Options Assessment for Structuring and Financing new Hydropower in PNG

Options Assessment for Structuring and Financing new Hydropower in PNG Issues and Options Report - Revised Judith Plummer November 2011

CONTENTS Summary...3 1 Introduction...4 Purpose of this Paper...4 Background...4 Public versus Private...4 2 Lessons from international experience...5 General...5 Single off-taker with some domestic use and a negotiated concession...6 Merchant Project without a long term power purchase agreement...7 Project with a split ownership...7 Projects let by competitive bidding...7 3 Risks...10 Types of Risk...10 Structuring the project...12 Legal framework and regulatory regime...12 Environmental and social permitting...13 Issues of land ownership...13 Credit worthiness...13 Public versus private development...13 4 Financing...15 Sources of finance...15 Financing plan...16 Illustration of Impact of Debt Tenor on Tariff...16 5 Structure of transaction and impacts for Government...18 Economic and financial benefits accruing to Government...18 Format of concession...19 Forming a transaction...20 6 Next Steps...23

Summary Hydropower provides a clean renewable source of energy when developed and managed responsibly. However, such projects are inherently risky because of their location, size, and nature. It is possible for Governments to off-load some of this risk to the private sector, but only at a cost (risk premium). Thus the question of financing and development of hydropower is always a matter of balancing both risk and cost. Hydropower projects can last for many decades and, after the initial debt financing has been repaid, can provide a source of electricity which is cheaper than most other options. The long term nature of the projects, together with the public nature of the resources involved has often caused Governments to feel that such projects should be developed in the public sector. However, hydropower projects have, in the past, had a reputation internationally for delays, cost overruns and poor management; particularly those developed in the public sector. One response to the difficulties encountered by public sector hydro has been to allow private sector development. While this can lead to improved efficiency, majority privately financed and developed hydro projects may have high tariffs in the early years after commissioning given the requirement to service the full cost of the debt incurred in construction over a short tenor. These tariffs are likely to be higher than the equivalent public sector project which may be eligible for lower cost, longer tenor debt finance or guarantees. Depending on the incentives in the off-take agreement, private sector projects may not necessarily be operated in such a way as to ensure maximisation of the economic gain for the country. To gain the benefits of all the options it may be possible to create a public private partnership to develop a project. The challenge is to structure the project to obtain the financing required to meet the tariff profile objective. In all cases the model needs to be commercially viable and sustainable, but precisely which model is appropriate depends on the intent of the project, broadly projects may fall into one or a combination of the following categories: - Where the project is built mainly to serve a single commercial, export or industrial off-taker it may be appropriate to develop it in the private sector with an emphasis on safe and sustainable development with maximization of the financial and economic gains for the country. Where the project is developed mainly for domestic use, it may be largely publicly developed using a form of public private partnership which is likely to maximise the benefit of available (development) finance options and minimise any adverse tariff impacts in the early years particularly for poorer consumers. Where the project is for mixed domestic and industrial use then a private public partnership may again be appropriate, but may be more complex to structure with emphasis both on maximizing financial and economic gains to the government from the project while providing quality commercial power supplies and also minimising any adverse domestic tariff impacts in the early years. Any combination of these models may be appropriate depending on the specific circumstances of the project concerned. Development of a hydropower project requires strong and experienced leadership. These skills can be hired in on a contract basis, but are likely to be more effective if they are exercised through a private investor. The likelihood of attracting such a private investor depends on the risk profile of the project. Careful attention to the management, mitigation and allocation of responsibility for various risks can do much to improve the attractiveness of a project for finance. Government needs to consider its preferred options in terms of project structure and risk allocation, based on extensive financial and economic modelling. It should be noted however, that the economic gains can be lost or reduced through delay in such decision making, so once information is available early decision making will be imperative.

1 Introduction Purpose of this Paper The objective of this issues summary paper, as specified in the terms of reference, is to set out a range of options for ownership, financing and arrangements for sharing the financial benefits for discussion with stakeholders in Papua New Guinea (PNG). The options analysis will explore private sector and public-private partnership models and compare these to a more public sector dominated approach. The paper begins by considering international examples of hydropower development with specific reference to finance considering the key issues of risk, financing and benefit sharing between Government and the developer. Finally the paper will suggest further steps, for discussion, that could be considered when setting out to pursue increased hydropower development. Background It is estimated that 12 % of PNG s population has access to electricity (According to the World Bank draft project appraisal document). The Government of PNG has set a target of achieving 70% access by 2030. To date, it has not been practical to establish a national power grid in PNG, due to the country s very rugged, mountainous terrain and capital constraints so the country has four separate main power grids, but large parts of the country remain un-electrified. Papua New Guinea s technically and economically feasible hydropower potential is estimated in excess of 4200 MW (36 800 GWh/year) of which less than 5% has been developed to date (www.small-hydro.com). The most significant growth in demand in the next few years is expected to be in Port Moresby, which is also an area where some plant is reaching the end of its life. As a result PNG Power Ltd. (PPL) is interested in pursuing the 80MW Naoro Brown Hydropower Project due to its proximity to Port Moresby. However, in addition, other projects which could serve demand in other parts of the country (both domestic and industrial) or serve new industries are also under consideration by both PPL and private developers. Public versus Private It is may be useful at this point to discuss the issue of public versus private. It is a popular misconception that there exists a hydropower project which is either totally private or totally public. Almost every project in the world requires the participation of both public and private sectors in some form. For example a privately funded and executed project must liaise with both central and local government on a range of issues of concern and legal necessities. It is very difficult for a private operator to implement a project without the support and cooperation of the public sector. Similarly a publicly funded and executed project will generally involve procurement and contracting or subcontracting to the private sector. Thus all projects are a combination of public and private aspects. However for the purposes of this report we will use the term Public for the project that is largely publicly developed and funded; the term private for a project which is largely privately developed and funded; and Public Private Partnership (PPP) for projects which involve both public and private finance. It should also be noted that projects may be publicly led (even though largely privately funded) or privately led (even though largely publicly funded). The leadership defines the control of the development rather than the funding. As will be shown in the sections which follow the level of private and public interest - as well as the lead role- can affect the financing and structure of the project.

