Power Sector Financing In India And Key Issues

Power Sector Financing in India and key Issues By Yasir Altaf Abstract The Indian Power Sector has been weighed down by the political and regulatory environment along with the inefficiencies of the State Electricity Boards (SEBs) and chronic shortages and pressures to meet demand. This has deterred private investment from flowing into the sector. The government's first stab on this i.e. the 1990s strategy of bringing in global sponsors to build Independent Power Producers (IPPs) was not particularly successful and Dhabol plant left a bad taste in everyone’s mouth. But with the passage of Electricity Act 2003, new rays of hope have opened for growth. The Electricity Act has an overall positive impact on the profitability of the power sector and encourages investment and efficiency. The new power strategy visible in India has much more of a domestic flavour even though bidding is open to foreign players. The government is keen to attract significant private capital into its power sector, which is facing a huge demand-supply gap. Badly affected states such as Maharashtra have 19% energy shortages, and this can rise to 27% peak power shortage levels. This power shortage is holding back industrial growth and corresponding economic development, and the World Bank has estimated that if India is to sustain current GDP growth levels in the 8% to 9% per annum range, it will need to add 160,000 MW of generating capacity over the next 10 years. The basic template evident is domestic sponsors raising cash on the stock market, and using this source of funding as the project equity component for competitive bids. In this new environment, Project Finance will be the key financing mechanism for growth. Also the investment will have to be directed towards all the components of the electricity delivery chain i.e. Generation, Transmission and Distribution. This would help India to overcome the bottlenecks in the long neglected Transmission and Distribution segments. The financing also needs to move to the next level of Public Private Participation with the Financial Institutions providing equity to the sector and not just debt. The sector also needs incentives in the form of lower duties, tax holidays and measures such as a higher return on equity (RoE) to attract more investments. Payment risks associated with SEBs which has been a major concern for IPPs have overcome to some extent with SEB restructuring and improvement in the security and payment mechanisms arrangements. But a word of caution needs to be attached to this optimistic view as the efficacy depends on the commitment of the Centre and State machinery to the reforms process. Except for the limited success by a few generation companies in accessing the debt market, transmission and distribution utilities have not managed to raise debt successfully from the open market. The availability of easily accessible debt from government backed financial institutions like the Power Finance Corporation (PFC) and the Rural Electrification Corporation (REC) has had the effect of "crowding out" the development of a private debt market. It is therefore important that these institutions scale down their activity, and confine themselves to the smaller and weaker utilities. The state utilities are too cash strapped for internal resources to be of any significance. Given the excellent commercial potential of merchant power plants, the equity market is a good source of raising funds. In any case, the Indian equity and especially debt market is too narrow and does not have the required depth and breadth to finance these huge requirements. It is therefore inevitable that Foreign Direct Investment (FDI) be incentivized, so as to meet the huge investment requirements.

1

Introduction ............................................................................................................... 5

2

Emerging Scenario.................................................................................................... 7

3

4

5

2.1

Power Market Dynamics ................................................................................... 7

2.2

Industry Structure .............................................................................................. 8

2.3

Generation......................................................................................................... 9

2.4

Transmission ................................................................................................... 10

2.5

Distribution ...................................................................................................... 11

2.6

Demand Supply Position ................................................................................. 11

2.7

Financing Requirements ................................................................................. 12

Project Life Cycle .................................................................................................... 14 3.1

Project Finance ............................................................................................... 14

3.2

Operational Agreements ................................................................................. 15

3.3

Project Development ....................................................................................... 16

3.3.1

Development Period ................................................................................ 16

3.3.2

Construction Period ................................................................................. 16

3.3.3

Operating Period ..................................................................................... 17

Power Generation ................................................................................................... 18 4.1

Engineering, Procurement & Construction Capability ..................................... 18

4.2

The Power Purchasers.................................................................................... 18

4.3

Project Economics........................................................................................... 20

4.3.1

Fuels Supply............................................................................................ 20

4.3.2

Capital costs ............................................................................................ 20

4.3.3

Wholesale Tariff Structure ....................................................................... 21

4.3.4

Capacity Allocation for Central Generating Stations ............................... 23

Power Transmission................................................................................................ 24 5.1

6

Private Sector Investment in Transmission Sector.......................................... 25

5.1.1

Mode of Investment by Private Investors ................................................ 26

5.1.2

Tariff based bidding process for transmission ......................................... 27

Power Distribution ................................................................................................... 29 6.1

Key issues facing the sector............................................................................ 29

6.2

Privatization of Distribution.............................................................................. 32

6.2.1

Privatization of Distribution in Delhi ......................................................... 32

6.2.2

Impact of Privatization on Distribution ..................................................... 33

2

7

Project Financing .................................................................................................... 34 7.1

Types and Sources of Finance........................................................................ 34

7.1.1

Debt ......................................................................................................... 34

7.1.2

Equity....................................................................................................... 36

7.2

Trends in Power Sector Financing .................................................................. 37

7.3

Key Power Financing ...................................................................................... 37

7.3.1

Financial Closures ................................................................................... 38

7.3.2

Central Sector Project Financing............................................................. 38

7.3.3

State Sector Project Financing ................................................................ 39

7.3.4

Private Sector Overseas Financing ......................................................... 39

7.3.5

Qualified Institutional Placements ........................................................... 39

7.4

Major Financiers in Power Sector ................................................................... 40

7.5

Policy development for Private Investment ..................................................... 40

7.5.1

Electricity Act 2003 .................................................................................. 40

7.5.2

Private Power Policy................................................................................ 43

7.5.3

Mega Power Policy.................................................................................. 43

7.5.4

Policy Reforms for Investment in Transmission ...................................... 43

7.5.5

Regulatory Reforms................................................................................. 44

7.5.6

Distribution Reforms and Privatization .................................................... 45

7.6

Framework for Private Investment .................................................................. 46

7.7

Status of Private and Foreign Investment in Power Sector ............................. 51

7.7.1

Private Investment in power sector ......................................................... 51

7.7.2

Foreign Investment in power sector ........................................................ 53

7.8

Issues and Concerns....................................................................................... 54

7.9

Enabling environment for the private sector .................................................... 55

8

Risks associated with Indian Power Sector............................................................. 57 8.1

Project Evaluation and Risks........................................................................... 57

8.2

Risk Mitigating Mechanism.............................................................................. 58

8.3

Impact of the Global Slowdown ....................................................................... 60

9

Conclusions and Recommendations....................................................................... 62 9.1

Generation....................................................................................................... 62

9.2

Transmission ................................................................................................... 63

9.3

Distribution ...................................................................................................... 63

10

References/Bibliography ..................................................................................... 65

3

4

1 Introduction India is now the second fastest growing economy in the world. Despite the current economic slowdown, India is expected to grow at approximately 7-8% this fiscal year. Current estimates suggest that India’s economic growth may slow to 7% as the global economy recovers from the slowdown. The expanding base of industries and services the main drivers of economic growth is exerting pressure on India’s weak infrastructure. The power sector remains a key infrastructure concern and India’s continued economic growth will depend critically on its ability to meet the growing electricity demand. Economic growth is only one aspect of the Indian story. Development and poverty reductions are the other imperatives. Improved access through better grid connectivity, increased certainty of electricity supply and price affordability all play an equally important role in shaping the politics and economics of the sector. India’s pattern of energy demand, consumption and growth, must therefore be understood in the context of its dual objectives – as a basis for sustaining economic growth and as an instrument for poverty reduction. Over the last few years, the story on India’s economic growth has been underlined by the story of India’s power sector. The power sector has long experienced capacity shortfalls, poor reliability and quality of electricity and frequent blackouts which has been a major impediment to economic growth. Despite reforms introducing private participation during the 1990s, the India’s electricity sector has remained dominated by the state. State utilities remain the dominant institutions within India’s electricity industry, controlling well over half of the electricity supply and the vast majority of distribution. Electricity as a subject is in the concurrent list of the Constitution of India. It means that both the Union and State Governments can formulate policies and laws on the subject, but the responsibility of implementation rests with the States. Distribution of electricity in particular comes in the domain of the states. There are a number of significant problems in the Indian power sector that appear intransigent. For example, agricultural subsidies continue to stifle reforms. There is a pressing need for the Indian government to implement a national policy on farm tariffs. At present political "generosity" such as the free grant of electricity to farmers needs to stop in order to make the sector financially more viable and attractive investment. A further bottleneck to progress is lack of adequate fuel resources and poor port facilities in the country. Although a number of initiatives in the coal sector should assist the supply of fuel for power generation, the quantum and reliability of the gas supply remains a concern. Overall however, after a number of false-starts, the Indian power sector is in the midst of a positive hue and much of that stems from a series of measures sought to liberalize generation, form regulatory commissions, unbundle electricity boards, create transmission as a separate business and introduce distribution reforms. Despite the piece meal approach, these reforms finally coalesced into the Electricity Act 2003. Although the implementation of the Act is far from complete, and progress is patchy across the states, a critical mass of reforms has been achieved and comprehesnive regulatory framework is now in place. This will go a long way in persuading private players and foreign investors to come off their sidelines and participate in the development of one of the world's largest infrastructure markets.

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India is facing a major challenge as it seeks to upgrade the entire electricity delivery chain. Given the various constraints on government, primarily the financial ones, private participation in power sector is likely to increase sharply. Government of India (GoI) has recognized the importance of changing its policies and creating an environment conducive to sustainable private sector involvement. But the pace of the reforms of needs to be accelerated, and private developers need to develop more flexible, innovative, and realistic project designs and concepts. This paper covers an overview of the electricity delivery chain and analyzes the financing of the Power Sector in India. The paper begins with an overview of the industry, the emerging market scenario and the financing needs. It then illustrates the current situation with respect to the financing of power projects in Power Generation, Transmission and Distribution and the risks as seen by the lenders in Power Project Finance in India. The provisions of the Electricity Act 2003 and their implications on the sector financing are then dealt in with detail. All the observations on the future trends in the financing of the Power Sector in India are highlighted. The paper concludes with observations on the future trends in the financing of the Power Sector in India.

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2 Emerging Scenario 2.1 Power Market Dynamics The restructuring of power systems across the globe started with the redesigning of its power markets. The power market design determines the level of efficiency, transparency, and flexibility offered to the market players. In India, electricity reforms started with the re-evaluation of Electricity Supply Act, 1948 and the Indian Electricity Act, 1910 which led to The Electricity Act, 2003. The Electricity Act, 2003 has been brought about to facilitate private sector participation and to help cash strapped SEBs to meet electricity demand. The Electricity Act, 2003 envisages competition in electricity market, protection of consumer’s interests and provision of power for all. The Act recommends the provision for National Electricity Policy, rural electrification, open access in transmission, phased open access in distribution, mandatory SERCs, license free generation and distribution, power trading, mandatory metering, and stringent penalties for theft of electricity. One more welcome step the Indian electricity market has seen is the implementation of Availability Based Tariff (ABT) which brought about the effective day-ahead scheduling and frequency sensitive charges for the deviation from the schedule for efficient realtime balancing. ABT is discussed in more detail under wholesale tariff structures in the chapter on Power Generation. Figure 2.1: Power Market Structure in India

POWER MARKET STRUCTURE

Long-term PPAs IEX Day-ahead Scheduling RLDCs Intra-day bilateral Contracts Upper price cap on UI, Congestion charge 3 Rs/kWh

Real-time balancing through UI & load shedding

To promote power trading in a free power market, Central Electricity Regulatory Commission (CERC) approved the setting up of Indian Energy Exchange (IEX) which is the first power exchange in India. IEX has been modeled based on the experience of one of the most successful international power exchanges, Nordpool. The exchange has been developed as market based institution for providing price discovery and price risk management to the electricity generators, distribution licensees, electricity traders, consumers and other stakeholders. The participation in the exchange operations is voluntary. At present, IEX offers day-ahead contracts whose time line is set in

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accordance with the operations of regional load dispatch centers. IEX coordinates with the National Load Dispatch Centers/RLDCs and SLDCs for scheduling of traded contracts’ to get up-to-date network conditions. The day-ahead market of IEX offers double sided auction and discovers the price incorporating the supply and demand side bidding. The exchange, as of now, offers only day-ahead contracts of an hourly time blocks. However, the exchange has plans for future to offer the adjustments contracts and long-term contracts like forwards and futures to hedge the risk against the uncertainty in electricity market. Putting together ABT mechanism, IEX and other market stakeholders, the Indian power market operations can be described as shown in fig.2.1 Power market in India is also following the decentralized market model. power market has now achieved all its segments of (i) Bilateral markets long-term, medium term and short-term markets; (ii) Multilateral market exchange (IEX) presently covering day-ahead segment and (iii) real-time balancing market i.e., Unscheduled Interchange(UI).

The Indian constituting i.e., power multilateral

2.2 Industry Structure Public sector institutions continue to play the dominant role in the electricity supply and delivery chain in India, primarily through central and state level government owned utilities. Figure 2.1 depicts the interactions between the various players in the Indian power market. The Ministry of Power (MoP) is the Central government institution responsible for overseeing India’s electricity industry. Several authorities and agencies operate under the MoP, among them the Central Electricity Authority (CEA), assists the MoP on technical and economic issues. Figure 2.2: Indian Power Market Institutional/Operational Framework Appellate Tribunal for Electricity

Ministry of Power, GoI CENTRAL SECTOR COMPANIES Generating Companies NTPC, NHPC, NEEPCO and NPCIL CTU - PGCIL Finance - PFC Rural Electrification (REC)

CEA

R&D CPRI, NPTI, PSTI NLDC

MOP, State Government

Electronic Trading Platform (Multiple Power Exchange)

State IPPs

Central Electricity Regulatory Commission

RLDC

State Electricity Regulatory Commission

SLDC

Forum of Regulators

State Sector Mega IPPs Trading Companies

Generation Transmission Distribution

Pvt. Distribution

The Central Electricity Regulatory Commission (CERC) is an independent statutory body with quasi-judicial powers. The CERC has a mandate to regulate interstate tariff related

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matters, advise the central government on formulation of the national tariff policy and promote competition and efficiency in the electricity sector. The CERC regulates Central government owned utilities both in generation and transmission. The State Electricity Regulatory Commissions (SERCs) have jurisdiction over state utilities in generation, transmission and distribution. Independent Power Producers (IPPs) are regulated by CERC / SERC depending on whether they sell power to one or more states. Regional Load Dispatch Centers (RLDCs) are responsible for managing the central transmission system, whereas State Load Dispatch Center (SLDCs) manage the intrastate and some inter-state systems. Central generating stations are contracted to state utilities and are dispatched by RLDCs. State owned generating stations sell power to their own state distribution licensee and are dispatched by SLDCs. Distribution licensees can also buy power from mega power projects, IPP, traders and through the power exchange. The central government, through public companies, owns and operates one-third of total generation capacity and interstate transmission lines. At the state level, SEBs own and operate most of the remaining two-thirds of the generation capacity, as well as the majority of intrastate transmission and distribution systems. Although the central government institutions, particularly after corporatization, have fared better, the SEBs increasingly faced the threat of bankruptcy during the development of India’s IPP program in the 1990s. At a time when new generation capacity and distribution infrastructure was desperately needed, the near insolvency of the SEBs created a serious impediment to private investment in the electricity sector. Public funds had also contracted. Without funds to invest in the development of the electricity sector, economic growth far outstripped electricity consumption growth during the 1990s. Despite the opening of generation to IPPs in 1991, the private sector provided less than 10,000 MW of total generation capacity through the 1990s. Through 2003, IPPs accounted for little more than 5000MW of new capacity since the introduction of private participation more than a decade earlier.

2.3 Generation The current installed capacity is approximately 143 GW with coal being the primary fuel source. Despite significant recent additions, there is a significant stock of aging plants that have poor performances. The sector also suffers from, fuel shortages, inadequate transmission evacuation system, regulatory uncertainty and payment security concerns. Concerns about the sector paved the path for reforms. Of this the central and state sector accounted for approximately 89% [MOP, 2004]. The statistics point to high perception of risk lack of enthusiasm on part of the private sector with regard to power generation in India. In the Central Sector, National Thermal Power Corporation (NTPC) is a player of global scale. The State Electricity Boards also operate generation facilities to serve their demand. Private Sector comprises of many players like Tata Power Company, Reliance Energy, GVK, GMR etc. Despite reforms introducing private participation in the early 1990s, India’s electricity sector has remained dominated by the state owned entities and has been unable to attract adequate private investments. Electricity Act 2003 introduced another wave of liberation aimed at create a legal and structural framework for a competitive market.

