Review of Financial Restructuring Plan of Nepal Electricity Authority (NEA) Prepared by AF-MERCADOS EMI May 2012 MERCADOS EMI AF-MERCADOS TABLE OF CONTENT TEXT ................................................................ I BACKGROUND AND CONTEXT ...............................................2 PERFORMAN II ANALYSIS OF NEA’S HISTORICAL PERFORMANCE ................................ .............................................. 4 2.1 OPERATIONAL PERFORMANCE PERFORMAN ............................ 4 ............................................................ .................................... 4 2.1.1 DEMAND AND SUPPLY GAP ................................................................ .................... 5 2.1.2 TARIFF AND AVERAGE COST OF SUPPLY.................................................... ..................... 7 2.1.3 TECHNICAL AND COMMERCIAL LOSSES ..................................................... IMPLEMENTATIO ................................................................ 2.1.4 PROJECT IMPLEMENTATION ................................... 7 2.1.5 NEA’S HISTORICAL PERFORMANCE PERFORM ES INCORPORATED ......... 7 WITH KEY MEASURES ................................ 2.1.6 DEMOGRAPHICAL AND GEOGRAPHICAL ISSUES ........................................... 8 ................................ 9 2.2 FINANCIAL PERFORMANCE ................................................................ ......................................... 10 2.2.1 OPERATIONAL COSTS ................................................................ ................................ ............ 11 2.2.2 FINANCING COSTS ............................................................................ .................................. 12 2.2.3 OTHER FINANCIAL ISSUES ................................................................ ............................. 12 2.2.4 FINANCIAL POSITION OF NEA ............................................................. CIAL RECOVERY PLAN ....................................................... III NEED FOR A FINANCIAL ....................... 15 .......................................... 15 3.1 CURRENT STATUS OF NEA ................................................................ ................................ 17 3.2 SALIENT FEATURES OF FINANCIAL RESTRUCTURING PLAN (FRP) .................................. ND ITS IMPACT ............................................................... IV EMERGING ISSUES AND ............................... 20 ................................ ...................................... 24 V ANNEXURES ................................................................................................ MERCADOS EMI AF-MERCADOS I BACKGROUND AND CONTEXT The Nepal Electricity Corporation (NEC) was formed in 1962 with limited functions of operation and maintenance of Power Plants and consumer services. At the time of establishment, NEC had installed capacity just over 100 MW and a small consumer base. The Nepalese Electricity market was under Electricity Department (ED) of GoN, Nepal state monopoly till 1984, being exercised through the Electricity Electricity Corporation (NEC) and different special purpose development committees to construct anning and some development works were taken up by ED and major hydroelectric projects. Planning development works were taken up by specific development committees whereas operation and maintenance of the generation, transmission and distribution and supply businesses were taken up by the NEC. The Nepal Electricity Authority (NEA) was established in 1985 under the Nepal Electricity Authority Act 1984 to meet the objective of creating a single entity responsible for planning, development as perating in a commercial manner. well as O&M, operating manner 1 .1: Snapshot of NEA Progress since Inception Table 1.1: Parameter NEA at Inception NEA Today (‘erstwhile NEC’) (July 2011) Installed Capacity (MW) 103 ~700 Consumer Base (Nos.) 1, 84, 000 20, 53, 000 Asset Base (NRS Billion) 2.73 109 Revenue Base (NRS Billion) 0.38 18.00 Source: NEA (2011) he total installed capacity of the country Currently the co 10 of which 696.43 MW is is 700.9 MW as of 2009-10 grid power and ~5 MW of power being produced off grid. Figures 1.1 & 1.2 indicate the break- within-grid up of the capacity into hydroo and thermal and also the type of HEP (as of 31st March 2011). 2011) Figure 1.1: In Grid Capacity (696 MW) up (643 MW) Figure 1.2: Hydro Capacity break-up Source: NEA (2011) Over the years, the Nepalese Power Sector has witnessed significant interest from the multilateral funding agencies like the World Bank, Asian Development Bank (ADB), DANIDA, USAID, NORAD etc. aimed with active investments in projects, programs and initiatives a imed at improving the Power Sector of the country. The World Bank in particular has been making significant efforts to facilitate project development in the country by financing critical projects. Some of the investment in this regard include: (i) itation of the Kali Gandaki ‘A’ Hydro Electric Plant (HEP), the largest plant in Nep Rehabilitation Nepal’s power system, as well as two existing thermal plants plants in Duhabi and Hetauda; (ii) Financing of the Bardaghat transmission line, to strengthen the old and severely Bharatpur-Bardaghat rely overloaded distribution network in Kathmandu Valley, and expand the Government’s off hydro rural electrification off-grid micro-hydro program; and (iii) Kabeli Transmission Project to support the addition of transmission capacity to the Integrated Nepal Power System. . In addition to the above, several discussions are already underway to expand this portfolio further. However, several concerns exist. 1 NEA has demonstrated technical capacity to implement and maintain transmission lines of up to 132 kV. The Integrated National Power System (INPS) has more than 1,600 km of transmission lines at the 132 kV level which are owned and maintained by NEA. dition, INPS has about 370 km of transmission lines at the 66 kV level. Existing substation capacities are about 1415 MVA, In addition, MERCADOS EMI AF-MERCADOS The Nepal Electricity Authority (NEA), the key body governing the power sector in Nepal has been ancial strain since the last 5 years and its ability to pay is a cause of concern that under severe financial may affect many of the upcoming projects going forward. . The ongoing power crisis in Nepal has been hampering Nepal’s economic development with over 14 hours power cuts in the lean hydro seasons. The recent growth in generation capacity has been unable to keep pace with the demand and the country faces widespread outages, particularly in the lean hydro seasons. NEA serves 15-20 15 percent hich shows a relatively low level of electrification. There of the total population of Nepal which here is a great e disparity between urban and rural electrification rates as in urban area the rate is 90 percent where 10 percent only. as that in rural area is 5-10 Even though the electrification level is poor, it is expanding, placing burdens on the NEA operations and finances. NEA has not had the benefit of any tariff increases in the past ten years even though substantially. This has put NEA under severe financial strain. the cost of service delivery has gone up substantially. , high system losses, high The position of power sector in Nepal is unsatisfactory because of low tariffs, rheads, over staffing, which has resulted in NEA suffering from excessive generation costs, high overheads, debt accumulation and lack of funds for undertaking expansion projects. The cost of generation and distribution of one unit of electricity has doubled in last ten years. This has led to accumulation of enormous amounts of liabilities for NEA and as a result result of this, NEA has reached the brink of sustainability and is not able to perform its operations or reduce its AT&C losses. The utility also faces high currency conversion risk since many generation projects are undertaken by NEA along with developers of foreign origin. This has led to transactions taking place in foreign currency, and since the Nepalese Rupees is steadily losing value, NEA has to pay more to transact in the foreign currency leading to massive losses. In summary, key factors responsible for f the weakening financial position of NEA are: • No tariff revisions in the last 10 years • High system losses • Increasing Costs i.e. the Power Purchase Costs and O&M