm output an, the temporal ditbution of cipected unservedenergy. During certain times of the day or season, perhaps durin peak periods, xpected unservedenergy is greater that other times. If windfarm output coincides with these periods, then its capacityresponsibt, and hence capacity value, is greater.

7. Ihis methodology assumes that in a capacity-constrained stem such as TNEB, the portionof annual total expected unserved energy ocring in any hour is proportonal to the differencebetween the frequency-corrected system load and the actual load for that same hour on the peakday of that month.

8. The model first derives the capacity responsibility of a windfiam for each month on thebasis of hourly profiles of unserved energy, ie. the difference between frequency-corrected andactual load 24/. and windfarm output. The capacity responsibility for that month is the sum over24 hours of the products of the hourly ratios of actual windfarm output to nominal c ity and thenormalized difference between actual and frequency corrected load. ITe model then derives annualapacity responsibiit by multiplying monthly capacity responslties by the respective monthlyweights, which are calculated in the same way as the hourly weights The mathematical formulationfor evaluating capacity responsibiity is given in Appendix 1 to this Annex.

Mhm EcQnomi Am s Model

9. The economic evaluation model compares the costs and benefits of windfarm with the cotand benefits of three other technologies: combustion urines, combined cycle plants, and coal based

?A/ ITe fequency-orrected load i the load whih would result if the actual load were met a50 Hi For the rare times when system frequency exceeds 50 Hz, the difference betweencorrected and actual load is taken as 1 MW for analytal convenience.

Anne 3Page 3 of 8

thermal power stations. 'Me model uses the following input data:

(a) System data, e.gload, capacity mix includi transacions, etc.;

(b) Cost and performance dcarerstks of the technologies under consideration; and

(c) Other economic parameters, such as discount rates, the cost of unserved energy, etc

10. Given this data, the model caklates the benefits (energ and capacity benefits) and costs(capital and operating) of all technologies and compares their benefit/cost ratios. Ener beneftare calulated using a modified production costing simulation in which the value of a new unit'soutput is given in terms of the cost of the energy it displaces. Capacity value of a new unit isassessed relative to a reference unit adjusted for capacity responsbility. Capital and operatng costsare evaluated using a revenue requirements approach. Following is a brief description of the model

11. The base year is the year for which benefits and costs are reported. In this study, 1990is used as the base year. All costs that may be incurred in future years (capital investment, fixedO&M costs, variable O&M and fuel cogst etc.) are discounted back to the base year, takg intoaccount real cost escalation rates.

wmwg v:

12 Simulations are performed for two years: 1992 and 2000. lhe first year (1992) is the yearin which the technology with the shortest lead time is expected to come on-line, asumingconstuction begins in the base year (1990). The second simulated year (2000) is ihe last year forwhich benefits and costs asociated with different generation technologies can be reasonablyestinated.

13. Given the hourl load prodlas 2S/, the hourly power purchases ?A/, and the hourlygeneration from bydro power stations 27/ for the base year, 1990, and the corresponding

2j/ The actual load in MW at the acual grid frequency.

X/ ?ower purchases indude TNEs share from coal-fired, lignite-fired and nudear powerstations in the central sector, as well as rts to/imports from other states which

nstitute the southern regional electriciqty stem.

27/ This is estimated in the model given the total annual hydro power generation, and saeof generation during two six-month periods (January to June, and July to December).Houry hydro power geerati is assumed to shave the peak load, en asumption that wasconfirmed as realstic by the NEB. Appendix 2 of this Annex summarizes the almithmused to caculate the hourly hydro power generation.

Page 4 of£8

forecasted annual growth rates for each 2fi/t the hourly contributions of thermal powerneration are calculated for each month of the two simulated years, 1992 and 2000.

14. Supply curves for thermal power generatin for 1992 and 2000 are computed fromavailable data on ystm expansion plans and variable fuel and non-fuel operation and maintenanoecosts of the thermal power stations. Power shortages are assumed when the system load exedsthe system total generation capacity (from thermal power stations, power puruaes and hydropower stations).

1S. 'he production simulat;^- '," nnt -'-,i,de spirning reserve effects of windfarm oprationbecause windfarm penetration was quite small in tems of the siz and operating tolerane of thesystem, and because incremental heat tLtes were unavailable for thermal generation on the TNEBsystem.

16. Given suppl cuves, the marginal cost of energy is calcued as the largest variableproduction cost (fuel plus non-fuel variable opeating costs) of all generation resources simulatedto meet the load. These calculations are performed for each hour of each month in each simulatedyear (1992 and 2000), and include average transion and ditibution losss inured in theTNEB sstem. When power shortages are simulated (when system load exceeds sytem totalgeneration capacity), the marginal oost of energy is the cost of unserved energy. Margn enerVcosts between 1992 and 2000 are interpolated using the geometric growth rate between the twoyears. If the rate between these two years is negative (as might oocur if there is a arge amount ofunserved enery in 992 but little in 2000 due to capau:ty additions) or ff the rate i greater thanthe real escalation rate for the cost of unserved energ (as might be the case if the amount ofunserved energy increases considerable between 1992 and 2000) then the rate beyond 2000 is fixedat the esaltion rate of the cost of unserved energy. his is typically taken to be the real esalationrate for diesel fueL Otherwise, the 1992 to 2000 gowth rate is asumed to continue indefinitely.

Cos of unsene energ

17. Customers suffer damages from outages through several ways indluding lost production,equipment damage, increased labr costs, lost leisure time. When service reliabfiit is poor enougb,customers may be prompted to buy emergency backup soures like diesel generators or batteries.

18. There are at least two ways to determine the cost of unserved energy, or customer outagecosts: one can try to measure the actual losses that a customer sustained during an outage, or onecan measure how much a customer would be wling to pay to avoid an outage. Several induswland commercial cstom rs in the TNEB service area have invested in diesel standby generators to

2/ Growth rates for annual elecricity requirement, annual hydro energy, and power purchasesare available for TNEB. These are used to project future hourly load and power purchaprofiles. It is assumed that the hourly load curve shape, hourly hydro generation, and thehourly proffies of power purhases remain unchanged from 1990 to I992 and 2000.

Page 5 of 8

mitiato the effects of frequent supply interruptions. In this study the cost of captive diesdgeneration has been used as a measure of cutomer osttage costs since if outage coda were less,fims would not pnrchase these generators. On the other hand, i the cost of actualy doing withoutelectriity were more, these costs could be mitigted by the purchase and operation of a delgenerator.

ISwvalues (at how" :

19. The value (or benefit) of energ delivered to the TNEB power system is the TNEBmarginal energy cost. The hourly energy value of a generation resource is the product of the systemmarginal cost of energy and the resource generation outpat.

20. Ihe average value of wind energy output (in Rs/KWh) in any year is calulated as thesum of all hourly energ values divided by the total wid energy in that year. The average energyvalue of the conventional technologies depend on the capacity factor of the technology. Since thesetechnologies are dispatchable, their energy value at a capacity factor, X, is based on the system Nlargest energy values, where N is the number of hours that correspond to a capacity factor X Thisassumes that the technology is dispatched during the hours of highest system marginal energy cost(i.e. highest energy value). Value accrued in any year is discounted back to the base year. Theprent value of all future benefits is then levelized to give a single energy value per unit of output.

21. Ihe value of short construcion lead times is taken into account by the fact that eneryis displaed sooner and therefore the cost of enag displaced at the margin is discounted less. Forexamplet compared to a unit which is operational in year 8, a unit which is operational in year 2wi generate additional benefits equal to the discounted value of energy displaced at the margin foryears 2 through 8. In the case of the TNEB system, this is partclarly significat because ofprevalence of cost unserved energy.