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Figure 2.3: Installed Capacity Share by sector 14% 34%

52%

Private

State

Center

To maintain the projected economic growth, India needs to add 100 GW of new capacity by 2012. The growth in capacity must be matched with efforts to i) optimize utilization of unevenly distributed fuel resources with proper evacuation system; ii) diversify fuel sources with cheaper and cleaner fuel from huge hydro and other renewable energy; iii) build raw material and infrastructural support; iv) adopt new generation technologies; and v) renovate and modernize program of existing plants. The target for new capacity additions has created a platform for approximately 100 billion USD of investments across different segment of the generation sector. Although, the system is still in a transitory phase, deepening reforms and a new policy framework have to create an optimistic outlook. The developers opting to set up a MPP might pose a challenge in financing the project and have to do so at their own risk. Setting up a merchant plant would necessarily mean balance sheet financing by the developer, as financial institutions/lenders as a rule, may not be comfortable with projects that don’t have long-term PPAs. Indigenous lenders are not yet comfortable carrying the risk of non-recourse financing on merchant plants. To facilitate the development and restructuring of the electricity market, with the objective to fill in the demand supply gap and provide additional generating reserve, the Ministry of Power has issued the approach and guidelines on the development of merchant power plants (MPPs). MPPs are planned with the objective to fill gaps in the peak loads. The total funds requirement for the generation segment during the 11th Plan has been estimated to be approximately 100 billion USD, of which central sector requirement is 49%. However, lack of financing and higher interest rates are likely to impede funds mobilization. But at the same time interest from foreign investors and the renewed interest of multilateral agencies in the electricity sector has been strong. There has been resurgence of international interest in the Indian power sector.

2.4 Transmission Transmission plan in India has always been generation based. It is therefore not going to help because there are bound to be imbalances. Even today, CTU and STU’s are very conservative in agreeing to create more than the desired transmission capacity and freely allowing interconnectivity. Investments in the Transmission sector have been therefore been inadequate due to the heavy emphasis on generation capacity. In most states, the existing distribution network has been formed by expanding and

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interconnecting smaller and disjointed networks. Consequently, there are several deficiencies in the Transmission system, such as high losses and low reliability. The major player in this sector is the government owned Power Grid Corporation of India. The total transmission system in India at 765/HVDC/400/230/220 kV corresponding to 1,32,329 Mega Watts (MW) of installed generation capacity at the end of March 2007 was 198,089 circuit kilometers of transmission lines, 251,439 MVA of AC substation and 8,200 MW of HVDC substation capacity.

2.5 Distribution India’s distribution sector has traditionally been a leaking bucket with the holes deliberately crafted and the leaks carefully collected as economic rents by various stakeholders that control the system. The logical thing to do would be to fix the bucket rather than to persistently emphasize shortages of power and forever make exaggerated estimates of future demands for power. Most initiatives in the power sector (IPPs and mega power projects) are nothing but ways of pouring more water into the bucket so that the consistency and quantity of leaks are assured. The Distribution arm of the Power Sector had been the domain of the SEBs for a very long time which gave rise to financial problems due to lack of collection of dues. The SEB’s financial difficulties led to problems in the upstream for power generation. To alleviate this situation Distribution Companies are beginning to be privatized in some states, most notable among them being Delhi. Reliance Energy and Tata Power Company were the first private sector players to make a foray into power distribution in the country.

2.6 Demand Supply Position Over the last five years, from FY 2003-FY 2007 India’s electricity demand has grown by over 6 percent annually 1 . The steady increase in electricity demand is attributed to the country’s rapid economic growth. Over and above India’s visible electricity demand growth, there is significant latent demand that remains under-represented. The demand projections have discounted the Places where electricity cables have not reached yet and industries that would come up if supply of electricity is guaranteed. Shortage is likely to be a major driver for new capacity development in future. Energy demand deficits have increased from 7 percent to 10 percent in the past five years, indicating that a high latent demand for electricity exists in India. This latent demand increases the potential for demand to grow even in periods of slow economic growth. Figure 2.6 illustrates the peak and energy deficit between FY 2003 and FY 2007. As the figure below shows, India has constantly been plagued with a demand supply gap in the Power sector. Such a gap is a major hindrance to the growth of a developing economy like India. The Government of India set up the Mission 2012: Power for All to eliminate shortages by 2012. Therefore, electricity demand and the investment required in the sector over XI plan are likely to grow even if GDP growth declines.

1

Power sector reports, CEA

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Figure 2.4: Peak and Energy Shortages FY 2003 - FY 2007 18%

16.9%

16%

15.9%

Demand Deficits (%)

13.9%

14% 12.2%

12% 11.6%

10%

9.8%

8.4% 9.6%

7.1%

8% 6%

Peak demand deficit %

7.3%

Energy demand deficit %

4% 2% 0% 2003-04

2004-05

2005-06

2006-07

2007-08

Source: CEA

2.7 Financing Requirements The Working Group on Power has estimated that Rs. 1,031,600 Crores will be required by the Power sector to meet the target of 78,577 MW capacity additions and development of related transmission and distribution infrastructure by the end of XI plan (FY 2007 - FY 2011). The question of generating this huge amount of funds therefore assumes prime importance. The planned additions in all the three sectors will be missed if significant steps are not taken to ensure a more congenial environment in the sector to bring in more investments. The investment in generation, transmission, distribution and rural electrification should ideally be in the ratio of 4:2:1:1. This implies for each rupee invested in generation a similar investment is required in Transmission & Distribution (T&D). Nevertheless, in practice actual investment in T&D so far has been 30 percent. As a result there is a severe gap in transmission capacity at state levels. The ratio for Central and State sectors has gradually improved over the various plan periods, but the Private Sector remains a gaping hole. The private investment in T&D segment has not been enough and needs to be roped in for balanced distribution of power across the regions.

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Table 2.1: Investment Requirements in XI Plan Overall Investment requirement in XI Plan (Rs Crore) Particulars Generation Distributed Generation Renovation and Modernisation Transmission Distribution and Rural Electrification Human Resource Development Research and Development Demand Side Management Total Power Sector Renewables and Captive generation Merchant Power Plants Total Investment Requirements

State

Central

Private

Total

1,23,792

2,02,067 20,000

85,037

4,10,896 20,000 15,875 1,40,000 2,87,000 462 1,214 653

85,037

8,76,100

93,000 40,000

1,15,500 40,000

2,18,037

10,31,600

15,875 65,000 2,87,000

75,000 462 1,214 653

4,91,667

2,99,396

22,500 5,14,167

2,99,396

While this could well be the investment needed, the absorption capacity, availability of financial resources and the viability of utilities are likely to act as constraints in realizing these investment projections. Hence the question of generating this huge amount of funds therefore assumes prime importance. Significant steps to ensure a congenial environment in the sector for bringing in more investments have to be taken up as lack of financing and higher interest rates are likely to impede funds mobilization. But at the same time interest from foreign investors and the renewed interest of multilateral agencies in the electricity sector has been strong. There has been a resurgence of international interest in Indian Power Sector.

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3 Project Life Cycle A typical Power Project Structure is a web of contracts. The Power Plant Promoters setup a project company via the Special Purpose Vehicle (SPV) route i.e. the project company is a distinct legal entity. The Company enters into two sets of agreementsProject Finance and Operational. Table 3.1: Power Project Structure in India

TYPICAL PROJECT STRUCTURE MULTILATERAL, BILATERAL, ECAS

SPONSOR A

BANK SYNDICATE

NON RECOURSE DEBT Inter-Credit Agreement

SPONSOR B

SPONSOR C

EQUITY Letter of Credit, Escrow Account

Shareholder Agreement

LABOUR Merchant Power Input COAL or GAS Supply Contract

Construction, Equipment, Operating and Maintenance Contracts

PROJECT COMPANY Power Plant

Output POWER SUPPLY Off-take Agreement

Host Government: Legal System, Property Rights, Regulation and Permits, Concession Agreements

3.1 Project Finance A Power Plant is financed via the Project Finance route. Project finance is usually defined as limited or non-recourse financing of a new project through the establishment of a separately incorporated vehicle company. The reliance on non-recourse debt represents one of the key differences between project finance and traditional corporate finance. In corporate finance, the primary source of repayment for investors and creditors is the sponsoring company, backed by its entire balance sheet, not the project alone. Even if an individual project fails, creditors will still retain a significant level of comfort in being repaid depending on the overall strength of the sponsor’s balance sheet. In project finance, on the other hand, if the project fails, investors can expect significant losses even if it is sponsored by a AAArated company or government. Limited or no recourse to the sponsors’ balance sheets

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and exclusive reliance on the project’s assets and cash flows make the credit risk faced by the lenders very project-specific, with little scope for diversification. Furthermore, loan repayments are subject to potential liquidity constraints facing the project company, especially during the construction phase. On the other hand, the possibility of funding projects with 70% and more non-recourse debt is attractive to the sponsors for a number of reasons. Project finance allows them to share in potentially large revenues while committing relatively little equity. Moreover, deconsolidating projects off balance sheet makes it possible for the sponsors to preserve their corporate debt capacity and keep their cost of funding low. A further reason for the sponsors to consider project finance is that the risks of the new project will remain separate from their other activities, avoiding any potential “risk contamination”. Project finance has been especially used to fund large-scale capital-intensive projects generating hard currency cash flows, for example from internationally traded commodities (e.g. power plants). In fact, this type of projects allows sponsors to enjoy the benefits of non-recourse debt and extensive contracting, while minimizing the related risks to lenders. In particular, structuring large projects – as opposed to several smaller deals - reduces overall legal and transaction costs thanks to economies of scale. Furthermore, financing projects with considerable capital assets that produce hard currency cash flows increases collateral value and reduces lenders’ exposure to exchange rate risks. On the other hand, financing large-scale hard currency generating projects leaves lenders naturally more exposed to political risk and sovereign risk in general. Host governments might have a keen interest in the high-profile projects being funded and might fail to renew concession agreements, change regulations or even expropriate project assets and cash flows to gain political rents or access to hard currency during economic downturns. In order to cope with these risks, project finance is making increasing use of larger syndicates and third-party guarantees, in particular political risk guarantees. Large-scale capital-intensive projects usually require substantial investments up front and only start to generate revenues after a relatively long construction period. Therefore, matching debt repayment obligations with project revenue cash flows implies that, on average, project finance is characterized by much longer maturities compared to other forms of financing.

3.2 Operational Agreements EPC Contract: The Company then enters into an agreement with an Engineering, Procurement and Construction (EPC) contractor for setting up the physical facility for the Power Plant. Fuel Supply Agreement: The Company also enters into a long term Fuel Supply Agreement (FSA) to ensure fuel availability. As the paper explains later, fuel is the most important component in ensuring the viability of the project. Power Purchase Agreements: Off take of the Power generated by the plant is guaranteed by a Power Purchase Agreement (PPA) with a TRANSCO. Some power may be utilized for merchant sales to industrial houses. Government Clearances: The Company also has to get the requisite clearances for the government with regard to property rights, permits and environmental concerns.

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3.3 Project Development From a planning and financing perspective, there are essentially three stages of independent power project (IPP) development: development, construction, and operation. The sources of funds, in general, are different for each stage. The risks associated with the completion of each stage are also different and hence, the cost of the capital is different.

3.3.1 Development Period During the development stage, one cannot be certain that a "financeable" project will result. The project must first be defined in terms of the buyer's needs, the site, the fuel availability and the permitting requirements. Then the feasibility work is done. This generally consists of engineering, cost estimation and environmental work, as well as the development of preliminary project pro formas. The developer must then obtain contracts, secure the site, and complete the permitting for the plant. The contract that sets the direction for the rest of a project's development is the power purchase agreement. It is during the development period that the greatest "value" is being created because efficient planning and engineering capability decide on the viability of the project and also the tariff competitiveness of the power produced is decided by the engineering excellence of the plant. The source of funds generally used during this period is equity. The developer and owner of the project provide these funds. The sources of financing for independent power projects are scarce because the risks of development are high. Until the project reaches financial closing for construction, there are a multitude of risks that could reduce the value of the project to zero. These risks include: Permitting risk Political opposition to the project Inability to secure fuel and fuel transportation under long-term contract Inability to obtain a financeable power purchase agreement, either because the power price is too low or the terms are not acceptable Regulatory disapprovals and Change in law

3.3.2 Construction Period A project enters the construction stage when it has met all the requirements necessary to put together a non-recourse project financing. This means that all of the contracts are negotiated and signed, the permits are granted, and the technology and equipment are selected. There is limited to no recourse to the developer if there is a problem. This is the nature of non-recourse project finance. The majority of the construction funds are through debt. The period of greatest risk for them is just before the plant is completed, because they have almost their entire loan outstanding and the plant is still not producing revenues. The Project Cost also includes provision for Interest during construction and a margin for working capital finance both of which are capitalized.

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3.3.3 Operating Period The primary financial management issue throughout the project life cycle is to minimize the financial and operating costs of the project. Once a project reaches commercial operation, a developer/owner has many options in terms of additional financing. For example, institutional buyers such as insurance companies and pension funds, as well as the public markets (which do not take construction risk), can now participate. The project now has real operating and financial data that can be used to assess the plant's performance and financial expectations. The key is planning and constant attention to the project finance debt market.

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4 Power Generation There are three major options for generating electricity: thermal, hydroelectric and nuclear. Thermal power plants can be based either on coal or on natural gas, including liquefied natural gas (LNG). In general, power plants with the lowest variable costs (fuel costs) should be employed to meet the base demand, while those with higher variable cost for the peak demand. Coal-based power plants have lower variable costs than those based on naphtha or natural gas. However, coal-based power plants have high capital costs (resulting in high fixed costs). In addition, these plants are less flexible in terms of varying their output with the variation in demand. Hence, coal-based plants are largely used to meet base demand. This results in lower fixed costs per unit, due to the higher PLF. Gas and naphtha-based power plants have higher variable costs and are more flexible in terms of varying their output. Hence, these plants are better suited for meeting peak demand.

4.1 Engineering, Procurement & Construction Capability To achieve investment grade or near investment grade rating, the following criteria for Engineering, Procurement and Construction (EPC) Capability are critical and should be analyzed. Table 4.4.1: Criteria for EPC

Criteria

Observations

Conservative construction schedule

Projects with longer construction schedules will only be able to achieve investment-grade or near-investment-grade ratings when vendors and contractors are able to demonstrate overwhelming capacity to manage the accompanying risk.

Strong turnkey construction contracts

The contract should shift substantially all construction risk to contractors and vendors.

Adequate capacity to perform on contract obligations

This will be demonstrated by a rating or financial guarantee in the form of a letter of commitment or surety bond providing for the payment of contract damages and penalties in sufficient time to maintain cash flow required for debt service. Power project construction also should be a major part of the long-term business strategy of key contractors and equipment suppliers.

Strong third-party trustee structure for management of construction funds

The trustee should be experienced in the administration and management of power project construction, preferably as a lender, and should retain an experienced engineer independent of any other interest on the project.

4.2 The Power Purchasers Dealing with the SEB Risk: The biggest risk as seen in the Indian Power Sector Financing has been the weak financial health of the State Electricity boards which are the primary purchasers of the

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power generated in the country. The Transmission and Distribution losses have taken a toll on the SEBs and as a result they have huge outstanding payments to be made to the power generators. For example, Aggregate Transmission and Commercial Losses for Uttar Pradesh, Jharkhand and Bihar are above 40%. This repayment risk has been the bane of the sector and has deterred many potential investors from coming into the sector. Traditionally, a major issue has been to mitigate the risks associated with the SEBs through widespread SEB restructuring and improvement in the security and payment mechanisms. The lenders and the private investors view the SEB risk differently. The lenders believe that the reforms path followed by successive central and state governments has ensure that the repayment risks are going down but the private investors still believe that the risks imposed on them make the required return on capital too high to allow the project to take off. Lenders’ Risks are Mitigating: PSU FIs have never had a problem in lending to Power Projects supplying power to SEBs. Commitment from Central Government on the speed of reforms was a comforting factor. When they lent to the power projects, they worked on the projected financial health of the SEBs assuming the reforms would go ahead. But they did identify that there was a huge single party risk as power was not tradable. This component still remains in many projects and they do have their mitigating mechanisms for that. They ensure that they have the following three: Irrevocable revolving Letter of Credit by the SEB in favor of the IPP A designated prime area escrow account State Govt. guarantee Private Players still wary: It was Andhra Pradesh that kick-started the entry of Private Investors back into the power sector after the Dabhol debacle as the state was the furthest on the reforms path. The SEBs have primarily started dealing with the PTC with no long term PPAs with the IPPs. This may reduce the risk to a certain extent. But the confidence of the lenders is not echoed by the private investors. Many instances can be sighted to support their argument. For example Reliance Energy has not been dealing with any SEBs except in Kerala. The experience of REL with SEBs has not been very comforting. Their payments have been delayed in the past and the BSES Kerala plant has not been running at the required PLF. The problem in dealing with the SEBs is the low level of consumer awareness about the need to pay. IPPs have been insisting on an Escrow Account whenever they negotiate a power purchase deal with the SEBs like Reliance Dadri plant. Notwithstanding, substantial foreign private sector equity and finance will not stream into the Indian power sector, until the major payment risks and power tariff issues are mitigated. Foreign investors and financers require sanctity of contracts (including the purchase of, and full payment for, contracted power), honored-payouts for purchased power under binding guarantees (i.e., payment (i.e., counter guarantees) and debt (i.e., sovereign guarantees) security mechanisms), and the knowledge that invoices will be paid in full and regularly without requiring litigation to ensure each payment.