expenses • Mismatch between the cost of supply and the revenue Taking note of the above situation, NEA has embarked upon a path to arrest the current losses by 2 developing a Financial Restructuring Plan (FRP) for the company . The FRP covers several aspects sales tariffs to such as issuing debentures, reducing financing costs, settling disputes, adjusting sale match debt service requirements, etc. However, there are several aspects that need to be additionally incorporated to ensure that NEA not only recovers from the current conundrum but is also able to effectively perform in 3 view of the future changes being witnessed in the Nepalese Power Sector . Keeping this in Mercados EMI was entrusted to prepare a report that brings to picture these aspects AF-Mercados along with their implications in the long run. sections The report covers the following critical sections. ’s Historical Performance Section II- Analysis of NEA’s Section III- Need for a Financial Recovery Plan Section IV- Emerging Issues and its Impacts Section V- Annexures 2 discussed with the Nepalese Government and principally approved It is understood that the FRP prepared by the NEA has been discussed 3 These changes are discussed and elaborated in the subsequent sections of the report. MERCADOS EMI AF-MERCADOS HISTORICAL PERFORMANCE II ANALYSIS OF NEA’S HISTORICAL The ongoing power crisis in Nepal has its roots in various inefficient practices that had been continuing since long. Over the years NEA has been under severe financial strain. Factors like purchas etc. have hampered Nepal’s irrational tariffs, high system losses, high cost of power purchase economic development with over 14 hours power cuts in the lean hydro seasons. PERFORMANCE 2.1 OPERATIONAL PERFORMA The operational inefficiency of power sector in Nepal has played a major role in shaping up the current picture, where NEA is at a critical stage looking for serious changes. These inefficiencies have resulted in general shortage of electricity which is manifesting itself in scheduled power cuts which became an incremental part of power supply in Nepal within the last years. Especially during dry- dry season Nepal’s dependence on hydropower becomes obvious, forcing the NEA to cut power in Kathmandu up to 16 hours per day (as in April 2011). y Gap 2.1.1 Demand and Supply The gap between demand and supply of power in Nepal is historical and is increasing year on year on account inadequate capacity addition and high level system losses. F Figure 2.1 illustrates the growing gap between electricity demand and supply and c orresponds with the appearance of load corresponds load-shedding. Since 2006/07 the supply gap increased from 105 GWh to 678 GWh in 2009/10, with the temporary peak in 2008/09 with 745 GWh. Furthermore, the figure shows the seasonal fluctuations due to e river discharges. Due to glacier melt and intensive rainfall during the monsoon irregular run-off the season, electricity supply almost matches the demand between June and October. However, during along the winter (where precipitation is far less) generation capacity decreases alon run g with diminishing run- off rivers. Figure 2.1: Gap between Electricity Demand and Supply in GWh Source: www.energypedia.org In order to meet the growing hunger for more electricity, imports from India became more important state-owned during the last decade. Whereas private and state owned hydropower generation has doubled in the last ten years, power imports from India almost tripled (from 238 GWh in 2001 to 694 GWh in 2011). between industrial (manufacturing) sector In 2008/09 consumption of electricity was almost balanced between (37.37 %) and households (45.52 %), while the commercial sector consumed only 6.6 %20. However, the industrialized and urban areas account for the majority of electricity demand. Around 28 % of n Nepal in the year 2005 was consumed in the Kathmandu Valley alone. electricity produced in Between 2002 and 2011 (estimated figures) peak demand has more than doubled from 426 to 946 MW. The shortage in electricity in Nepal has reached to a level ~ 500 MW in dry seasons. This if not addressed, will jeopardise the sector in future. Figure 2.2 shows the increasing trend in energy availability and peak demand MERCADOS EMI AF-MERCADOS Figure 2.2: Total energy availability and peak demand 2.1.2 Tariff and Average Cost of Supply The Nepalese power sector has been facing cash flow issues since more than a decade. The average cost of supply is far more than the revenue realized. The main factors responsible for this mismatch tariffs and increasing are non- adjustment of the electricity tariff ing fuel and operating expenses. In Nepal, tariff has been revised only twice in 1998 and 2001. The Electricity tariff was increased by 10% in September 2001. Since then there has been no tariff adjustmentadjustment. cost of supply of power, with implications that the Figure 2.3 compares the historical revenue and cost average cost of supply has been higher than the revenue collected over most of time in last one decade. Figure 2.3: Revenues Vs Costs Source: NEA The above situation is due to the fact that prices of all inputs in market have gone up many folds. About 45% of the total energy served by NEA comes through purchases. There is regular annual escalation of about 6% on most of the internal purchases from IPPs, about 5.5% on import und under power exchange agreement and the import under trading agreements escalates by about 50%. NEA has been absorbing all these escalations over the years. Figure 3.2 shows the breakdown of cost of supply over the years. It is seen that historically the power purchase cost contribute almost 40% of the total cost of supply. The sudden increase in the cost of power purchase in 2007 had drastically increased the gap between revenues and total cost of supply. This gap has now reached abnormal levels. MERCADOS EMI AF-MERCADOS igure 2.4 cost of power purchase contributes almost 40% of the total cost of As shown in figure power supply. There has been a tremendous jump in the cost of power purchase post 2007. revenue have not been Since then the expenses have drastically increased, however the revenues able to keep pace with it. 2.4 Breakdown of Costs over the Years Figure 2.4: Source: NEA Another analysis shown in figure 2.5 based on historical data reveals that the cost of power purchase especially that of imported power India has been hitting the finances of NEA the most. Figure 2.5: Variations in the total Generation Costs in NRS/kWh (Own Generation and Power Purchase costs) Source: NEA 2006-07, the cost If we analyze the average sales price and cost of service in Nepal since 2006- of service per unit has increased at CAGR of 8.74%, while the average sales price per unit has increased at a minimal CAGR of 0.08%. Table 2.1 compares the saless and cost figures from 2006-11. V Cost of Production from 2006-2011 Table 2.1: Average Sales Prices Vs Description FY 2006/07 FY 2007/08 FY2008/09 FY2009/10 FY2010/11 (Provisional) Avg. Sales Price 6.56 6.51 6.46 6.63 6.58 (NRS per kWh) Cost Of Service 6.91 7.33 9.17 9.77 9.66 (NRS per kWh) Net Profit (Loss) (0.35) (0.82) (2.71) (3.14) (3.08) (NRS per kWh) Source: NEA MERCADOS EMI AF-MERCADOS 2.1.3 Technical and Commercial losses non It is widely accepted that NEA’s non-technical losses are excessive, and that any initiative to reduce priority Various initiatives in this regard were taken, however losses must target those losses as first priority. all in vain. Some of them include the inclusion of targets for loss reduction in management contracts for the distribution centers; and a s cheme, supported by the Danish Government, scheme, co operatives, which assumed to sell electricity at discounted wholesale rates to consumer co-operatives, ownership of the local distribution networks and responsibility for their operation. NEA committed to decrease losses by 2% 2% every year; however this could not be realized. The Government also introduced the Electricity Theft Control Act 2058 and the Electricity Theft treat Control Regulations 2059, which treated g electricity theft as a criminal offence and gave NEA new powers to deal with the problem. However no significant improvement could be achieved and slowly these losses started showing their impact on the finances of NEA. In 2003 the system losses were 22.9% which have now reached to level of 27.4% in 2011. Figure 2.6 shows t that despite several initiatives, the losses in NEA’s system have gradually increased. : NEA’s System Losses over the Years Figure 2.6: Source: NEA 2.1.4 Project implementation NEA has been facing high cost of projects constructed under grants as these projects are awarded under limited bidding (i.e. MMHEP). NEA has also been facing delays in project development. The 10th five year plan had set a target of adding 314 MW of power (100MW by NEA and 214 by private sector) only 40 MW could be added. The MMHEP (70MW) was delayed by 5 years and its cost was just double than the base price of estimated amount. III, Chamaliyagarh and Trishuli-IIIA The construction of the KL-III, Trishuli IIIA projects has been delayed. The revised target for completion is 2015 construction of UTKHEP is also getting delayed and revised Hetauda- Bardaghat , Due to delays in construction of the 220KV transmission lines especially Hetauda- transmission system has encountered congestion and is unable to transfer all the powers generated Kathmand by KG A and MMHEP to Kathmandu-Hetauda- Biratnagar. This has resulted in spill energy in wet season on one hand while on the other; NEA has to resort to load shedding even in wet season. 