The Take or Pay Clause

Why do long-term take or pay contract relevant in project finance?

Project finance [1] proceeds on the fundamental principle that limits the lender ‘initially’ to project revenues for the purpose of servicing the project debt. [2] It is thus, a vital concern in the project credit analysis not only that the project is viable but also that the revenue flows are certain and predictable. The predictability of revenue flows from the project reduces the lender’s concern over potential risk of non-payment of the project debt. This factor strongly influences the lender’s judgment in respect of the bankability (i.e. acceptance) of the project structure. [3]

In this essay we concern generally energy project. Because of energy industry has been traditionally characterized by long- term take or pay contracts between producers and purchasers. This is due to the special nature of the energy sector. The use of long-term contracts is common in the energy sector as it is the most convenient method of attaining this product and guaranteeing that the energy produced will be sold. Also, the energy industry is very capital intensive. Sellers incur very high fixed costs to produce energy. Their financiers require some guarantee that these costs will be recovered. Rather than leaving this to the unpredictability of markets, where the demand for price fluctuates, and sellers prefer to enter long term take or pay contracts. By doing so, their income is assured over a considerable period of time. The take or pay clause is an important contractual mechanism utilized by producers to secure their investments as its basic function is to ensure that the seller is paid a minimum amount within the framework of the long term contract.

It is important at this stage to clarify certain terms. The phrase ‘long term take or pay contract’ is commonly used for the purpose of convenience. Henceforth, this terminology is adopted by this paper. The actual contract is the long-term contract. Take or pay is not a contract. It is a clause within the contract, which, as already mentioned, serves the function of making certain that sellers receive an agreed sum to cover their costs.

For energy projects ranging from pipeline, oil, gas, Liquefied Natural Gas (LNG) to power, long-term contracts with their ‘take or pay provisions’ have been the principal means for assuring predictable cash flows. The lender’s paranoia for predictable cash-flows stems from the need to limit its involvement in the project to only credit risks and to locate support for the project loan and arrangements for its repayment within the market. The relevance of long-term contracts to energy project economics is predicated on three factors. First is the high capital intensity of energy projects.

Second is the long duration (usually from 20 to 30 years) thus giving the project sponsor adequate opportunities to recoup investments and achieve repayment of project loan plus interest to the lender. Third is the take or pay element. A take or pay provision commits the off taker/buyer either to take delivery of the specified minimum quantity of the off take or to pay for the shortfall. [4] The term ‘take or pay’ is appropriate in the context of an oil, gas or power project structure whilst the same effect is re-enacted in a pipeline project arrangement through ‘put or pay /ship or pay’ provisions. The peculiar and differential features of particular energy projects and financing arrangements are more clearly highlighted in the body of the paper.

The increasing liberalization of energy markets and the consequent introduction of market discipline have provoked a re-examination of the role or relevance of long- term contracts in terms of energy projects financing. Indeed, there is a certain view that the emergence of competitive market structures in energy markets erodes any incentive for firms to conclude long-term contracts. [5] Besides, the inflexibility of traditional long-term contracts heightens the risk to the buyer in terms of market fluidity and volatility. [6] Thus, whilst long-term contracts assure long-term security of supply to a buyer, such value may become considerably diminished in the light of financial difficulties arising by way of supply-demand fluctuations in the market.

The acute financial difficulties which arose within the US and European energy markets in respect of long-term take or pay contracts, particularly at the wake of the transition to competition, have somewhat forced the issue of abolition for contemplation. In fact, at the beginning of the 1990s, some American regulators were in favors of a complete abrogation of long-term contracts and directing all parties to existing arrangements to re-contract. [7] Abolition of long-term contracts is a potential but extreme incident in the context of this paper. It, however, provokes a review of the issue whether real, flexible and market-based mechanisms exist for assuring predictable cash flows to support the economics of energy project financing.