22. The value (or benefit) of capacity available to the TNEB power system is the TNEBmarginal capacity cost, ie. the TNEB cost of providing additional generation capacity.The capacity benefits associated a new generation technology (in Rs/KW) is the product of theTNEB avoided capaity cost and the effective capacity of the technology. For wind, the effectivecapacity is calculated by the capacity responsibility model described above. Ihe description of thecpacity responsibility model also noted that for conventional technologies the effective capacity iscalculated as the derated capacity of the technology, where derating is used to adjust for scheduledand forced outages.

23. The total value (or benefit) of a resource is the sum of its levelized energy and capacityvalues calculated from the first year of operation (base year + lead time) through the end of itseconomic life time. For this smmation, it is assumed that the construction work begins in the baseyear (1990); therefore the last year for summation corresponds to the construction lead time plusthe economic life span.

Page 6 of 8

Bene :t to cost Rt:

24. In order to determine the leastt alternative, all costs and benefits asciated with eachalernative ae identified for the alternative's economic life. Since a variety of costs and benefitsoocr at various tdmes through the considered planning horizon, a single number evaluation of agcosts and benefits would be far more usefi than the complete time series of costs. Tbus, theBenefit to Cost Ratio (B/C) or the ratio of the levelized annual benefts to the levded annualcosts is calculated for each alternatie; B/C ratios of all alternatives are then easily eopared TMekwvbd bewl/cao Ado apprach is the approach most commonl used in power system expansionplanning to compare alternatives on the basis of value per unit of cost.

A3-

Appendix 1: Formulaton of the Windfam Capcity Responsiity Model

(1) Compute normalized frequeny correted load minus actual load for each hour andmonth.

a - sMth qf the yearh - howr of t dayPYL, - J;eqewy-coretd lead In mt m howr hALwA - acs led hI mnha x, how AND,1 - he mont nomal*d dtOmce bhow euAwvur-cmred

ad acba lad hi Mt A , hw h

Note: f the difference betweon frequency-coed and actual load is less than or equalto 0, then It is assumed to be 1.

(2) Compute monthly wet

%*i.dst heew w*bk trW., -th minght for AMAnth

(3) Compute windfarm capacity resosilit in MW per MW of intalled capacity.

WCR - ND.A xW O,,) x W.)

w** de wvw madable ar.1K, - wu_wo uWt per MW aifaociy in u" , ahow A

- I N - whi4fr acquc reei

Page 8 of 8

Appendix 2: Computation of Hourly Hydro Oeneration

(1) Compute bydro power generation in each six-monthly period.

HG, - AHG xfwhe.p - Jda for twe six month pei Joy to Jww or Jab to DecmberI, - ecdo of toul hyho geeamio whih ocw in period pANG - toot anial hydro geneHGO hyo geao in perod p

Note: fl - 12f,

(2) Compute the hourly profle of hydro generation for each of the six months in a given period.

HG~ _ AL,~-B KlW) G,~E4L -BLW.)'3OO

whe e nemw varabls are:BLo_ - bas load powr in month m, how h2 - oxent wch gu hydo disath on an hou4y bat

Notes: (a) The months referenced by the month index m must belong to the relevant penodreferenced by the period indexp.

(b) The hydro dispatch exponent E is determined by conducting iterative simulationruns. An acceptable value for E is one which: (i) the resulting hydro output for eachhour in each month does not exceed hydro capacity (ii) the resulting share ofgeneration computed for each month does not differ signifcantly from TNEB data;and (ith) therthemal generation levels requWred do not vy greatly by hour withina month. Tbis model was introduced because hourly bydro generation profiles werenot readily avaiable from TNEB.

(c) A fictor of 30 is inluded to adjust houry profies for one day in each of six monthsto match the total hydro generation for a entire six month period specified by HGr

AnnaA Page 1 of 14

ANNEX 4: INPUIS TO THE ECONOMIC EVALUATION

Inltroduction

1. TNEB generates power from its thermal and hydro power station as well as somewindfanns. It also purchases power from central sector power stations 22/ which are:

(a) lignite based thermal power stations operated by the Neyveli Lignite CorporationL);

(b) the Madras Atomic Power Plant; and

(c) Ramagundam Super Thenmal Power Station of the National lhermal PowerCorporation (NTPC). TNEB also purchase power from the Madras Refineries LAdIn addition, as a member of the Southern Regional Electricity Board, the TNEBalso has import/export arrangements with the other states of the region: AndhraPradesh, Karnataka and Kerla.

2. This annex summarizes the data collected for the TNEB system for the economicevaluation of windfarms at Kayathar and Thalayuthu.

Load Forecast and System Expansion

3. Power demand forecasts are revised every two to three years in Idia. The mostcomprehensive forecasts are those of the Power Survey Committee (PSC). The PSC has beenestablished by the GOI's Department of Power under the Central Electicity Authority(CEA) 3/.

4. Load forecasts from the PSC's thirteenth Annual Power Survey (APS) are given inTable 1. Thbis table also presents the load forecasts prepared by TNEB which wfll be discused

22/ Central sector power stations are owned and operated by utilities which supply power to allstates/union territories which constitute the regional electricity grid system. The sales fromeach central sector power staion to each state/union territory are as per some pre-determined shares.

Lo/ Various electric power utblities are represented on the PSC. The normal practice is thatstate electicity boards (SEBs) and other power utlies responsible for generation anddistribution of electrc power in a paular state/union territory, prepare a load forecastfor their respective state/union territory, and submit it to the PSC The PSC then reconcilesthese load forecasts with the national level forecasts prepared in-house in the CEA.Normally, this reconciliation process involves a downward revision of the load forecastmade by the SEBs and other utilities.

A4APap 2 of 14

during the preparation of the PSCs fourteenth APS 31/. Table 1 also indicates that TNEBsprojections for the fourteenth APS are higher than those of the thirteenth APS. lhe demadforecasts of the thirteenth APS show total energ requirements increasing at a rate of 8.7 per cantper annum during the ten year period 1990 to 2000.

5. As of 31 March 1990, the instaled capacity in the TNEB system plus 7hEWs shae ofcental sector projects was 5475 MW. According to present plans, the generating capact atTNEB's command wil increase by 1995 MW during the Eighth Five Year Plan (FYP) perid (1990to 1995). Tbis is as much as 36 per cent of existing capacity and indludes TNEB's central sectorshare. In the Ninth FYP period (1995 to 2000), TNEB'a planned capacity additions amount to 2503MW if its anticipated share from new central sector projects (which are not yet commited) isincluded, and 1480 MW if this tentative estimate is excluded. These additions include hydro,thermal, nuclear and windfarm capacities.

6. Table 1 compares the demand forecasts to the year 2000 with projections of planned andeffective installed capacities. The effective installed capacity takes into account the forced outagerates (FOR) and the maintenance outage rates (MOR) for the different tecnologies i thegeneration mix Data on FOR and MOR are presented later in this Annex 2/. Table 2disaegates TNEB's planned capacity additions by type of generation.

Table 1: Demand Forecasts and Planned Capacities, MW

1990 1995 2000

*~1 1213tth OPS 2929 S792 858 "Proposed by TIES for the

14th APS 6345 10.191

Ptanne Instald% Dct-x" n csector share S47i 7470 a9S0

In 9th P per10dIncludinc central sector share S475 7470 9m

In 9th FTP period

Effectlfz I st edCDCtr c ral share 4050 5421 6455

in 9th FYP periodIncluding central sector share 4050 S421 7229

in 9th FYP period

correspo irng to an enugy reqPirement of 30,614 GMb.* corresponding to en energy reoqureInt of U4982 GWh.