2.1.5 NEA’s historical performance with key measures incorporated Mercados analysed NEA’s historica AF-Mercados l performance incorporating certain key measures. Figure 2.7 historical shows the annual tariff hike that would have been required to match revenues costs. Similarly if there l would have been a loss reduction of 0.5% annually the required tariff hike would have been lower as shown in figure 2.8. MERCADOS EMI AF-MERCADOS years Figure 2.7: Tariff Hikes in each year to bridge revenue gap (over last 10 years) Source: NEA Figure 2.8: Tariff Hikes in each year to bridge revenue gap (over last 10 years) @ 0.5% loss reduction each year Source: NEA 2.1.6 Demographical and Geographical issues he geographical condition of Nepal does not allow grid extension to remote rural areas due to high The infrastructure cost and losses, lack of optimum load, and poor returns compounded by constrained gainst the backdrop, modern energy solutions in the form of improved cook Government budget. Against stoves, biogas, and agriculture and forest waste based biomass power generation plants, distributed in the urban areas it is 90 generation, there is a great disparity in the electrification rate in Nepal, and in percent where as in rural areas it is less than 10 percent only. Nepal has significant rural population (approximately 80%4 of total population with over 30% living below the poverty line of US$ 12 per person /per month) including large segments that still do not 4 Source: International Fund for Agricultural Development, 2004 MERCADOS EMI AF-MERCADOS have access to electricity. Lack of adequate access or increase in electricity prices significantly impact andard of living and is generally accompanied by corresponding reduction in spending on basic their standard society amenities. Inadequate supply of electricity further accentuates inequality in the Nepalese society. : Nepal’s Urban and Rural Geographies Figure 2.9: or the Central Region (Mid North and Mid South), a large part in the country is pre Except for pre- dominantly rural in the country. Based on the analysis it is seen that the cost of serving rural areas in overall revenue and since 2007 there Nepal has been too high. Rural areas hardly contribute in the overall has been significant loss in such supplies. Figure 2.10 shows the same Figure 2.10: Cost of serving rural areas Source: NEA INANCIAL PERFORMANCE 2.2 FINANCIAL Due to continuous financial loss in the last few years NEA’s financial health is in bad shape. Various factors have contributed in deteriorating NEA’s financial health in last few years. Not only the pending tariff adjustment for a long period, but also the higher cost of capital, high cost of projects, rural electrification and high power purchase granted as well as bilateral projects, agreements costs in past have been the reasons for worsening financial performance of NEA. It is also noted that high cost of service along with no tariff adjustment for almost a decade kened NEA’s financial health has not only weakened health, it is also contributing towards miss match between demand and supply in electricity market resulting into very serious economic problem called upon by long hours of load shedding in Nepal. MERCADOS EMI AF-MERCADOS sufficient cash from business operation, which is required for debt NEA has not been able to generate sufficient service obligation and for funding future development projects (generation, transmission, distribution and strengthening). There has been year on year increase in payable to government and such outstanding payable was recorded to Rs 21.02 billion in FY 20 20 2009/10. Net losses for the FY 2009/10 were recorded to Rs 6.96 billion compared to Rs 4.9 billion losses in FY 2008/09. . This has weakened NEA’s ability to pay current liabilities (payment to contractor) on time. Table 2.2 presents a snapshot years. of NEA’s financial status for the last five years : Financial Snapshot of NEA Table 2.2: Figures in Million NRS Description 2006 2007 2008 2009 2010 2011 Revenues 13,332 14,450 15,041 14,406 17,165 18,004 EBITDA 3,516 4,118 3,651 2,846 1,997 2,283 PAT (1,268) 240 (2,315) (5,093) (6,924) (6,512) Shareholder's Equity 17,568 20,730 21,032 21,058 19,261 16,100 Change - 3,162 302 26 (1,798) (3,161) Source: NEA (2011) Table 2.2 clearly shows the grim picture of NEA’s finances over the years. NEA has been suffering om a negative operating margin and underinvestment. Excess demand has lead to from widespread power rationing. 2.2.1 Operational Costs The weak financial position of NEA is on account of increasing expenses in terms high operational costs. NEA purchases power at a very high rate. As of 2009/10, the effective power purchase rate from IPPs and Import is higher (NRS 8.97 / KWh) than NEA’s av erage net sale price average (at NRS. 6.58 /KWh). Thus, NEA incurs a direct loss of NRS 2.25 per unit on sale of every kWh. This is further contributing to the already high financial losses incurred by the NEA. PPAs are on “Take or Pay” basis. Thus even during wet season, NEA is compelled to buy energy from IPPs and spill the water from its generators. During dry season, NEA has to import power from India on commercial terms to meet the energy demand. Company (HPLC) is the most expensive Among the IPPs with the higher purchase rates, Himal Power Company followed by Bhotekoshi Power Company (BKPC), Chilime Hydropower Company Limited (CHPCL) and Butwal Power Company (BPC). . PPAs in the first two cases are dollar denominated resulting in the exchange risk as well. Table 2.3 indicates the contract energy and average rate from various IPPs for 2009/10. a large part of the cost remains unrecovered. The revenue gap was of the or order of NRS 3.08 per unit at the end of FY 2010/11 : Average Tariffs & Contract Energy for IPPs during 2009/2010 Table 2.3: Plant Average Rate Contract Energy (NRS /kWh) (GWh) HPLC 6.97 350 BKPC 6.84 246 CHPCL 6.27 133 BPC 5.17 850 Source: NEA (2011) Besides power purchase costs, the cost of NEA’s own generation, transmission and distribution have rend of per unit cost increased drastically in last 5 years. Figure 2.11 below shows the historical trend distribut contribution by generation, transmission and distribution segments in Nepal. . There has been a significant increase in the costs particularly generation. MERCADOS EMI AF-MERCADOS Figure 2.11:: Historical Trend of Per Unit Cost Contribution by Generation, Transmission and Distribution Segments in Nepal 2.00 1.80 Per Unit Cost (in NRs) 1.60 1.40 1.20 Per unit cost of distribution 1.00 0.80 Per unit cost of transmission 0.60 Per unit cost of generation 0.40 0.20 0.00 nses of NEA in 2008-09 A look at the operating expenses 2008 10, clearly indicates that power and 2009-10, purchase costs and generation costs are the primary components of operating costs and have been c contributing maximum share in the overall increase of costs. Table 4.2 compares the operating costs and the % increase in different components. : Operating Expenses in 2008 Table 2.4: 2008-09 and 2009-10 Operating Expenses (M. NRs) 2008-09 2009-10 % Increase Generation 1119.7 1541.26 37.6 Power Purchase 7691.2 9746.5 26.7 Transmission 328 337.7 3.0 Distribution 