FINANCIAL ANALYSIS. A. Introduction

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Bernice Gilmore
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1 Power Trnsmission nd Distribution Efficiency Enhncement Project (RRP NEP 50059) FINANCIAL ANALYSIS A. Introduction 1. The finncil evlution of the proposed investment ws crried out in ccordnce with the Asin Development Bnk (ADB) Guidelines for Finncil Mngement nd Anlysis of Projects. 1 The evlution covers the three components of the investment: (i) ugmenttion of trnsmission substtion cpcity for supply to the Kthmndu Vlley; (ii) reconstruction nd upgrde of medium-voltge nd low-voltge distribution networks in the Kthmndu Vlley (strting with the Rtnprk nd Mhrgunj distribution centers); nd (iii) introduction of smrt grid elements in the Kthmndu Vlley nd cpcity building within the Nepl Electricity Authority (NEA) in reltion to these technologies. The evlution excludes the Jpn Fund for Poverty Reduction (JFPR) grnt to support gender inclusiveness. B. Methodology nd Mjor Assumptions 2. The overll objective of the project is to enhnce the quntity nd qulity of power tht NEA supplies to its customers in Kthmndu Vlley. With this objective in mind nd becuse of the inherent interconnectedness of ech investment component, the finncil evlution ws crried out for the project s whole. This ws done by compring the project s finncil internl rte of return (FIRR) ginst the investment s weighted verge cost of cpitl (WACC). The sensitivity of the FIRR to dverse chnges in the underlying ssumptions ws lso ssessed. 3. NEA s overll verge revenue reliztion in fiscl yer (FY) 2016 ws NRs8.6 per kilowtt-hour (kwh). Averge reliztion is significntly higher in Kthmndu Vlley (NRs10.1 per kwh in FY2016) s consequence of the generlly higher levels of consumption nd more fvorble customer mix in Kthmndu compred with the rest of the country. An verge 19% triff increse grnted by the Electricity Triff Fixtion Committee (ETFC) t the strt of FY2017, the first increse for 4 yers (nd only the second in the lst 16 yers), will significntly improve reliztion. 2 The ETFC hs stted tht it intends to introduce n infltion-indexed utomtic triff djustment formul in FY2018, nd in this context (nd to reflect the ssumption dopted in the finncil projections developed for NEA) triffs re ssumed to be constnt in rel terms from FY2018 onwrd. Sensitivity to this ssumption ws tested. 4. NEA does not produce seprte demnd forecst for the Kthmndu Vlley. In lieu of specific demnd forecst, n verge growth rte of 9% ws dopted to reflect NEA's expecttion of fster demnd growth in Kthmndu thn in the rest of the country. This rte of growth ppers resonble given the high levels of suppressed demnd s consequence of yers of significnt lod shedding imposed by NEA on its customers. 3 Using conservtive ssumptions nd in recognition of other investments tht will be required to meet demnd, cumultive lod growth in the Kthmndu Vlley ws cpped t 300% over the estimted bseyer lod of 400 megwtt (MW) for modeling purposes. Sensitivity to the demnd growth rte ws lso tested. 1 ADB Finncil Mngement nd Anlysis of Projects. Mnil. 2 Becuse consumers in Kthmndu effectively cross-subsidize consumers in the rest of the country nd given the nture of the triff increse grnted by the ETFC, the verge triff uplift in Kthmndu is likely to be significntly higher thn 19%. However, for the purposes of this nlysis n verge increse of 19% ws ssumed. 3 Lod shedding hd historiclly been required becuse of supply-side constrints, but in recent yers constrints on trnsmission nd distribution networks lso required lod shedding from time to time.