2 Lessons from international experience General The concept of an independent power producer (IPP) became prevalent in the 1990s. Thermal power projects are routinely financed in this way, but using such a private development approach proved difficult for hydropower because of their particular characteristics of: - Capital intensive hydropower projects have high initial capital costs: higher than the equivalent thermal power station. As with any highly capital intensive infrastructure projects this can provide opportunities for corruption. Unrecognised (unremunerated) benefits hydropower projects may have additional benefits such as grid stabilisation, water storage, flood control, provision of access roads, and establishment of fish habitats or centres of tourism. While these may be significant benefits to the country the value of these benefits may not accrue to a private developer. Social and environmental safeguard issues - hydropower projects have historically become identified with poor standards of social and environmental implementation. While improvements have been made in these areas, contractors still have concerns over the risk of delays caused by protest by non-governmental or other interest groups. High front-end risk profile - hydropower projects are considered high risk (see further details in subsequent sections), but the risks are also frontloaded in a project, such that developers need a long period of operation (which tends to be low risk) to counter the high levels of risk encountered during construction. As a result private hydropower is still relatively rare, but in recent years private financing has shown interest in new generation projects in a range of countries, particularly where the power is to be used for industry or for export. The recent trend is for more forms of Public-Private Partnership where both sectors participate in the financing and ownership, as well as sharing the risks and rewards. Such arrangements are often the only solution when public funds are scarce and the private sector is unwilling to assume all of the cost and the risks. The reasons some governments choose to involve private sector is that they may bring good commercial practice to reduce construction and operation costs and, possibly, to ensure timely project delivery. The private sector may also have access to specific finance which may not be available to a public sector entity (see section on Financing) and which may be critical for financing the project if public resources are insufficient. The long concession periods noted above are possible given the long productive life of a hydropower project (often more than fifty years). However, it is difficult to find private finance which is of longer than about 12 year tenor (without use of guarantees or other credit enhancements). As a result the project struggles to cover its costs and repay its debts in the early years, but continues to yield revenues for many years. This profile of revenues is difficult for private operators to accommodate and most will require high tariffs in the early years to cover the cost of debt repayments. For this reason the Government returns from a project are sometimes built on a stepped basis to keep the Government returns low during the initial debt servicing phase and increase them later.

The additional benefits noted above, together with the traditional economic benefits of a large construction project and increased availability of productive power, can lead to significant economic benefits to a hydropower project well in excess of the financial benefits. However, even for a government agency these benefits are difficult to monetise and for a private operator they are impossible. Thus although the decision to develop a project should be based on the economic gain to the country; the decision as to whether finance will be available and whether the private sector will be willing to develop it, depend on the financial returns and the risk profile. This referred to as the gap between economic and financial viability and possibly the most significant problem in hydropower development, particularly if the project has more than one purpose (e.g. electricity and flood control). The economic costs and benefits particularly the secondary or less obvious costs and benefits are rarely well assessed. Most analysis is carried out on a project basis or from the developer s point of view and thus does not include such issues as the secondary benefits to the local economy or environmental losses which are key to Government decision making. Such is the comparative rarity and complexity of private or public/private hydropower developments; it is not possible to outline a typical project. Some recent projects have been financed on the basis of a single or majority industrial off-taker who guarantees to use most of the power produced. These projects may be similar whether the power is used for domestic industry, industrial production for export, or export of power. In Iceland, for example, they have imported consumers such as an international aluminium plant as it is difficult for the country to afford the cost of a dedicated cable to export their surplus power Europe. Most arrangements are still bespoke to the project concerned. However the following projects give an indication of a range of possibilities such as single off-taker projects, merchant projects and split ownership projects; together with some examples of the use of competitive bidding for private sponsor/developers: - Single off-taker with some domestic use and a negotiated concession Theun Hinboun Hydropower Lao PDR 120 MW Theun Hinboun was Lao PDR s first IPP concession. The project was let on a negotiated basis for an initial concession period of 30 years with an option for a ten year extension with the majority of electricity being evacuated to Thailand. Royalties are paid to the Ministry of Finance in the amount of 5% of all revenues for the duration of the project concession plus income tax at 15% subject to a five year tax holiday. Dividends (of some US$ 20 million) are also paid to the Lao PDR Government s state owned power company, in line with its 60% equity share (financed though and ADB loan). In addition the project was made responsible for US$ 2.6 million of costs associated with environmental mitigation. On termination of the concession the plant reverts to Lao Government ownership. Thus this is a private export project, but one which has benefited from a high level of public support from the outset. The originally planned 65/35 debt to equity ratio became 55/45 after the Asian currency crisis seriously disrupted financing during construction: further refinancing after several years of operation released the capital necessary for expansion as well as releasing capital for the shareholders. Nam Theun 2 Hydropower Lao PDR 1,070 MW Recently completed, Nam Theun 2, it is one of the largest private financing arrangements of any hydro project. The total cost of $1.45 billion was financed through a complex mix of commercial loans backed by guarantees, private equity, and aid. The project was financed on a 72/28 debt to equity ratio. The Lao Government holds 25 percent of the equity, for which funding was obtained from Multilateral Development Banks. Some US$500 million of debt was raised from international banks on the basis of guarantees from the World Bank and other multilateral development banks, and another US$500 million from Thai Banks based on the creditworthiness