2575.09 3091.2 20.0 Others 3,905.58 4,653.50 19.2 Source: NEA 2.2.2 Financing costs NEA has been facing high cost of projects constructed under grants as these projects are awarded under limited bidding (i.e. MMHEP). High interest rates have been impacting the cash flows of the NEA. Interest rate on long term loan under bilateral and multilateral agreement is 8% (up to 2005/06 it was 10.25%). The interest on term loan has been increasing year on year and resulting in negative profits. Figure 2.12 shows the increasing interest burden of NEA. Figure 2.12: Year on Year comparison between EBITDA and Interest on Long Term Loans Source: NEA MERCADOS EMI AF-MERCADOS There is net outstanding amount of 50.4 Billion for the projects having high interest rates i.e. 8%. Considering the low foreign exchange risk to GON present relending rate is still high to NEA. Further it from internal source for capital investment in new has been difficult for NEA to mobilize resources from projects due to increasing operational loss resulting annual cash deficit. Investment in Renewable Energy in Rural Areas by NEA is also a a loss making business. transferred to NEA as loan. Rate of return on Grant assistance by WB, ADB to GON is also tra run RE investment is very nominal, consequently, NEA can’t sustain in long run. 2.2.3 Other Financial Issues There are several other issues which have affected NEA’s finances in recent years. Some of them are: • Electricity act 1992 provides for royalty on the sales price of electricity at generation point. The IPPs have been paying on the same basis. However NEA has been paying royalty at the selling price assumed at generation point Rs. 5.41 per kWh which is higher higher than the actual deemed selling price at the NEA’s generation station ( Rs 4.0 per kWh) even after adding 12% profit margin in its actual cost of generation Rs. 3.57. This has added the expenditure by Rs. 150 million per annum to NEA. Recently MoLD (Ministry of Local development) has demanded royalty from NEA on the power purchase from Tanakpur which is not justifiable • The receivables from municipalities on account of street lighting amounted to NRS. 1.84 billion up to 2008/09 and the Government of Nepal (GoN) paid NRS. 980 million and the balance of NRS860 million was written off by NEA. The payment mechanism for the street light bill of Municipalities' receivable from FY 2009/10 as well as outstanding bill of VDC has not been finalized and the total receivab stood approx. at NRS. 2,253.50 million up to 2010/11 including 25% surcharge • th In the last five years, NEA’s power stations generated only 2,093.23GWh which is less than by 21% of the annual generation of 2647.55 GWh. NEA is losing an annual income of Rs 2,650 million from the potential sale of 554.32 GWh. • At present NEA’s liabilities towards retiring employees’ amount to about Rs. 9,000 million as per liability. Many claims actuarial valuation but NEA does not have fund to manage this liability laims put forward by the contractors are in the process of tribunal. If these claims are not settled in NEA’s favor, then NEA will have to bear additional liability of NRs. 8/10 billion. 2.2.4 Financial Position of NEA here has been no adjustment in electricity sales tariff since 2001 the financial health of NEA Since there has aggravated. Deficit budget stands at about NRs. 6,000 million p.a. Annual financial loss of NEA is increasing about by Rs. 7 billion million every year year. The financial position as in 2010 was as follows: • Share Capital- Rs 38.64 billion • Reserve & Surplus- Rs (18.42) billion • Long Term Loan- Rs 58.02 billion • Net Working capital- Rs (25.66) billion • Net Fixed Assets- Rs 83.13 Billion • Capital Work in Progress- Rs.16.90 billion • ty Shares Investment in Equity Shares- Rs 4.42 billion • 10- Rs 5.95 billion Net loss for the FY 2009/10 • Deficit Cash Flow- Rs. 7.81 billion • Overdue payable to GoN o Interest: Rs.14.91 billion o IDC : Rs. 10.16 billion, o Royalty : Rs. 1.06 billion Power Purchase: Rs. 1.03 billion MERCADOS EMI AF-MERCADOS Currently the accumulated financial loss stand at Rs. 27.53 billion (provisional) and has crossed 2/3 of its paid up capital. The profitability status of NEA has been shown in Table 2.5 Table 2.5: Profitability Status of NEA FY20010/11( Description FY 2006/07 FY 2007/08 FY2008/09 FY2009/10 pro.) Net income from sale of 14,449.93 15,041.49 14,405.93 17,164.60 17,934.18 electricity Total Expenses 16,020.69 (18,311.62) (21,120.82) (25,276.46) (25,635.40 Operating Profit ( loss) (1,570.76) (3,2270.15) (6,714.89) (8,111.86) (7,701.22) Other Income 1,016.61 (934.66) (1,601.67) (1,188.27) 1,189.58 Net profit ( Loss) (554.15) (2,335.47) (5,113.22) (6,923.59) (6,511.64) Accumulated Loss 6,650.14 8,985.61 14,098.83 21,022.42 27,534.06 Source: NEA : Graphical Representation of NEA’s Profitability Figure 2.13: NEA Profitability 30000 2000 1000 s 25000 nNr 0 s d e nNr n r 20000 -1000 u illio ea it illio d -2000 u Tinm n 15000 n e -3000 in m e p v x e 10000 -4000 E R B -5000 P 5000 -6000 0 -7000 0 1 2 3 4 5 6 7 8 9 0 0 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 2 2 2 2 2 2 2 2 2 2 2 Fisca l Ye a r Revenue Expenditure Profit/Loss before tax Source: NEA If tariff is not increased within this fiscal year then the accumulated loss would be about NRs. 50,000 million in the next 3 years. This will make the net worth negative. Consequently NEA will be unable to meet the cost of operation, maintenance, and power purchase 2.6 clearly indicates the cash flow crisis in The historical trend of NEA’s financial ratios given in table 2.6, the sector. MERCADOS EMI AF-MERCADOS Table 2.6: Ratio Analysis of NEA’s Historical Performance FY FY FY FY FY Description 2006/07 2007/08 2008/09 2009/10 2010/11 (pro.) Solvency ratio 30:70 30:70 28:72 25:75 21:79 Gross profit Ratio (%) 37.48 36.64 31.03 27.32 26.57 Expense Ratio (%) 105.36 113.98 146.47 147.96 142.94 Net profit Ratio (%) 1.67 (6.39) (31.82) (37.72) (34.05) Return on Fixed Assets (%) 5.07 2.53 (3.90) (3.96) (3.52) Debt Service Coverage Ratio (%) 1.32 1.25 0.40 0.33 0.38 o The decreasing solvency ratio over the years is an indication that NEA has been aggressively using debts to finance its assets. This is also on account of accumulating interest payments. o There has been a regular decline in NEA’s gross profit margin. This is on account increasing costs and inadequate revenue realization. o On account of increasing cost of power purchase and other operating costs there has been a drastic increment in the expense ratio of NEA over the years. o 08 NEA has been suffering from a negative net profit ratio. This is on Since 2007-08 account of a negative operating margin that has continued over the years o The increasing debt burden and inadequate revenue has completely degraded NEA’s DSCR. There is hardly any cash flow available to meet annual interest and principal payments on debt, including sinking fund payments. MERCADOS EMI AF-MERCADOS III NEED FOR A FINANCIAL RECOVERY PLAN The historical analysis in the preceding section shows that NEA’s operational and financial health has been under serious threat over the years. Looking at the current status of NEA it seems that unless seriou consequences in the future. urgent measures are taken, the sector will see serious 3.1 CURRENT STATUS OF NEA ak load in the country is ~947 MW resulting in a shortage of over 500 MW in dry Currently the peak 700 MW, only 308 MW was available during the winter of seasons. Out of total installed capacity of ~700 2009-10. Even with a maximum available import capacity of 80 MW, a deficit of over 50% of demand was inevitable. The peak and energy demand is growing at an average annual rate of about 10%. Shortage of energy and capacity is expected to continue for quite some time to come as there is no significant addition of generating plants. The shortage has forced NEA to resort to load shedding. Table 3.1 shows the volatility of the power supply during the wet and dry seasons. The Nepalese Power Sector faces a peak shortage of ~450 MW. : Variability in Power Supply & Demand during Wet and Dry Seasons. Table 3.1: Demand Availability Surplus Season (MW) (MW) (MW) Wet Season 1185 1286 101 Dry Maximum 1292 833 -459 Source: NEA (2011) At the consumer end, shortage of power in the lean hydro seasons has led to increased deployment of non-availability coping strategies, particularly in the use of diesel to