Source: TIES.

S1/ Discussions on the fourteenth APS were initiated in mid-1989; the report should be finalizedduring 1990/91.

32/ In addition,total plant availability factors of 89% and 88% are assumed for nuclear andbydro power plants respectively. These avaflati£ity factors result in rather qpti:misestiates for effecive capacities.

Annexl4Page 3 of 14

Table 2: Generation Mix of TNBWs Capacity Expansion Program

2000

1990 199f Including ExcludingContral Sector Share of NowShare Central Sector

Projects

Coel/Lfinite 3166 4628 5812 S628

CcahmtfionTurbire 0 430 11 730

Nydro 1945 1948 2128 2128

Total EffectiveCapocftj 4050 5421 7229 6455

agj: mUED.

7. Dmnd forecass for the years 1995 and 2000 exceed the effective capacities, even whenplanned capacity additions are included. Even if one were to take the lower demand forecasts of5792 MW in 1995 and 8558 MW in year 2000, and the more optimistic capacity plans (i.e. includingthe tentative central sector share for TNEB in Ninth FYP period), the effectie capacities of 5421MW in 1995 and 7229 MW in 2000 fall short of the deand. Power shortages in Tamil Nadu areiely to continue in the foreseeable future.

8. TNEB's total net power purchases (transfers from central sector projects plus net importsfrom other states in the Southern region) in 1990 were 6837 GWh. They are expected to increaseto 16,487 GWh in the year 2000 (if the generation from new central sector projects that have notyet been committed is included), a rate of 9 2% per annum. However, if the central sector projectswhich are not yet committed are not included, then net power purchases will rise to only 8818 GWhby the year 2000, an average growth rate of 2.6% per annum. As power purchases comprise largelybase load requirements in the INEB system, 6837 GWh is modeled to correspond to 780.5 MW ofcapacity, which is expected to increase at the energy growth rates given above.

9. According to avaflable estimates, TNEB's bydro power station capacity is likely to increasefrom 194S MW at the end of 1990 to 1948 MW by 1992, and to 2128 MW by the year 2000.Corresponding to this capacity increase, annual generation is projected to increase from 3353 GWhin 1990 to 3358 GWh in 1992 and 3418 GWh in the year 2000. The seasonality of bydro powergeneration wffl likely remain the same as in 1990: 40% of total annual generation during the simonths January through June, and 60% during July through December.

Page 4 of 14

btem Load une

10. Despite efforts to maximize generation within the TNEB system as well as transfer fromoutside the system, serious power shortages persist in Tamil Nadu. Other states in the Southernregion have experienced similar shortages. However, owing to good monsoon rains during 1989,which flled hydro reservoirs and allowed additional hydro generation, shortages have been relativelyless since July, 1989. Nevertheless, the TNEB system has continued to operate at less than thestipulated frequency of 50 Hz. Discussions with TNBB officials revealed that even during off-peakhours, when certain TNEB power stations are available and their generation levels could beincreased to boost system frequency 50 Hz, this Is not done. If it were, TNEB would have to sellpower to the other states at presumably unattractive rates, or reduce its allocation from the centralsector power stations.

11. Figure 3.3 in the main text shows observed load curves together with load curves correctedto a system frequency of 50 Hz. The graphs show that the morning peak oceurs from 0600 to 1000hrs, and the evening peak from 1800 to 2100 hrm Table 3 shows that for several months, the systemfrequencycorrected load is 90% or more of the daily system peak load during these time intervalIn fact, in all months, the system load eweeds 85% of the daily system peak load during themorning and evening peak hours

Table 3 The Regularity of Peak Load Conditions on the TNEB System

Nouw of day when tIedPeak Tim of day exceeds 90X of system peakload for system

'enth (HU) peak Nornin Evening

Juty 1989 2619 2000 0600-0900 1900-2100Aug. 1989 2749 2080 0600-1000 1900-2100sep. 1989 2789 2000 0700-0900 1800-2100Oct. 1989 2?55 1900 0600 1900-2100Nov. 1969 2704 2000 0800 1800-2000Dec. 1989 2998 0800 0600-1000 1600-2000Jan. 1990 2976 0900 0700-1200 1700-2000Feb. 1990 3024 0800 0700-1S00 1900-2000Nor. 1990 3147 0800 0600-1200 1400-2400Apr. 1990 3022 2000 0600-1200 1500-2100May 1990 2965 0600 0600-0800 1800-2100June 1990 2967 0600 0500-10(4 2000-2100

forcesQ* DESU

SMog Ctu e

12. It is evident from the preceding section that significnt power shortages are liely toconinue in Tamil Nadu durig the 1990's. In anticipation of power supply restrictions andbrown-outs, several industrial and commerc bments have sought to mitte the effect

AnAnPage 5 if 14

by investing in standby generation facilities. Such standby or captive generators are usually dieselgenerators of less than 100 kVA capacity to as much as 3000 kVA capacity.

13. Investment in these generation facilitie is a consequence of decisions made by privateentrePreneurs, and is not included in the capacity expansion planning framework of the orgniedpower supply industry (ie. TNEB and other central sector agencies). These diesel generators useimporte high#speed-diesel (HSD).

14. The vety fact that prnvate industiy prefers to use standby diesel generators when ittperiences power shortages ind;cates that it finds it more economical to do so than to foregoproduction. The costs of investing in, maintaining and operating this back-up source of powergeneration may therefore be considered as a lower bound for outage coos Asuming that thediesel generators are used for 2000 hours each year, shortage costs are estimated at Rs 1.44 to Rsl.91/kWh depLading on the size and efficiency of the generator. Table 4 summarizes these results.

Table 4: Estimated Costs of Captive Diesel Generation

50 IkW 200-400 kWmacbine othirne

A. fixed Costs (Rs/kW)a.1 Capital cost plus installation charges 6300 4420*.2 Anualted capital cost 925 649a.3 Salaries 666 449*.4 Naintenan 134 920.5 Total fixed annual costs 1727 1190

5. Variable Operating Costs MRA/kWh)b.1 Diesel 1.008 0.806b.2 Lu*ricatfng oit 0.040 0.040b.3 Total variable C0st 1.048 0.846

C. Total Generation Cost (RM/kWh) 1.912 1.441

lotestB.t: As given in the World Bank's report "Private Power Utilittes Project 1".

a.2: Assuwng a 15-year life and 12X discount rate.

b.3: Assumng a c.i.f. diesel price of US22.40/bbl or Is 2.40/liter (Ufl 1 a Rs 17.00);storage/handltng/transport costs of Rs 0.1/tliter; and c_nsAption of 0.3 liter/kMh

b.4: Asuming cost of ltube oil as Rs 10/liter (c.i.f. prfce plus storage/handling/transportcosts) and tube consuiptfon of 0.006 liter/kWh.

C: AsUming capacity factor of 22.8% or wnnual generation of 2000 kMh/kU of installedcaacfty.

Page 6 of 14

15. On the other hand, the Federation of Indian Chambers of Commerce and Industry(FICCI) 32/ estimates that the loss of value added in manu ng industry due to unreliabilityof power supplies is about Rs3.030/kWh in financial prices. This corresponds to about Rs 2.40/kWhin economic terms.

