Energy ventures require large financial resources from investors, varying from around US$ 600 million for the construction of a power plant based upon CCGT - Combined Cycle Gas Turbines - to several billion US dollars for the creation of an integrated LNG – Liquefied Natural Gas chain.

Not many companies in the world can afford to use their own resources in the development of such projects. Even the ones that do, often resort to financial markets for the provision of funds. These third party financial resources come through basically two types of systems: balance sheet and project financing.

This paper will focus on international project finance, which is a topic of increasing interest among energy companies operating world-wide. Considering that the banks lend financial resources based mainly on projects' ability to foster revenue, such institutions must address a variety of risks facing the project itself, and not necessarily those affecting the sponsors. Among these, the market risk is perhaps the risk most closely affecting cash generation.

This paper provides an analysis of offtake agreements and their role in project finance with regard to reduction of market risk. Due to constraints on availability of real project finance documentation, the survey will be based on legal, financial and industry literature.

2.0 ENERGY RELATED VENTURES AND PROJECT FINANCE

Most debt in the energy sector is financed by balance sheet financing, (conventional or corporate financing). For financial institutions, what matters in this kind of financing is the borrower himself. The approval of a loan under balance sheet financing would depend on the credit of the company, whether it has defaulted on a financial obligation before, the balance between its assets and liabilities, and many other criteria, all related to the company itself and above all, to its ability to repay the loan.

By contrast, project finance relies on the concept and virtues of a given project, e.g. a project to develop upstream natural gas production, be it for sale through pipelines or for overseas sale in LNG physical form, or to build and operate a power generation plant. The banks would still look at the financial strength of the energy company proposing the new venture (the "sponsor" or "sponsors", where there is a joint venture), but their decision on providing funds would be based on the projected cash flows from the project, and their capacity to service debt.

In other words, the proposed project must be robust enough to generate a steady flow of revenues to repay the debt, while, for instance, meeting operational expenses (e.g. wages and maintenance) and complying with sponsor requirements (e.g. minimum rate of return envisaged for the project). However, project financing for energy projects rarely excludes financial contribution and other commitments from the sponsors; this is what is called limited recourse project finance. If no commitment whatsoever is required from the sponsors, the transaction is termed non-recourse project finance.

In order to isolate the cash flow of the project, so that it can be captured contractually for the purpose of the financing, the sponsors set up a new company, the so-called SPC – Special Purpose Company. The SPC would carry all direct rights and obligations for the project, including ownership of all assets, such as, in the case of an electricity project , the power generation plant.

2.2.   Why it is More Expensive

The analysis of all risks involved in project finance is very time consuming. This leads to higher transaction costs entailed by man-hours put in the project, related to experts such as business analysts, lawyers, financial advisers and others. Banks which are candidates for project loans are, for obvious reasons, less familiar with the uncertainties, strengths and possible shortcomings of projects than their sponsors. They fairly demand much more time to understand the project and comprehend where they stand in assuming their share of the risks.

In comparison with conventional financing, project financing documentation is far more complex, and much more time and money are spent in drafting, evaluating and tailoring the web of contracts to the satisfaction of the several parties participating in the financing of the project.

Another source of costs comes from the continuing role of banks long after contract finalisation. Since payback of the debt depends on  project revenues and since they have limited recourse to sponsors, banks spend a considerable amount of money assuring that everything goes along as planned, including  construction progress, budgetary constraints and overall performance of the venture.

Extra costs from the preparation and monitoring of project financing, as referred to above, are not absorbed by the banks, but rather transferred either to the sponsors or to the SPC. As well as these costs, the sponsors bear higher interest rates in connection with the loan. The risk versus reward relationship applies coherently to project finance. Since the project lenders are invited to share higher risks than in ordinary lending, the usual project financing interest rates are considerably higher.

However, notwithstanding the fact that it is more expensive, energy companies have a reasonable number of projects funded by project finance, which have a common trace: not all of them would have been launched if the banks had not agreed to participate by taking or sharing some of the risks, unbearable for those companies themselves.

2.3.   Risk Sharing and Other Reasons for Project Finance

In the energy sector, there is a set of companies with very strong financial capability. In view of their strong balance sheets, financial institutions compete between themselves for providing loans and other financial facilities to them, at a cost that most other companies in the world could not even dream of. Indeed, in the jargon of financial markets, these energy companies have credit ratings close to zero. This is due to their market reputation in paying past borrowings and, basically, to the fact that their asset base is much larger than their debt requirements. Nevertheless they choose that some of their international projects be funded by project finance, which is a much more costly way of raising funds from third parties.