of the Thai utility power as PPA off-taker. As with Theun Hinboun, the plant reverts to Government at the expiry of the concession. Nam Theun 2 was let through individual negotiation after an approach directly from prospective developers. US$30 million was paid as a concession payment to the government as consideration for the project land and the opportunity cost for loss of biodiversity. Royalties for the project are set on an increasing scale. From 5.2% for the first 15 years, increasing to 15% and then 30%; averaging 12% per annum for the life of the project. Income tax is also on an increasing scale from 5% to 30% following an initial 5 year tax holiday. Cumulative revenues to the government from are estimated to total US$ 2 billion over the concession period; more than 15 times the level necessary to service the debt used to finance the Lao government s shareholding. In addition Lao PDR will obtain an effective discount of 16.67% on the standard rate charged to Thailand for power off-take. Merchant Project without a long term power purchase agreement Allain-Duhangan Hydropower India 120 MW Allain Duhangan is a medium-sized private project (US$191million) developed by local and foreign sponsors on a merchant plant basis without a long-term power purchase agreement or any other form of public support, which is very unusual. However, the project sponsors did have industrial links which would allow them to sell some power direct to off-takers if they failed to find any other purchasers. The project was financed on a nominal debt/equity ratio of 65/35, with US$40 million of debt being provided by an IFC A Loan (denominated in Rupees) which allowed a further US$75 million to be raised from local banks. The project structure was made possible by the particular strength and features of the Indian power market and the pervading power shortages. Project with a split ownership San Roque Multipurpose Philippines 345 MW This US$1.19 billion multipurpose project failed to be financed in the public sector, and was then successfully implemented as Pubic-Private Partnership. It is one of the few examples of a Split ownership, where the project is geographically divided into public and private parts although both were implemented under a single contract by the private partner, which made construction coordination easier. The dam (US$610 million) was financed in the public sector using a bilateral soft loan (65 percent) and domestic funds. The power complex (US$580 million) was financed on a 75/25 debt to equity ratio, with 52 percent of the total cost derived from Export Credits. The rest of the debt came from Japanese Government loans and commercial banks. The utility payment obligations were backed by Sovereign Guarantees. Splitting the project also allowed the Government to operate the dam in line with the requirements of irrigation as well as power. Projects let by competitive bidding Nepal large hydropower development The Government of Nepal let three large projects as concessions though competitive bidding, which would partly provide power for export to India and partly provide domestic power. The project bids were variously judged on the percentage of power given free for domestic use and the percentage of royalties. All were BOOT projects, with the assets reverting to Government at the end of the concession period:- Royalties to Government Free domestic power Government Equity Upper Karnali 12% 27%

West Seti 2% first 15 years 10% thereafter 10% 15% Arun III 7.5% 21.9% In addition the bid for Arun III included an amount to compensate Government for the earlier work on the project that had been carried out in the public sector. The Government stood to benefit from, dividends, royalties, export tax, value added tax, corporation tax, free power and a range of economic benefits associated with employment and construction; in addition to receiving the assets at the end of the 30 year concession. Financial models were used to estimate the relative value of different levels of free equity or free power. In the case of West Seti these financial benefits were estimated at US$ 2 billion over the life of the project and economic benefits were estimated at an additional US$ 1.1 billion. However, despite being agreed in 2008, none of these projects have yet started construction owing to the difficult conditions in Nepal and perceived security issues. The concession for West Seti has been cancelled and the Government is now seeking concessional finance from China to develop this project. Uganda Bujagali hydropower project Uganda has an estimated power requirement of 380 MW at peak load (290MW base load) and its current power potential is only some 270 MW, as a result of which the country suffers regular power cuts. Facing this power deficit, the Government decided in 1994 to pursue an additional power project the Bujagali Hydropower Project. This was proposed as a privately developed project as Uganda had neither the financial capacity nor the latitude within its internationally financed development programmes to fund the power station as a public project. Following the failure, in 2002, of a negotiated concession with AES Inc, a major American power company which spent seven years endeavouring to develop the project, Government of Uganda decided to hold a competitive process to select a new developer. The World Bank/International Finance Corporation project appraisal document for the Bujagali project (April 2007) describes the following process for selection of the project sponsor (developer). In 2004, the Government established the Bujagali Project Steering Group to oversee and manage the project, in general, including the sponsor selection process. In addition to providing oversight, this multi-institutional Project Steering Group enhanced the accountability and transparency of the sponsor selection process. The following process for selection was to follow several phases in which sponsors were pre-qualified and then their comments were sought on the project documents. The RFP also stipulated that the Government would require the selected sponsor to undertake a transparent and competitive process for awarding the engineering, procurement and construction (EPC) contract for the project. The final RFP was issued to pre-qualified sponsors and the bid selected on the basis of price given: - The internal rate of return on the equity to be invested by the sponsor in the project, stated as a percentage and carried out to three decimal places; A cap on the Development Costs that the sponsor would be allowed to include in the tariff under the PPA; Sponsor acceptance of responsibility for the UETCL transmission line construction management; and The monthly operation and maintenance fee that the project company (to be formed by the selected sponsor) will earn under the PPA to the extent the plant s target availability is achieved.

Industrial Promotion Services (Kenya) (IPS(K)) (part of the Aga Khan Fund for Economic Development) was selected and invited for further negotiations and awarded the concession. They (with their partners Sithe Global Power LLC) formed a company, Bujagali Energy Limited (BEL), and signed the Power Purchase Agreement and Implementation Agreement on December 13, 2005. The process of selecting the sponsor took almost two years. Brazil - hydropower development The power sector in Brazil moved to a free market model in the 1990s including a move towards concessions awarded on a highest rent basis. Changes were made to this model in 2004 to encourage improved security of supply and facilitate more private investment. Hydro concessions were from then on to be auctioned on the basis of the lowest tariff offered. This auction system has now been used even for some very large (>3000MW) sites. This system is made possible in Brazil by the ability substantially to limit risk by: - pre-specifying projects in great detail; providing surety of payment and providing finance from the local development bank (BNES). While this has been successful for Brazil, there remain issues such as the question as to: - Whether the tariff should be capacity based and whether competition is ensured, particularly when one firm has the advantage of having carried out earlier studies. For other countries attempting a similar exercise; the large amount of equity required, the possibility of limited competition; the lack of finance and payment surety; and the possible sovereign risk makes this model very difficult to replicate. India hydropower concessions In India three models for the allocation of concessions are currently in practice:- Competitive bidding under which bids are assessed considering the extent of free power offered; the level of tariff; and the terminal value of the project (the value at transfer). This is somewhat similar to the method used in Nepal noted above Up front premium, under which bids are assessed considering the extent of free power offered and the level of up front payment offered for the award of the concession. Memorandum of understanding representing the terms of a bilateral agreement between the Government (state or central) and the developer. Originally the most frequently used model, but less common since the requirement for competitive bidding was introduced in the 2005 tariff policy (although hydropower projects were provided with an exemption from this policy).