substitute non availability of the grid power. This can be clearly witnessed from the increased dies el consumption by consumers in Nepal during the diesel lean hydro season i.e. from December to May 2011 (Refer Figure 3.1). Future projections indicate durin the dry season is likely to continue in the next five that the shortage scenario particularly during years (2014-15). wise break of Diesel Consumption (in kilo litres) during 2010/11 Figure 3.1: Month-wise 75000 70000 65000 60000 55000 50000 45000 40000 35000 30000 25000 Apr-11 Sep-10 Jul-10 Aug-10 Feb-11 Nov-10 Oct-10 Jan-11 Mar-11 Jun-11 Dec-10 May-11 Source: NEA (2011) 5:30-9:30 PM) NEA system load curve has peak demand in the evening (usually between 5:30 followed by another peak in the morning which is about 80% of the evening peak. Peak happens in winter season when the discharge in the rivers decreases. Nepal experiences period critical power shortages during winter period. Figure 3.2 below shows the energy demand/ supply and the corresponding load shedding in 2011-12. It is seen that the months of Falgun and Chaitra witnessed maximum energy deficit with load 20 hrs daily. shedding reaching almost 19-20 MERCADOS EMI AF-MERCADOS : Demand/ Supply and Load shedding Scenario in 2011 Figure 3.2: 2011-12 Source: NEA In Nepal the increased demand d for power is growing at a rate of over 9% YoY: The energy 17 is over 7600 MUs requirement projected for FY 2016-17 MUs. The upcoming Muzaffarpur rpur – Dhalkebar 400 kV line is likely to create significant demand pressure within Nepal as it allows higher capacity of electricity transmission as compared to its existing lines of ~100kV. The emand is likely to match up with the energy requirement (or the unconstrained demand). demand demand) The increasing demand is placing burdens on the NEA operations and finances. NEA has not had the benefit of any tariff increases in the past ten years even though the cost of service delivery has gone finan up substantially. This has put NEA under severe financial strain. The position of power sector in Nepal is unsatisfactory because of low tariffs, high system losses, high generation costs, high overheads, over staffing, which has resulted in NEA suffering from excessive debt accumulation and lack of funds for for undertaking expansion projects. The cost of generation and distribution of one unit of electricity has doubled in last ten years. This has led to accumulation of enormous amounts of liabilities for NEA and as a result of this, NEA has reached the f sustainability and is not able to perform its operations or reduce its AT&C losses. brink of The utility also faces high currency conversion risk since many generation projects are transactions undertaken by NEA along with developers of foreign origin. This has led to transa taking place in foreign currency, and since the Nepalese Rupees is steadily losing value, NEA has to pay more to transact in the foreign currency leading to massive losses. In summary, key factors responsible for the weakening financial position of NEA are: • No tariff revisions in the last 10 years • High system losses • Increasing Costs i.e. the Power Purchase Costs and O&M expenses • Mismatch between the cost of supply and the revenue Taking note of the above situation, NEA embarked upon a path to arrest the current losses by 5 developing a Financial Restructuring Plan (FRP) for the company . The FRP was developed by a committee formed by the Government of Nepal. The FRP covers several aspects such as issuing disputes, debentures, reducing financing costs, settling disputes, adjusting sales tariffs to match debt service requirements, etc. Salient features of RFP have been discussed in the next chapter. 5 y the NEA has been discussed with the Nepalese Government and principally approved It is understood that the FRP prepared by MERCADOS EMI AF-MERCADOS ING PLAN (FRP) 3.2 SALIENT FEATURES OF FINANCIAL RESTRUCTURING The Financial Restructuring Plan is aimed at bringing following changes: • To meet cost revenue gap • To translate negative Balance Sheet into positive one. • To promote the development of an efficient, reliable, commercially viable in power sector • To reduce dependant on Government for support • To finalize the SLA • To settle the receivables & payables between GoN and NEA • To adjust electricity sales tariff based on • Cost ( required to hike by 40% to meet BEP) • Debt service (required to hike by 45% to meet DSCR) • Cash flow for Project investment and recovery of accumulated losses within a period of four years (required to hike by 75% to meet project investment) The Plan will aim to incorporate following recommendations: • Financial Institutional Reform (Share Capital, Reserve & surplus) – Increase Authorized capital From NRs. 30 billion to NRs 75 billion – Writing off accumulated loss NRs 27.53 billion – Conversion of Interest During the Construction Period (IDC) NRs. 9.620 billion into Equity – and 15% to Revising the ratio for project investment between GoN and NEA from 5% and 10/10% . – Writing off Foreign Technical Assistance ( TA) received other than Capital Goods instead of current practice of capitalizing in equity and/or Long Term loan • Long Term Loan & Grants – In case of projects for which no subsidiary agreement has been made, such agreement has to be made without delay – Projects constructed funding through foreign grants shall be capitalized at 50% of such grants and the same shall be accounted as loan instead of grants – rsyangdi HEP and Load Dispatch Center Grants related to the projects (Middle Marsyangdi concluded) extension) shall be converted accordingly( SLA has not been concluded)- • Interest Rate – Reducing interest Rate from 8% to 5% financing through foreign source. – Reducing Interest rate on local source from 6.5 % to 5%. – In case of the projects in which interest rate is specified but SLA has not entered into, SLA has to be made fixing the rate at 5%. – Interest rate of the project with specified interest rate less than annual 5% has to be maintained as it is. – ting IDC of a project, the interest rate shall be calculated by taking only 50% For calculating of the chargeable interest rate. – IDC of a project from a grant should be zero – The aforesaid interest rate should be made applicable from FY 2009/10 MERCADOS EMI AF-MERCADOS • Electricity Royalty – y shall be calculated as per the provision of Electricity Act 1992 i.e on the basis of Royalty selling price at Generation point • Capitalization of the MMHEP – i.e. Out of foreign portion of the grant Rs 13.540 billion, account only Rs. 6.670 billion i.e nt as loan while capitalizing the project. ( GoN should give up 50%) 50% of the grant – IDC and cost of the project increased from foreign exchange loss should also be adjusted accordingly. This will reduce the project cost by Rs. 4.75 million. • Settlement of Arrears between GoN and NEA – GoN has to receive from NEA Rs.21,412.34 billion and NEA has to receive from GoN Rs. 5,208.46 billion. – To adjust these amounts, the net amount payable by NEA to GoN is Rs. 16,203.88 million • Payment mechanism of Street Light Bills – GoN should deduct the amount of street light bill from the allocation of budget to local bodies and to make the full payment of such bill to NEA • Incorporation of Rural Electrification Company – electrification To mitigate the heavy loss suffering from rural electrification, a rural e company under the ownership of GoN should be incorporated. – The assets , liabilities based on rural electrification and the organizational structure of NEA have to be handed over to such company – electrification Alternatively, GoN has to operate rural electrification program only by providing subsidy to NEA • Operation of Multi fuel and Diesel Plant – If the multi fuel and diesel centers have to be continuously operated to supply electricity, the operation cost exceeding the average generation cost of NEA has to be made available to NEA by GoN as a subsidy – If the operation is only for the voltage improvement, NEA has to bear the entire cost • Issue of Debentures – To manage the required fund for project investment, it would be appropriate to make provision of investment by issuing debentures against the security of GoN • To control Electricity Losses – Reduce loss by 2% per year as committed in earlier years by NEA – operate for loss reduction GoN should co-operate – Initiate the activities