Convetina Power Generaftio einlg

16. As Table 2 indicates, TNEB plans to inftll hydro power stations, coal-fired steam thermalpower stations (TPS) and oil-fired combustion turbines (Crs). It is expected that one gas-firedcombined cycle plant (CCP) will come on line during the 1990s, and that TNEB's share of coal andlignite based generation capact and nuclear capacity operated by the central sector agencies willincrease.

17. Discussions with TNEB officials revealed that there is no significant difference betweencoal-fired and lignite-fired power stations in terms of capital investment requirements, constructionlead times, fixed operation and maintenance costs, and so fordt. Reliable data on the cost andperformance parameters of nuclear power capacity are not readily avaiable. Expansion ofhydropower capacity wl continue as planned. Therefore, windfarms are not compared economicallyto lignite-fired capacity, nuclear power stations or hydro power. Instead, it is compared to:

(a) a 3 x 210 MW coal fired TPS;

(b) a 4 x 30 MW CI power plant using HSD; and

(c) a 90 MW CCP running on natural gas.

18. Capital cost and performance data for these units have been taken from recent feasibilityreports of the respective projects and are shown in Table 5. These figures may be somewhatoptimistic since they do not take into account the time and cost overruns which are usuallyexperienced in commisioning such power plants. The overight capital costs (OCC) in Rs/kW arederived from the total project cost (as sanctioned) and the generation capacity to be installed, andare expressed in constant 1990 prices.

19. Data on fixed annual operation and maintenance epes and auxiliaty consumptionlevels are based on experience in TNEB and other utilities in India, at least for coal-fired TPS andoil-fired CIs; maintenance and fixed operating co for CCPs are based on experience elsewhere,and are not backed by any opeational experience in India. Similarly, there is little or no dataavailable in India regrding plant economic life, forced outage rates (FOR) and plannedunavlabilit (mntenance outage rates or MOR) for CIs and CCPs. As far as MOR and FORfor coal-fired TPS are concerned, the norms used by CEA for its planning purposes are alsoadopted by TNEB, and are used in this analyis. However, TNEB assumes the economic life ofcoal-fired TPS units to be 25 years, which is used in this analysis, while the CEA adopts 30 yearconvontion for planning purposes.

3/ FICC1, "Self Generation of Power by Industr?, Seminar Report, New Delhi, June 1988.

Pagp 7 of 14

Table : Cost and Performance Parameters of Conventional Thermal Power elneration System

Coal based Cumeustion Cwbirned CycleTPS Turbine (CT) Plant (CCP)

Overnight capitalcost (Rs/M) (a) 12,125 10.280 14,020

Constructfon tifm(years) 7 (a) 4 (b) 4 (b)Phasing of capitalexpenditure tX) (a)* Year 1 11.1 9.35 12.5* Year 2 13.1 26.94 37.5* Year 3 18.3 31.18 37.5- Year 4 22.9 32.53 12.S-Year S 18.3 NA IA-Year 6 13.1 NA NA-Year 7 3.2 NA NA

Fixed 0 & Ncsts (X of OCC) 2.S 2 2.5

Fuel Type Coal; Furnace High Speed NaturalOfl (F0) Diesel Gas

Fuet cost Coal:0.4960 (c) 0.8099 (e) 0.5357 (f)(Rs/kUh gross) FO:0.0307 (d)

Real fuel cost Coal:2.5 2 2oscalation rate f0O2(X per anmo)

Aux. consmiptionsX of gross generation) 8 2 4

Economic tife (years) 25 30 25

Forced outagerate(X) (a,b) 24 15 1S

Naintenance outagerate (M) Ca,b) 1S 10 10

Eiwirouusntal costs- fixed (M of OCC) 8.6 8.6 8.6- variable (S of VOC) 7 4 S

Notes:

(a) Provided by the TNEB.

(b) Provided by CEA, Lon Term Platifn bfrectorate.

tc) Cost of delivered coal - Rs 800/ton; coal co_ption of 0.62 kgAUh.

(d) Cif. cost of t n oft - Rp/to n;, toreeils o f fO n atlw/ton; 7fO consipteon a 15 a/U,; specifw c gravity Of Fsa0.9/ kg/liter.

e) C.f.f.acostnofN aUS$22.40l°1,orR1t2.3954/liter 1u5P a fIMorg ts/tryspertcost a Rs 0.12/liter; catorYll value u%1I4 kcal/titer; thewmal

(f) Econoemc price of natural Xs a Rs 22S0/thousand standard c"bic mters (SCM); calorific valuea 9000 kCal/SOI; thermal efficiency of CCP a 40L

Page 8 of 14

20. Current fuel cost estimates have been taken from the respet feasibiity studies usedfor capital cost estimation. Estimates of real fuel price escalations are based on likely trends in theindigenous coal industry and international oil and gas markets. Estimates of local environmentalcosts are taken from a study recently submitted to DNES i/. Transmission and ditributionlosses are taken as 20% of gross generation. This is the averag level of such losses in the TNEBsystem

Mauwia Cost of oertemnon *om Ibemal Power Stadon

21. Since TEB's thermal pow r stations are more expensive to operate than its hydro powerstations, and because TNEB's power purchase quotas are more or less fixed, TNEE's own thermalpower capacity i used at the margin Not all thermal capacity must be on-line to foll load;TNEB's thermal capacty accounts for 35% of the total capacity at TNEB's command (includingits share from central sector projects) in 1990. Tbis share is likely to increase to 36 per cent by1992 and over 50% by the year 2000.

22. The baclWound information used for estimating the marginal costs of generation invarious thermal power stations is given in Table 6. On the basis of this information, the marginlcost of generation are estimated and prsented in Table 7.

W-dfarm SpecSiation

23. As mentioned in Annex 1 of this report, cost and performance data for windlirms is basedon the experience gained from existing windfarms in India. Table 8 summarizes some of therelevant base case cost parameters. A more detailed presentation ofwindfirm parmeter values,incuding technical parameters, is given in Table 9.

24. Values of many of the parameters of the economic evaluation are uncera Todetermine whether this uncetainty in fact has a bearing on the outcome of the analysis, and toascertain the conditions under which these windfrms appear atactve, extensive sensiivity analysiswas carried out. The parameter variations considered are given below in Table 9. The resuts werepresented and discussed in Sections 3 and 4 of the main text

i/ Metaplanners and Managment Consultants, "A Study on Cost of Electricity Generation andEnvirownental Aspects", report bmted to DNES, Patna, Septmber 1989.

Page 9 of 14

Iabl6: Cost and Performance Characterics ofEsting and Planned TNEB hermal Capacity

NorthEncore Tutfcorin Nottur Ntdras

TPS TPS TPS TPS CT

Fuel useN- Coal Yes yes Yes Yes NO- furnwc Oil (FO) Yes Yes yes Yes yes

Averae bet rateWste/ktdh) (a) 2646 2560 256 2500 26O

Avera hest ratelot by-Coa tX) 9S 95 95 95- F0 (X) 5 5 5 5 100

Caloriftic value offuels CetkCa/e)- coal 4000 4000 4000 4000 N.A.-0 9900 990 99 9900 9900

telivered fuelPrice (ts/ton)- Cost 853.38 901.04 909.48 800 S NA.-- 9 2100 2100 2100 2100 2100

Forced outage rate (X) 24 24 24 24 1S

Nafntenence outagRot (e ) 1S 15 1S 1S 10

source: (a) TIE, April 1990;

Pap 10 of 14

able: Insted Capaci, Effetive Capacity and Variable Opeating Costsof Existng TNEB Thermal Power Stadons (a)

lm ~ am

imtatled amity (NW)

- Encore VP. 450 450* Tuticorin TPI 840 1050* NIttur TPI 840 840- North Nadras TV 1630 (b)- CT70

Effectiw amlty flU)

En l 291 291-Tuticorfn TPS 543 678

-Nttur P 543 543North adras * 1053CT . 555

Varab*le Operati Costsin 1990 nrles t to)

- Encore TPS 0.56.3* Tuticorwn V O.S750 0.5750- Nttur TnP 0.5101 0.501- Nrth Nadras PS 0.5015 O.S50' CT 0.1 0.M

Notes:

(a) Providud by the T, April, 1990.