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4.3 Project Economics The cost of power generation varies, depending on the type of fuel used. The choice of fuel for a power plant is influenced by a number of factors such as the relative cost of generation, availability, transportation constraints, and environmental hurdles. The capital costs of power plants also vary significantly, based on the source of energy, infrastructure, plant size, technology and equipment and interest during construction (IDC).

4.3.1 Fuels Supply As pointed out earlier, power plants with the lowest variable costs (Coal) should be employed to meet the base demand, while those with a higher variable cost (Gas) should be employed to meet the peaking demand. This will result in a minimum overall variable cost of power. Cost: The delivered price of any fuel can vary significantly depending on the source of supply (imported or indigenous) and the distance of the plant from the source of supply. Power plants located near coal mines (pit-head plants) are able to generate power at a fairly lower rate than plants that need to transport coal over long distances. Supply: An interruption in the fuel supply can lower the plant’s PLF, resulting in a higher overall cost of power. Given the fuel supply constraints faced by existing power plants, banks and financial institutions insist on a regular fuel supply arrangement (FSA) before funding private sector power projects, especially those proposed to be funded on a nonrecourse basis. As a result, private power producers want to have legally enforceable fuel supply agreements with fuel suppliers and fuel transporters where the power producer would pay a premium on the price of the fuel, to ensure its adequate and regular supply and would also guarantee a minimum off take of fuel from the fuel supplier.

4.3.2 Capital costs Power projects are highly capital-intensive and have a gestation period of 4-6 years. The fixed component of the power tariff is linked to the capital cost of the project. Hence, the capital cost of a power project is a very important determinant of the total cost of generation. The capital costs of power plants also vary significantly, based on the source of energy, infrastructure, plant size, technology and equipment and interest during construction (IDC). Hence, it is not possible to set standard benchmark costs for power plants. However, the capital costs of most projects in the private sector are assumed as shown in the table above. Table 4.4.2: Power Project Costs

Power Project Cost Project Type Coal Gas Hydro

Rs(Crores)/MW 4-5 3.5-4 5-6

The various factors that affect the cost of setting up a power plant are discussed below.

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Table 4.2: Factors affecting Costs Factors affecting cost Remarks

Factor Source of energy

The cost of setting up a coal-based plant is lower than nuclear plants and higher than those based on natural gas, naphtha and fuel oil. The high cost of coalbased plants is attributed to the additional equipment required, such as coalhandling and ash-handling plants.

Infrastructure

The availability of water, transportation infrastructure, and power evacuation and transmission facilities influence the location of a power plant.

Size

A larger plant costs less, in terms of cost per unit of capacity. Larger units also have better thermal efficiency and lower O&M costs.

Technology and equipment

Equipment costs account for 75-80 per cent of the total cost of a thermal plant. However, depending on the choice of technology and equipment, the capital cost of two projects of the same size and using the same fuel can be different.

Interest during construction (IDC)

The long gestation period, and the capital-intensive nature of power projects, results in accumulation of the interest on debt till the commissioning of the plant which implies that delays in the implementation of a project could raise project costs significantly.

The itemized cost break-up for a typical power plant is shown below Table 4.3: Total Cost Break-up

Total Cost Break-up Item Land and Site Development Civil works including foundation Plant and machinery Consultancy fees Preliminary & pre-operative exp. Contingencies and escalation Margin money for working capital

Rs. Million per MW 0.3 - 0.5 2.4 - 2.7 16.5 - 21.5 0.3 - 0.9 3.6 - 4.5 4.8 - 5.1 0.2 - 0.3

Percentage of total cost 1.0 - 1.5 8.0 - 9.0 55.0 - 58.0 1.0 - 3.0 12.0 - 15.0 16.0 - 17.0 0.5 - 1.0

30 - 45

100

Total

4.3.3 Wholesale Tariff Structure The term Availability Tariff -- in the Indian context -- stands for a rational tariff structure for power supply from generating stations on a contracted basis. In the Availability Tariff mechanism, the fixed and variable cost components are treated separately. The payment of fixed cost to the generating company is linked to availability of the plant, that is, its capability to deliver MWs on a day-by-day basis. The total amount payable to the generating company over a year towards the fixed cost depends on the average availability (MW delivering capability) of the plant over the year. In case the average actually achieved over the year is higher than the specified norm for plant availability, the generating company gets a higher payment. In case the average availability achieved is lower, the payment is also lower. Hence the name ‘Availability Tariff’. This is the first component of Availability Tariff, and is termed ‘capacity charge’.

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The second component of Availability Tariff is the ‘energy charge’, which comprises of the variable cost (i.e., fuel cost) of the power plant for generating energy as per the given schedule for the day. It may specifically be noted that energy charge (at the specified plant-specific rate) is not based on actual generation and plant output, but on scheduled generation. In case there are deviations from the schedule (e.g., if a power plant delivers 600 MW while it was scheduled to supply only 500 MW), the energy charge payment would still be for the scheduled generation (500 MW), and the excess generation (100 MW) would be remunerated at a rate dependent on the system conditions prevailing at the time. If the grid has surplus power at the time and frequency is above 50.0 cycles, the rate would be lower. If the excess generation takes place at the time of generation shortage in the system (in which condition the frequency would be below 50.0 cycles), the payment for extra generation would be at a higher rate. Likewise, if a state / customer draws more power from the regional grid than what is totally scheduled to be supplied to him from the various CGSs at a particular time, it has to pay for the excess drawal at a rate dependent on the system conditions, the rate being lower if the frequency is high, and being higher if the frequency is low. The deviation from schedule is technically termed as Unscheduled Interchange (UI) in Availability Tariff terminology. Figure 1.13 illustrates how and when the UI mechanism works. Figure 4.1: Availability Based Tariff Framework

The payment due to the generation company by the buyer in any year is computed as follows: Total payment due = Fixed charges + variable charges + UI charges, where Fixed charges comprise: 1. Interest on long-term debt 2. Depreciation 3. O&M expenses (including insurance expenses) 4. Return on equity 5. Incentive return on equity

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6. Interest on working capital 7. Taxes Variable charges comprise: 8. Cost of primary fuel 9. Cost of secondary fuel UI charges comprise: 10. Cost of secondary fuel

4.3.4 Capacity Allocation for Central Generating Stations CGSs were built to create economies of scale and to ensure an economically efficient mix of energy sources, such as hydroelectricity and coal. CGSs were also designed to complement the limited investment capacity of State Electricity Boards (SEBs). CGSs serve more than one state, generally in the same region. As illustrated in Figure 1.14, plant capacity is allocated in three parts: 1. 10% of the capacity is reserved for the state in which plant is situated. 2. 75% of the capacity is allocated among the various states as described below. 3. 15% of the capacity is reserved as unallocated for discretionary use as follows: Given to states on need basis. In the absence of emergency requirements, this share is split up among the states in the ratio of their planned allocation The allocation of 75% capacity is done as follows: 4. Center notifies each state about the available capacity and terms and conditions 5. States inform center about requirements 6. Center allocates capacity based on response of states 7. Once the capacity is allocated, it is fixed for the life of the plant 8. States may or may not draw their allocated share of power, but they still continue to pay the fixed charges for their allocated share In case of reduced availability of power for any reason, the share of all states in the allocation is reduced in the proportion of their original allotment.

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5 Power Transmission The transmission network in India currently reaches about 80% of the population. The transmission infrastructure formerly consisted of five regional grids that were not interconnected into a national grid. In 1998, restructuring efforts of the transmission system began with the creation of the Powergrid Corporation. The state-owned Powergrid (PGCIL) is responsible for transmission of about 40% of the electricity generated in India. India has successfully established links between the regional grids. In order to accomplish the planning objective for 2012, it is imperative to create an investment framework for timely and adequate evacuation infrastructure and transmission facilities. As per the Working Group for Power constituted by Planning Commission, the estimated investment of around USD 36 billion is required in XI Plan for completion of National Grid, its associated transmission system and state level transmission infrastructure. Out of this, an investment of about USD 14 billion would be required in central sector transmission systems alone and the balance in state and private sector projects. The actual investments in the X plan was around USD 12 billion out of which USD 5 billion was spent in central sector and the rest in state sector. While the investment needs of XI plan have tripled, the absorption capacity, availability of financial resources and the viability of utilities are likely to act as constraints in realizing these investment projections. Figure 5.1: Figure: XI Plan Investments in Transmission (USD Billion)

The investments by Central Sector have been more or less up to the mark in the past and central sector is likely to meet the targeted investment in the XI plan. The state sector investment has encountered constraints in terms of limited internal financial resources, assured return on investment and funding of projects in North Eastern Region (NER), Bihar, Jharkhand and J & K. The enabling conditions for raising the requisite resources and sustaining the investments remain testing for state sector. The SERCs need to promote investments in networks through appropriate pricing and regulatory arrangements. Inadequate consideration on the above aspects can seriously restrict the

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ability of the state sectors to raise investments. This can lead to shrinking of the state level plans with consequent impact on central sector growth. The policies and measures initiated so far have to be consolidated and carried forward to achieve the optimum transmission targets. The private sector participation is expected to increase as is evident from various Joint Ventures (JV) formed between PGCIL and various private companies and also few projects being developed by private companies through IPTC route. This would translate into higher investment by private sector going forward. The Ministry of Power has formulated guidelines to encourage competition in development of transmission projects. These guidelines include: 1. CERC and SERCs to grant transmission licenses 2. Agencies to identify transmission projects for tariff based competitive bidding 3. CTU to fund preparation of detailed project reports. 4. The developer and concerned utilities to sign Transmission Service Agreement (TSA) for payment of transmission charges on the basis of competitive bidding and approval by appropriate Commission. 5. TSA to include an arrangement for payment security consisting of revolving letter of credit of required amount and escrow arrangement. 6. Ministry of Power to appoint a committee to identify projects to be developed, facilitate bid preparation invitation, and evaluation, finalization and signing of TSA between the developer and the concerned utilities, and enable further development of the project. 7. RLDC to assist the developer in case of default in payment. 8. CEA to monitor the progress of the project to ensure the timely completion. The transmission forms a vital link of the electricity delivery chain. The different elements of transmission such as policies, regulatory framework, open access, transmission losses, transmission charges, private participation etc pose a challenge to the evolving Power Sector in India. Merely adding transmission capacity to the existing infrastructure may prove inadequate. It becomes equally imperative to revisit the individual elements in order to remove the constraints in financing. The transmission network is the heart of a competitive market. In today’s scenario, the transmission sector runs the risk of getting trapped between competitive generating and distribution sectors. A lot requires to be accomplished in this sector to realize the vision Power for All by 2012.

5.1 Private Sector Investment in Transmission Sector More or less, transmission utilities in India are publicly owned, though private ownership is permitted under the Electricity Act 2003, as long as common carrier principles and open access are followed. Although, the Act is conducive for private players, the private investment so far has been abysmally low with only few takers. The investor enthusiasm has been subdued partly due to slow evolution of subsequent regulatory and policy reforms. Moreover, the suspicions for investors are kept alive due to inadequate experience of authorities in many states in dealing with private sector, past experience, environmental clearances, technical and bureaucratic hurdles and delayed project development. Despite this, the initial response of the domestic and foreign investors to the policy of private participation has been optimistic. Planning Commission has estimated USD 8 billion worth of investments to be pumped into the transmission

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through Private Participation by 2012. This is about one third of the investment expected from Private Players in the generation sector. The efforts of MoP to attract private investment continue. In order to overcome the apprehension and facilitate private investment, concept of Special Purpose Vehicles (SPVs) on the lines of UMPP’s has been introduced. The SPVs comprising of Power Finance Corporation Ltd (PFC) and Rural Electrification Corporation (REC) as the nodal agencies will look into the contentious issues such as initial and detailed surveys, feasibility reports, environmental clearances, obtaining transmission license and ‘Right of Way’ (RoW), site identification and land compensation. Fourteen Ultra Mega transmission projects worth USD 5 billion on build-own-operate (BOO) basis have been identified underneath this scheme for developers under competitive tariff based bidding. With the need for approvals obviated, successful bidders can focus on planning and executing the projects. However, so far, expressions of interest have been invited for only four projects and there has been delay in awarding these projects. As against the original plan of finalizing developers by end of 2007, even requests for qualification have not been invited.

5.1.1 Mode of Investment by Private Investors The Electricity Act facilitates two modes for private hands in transmission projects. First, through Independent Private Transmission Company (IPTC), where full fund has to be mobilized by the private entrepreneur and the second through Joint Venture Company (JVC), where equity participation between CTU or STU and private party is allowed. The selection of private party is made by CTU or STU or both through competitive bidding. However, the minimum qualification for grant of license requires implementation experience of similar projects, operation and maintenance of transmission lines/substations at appropriate voltage levels and financial requirement of net worth. Most Indian private players neglecting a few do not qualify for the same, unless and until they tie up with some International players. The Joint Venture route for private participation is expected to be more favorable among the potential investors. The Joint Ventures will have the expertise of PGCIL, thus allowing better management of critical commercial issues like payment security and operational issues like obtaining right of way (RoW), environmental clearances, etc. It is being envisaged that about 70% of the total investment in private sector can be through JV route while rest will be IPTC. The first success story of JV was the Tala transmission line (49:51 JV between PGCIL and Tata Power). Subsequent to this, a JV was formed between PGCIL and Jai Prakash Hydro for power evacuation from Karcham Wangtoo hydropower project in Himachal Pradesh. Another 26:74 JV between PGCIL and Reliance Energy was formed to develop transmission lines associated with Koldam and Pārbati hydro projects again in Himachal Pradesh. A JV has also been signed between Torrent power and PGCIL. Contracts have been awarded to private parties through IPTC routes too such as to Tata power for building 400 kV single circuit Kishenpur-Thathar-Wagoora transmission line and Reliance Power for strengthening of Western Grid. A quick review of the CERC orders for the above two projects through the IPTC route indicates several issues that have delayed the execution of the two projects.

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Box 1: The Tala Experience – India’s first private sector transmission project Tala Transmission system is the first Private sector transmission project in India, which has already set precedence for other projects to follow. PGCIL established this first Public-Private joint venture in transmission sector with M/s Tata Power in 2001. Powerlinks Transmission Limited, the joint venture company (49:51 between PGCIL and Tata Power) implemented the major transmission lines of Associated Transmission System of Tala hydro electric project in Bhutan, East-North inter connector and northern region at about USD 34 billion. Tala received excellent response from International Funding Institutions like IFC, including multilateral financing from private sector arm of ADB, Manila and Indian Financial Institutions like IDFC and SBI. The Joint Venture Company received its transmission license from CERC, the first such license in Indian power sector. Financial closure of the project was achieved in May 2004. A debt of USD 233 million has been tied up with the consortium of multilateral and domestic financial institutions. Tala Transmission System was completed successfully in August 2006. PGCIL envisages implementing some more transmission projects in Joint Venture with private sector. For timely completion of National Grid, there is no choice but involving the Private Sector in transmission. The limited fiscal space for increasing investment by the central as well as state governments also accentuates the need for private sector in transmission. An appropriate policy framework for private participation in the sector is necessary but not a sufficient condition to improve the climate for private investment. Over the longer run, the incentive for transmission utilities to invest in and maintain networks depends on the transmission pricing. The fundamental challenges such as transmission pricing and losses, political acceptance and support, maintaining transparency in project implementation, delays in regulatory approvals, inadequate legal and commercial framework and consistency in policy matters throughout the execution of PPPs need to be addressed.