3 Risks Types of Risk In the general parlance of hydropower projects, a risk is anything that can have a negative effect on the project outcome 1. Risks may be real or perceived; in other words, some risks depend on an individual s point of view, while others appear the same to all. An example of a real risk may be of an earthquake if the project lies in an earthquake prone zone. A perceived risk is more subjective; e.g., for an international financier, the political risk (risk of a project being affected by changes imposed by government) of a particular country may appear high, but for that country s government or that of its neighbour, the political risk may be acceptable. Risks are normally categorised as being Political risks (which may be mitigated by guarantee): Financial risks (which may be mitigated by insurance) or Project-related risks (technological, social or environmental, which are not generally insurable). A list of representative types of risk and the possible mitigation and management techniques for each is listed in Annex 1. This section highlights the key risks perceived by private investors: - Political risk - Adequacy of government and public sector agencies to respond in a timely manner in terms of issuance of licenses and approvals or other coordination with the project can be a matter of concern to private investors and cause project delays. Assigning responsibility for liaison with Government to a specific agency which is formally responsibly for coordinating with all the other agencies of Government on behalf of the project can minimise this risk. Hydrological risk is often left with the project company, but may be more effectively managed by the off-takers (who have alternative energy supplies with which to ameliorate the risk). Thus a tariff which is biased towards a capacity element and with only a small energy element, i.e. where the project company is effectively remunerated for the capacity available at the station rather than the actual energy generated. Payment Default. The payment obligations of the utility companies would need to be covered by a requirement to establish an Escrow account with a minimum holding. This could also be back-stopped by a government guarantee. Local Currency Devaluation. There may not be a sufficient financial market to provide for formal hedging so the risk may need to be born by the Project Company. Affordability of local domestic tariffs may be a problem in the initial period after commissioning when debt service is highest. The best option is to optimize the financing such that the grace period and tenor are maximised so that the early repayments are minimised. Alternatively, Government may wish to defer its dividends, royalties or taxes to keep the initial tariff lower. Other risks listed in annex 1 such as delay, cost over run, social and environmental objection and associated infrastructure risks can also cause very significant difficulties to a project. 1 Although in theory risks are issues for which it is possible to predict the probability of occurrence and uncertainties are issues for which the probability of occurrence is not known for the purposes of this report the general parlance of risk for all risks and uncertainties will be adopted

Whether a risk is real or perceived, they can all affect the likelihood of a project being financed or attracting private developers. The more risk a developer or financier feels that it is accepting, the higher the charge will be for accepting that risk. At the limit, when the risk profile is too high to be costed, the project may not attract any offers of finance. As noted above, hydropower projects are considered risky because they are capital intensive, environmentally and socially sensitive, and often built in challenging geographical conditions with limited infrastructure access (sometimes in countries without a strong track record of project implementation). As with other power projects, many hydro projects also suffer from weak financial viability due to low national electricity tariffs, poor collection efficiency and lack of a reliable regulatory framework. The attitude to risk of the various partners in a project will depend on their position and their perception of risk. Those providing debt are only interested in the security of their repayment and tend to be risk averse, whereas equity partners take a share in the profits and thus may be prepared to accept a little more risk in return for the prospect of higher returns. Equity Investors may also include the sponsors who actively manage the project and thus feel that they can manage and mitigate some of the risk. In some cases the view of risk is increased by the range of risks so where a developer might accept the political risk alone (e.g. for a thermal power plant) they may not accept the political risk when combined with the high perception of project risk (e.g. for a hydropower project). Although some of these risks are insurable, many others are not. Even the cost of insurance may vary according to which entity is taking the risk. When it comes to Public-Private Partnerships, careful thought has to be given to the allocation of risk between the public and private sectors to ensure that risk is handled in the most effective way possible and at least cost. It is usually recommended that risk is allocated to the parties most able to control the risk parameters. But if control (or mitigation) is not possible, then the risk must be born by one of the parties. There is often a tendency for the public sector to expect the private sector to take a larger share of the risk of the project than is feasible. The private sector will always seek a cost compensation for risk, so the more risk it has to bear, the higher its price. At a limit, if the risk is too high, the private sector will not participate. The cost of trying to off-load risk should be carefully considered; the public sector is often better off bearing a risk if it makes the project financeable. A well prepared analysis of financing options will include a risk analysis, which gives consideration of each risk; the degree to which it is capable of being mitigated, insured, or guaranteed; the likely effect on the financial viability and the financing of the project; and which party should bear the risk. Risks can be aggregated by a country s own portfolio of projects e.g., a country with a range of fuel options for power generation has effectively limited the effect of hydrological risk on its overall generation profile. Beyond aggregation, various types of risk mitigation instruments exist. These are variously referred to as guarantees or insurance, and often with a confusing mixture of definition of the terms. Broadly, a guarantee covers specific, mainly financial events, such as timely payment of debt service and has clear terms of default under which it is invoked. Insurance covers a wider range of events and has a time-limited process for claim against that event, which is subject to various exclusions. Credit Guarantees cover losses in the event of a debt service default regardless of whether the cause is a political or commercial risk. o Partial credit guarantee covers part of the debt service and are largely offered by international finance institutions such as a multilateral development bank. The purpose of such guarantees is to improve the terms (reduced interest and extended maturity) and increase the availability of debt finance to the borrower by sharing the risk between the guarantor and the lenders. o Full credit guarantee sometimes referred to as a wrap guarantee; covers the entire debt service in the event of default. This can be used, for example, to improve the credit risk rating of a bond issue. This type of guarantee is largely provided by private companies and is only available where the country s underlying risk rating is