(b) Includs North Nadras TP $tags 11 of 1000 NW capacty.

Cc) Exud real fuel cost escaltion rates.

ASS4Page 11 of 14

IsUal: Windfarm Cost Parametes

Kaythar Talapthu

,Overniht Capital coat

- RsAW (1 pri) 17,629 7N O/W (1990 prie) 18,158 18535

fixed and Variable 0 & Ncosts (Rs/kVI ) 0.20 0.20

Construction Time 20 16(=onths)

inf of caoitat exond1ture tSZ

- year 80 90-Year 2 20 10

Notes:

(i) An exhg rate oo s 15.25/USS is assumd for the 1989 prices.

(iiO A rel cost escalation rate of 3X per arin is assumed.

(iif) The phasine of apital elniture as iven above Indicates that for both windfarm to r,83.46xo the capital expeniture is Incurred In the first 12 months.

Iaba 9: Parametric Variations for the Senitity Anabyis

Dase Low High

1. For changs In nf it-Cost Ratios of All Technologes

Overnigt CapitalCosts (Ms/kW) 1* Coal bsed TPS 12125 * 15156- CT 10280 - 12850* CCP 14020 - 17525- Windfam 18284 13713

Lead Tfr (year.)-Coal bsed TPS 7 S/ 9-CT 4 3 d. CCP 4 3f S 3* Iindfarm 2W 1

Real Escalation Rte of Varableperating Costs (X per year)

-Coslt bodM 1 0 3.5- CT 1 0 3.5- CCP 1 0 3.5- Windarm -

hn 4Page 12 of 14

Boe" Lou Highb

Fixed Enviromental Costs (I of 0CC)- Coal based TPS 8.6 0 17.21/t CT 8.6 0 17.21/t CIt 8.6 0 17.21/

- Windferm

Varfable Envirorvmntal Costs(1 of VC)

*Coolt bedTP8 7 0 14 107 J-C T 4 0 8 43/-CCP 5 0 10 351* Windf*rm * *

Transmission & DistributionSystem Losss () IV-Col based PS 20 1S 25-CT 20 1S 25-CCP 20 IS 25- Vfndfarm 1S 10 20

2. For Changes In Vindfarm Performe and Cost Only

wbrne Size, kW 1/ 225 100 450Vindfam Size, NM 7n 20Mind Resource expsa capacity factor) of 17.8 17.21 24.01rid & Turbine

Availability g 90.6X 81X 986

3. thr Changes

Cost of Unsrv Energy (es/kWh) 1.441 1.243 g/ 3.226 tAbvutl Rel Discount Rate (X) 12 10Arnal Load GroWth Rate CX) r/ 8.74 6.74 10.74

Capacity accese by TIES In 2000 (MM)- Central Sector 3031 2008 3051 3031- CoAl/Lnite (e¢l. central 3970 370 3 S470 A/- CT (exct. central sector) 73 73 20o0 V 730-O thr 22Z 2242 2U2 2242

Total 9973 89S0 11243 11473

Motes: sa3w case convntional t ology costs s on feaiblilty studis cited lIn text. N110cotcase includes 251 mrkup. Be case windfam costs bas on xpoerience with 20 NV Donid-financed windfarm in India, as dis sed in Amex 1. Low windfam cost case rep ets a 251reduction In OCC, based on Lynette, cf. footnote 14.

IV The IVestlment Is phaed n fi fve years in the following nnwer 11.11 in the first yar, 22.2Sin second, 33.31 In third, R222X In fourth, and 11.1X 1n fifth (Sourme: Ci, PersoalCouinications).

) The Investment in nine yeors Is spread soxiately a8 follos 41X in the first year, 0S insecond, 121 in third, 161 in fourth, 201 fn fifth, 141 in sixth, 121 In seventh, 1 In eighthand 46 fn nfnth (Source: CIA, Personal Coramunications).

i The investment Is phased in 3 years as follows: 251 in the first and third years, and 501 Inthe second (Source: CIA, Personal Coummications).

The inwetsent proftle during the construction tie of five years Is -pprxmatety as follows:8X in first year, 241 In second, 26X in thfrd, 271 in fourth and 151 in fifth (Smurce: CIA,Personal Comiations).

Pag 13 of 14

No previous experiene in Indfa so for; but likely 1nestm profile In three years ofconstruction time is 25 in the first and third years, and 5 n the second.

8 lo pwfw fr In Indfa so far, but likely nestmnt profile In five yar ofcontruetlen tfz fls 14X In first year, 22.21 in seco, 33.31 in third, 22.2X in fourth and11.11 In fifth.

tv mused on experience with existing windfams In India.

Used fn high local envirantel cot case only.

f nistimted from Pace University study of gltoal erorntal costs, cf. foote 13 of thisreport; used for high globl ewirental cost ca". g ca local envwromntal costsdrived from Ieteplrs, cf. footnote

Transmisson nd distribution losoes In TM ae pprom tely 20X. Vindfarm ltoas ar as dto be lower bAs of oimty to lod centers that would othwise rmAn for from

eneation source. Auxilary loss are taken Into seccost seprately as follows 7%e awe TPat lorth Nedras is expected to hae n af xli ay C atnto level of about 81 of grosgenation; auxiliory toso at Tutecorin are below 81 ea rs d Nttur are above SX.Therfor, coul Is dcterized by OX asiliary loss, CCP by 4, CT by 21, nd windfamby no loes.

Turbine size effects several peramter as follows

sm cas windfam having 225 kW Vestas tubne.Low eusems wiadfars having 100 kId US Winowr turbines.Nigh cae: windfarm having 450kW Sms turbines.

Asume standwd air demity of 1.22S k .

Ufnapeod Bae LoW Hfigple output. kVD output, kId output, kV

0 0 0 01 0 0 02 0 0 03 0 0 0s 0 3.0 05 0.? 13.0 16.76 8.3 27.5 44.87 18.3 45.0 02.48 31.3 70.0 117.89 47.2 99.0 142.910 65.6 129.5 212.911 86.6 160.5 201.012 107.5 189.0 305.613 107.5 207.5 356.714 107.5 218.5 400.0IS 1OT.5 225.0 440.016 107.5 225.0 470.017 107.5 225.0 490.018 10T.5 225.0 500.019 107.5 225.0 500.020 0 225.0 405.021 0 225.0 475.022 0 225.0 450.023 0 225.0 430.024 0 225.0 410.025 0 225.0 420.0

omrat1io and eIgnt CoBas and Ni9b cases US 0.013/ki.Low cs: M 0.0125/Ii.