5.1.2 Tariff based bidding process for transmission Central Electricity Regulatory Commission decided to get implemented two projects forming part of Western Region System Strengthening Scheme-II through 100% private sector participation based on international competitive bidding. In compliance to CERC order, POWERGRID submitted Process & Procedure for selection of Bidders for implementation of transmission lines associated with WRSSS-II projects B & C through 100% private sector participation via IPTC route to CERC in September 2005 which was approved by CERC expeditiously. Taking note of all the hiccups and delays in awarding and execution of the above projects clearly demonstrates that clarity about process, scope and obligations play important role in the success of the process. However, the eventual success of the projects also demonstrates attractiveness of the competitive bidding route for infusing more private investment in transmission sector. Tariff coming out of the bidding process is found to be significantly lower than two benchmarks based on estimated capital cost of the projects. It is concluded that minimization of uncertainties and consequent reduction in risk perception of the bidders

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lead to success of the bidding process. This success also establishes competitive bidding as a viable option for private sector participation in transmission sector. Simpler technical and financial bids are more likely to be perceived as fair by the public and by other bidders. In this context, the decision of the CERC to change the complex and somewhat ambiguous method of evaluating the bids based on the tariff calculated from the cost and financing data submitted by the bidders to a simpler and unambiguous method based on the tariff quoted by the bidders seems to have contributed significantly in the success of the bidding process. Certainty and predictability plays an important role in the success of the bidding process. Ambiguity and uncertainties in the bidding process and provisions of the agreements, which are part and parcel of bid documents, greatly contributes to the risk perception of the bidders. If uncertainties are too many or perceived to have significant consequences, some of the conservative bidders may even decide not to participate in the bidding process. Others may assume consequences of uncertainties and ambiguities to have maximum possible cost impact and accordingly may end up quoting much higher tariff. Table 5.1: SWOT Analysis of Transmission Sector

SWOT ANALYSIS STRENGTH

WEAKNESS

Won confidence of World Bank, ADB and other International Funding agencies

High Capital Investment in Projects and heavy dependence on debt financing

Monopoly business & Govt. Protection

Investment approvals required from GOI Mismatch in Generation Project and Transmission System adversely affect financial Strength

Transmission highway would enable setting up of large size pit head stations having lower cost of energy

Lack of Profit centre concept at regional level

Investment towards fuel transportation infrastructure could be avoided.

Issues pertaining to transmission pricing and loss sharing Delays in regulatory approvals and awarding of the projects

OPPORTUNITIES OPPURTUNITIES

THREATS

Introduction of Private Sector participants to induct Financial resources

Poor health of Consumers ( SEBs ) and recovery can affect development of transmission systems and hence future development

Innovative methodologies need to be adopted for recovery of transmission charges of Highways

Uncertainty in addition of planned generating Capacity

National Grid to be established through Govt. support as basic infrastructure, similar to National Road Highways

Lack of commensurate long term Funds to meet Transmission Requirement Possibility of losing monopoly status in times to come and subsequent competition

Existing Infrastructure for diversification into telecom

Cost dependency on Exchange rate variation Working in Regulatory regime

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6 Power Distribution Out of the three sectors of electricity delivery chain, the distribution sector in India has been the most daunting sector. More than 80 % of the total energy consumption is distributed by the public sector while the balance is distributed by the private sector. The distribution sector is segmented into urban and rural parts. Both segments are distinct with different challenges and concerns. The urban distribution is distinguished by high consumer density coupled with higher rate of demand growth. The consumer mix is mostly commercial, residential, and industrial. Rural distribution segment is characterized by wide dispersal of network in large areas, high cost of supply, low consumer paying capacity, large number of subsidized customers, un-metered flat rate supply to farmers, non metering due to high cost and practical difficulties, low load and low rate of load growth. The consumer mix in rural areas is mainly agriculture and residential. The biggest challenge of the distribution sector is the high Aggregate Technical & Commercial (AT&C) losses. The current AT&C losses are in the range of 18% to 62% in various states with a National average of 30%. The poor condition of distribution sector has attracted the policy makers and regulatory attention. The need to improve this sector was realized was felt at the beginning of X Plan and is ongoing in the XI Plan.

6.1 Key issues facing the sector The problems in distribution sector such as lack of investment, commercial orientation, high AT&C losses and distorted tariff policies have accumulated over the years. The key issues effecting overall performance of the distribution sector are more or less common across India. The critical issues facing the distribution sector are highlighted below Issues related to high AT&C losses: The biggest challenge of the power sector is the high AT&C losses. Both technical and non-technical factors are contributing to high AT&C losses. More than 80% of the total technical loss and almost the entire commercial loss occur at the distribution stage. The average AT&C losses which primarily include theft, poor billing, collection inefficiency and network losses currently exceed 30% for the country as a whole. Such high losses, coupled with tariff distortions, have made the distribution companies financially unviable, thereby constraining their ability to either fund their own investment needs or attract private capital. Table 6.1: Reasons for high AT&C Losses Reasons for high AT&C Losses Technical Losses overloading of existing lines and substations lack of up gradation of old lines and equipments low HT: LT ratio poor maintenance of substations non-installation of sufficient capacitors

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Commercial Losses low metering/billing/collection efficiency theft, pilferage and tampering of meters Low accountability of employees lack of energy accounting and auditing

The all India T&D loss for the period 2002-07 has registered a drop of 6% while AT&C losses have dropped by only 2%. The current AT&C losses in the range of 30% of the power generated is one of the highest in the world. Table 6.2: Average National T&D and AT&C Losses (%) Average National T&D and AT&C losses (%) Fiscal Year

T&D

AT&C

2002-03

32.54

32.54

2003-04

32.53

34.78

2004-05

31.25

34.33

2005-06

30.42

34.54

2006-07

28.61

32.07

2007-08

26.91

30.46

Source: CEA

The current AT&C losses are in the range of 18% to 62% across various states. The average national AT&C loss is about 30%. There is wide variation of losses among the states and discoms within the states. The major portion of losses is due to theft and pilferage which is estimated at about USD 5 billion annually. Apart from theft, the distribution sector is plagued with billing of only 55% and collection efficiency of 41% in almost all states. Table 6.3: State wise AT&C Losses State wise AT&C Losses Less than 20%

Between 20-30%

Between 30-40%

Above 40%

Goa

Andhra Pradesh

Karnataka

Delhi

Tamil Nadu

Gujarat

Kerala

Uttar Pradesh

West Bengal

Assam

Bihar

Himachal Pradesh

Rajasthan

Jharkhand

Maharashtra

Haryana

Madhya Pradesh

Tripura

Meghalaya

Arunachal Pradesh

Punjab

Chhattisgarh

Manipur

Uttaranchal

Mizoram

Nagaland

Source: CEA

In financial terms, the commercial losses excluding subsidy have increased from USD 91 million in 1990-91 to USD 524 million in 2004-05. These losses have been attributed to low metering efficiency, un-metered supply, theft and pilferages. MoP has estimated that 1% reduction in T&D losses would produce savings of over USD 170 - 190 billion and reduction of T&D loss to around 10% will generate an additional capacity of 10,00012,000 MW. To improve the financial viability of utilities and reduce T&D losses, Accelerated Power Development and Reform Program (APDRP) was launched in 2001. Under the APDRP, MoUs (Memorandum of Understanding) and MoAs (Memorandum of Association) were signed with state governments for linking government support to upgradation of distribution network and progressively reducing the AT&C losses.

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Issues related to state governments: The distribution sector in India is for the most part under the purview of state sector .The state sector has not shown proactive commitment in the reform process. The unbundling and restructuring of State Electricity Boards (SEBs) conceived in 1990’s has been delayed and some states are still undergoing unbundling. The limited financial support to unbundled utilities during transition period has further delayed the reform process. The poor financial support received by the state sector for providing subsidized power to domestic and agricultural consumers coupled with inadequate administrative support in curbing theft have adversely affected the revenue recovery. The frequent change in policies by some state governments with regard to subsidies and free power to farmers has also impacted the cost coverage of utilities. Issues related to regulatory process: Although, twenty one states have unbundled and formed SERCs so far, but some of the SERCs are inadequately staffed with poor infrastructure. The unbundled distribution licensees have also not been able to fully implement regulations and directives due to financial resource constraints, lack of skilled human resources and inadequate awareness. The tariff filings are often delayed due to lack of competency and resources in discoms. In several cases, discom’s have to revise their filings on account of data gaps or improper information. There is no transparency in data which leads to delay in filing petitions and responding to queries from the regulator. Issues related to corporate governance: The focus of distribution companies for efficiency improvement is diverted mainly because most of the distribution companies formed as a result of unbundling of SEB’s are still not fully autonomous. The unbundling is limited to operational and technical segregation only. Segregation of accounts, cash flow, human resources is not complete. Successor companies are highly dependent on their parent company for financials, cash flow, human resources, investment decisions and other administrative matters. Reinforcement of existing network in the form of new transformers, new lines and augmentation of existing transformers and lines commensurate with load growth is poor. Also, the existing distribution networks are ageing which resulting in poor reliability, increased Renovation and Modernization (R&M) expenses and poor quality of supply. The distribution system has low HT:LT ratio. The consumer awareness about Demand Side Management (DSM) is limited which results in to higher consumption and increased losses. Commercial and operational issues: Ministry of Power (MoP) has estimated commercial losses at about USD 5 billion per year. The commercial losses are primarily due to improper energy accounting, billing processes, faulty metering, under-billing, theft, pilferage of energy and lack of accountability within the organization. Many states have undertaken 100% metering programs, but so far only 87% of the total consumers are metered. The low level of collection efficiency is attributable to lack of accountability, inadequate collection facilities, limited usage of IT and technology, billing errors and political and administrative interference. The utilities are not able to conduct energy audit due to inadequate metering and data collection system in place. Discoms do not have proper

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load monitoring and control mechanisms which results in random control of the demand and often leads to loss of revenue. Issues related to technology: The utilities especially in rural areas maintain manual records of consumers and as result do not have complete record of all consumers resulting in revenue loss. Electromechanical meters, manual reading of meters, manual bill preparation and delivery and inadequate bill collection facilities leads to delay in revenue collection and revenue leakage. Monitoring of consumer energy metering systems is critical to overall revenue collection. Asset database is crucial in efficient management of assets and claiming depreciation under annual revenue requirement. Almost all distribution companies do not have real-time monitoring system for demand management. Most discoms do not have distribution control centre for managing load shedding and instructions from SLDC. Issues Related to Private Participation The experience of private participation in distribution has not been to the expected level. However, the Electricity Act provides adequate signals in terms of attractiveness of this segment for private investment. The Act provides for parallel and second distribution licensee in same area of supply, which enables setting up parallel distribution lines in specific areas. Private participation impediments can be largely attributed to the risks involved. Until risks related to measurement of operational parameters such as losses, regulatory risks and political risks are not minimized, the privatization opportunities may be limited.

6.2 Privatization of Distribution The Private distribution companies have already been operating in various parts of the country, namely Calcutta Electric Supply Company (CESC) in Kolkata, Ahmedabad Electricity Company Limited in Ahmedabad, Surat Electricity Company Limited in Surat, Tata Power Company and Bombay Sub-urban Electric Supply Company Limited in Mumbai and Noida Power Company in Greater Noida. These companies have been functioning smoothly over a period of time. Consequent to enactment of the Reform Acts, Orissa and Delhi have privatized distribution in their States. Distribution was privatized in Orissa in 1999 and in Delhi in July 2002. The Reforms act provide for constitution of Electricity Regulatory Commission, restructuring of electricity industry and increasing avenues for participation of private sector for taking measures conducive to the development and management of the electricity industry in an efficient, commercial, economic and competitive manner.

6.2.1 Privatization of Distribution in Delhi Delhi Electricity Reform Act was notified on 8th March 2001. In terms of the provisions of the Reforms Act and on the basis of the recommendations of the consultant, the Government of NCT of Delhi unbundled Delhi Vidyut Board (DVB) into six successor companies viz., GENCO (Indraprastha Power Generation Company Limited) for generation of electricity, TRANSCO (Delhi Power Supply Company Limited) for procurement, transmission and bulk supply of electricity,

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Three distribution companies namely, DISCOM 1 (Central-East Delhi Electricity Distribution Company Limited), DISCOM 2 (South-West Delhi Distribution Company Limited) and DISCOM 3 (North-North West Delhi Distribution Company Limited); and One holding company (Delhi Power Company Limited). Major equity of DISCOM 1 (Central East Delhi Electricity Distribution Company Ltd.) has been divested to BSES Yamuna. Major equity of DISCOM 2 (South- West Delhi Distribution Company Ltd.) has been assigned to BSES Rajdhani. Tata Power took over the major equity of DISCOM 3 (North- North West Delhi Distribution Company Ltd.) as North Delhi Power Limited.

6.2.2 Impact of Privatization on Distribution Delhi is seen as the future model for privatization of distribution in the country and the impact of the privatization was immediate on the performance. The Delhi power scenario in itself has been rated the best in the country according to CRISIL and ICRA [CRISIL and ICRA, 2004]. Prior to privatization, the Aggregate Technical and Commercial (AT&C) loss level was 50.7 per cent. A loss reduction path of 17 percentage points was charted for the private distribution companies over a period of five years. These private companies have strong incentives to outperform these targets, since the loss reduction would be equally shared between consumers and the distribution companies. Distribution has been a tough business from the borrowers experience unless there is adequate support from state govt. The non-financial aspects of the Discom business include a constant need to keep pace with everything related to business in terms of technology, regulatory changes, legal issues etc. Past experience has suggested that it is tough to get appreciated. The financial aspects of the business include a necessary time of 3 years for the business to stabilize. The returns are also not that attractive compared to the risk involved. What makes business sense to the players is the fact that they can takeover Discoms to protect their generation. So we can expect players like Reliance Energy and Tata Power to move aggressively to take over Discoms in UP and Maharashtra, where they have generation interests.

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7 Project Financing The Indian economy is poised for higher economic growth in the years to come. This will require large investment in the infrastructure sectors including the power sector. The National Electricity Plan of India aims to provide access to electricity to all households by 2010 and to meet all shortages by 2012. This will require an investment of around USD 200 billion to finance generation, transmission, distribution and rural electrification projects. During the 1990s, up to 80% of power sector funding came from the public sector, followed by the private sector (10–15%) and official development assistance (5–10%). Increasingly, both the central and state governments are facing the need to meet competing budgeting requirement from other social sectors such as health and primary education. The need for enhanced fiscal discipline and macroeconomic stability is also placing a limit on borrowing capacity of the government both at central and state level. Given the limited fiscal space for budgetary support for such investments, greater private sector participation is inevitable. Inefficiency, administrative bottlenecks and poor and inadequate infrastructure facilities, in particular continued shortage of electricity in India under public ownership has necessitated enhanced private participation in the sector. Power sector reforms have been initiated in India with the aim of creating an enabling environment for private investment thereby helping to bridge the gap in public investment. Persistent power shortages, inadequate public investment and the economic crisis faced by India in the early 1990s led to the opening up of the power sector to private investment and major policy initiatives were undertaken to encourage private and foreign investment. The investment climate was further strengthened through gradual restructuring of the state electricity boards (SEBs) and initiation of regulatory reforms at the central and state level. More recently, enactment of the Electricity Act 2003 includes enabling provisions for enhancing competition in the sector and to improve the environment for private participation. The abolition of the single buyer model and phased access to consumers has unlocked substantial potential for private investment in the sector.