2 2 5. The proposed project will dd 270 megvolt-mperes (MVA) of primry substtion cpcity to the Kthmndu Vlley ( 36% increse over the existing instlled trnsformer cpcity of primry substtions). However, NEA will not be ble to utilize ll of this incrementl cpcity until corresponding downstrem investments re mde to increse the cpcity of the distribution network in Kthmndu Vlley. The proposed project includes reconstruction of two of NEA s 10 Kthmndu distribution centers (lbeit two serving number of high-vlue commercil customers). 4 Bsed on the intended cpcity of the upgrded medium-voltge circuits in these two distribution centers nd on n ssessment of spre distribution cpcity elsewhere in the Kthmndu Vlley, it is estimted tht the project will llow NEA to meet n dditionl 90 MVA of demnd in the vlley. This trnsltes to incrementl nnul electricity sles of pproximtely 600 gigwtt-hours (GWh) by 2030 (which represents 16% of NEA s totl electricity sles in FY2016). 6. Further benefits ccrue from the expected improvement in the qulity of supply tht the investment will bring, nd in prticulr reduction in the frequency nd durtion of mediumvoltge nd low-voltge outges in the two distribution centers to be rebuilt. At present, fults nd overlods occur frequently s consequence of poor network condition nd indequte cpcity, resulting in prolonged outges for NEA s customers. To vlue this benefit, the estimted verge outge frequency nd durtion on medium-voltge feeders ws derived from rw dt provided by NEA, nd n 80% reduction ws then ssumed s result of the investment (resulting in incrementl electricity sles for NEA). 7. Loss reduction is expected to be significnt in the two distribution centers included in the investment. Bsed on technicl nlysis undertken over 25-yer spn, 25% reduction in technicl losses is expected (i.e., reduction from round 8% to 6%). With the doption of underground cbles nd eril bundled conductors for medium-voltge nd low-voltge networks nd the introduction of smrt metering technology enbled for remote reding, commercil losses re lso expected to decrese significntly 75% reduction is ssumed, hlf of which is converted to sles (nd the other hlf reducing NEA s electricity purchses) strems used to determine the FIRR included lnd cquisition nd development, civil works, equipment, incrementl opertionl nd mintennce costs, engineering consulting nd project mngement costs, txes nd duties, nd physicl contingencies. Price contingencies nd finncil chrges during construction were excluded. NEA hs not pid corporte tx in recent yers nd is unlikely to do so for the foreseeble future. For this reson, corporte tx ws excluded from the nlysis nd tx shields were ignored. Electricity supply costs were estimted, on sesonl bsis, using contrcted power purchse rtes from independent power producers (IPPs) nd from the 456 MW Upper Tmkoshi project tht is expected to be commissioned within the next 18 months (nd is designed to provide dry-seson pek energy nd cpcity to Kthmndu). Even though lmost ll IPPs offtke rtes re designed to decline in rel terms over time, to tke conservtive pproch, rtes were ssumed to be constnt in rel terms from FY2021 (on the bsis tht other, more expensive generting plnts will need to be progressively commissioned). 4 The rest of the Kthmndu Vlley distribution network will be upgrded under future lons, nd the rest of the primry trnsformtion cpcity will be tken up t tht stge. 5 Under this project, NEA intends to procure quntity of smrt meters nd distribution trnsformers beyond the requirements of the two distribution centers to be rebuilt under this lon (Mhrjgnj nd Rtnprk). Becuse other network investments re expected to be necessry to fully cpture their benefits, only the costs of these dditionl smrt meters nd trnsformers re included in this nlysis.