The main reason for such choice is that energy companies, depending on the challenges posed by the particular project, understand that the benefits of risk sharing under project finance outweighs undesirable higher costs. The proposed project may be too risky or demand an overwhelming level of investment. In such cases, the energy company may be unwilling to go ahead by themselves. Their final investment decision would depend on financial market signals that the project will be project financed, i.e. that the banks, after careful examination of the project information memorandum, will be prepared to finance the venture by project finance, hence sharing serious risks with sponsors.

However, besides risk sharing, there are other factors informing the decision-making of sponsors considering project financing rather than other means. The other more common reasons for borrowers to opt for project finance are political risks, accounting treatment, restrictions on borrowing and tax benefits. Indeed, the project may be planned for a country where the political situation does not recommend the exposure of foreign investment from energy companies. In such a situation, it is preferable to involve institutions such as the World Bank as project lenders. This may prevent political action against the project due to the likely need of the host country to keep lines of  international credit open for other needs, such as infrastructure financing, poverty alleviation projects and others. 

Also, sponsors eventually reach limits in borrowing more money through conventional financing. This is due to the need for security of assets, to a direct obligation to repay the loan in case of SPC default, or to restrictions imposed by shareholders or by existing creditors (e.g. negative covenants regarding new borrowings).  Hence, where the situation of the project sponsor does not allow further borrowings for new energy ventures, the way to move forward may be through project financing, which can "employ a finance structure that is not legally classified as a borrowing, such as a forward purchase agreement, trustee borrowing or production payment arrangement".

2.4.   Project Risks

Project finance is an exercise of project risk identification. The more accurately the existing risks can be identified, the better the parties involved can negotiate the allocation of such risks to the party most prepared or able to bear each of the risks. In project financing, clarity as to what are the risks and who are the parties sharing or taking each of the risks in full is essential.  These risks are dissimilar in nature and can apply differently to each project.

For example, political risk is a key concern in international project financing, which is subject to changes promoted by host country authorities that can affect the expected stream of revenues, such as a change in taxation or in regulation of gas prices. A classic preoccupation is the expropriation of project's assets, due to unexpected changes in political orientation. Other risks follow, such as market risk, completion risk, technological risk, exchange rate risk, environmental risk and many others well covered by literature, which could adversely affect the assumptions of sponsors and banks as to the feasibility of the project.

However, market risk alone, as one of the higher-weight risks in the decision-making process, can kill a project from the outset. Unless the market risk test is passed, none of the other risks need be addressed. If there is no market for the gas, LNG or electricity to be sold under the envisaged project, it is obviously best not to proceed. However the most common situation is the uncertain ability of the target market to absorb the project's product, which, for many reasons, will be offered to potential purchasers under special conditions such as price, volume, specification and other.

All sorts of issues affect the commercial feasibility of a proposed energy project, including competitors, access to markets, applicable tariffs and trade barriers. All these concern market risk, which is usually taken by lenders of project finance. After all, it imposes a direct effect on the generation of revenues by the project, which is the main source of repayment of the project debt.  In limited recourse or non-recourse project finance, there is little option for loan recovery if the project fails due to market risk. This calls for a specific remedy.

3.0   REASSIGNING MARKET RISK THROUGH OFFTAKE AGREEMENTS

If the banks are prepared, under project finance, to face market risk, by the same token they would seek every possibility to mitigate this risk before committing their funds to the transaction.  One way of doing this is by demanding the prior signature of offtake agreements.

The offtaker, i.e. the customer of the electricity, LNG or natural gas, agrees to buy part or the total output of the power plant or gas production facility, at pre-determined prices and conditions. This is normally over the long term (usually from 15 to 25 years, depending on the type of project), necessary for making available to the SPC enough funds to repay the debt and to pay necessary operating costs and expenses.

Thus, instead of relying on an uncertain customer market base, for there is no kind of guarantee, project finance is backed by agreements that have the legal force to lock in a given customer for the time deemed necessary for the debt-service. Another risk, however, emerges. It is the credit risk of the offtaker. Of course, an offtake agreement has no value unless the creditworthiness of the project product buyer is previously assessed and assured. As examples of offtake agreements, the agreements below will be scrutinised in view of how they contribute to the mitigation of market risk.