In addressing this issue, this paper adopts an analytic approach. It reviews the rationale and functions of long-term contracts, their relevance in the economics of energy projects – pipeline, oil, gas/LNG, and power with specific emphasis on the peculiarities of each project’s financing structure/arrangements. The paper reviews the case for abolition and considers the implications for bankability of such abolition for energy financing purposes. Thereafter, the paper reviews and evaluates the possible options for enhancing revenue earning potential of energy projects in the absence of long-term contractual arrangements. In this paper, the term ‘lender’ has been used narrowly and in the context of a commercial bank.

2.1 PRELIMINARY ISSUES

Energy projects [8] often require long-term funding of between 10-15 years. As Vinter pointed out, “[traditionally] long term loans require long-term contracts.” [9] The essence of project finance is the raising of funds to finance the costs of a project, debt service and return on equity from cash flows generated by the project. [10] For project sponsors, the attraction for project financing arrangements is influenced by the high- risk profile and capital intensity [11] of energy projects. Project sponsors are thus motivated by the desire to spread risk and limit recourse. [12] Equally, the lender, wishing to limit its involvement in such projects to credit risks, determines the extent to which the proposed project structure has recognized, allocated and mitigated associated risks to enhance the revenue earning potential of the project.

It is locating the appropriate economic/market support for the project that, in the lender’s perspective, determines the bankability of such projects. [13] Ultimately, regardless of any potential benefits from the project (i.e. high margins and fees corresponding to the level of lender’s involvement in the project) the lender’s primary concern is that the project can generate revenue sufficient to repay the project loan plus interest. [14] Accordingly, the lending decision is a culmination of a process of evaluation of the project structure for eligibility and financial and technical feasibility. [15] It may be useful however, to mention here that most energy projects are leveraged from 60% to 80% or at times 90% debt to equity [16] depending usually on the creditworthiness of sponsors, the risks and the location of the project. [17]

2.2 LONG-TERM CONTRACTS: RATIONALE AND FUNCTIONS

Long-term contracts facilitate capital investment in major projects where returns accrue over long periods. [18] In energy projects, long-term take or pay contracts provide the mechanism for assuring to the lender predictable cash flow. Long-term contracts are contracts whose duration usually ranges from 20 to 30 years. In this context, they differ and are easily distinguishable from short or medium contracts. [19]

The thinking is that such long duration enhances sponsors’ potential to recoup their investments in the project and to pay the project debts. The take or pay element in such contracts guarantees that in any event the project earns revenue.

The take or pay provision requires the off taker/buyer ‘either to take delivery of not less than a specified minimum quantity of the product, say, gas over a specified period (typically a year) or if the buyer does not in any event take that quantity, to pay for the shortfall of that quantity from the agreed minimum quantity’ subject, of course, to deductions for deliveries not taken due to force majeure and non-delivery by the seller/producer. [20] The term ‘take or pay’ is appropriate in the context of an oil, gas or power project structure whilst the same effect is re-enacted in a pipeline project arrangement through ‘put or pay /ship or pay’ provisions.

Thus, a take or pay contract will usually perform the following functions:

• protect revenue stream for seller;

• assure the bank to support third party or project financing;

• support project economics and enhance decision making;

• move risk;

• useful as trade off against other key components of price;

• secure commercial advantage; [21] and

• provide less negative impact on the credit of the sponsor than a guarantee. [22]

In other words, take or pay contracts are risk-sharing instruments between producers

and buyers due to long lead times in investment planning and capital-intensive operations. [23] Also, they serve as mechanisms for effecting appropriate incentives for

contractual performance. [24]

3. What are the main risks in long term take or pay contract?

The long-term nature of the contracts at issue makes them vulnerable to disruption from unforeseen events or events, which the parties – for whatever reason – did not and perhaps, could not deal with in the contract with sufficient time and in sufficient detail. The longer-term an agreement and the more exposed to geological, commercial and political risk, the more it becomes vulnerable to external events. Such events can make the operation of the contract partially impracticable or, from a commercial and financial perspective, no longer viable for one party. One consequence is for the parties to terminate the agreement or one party to withdraw.