7.1 Types and Sources of Finance 7.1.1 Debt Given the capital-intensive nature of power projects, mobilization of long-term debt becomes critical to the development of power projects. Project finance debt is generally secured by projects assets such that after paying operating expenses, debt and debt service is paid from cash flows. Debt typically constitutes up to 70% of the power project costs in India. The type of debt used in power projects finance structures has been varied. The following are some of the sources of debt available to power projects developers: Government: Traditionally, the main source of debt has been the government. Both the central and state governments lend the money to utilities from time to time for expansion plans or working capital. They extend loans for longer tenure and at lower interest rates than commercial rates. Multilateral Agencies:

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In the past, multilateral agencies have funded expansion plans of central utilities such as NTPC, NHPC or PGCIL. In the mid-nineties, they switched their focus from lending to support power sector reforms in states aimed at mobilizing investments and increasing economic efficiency. The have funded restructuring and reforms efforts of SEBs. The tenure of these loans typically ranges from 1525 years, with moratorium of five years. However, the investments yielded limited results, with the state governments faltering on the milestones attached to the funding. Subsequently, the agencies discontinued lending to state reform programmes. In the last couple of years, these agencies have shown greater confidence in the sector, mainly due to Electricity Act 2003 and follow-up policies. Majority of the funds from these agencies are still provided to Central Public Sector Undertakings (CPSUs). Commercial Banks and Financial Institutions Commercial banks and Financial Institutions (FIs) have consistently increased lending to power sector in the last 4-5 years. Most of the lending has been skewed towards the generation segment. With the opening up of the T&D segment to the private sector, commercial lending is likely to increase in future. For generation projects, the standard tenure of loans is 13-14 years, which included construction period and repayment period of 10 years. Earlier the lending use to be under recourse financing, but in the last 4-5 years, the lending institutions have become more liberal and comfortable with lending to bankable power projects. Although, commercial banks and FIs continue to increase their exposure to the power sector, individual exposure of banks to the sector remains limited. This is mainly because they are still constrained by financing limits as per prevalent prudential norms prescribed by the Reserve Bank of India (RBI). Niche Institutions There are also niche institutions such as Power Finance Corporation (PFC) and Rural Electrification Corporation (REC), which provide loans specifically to power sector. While PFC provides loans for all kinds of investments, REC focuses mainly on rural electrification. The state sector’s reliance on these institutions for debt is very high mainly due to the competitive rates and liberal terms and conditions offered by them. In the recent past, due to their experience and expertise in the sector, these institutions have been competing with commercial banks. Moreover, since issues like asset-liability mismatch and exposure limits are not applicable to PFC and REC, it is easier for these institutions to lend to the sector. Insurance Companies Insurance companies like the Life Insurance Corporation of India (LIC), General Insurance Corporation of India (GIC) have extended financial support to the power sector. There are limits on the investments prescribed by the Insurance Regulatory and Development Authority of India (IRDA). Life insurance and general insurance companies have to invest at least 15% and 10% of the fund respectively to the infrastructure and social sectors. External Commercial Borrowings

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External commercial borrowings (ECBs) were quite a popular means to raise finances until some time back, especially for large projects funding. These loans are raised at Libor-plus rates, which are generally lower than the interest rates in the domestic market. ECBs have declined of late due to RBI restrictions on foreign funds flows for rupee expenditure and due to an increase in borrowing costs as a result of the sub-prime effect. Export Credit Agencies Loans from export credit agencies are cheaper than commercial loans and are generally used when equipment needs to be imported from a particular country. These are likely to gain importance in the medium term mainly fuelled by the requirement of importing super-critical units in the eleventh and Twelfth plan periods, and until this demand is met by the domestic market. Bonds Several utilities and state power corporations have resorted to issuing bonds to raise funds. These are generally subscribed by provident and pension funds, gratuity trusts, insurance companies, mutual funds, individual, etc. These bonds typically have tenure of 7-8 years.

7.1.2 Equity The equity in power projects, like in other projects, is driven by the rate of return that is expected from the investment apart from acting as a cushion to project finance. In the power sector, the return on equity is fixed at 15.5% on 30% of the equity investment. The sources of equity are promoter’s equity, internal accruals, equity funds and strategic equity investors. Raising funds from capital markets is also becoming increasingly popular. The following are some of the sources of equity available to power project developers: Promoter’s Equity And Internal Accruals Most project developers invest some amount of the total project cost as promoter’s equity to be able to earn the minimum return on equity and raise the required debt. Many CPSUs, including National Thermal Power Corporation (NTPC) are increasingly relying on internal accruals for investing equity in new projects. Primary/Capital Markets In recent times, power sector companies have been raising funds from primary markets through Initial Public Offerings (IPOs). Almost all IPOs of power companies in the last two to three years have met with an overwhelming response from investors or have been performing well in the stock markets. Some of the successful IPOs have been those of CPSUs like NTPC, and PGCIL, private developers like Suzlon Energy, JP Hydro and Reliance Power and infrastructure companies like GMR, GVK and Lanco. Many power companies are expected to launch their IPOs in the coming years. NTPC is also planning to come out with a follow-on public offer. Qualified Institutional Placements Another source of equity, which is increasingly being tapped by power sector companies, is private placement with qualified institutional investors. For instance, GVK Power & Infrastructure Limited (GVKIL) and Kalpataru Power

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Transmission raised USD 300 million and USD 85 million respectively through this route in May 2007 and September 2006 respectively. PTC India also raised around USD 29 million through this route in January 2008 by allotting shares to institutional buyers like LIC and Morgan Stanley, among others. Equity Funds Specialized equity funds such as India Development Fund by Infrastructure Development Finance Company (IDFC) have been set up to invest in equity in private sector power sectors. The India Power Fund by PFC which was expected to be launched in 2004 is however, yet to start operations. India Infrastructure Finance Company Limited (IIFCL), Citigroup, Blackstone have also instituted a USD 5 billion India infrastructure financing initiative for investing in infrastructure projects. The Anil Dhirubani Ambani Group and Singapore’s Temasek Holdings constituted the Reliance India Power Fund with equal contributions. Others planning to set up infrastructure funds, which would pick up equity in power projects as well, include a USD 2 billion infrastructure by ICICI bank, the USD 1 billion Macquarie India Infrastructure Opportunities Fund by Macquarie and International Finance Corporation (IFC), a USD 1 billion India focused infrastructure private equity fund by Standard Chartered and IL&FS Investment Managers and a USD 2 billion India Infrastructure Fund by JP Morgan and Chase Company. PTC India’s investment arm PTC Financial Services also plans to pick up equity in power projects through an Energy Equity Fund.

7.2 Trends in Power Sector Financing Increased investor confidence resulting in commitment and disbursement of more funds IPP revival triggered by increased investor confidence Gradually increasing interest rates leading to increased project costs Increased availability of longer-term debt Skew towards investment in generation continues External Commercial Borrowings (ECB) loses sheen as RBI tightens norms As local capital market mature, more companies are opting for IPOs Lenders no longer demand government guarantees, counter guarantees. Bankable and competitively priced projects are able to raise funds easily. Project financing criteria relaxed by financiers for new types of projects. Promoter’s track record is a important consideration

7.3 Key Power Financing Power companies continue to raise funds through a variety of vehicles including public offers, bond issues and debt syndication. Multilateral agencies have shifted back to utility finance. Commercial Banks and FIs have also increased lending to the sector apart from PFC and REC. The IPP segment has seen renewed vigour.

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7.3.1 Financial Closures Over the last year and a half, over 8,000 MW of private sector power projects have achieved financial closure. Some of those projects are as under: 1,200 MW Rosa power project in Uttar Pradesh being developed by Reliance Energy Limited. 500 MW Teesta VI hydro project in Sikkim being developed by Lanco Infratech. 1,200 MW imported coal based power project at Ratnagiri, Maharashtra being developed by JSW Energy. 330 MW Shrinagar hydro projects in Uttarakhand being developed by GVK. 1,015 MW coal based Nagarjuna power project at Mangalore, Karnataka being developed by Lanco Infratech and Nagarjuna Group. 1,000 MW Karcham Wangtoo hydro project being executed by Jaypee Group. 1,200 MW Teesta-III hydro project being executed by Teesta Urja Limited. 540 MW captive thermal power project at Chandrapur, Maharashtra being developed by KSK Energy Ventures. 1,000 MW lignite based power project in Rajasthan being developed by JSW Energy.

7.3.2 Central Sector Project Financing In the past, NTPC and PGCIL have raised funds in the form of equity and debt. Their equity component includes internal accruals, government budgetary support and joint ventures (JVs), while the debt component comprises private placement of bonds, market borrowings from FIs and niche institutions and loans from multilateral agencies. The following are the details of some of the recent financings: NTPC In September 2006, NTPC entered into a loan agreement of USD 300 million with Asian Development Bank (ADB) under latter’s complementary finance scheme for Sipat and Kahalagaon Stage II projects In February 2007, NTPC received a grant of USD 12 million from the ministry to implement 14 distributed projects. The grants were given under the Ministry of Power’s Delivery through Decentralized Management (DDM) scheme. In March 2007, NTPC signed a loan agreement of USD 100 million with KfW to part finance the expenditure on R&M of NTPC plants. This is the first loan provided by KfW directly to NTPC. In July2007, NTPC signed a MoU with ADB to set up a JV for renewable power generation. NTPC and other government entities will hold 50% stake, while strategic investors will hold the remainder. ADB is expected to acquire 20% stake at a later stage. The JV is expected to hold a portfolio of about 500 MW of renewable generation over the next three years, the initial focus being wind power and mini and micro hydro power projects.

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PGCIL In 2006-07, PGCIL undertook capital investment of USD 1.5 billion. Of this it mobilized USD 1 billion through private placement of bonds and the balance from internal resources and multilateral agencies. In the past, World Bank has extended USD 450 million as loan to PGCIL for Power grid System Development Project II in 2001 and USD 400 million for Project III in 2006. Other multilateral agencies such as ADB and JBIC have extended a USD 400 million in 2004 and USD 3.14 billion in 2005 respectively to PGCIL. For funding its future projects, PGCIL is negotiating with the World Bank and ADB for loan assistance of USD 600 million each.

7.3.3 State Sector Project Financing During the period 2006 through December 2007, the state sector funded their power sector programmes mostly with loans from PFC and REC or grants from the government. Some of the details are as follows: Tamil Nadu – In April 2007, REC signed a MoU with Tamil Nadu Electricity Board for providing a loan of USD 3.8 billion over the next five years for augmenting power sector capacity and transmission & distribution schemes. Jammu & Kashmir – In March 2007, the government agreed to give a USD 900 billion special power reforms grant to J&K over three years. Haryana – The Haryana Power Generation Corporation (HPGC) entered into loan agreement with PFC and REC in May 2007 for construction of 1,200 MW thermal power plant at Hissar.

7.3.4 Private Sector Overseas Financing During the period September 2006 through December 2007, a few Indian companies made some overseas investment. Some of these are as follows: Suzlon’s acquisition of REpower – In May 2007, Suzlon Energy completed the acquisition for German wind turbine maker REpower for Euro 1.34 billion. The lead financiers for the acquisition were ABN Amro, SBI and ICICI Bank TPC’s acquisition of PT Kaltim Prima Coal (KPC), PT Arutmin Indonesia and other related coal trading companies owned by PT Bumi Resources Tbk - TPC completed its acquisition of 30% equity in Indonesian assets for USD 1.1 billion. It took a bridge loan facility of USD 950 million from a group of banks led by Barclays Bank.

7.3.5 Qualified Institutional Placements During the period September 2006 through December 2007, many private sector companies raised money through QIP route. Some of these financings are as follows: GMR Infrastructure Limited raised USD 950 million through a QIP of 9% equity stake in December 2007 for various energy projects, airport project and Special Economic Zone (SEZ).

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Suzlon Energy raised USD 520 million through QIP of shares to repay a part of debt raised to fund the acquisition of REpower and Belgian gearbox maker Hansen Transmission International in December 2007. CESC Limited raised USD 150 million through its QIP issue in December 2007 to fund its upcoming power projects.

7.4 Major Financiers in Power Sector Power Finance Corporation Rural Electrification Corporation World Bank International Finance Corporation Asian Development Bank Japan Bank for International Cooperation Kreditanstalt fuer Wiederaufbau Department of International Development India Infrastructure Finance Company Limited Infrastructure Development Finance Company Life Insurance Company Punjab National Bank ICICI Bank IDBI Bank State Bank of India SBI Capital Markets

7.5 Policy development for Private Investment The economic crisis faced by India in 1990–91 provided an opportunity for unshackling the economy by de-licensing a number of sectors. This led to the opening up of the infrastructure sectors including power to enhanced private participation. The power sector has witnessed various phases of policy developments. The earliest phase, which began in the early 1990s, was aimed to improve the policy climate for private investment. Later on, the emphasis was placed on regulatory reforms leading to the establishment of independent regulatory commissions. The enactment of the Electricity Act 2003 led to deepening up the reform process through the introduction of a competitive regime in the Indian power sector. These policy and regulatory developments are further discussed below in terms of specific policy milestones.

7.5.1 Electricity Act 2003 The conceptual framework underlying this new legislation is that the electricity sector must be opened for competition. The Bill moves towards creating a market-based regime in the power sector. As stated earlier, the Bill seeks to consolidate, update and rationalize laws related to generation, transmission, distribution, trading and use of power. The new Electricity Act, 2003, effective June 10, 2003, consolidated all previous

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electricity laws in India. The enactment of this new statute was a welcome step for foreign investors, as well as for private domestic players, for a number of reasons including but not limited to, the following: A power generating company has been allowed to establish, operate and maintain power generating stations without obtaining a license on fulfillment of certain conditions. The Act allows private participation in transmission and distribution facilities subject to licensing by the Central Electricity Regulatory Commission (“CERC”). Licensors are to provide non-discriminatory open access to their transmission and distribution systems for use by any licensee, generating company and consumer, subject to the payment of certain charges. Independent Power Producers (“IPPs”) and captive power generators have been allowed to sell directly to any licensee or consumer on terms and conditions agreed to between the parties, subject to the payment of certain charges. The Appellate Tribunal for Electricity (“Tribunal”) has been established for hearing appeals from decisions from the CERC and State Electricity Regulatory Commissions (“SERC”s). The Tribunal will have powers similar to that of a civil court. The Act provides for re-organization of State Electricity Boards (“SEB”s) through corporatization and unbundling The benefits of the Bill are several however, all of these not likely to materialize in the medium term. Until such an interim period when the free and open market systems are developed, the role of the regulator will become very crucial. The role will be important especially when promoting competition, fixing reasonable charges for transmission, generating tariffs, fixing wheeling and cross-subsidy charges and in protecting the consumers from the rising prices of electricity, more so in times of shortage. According to the Industry Experts, SEBs will have to fall in line as they need to survive in the heightened competition. The SEBs and other govt. utilities do not have an option to just die out. The unbundling and privatization of the SEBs will continue. The SEBs T&D revenues are set to improve with the advent of power trading. Being the sole owner of the Transmission networks, they will have cash inflows in terms of wheeling charges and access charges. All new contracts being signed are primarily agreements with the Power Trading Corporation as direct MOUs with the SEBs have a long lead time (18 months in some cases) due to legal and other wrangles. This keeps the window open for Merchant Power and Trading. But wholly merchant power based plants are also not viable. They require that the borrowers have an agreement for at least a part of their generation, say 60%. Dabhol experience has also taught the Indian Power sector to not indulge in MOUs but rather go for competitive biddings at all stages. This has further increased the confidence in the system. There have been setbacks on the way, like the free power promise to farmers in Andhra. But to mitigate such risks, sponsors are obliged to take the first hit. As for the Act and state utilities falling in line, the market really sees no option for them and has confidence in the reforms process. But the full impact of the Electricity Act will take at least another

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3-4 years with the clear policy on things like wheeling charges to take another 6-9 months. The restructuring of the SEBs has been slower than expected. The private investors believe that this is an inevitable process but it will take time, until which time dealing with an SEB would remain a risky business proposition. Reliance thus would like to set up power generation plants for supply to its own distribution circles. Dahanu plant supplies to Mumbai and the Dadri plant is for power to Delhi and the prospective distribution circles in Uttar Pradesh. As for the reforms in the power sector, IPPs have seen a marked improvement in the collections from urban areas mainly due to the increased awareness. The tariff policy has delineated the roles of State govt., the utility (Private Generators) and the Consumer (SEBs) in determining tariffs. The competitive bidding guidelines ensure that the private players get their due tariffs. The govt. is looking to withdraw from direct investments in the sector primarily due to a resource crunch and the establishment of the Regulators has brought in a Quasi-judiciary setup, which will hopefully ensure a fair business model. The Electricity Act has brought in a more commercial approach among all players, as they have to compete in order to survive. The Act has proposed incentives for efficiency. But lot more needs to be done. Things like tariff policy, wheeling charges, surcharge for subsidy need to be clearly defined before the benefits of the Act are realized. The competitive guidelines ensure that the financial health of the IPPs is not endangered. The regulations ensure that an escrow account is provided for the IPP by the state utility. The minimum off take is also guaranteed by the agreements. In case of inadequate purchase or default on payment, the guidelines provide the IPP with an option to cut-off the power supply with immediate affect, a drawdown on the escrow account and merchant power selling. The power market as that is, the IPPs are very sure of finding buyers for their power in case the SEBs default and even with the wheeling charges, they believe the power supplied will be economical. The power generated is at Rs.1.60 per unit plus wheeling charges of 25 paise on an average. The total of Rs. 1.85 is lesser than Rs.2.10 that states of Karnataka and AP pay. The Power sector still needs a more investor friendly regulatory setup. The private investors still face a lot of problems when dealing with regulators for clearances and security mechanisms etc. For example in Orissa, there was no change in tariffs and then they were revised negatively this year. IPPs want transparency and consistent interpretation of regulations in between states. IPPs want a more prudent commercial and financial support system with the power sector being declared a priority sector. The regulators also need to maintain a balance between all the stakeholders. Numerous private players are looking for project financing, for both SEB supply and Merchant Sales. But purely merchant sales are viewed with some reservations and it is preferred if off-takers are identified and a proof of existing demand is furnished. SBI for example requires that the power generators have an agreement for at least a part of their generation, say 60%. The rest can be for merchant power. With the advent of Power Trading as a provision of the Act, licenses for the same have been awarded to Tata Power, Adani Group, Reliance Energy Limited and NTPC. This also involves problems associated with open access and the regulatory framework is yet to be decided upon. Unless things like wheeling charges, surcharge for subsidy and access charges are decided on power trading cannot happen. Open Access has its own problems. The biggest problem is of measuring usage of electricity and the ideal location

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of metering. Discipline has been a problem in the Indian power sector, and for this ABT and UI for traders also needs to be clearly spelt out. India needs to do a lot of groundwork and ensure that there is a countrywide market exposure available for the participants to diversify the risks. For this the need for Transmission infrastructure is highlighted. Also needed is a proper settlement and balancing mechanism. Open Access will take another 3 to 5 years to come into full effect, as is the case with all other provisions of the Act.