Anne" Pye 14 of 14

rray EfftIfa I

Kayathar ThalayuthuSO NW SO NW so NW 10 NW 25 NW 25 NW 25 NW 10 NW

Nonth 100 kV 225 kW 450k 22S kV 100 kV 225 kV 450 k 2S kW

Jan 0.62 0.69 0.70 0.81 0.54 0.65 0.69 0.77Feb 0.62 0.65 0.70 0.81 0.54 0.64 0.69 0.77Nar 0.62 0.69 0.70 0.81 0.54 0.70 0.69 0.77Apr 0.71 0.81 0.81 0.91 0.70 0.80 0.89 0.91Nay 0.71 0.83 0.81 0.91 0.70 0.86 0.89 0.91Jun 0.71 0.91 0.81 0.91 0.70 0.87 0.89 0.91Jul 0.70 0.88 0.87 0.94 0.72 0.88 0.92 0.93Aug 0.70 0.87 0.87 0.94 0.72 0.91 0.92 0.93Sep 0.70 0.84 0.8? 0.94 0.72 0.84 0.92 0.93Oct 0.65 0.76 0.73 0.84 0.58 0.82 0.74 0.79Nov 0.65 o.75 0.73 0.84 0.58 0.80 0.74 0.79Dec 0.65 0.75 0.73 0.84 0.58 0.64 0.74 0.79

Overnight CaDital Costs

Dase cases Ksyathars Rs 1f 158JkU; Thalayuthu Rs 18.535/W; Coabined: Rs 18,284/kV.LOW casems Kaythar: Re 14,526AW; Thslayutsw: R8 14,82.k'W; Cmobineds Rs 14U627/k;High case: As for the base case.

I Bse case indfar size s sn NW at laysthar and 25 N at Thalayuthu. Lowcm sassumas 10 NWat each site. array effictemy as spec1fled fn note I/ abov, and tow case construction leadttm.

ly Omge case wirdresources are based on hourly u1ndspeed averages for three years. Low case isbased on 1968 only, considered to be a "Mind drought3 year. Nigh case based an averageperformance of most recent Calffornia windf ms.

sy Base case 18 based on Kayethar I obsarved grd aval ab lity of 94.2X in 1989 and turbineavailability of 96.2X. Low case assumes 96 grid availability and 901 turbine availability.Nigh case is based on best performance of California and Danish windfarm of 991 availabilityfor the grid and 99X for the turbines. Golng back as far as 1986-1987, sae Alttauunt PmSwindfarms in California reported 982 total availabilfty (Electric Power esearchInstitute,9ifhd Power Station Performance and Reliability, North. 1989).

y A utilifation rate of 3000 kWh/kU per annum is assunad for diesel sets (refer to Table 4 ofthis Annex).

3/ Assudng an nual utilization rate of 500 kUh/kV for diesel sets (refer to Tibte 4 of thisAx).

It is assuued that total energy sales Mill increase at the rate of 8.742 per year from 1990to 2000 (i.e. from 19 U6rWhs sal.ts in 1990 DTNIB data provided In April 19901 to 44982 UsIn the year 2000 BSource: CMA Thirteenth Electric Power Survey. 19672.

3/ Assuing that an addititnal lignite based power statfon of 1500 NW coams on stre by 2000.This is included in the TIEBSs power expansion programme. Its costs and performance areassumed to be the sam as that of the ooal based North Nadras Ms.

Assuming that an additional CT of about 1270 NM capacity is caumissoned by the year 2000.This additional CT has the ae, effective capacity (as per bae cae assumptions of NM andFOR) a a 1500 M lignite basd TPS.

Page 1 of 2

ANNEX 5: CALCULATION OF C02 ABATEMENT COSTS

1. The calcalation of C02 abatement osts is bas on a revenue requrments methodolog.Thbis approach derives a single price which coud be charged per ton of C02 over the life of thewindfarm such that net life-le osts of abatement are fuly recovered.

hP m wale olwwueal - -cyce co

E[-A--} x CO:2X - 1 ACW, - (,,LACCJ

S 1 ACWnd -L-ACC,x W-andxW,C(I +1k)' *(14k)' (I (14) Ia (lA)' w

aatAitab ad a*qft for E

whwrI - kndx for dee year, 1 tossj die lfe6a of the wl 4k

- te ra it rat (VP L the rea kelid abaotn cothe d kewlld CO2 abatasen CM

C02, - th tol amon of CO2 abatd Is yew IACW - to wL4fm eweaw In yer IACC, - toal coxwasoad g _nemdon aeJmforwgm as a rek of

d4tm opesan ar irea kwld enmV produco cog aor the whn4fs

2 C - redal ke d eeC prodcthon cor de convenonal geneuation wae', - wh M geedon u ener nin earm

aO- - Om-otE of th2 proed per val of oregnedenal generadonIe

iso,utantfor all I

2. ~Because ACC, is only the foregone conventional generation expensei and becauseconventional plant lifetime and phasing may differ from that of the windfarmn, the present value ofconventional generation 'revenuese in terms of the levelied enerVy production cost is only an

apprximaionof the present value of foregone conventional generation expenses. The closer thelifedme and phasing of the two plants, and the closer foregone conventional generation expensesper windfarm kWh are to annual life-ycle costs of conventional generation per kWh of output, thebetter this tion wM be. If the windfarm only displaces energy and does not affectinvestment decisions regrding the szig of new conventional capacity, thenACC, and convendonallevelized energy costs incude only variable operating costs

AnnexSPage 2 of 2

3. The levelized energy production costs of wind and conventional technologies are knownfrom the economic evaluation. The amount of C02 produced per unit of conventional generationis known from the conventional generation heat rate and the physical composition of the fuel interms of ash, carbon, sulfur, etc. The C02 abatement cost can therefore be determined from thefEal equation.

EtERGY SECIrOR MANAGEMNT ASSISTANCE PROGRAMME

COMPLETED ACTIVTIES

CAN" Adh* Date Nuwnbr

SUBtAHARAN AMCA (AFR)

Afiica Regionl Anglophone Afiica Household Eery Wkshop (English) 07/88 085/88Regioa Power Smnar on Reducing Electric Power System

Loss in Afrc (nlsh) 08/88 087/88Instittonal Evaluation of EGL nglish) 02/89 098/89Biomass Mapping Reonal Wokso (nlih - Out of Print) 05/89 -

Franophone Household Enagy Workshop (French) 08/89 103/89trafican Electrica Engineering College: Propos for Short-and LnTerm Developmeat (Eli^sh) 03/90 112/90

Biomss Asmnt and Mapping (Eglish - Out of Print) 03/90 -

Angola Ener Aent (English and Portuguese) 05/89 4708-ANGPowe R and Technical Assistance (Engl) 10/91 142/91

Bai Eneg Assesment (Eqgli and French) 06/85 5222-BENBolawna EnergV Assement (En h) 09/84 4998-BT

PUMp ElectrectionlPefeasility Study (English' 01/86 047/86Revw of Eedricity Semie Connmecion Policy (Eglish) 07/87 071/87Tuli Block Farms Electrficion Study (English) 07/87 072/87Houehold Energy I6sues Study (Enlish - Out of Prit) 02/88 -

Urban Househbld Energy Strategy Study (English) 05/91 132/91Burkina Paso Energy Assessment (English and French) 01/86 5730-BUR

Technical Aistance Program (Engsh) 03/86 052/86Urban Household Energy Stregy Study (English and Frech) 06/91 134/91

urunmdi Ener Assessment Egs) 06/82 3778-EBUPetrolem Supply Management (Eglish) 01/84 012/84Status Report (English and French) 02/84 011/84Presentation of EnergyPojcts for the Fourth Fie-Year Plan(1983-1987) (English and Fiench) 05/85 036/85