substantially better than the project for which finance is being raised. The recent developments in the international financial markets have largely excluded this as an option to projects. o Export credit guarantee i.e., insurance; covers losses for lenders or exporters where the aspect of the project concerned is tied to export of goods or services. This is offered by export credit agencies (ECA) and supported by the country interested in promoting its exports. (ECAs may also effectively provide finance for exportrelated transactions) Political Risk Guarantees (or Partial Risk Guarantees) cover losses to commercial lenders caused by specific political events. Political Risk Insurance covers losses to equity investors for political events such as war, expropriation of assets, or lack of convertibility of currency. Structuring the project Before commencing on developing a project structure it is necessary to consider some framework issues related to the risk elements identified above, particularly: the legal and regulatory framework, the environmental and social issues and permits and the overall creditworthiness potential of the project. The following section will consider each of these issues in tern and then consider the alternative project structures. Legal framework and regulatory regime Key to the perception and management of risk are certain structural issues such as the legal framework, regulatory regimes, including the fiscal and other incentives (e.g. tax concessions) and access to arbitration. Regulatory risk or the risk of losses caused by adverse regulatory actions on such issues as tariffs, tax payments, or expatriating profits is often cited by the private sector as one of its most significant investment concerns. This perception of risk is heightened by the company s belief that this is an area in which they have no control over the outcome. In order to encourage private participation, governments need to put in place a sound and predictable regulatory framework. However, while this framework is being tried and tested, it may be necessary to define some aspects, such as the method of tariff calculation and fixation in the contract for an infrastructure project, and protect these aspects from future regulatory changes. To reduce the perception of regulatory risk, governments need to ensure that there is a clear and enforceable procedure for the regulatory process. This should include: A legal framework: o published policies and laws as well as procedures for their revision; o an independent regulator; and o a quick and effective dispute resolution system, such as an independent tribunal. A clear strategy: o an articulated government strategy for promotion of infrastructure development, including private participation; o in situations where incentives (e.g., tax holidays) are provided, these need to be transparent, easily accessible, and consistently applied; and o where possible, the administrative burden on the private sector (and opportunities for corruption) should be reduced by implementing initiatives such as single window clearance procedures. Transparent approach: o Public planning and procurement procedures need to be fair, transparent, and accountable.

While the reputation and consistency of the regulatory framework is being built, it may be possible to employ a partial risk guarantee, from a multilateral development bank (MDB), to reduce the regulatory risk. Environmental and social permitting As with all large infrastructure projects, environmental and social impacts need to be carefully handled or they can potentially be a source of substantial project delay and increased cost. The private sector will want to see that such issues have been clearly identified and plans put in place to agree them to the satisfaction of all parties, before committing themselves to a project. Environmental permitting and resettlement will remain essentially a sovereign issue and early actions may involve the Government in upfront cost. (These issues are not covered further here as they are not the focus of this paper but issues surrounding sustainable hydropower development are vital to successful and equitable project development.) Issues of land ownership In all hydropower projects, issues of land ownership and sharing of natural resources cause concern and often controversy. Countries such as Canada have spent years developing appropriate benefit sharing mechanisms for the traditional land owners. Packages of benefit sharing involve:- Financial compensation Land compensation Shares in the project company (giving an on-going share of profits) Payments for environmental services such as catchment protection Long term revenue sharing agreements Income generating schemes, The appropriate combination of such options can only be determined in a case by case basis but it is advantageous if there is an agreed Government policy on compensation. Schemes which give and ongoing small share in revenues for the expected project life (such as shares in the project, or catchment protection payments) are growing in popularity as they provide an interest in the project for subsequent generations of affected families. Credit worthiness An assessment of all the above issues (i.e., economic and financial analysis, assessment of environmental and social effects, risk and regulatory issues) will combine to give a picture of the creditworthiness of the project. Ultimately, it is this creditworthiness that will determine which players are interested in participating in the project and, in particular, whether the project proponent will be able to raise international or local private equity or debt or even parastatal equity or debt. Creditworthiness may be expressed as a credit rating, although this really only takes into account certain types of risk and financial returns. If the project is not deemed credit worthy, it may be necessary for the government to take action to support the project through a sovereign guarantee to underwrite the payment obligation of the power off-taker. If the sovereign guarantee is not considered acceptable, then a guarantee from a multilateral development bank (or other institution) may be required to enhance credibility. Public versus private development Once a project has been assessed as to its creditworthiness and risk, it is possible to begin to design a structure for it and assess the extent to which it is either a mainly private or mainly public project or a

public/private partnership. The degree to which the various risks can be mitigated will have a strong influence on the choice of project structure. If the risk is substantial and cannot be mitigated to any significant degree, then the project will be unlikely to attract private participation and will need to be developed in the public sector. However, even in a public sector project there may be opportunities for private participation in carefully structured areas where the risk is not transferred to the private player. The following diagram illustrates an overview of the decision-making process for assessing the appropriate project structure. Figure 1 Public or Private? (Head 2006)