7.5.2 Private Power Policy In 1991, the government of India amended the Electricity Supply (Act) 1948 to allow the entry of private investors in power generation and distribution. A tariff notification issued in 1992, provided for a two-part tariff structure covering fixed and variable costs. It provided for a 16% rate of return on equity at 68.5% PLF for thermal plants and (coal / lignite/ gas) at 90% availability for hydro power plants. The achievement of higher efficiency levels translated into higher rate of return for investors.

7.5.3 Mega Power Policy In 1995, the government strengthened its policy for private investment in generation projects over 1000 MW and which would supply electricity to more than one state, terming them as Mega power projects. The policy was intended to introduce a competitive bidding for awarding the projects. CEA, PGCIL and NTPC were to provide catalytic support to private investors by identifying potential sites, arranging the transmission of power and for preparing feasibility report respectively. The policy did not propose any fiscal concessions. Some of these shortcomings were addressed in the revised policy of 1998 (Revised Mega Power Policy). Nineteen projects, 14 in the public sector and 5 in the private sector, were declared to be mega power projects. To alleviate risks to private investors on account of payment security, PTC was setup to purchase power from the identified projects and to sell it to identified SEBs. This included the adoption of a new package of security mechanism consisting of Letter of Credit and recourse to state government’s share of Central Plan Allocations. Establishment of Regulatory Commissions and privatization of distribution in cities with a population exceeding one million were included as pre-conditions in the policy. Import of capital equipment for such projects was exempted from customs duty. The projects were also granted income tax holiday for 10 years and, which could be claimed in any block of 10 years within the first 15 years. The policy was further liberalized by according mega project status to all inter-state thermal projects of 1000 MW and above, and to all interstate hydro projects of 1000 MW and above. These projects were now able to secure duty free import of capital goods. Due to concerns over transparency associated with MOU-based projects, the government issued norms for tariff-based bidding for thermal power projects in 1997. Further, this role was handed over to respective regulatory commissions. These norms were to serve as guidelines, and the regulatory commissions were to issue terms and conditions for tariff and retain purview over the PPAs for sale of power to the respective state utilities.

7.5.4 Policy Reforms for Investment in Transmission In addition to generation, the sector also requires substantial investment in the transmission network. In order to meet the projected requirement for additional power generation capacity of 100,000 MW by 2012, the Ministry of Power estimates that the

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investment requirement for the inter-state transmission network will be USD 17 billion. A significant proportion of this (USD 12 billion) is expected to be undertaken by POWERGRID, the Central Transmission Utility (CTU). The remainder (USD 5 billion) is expected to come from by private investors. As a means to encourage private investment in transmission networks, the Electricity Laws (Amendment) Act 1998 was enacted. This facilitated the infusion of private sector investment in transmission through grant of transmission licenses. Guidelines for private sector participation in the transmission sector were introduced in January 2000. These guidelines envisage two routes for private sector participation: Joint Venture (JV) route, wherein the CTU/STU owns at least 26% equity and the balance is contributed by the Joint Venture Partner (JVP) and the Independent Private Transmission Company (IPTC) Route, wherein 100% of the equity is owned by the private entity. A joint venture between PGCIL and Tata Power has successfully commissioned a 1200-km transmission line to transmit power from Bhutan to the Northern grid in India.

7.5.5 Regulatory Reforms An appropriate policy framework for private participation in the power sector is a necessary but not a sufficient condition for to improve the climate for private investment in the sector. Major hurdles faced by the private investors included frustrations in receiving administrative approvals, payment risks with financially weak SEBs/distribution utilities, lack of sovereign guarantees, political instability and the partially liberalized fuel markets, especially for the coal sector. The government realized that in order to attract much-needed private investment into the power sector, the separation of the distribution segment of the power sector should be carried out to improve its performance. Led by similar developments in a number of countries around the world a process of reform was introduced in the state of Orissa. It became the first state to unbundle the electricity board into five corporatized entities— one each for generation and transmission, and one each for the three distribution zones in the state. An independent regulatory commission (Orissa Electricity Regulatory Commission) was also set up to oversee the functioning of the transmission and distribution companies. Orissa later privatized its power companies. Subsequently, Haryana and Andhra Pradesh also followed the twin strategy of unbundling and regulatory reform. In 1998, the Central Electricity Regulatory Commission (CERC) was set up under the Electricity Regulatory Commissions Act, 1998. The main functions of the commission include regulating the tariffs of generating companies owned or controlled by the Central Government or those serving more than one state, as well as inter-state transmission and tariffs of transmission utilities. At the state level, the State Electricity Regulatory Commissions (SERCs) introduced a transparent procedure for tariff filing, its review, and the adoption of an order under which the utilities would fix transmission and distribution tariffs for various consumer categories. The process of tariff determination has become more transparent and participatory due to public announcement of tariff filings by the utilities. This process includes organization of public hearings and invitation for public comments thus bringing credibility to the process. In order to alleviate consumer concerns regarding quality improvement and better response by the utilities to their complaints, the SERCs have not only undertaken steps toward the formulation of complaint handling procedure by the utilities but also a system for themselves so that consumers can bring their concerns before the commission. Twenty-five states have set up regulatory commissions out of which twenty-one are functional, and 20 of these regulatory commissions (the SERCs)

44

have issued tariff orders. The smaller states (Manipur, Meghalaya and Nagaland) in the North East have established a Joint Electricity Regulatory Commission. Thirteen states have unbundled and corporatized their previously integrated SEBs. Orissa and Delhi have privatized distribution. The bitter public experience and its political concerns have led other state governments to take a more cautious approach toward privatization. The independence of regulatory institutions remains undermined by indirect control over the appointment of the members of the regulatory institutions and by delaying financial independence to such institutions. The regulatory environment has nevertheless reduced uncertainties associated with ad hoc behaviour by the electricity utilities under political influence. The concerns regarding regulatory uncertainty and lack of incentives in the rate of return regulation have been addressed through adoption of a multi-year tariff (MYT) framework by the CERC. The Electricity Act of 2003 prescribed adoption of MYT principles by all regulatory institutions. Some of the SERCs have initiated a consultation process for introducing the same. However, its effective implementation would be influenced by availability of reliable historical data which is crucial to designing appropriate incentives.

7.5.6 Distribution Reforms and Privatization Most of the ills of the Indian power sector find their origin in the distribution segment. The distribution segment has lagged both in terms of operational efficiency as well as financial performance. The slow pace of investment generation as well as distribution segment can be attributed to the severe cash flow problem associated with the underrecovery of costs and poor collection efficiency. Poor operational efficiency further aggravates the situation. Recognizing the need to accelerate reforms in the distribution sector the central government introduced the Accelerated Power Development Programme (APDP) in 2000–01 to restore the commercial viability of the distribution segment. To encourage reforms in the distribution sector, it was rechristened the Accelerated Power Development and Reforms Programme (APDRP) during 2002–03. Additional emphasis was placed on milestones for reforming the ailing distribution segment in the states. The main objectives of the programme include improving the financial viability of state utilities, reducing of aggregate technical and commercial (AT & C) losses, improving customer satisfaction, and increasing the reliability and quality of the power supply. The scheme also encourages the establishment of SERCs, metering of 11 kV feeders and of all consumers, and energy audits at the 11 kV level. A number of state utilities gained from the APDRP scheme by reducing cash losses and securing equivalent grants from the central government. The reform linked investment component also motivated restructuring and initiation of regulatory reforms in various states. The privatization plan for distribution zones in Delhi specified a five-year tariff profile, agreeable to the regulator (Delhi Electricity Regulatory Commission). This helped in mitigation of regulatory risk by ensuring tariff certainty and performance milestones for a five-year window. Even so, the privatization scheme was made possible by a substantial subsidy budgeted by the state government over the five year period. This would not be easy to replicate in other states. The Planning Commission has estimated that if the privatization of distribution in other states is carried out in line with the Delhi model, it would translate into a huge viability gap financing. In the privatized distribution zone of Orissa and Delhi, T&D losses remain above 33% and 25% respectively. Given the notso-successful experience to date, the Planning Commission has suggested alternatives such as last mile privatization involving metering, meter reading, billing and collection.

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7.6 Framework for Private Investment Policy reforms in the Indian power sector and regulatory initiatives have resulted in the emergence of a framework for private investment in generation, transmission, distribution and trading activities as outlined below. Available information related to market entry, pricing framework and policy and regulatory framework have been synthesized from appropriate policy and regulatory documentations, and is presented in the tables below. Table 7.1: Framework for Private Investment in Power Generation S. #

Market Characteristic

1 Customers

2

Entry

Policy and Regulatory Framework • • • • • • • • •

3

Market (Customer) Access

• •

• •

• 4

Pricing Framework for Sale to Distribution Utilities • • •

5

Pricing Framework for Sale to Open Access

•

SEB / Distribution licensees. Customers accorded open access by respective SERCs. Traders . De-licensed thermal and captive generation. CEA’s concurrence required only for hydro projects over a specified capital cost. No licensing for generation and distribution in rural areas. Built Own Operate (BOO) as well as Built Operate Transfer (BOT) framework. Open access of inter-state and intra-state transmission. Phased open access of distribution network as specified by the respective SERCs. Access to large customers available in some states as early as April 2005. Provision for multiple distribution license (EA, Sec. 14). Distribution licensees to purchase a percentage of the total consumption of electricity in the area of a distribution license from electricity generated using renewable sources. Such percentage to be specified by the respective SERCs. (EA, Sec. 86 (1) (e)). New IPPs—Competitive bidding as per guidelines for competitive procurement by distribution licensees (EA, Sec. 63). New IPPs—Non-competitive projects for sale to distribution licensees, to be determined by CERC / SERC as the case may be. As per terms and conditions of CERC/SERC, as the case may be. (EA, Sec. 21 (1) (a)). Existing plants owned / controlled by CPSUs and state owned generating companies (including new plants to be built up to next five years or as decided by regulatory commission as envisioned in the NTP), as per the terms and conditions of CERC/SERC. Existing IPPs and one time capacity extension up to 50% as per existing or agreed PPA and terms and conditions of CERC/SERCs, as the case may be. Distribution companies to buy a certain percentage of their power purchase from renewable sources. Price determined by the SERCs. Transactions due to real time imbalances as per the frequency-linked charge for unscheduled interchange (UI) under the ABT framework. For direct sale by any generating company / trader to customers granted open access as per mutual agreement.

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S. #

Market Characteristic

Policy and Regulatory Framework

Customers

6

7

Financial Conditions for Tariff Determination for Generating Companies

Subsidy

• • • • • • •

8

9

10

11

Cross-subsidy

FDI

Policy Framework

Regulatory Framework

•

• 100% foreign equity permitted; through automatic route • • • • • • • • • • • •

12

Other Related Agencies

• • • • • •

13

Future Developments

(EA, Sec. 49), subject to cross-subsidy surcharge and additional surcharge to be determined by the respective SERC. Rate of Return on Equity—15.5% (post tax) D/E Ratio—70:30 Target availability for recovery of full capacity (fixed) charges—85% Incentive—25 paise/kWh for ex-bus scheduled energy corresponding to scheduled generation in excess of ex-bus energy corresponding to target Plant Load Factor of 85%. Operational and financial norms notified by CERC. No direct subsidy burden—To be provided directly to the distribution licensee by the respective state government, if it desires to subsidize a consumer or class of consumer. Only in case of sale to open access customers—Crosssubsidy surcharge and additional surcharge. Cross-subsidy surcharge to be eliminated by SERCs in phases. Cross-subsidy surcharge not applicable in case of consumer switching to another distribution licensee. i.e., if generator also secures distribution license of the area, it avoids payment of cross subsidy or additional surcharge.

• •

Private Power Policy 1991 Mega Power Policy 1995 (Revised in 1998 and 2003) Electricity Act 2003 National Electricity Policy National Tariff Policy National Electricity Plan Ministry of Power guidelines Relevant regulations issued by the Central Electricity Regulatory Commission as per applicable jurisdiction Respective State Electricity Regulatory Commissions as per applicable jurisdiction. Appellate Tribunal for Electricity Central Electricity Authority (CEA) Inter Institutional Group to facilitate financial closure of projects Central Transmission Utility (CTU)—Power Grid Corporation of India Ltd. State Transmission Utilities (STUs) Regional Load Dispatch Centers (RLDCs) State Load Dispatch Centers (SLDCs) Regional Power Committees Power market development and emergence of Merchant Power Plants. Initiative for Nine Ultra Mega Projects for 36,000 MW capacity. Scope for Regional Power Projects for import of electricity in the country

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Table 7.2: Framework for Private Investment in Inter-State and Intra-State Transmission S. #

Market Characteristic

1 Customers

2

3

Entry

Market Access

4

Pricing

5

Framework for Return

6 7 8

9

10

Subsidy Cross-subsidy FDI

Policy Framework

Regulatory Framework

Policy and Regulatory Framework • SEB / Distribution licensees for short-term and long-term transmission of electricity; • Open access customers for short-term and long-term transmission of electricity • Licensed by CERC (inter-state transmission) / SERCs (intrastate transmission) • Two routes for private sector participation: o Joint Venture (JV) route, wherein the CTU/STU owns at least 26% equity and o Independent Private Transmission Company (IPTC) Route, wherein 100% equity is owned by the private entity. • In concurrence with Central Transmission Utility (CTU) (inter state) / State Transmission Utility (STU) (intra-state) / RLDC / SLDCs • CERCs Terms and Conditions for Tariff—current conditions applicable till March 2009. • Regional postage stamp basis with normative D/E ratio of 70:30 • Guided by National Tariff Policy • Rate of Return on Equity—14% (post tax) • Target Availability for recovery of full transmission charges (AC system—98%; HVDC—95%). • Incentives—on prorate basis for availability above the target availability for the transmission system. • Return on Foreign Equity—Equity invested in foreign currency is allowed a return in the same currency and payment is made in Indian Rupees on the exchange rate prevailing on the due date of billing. • Operational and financial norms notified by CERC. • No direct subsidy burden • No direct cross-subsidy burden (indirect influence through revenue stream of the distribution licensee) • 100% foreign equity permitted through Independent Power Transmission Corporation (IPTC) route. • As JV with local CTU/STU holding up to 26% stake in the transmission company • Guidelines for Private Investment in Transmission, 2000 • Tariff based Competitive-bidding Guidelines for Transmission Service, 2006 • Guidelines for Encouraging Competition in Development of Transmission Projects, 2006 • Electricity Act 2003 • National Electricity Policy • National Tariff Policy • Ministry of Power guidelines • National Electricity Plan • Relevant regulations issued by the Central Electricity Regulatory Commission as per applicable jurisdiction • Respective State Electricity Regulatory Commissions as per

48

S. #

Market Characteristic

Policy and Regulatory Framework applicable jurisdiction.