However, such complete destruction of the contract would then also destroy the contractual relationship, which often would have continuing benefits for both parties. Parties can also suspend operations under the contract, which if the issues are not solved will in many cases equally result in the destruction of the contract. Finally, both parties often welcome to be seen as reasonable partners with whom one can do business with, and salvaging a contractual relationship from the destructive impact of unforeseen and unregulated external events tends to contribute to the parties’ reputation as “good to do business with” in the international business community – here the natural resources industry. Such reputation becomes as a rule known quite rapidly in the rather narrow community of the international petroleum industry. It is for this reason that most governments and companies will accede to reasonable requests for renegotiation by their partners when the contractual and in particular financial equilibrium was seriously disrupted by external events.

a) Change in geology and economic fortune of the project:

-Case Analyse AnaOPEC – Oil Companies in the 1970s:

The old oil concession regime granted the oil companies unlimited rights in the exploitation and disposal of  the petroleum resources of the host states. The oil companies determined the rate of production and set prices at which to sell the products .Until the 1960s, the host states had little or no say in the exploitation and management of their petroleum resources. [25] However, the establishment of OPEC in 1960 (which was triggered by the oil companies’ unilateral cut in posted oil prices) led to significant changes in the relationship between host states and oil companies . Not only did the host states assume an important role in setting prices, they were also able to secure renegotiation of  the concession agreements. [26] Those renegotiations and subsequent ones were backed by OPEC Resolution XVI in 1968 which formally called for  renegotiation of existing concessions between member states and oil companies on the basis of changed circumstances. [27] Subsequent declarations by the Organisation called for an increase in the level of state participation to reach 51% by the year 1983. By  1974, most OPEC member countries had achieved  either full state control or majority state participation as set out in the resolution.

As we have seen from the Opec, renegotiation case studie, an unexpected rise in prices of the natural resource product on the international market bringing windfall profits to the foreign investor, coupled with shift in bargaining power in favour of the host state were the main reasons which led to the renegotiations in the 1970s. [28] These case illustrate the obsolescence bargain theory – with the host governments reassessing their “relations with [the] foreign investors on the basis of their countries’ current [diminished] need for foreign capital and technology,” on one hand, and the foreign investors “hostage” status on the other. [29] Similarly, an unexpected discovery of large (‘bonanza’), high grade mineral ore or petroleum deposits, or changes in technology which reduces cost of developing the project, may also lead the host government to demand for renegotiation as might the foreign investor following a disappointing find in a hostile geographical environment. [30]

b) Regulatory Risk:

Renegotiation is often necessitated by the unexpected intervention of government into the contractual relationship. The binding nature of take-or-pay contract which has become onerous to one of the parties following regulatory change has also been emphasised by UK courts in actions  brought before them by some contractual partners to enforce take-or-pay obligations against Enron and Teeside Gas Transportation Ltd, a subsidiary of Enron. In one of the cases [31] , contracts were signed in 1993 between the North Sea J-Block partners and Enron agreed to purchase all the gas produced from the J-Block until the year 2011. Under the agreements (which were signed prior to the liberalisation of the UK gas industry), Enron was to pay around 20 pence per therm. [32] Delivery was to commence after the commissioning (not later than September 1996) of the parties’ respective facilities. The Agreements required the parties to use “reasonable endeavours” to agree on a commissioning date. Although construction of the facilities were completed in February 1996, the parties could not agree on the commissioning date. One of the main reasons was the relunctance by Enron to proceed with the contract as prices of gas had fallen to about 9-10 pence per therm on the spot market (as against the 20 pence under the contract) as a result of deregulation. [33] Enron failed to persuade the parties to renegotiate the contracts as a result of which the parties went to court. The High court held that Enron could not refuse to agree a commissioning date simply because it did not suit its commercial objectives. In other words, the decision seems to suggest that allowing the subjective commercial interest of Enron to prevail over the parties agrements might amount to indirect renegotiation of  the contracts. [34]