4 Financing Sources of finance The range of financing options is wide and complex. There is a variety of sources and typical terms and conditions for potential sources of financing including for example developer equity, government equity, commercial lending, multilateral development banks, bilateral and export credit, off-taker financing, but these can broadly be summarised into the following key types:- Table 1 Types and source of finance Type of finance Source Interest Tenor notes Concessionary finance Grants or soft loans Usually from bilateral or multilateral development agencies; carbon credits Very Low Interest or administration fee Long term Public equity Public investment with the support of the government, sometimes indirectly funded from bilateral and multilateral development sources. Dividends Variable can start low and build Indefinite Could be structured such that it is marketable later if appropriate Public debt Project-specific loans from the government or from bilateral and multilateral development banks. Funds may be raised though public bonds. Interest rate set by Government Variable medium to long term - can include a grace period Could be structured such that it is marketable later if appropriate Export Credit Finance direct from the Export Credit Agencies. In proportion to equipment contracts., Medium to high interest Variable but generally short to medium term May depend on source of equipment/ contracting Private commercial debt Loans from private banks, and from the commercial arms of the multilateral development banks. (Possibly with surety from a Guarantee from a multilateral development banks.) High interest (Although may be moderated in presence of a guarantee) Short to medium term (although can be extended with guarantees) Possibly marketable (may include private bonds) Private equity Direct investments made by private Sponsors and other private investors, and the by the private arm of multilateral development banks. May also be subject to a guarantee. Dividends (high return expected for accepting risk) Depending on the length of the concession Possibly marketable Private and public equity and debt can come from either domestic or international markets.

Financing plan These financing options need to combined into a financing plan for the project which is put together well in advance of the planned construction scheduling. The instruments can be matched to different project structures from the private project (IPP), through various forms of public private partnership to the public project as shown in the diagram below:- Figure 2 Main financing instruments for different project structures (Head 2006) Illustration of Impact of Debt Tenor on Tariff As noted above, the tenor of finance can have a significant impact on the ultimate project tariff profile. Hydropower projects have a long operational life often in excess of 40 years and yet debt repayment periods may be as short as 12 years where no credit enhancement is available. Thus the cost profile (including debt repayment) may be significantly front-loaded. Unless the developer has any way to smooth this profile the tariff required of the project may be high in the initial years. Many of the public, concessionary or IFI backed forms of finance have longer tenors which can extend the average tenor of the overall financing package. The graphs shown overleaf give an indication of the cash flow and levelised tariff profile of otherwise identical projects financed using 10 or 20 year debt. As can be seen from the illustrative graphs, the actual tariff profile necessary to meet the projects cash flow requirements may differ significantly from the levelised tariff (discounted average), which is often used to compare projects. There may not be available local debt finance to provide cash flow finance with which to smooth this profile, or such debt may add significantly to the overall project cost.

Comparison of long run tariff profiles Project financed with debt on 10 year tenor 6.50 6.00 5.50 5.00 C/kWh 4.50 4.00 Project levelised tariff Current tariff level 3.50 3.00 Tariff required to meet project cash flow 2.50 2.00 1 6 11 16 21 26 31 Year Comparison of long run tariff profiles Project financed with debt on 20 year tenor 6.50 6.00 5.50 C/kWh 5.00 4.50 4.00 Project levelised tariff Current tariff level 3.50 3.00 Tariff required to meet project cash flow 2.50 2.00 1 6 11 16 21 26 31 Year Superimposing the two graphs demonstrates the difference between the two profiles and highlights the critical importance of debt tenor to hydropower project finance. The longer the debt tenor the closer the project cash flow will approach the levelised tariff levels. Given the political and social sensitivity of raising tariffs, the early years of the project may cause great difficulty for both Government and private developers. Above all, decisions should not be taken on the basis of levelised tariff unless this also reflects the actual tariff required with careful attention to the early years of project operation. Comparison of long run tariff profiles 10 vs. 20 year tenor debt in otherwise identical projects 6.50 6.00 10 year tenor 5.50 5.00 20 year tenor Project levelised tariff C/kWh 4.50 4.00 Current tariff level 3.50 3.00 Tariff required to meet project cash flow 2.50 2.00 1 6 11 16 21 26 31 Year

5 Structure of transaction and impacts for Government As has been seen in the previous sections, in considering the implications of risk allocation, financing structures and financial benefits-sharing arrangements for the different project and ownership structures it is necessary to look at the implications for (a) the cost of producing electricity; (b) end user tariff and thus (c) the overall finance-ability of the various options. The cost and tariff implications are project specific, but generally private finance tends to be more expensive and of shorter tenor than public finance leading to higher tariffs particularly in the early years after commissioning. In considering the financial issues of specific projects it is also necessary to consider the economic benefits, and the structure of the transaction which are discussed in the following paragraphs. Economic and financial benefits accruing to Government The sources of financial and economic gain to Government from a hydropower project come in a variety of forms. The extent to which each is relevant will depend on whether the project is for domestic, industrial or export use: - Upfront concession fee favoured by Governments as it gives immediate short term cash advantage and are retained in the event that the project fails to materialise. However developers can be discouraged by them as they require upfront cash and can be seen as Government lack of faith in the continuity of the project or the long term commitment of the developer. These amounts are recovered by the developer from later project revenues, thus decreasing the amounts available to Government later in the project. Royalties usually based on water usage or availability, such that the revenues to government are not affected by the vagaries of variations in production or operating cost. Dividends from the Government s equity stake in the project usually at the same rate of calculation as dividends paid on private equity, unless Government decides to waive its dividend in return for lower public sector off-take prices (e.g. for development or rural electrification). The use of such funds may depend on how the equity contribution was financed (e.g. dividends may be used to service a loan used to fund the equity) Taxation in line with corporate taxation guidelines. This can include sales tax as well as corporation and other employment taxes. Low cost electricity supplies the Government may trade some of its other benefits for a discount on the cost of electricity from the plant to promote development and rural electrification. However, the project will have a certain level of financial robustness such that in whatever form the financial benefits accrue to Government they will cumulate to the level that the project can bear and no higher. It is therefore not feasible to maximise each of these payments at the expense of the developer. In the end, the developer may lose interest if the Government demands higher payments than the project can pay and still leave the developer a profit appropriate to the level of risk accepted. Thus to increase its financial returns the Government may have to insulate the project from some of the attendant risks leading the Government back to the familiar balance between risk and return. As custodian of the natural resources of a country, Government experiences a wider range of environmental, social and economic costs and benefits from a project than a developer. As noted