Improved Charcoal Cookstove Strategy(E3ngish and French) 09/85 042/85Peat Utilization Project Egi8h) 11/85 046/85Energy Aessmcnt (Engish and French) 01/92 9215-BU

Cape Verde Energy Assessmet ( h and Portuguese) 08/84 5073-CVHousehold Energy Straegy Study (English) 02/90 110/90

Cetdral AfricanRepblEicnergAssessat (Frenh) 08/92 99W8-CAR

Comoros Energy Assessmnt Egsh and French) 01/88 7104-COMCongo fneqgy Aessment (English) 01/88 6420-COB

Power Devlpnment Plan (Eng4ish and French) 03/90 106/90C(;b dhoe Enr Awoment (English and French) 04/85 5250-IVC

Improved Biomass Utlbzati (English and French) 04/87 069/87Power Systm Efficiency Study (Out of Prid) 12/87 -

Power Sector Effiency Study (French) 02/92 140/91Ehopia Energy Assessmnet (English) 07/84 4741-ET

Power System Efficiency Study (Englsh) 10/85 045/85

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CoUay Acd* Date Number

Agricutura Residue Briquetting Pilot Project (English) 12/86 062/86Bagasse Study (English) 12/86 063/86Cooking Efficiency Project (English) 12/87 --

Gabon Energy Assessment (English) 07/88 6915-GAThe Gambia Energy Assessment (English) 11/83 4743-GM

Solar Water Heating Retrofit Project (English) 02/85 030/85Solar Photovoltaic Applications (English) 03/85 032/85Petroleum Supply Management Assistance (Enlish) 04/85 035/85

Ghana Energy Assessment (Engi;sh) 11/86 6234-GHEnergy Ratiolition in the Industrial Sector (English) 06/88 084/88Sawmil Residues Utilization Study (Eish) 11/88 074/87

Guinea Energy Assessment (Out of Print) 11/86 6137-GUIGuinea-Bissau Energy Assessment (English and Portuguese) 08/84 5083-GUB

Xecommended Technical Assistance Projects (English &Portuguse) 04/85 031/85

Management Options for the Electric Power and Water SupplySubetors (Englih) 02/90 100/90

Power and Water Institudonal Restrucing (French) 04/91 118/91Kenya Energy Assessment (English) 05/82 3800-KE

Power System Efficiency Study (English) 03/84 014/84Status Report (English) 05/84 016/84Coal Conversion Action Plan (English - Out of Print) 02/87 -

Solar Water Heating Study (English) 02/87 066/87Ped-Urban Woodfuel Development (English) 10/87 076/87Power Maser Plan (Enlish - Out of Print) 11/87 -

Lesotho Energ Assessment (English) 01/84 4676-ISOLiberia Energy Assessment (English) 12/84 5279-LBR

Recommended Technical Assistance Projects glish) 06/85 038/85Power System Efficiency Study (English) 12/87 081/87

Madags Energy Assessment (Englsh) 01/87 5700-MAGPower System Efficiency Study (English and French) 12/87 075/87

Maawi Engy Assessment (English) 08/82 3903-MALTechnia Assistance to Improve the Efficiency of FuelwoodUse in the Tobacco Industry (Engish) 11/83 009/83

Status Report (English) 01/84 013/84Mau Energ Assessment (Egish and French) 11/91 8423-MLI

Household Energy Strategy Eglih and French) 03/92 147/92Ilamic Republic

of Maurnia Energy Assessment (English and French) 04/85 5224-MAUHousehold Enery Strategy Study (English and French) 07/90 123/90

MAvritius Energy Assessment (English) 12/81 3510-MASStatus Report (Engish) 10/83 008/83Power System Efriciency Audit (nglish) 05/87 070/87Bagasse Power Potental (English) 10/87 077/87

Moambique Energy Assessment (English) 01/87 6128-MOZHousehold Electricity Utilization Study (EnSish) 03/90 113/90

Niger Energy Asemen (French) 05/84 4642-NIRStatus Report (English and French) 02/86 051/86Improved Stoves Project (nglish and French) 12/87 080/87

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Acdh Dae Nbr

Nlger Household Energy Conservation and Substitution (Englishand French) 01/88 082/88

tgeria Energy Ament (English) 08/83 4440-UNI

RwanC1.a Energy Assesment (nish) 06/82 3779-RWEnerg Assessme (Englsh and French) 07/91 8017-RWStatus Report nish and French) 05/84 017/84Improved Charcoal CDokstove Strtegy (English and French) 08/86 059/86Improved Charoaw Production Techniques (Eglish and French) 02/87 065/87Commerdialiaon of Improved Charcoa Stoves and Carbonizaion

Techniqwes Mid-Term Progess Report English and French) 12/91 141/91SADC SADCC Regional Sector: Regiona Capacity-Building Program

for Eney Surveys and Policy Analyis (English) 11/91 -

Sao Tomeand Princpe Energy Asssment (English) 10/85 580-STP

Senel Ery Asssmen (Eglish) 07/83 4182-SEStatus Report (English and French) 10/84 025/84Industa Ergy Conservation Study (English) 05/85 037/85Preparatory ssisance for Donor Meeting (English and French) 04/86 056/86Urban Household Ene Sttegy (English) 02/89 096/89

Seyhelles Energy Asme (Englishi) 01/84 469-SEYEectric Power System Efficency Study (Engish) 08/84 021/84

Sierra Lene Enrgy Assessment (Engfish) 10/87 6597-SLSomalia EneW Assessment (Eaglish) 12/85 57%-SO

Sudan Maa tAssAnce to the WMinsty of Enegy and Mibnng 05/83 003/83Energy Assessment English) 07/83 4511-SUPower Systen Efficiency Study (English) 06/84 018/84Status Report (English) 11/84 026/84Wood Enegy/Forestry Feasibty (Engsh - Out of Print) 07/87 073/87

Swaziland Energy Assesment (Englsh) 02/87 6262-SWTanzania EneWgy Asessment (Engsh) 11/84 4969-TA

Peri-Urban Woodfuels Feasbiy Study (Eaglish) 08/88 086/88Tobacco Curing Effciency Study (English) 05/89 102/89Remote Sensing and Mapping of Woodlands (English) 06/90 -

Industrial Eney Effiiency Tec a Assistanc(nglish - Out of Print) 08/90 122/90

Togo Ery Assesment (English) 06/85 5221-TOWood Recovery in the Nangbeto Lake (English and French) 04/86 055/86Power Efficiency Improv&ment (Englsh and French) 12/87 078/87

Uganda Eny Assessmeat (nglih) 07/83 4453-UGStats Report (English) 08/84 020/84nstitutionl Reiew of the Energy Sector (English) 01/85 029/85Eneugy Efficiency m Tobacco Curing Indusby (English) 02/86 049/86Fuelwood/Forestry Feasbity Study W lsh) 03/86 053/86Poer System Efficcy Study (English) 12/88 092/88Enegy Efficiency hnmprovment in the Brick and

Tle Industry (Engish) 02/89 097/89Tobacco Curing Pilot Pect (ENg - Out of Print) 03/89 UNDP Trminal

Report

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O' A'* DW wb

Zaire Ener Assemet (English) 05/86 S837-ZRZambia Energy Asmet (Engs) 01/83 4110-ZA

Staus Repot (English) 08/85 039/85Enegy Seor Institutional Rew (English) 11/86 060/86

Zambia Power Subsedor Efficien Study (English) 02/89 093/88Energy Strae Study (EnAish) 02/89 094/88Urban Household Energy Strategy Study (Eglish) 08/90 121/90