3.1.   Gas Sales Agreements

Gas sales agreements (hereinafter GSA) can be very instrumental in the success of project finance. A GSA regulates the sale of gas from the producer to the gas buyer. Depending on how the gas and electricity industry is structured in the host country, buyers of gas in bulk can be natural gas pipeline transmission companies, natural gas distribution companies, power generation companies, large industrial consumers and others.

Banks are expected to require that the GSA provides for the purchase of gas under the purchaser's firm commitment to pay for a nominated quantity of molecules, usually irrespectively of effective gas offtake, as will be discussed below. This would secure a steady flow of revenues to the seller – the one looking for financing – at a level necessary to carry out its producing operating activities and to make repayments of principal, interests and other financial expenses derived from the loan. Such cash flow would be given as collateral security to the banks, enabling them to handle market risk and therefore build a stronger case for project financing gas production.

3.1.1.   Price Formula

A substantial challenge for the success of project finance in gas production is the establishment of the price under which the gas will be sold. Gas per se is not easy to price, in that gas prices at the consumer's burner tip must be set in the context of alternative fuels available in a given market. Examples of pricing systems used by the industry are: a) price agreed per capacity of gas to be made available, whether used or not; b) price per unit of gas delivered; c) cost-plus-linked price; or d) price derived from the replacement value of the gas against its substitute in the market.  Whatever the system, the general rule is that, unless priced at reasonable competitive levels, molecules out of a proposed gas production project would never find a prospective offtaker, let alone a market.

The difficulty of the task builds up due to the long timeframe of GSA's necessary to attract project finance. The parties to such contracts must design a price formula which can cope with market changes over decades. The price structure must reflect changes in gas production costs, the value of money, exchange rates, taxation, price of competing products and/or many other variables.

From the standpoint of the financial institutions lending money to the project, the price formula must provide a sustainable price for the gas at all times, or, at least, during the period the debt is outstanding. A sustainable price is one sufficient to enable the seller to operate gas production installations and repay the project's financial debt.

3.1.2.   Take-or-Pay, Make-up Rights and Carry Forward

Take-or-pay clauses are absolutely crucial towards project finance for gas producing fields. A GSA with a well negotiated take or pay clause can give the banks a substantially different perception of project market risk. Under a clause of this type, the offtaker makes a commitment to take a certain quantity of gas made available by the seller under the GSA and to pay the price set forth in the contract, or, alternatively, to pay anyway for gas eventually not taken by him, within the agreed quantity.  The level of take-or-pay that seller and buyer are able to negotiate and agree upon is key for the calculation of the debt-service terms and other related conditions. It is important, however, that the parties keep their assumptions on the conservative side, so that the take-or-pay quantity is within the real consumption patterns of buyer's customers and realistic in terms of potential demand growth of the target market. This way the proceeds of the GSA are not likely to be disrupted by miscalculation of demand, hence maintaining the regular revenue flow required for compliance with project finance obligations.

A take-or-pay clause is not intended to penalise the buyer in case the quantity of gas is not taken, nor to create the possibility of unfair profits for the seller derived from the same reason. Instead, within the framework of project finance feasibility, the scheme serves to enhance cash flow rather than gas flow, since servicing of the debt cannot remain liable to variability of demand. Therefore, the gas purchaser is entitled to "make-up rights", i.e. to the right to take gas from the seller up to the amount paid in anticipation.

In order not to cause a breach to the pre-defined cash flow, the purchaser will only be able to offset such anticipated payments against payment obligations related to gas taken in the future in excess of the quantity committed by the purchaser in the GSA as a take-or-pay obligation. Make up rights are, however, limited in time, as a protection to the seller from having to supply make-up gas indefinitely. When the make-up right time limit has expired, the seller may deliver the respective quantity of gas to other customers or count on them for further commercial arrangements with the offtaker.   

Another concept commonly adopted in gas sales agreements is that of carry-forward right, meaning that "gas taken in excess of the minimum pay could be credited against the minimum-pay quantities in later years, reducing the minimum-pay obligation in those years". Thus, the take of gas in excess of the contractual quantity (to which the buyer is liable to take-or-pay) reduces future quantities required to be taken by force of take-or-pay clauses, provided that the respective invoice for such gas is duly liquidated. In theory, such a reduction of take-or-pay levels in later years produced by carry-forward rights need not affect project finance requirements, since the cash flow necessary for repayment of the loan remains intact, but the timing of the inward revenues is faster than expected by the parties.  Indeed, the minimum payment behind the pre-defined level of take-or-pay is the threshold under which the gas sale is profitable and the repayment of the loan is guaranteed. However, in order to avoid short protection for the loan, the banks must ensure that the arrangements of the project finance capture as security every and each revenue obtained by the seller, including earlier and perhaps unexpected proceeds that entitle the buyer to carry-forward rights.