above the Government can expect wider economic costs and benefits from such issues as the employment generated by the project. Such employment will provide salaries to boost the local economy and also taxes paid on individual income. There may also be development benefits from the increased supply of electricity which may support development and also encourage investment. However, the development of the project may reduce income from tourism or fishing. These wider economic costs and benefits can have a significant impact on the host country, but are difficult to quantify and hard for developers to assess. As a result the project may be economically beneficial to the Government, but appear less financially attractive to a developer. This is referred to as the gap between economic and financial viability and it is one of the principal reasons for the difficulty in attracting developers and finance to hydropower projects. In the case of a lack of financial viability of a project which Government is keen to support for development reasons, the Government can improve its financial attractiveness of the project by providing subsidies or other forms of fiscal support to the project if is considers it an economic priority. Format of concession Concessions for private development can span a wide range of structures depending on the ownership of the assets and the sources of funding. Models may include management contracts and leases, but these are uncommon in hydropower. More commonly used models include BOOT (Build, own, operate, transfer) where the assets are owned in the private sector but later transferred to the public sector; BOT (Build, operate, transfer) where the assets are owned in the public sector but managed in the private sector; or ROM (Rehabilitate, operate, maintain) to rehabilitate and operate old state owned assets. If none of these structures are possible or attractive then the project may only be developed in the public sector. In this case the structure can either be a public company or special purpose vehicle which can attract some private finance (often referred to as a parastatal company). Alternatively, if sufficient public finance is available then the project can be developed entirely in the public sector. In some circumstances it is possible to divide the project into two and develop aspect (such as the dam) in the public sector and one aspect (such as the power station) in the private sector. The choice of model is summarised in figure 3. Figure 3 Choice of structure (Head 2006)

Forming a transaction Most forms of private development or public private partnership start with the development of a concession or other agreement which defines the obligations in the project. There are various ways of awarding a concession or otherwise setting a project in motion. In some cases this can be done through a preferred supplier (directly negotiated concession), but effort must be made to ensure that the deal is structured fairly and this can be done by asking an independent agencies to consider the costs and complexity involved in the projects. More often (in recent years) the concession is let by a competitive process, which is structured and arranged by Government with expert advice. In this case the process commences with public notification of the Government s intent to award a concession followed by a bidding process. The issue to be optimized through the bidding process may be the price of local off-take power or the level of Government royalties or a combination thereof. The Government of PNG should consider the options available to them and the pros and cons of each and take expert advice on financing specific transactions, allocation of risk and legal advice before taking a final decision on how to structure the project. This should then be explained in an outline document setting out the shareholdings, water rights; reservoir operation; tariffs principles; power sales; and method of procurement of the private partner. The document should also identify the length of concession, fiscal incentives, tax regime, royalties due, and environmental and social obligations. Having outlined the preferred structure it would be appropriate to consult potential investors to gauge the appetite for such a transaction: If the response is positive then a bidding process can be set in motion to attract private players as determined by the proposed structure. Depending on the extent of public involvement in the financing of the projects, the same document can be used to elicit interest from the multilateral investment banks and financial support from the private sector with the aim of assembling an outline financing plan and detailed financial model of the project. In some circumstances, projects may even be subject of a competition for finance. This method has particularly been used where some element of multilateral finance is available and the risks are considered moderate so several international banks may be interested. The competition may be based on the least cost, longest tenor, or a combination thereof.

There may be cases in which it is appropriate to allow a private project to be developed for the use of specific private off-takers such as industrial units. It is vital that in such cases the Government ensures the maximisation of economic and financial gain to Government including the provision of a percentage of power for domestic use to ensure social equity. This can be through the provision of free power as is defined for Indian projects or by providing a dedicated turbine for domestic offtake as in the Nam Theun 2 example. Table 2 below compares the form of returns likely to accrue to Government under various project structures.

Table 2 Table showing benefits to Government likely to be associated with various development models Public project Public private project Split Project Private project Royalties None Some Some Substantial Tax Some Some Some Substantial in later years of project Dividends Possibly depending on how public utility is funded Some depending on how project is funded Some depending on how public utility/project is funded Some depending on how project is funded Economic benefits Substantial Substantial Substantial Substantial Free/Cheap power None but overall cost of power may be lower None but overall cost of power may be lower Depends on concession agreement Possible Low cost finance Substantial Substantial Substantial Unlikely Benefits of international experience and commercial practice Limited Substantial Substantial Substantial Overall likelihood of reaching financial closure/development Possible with security Substantial but may be costly Substantial but may be costly Depending on risk likely to be costly

6 Next Steps Papua New Guinea requires a better understanding of the financial cash flow and economic costs and benefits of its power development strategy, including the trade off between the use of gas (as opposed to sale at world market prices) and the use of hydropower. Detailed financial and economic models would allow the Government to understand the impacts of going ahead with projects under different financial and risk scenarios as compared to the impacts of delaying or cancelling the project. A better understanding of the economic rationale for projects would allow Government to take clearer decisions on how to support a project (or not) and under what terms with respect to such issues as royalties or provision of power for domestic use. Domestic finance may be available to contribute to the financing of projects, particularly from the revenues from LNG, but it makes sense to spread the available domestic finance over more than one project rather than to place all of the available funds in one (possibly risky) project. To reduce risk domestic finance may need to be spread over time as well as projects and could be used to refinance projects after construction if this option were built in to the financing structure from the outset. Further work on the available mechanisms to manage and reduce the project risk profiles would also accelerate hydropower development, where this is considered a strategic priority. For individual projects it will be important to ensure as much as accountability and transparency as possible is vested in the project and that the long term sustainability of the project is ensured. References Head 2000 Financing of Private Hydropower Projects, Chris Head. World Bank Discussion Paper 420, 2000. Head 2006 The Financing of Water Infrastructure: A Review of Case Studies, Chris Head, World Bank, 2006. Trouille, B., J. M. Devernay, et al. (2008). Hydro Finance Handbook - Prepared as a Companion Document for Hydro Finance Tutorial, Session 1c of the New Development Track of the Hydrovision 2008 Conference, HCI Publications - Under revision for future re-publication.