11

12

S. # 1

2

3

4

Other Agencies

Future Developments

• • • • • • • • •

Table 7.3: Framework for Private Investment in Distribution Market Policy and Regulatory Framework Characteristic Customers

Entry

Market Access

Pricing Framework

• • • • • • • • • • • • •

• • 5

6

Financial condition for tariff determination

•

Subsidy

• • •

7 8

Appellate Tribunal for Electricity Central Electricity Authority (CEA) Empowered Committee constituted by Min. of Power Central Transmission Utility (CTU)—Power Grid Corporation of India Ltd. State Transmission Utilities (STUs) Regional Load Dispatch Centers (RLDCs) State Load Dispatch Centers (SLDCs) Regional Power Committees A transmission pricing that takes into account distance and direction in addition to the quantum of power flow (National Electricity Policy).

Cross-subsidy

FDI

• •

End consumers Other state utilities Distribution License for Urban areas issued by SERCs Provision for Multiple Distribution License Distribution (including generation) in rural areas is de-licensed. Distribution Licensees can appoint franchisees for operations within their license area. Third party access through phased open access by SERCs. Provision of multiple distribution licensees by the SERCs. Rate of Return on Equity - 14% (post tax) Retail tariff determined by SERC under Rate of Return Regulation. Multi-year tariffs (MYT) framework to be introduced by SERCs. Access to distribution network priced by the SERCs. Third party access attracts a cross-subsidy surcharge and additional surcharge to be determined by the respective SERC. Cross-subsidy surcharge to be eliminated by the SERCs in a phased manner. In case of multiple distribution licensees, SERCs may fix only a maximum limit on tariffs (EA, Sec. 62(1)(d)). Rate of Return—National Tariff Policy specifies a rate of return on equity of 14%. SERCs can consider higher return for the distribution business due to increased risk to investors. Operational and financial norms notified by respective SERC. To be provided in advance by the state government to subsidize any consumer or class of consumer. (EA, Sec. 65) Industrial and commercial consumers cross subsidize domestic and agricultural consumers. SERCs to reduce and eliminate cross subsidy in a phased manner (EA, Sec. 39) 100% foreign equity permitted; through automatic route.

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S. #

9

10

11

12

Market Characteristic

Policy Framework

Regulatory Framework Future Developments

Other Agencies, Programs

Policy and Regulatory Framework • • • • • •

Private Power Policy Electricity Act 2003 National Electricity Policy National Tariff Policy Ministry of Power guidelines (for competitive procurement and bidding)

• State Electricity Regulatory Commissions • Multi-year Tariff • Privatization of distribution utilities formed after restructuring of erstwhile SEBs. • Performance based regulation. • Appellate Tribunal for Electricity • Grievances Redressal Forum and Ombudsman • Accelerated Power Development and Reforms Programme • (APDRP)—targeted at efficiency improvement and reduction of losses of distribution utilities. • Rajiv Gandhi Grameen Vidyutikaran Yojana (for Rural Electrification)

Table 7.4: Framework for Private Investment in Inter-State and Intra-state Trading Market Policy and Regulatory Framework S. # Characteristic 1 • License by CERC (for inter-state trading) Entry • License by SERCs (for intra-state trading) • License for annual trading volume linked to net worth of the Market Access 2 licensee in accordance with trading regulations issued by CERC/SERCs. • For trading under competitive bidding, there is no regulation of price. • For negotiated trading transactions, the maximum trading 3 Pricing margin on inter-state trading has been fixed by CERC at 4 paise per kWh. • Margin for intra-state trading. Rate of Return • No rate of return assured for trading activity 4 • Cap on maximum margin for negotiated trades. Subsidy 5 • No direct subsidy burden

6

7 8

Cross-subsidy

FDI Policy Framework

• For sale to distribution licensees. No direct cross-subsidy burden (indirect influence through revenue stream of the distribution licensee due to cross-subsidization of the tariff for certain category of consumers) • For sale to open access customers. Cross-subsidy surcharge and additional surcharge determined by the SERCs. • 100% foreign equity permitted; through automatic route. • Electricity Act 2003 • National Electricity Policy • National Tariff Policy

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S. #

Market Characteristic

Policy and Regulatory Framework • Guidelines for competitive procurement by distribution licensees

9

Regulatory Framework

10

Future Developments

• Relevant regulations issued by CERC / SERCs, especially those related to trading and open access. • Market Development initiatives such as Power Exchange that would allow futures and spot trading. • Regional Electricity Market encompassing electricity trade with neighboring countries.

As per the National Tariff Policy, new projects to be undertaken by the CPSUs/state generating companies during the next five years need not undergo the process of competitive bidding. Tariffs for such projects would be determined by the CERC/SERCs under the prevailing rate of return framework. This offers a window of opportunity for foreign investors as minority stakeholders in such projects. A number of crucial policy initiatives have been put in place to create an enabling environment for private participation. The immediate concern for the Indian power sector is to improve the performance of distribution utilities as this influences payment security for private investors in generation and transmission projects. The development of a power market would also help improve investment climate by providing efficient signals for investment and would offer an alternative market in case of payment problem with the state utilities. Although policy reforms and growth prospects were able to generate interest from private investors in the power sector in the 1990s, bureaucratic delays often frustrated investors’ efforts and many project proposals fell through. In spite of such hiccups, private investors have acquired a stake in the growth of the Indian power sector. The following section reviews the state of private and foreign investment in the sector.

7.7 Status of Private and Foreign Investment in Power Sector 7.7.1 Private Investment in power sector The economic crisis facing the country in the early 1990s opened up opportunities for private, including foreign investment, in the Indian power sector. The Private Power Policy 1991 opened up the path to private and foreign investment in the generation and distribution of electricity. Private investors were offered a 16% return on equity, which was further incentivised in the case of higher efficiency levels in terms of plant load factor (PLF). The policy framework for private investment was further strengthened through the introduction of the Mega Power Policy in 1995 for thermal projects over 1000 MW and hydro projects over 500 MW. This was revised in 1998 and a number of fiscal incentives were added for large power projects. Initially, these initiatives generated overwhelming initial interest from local as well as international private investors. However, the insolvency of the sole buyer, the SEBs, and delay in project development frustrated the efforts of private investors. Clearly the investors were not finding the assured 16% return on equity to be commensurate with the risk of investing in the sector at that time. They sought the comfort of sovereign guarantees, which were limited to eight fast track projects, a misnomer. Enron’s Dhabol power plant, which was one amongst them, has been riddled with controversies since it was first agreed upon. The controversial PPA, which was lopsided in the favour of project developers, was

51

renegotiated amidst a political drama. It later fell into serious trouble when the parent company Enron faced trouble back home. The controversy has recently been settled after the foreign investors’ stake was purchased by a SPV created by state-owned companies. Growth in the power sector since independence has been primarily accompanied by public investment through economic planning. As a result of this, most of assets in the electricity sectors are owned by government-owned companies or the SEBs. The erstwhile SEBs own about 55% of the generating capacity followed by the central sector generating companies, which are owned by the central government. Since the policy liberalization in 1991, around 8,500 MW of conventional capacity and around 9,000 MW of renewable capacity have been added by private sector by March 2008. Most of the distribution network is owned by the state utilities. A few urban areas, some of which have been licensed to private companies for nearly a century, and the distribution companies in Orissa and Delhi, are under majority private ownership. The transmission segment is dominated by public ownership with the exception of the upcoming publicprivate joint venture for importing electricity from the Tala hydroelectric project in Bhutan. Given the limited fiscal space for increasing investment by the central as well as state governments, and requirements for future investment, there is a greater scope for private participation in the sector. The geographical distribution of private power projects in the country reveals a preference for the southern and western regions of the country. Table 7.5: Privately Owned Generation Capacity and its Share as in March 2008 Regions

Total Capacity (MW)

Private Capacity (MW)

Percentage Share

Northern

38,210

1,494

4%

Western

43,305

7,975

18%

Southern

39,344

9,125

23%

Eastern

19,784

1,445

7%

North-Eastern

2,340

24

1%

142,983

20,063

14%

All India

The relative dominance of states in the southern and western regions could be explained as follows. In terms of financial and operational performance, and reform parameters, the power sectors in the states of Andhra Pradesh Gujarat and Karnataka have been rated amongst the best in recent years. In terms of overall investment attractiveness, the states of Maharashtra, Andhra Pradesh, Karnataka, Tamil Nadu and Gujarat have been rated the top five destinations by foreign investors. Table 7.6: Top Five Rated State Utilities Rank

2003

2004

2005

2006

1 2 3 4

Andhra Pradesh Karnataka Haryana Rajasthan

Delhi Andhra Pradesh Goa Karnataka

Andhra Pradesh Gujarat Delhi Karnataka

Andhra Pradesh Gujarat Delhi Karnataka

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Rank

2003

2004

2005

2006

5 6 7 8 9 10

Maharashtra Delhi Gujarat Himachal Pradesh Tamil Nadu Punjab

Gujarat Haryana Punjab Himachal Pradesh Uttar Pradesh Rajasthan

Tamil Nadu Goa Himachal Pradesh West Bengal Uttar Pradesh Chattisgarh

West Bengal Goa Himachal Pradesh Himachal Pradesh Maharashtra Kerala

The investors perceive relatively higher risk for investment in the distribution segment, which is characterized by inefficiency and is exposed to regulatory risk. The limited experience of distribution privatization in Orissa and then in Delhi also fails to present encouraging results. Distribution, being a state issue, is highly influenced by local political dynamics. Since privatization would suggest an increase in tariffs and less space for inefficiency, there is resistance from within these organizations. Due to the poor financial status of most of the state utilities, the privatization of distribution requires support by the respective state government. In the case of privatization of distribution companies (Discoms) in Delhi, the state government committed substantial financial support to the private investors over a period of five years against benchmarks for efficiency improvement, in terms of the reduction of Aggregate Technical and Commercial (AT&C) losses. Improving the financial and technical performance of the state utilities would be an effective alternative to this financial dole. More recently, a number of state distribution companies have shown signs of turnaround, as seen through improvements in various financial and technical benchmarks. This is a positive sign for prospective investors in greenfield generation assets and for future privatization of these Discoms.

7.7.2 Foreign Investment in power sector Liberalization of the Indian economy in the early 1990s was aimed at attracting private domestic as well as foreign investment. The policy framework for FDI in the power sector is designed to offer unhindered flow of capital from outside the country. It provides for 100% FDI in the power sector through an automatic route. For the period 2000 to 2005, the actual FDI in the power sector amounts to USD 1.1 billion whereas the approvals were a staggering USD 12.9 billion. This provides a lot of insight into the agony of foreign investors, whose efforts were frustrated during the process of project development. Over the last few years, the emerging growth theory has led to significant investment in the Indian stock markets. Some of the listed power sector companies have witnessed significant interest from the Foreign Institutional Investors (FIIs). This speaks only about the private and the professionally managed companies owned by the central government. The NTPC earns returns in a regulated environment and is exposed to a very limited payment risk since the tripartite agreement on SEB dues was concluded. The BHEL’s attractiveness is attributed to the fact it has easy access to a relatively protected and growing market. It continues to enjoy a preference in the equipment procurement by the CPSUs. Although this kind of portfolio investments reflect positive sentiments toward the sector but these are not a sustainable means for attracting financing to the sector. Such investments are also subject to volatility and do not significantly assist in sustainable asset addition in the sector.

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While the sustainability of large public investment in the sector is desirable, there is growing need for investment in other social sectors like health, primary education etc. Apart from this, the concerns for management of government finances leave much to be desired from the private sector. In order to meet the long-term growth requirements of the sector, the sustainability of private and foreign investment is also desirable. This, however, is influenced by a number of factors—policy and regulatory environment, legal framework, and financial attractiveness.

7.8 Issues and Concerns The public sector has been the main provider of power sector infrastructure in India. Given the exponential growth in investment requirement the public financing will not alone be able to generate the needed levels of investments. The government strategy for bridging the deficit has to include: Revising policies and regulations in the power sector for enhancing private sector participation through public-private partnerships (PPPs) Enabling arrangements for long-term funds through all possible sources Strengthening the capacity at all levels for promoting PPPs for power sector development The major issues and concerns hampering the desired growth in the power sector are as under: Projects delayed due to inability to achieve financial closure: Due the Tenth Plan period, projects totaling around 5,300 MW could not take off due to a lack of payment security as a result of which funds could not be tied up. IPPs have been attempting to achieve financial closure for their generation projects plans, but continuing doubts about the financial viability ensures that due diligence and related activity drags on. Concerns about inadequacy of funding for the Eleventh Plan: As mentioned earlier, the fund requirement of the power sector has been estimated to be around USD 200 billion to achieve ambitious targets across the entire value chain. In light of this, availability of funds may be an issue in case all the projects fructify, contrary to past experience, and go to the market for funds at the same time. The existing lenders, particularly banks and FIs, would be unable to fund such massive requirement as they are constrained by prudential and sectoral limits. In addition, the non-availability of longterm sources of funds would hinder lenders to take long exposure as per requirements of the projects. Sector experts suggest that to overcome these difficulties, the debt market needs to develop and long-term pension and insurance funds need to be channelised. Further, the proposal to use a part of the country’s foreign exchange reserves through a SPV floated by IIFCL could also become an important source of funding in the future. The Working Group on Power for the Eleventh Plan has suggested modifications in the ECB guidelines to allow PFC, REC and IDFC to borrow funds from the overseas market under the automatic approval route and exempting debt servicing from income tax. Lenders continue to insist on various clearances and contracts to be in place before committing funds: Lenders are still looking at the strength of the contracts, like PPAs, FSAs, and EPC contracts. Multiple PPAs are highly favoured by banks, especially if they involve credible buyers. These doubts arise mainly on account of continuing concerns over the credit quality of the customers (state utilities), bureaucratic hurdles

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and costs involved in obtaining clearances from the authorities as also in negotiating project contracts with them. As for the FSAs, lenders look at the cost of the fuel, its availability, whether its supply is assured over a period of time and the price volatility associated with the fuel. They are also concerned whether there is an agreement in place with the Indian Railways or ports, depending on the project requirement, to transport fuel. Depending on the fuel type, lenders also examine the environmental impact and want to make sure that all necessary environmental clearances have been obtained. In the case of hydro projects, rehabilitation and resettlement plans are also examined. As for the EPC contract, the cost of the contract, the strength and reputation of the EPC contractor as well as the technology being used are important considerations. Lenders are now looking beyond just the existence of the contracts, particularly with respect to EPC contracts. One of the concerns is that there are a few good construction companies, most of which are over booked for next 3-4 years. Lenders are now analyzing the previous record of these EPC companies for adherence to delivery schedules to assess if equipment delivery and construction would take place on time. Market imbalances remain to be addressed: An area of concern is the gap between financial closure and commencement of construction. This translates into a gap of around 6-18 months between sanctions and disbursement. Lenders are generally not comfortable with this as they commit sanctions at certain rates and have to hold on to funds and the rates till the time of disbursement. Also, sector experts indicate that interest rates for power projects are not based on logical risk-return maturity pricing and are generally independent of tenures. This is because too many lenders are chasing too few good projects.

7.9 Enabling environment for the private sector In order to facilitate greater private sector participation in power sector projects, the GoI needs to concern themselves with the following issues: Transparency of process: Private sector investment opportunities are conditioned on the existence of specific government policies and programs that encourage private sector entry and a transparent system of evaluating bids and awarding contracts. Competitiveness of bids: Transparency and public accountability are best achieved by using a competitive bidding process to select contractors for infrastructure projects. Appropriate allocation of risk: Risk sharing among the government, utility, lenders, and developers is at the heart of most reservations or debate about private sector BOT/BOO (build-operate-transfer/build-own-operate) projects. Developer returns commensurate with risks: Quantifying the risk inherent in—and, by extension, acceptable equity return on—large power sector projects is difficult but essential. Stable policy regime: Private investors in power sector, whether they are domestic or foreign, seek a policy regime (including such elements as the tax and investment frameworks) that is both stable and predictable. Government guarantees and credit enhancements. Bilateral and multilateral guarantees and credit enhancements are often critical to the successful financing of power projects in India (including, among others, independent power provider) projects,

55

particularly during their early years and the transition from state dominance to a more market-oriented economic system.