3.1.3.   Special Characteristics of LNG

A LNG sale and purchase agreement (hereinafter SPA) usually adopts the features referred to above with regard to a GSA, with adaptations, but it is worth mentioning some aspects of  this agreement, which attracts more stringent scrutiny due to the magnitude of investment and associated project financing risk.  Undeniably, the industry is known to bear exorbitant costs, specially those derived from the construction of production trains, liquefaction installations, dedicated ships, special port facilities and terminals for LNG regasification.

Greenfield LNG developments require a minimum term of 20 years for the SPA. Revenues for the first 10 to 12 years will be allocated for servicing the debt of the loan, leaving the balance of the contract term (8 to 18, on contracts termed 20 to 30 years) for the sponsors to obtain a return on their investment in the project.  This reflects the economics of the billions of US dollars needed to launch a LNG project. Without this time span, it would be impossible to generate sufficient revenue to repay project finance loans committed by lenders to LNG projects.

Due to higher costs and related difficulties in winning competition from other fuels readily available in the host country, LNG pricing is a somewhat harder task than pricing natural gas under a GSA, demanding an extended period for lenders, sponsors, prospective buyers, governments and other relevant parties to analyse the economic feasibility of the project.

The US$/mmBtu LNG price is calculated taking into consideration two main elements, the energy element and the element for transportation. The latter is in case the SPA provides for ex-ship sales rather than FOB sales. Both elements are subject to adjustments by virtue of carefully drafted clauses, such as adjustments designed to maintain the LNG price competitive with other energy sources, to offset the effects of inflation, to compensate for vaporisation during transportation and to allow reductions in transportation cost to enable competition with suppliers located closer to the buyer.

The forecast volume of LNG to be sold under a SPA at a negotiated US dollar price per million Btu is not, however, sufficient to secure favourable decisions from financial markets. Assuming that the buyer has a sound credit rating, which, together with a signed long term offtake agreement, alleviates both market and credit risks, there are still two other risks related to the economic feasibility of the project. These are, a) price risk, i.e. the risk that competing energy prices fall considerably, resulting in insufficient LNG price levels, since the fate of the former is usually attached to the latter in built-in price formulae that capture the volatility of other fuels prevailing in the market; and b) volume risk, i.e. the risk that the huge contracted volume turns out not possible to be forwarded in subsequent sales by the buyer to his customers.

The reaction of the industry and financial markets to the volume risk was to persuade buyers (sometimes also sponsors of the LNG project finance scheme) to accept stringent take-or-pay commitments, and to undertake to pay a minimum price throughout the life of the project, as a defence against price risk. A minimum price, usually attached to historical LNG prices of the market concerned, provides the assurance that lenders seek when applying their lending assumptions to proposed LNG financing. These devices can together encourage the banks to give a green light to proposals, in that they allow sufficient cash-flow coverage to meet  the financial obligations of the borrower.

3.2.   Power Purchase Agreements

The so-called Power Purchase Agreement or PPA is often used as a tool for ensuring electricity project finance at international level. As a long-term agreement, through which the power generator sells energy and availability to a purchaser or offtaker, a PPA is very helpful where there are uncertainties with regard to the placement of the output in the envisaged market. Thus, it is a key contract for project financing the construction of new power generation plants.

On one side in the contract is an independent power producer (hereinafter IPP). On the other, a central purchasing agency, if the electricity sector of the host country is built upon competition in generation, or an electricity wholesaler or aggregator, where there is competition either in wholesale or retail. A dual tariff model for the purchase of power under such offtake agreements was an important development. With regard to the interests of project finance lenders, the energy and capacity components of the tariff, as per below, allow the establishment of revenue generation even at times when the plant is not actually running.

3.2.1.   Energy Charge

The first component of the tariff relates to the revenue owed to the generator when the plant is dispatched. It is normally charged in US dollars per kilowatt hour, and is due for payment by the buyer every time the plant is effectively generating power at the request of the buyer. The energy charge is for recovery of variable costs such as fuel, maintenance and operating costs, all dependant on the level of energy production. Therefore, security for loans is sought elsewhere, in the capacity charge.