Although the J-Block partners did lodge an appeal to the House of Lords, they were able to reach a settlement with Enrol under which they agreed to cut prices under the take or pay contract to reflect prevailing market conditions (though quantity remains unchanged), in return for a US$440million cash payment from Enron. [35]

In the other case involving Teeside Gas Transportation Ltd (TGTL), a subsidiary of Enron, the High Court held TGTL bound to pay all the monies it owed the Central Area Gas Transmission System (CATS) owners under a 15 year Capacity Reservation and Transportation Agreement (CRTA) relating to the transportation of natural gas from Central North Sea to Teeside. Beginning April 1993 until the end of 1994, TGTL had been paying the CATS owners reservation fees under the agreement even though no gas had been transported. But following the collapse of gas prices on the UK spot market in 1995, TGTL withheld payment claiming the CATS owners had failed to comply with some technical aspects of the CRTA. The CATS owners went to court and it was held that the CATs owners had been capable of transporting the 300million cf/d of gas from the J-Block fields under the CRTA and that they were capable of fulfilling their obligations. Therefore, TGTL was bound to honour its own side of the bargain. [36]

These cases illustrate how changes in the regulatory regime of an industry might affect existing contracts between third parties. They also illustrate the relunctance of English courts to allow parties to commercial agreements to escape from their contractual undertakings which have turned sour [37] , even though changes in the market were brought about by an unexpected change in law in the industry or sector. Thus, under Anglo-American laws, the formality of law approach to contracts seems to be preferred over court induced modification of same. [38]

Perhaps, the “shadow” of these cases did hover over the much-publicised British Gas take or pay dispute with some other North Sea gas producers which also ended in settlements consisting of cash payments by British Gas to the producers in exchange for reduction in both the quantity and prices of the gas being supplied British Gas. The facts of the dispute reveal the conflicting arguments surrounding sanctity of contracts and re bus sic stantibus in relation to long-term agreements and the sort of compromises which businessmen could achieve under those circumstances. For that reason, we think it worthwhile to summarise the facts and dispute and its outcome.

Following the liberalisation of the UK gas industry and the resulting collapse in prices on the spot market, British Gas found itself in 1995 having to cope with more than US$61 billion worth of high-priced take or pay contracts [39] – over the next 20 years – most of which were signed in the 1980s with North Sea producers (including BG’s own subsidiaries). In view of its difficulties, BG called on the producers and the government to bail it out by renegotiating the contracts. [40] Basically, BG argued that the contracts were a legacy of the monopoly era and therefore not suitable in a competitive market, that it could not have foreseen the speed with which the government intended to open-up the market, nor the extent of the competition it will face and loss of significant market share, or the build-up of gas surplus and the price collapse, or the mild weather which reduced demand, or delays in construction of new gas-fired power stations. [41] To further buttress its arguments BG cited as an example, other companies such as Enron which had signed similar contracts well after the government’s publication of the liberalisation time table in 1993.

But the idea of contract renegotiation was fiercely criticised by BG’s contractual partners. Among the reasons they advanced were that the principle of sanctity of contracts was regarded as “one of the most important things in the industry,” the more so as such contracts were freely negotiated, signed and approved by experts and senior officials from both sides, that the producers owed their share holders a duty to protect the value of the contracts [42] , that renegotiation with BG was likely to lead to demands from other purchasers for similar readjustment of their contracts, that if BG was in a more favourable position, they could not alter the contracts without its consent, and that the market is so unpredictable and no one could tell what the position would be in 2 or 3 years time. Some producers were concerned that renegotiating the contracts would give BG a competitive advantage both at home and in the European market. Others blamed BG for the excess capacity because in the 1990s, it deliberately produced more than it required from some of its fields in order to reduce competition. Above all, the critics sought to downplay the relevance of the fall in prices by emphasising that the spot market accounts for only 5 per cent of the pricing system in the gas market as such it had less impact on the over all market structure than it was assumed. [43]