specified in the Electricity Crisis Mitigation Program 2065 regarding loss control • Electricity Tariff adjustment – Legal provision for tariff fixation is already made – The Electricity Tariff Fixation Commission should take appropriate decision with regard adjustme to the long awaited tariff adjustment MERCADOS EMI AF-MERCADOS cover all the aspects pertaining to Though the Financial Restructuring Plan more or less covers verall aim has to be to develop a plan that provides strategic NEA’s financial health, its overall financial stress (aim of direction to NEA so that it not only recovers from the current financial Financial Restructuring Plan) but also to provides recommendations to sustain this in the long-run. Mercados EMI proposes a Financial Recovery Plan. Unlike a Financial Thinking on these lines AF-Mercados Restructuring Plan which is focussed on accounting issues, a financial Recovery Plan aim to analyze AF and incorporate several other dimension and not just financial and accounting issues. AF-Mercados throug following approach. EMI has analysed NEA’s current position through • Analysis of past performance and identifying critical issues affecting NEA’s performance • Identifying future development that could impact NEA finances significantly • Looking at other dimensions that can contribute towards improvement of NEA’s performance towards long run. Hence the Financial Recovery Plan proposed as part of this report looks at the following aspects reform measures are sustained in the long run. (Figure 3.3) to be addressed so that the overall reform run Figure 3.3: Things FRP Should Address 1. Legacy Financial Issues- • Tariffs abnormally low due to absence of revision since last 10 years • Escalating and Volatile Costs – Power Purchase and Operational al Commitments resulting in Cash Flow Constraints for NEA • Huge Capital • Large Energy Inflows with no commensurate tariff flexibility. 2. Organizational Issues • Unwieldy Organizational Structure – very large number of field accounting units (cost centres) resulting in lack of control and operations losses and leakages 3. Structural Issues • Outdated Systems and Procedures non • Large number of employees – Over 10,000 employees with low professional to non- professional ratio 4. Regulatory Issues • Inability/unwillingness of NEA to expand and serve rural areas • No regulatory push towards rationalization of tariffs A Comprehensive FRP besides addressing the above issues should also recognize the inter issues linkages and inter dependencies among the above is course sues and decide on appropriate course. MERCADOS EMI AF-MERCADOS IV EMERGING ISSUES AND ITS IMPACT The financial restructuring plan which aims at bringing reform on the financial and accounting front does not however consider other issues that might affect the future of power sector in Nepal. The Mercados EMI in the process of developing a financial recovery plan focuses on analysis done by AF-Mercados such developments in future. The anticipated scenario post restructuring is as follows: • The extent of financial restructuring requirements will be closely linked to the tariff awards • One time financial restructuring necessary, but not sufficient in a volatile operating environment • Next few years are likely to see significant changes: o New Generation projects will come o Larger IPP participation o New Transmission Lines o Large Quantity of Power Flows in the System with high level of volatility in the system There are several key challenges that need to be addressed as early as possible; otherwise the purpose of financial restructuring would be defeated. Some of these challenges are: • Tariffs abnormally low due to absence of revision since last 10 years • Escalating and Volatile Costs – Power Purchase and Operational • Huge Capital Commitments resulting in Cash Flow Constraints for NEA • flows with no commensurate tariff flexibility. Unless tariffs are made Large Energy Inflows more flexible, NEA could potentially suffer financially • Outdated Systems and Procedures • Unwieldy Organizational Structure – very large number of field accounting units (cost centres) resulting in lack of control and operations losses and leakages • Inability/unwillingness of NEA to expand and serve rural areas • non Large number of employees – Over 10,000 employees with low professional to non- professional ratio sector AF-Mercados In order to study the impact of future developments in the sector, Mercados EMI has done the following analysis: • Analysis of the demand trends witnessed by NEA; • Supply of electricity from various sources and identification of demand and supply gap, duly considering time of day and seasonal aspects; • Analysis of operations costs of NEA and trends in this regard; • Assessment of tariffs and a comparison of the tariffs with average cost of service delivery • Assessment of T&D losses and loss reduction based on available information • lopment of a detailed financial model consisting of operational. projections, Development investment plans, financing plans, tariff scenarios, etc Mercados EMI has been able to In an attempt to foresee the sector scenario by the end of 2018, AF –Mercados estimate revenues and costs under certain reform measures. Besides that impact of future developments in the sector on the financial and operational health of NEA has also been done. These have been discussed below. MERCADOS EMI AF-MERCADOS • Increased demand for power growing at a rate of over 9% YoY: The energy requirement 17 is over 7600 MUs i.e. a growth of over 9%. This would place a huge projected for FY 2016-17 strain in terms of demand for power in the coming five years. In addition to the above, with border interconnection i.e. Muzzarpur–Dhalkebar the coming up of cross-border Muzzarpur Dhalkebar 400 kV line, the demand is likely to grow even at a faster pace as supply will be available from source in India. • New Generation Capacity to be added in the next 5 years: Currently, 130 MW of hydro capacity is under construction/under execution. Key new projects that are likely to come up II (14 MW), Chameliya HEP (30MW), Trisuli include Kulekhani-II IIIA (60 MW) and Rahughat (32 Trisuli-IIIA MW), Budhigandaki (600 MW). • Larger IPP participation: Of the total planned capacity likely to come online in the next five years, a large percentage is to be contributed by the private sector. IPPs under the contractual framework will demand strong payment security mechanism • New Transmission Lines: Significant transmission capacity addition is expected in the next five years with over 12 transmission lines (220 kV and 400 kV) spanning 1200 km to be added. Key Dhalkebar-Duhabi lines include Hetauda-Dhalkebar Koshi Duhabi 400kV transmission line spanning 290 km and the Kos Transmission Corridor with a 220kV transmission line of 110 km. Commissioning of these lines would permit higher imports during the lean hydro seasons, as well as possibility of exports during the high hydro season. • Large Quantity of Power Flows in th e System with high level of volatility in the system: the inter-country lines, With the coming up of new transmission lines particularly the high capacity inter- the quantum of power flows is likely to increase significantly. In addition, owing to integration he Indian Grid, the power flows are likely to witness a high level of volatility that will need with the to be dealt with. All of the above issues are likely to have considerable impact on the NEA’s financial Financial Restructuring envisaged as performance and hence are essential elements of the Financial part of this assignment. Thus, it is essential that the FRP takes into account these realities (and possible scenarios that may emerge) and develop appropriate measures to ensure su that the sector moves on a path that is sustainable in the long-run. Figure 6 provides an indication of impact of the sectoral developments in the Nepalese Power Sector (upcoming Dhalkebar 400 kV line) on the NEA’s finances (based on certain assumptions). Muzzarpur–Dhalkebar : Likely Energy Supply/ Demand Scenario with commissiong of the Muzzarpur– Figure 4.1: Dhalkebar 400 kV line 14000 12000 Energy Requirement 10000 (GWh) 8000 Energy Available 6000 4000 Energy Requirements with 2000 new s upp ly Ad ditional energy 0 o ver current Source: AF Mercados EMI Analysis The upcoming Muzzarpur – Dhalkebar 400 kV line is likely to create significant demand