3 3 C. Weighted Averge of Cpitl 9. The WACC ws clculted for the overll investment in rel terms. The government is expected to relend to NEA on bck-to-bck bsis, with the foreign exchnge risk pssed on to NEA. 6 The government dds 0.25% service chrge to the interest rte of the finl lon (but not to the rte used to clculte interest during construction). A cost of equity of 11.75% ws dopted for the 2014 South Asi Subregionl Economic Coopertion Power System Expnsion Project lon, clculted by dding issuing costs (1.50%) nd risk premium (2.50%) to the rte t which NEA issued its 2008 domestic bond (7.75%). 7 Recent government development bonds hve been issued t very low interest rtes 4.94% for 15-yer mturity issued in April/My Tresury bills hve recently been trding t rtes s low s 0.779% (July 2016). These rtes reflect excessive liquidity; given tht domestic infltion is in excess of 7%, rel rtes re negtive. In this context, conservtive pproch ws tken to estimte the cost of equity; nominl risk-free cost of 7.5% ws ssumed (lmost 0% in rel terms) plus 4.0% premium to cover risks nd issuing costs (s ssumed in 2014) giving nominl cost of equity 11.5%. 10. Tble 1 shows the WACC clcultion. Tble 1: Weighted Averge of Cpitl Pre-Tx Nominl Tx Rte Post-Tx Rel Weighted Item Amount ($ million) Weight ADB concessionl OCR lon Equity Totl OCR = ordinry cpitl resources, WACC = weighted verge cost of cpitl. D. Finncil Internl Rte of Return 11. Incrementl csh flows ttributble to the investment were estimted bsed on the ssumptions outlined bove. The ggregte csh flow, shown in Tble 2, yields n FIRR of 7.9%, which is bove the WACC of 0.5%, suggesting tht the investment is finncilly vible. Tble 2: Aggregte Finncil Internl Rte of Return Clcultion (NRs million) Benefits s Yer Incrementl Revenue Cpitl O & M Electricity Purchses Net Csh Flow , (2,319) , (3,520) , (5,681) , (25) (6,216) , (1,726) , ,465 3,857 Terminl vlue 1,343 FIRR (post-tx rel) 7.9% FPNV 34,481 ( ) = negtive, FIRR = finncil internl rte of return, FNPV = finncil net present vlue, O&M = opertion nd mintennce Selected yers shown for brevity. 6 NEA repys in locl currency t the previling exchnge rte of the dy (NEA is not llowed to del in foreign currency). 7 This bond ws never trded on the secondry mrket nd ws redeemed in full in 2013.

4 4 E. Sensitivity Anlysis 12. The investment s finncil performnce is sensitive to the ssumed electricity triff pth. Historiclly, NEA s finncil performnce hs been hindered by electricity triffs set well below cost-recovery levels. Since 2012, the verge triff hs risen by 43% through 20% increse introduced in FY2013 nd 19% increse in FY2017. However, becuse the triff hd not been rised for 12 yers prior to FY2013 nd in the context of domestic infltion in the rnge of 6% 10%, rel triffs re still too low (nd hve declined in rel terms over the pst 15 yers). As noted bove, guidnce from the ETFC is tht n utomtic infltion-indexed triff djustment mechnism will be introduced from FY2018, but tht my not hppen. Therefore, nlysis ws undertken to test the impct of lower triff trjectory. Anlyses were lso crried out to exmine the sensitivity of the FIRR to chnges in the ssumed vlues of cpitl nd incrementl opertion nd mintennce expenditure (10% increses were tested), 1-yer dely in implementtion, nd lower demnd growth thn expected. Electricity purchse costs could lso vry significntly from the rtes ssumed in the bse cse, prticulrly if delys in commissioning domestic hydropower plnts require ongoing bulk importtion from Indi to continue to bridge supply deficits (nd in this context, 50% verge increse in supply costs ws tested). Tble 3 shows the results of the sensitivity nlysis. The project s FIRR exceeds the WACC in the bse cse nd under most sensitivities test. Triff remins mteril risk to project vibility. Tble 3: Sensitivity Anlysis FIRR FNPV FIRR Sensitivity Prmeter Vrition (NRs m) SV Bse cse , Annul triff increses lower thn expected (50%) (1.8) (5,003) (38.6) 2. Project cpitl costs higher thn expected +10% , Electricity purchse costs higher thn expected +50% , O&M costs higher thn expected +10% , Dely in commissioning 1 yer , Demnd growth lower thn expected (25%) b ,337 (66.7) ( ) = negtive, FIRR = finncil internl