3.2.2.   Capacity Charge, Bonuses and Penalties

Electricity is an odd commodity when it comes to storage capabilities. Since it cannot actually be kept for later use, electricity systems match demand to supply by the hour, and even by the half hour in some electricity systems. Hence, in effect the purchaser is buying the ability of a power plant to generate power at times and under conditions specified in the PPA, when the seller must guarantee the availability of the plant.

Usually, in power plant project finance backed by a PPA with a two-element tariff, the capacity charge is usually set at a higher level during the time the debt is outstanding. After the debt is paid in full, this part of the tariff can be lowered. This is because the capacity charge comprises all fixed costs of the project, including capital borrowed from third parties. As soon as principal, interest and other financial costs are returned to the lenders, there is no longer an economic justification for maintaining the capacity charge at same level.

The economic feasibility of a project finance operation for the construction of a power plant depends on the calculation of the price for the capacity charge. The value of the capacity charge and the level of plant availability (hours per year) to be negotiated and fixed in the PPA must meet the pay-back requirements of the lenders. Burdensome negotiations can be avoided if the power generator is selected by the offtaker through a bidding procedure where the capacity charge per MWh forms the criterion for the award of the contract.

In theory, however, the value of the capacity charge should be equal to the difference between: a) the value of the generator's output to the system if it was not there in the first place, that is, the extra costs incurred by the system for offtaking power from a more expensive generator (the "System Marginal Cost), or, if the alternative is to cut off some consumers, the costs associated with this measure (the "Value of the Lost Load" or VOLL); and b) the price fixed in the PPA for the generator's output.

Also, as far as project finance is concerned, the PPA must have mechanisms to ensure that the generator will strive to maintain the agreed level of availability at all times, so that the IPP is entitled to the respective payments from the offtaker, thus protecting the interests of the lenders. For this reason, banks often require that the PPA establishes a penalty to be paid by the generator in case of non-compliance with capacity levels. On the other hand, bonuses can be negotiated to the benefit of the generator should he keep availability above the target.

4.0   ACCEPTING MARKET RISK IN COMPETITIVE ENERGY MARKETS

This paper could not be finished without mentioning that long-term offtake agreements are not a necessary condition for project financing in energy ventures. There are situations under which banks may be prepared to assume market risk directly. In such cases, project financing is more difficult, inasmuch as the expected earnings of the venture, necessary to meet the schedule of loan repayments, need to be tested against market factors not falling within the control of the banks. Demand, supply and cost, as roughly the main aspects of market risk, will have to be more closely scrutinised, with competition arising as a dangerous variable.

In mature competitive electricity markets, for example, a large proportion of energy is sold in spot markets, where, in principle, high cost generators or poorly operated plants have little chance of being used, except when demand is considerably higher than the installed capacity of the most efficient generators. On an hourly or half-hourly basis, these markets allocate supply through bidding procedures, under a system of merit order that determines that cheaper plants are dispatched first. In other words, in each period of 30 or 60 minutes of a given day, the need for power is satisfied by the lowest cost generators, until the level of demand required by the market is reached.

Plants operating entirely on spot markets, with no commitment to sell power under PPAs (the so-called merchant plants), may still be able to generate a sustainable flow of revenues over time, sufficient to underpin project finance payment requirements.  Sponsors with an impressive track record in terms of "in merit" power plant operation, can convince prospective lenders to commit their own funds to greenfield projects, although the latter may expect a higher contribution from the former in terms of equity, so that some extra self-confidence in the project is demonstrated.

Of course there are other considerations for banks to carefully take into account, including marketing studies, analysis of actual and possible future competition, experience and reliability of the proposed contractor (for the construction of the plant) and plant operator. But proven operation in merit order is a strong signal that respective sponsors have successfully passed all these tests in past projects. This reputation makes these sponsors serious candidates for new funds under project finance, irrespective of long-term offtake agreements.

5.0   CONCLUSION

This paper has discussed the means by which financial institutions may address market risk, a key element in judging the commercial feasibility of new energy ventures. Mitigation of such risk is fundamental for enhancing the interest of banks in providing funds through project finance. In this context, offtake agreements can play a pivotal role, in that they make possible the assignment of market risk to buyers bearing healthy and solid credit ratings.

However, such contracts are not always a pre-condition for the closing of project finance. New energy ventures, where the challenge is to sell products in spot markets on a day to day basis, are still able to attract financial institutions willing to invest project finance funds. This depends upon a variety of factors, including the conditions of the energy market in question and the experience, reputation and track record of project sponsors.