Annex 1 Risk characteristics of Hydropower Projects: - Political Risks Economic and Financial Risks Technical Risks Social Risks Environmental Risks Political Risks Political Change risks (risks to project caused by local or national changes in government, policy, legislation, regulation, political instability or unrest, etc.): Enact special legislation Sovereign guarantees Political risk guarantees Corruption risks (risks to project implementation or developer reputation caused by corruption issues): Anti-corruption policy Vet contractors Transparent practices for tendering, management & business Third-party monitoring Adequacy of government and public sector agencies to respond in a timely manner in terms of issuance of licenses and approvals or other coordination with the project: Enact special legislation Sovereign guarantees Political risk guarantees Political Change risks (risks to project caused by local or national changes in government, policy, legislation, regulation, political instability or unrest, etc.): Enact special legislation Sovereign guarantees Political risk guarantees Trans-Boundary Issues (upstream and downstream riparian rights and treaties, border security issues, etc.) Treaties and agreements Water/watershed management plans Benefits sharing agreements Co-development or co-ownership of project Economic and Financial Risks Cost Escalation (inflation, commodity prices, competition for resources and other local and international cost effects) Enhanced supervision of project activities Mitigate risk through engineering (enhanced investigation and design) Transfer risk through contracting methodology (e.g. fixed-price EPC) Hedging against future increases in price of steel, cement or other commodities Transfer risk through bonding or insurance Penalty/bonus incentive scheme

Foreign Exchange risks (changes in relative exchange rates between currencies in use for the project, particularly between main currency for cost and main currency for revenue ) Transfer risk to contractor Natural hedging (matching currencies of revenues and costs) Financial hedging (e.g. forward contracts, futures, options, swaps) Electricity Market risks (changes in the price of electricity for merchant plants or changes in the regulatory mechanism for setting price, etc.) Long-term electricity sales contracts Financial hedging (e.g. forward contracts, futures, options, swaps) Use of regulatory mechanisms for price increment Public utility rate base with guaranteed rate of return on equity Financing Package risks (debt, equity and other financing instruments, cost, conditions and tenure of available finance) Require contractors to arrange finance Invite additional public equity and debt Use sovereign guarantees Lower overall project risk profile Build in re-finance option Involve International Financing Institutions to encourage other private equity and debt Lower debt interest rate and longer repayment period Apply for carbon finance or similar Performance of Contractors or Construction Schedule delays (due to poor scheduling or inefficiency rather than as a result of delay caused by other risk elements): Expert advice/ review of project schedule Prequalification of Contractors Contract terms and conditions Transfer risk through Bonding and Insurance Warranties and Guarantees Enhanced supervision of project activities including rapid dispute resolution mechanisms Technical Risks Hydrological risks (operational or construction related risk of lower or higher than expected flows, floods or unusual seasonal variations): Investigations (feasibility or design stages) Construct diversions or storage reservoirs to supplement river discharge Modify project design or operation Allow contingency margin for project output Hydrological or energy reserve exchanges with other hydropower facilities Flood mitigation part of emergency/ contingency planning Negotiate with other water users Geotechnical-Seismic risks Investigations (feasibility or design stages) Special design or relocation of structures to avoid damage Redesign or relocation of project to mitigate consequences of damage

Electro-mechanical Equipment Performance Technical & commercial terms & conditions of contract Supervision, inspection, and quality assurance measures Preferred suppliers Physical model testing Shop inspections Reliability tests Penalty/bonus incentives Rely on guarantees and warranties Construction and Installation Quality risks Technical and commercial terms and conditions of contract Supervision, inspection, and quality assurance measures Preferred contractors Penalty/bonus incentives Rely on guarantees/warranties Operation and Maintenance risks Adapt design to facilitate operation and maintenance Operation and maintenance contracts with project contractor/ suppliers Rely on guarantees/ warranties Associated infrastructure risks Formal agreement with organisations responsible for transmission, roads etc. Back to back agreements to compensate for delay caused by one party or the other Coordination through joint group or nominated agency Social Risks (Most risks also covered in the social or environment action plan) Land and Water Use Conflicts (issues raised by local water users or downstream riparians on use of water or catchment): Modify project (e.g. location or design) Modify project operation Formal agreement with stakeholders Resettlement and Social Unrest risks (local issues over resettlement or other issues such as employment and compensation): Modify project (e.g. location or design) Modify project operation Agreement with stakeholders Public Health and Safety risks (issues of physical safety as well as spread of disease during all phases of the project): Safety management plan Modify project (e.g. location or design) Modify project operation Agreement with stakeholders Communication main international objections on social, environmental or cultural grounds Modify project (e.g. location or design) Modify project operation Communication

Cultural Heritage issues(preservation or protection of culturally or historically significant sites or artifacts): Modify project (e.g. location or design) Modify project operation Specific pre-project activity to investigate or preserve Agreement with stakeholders Environmental Risks (most risks also covered in environmental management plan) Water-Air Quality risks Modify project (e.g. location or design) Modify project operation Compensate for impacts Sedimentation risks Modify project (e.g. location or design) Modify project operation Coordinate with other hydro operators in catchment Upstream and Downstream Flow Regime risks Modify project (e.g. location or design) Modify project operation Compensate for impacts Greenhouse Gas Emission risks Modify project (e.g. location or design) Modify project operation Apply GHG offsets Wetlands Protection risks Modify project (e.g. location or design) Modify project operation Compensation Biodiversity risks Modify project (e.g. location or design) Modify operation Compensate for impacts Pest management Fish Habitat risks Modify project (e.g. location or design) Modify operation Compensate for impacts