pressure within Nepall as it allows higher capacity of electricity transmission as compared to its existing lines of ~100kV. The demand is likely to match up with the energy requirement (or the unconstrained demand). If NEA caters to the additional energy requirement, the sit uation can manifest situation itself into a huge opportunity to earn revenue or a big burden (as NEA loses NRS 3.08 for every unit sold to the consumer) for the NEA. Thus, it will be critical for the NEA to revive its current situation before the above integration occurs o . MERCADOS EMI AF-MERCADOS A major focus of financial recovery plan would be to increase and subsequently reduce the system . These measures will no doubt improve NEA’s profitability; however the impact of future losses. developments should be tracked. Keeping this mind three scenario have been developed and discussed below Hike- Business as Usual SCENARIO 1(Base Case): No Tariff Hike Unless there is significant hike in tariff, the costs will continue to outstrip revenue in future. Going forward by 2018 and afterwards the situation will worsen. The figure below shows that there is a significant gap between the base case revenues and the base case costs. : Future Projections with No Tariff Hike Figure 4.2: Source: NEA SCENARIO 2: One time tariff hike of 20% in 2012 Mercados EMI has estimated that with 20% tariff hike in 2012, the situation will improve and NEA AF-Mercados will become profitable by 2018. Figure 3.7 below shows the manner in which the sector will shape up going forward. : Future Projections with one Figure 4.3: on time tariff hike of 20% in 2012 Source: NEA MERCADOS EMI AF-MERCADOS Following key points emerge from the above figure: • Even though the accumulated losses have been taken from a base zero in 2012, they are so large increasing, thus nullifying the affects of tariff increase year on year. in number that they keep on increasing • The gap between cost and revenue will decrease but the major turnaround will happen in 2015 when Upper Tamakoshi Project comes online. • The same situation will occur with the commission of Budhigandaki Project in the middle of 2016. • The accumulated losses will continue playing their role in suppressing the profits. • Thus by 2018 NEA will become profitable but suffer from severe cash stress. The losses will remain but on a lower side. The point to be noted here is that above analysis is based on the assumption that the projects Upper Tamakoshi and Budhigandaki will come online on time as estimated. However looking at the history of projects in Nepal this seems very unlikely. SCENARIO 3: One time tariff hike of 20% in 2012 and Loss Reduction of 1% each year starting from 25% Taking note that tariff hike alone would not be able to tackle the situation; a scenario with loss reduction of 1% each year was considered. Figure 3.8 shows the result that is likely to emerge Figure 4.4: : Future Projections with one time tariff hike of 20% in 2012 and Loss Reduction of 1% each year starting from 25% Source: NEA Following key points emerge from the above figure: • There is a significant improvement in margins with revenues s urpassing costs in the middle of surpassing 2014. Profits become more prominent after 2016 and tend to increase after 2018. • Inspite of gradual reduction, accumulated losses will exist even beyond 2018 Looking at the above analysis it is imperative that the impact of future developments need to be carefully tracked to ensure that potential risks are obviated. Some of them are: 1. Delay in Commissioning of Upper Tamakoshi (450 MW) – Scheduled for 2015 – What happens when the plant gets delayed by 2 years ocurement Increases 2. Cost of India Procurement 3. Commissioning of Muzaffarpur –Dhalkebar Line 4. Unfavourable Foreign Exchange Variations MERCADOS EMI AF-MERCADOS V ANNEXURES Model Assumptions Generation Capacity & CODs Upcoming Cost NEA Plants of Cons Cod Exp. Capacity in Bn Capex Adl. Total D/E Stake in NEA Year Year MW Generation Ftr NPR Done Capex $ Mn Ratio Equity Kulekhani-III 2006 2013 14 40.85 33% 2.33 0.553 1,781 29.9 4 0% Chameliya 1997 2013 30 184.21 70% 9.38 2.070 7,305 120.0 4 50% Upper Trishuli 3A 2006 2014 60 460.00 88% 5.70 0.019 5,681 72.9 4 50% Ruhughat 2008 2014 30 186.00 71% 4.91 0.014 4,898 62.9 4 50% Upper Trishuli 3B 2008 2014 37 296.00 91% 5.10 0.015 5,085 65.3 4 50% Budhigandaki SHEP 2009 2017 600 2500.00 48% 42.12 0.677 41,440 539.0 4 50% Upper Seti Storage - Storage Project 2013 2018 127 484.00 44% 26.65 0.036 26,610 341.0 4 50% Tamakoshi VHEP 2014 2018 87 446.00 59% 11.17 0.000 11,170 142.9 4 50% Nalsyagu Gad - Storage Project 2015 2020 400 889.00 25% 28.99 0.007 28,982 371.0 4 50% Tamor Storage Project 2015 2020 382 1673.00 50% 28.99 0.001 28,989 371.0 4 50% Exp. Int. Capacity Existing Plants of NEA COD Year MW Generation Cons. Net Sold Ftr Panauti Hydro Power 1966 2 1,880 240 1,640 9% Trisuli H.P. 1967 21 114,939 745 114,194 62% Fewa (Pokhara) H.P. 1970 1 2,180 18 2,162 23% Sunkoshi H.P. 1972 10 60,594 500 60,094 69% Tinau H.P. 1974 1 6,000 80 5,920 67% Gandak H.P. 1979 15 20,525 650 19,875 16% Kulekhani-I H.P. 1983 60 75,114 1,200 73,914 14% Devighat H.P. 1984 14 81,438 350 81,088 66% Seti H. P. 1985 2 10,870 34 10,836 83% Kulekhani-II H.P. 1986 32 36,935 250 36,685 13% MERCADOS EMI AF-MERCADOS Marsyangdi Hy. Pro 1989 69 404,805 1,220 403,585 67% Tatopani H.P. 1995 2 13,000 19 12,981 74% Ilam Puwa H.P. 2000 6 31,683 52 31,631 58% Modi H.P. 2001 14 62,521 226 62,295 51% Kaligandaki 'A' H.P. 2003 144 753,368 2,954 750,414 60% Middle Marsyangdi Hydro P 2009 70 169,000 400 168,600 28% PPP - NEA Project Project NEA Expected Capacity Investment Capacity Cost Cost D/E Share Investment /GoN Const COD Gen factor done ($ (MW) (Bn (MM Ratio of due ($ Mn) owned (GWh) (%) Mn) NPR) USD) Equity Plants 2009 2015 456 2281 57.11% 34.00 435 2.33 41% 16.64 418.48 Upper Tamakoshi 2010 2014 42 202 55% 4.00 51 2.33 51% 1.47 49.72 Upper Modi A IPPs COD FY MW Remarks Planned Projects Belkhu 0.32 PPA concluded Golmagad 0.58 PPA concluded Lower Piluwa 0.99 PPA concluded Mai 2.40 PPA concluded 2011 4.29 Lower Indrawati 4.50 PPA concluded BhairabKunda 1.85 PPA concluded Jiri 0.99 PPA concluded Lower chaku 1.76 PPA concluded Biomass 0.50 PPA concluded MERCADOS EMI AF-MERCADOS Phawa 4.95 PPA concluded Tinau 0.99 PPA concluded Total 2012 15.54 Siuri 4.95 PPA concluded Chake 0.99 PPA concluded Hewa 2.40 PPA concluded Lower Nyadi 4.50 PPA concluded Tadi 3.50 PPA concluded Lower Modi 1 9.90 PPA concluded Mailung 5.00 PPA concluded Sipring 9.70 PPA concluded Charnawati 0.98 PPA concluded Dapcha Roshi 4.90 PPA concluded Upper Puwa 9.80 PPA concluded Total 2013 56.62 Madi 10.00 PPA concluded Upper Mai 3.10 PPA concluded Dharam khola 5.00 PPA concluded Sanjen 35.00 Private Uppersanjen 12.00 Private Upper Modi A 42.00 NEA private JV Total 2014 107.10 Balephi 20.00 Private Kabeli A 30.00 Private MERCADOS EMI AF-MERCADOS Upper Marsyangdi A 50.00 Private Total 2015 100.00 Transmission Lines Capex Cons. COD Length Total $ Bn NPR Blc. D/E NEA vs Project Year Year (km) Mn Spent Capex Ratio GoN Thankot-Chapagaon-Bhaktapur 2009 2011 28 23.00 0.94 1,703 4 50% 132 kV TL Khimti-Dhalkebar 220 kV TL 2009 2013 76 29.74 0.61 2,263 4 50% Chandranigahapur System Reinforcement (132 KV SS & 2009 2011 74 5.26 0.07 404 4 50% 33 KV TL) Butwal-Kohalpur 132 kV TL 2010 2013 208 13.80 0.00 1,078 4 50% 2nd Circuit Stringing Mid Marsyangdi-Dumre- 2010 2013 45 16.60 0.00 1,297 4 50% Damauli-Marsyangdi 132 kV TL Pathlaiya 132 KV Substation 2010 2013 0 5.40 0.00 422 4 50% Shyangja 132 kV S/S 2010 2013 0 6.60 0.00 515 4 0% Matatirtha 132 KV Substation 2010 2013 0 3.30 0.00 258 4 50% Extension Chapali 132 KV Substation 2010 2013 0 16.00 0.00 1,250 4 50% Hetauda- Bharatpur 220 KV Tr 2009 2013 70 31.00 0.00 2,422 4 50% Line Baneshwor-Bhaktapur UG 2009 2013 40 29.30 0.00 2,290 4 50% Cable 132kV Kabeli Corridor 132 kV TL 2009 2014 79 35.62 0.01 2,782 4 0% Bharatpur-Bardghat 220 kV TL 2009 2014 70 31.00 0.13 2,409 4 50% Singati-Lamosanghu 132 kV TL 2009 2015 38 13.00 0.00 1,015 4 0% Marsyangdi-Kathmandu 220 kV 2009 2014 85 46.70 0.01 3,649 4 0% Hapure-Tulsipur 132 kV TL 2009 2015 22 6.30 0.00 492 4 0% Modi -Lekhnath 132 KV TL 2010 2014 45 14.80 0.00 1,156 4 0% Kaski-Bhurjung-Parbat-Kusma 2010 2014 45 14.25 0.00 1,113 4 0% 132 KV TL Lekhnath-Damauli 132 kV DC 2010 2014 40 31.50 0.00 2,461 4 0% Kohalpur-Surkhet 132 kV 2010 2016 55 15.88 0.00 1,241 