rte of return, FNPV = finncil internl rte of return, m = million, O&M = opertion nd mintennce, SV = switching vlue The bse cse ssumed nnul increses equl to the rte of domestic infltion, pproximtely 7% per nnum. For this sensitivity, nnul increses t 50% of the rte of domestic infltion were tested. b The bse cse ssumed demnd growth of 9% per nnum. Demnd growth of 75% of 9% (6.75%) ws tested here. F. Conclusions 13. The finncil nlysis demonstrtes the reltively high finncil vlue to NEA of improving electricity supply to the Kthmndu Vlley (s result of the higher lod densities nd revenue yields in Kthmndu compred with the rest of the country). Triff trjectory remins risk, however, nd in this context ongoing dilogue with the ETFC nd the government is required to ensure tht recent positive signls with respect to electricity price regultion re trnslted into ction. G. Finncil Performnce nd Projections of Nepl Electricity Authority 14. NEA continues to incur ccounting losses nd does not generte sufficient csh flow to meet its self-finncing nd investment requirements, nor is it ble to meet interest costs on long-term borrowing from the government. NEA s blnce sheet contins long-term debt tht is

5 5 unlikely to ever be repid, nd equity cpitl tht is overstted in vlue, finncing overvlued fixed ssets ginst which commercil return is unlikely to ever be erned (nd the deprecition of which is unlikely to be recovered through consumer triffs). 15. Ten-yer finncil projections were developed for NEA nd re summrized in Tble 4. Even with n ssumption of nnul triff increses (nd the one-off increse of 19% in FY2017 tht hs lredy been implemented), the government s equity position in NEA is forecst to continue to erode s losses ccumulte. The forecst net equity position by FY2026 is NRs22 billion, despite n ssumption of new equity injections of NRs63 billion over the forecst period. As concluded in previous ssessments, significnt blnce sheet restructuring is required write-off of long-term debt nd interest rrers, conversion of some long-term debt to equity, nd write-down (impirment) of the crrying vlue of fixed ssets to reflect their condition (prticulrly in the cse of some hydropower ssets) nd their revenue-erning potentil. Tble 4: Summrized Finncil Projections for Nepl Electricity Authority, fiscl yers Item FY2017 FY2018 FY2019 FY2020 FY2026 Forecst Commercil Electricity sles (GWh) 4,174 4,977 6,192 6,712 7,850 Averge revenue per unit sold (NRs/kWh) Averge cost per unit sold b (NRs/kWh) Finncil Revenue (NRs m) 44,568 56,282 73,895 85, ,634 Operting expenses (NRs m) 51,135 57,190 61,563 68, ,406 Operting profit (NRs m) (6,567) (908) 12,332 16,401 39,228 Overheds (NRs m) 4,184 4,100 4,422 4,782 7,187 Deprecition (NRs m) 4,082 5,602 7,141 8,667 12,863 Finnce costs including FX (NRs m) 3,774 5,347 7,255 9,137 17,930 Net profit before tx (NRs m) (18,606) (15,956) (6,486) (6,185) 1,248 Cpitl expenditure (NRs m) 44,515 45,235 39,692 34,556 0 Operting csh flow (NRs m) (6,400) (8,635) (946) 7,914 17,341 Net csh flow (NRs m) (5,444) (6,750) ,814 17,341 Interest nd roylty rrers (NRs m) 39,800 45,147 52,182 61,106 61,106 Current ssets (NRs m) 28,030 26,982 37,496 56, ,083 Current libilities (NRs m) 87,023 94, , , ,699 Fixed ssets (NRs m) 215, , , , ,204 Long-term libilities (NRs m) 143, , , , ,313 Cpitl nd reserves (NRs m) 13,021 9,259 12,844 16,620 22,276 Return on verge net fixed ssets c (11%) (4%) 5% 5% 11% Debt-service coverge rtio d (1.68) (0.58) Debt equity rtio e 68:32 69:31 70:30 70:30 72:28 Receivble dys ( ) = negtive, FX = foreign exchnge, GWh = gigwtt-hour, kwh = kilowtt-hour, m = million, NEA = Nepl Electricity Authority. Selected yers shown for brevity. b Includes cost of sles, operting costs, dministrtion costs, nd deprecition. Finnce costs re excluded. c Clculted s ernings before interest, tx, nd deprecition divided by closing net fixed ssets. d Clculted s ernings before interest, tx, nd deprecition divided by interest nd principl pyments due. e Long-term debt divided by equity net of ccumulted profits/losses. Note: FY denotes the fiscl yer ending on 15 July of the clendr yer indicted. Source: Asin Development Bnk stff estimtes.

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