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8 Risks associated with Indian Power Sector Historically, since its commencement of economic liberalization in 1991, India’s increasingly insatiable power needs, along with its general trend toward economic liberalization, led to much interest among foreign investors in establishing IPP projects in India. While dozens of projects were approved, and the foreign and Indian private sectors constructed several such power plants between 1992 through 2004, most of the largest projects have been stalled by considerable payment risk issues. A number of factors in the power sector hampered IPPs from attaining financial closure. These factors include, but are not limited to, the following: Lack of credit worthiness of the SEBs Substantial cross-subsidies and politicized tariff setting Inadequate off-take and payment guarantee mechanisms Inadequate fuel supply and transportation agreements, with the significant issues involving how to cover risks between the SEBs, Coal /Gas supply

8.1 Project Evaluation and Risks A credit analysis on the sponsors is conducted for every project before finances can be arranged. These reviews are often conducted according to a process that differs from one bank to another, but certain fundamentals are constant. Typically, a separate credit department that uses a rigorous set of criteria to determine the creditworthiness of the project, the sponsor, and the off taker performs the analysis. Power has always been used as a Political handle in the country due to its widespread economic implications both for the industrial as well as the agricultural sector. Thus the major risks in the Indian Power Sector would be country, political and economic risks, lending risks and project risks. Also an analysis is warranted for company management. The following risks are typical of the Indian scenario: Permitting risk and Political opposition to the project Inability to obtain a financeable power purchase agreement, either because the power price is too low or the terms are not acceptable Regulatory disapprovals and Change in law Following is a comprehensive list of all the risks involved in project finance for power sector in India: Industry

Table 8.1: Risks involved in project finance for power sector Industry cycle Industry prospects over the life of the loan

Market and service area

Customer mix and growth prospects Credit quality of major industrial customers Economics of conservation and DSM

Competitive position

Market Share Alternatives offered to consumers Variable and total cost of production Extent of large customers

57

Fuel and power supply

Adequate Availability Fuel costs and contracts

Operations

Percentage of Off takers Locked in Dealing with which SEB Transmission and Evacuation Facilities Back to Back Overrun Penalty Contracts

Asset concentration

Major assets as % of net plant & common equity Operating independence of major facility

Regulation

Support for reasonable cash return Quickness of decisions & Adjustment mechanism Creative ratemaking in competitive markets

Management/Promoter Company Evaluation

Company financial performance & credit standing Company experience and sustainability to see project through completion Understanding of the Infrastructure Project space and a long term commitment to Infrastructure Development Sufficient capital to sustain: operating losses, shortfall in liquidity and shortfall in receivables Business plan, source of repayments and dependence on one consumer

Repayment Risk Mitigant

Letter of Credit Prime Distribution Area Escrow Account

Financials

Debt Equity Ratio DSCR Debt Service Reserve Fund Upfront Promoter Equity Contribution Pass through Fuel Price Risk Pass through Foreign Exchange Risk

Tariff

Competitive Tariffs

8.2 Risk Mitigating Mechanism To reduce the exposure to the financially weak SEBs and their business risk, the mechanism relies on the IPP to establish multiple layers of security from the SEB and the state government to support its power purchase agreement (PPA). Irrevocable Letter of Credit by the SEB in favor of the IPP A designated prime area escrow account SEB reforms PTC Power Purchases State Govt. guarantee if applicable Irrevocable Letter of Credit (LOC): In a typical “PPA”, the generating company submits an invoice within an agreed timeframe. The invoice is generally payable through an irrevocable revolving letter of credit (“LOC”), issued by the concerned SEB through its banks. However, in case of a default, the bank may simply refuse to renew the LOC, and the generating company may end up facing the same risk.

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The irrevocable letter of credit is an instrument issued by a bank guaranteeing payments on behalf of its customer (the SEB) to a beneficiary (IPP) for a stated period of time and when certain conditions are met. Although IPP developers would like to have long-term LCs, banks have been reluctant to offer these and LCs would most likely be one-year and irrevocable. The SEB would be required to open a LC for a value equal to three months average IPP billing. The payment made under these LCs would be immediate if the SEB failed to make a payment to the IPP for any reason. The bank would either issue the LC under the working capital limits already approved for the SEB or it would issue a new credit for this specific LC. Upon a draw under the LC, the SEB would be required to reimburse the bank within three days. In the event that the SEB does not reimburse the bank, the bank can refuse to revalidate the LC. Escrow Account: An escrow arrangement is another mechanism to protect against the SEB credit risk. It is usually a complex arrangement, whereby an escrow agent is appointed for the specific project. The escrow agent establishes escrow accounts, an SEB account and a generating company account. Such agent also creates a charge and hypothecation over the SEB receivables. In the event of a default in payment, the escrow agent transfers an equal amount of receivables from the SEB escrow account to the generating company’s account. It is advisable to retain some amount as security in the escrow account in order to provide effective security to the generating company. The escrow account would be an account opened by the SEB for the benefit of the IPP. The escrow account would be administered by an independent escrow agent (normally a bank). A three-party agreement would be entered into among the IPP, the SEB, and the escrow agent, who would act as an agent of the IPP. The cash flows (receivables) of the SEB from selected customers would be deposited directly into the escrow account instead of being paid to the SEB. If no event of default has occurred and there are no outstanding draws under the LC, the agent bank will transfer the funds from the escrow account to the SEB, and the SEB will meet its IPP and other payment obligations. In the event of default, the flow of funds from the escrow account to the SEB would be stopped and the escrow agent would make payments from the escrow account directly to the IPP. However, there are a number of difficulties involved in the escrow account security mechanism. One such problem is the simple failure of an SEB to fund the escrow account. In such case, a hypothecation agreement can be protective, as it would shift payments of power purchasers from the SEBs directly to the electricity generator. SEB Reforms: In the long run, reforms must concentrate on how the SEBs may collect more revenues through more efficient collection mechanisms, power theft control and market-linked tariff regimes, as well as through the privatization of the electricity distribution sector. Few SEBs of states, such as Orissa, Delhi, Haryana, Karnataka and Andhra Pradesh, already have taken positive steps towards (i) unbundling power generation, transmission and distribution assets into new entries and (ii) corporatizing those entities with leadership less subject to political whims. Distribution of electricity in the states of Orissa and Delhi has been privatized. PTC Power Purchases: Innovative structures, wherein agencies such as the Government of India-owned Power Trading Corporation (“PTC”) are intermediate buyers of power, and effective offtake risk

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mitigation measures, also have enhanced the potential of new projects to achieve financial closure and better ensure success. Many of these projects simply would not have reached financial closure and achieved commercial operation within a single buyer model. Recently, the PTC has short-listed 35 power projects (with generation capacity exceeding 23OOMW) for long term power purchases. The PTC also will acquire up to 15% equity in each such project. In a milestone in the evolution of India’s power sector, the Hyderabad-based Lanco Group’s 300 MW thermal power project in the State of Chhattisgarh became the first power company to achieve financial closure on the strength of a PPA with the PTC. To date, all Indian private sector projects have secured financing from banks and financial institutions on the basis of executing sophisticated PPAs with SEBs. The debt-equity ratio for the Lanco project is 70:30. The process of achieving Lanco’s financial closure accelerated the creation of an inter-institutional group (IIG) of lenders. The IIG consists of the IDBI Ltd, State Bank of India, ICICI Bank and Power Finance Corporation. Over a dozen projects have achieved financial closure in India, since the IIG was established in January 2004. Similarly, at least another dozen projects await the commitment of similar funds. Many of these projects, financially closing on “all – India finance” (i.e., no foreign lenders) basis, have reached such closings, only because project sponsors, unlike previously, have agreed to accept fuel and other project risks. Guarantees: In the event that the escrow proved inadequate, the IPP could have further recourse to the state government through the state's guarantee of SEB performance. Numerous variations on the LC, escrow account, and state guarantees would be possible to structure and implement.

8.3 Impact of the Global Slowdown The Indian power sector has also been hit by the current financial crunch, with several projects unable to achieve financial closure. The banking sources after the financial meltdown, no longer have the risk appetite to fund projects, especially those planned on a non-recourse basis, which are devoid of the parent’s balance sheet support. The current financial crisis will hamper power companies’ ability, more so for the private sector, to raise debt funds from banks, domestic and international, thereby delaying financial closures of projects. External commercial borrowings, which are used by the corporate sector, have dried up, as have international supplier’s credits. The latter includes vendor credit raised by the equipment supplier that will supply equipment to the power companies. As a result, the banks will not lend to companies that planned on vendor credit. And even for companies that have not planned for such credit, raising capital is going to be difficult under the current scenario. As a matter of course, the sources of financing for the capital required by the power sector projects are predominantly multilateral institutions, domestic banks and financial institutions, and foreign commercial borrowings. The financial crisis currently afflicting the world has chipped away at the global financial market as a source for the much needed funds. It is difficult for power projects, at this moment, to obtain resources from external sources, even though the Reserve Bank of India had relaxed the guidelines for external commercial borrowings in October 2008. The power sector, therefore, is being forced to increasingly rely on domestic sources and multilateral financial institutions. Accordingly, an appropriate measure to improve the availability of funds for the power

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sector in order to ensure that the capacity addition targets are met is the need of the hour. In a bid to overcome the liquidity crunch, caused by the global financial crisis, that has affected the financing of domestic power sector projects, NTPC has urged the Government of India to induce multilateral institutions, such as the Asian Development Bank (ADB) and World Bank, to enhance their earmark of funds for the power sector in India, especially through non-sovereign lending operations. Ensuring a stable source for funds is especially important given the fact that a growth rate of 9.5% for the power sector is envisaged during the XI plan. NTPC has also sought a greater role for instruments that leverage risk through the participation of commercial banks. This would include facilities such as ADB's 'A loan' and 'B loan' provisions. This is essential if the capacity addition target for the XI plan is to be met. In order to ensure that growth is not hampered due to want of funds, the power ministry has asked the Ministry of Finance to consider a hike in the limits prescribed by the Reserve Bank of India (RBI) for domestic banks that wish to invest in power projects. Currently, RBI prudential norms limit investments to 20% of the Tier I and Tier II capital for individual borrowers. For the entire group, a total of 50% of capital can be invested. In addition, banks are also required to fix sector-based limits for investments, derived from performance of the various sectors and risk perception. The Ministry of Power has declared that there is a strong case for enhancing such confines imposed upon the banking sector in order to increase the funds available to the power sector. It has, thus, appealed to the fiscal authorities to consult with the Reserve Bank and create an enabling framework to enhance investment ceilings, so that the relevant banks can take investment decisions based on credit quality of the venture and their own credit appetite. NTPC has also requested the Government of India to revisit the IRDA guidelines stipulated for indemnity pool fund investments to increase the amount of capital available to the crucial power sector of the country. Pertinently, a growth rate of 9.5% for the sector is envisaged during the XIth plan period. This goal is being hampered by the liquidity crunch in the domestic economy, caused by the global financial crisis. Access to financial resources is important if the power sector is to contribute meaningfully to the growth of the Indian economy. Interestingly, the transmission sector is the only silver lining, as despite all odds, the central transmission utility, Power Grid Corporation, has achieved an inter-regional transmission capacity of almost 19,000 mw against the proposed 37,000 mw by end of 11th Plan. Power Grid Corporation's investment plan of Rs 55,000 crore for the entire period has not been affected. In fact, the World Bank and Asian Development Bank are eager to provide additional funding in addition to whatever has been released.

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9 Conclusions and Recommendations It is necessary to appreciate that inspite of all the encouragement and reforms; the power sector is still riddled with many gross uncertainties. Emerging economies such as India has therefore much to do and learn about the execution of the reform processes. The reforms process should be carried out in gradual steps and the sector should not be left to market forces from the very outset. Financing of the power sector will involve a thorough analysis of the risks involved and the following observations can be used for arriving on financing and investment decisions by lenders and private investors respectively.

9.1 Generation Power generation is the only sector wherein the lenders insist for long term selling arrangement, whereas in other capital intensive industry like mining, petroleum, etc. there is no such expectation from the lenders. Financial closure is achieved with certain tariff regulations and any change during implementation affects investors confidence and risk perception of the project. Though the private sector has shown some interest in capacity addition, however, still major part of the capacity addition, has to come from central & state power utilities. Since neither central nor state governments are able to provide budgetary support, all future capacities in the government sector will have to be funded by the utilities out of their internal resources. Utilities can generate the resources only through the tariff allowed. Therefore, tariff norms must consider requirement of resources to be generated in the sector. The regulatory certainty for longer periods could attract investments. The primary off takers of power i.e. the SEBs need to reform even if the process at hand seems long and politically fragile. The repayment risk from the weak financial standing of the SEBs should be addressed with innovative payment security mechanisms. There is still lack of alternatives in case the primary customer defaults. Development of power markets would mitigate the risks. Adequate rate of return considering the market expectation, risk perception and need to attract substantial investment in the power generation. The major road block in financial closures is the lack of confidence in the power market structure and power utilities and payment security mechanism for recovery from the purchasers. Proactive support to merchant power capacity addition through facilitatory measures such as timely fuel allocation and other clearance requirements The perennial problem of lack of transmission infrastructure unless addressed at war footing, will not allow generation to achieve cost efficiency.

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9.2 Transmission With an increased awareness of transmission being the bottleneck in Indian power scenario, a much more concerted effort on part of the governments, PGCIL and private players is the need of the hour. The growth in the sector has been slow to begin with, with only few private projects taking off. The investor apprehension is due to the virgin territory of investments. The lender needs to get more involved in the strategic thought process of the borrowers to gauge the risks involved. The government on its part should identify and facilitate clearances incase of projects for private sector participation. Appropriate transmission pricing regime that provides right locational signals can attract substantial investment in the power transmission. Accountability needs to be fixed by Regulators to provide assurance about timely processing of applications. Augmentation of transmission capacity in line with generation capacity to ensure a de-bottlenecked transmission system. Transmission pricing and Wheeling Charges (including losses) need to be addressed on commercial principles. RoE for the sector should be based on the principles of sustainability and future growth outlook through adequate public/private investments The outlook is optimistic as the sector will involve huge investments in the future.

9.3 Distribution Total revenue in the power sector (including the revenue for generators, fuel suppliers, transmission, and distribution) has to come from the consumers, channelised through Distribution/Supply Licensee and open access to the consumers. Therefore, interface with consumers needs highest attention. Preparation of Road Map for reduction of losses and cross subsidies through efficiency improvements by way of privatization Success and Strength of Distribution is the key for catalyzing investment in power sector. Power Distribution and Supply business need to be streamlined and strengthened for catalyzing investment. Separation of Distribution and Supply business If power supply is to be subsidized, it should be done by the government and not at the cost of others through cross subsidy. Create awareness among Distribution Utilities; provide them appropriate Govt./ Regulatory flexibility and support The Electricity Act, 2003 aims to bring in more competition in the power sector in India to increase the efficiency of the system in general and the State Electricity Boards in particular. Yet thus far, the pace and implementation of reform has not proved

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successful in raising tariffs to cover costs, and although some states have made progress, work must still be done to improve abysmal bill collection rates. The renegotiation and cancellation of PPAs in India reflected these failures of reform by forcing heavily burdened SEBs and regulators to squeeze private investors when facing a budgetary impasse, which was aggravated by political transitions. But unless the next few years continue corporatizations and subsequent privatizations of the SEBs, the good intentions may never materialize. However, with the retreat of global energy investors and contractors, well established domestic electricity and infrastructure companies such as Tata and Reliance have partially filled the gap and may continue to hold the competitive advantage The Ministry of Power needs to accelerate the development of the National Grid because the lack of Transmission capacity is harming the cost effectiveness of delivered power. As for financing the sector, the Inter-Institutional Group needs to start working on the Public Private Participation model wherein the Private entrepreneurial skills are actively supported by public funds not just in the form of debt financing but also equity participation. Direct incentives should also be provided to the Independent Power Producers in terms of lowering of Customs and Excise duties on project imports for IPPs. To improve the inherent financial viability of the sector the government needs to introduce multi-year tariff regime to improve predictability of investment outcome and also eliminate cross subsidies that hamper rationalization of tariffs.

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10 References/Bibliography Literature References Central Electricity Authority (CEA) Power Finance Corporation (PFC) Central Electricity Regulatory Commission (CERC) Ministry of Power (MoP) Power Finance Corporation (PFC) Power Grid Corporation of India (PGCIL)

Weblinks Ministry of Power, Govt. of India (powermin.nic.in) Central Electricity Authority (www.cea.nic.in) Central Electricity Regulatory Commission (cercind.gov.in) Infraline (www.infraline.com) Crisinfac (www.crisinfac.com) The Associated Chambers of Commerce and Industry in India (www.assocham.org) Confederation of Indian Industries (www.ciionline.org) IDFC (www.idfc.com) IDBI (www.idbi.com) SBI (www.statebankofindia.com) Power Finance Corporation (www.pfcindia.com)

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