4 0% Hetauda-Dhalkebar 400 KV TL 2010 2015 140 76.00 0.00 5,939 4 50% Dhalkebar-Duhabi 400 KV TL 2010 2015 160 85.00 0.00 6,642 4 50% MERCADOS EMI AF-MERCADOS Marsyangdi Corridor 132 kV TL 2010 2015 45 11.90 0.00 930 4 0% Sunkoshi-Dolakha Corridor 132 2010 2015 20 8.00 0.00 625 4 0% kV TL Koshi Corridor (Kusaha- 2010 2015 90 44.88 0.00 3,507 4 0% Basantpur )220 kV TL Samudratar-Naubise TL 2010 2015 50 15.13 0.00 1,182 4 0% Ramechhap-Garlyan-Khimti TL 2010 2015 50 16.63 0.00 1,299 4 0% Chilime-Trisul-Galchhi TL 2010 2015 60 18.38 0.00 1,436 4 0% Butwal-Sunavli 2009 2016 60 16.75 0.00 1,309 4 50% Kaligandaki Corridor 220/132 2010 2016 150 40.25 0.00 3,145 4 0% kV TL Solu Corridor TL 2010 2016 70 25.00 0.00 1,954 4 0% Mid. Marsyangdi-Manang TL 2011 2017 60 16.75 0.00 1,309 4 0% Khimti-Kathmandu 220 KV TL 2011 2017 0 57.50 0.00 4,493 4 0% Bajhang-Dipayal-Attariya TL 2011 2018 100 28.25 0.00 2,207 4 0% Surkhet-Dailekh-Jumla TL 2010 2018 110 31.86 0.00 2,490 4 0% Kaligandaki-Jhimruk TL 2011 2018 110 20.13 0.00 1,573 4 0% Gulmi-Arghakhanchi-Chanauta 2010 2018 90 20.13 0.00 1,573 4 0% TL Trishuli 3B Hub Substation 2009 2016 60 9.40 0.00 735 4 0% Modi-Lekhnath TL* 2010 2014 22 10.25 0.00 801 4 0% Hetauda, Kamane 132 KV 2010 2013 10 3.50 0.00 273 4 0% Substation, 33kV Tr. Line** Kusum-Hapure 132 KV 2010 2013 22 6.25 0.00 488 4 0% Transmission line** Mirchaiya- Katari 132 kV TL** 2010 2015 20 7.50 0.00 586 4 0% MERCADOS EMI AF-MERCADOS Financing Assumptions Generation Projects Transmission Lines Interest Rate % 8% Interest Rate % 9% Interest Rate during Construction % 8% Interest Rate during Construction % 9% Tenor Years 6 Tenor Years 6 Working Capital Interest Rate % 12% Foreign Exchange Assumptions NPR/USD 78.1 2011 INR/USD 49.1 Depreciation 3.00 NPR % % Depreciation 3.00 INR % % 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Year 101.9 105.0 65.44 67.40 69.43 71.51 73.65 75.86 78.14 80.48 82.90 85.39 87.95 90.59 93.30 96.10 98.99 5 1 NPR/USD 41.12 42.35 43.62 44.93 46.28 47.67 49.10 50.57 52.09 53.65 55.26 56.92 58.63 60.39 62.20 64.06 65.99 INR/USD Working Capital Assumptions Inventories % Sales 15% Sundry debtors % Sales 33% Loans & Advances % Sales 17% Sundry Creditors % Sales 50% Provisions % Sales 23% Margin Money % Sales 25% AF-MERCADOS EMI Demand Ye Curve ar 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Assumption Assumed 558 603 648 722 813 885 946 1,057 1,163 1,272 1,387 1,510 1,641 1,770 1,907 2,052 2,206 PeakDemand(MW) Net Energy 10,30 Consumption (Gwh) 2,643 2,781 3,052 3,186 3,131 3,712 3,858 4,851 5,350 5,860 6,404 6,984 7,604 8,219 8,870 9,563 0 / Sold NEA Estimates PeakDemand(MW) 1,057 1,163 1,272 1,387 1,510 1,641 1,770 1,907 2,052 2,206 2,363 2,545 2,741 2,951 3,177 3,419 3,679 Energy 10,30 11,05 11,92 12,87 13,88 14,97 16,14 17,40 4,851 5,350 5,860 6,404 6,984 7,604 8,219 8,870 9,563 Consumption Gwh 0 4 9 0 2 1 3 4 Historical Growth Curve 9. PeakDemand(MW) 21 558 603 648 722 813 885 946 1,033 1,128 1,232 1,346 1,470 1,605 1,753 1,915 2,091 2,284 % 6. Energy 51 2,643 2,781 3,052 3,186 3,131 3,712 3,858 4,110 4,377 4,662 4,966 5,289 5,633 6,000 6,390 6,807 7,250 Consumption Gwh % Custom Curve Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Growth in Industrial 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% Demand Economic Growth 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% Improvement in 4% 4% 4% 4% 0% 0% 0% 0% 0% 0% Transmission Ba se 20 11 Peak Demand ( 94 1,005 1,068 1,135 1,206 1,269 1,336 1,406 1,480 1,557 1,639 MW) 6 3, Energy 85 4,100 4,356 4,628 4,917 5,175 5,447 5,733 6,034 6,351 6,684 Consumption (Gwh) 8 Internal 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Consumption Export 10% 2% 3% 3% 2% 2% 2% 2% 3% 3% 3% 2% Review of Financial Restructuring Plan of Nepal Electricity Authority (NEA) 30 AF-MERCADOS EMI Electricity Tariffs Tariff Indices- Year on Year esclations Escalations 5% 10% 7% 5% 5% 5% 5% 5% 5% 5% Categories of Consumers 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Domestic 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Non-commercial 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Commercial 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Industrial 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Water supply 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Irrigation 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Street-Light 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Temporary 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Transport 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Temple 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Community 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Internal Consumption 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Export 1.00 1.04 1.07 1.04 1.02 1.02 1.02 1.02 1.02 1.02 1.02 Average Tariffs - Projection 2010 Categories of Consumers Avg. Domestic NPR/kwh 6.64 6.64 6.90 7.39 7.68 7.84 7.99 8.15 8.31 8.48 8.65 8.82 Non-commercial 9.36 9.36 9.73 10.42 10.83 11.05 11.27 11.50 11.73 11.96 12.20 12.44 Commercial 9.36 9.36 9.73 10.42 10.83 11.05 11.27 11.50 11.73 11.96 12.20 12.44 Industrial 6.30 6.30 6.55 7.01 7.29 7.44 7.59 7.74 7.89 8.05 8.21 8.38 Water supply 4.88 4.88 5.08 5.43 5.65 5.76 5.88 6.00 6.12 6.24 6.36 6.49 Irrigation 3.88 3.88 4.04 4.32 4.50 4.59 4.68 4.77 4.87 4.96 5.06 5.16 Street-Light 6.70 6.70 6.97 7.46 7.75 7.91 8.07 8.23 8.39 8.56 8.73 8.91 Temporary 13.50 13.50 14.04 15.02 15.62 15.93 16.25 16.58 16.91 17.24 17.59 17.94 Transport 5.06 5.06 5.27 5.63 5.86 5.98 6.10 6.22 6.34 6.47 6.60 6.73 Temple 5.29 5.29 5.50 5.88 6.12 6.24 6.37 6.49 6.62 6.76 6.89 7.03 Community 3.59 3.59 3.74 4.00 4.16 4.24 4.32 4.41 4.50 4.59 4.68 4.78 Internal Consumption 8.98 8.98 9.34 9.99 10.39 10.60 10.81 11.03 11.25 11.47 11.70 11.94 Export 6.88 6.88 7.16 7.66 7.97 8.13 8.29 8.45 8.62 8.80 8.97 9.15 Power Purchase tariff - Escalations 2010 Year on year tariff escalation NR/kWh 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Power purchased from NEA Subsidiaries/PPPs 4.00 0.0% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% Power purchased from Nepal IPPs 7.60 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% Power purchased under exchange agreement with India 4.02 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% Power Purchase from India on commercial basis 10.72 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% Review of Financial Restructuring Plan of Nepal Electricity Authority (NEA) 31 AF-MERCADOS EMI Operating Costs - Escalations & Efficiency Improvements Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Efficiency Improvement 0% 0% 1% 3% 3% 3% 3% 3% 3% 3% 3% Escalation in Fuel,Salary, Wages & Allowance 0% 8% 8% 8% 8% 8% 8% 8% 8% 8% 8% Escalation in O&M Costs 0% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% Generation Assumptions Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Capacity Factor 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% 75% Auxiliary Power 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% Export 0.8% 0.8% 0.8% 0.8% 0.8% 0.8% 0.8% 0.8% 0.8% 0.8% 0.8% System Losses 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% Split of Energy by Type Year 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 NEAHydro Gwh 5.69% 1,523 1,569 1,747 1,793 1,840 2,109 2,122 2,184 2,387 2,989 2,982 2,991 5,835 6,821 6,810 10,558 10,487 - NEAThermal Gwh 20.70 14 16 13 9 9 13 3 3 3 3 3 3 3 3 3 3 3 % India(Purchase) - 19.25 Gwh 5% 241 266 329 425 356 639 694 729 765 803 844 886 930 977 1,025 1,077 1,131 Max % Nepal(IPP) - Max Gwh 5% 3.10% 865 930 962 958 926 951 1,039 1,091 1,145 1,203 1,263 1,326 1,392 1,462 1,535 1,612 1,692 Total Purchases Gwh 1,106 1,196 1,291 1,384 1,282 1,590 1,733 1,820 1,911 2,006 2,106 2,212 2,322 2,438 2,560 2,688 2,823 AvailableEnergy(G Gwh 2,643 2,781 3,052 3,186 3,131 3,712 3,858 4,007 4,301 4,998 5,092 5,206 8,161 9,263 9,373 13,250 13,313 Wh) 24.8 25.1 26.7 26.5 25.3 28.9 28.4 28.35 28.35 28.35 28.35 28.35 28.35 28.35 28.35 28.35 28.35 System Losses % 2.23% % % % % % % % % % % % % % % % % % Same Losses 0.00 28.4% 28.4% 28.4% 28.4% 28.4% 28.4% 28.4% 28.4% 28.4% 28.4% Continue % 1% reduction each 1.00 27.4% 26.4% 25.4% 24.4% 23.4% 22.4% 21.4% 20.4% 19.4% 18.4% year % 0.5% reduction 0.50 27.9% 27.4% 26.9% 26.4% 25.9% 25.4% 24.9% 24.4% 23.9% 23.4% each year % Review of Financial Restructuring Plan of Nepal Electricity Authority (NEA) 32