Zimbbwe Enegy Assement (Elsh) 06/82 3765-ZNPower Systm Efficienc Study (nls) 06/83 005/83Status Report (E h) 08/84 019/84Power Secta Managmen Asistan Project (English) 04/85 034/85Petolem Management Astan (Enh) 12/89 109/89Power Sector Management Instituton Building

(Ensh-Out of Print) 09/89 -

Charcoal Utilizatin Prefeasblity Study (Enlish) 06/90 119/90ntegrtd Enery Steg Evaluation (ng) 01/92 8768-ZN

EAST ASIA AND PACIFIC (ZAP)

Asia Regional Pacific Household and Rural Energy Seminar nih) 11/90 -

China County-Level Rural Energy (English) 05/89 101/89Puelwood Foresty PreNemeut Study (Eng) 12/89 105/89

Fi Eney Assessment (English) 06/83 4462-PUndsnesia Energy Assessment (Enh) 11/81 3543-IND

Status Report (Engl) 09/84 022/84Power Gnertion Efficien Study (Enh) 02/86 050/86Energy Efficien in the Br:k Tle and

Lim ustries m(Egih) 04/87 067/87Diesl Geneing Pbat Efficiency Study (u") 12/88 095/88Urbn Household Energ Setrt Study (ns) 02/90 107/90Biomass Gasifier Study Vols. I & H (Elish) 12/90 124/90

Malaysia Sabah Power Systm Effiieny Study (English) 03/87 068/87Gas Utlatin Study (Enlish) 09/91 9645-MA

Myamr Energy Aessme (glish) 06/85 5416-BAPapua New

Gunea Energ Ament (nglish) 06/82 3882,PNGStatus Report (Engish) 07/83 006/83Energy Strategy Paper (Eng - Out of Prit) - -

Inttutional Review in the Eng Sector (English) 10/84 023/84Power Tariff Study (Eqglih) 10/84 024/84

Solomon Islands Energy Assessment (English) 06/83 4404-SOLEnergy Asessment (Enh) 01/92 979/SOL

South Pacific Petroleum Transport in the South Pacific (ngis of Print) 05/86 -

Thailand Energy Assessmet (ngsh) 09/85 5793-THRurd Energy Issues and Optioms (English - Out of Print) 09/85 044/85Accderated Dismfin of dImpved Stoves and

Charcoal Kilns (Eng - Out of Print) 09/87 079/87

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QCwdy Ad14 Dat Numbw

Thaland Northeas Region Vla Foresty and WoodfueJtPrFInvstment Study ( 3glsh) 02/88 083/88

Impact of lowe 0 Prices (ngl) 08/88 -Coal Devlopment and Utlatio Study (Eglish) 10/89 -

ToW Enr Assessment (English) 06/85 5498-TONVanuau Eer Assessment (Engish) 06/85 5S77-VAWosten Samoa Energ Asement nglish) 06/85 5497-WSO

SOUTH ASIA (SAS)

Ba4bde Energy Asssmien (Engih) 10/82 383BDPriority Invstment Progam 05/83 002/83Statu Report (Engish) 04/84 015/84Power Sstem Effiecy Study (nglsh) 02/85 031/85Smd Scale Uses of Gas Prefesiblty Study (Engi -

(Out of£Piw) 12/88 -Inda forw Commerfoalizato of Nonconventional

V Systems (English) 11/88 091/88Maharastra Bagae Energy Efficin Project ngish) 05/91 120/91Mn-Hydro Deelment on Irr n Dams and

Canal Drops VoIL t I and m Engs) 07/91 139/91WindFarm Pre-ITvestment Study (nlh) 11/92 150/92

Nepal Ery Assssent (Engish) 08/83 4474-NEPSs Report (nglish) 01/85 028/84

Pakistan Houshol Eney Assessment (nglh - Out of Print) 05/88 -Assesment of Phdotooc Programs, Applons, and

Markets (Engish) 10/89 103/89Sri Lanka Enrgy Asement (Engsh) 05/82 392-CE

Power System Lss Reductio Study (Enlh) 07/83 007/83Status Report (Enish) 01/84 010/84

dustrW Energ Consrvati Study (nglish) 03/86 054/86

EUROPE AND CENTRAL ASIA (ECA)

Easr EurWpe The Futue of Natural Gas in Eastern Europe (Eqglish) 08/92 149/92Potugl Energy A me (English) 04/84 4824-POTurkey Ener Assesmen (Eglsh) 03/83 3877-TU

MIDDLE EAST AND NORTH AFRCA (MNA)

Morocco Eemssessnt (Egsh and French) 03/84 4157-MORSt Report (English and Fraenc) 01/86 048/86

Syia Enery Asssme(Englsh) 05/86 5822,-YRElecr Power Efficency Study (Engish) 09/88 089/88Enegy EffAciency Ipovement in the Camae Sedor (Eni) 04/89 099/89Energn Efciy Im ment i te Fertilizer Seorh) 06/90 1lS/90

c4amy dj Data Akng

Tunisia Fuel Substitution (English and French) 03/90 -Power Efficienq Stu (EnglIh and French) 02/92 136/91Energy Management Strategy in the Residential and

Tertiary Sectors (English) 04/92 146/92

Yemen nergy Assessment aeglish) 12/84 4892-YAREnergy Investment Piorities (English - Out of Print) 02/87 6376-YARHousehold Enegy Strategy Study Phase I (English) 03/91 126/91

LATIN AMERICA AND THE CARBBEAN (LAC)

LAC Regional Region Seminar on Electic Power System Loss Reductionin the Caib (English) 07/89 -

Bolivia Energy Assessment (English) 04/83 4213-BONational Energy Plan (English) 12/87 -Nationd Energy Plan (Spanish) 08/91 131/91La Paz Private Power Technical Aistan (English) 11/90 111/90Natural Gas Distribution: Economics and Regton (English) 03/92 12/92Prefeasibility Evaluation Rural Eleification and DemandAssessmuat (Eglish and Spanish) 04/91 129/91

Private Power Generation and Trasmission ngli) 01/92 137/91Chile Energy Sector Review (English - Out of Print) 08/88 7129-CHColombia Eew Strateg Paper (English) 12/86 -Costa Rica Eney Assesment (Engish and Spanish) 01/84 4655-CR

Recommended Technical Assistance Prjects (Engsh) 11/84 27/84Forest Resdu Utilization Study (nglish and Spanish) 02/90 108/90

DominicanRepublic Energy Assessment (ngish) 05/91 8234-DO

Ectador Energy Assessment (Spanish) 12/85 5865-ECEnery Strategy Phase I (Spanish) 07/88Energy Strateg (English) 04/91

Haiti Energy Assessment (English and French) 06/82 3672-HAStatus Report (English and French) 08/85 041/85Household Energy Strategy (English and French) 12/91 143/91

Honduras Energy Assment (English) 08/87 6476-HOPetroleum Supply Management (Engish) 03/91 128/91

Jamaica Ener Assessment (English) 04/85 5466-JMPetroleum I ocurement, Refining, and

Distribution Study (Englsh) 11/86 061/86Energy Efficncy Bulding Code Phase I (English-Out of Print) 03/88 -

Energy Efficiency Standard adLabels Phase I (English. .. of Print) 03/88-

Management Information S. Phase I (Eglish - Out of PRint) 03/88-Cbarcoal Production Project (Enh) 09/88 090/88FIDCO SawmM Residues Utiliztion Study (English) 09/88 088/88Enr Sector Strateg and Inwvtment Planning Study (English) 07/92 135/92