Although the government did not want to intervene directly (purely on ideological and self-interest reasons) nonetheless, it did indicate its preference for renegotiation by the parties. While stating that the “government has neither the power nor the desire to impose a solution”, the then Energy Minister did express the government’s believe that a “sensible commercial renegotiation among the interested parties will result in a far better outcome for all.” [44]

In spite of the seemingly opposing position of the parties, renegotitions did finally take place between BG and many producers. [45] Among the factors which led to agreement by the parties’ were: the quid pro quo; possibly, the desire to maintain commercial relationships; the uncertainties surrounding the market – a seller’s market today could be a buyer’s market tomorrow; and perhaps, the feeling that the government might, in some way, penalise some non-cooperating producers. [46]

Another closely related factor which may lead to renegotiation of an investment agreement is what one may call the ‘legal risks’ associated with jurisdictional/title security issues. In many parts of the world where there have been jurisdictional disputes over ownership of a territory bordering two or more countries, development of mineral resources, particularly oil, located in such disputed area may have to be delayed until some form of settlement is reached between the states concerned. Part of the settlement may involve sharing the mineral resources with third party which may affect the foreign investor’s expected returns from the project. [47]

c) The Environmental risk:

As the Egoth case [48] reveals, concern over the environment may pose a serious risk to a long-term investment project. Pressure from environmentalists may force a cancellation or suspension of a project which is perceived as likely to cause serious damage to the environment, to the detriment of parties to the agreement who might have invested a substantial amount of money into the project. [49] Compliance with a new national or international environmental standards (e.g. on gas flaring, mine construction or disposal of tailings, etc.) may add cost to a project which was not contemplated by the parties at the time of the agreement. [50] This happens more often in developing countries where environmental regulations are not well developed and quite often, they are issued in reaction to one environmental disaster or another which is publicised and taken up by some powerful environmental pressure groups (local or international). The usually centralised political set up of many developing countries (with important decisions being taken by government beauracrats with no input from members of the public) means that the impact of large development projects on the environment are not subjected to critical analysis until when a disaster occurs or the impact of the project on the environment became apparent – when capital have already been sunk into the project. Salvaging the project may involve revisiting the agreement by the parties so as to address those environmental concerns. [51]

d) Change in Government: Although change in government per se may not provide any legal basis for renegotiating an agreement entered into by the previous government, nonetheless, in international business, a regime change (especially if brought about through a coup, revolution or other drastic measures) does put pressure on contractual relations and more often than not, used by the new government as one of the reasons for seeking to renegotiate an agreement signed by its predecessor especially if circumstances surrounding the initial agreement are tainted by allegations of corruption, improper procedure or abuse of office by the previous regime. [52]

4. The Crucial Term On Long Term Take or Pay Contract

In this part this essay focus main clauses to cause common disputes in long term take or pay contract.

4.1.Force Majeure Clause

Typically, force majeure clauses were not negotiated. [53] Instead, they were buried deep in the boilerplate provision of long term take or pay contracts. In fact, the object lesson from force majeure disputes must be that boilerplate provisions oftentimes fail. The drafter lawyer must put careful thought into the preparation of the force majeure clause to make it effective. [54] Many contracts claims force majeure failed on the requirement to give notice. A force majeure clause contains three basic elements:

The requisite notice to be given,

The definition of the types of activities or situations that would constitute force majeure

The effect of those activities on the parties’ obligation

Courts have consistently ruled that the notice in the force majeure clause was a condition precedent to the existence of defense. Without such specified notice, the defense would fail as a matter of law. [55] A producer responding to a force majeure assertion is better able to show lacks of the requisite notic