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14 International Projects—Sector Focus

Aled Davies, James Orme

From: International Project Finance (3rd Edition)

Edited By: John Dewar

From: Oxford Legal Research Library (http://olrl.ouplaw.com). (c) Oxford University Press, 2023. All Rights Reserved. Subscriber: null; date: 06 June 2023

Credit risk — Capital markets

(p. 387) 14  International Projects—Sector Focus

Section A—Oil and Gas

Aled Davies and James Orme, Milbank LLP


14.01  From an early age, oil and gas development companies have been looking to the lending community to support the finance of their developments by relying on the proceeds of production from the particular project. Many of the techniques adopted for project financing generally have their roots in oil and gas project financing of North Sea oil reserves in the (p. 389) 1970s. Before focusing on the key features of oil and gas project financing though, it is worth becoming familiar with some of the features and concepts adopted in the oil and gas industry itself. Very simply, the oil and gas business is divided into three major operational components: upstream, midstream, and downstream. From a project finance perspective, as midstream operations are treated similarly to downstream operations, projects are often bifurcated into upstream projects and downstream projects.

14.02  The upstream sector is commonly understood to refer to the exploration for, and production of, crude oil and natural gas and is otherwise known as the exploration and production (E&P) business. Upstream projects comprise the searching for potential oil and gas reserves, and the drilling of wells and the recovery and sale of hydrocarbons from such reserves. The downstream (and midstream) sector is commonly understood to refer to the refining or processing of hydrocarbons and the sale and distribution of petroleum or natural gas products. Downstream projects comprise oil refineries, LNG liquefaction facilities, petrochemical plants as well as other gas processing plants (i.e. gas to liquids), and LNG regasification plants.

14.03  Refinery and petrochemical plants are complex in that by using various technological processes, a wide range of petrochemical products can be produced for direct sale, or for further processing into different products often at a higher commercial value. Examples of products that can be produced from oil or gas feedstocks are petroleum/gasoline, diesel, ethane, ethylene, polyethylene, paraxylene, and benzene. All of the different units comprising the refinery and petrochemical complex often operate together on an integrated basis to produce such products.

14.04  Similarly, technological innovation has allowed for the development of Liquefied Natural Gas (LNG) projects, often in challenging geographical locations, that cool down gas into a liquid form and then transport it over long distances to markets where there is a demand for gas as fuel. A fully integrated LNG project is understood to refer to each of the following:

  1. (1)  the development and operation of the upstream gas field;

  2. (2)  the construction and operation of a pipeline system that transports the gas to the liquefaction facility;

  3. (3)  the construction and operation of the liquefaction facility to purify and refrigerate the gas into a liquid state;

  4. (4)  the acquisition or leasing and operation of a fleet of LNG tankers; and

  5. (5)  the construction and operation of a regasification plant to covert the LNG back into gas (regasification) so that it can then be distributed to final end-users.

14.05  Each of these components is interdependent in the process of bringing gas from source to market, otherwise known as the LNG value chain.

14.06  Oil and gas projects have their own unique commercial, contractual, and regulatory framework, and understanding such framework is important in explaining the risks and structural features that are particular to such projects.

Project Structuring

14.07  Typically, the oil and gas deposits located within a state or country’s borders are owned by that state or country. The relevant state or national government will grant the private sector—often an international oil company (an ‘IOC’)—the right to both explore and (p. 390) develop the oil and gas deposits in a particular field, and extract the hydrocarbons from it. Such right is typically granted pursuant to a concession agreement, a production sharing contract, a service contract, or a licence.

Concession Agreements

14.08  A Concession Agreement grants the sponsor the right (known as a concession) to develop a concession area for a specific term. During the development of such concession area, the sponsor assumes the legal title to any hydrocarbons extracted from it and, in return, will pay the host government a royalty in connection with the sale of the hydrocarbons.

14.09  Pursuant to some Concession Agreements, host governments have also required certain fixed or immoveable infrastructure used at the concession area to be transferred to, and become the property of, the host government at the end of the concession term. Host governments occasionally require that an agreed percentage of produced hydrocarbons must be sold for domestic use. Brazil is one notable host government that has recently utilized the Concession Agreement framework to develop their oil and gas reserves.

Production Sharing Contracts

14.10  Another framework for an oil and gas project is the Production Sharing Contract (a ‘PSC’). PSCs have been particularly popular with host governments based in Asia and are the model adopted for oil and gas development in Indonesia (where the PSC originated), Vietnam, Myanmar, and the Philippines. Pursuant to a PSC, a sponsor is given the right to develop the contract area for a specific term, but, unlike a Concession Agreement, legal title to any oil or gas extracted remains with the host government. The host government typically agrees the sponsor can recoup certain development costs, and also allows for sharing (in some agreed proportion) of the profit generated from the sale of hydrocarbons. Specific to PSCs, oil that is extracted and sold and then applied to cover development costs is referred to as cost recovery oil, and all other oil sale proceeds in excess of that is called profit oil. In addition to sharing profits, the sponsor may also be required to pay to the host government a production bonus upon the occurrence of certain events—for example, the entry into the PSC by the host government or upon the sponsor making a new discovery of oil and gas. PSCs also occasionally require that a percentage of production is sold in the domestic market (a so-called domestic market obligation).

Service Contracts

14.11  A Service Contract is a contractual framework that contemplates the sponsor developing a specific area on behalf of the host government and, in return for carrying out such development, being paid a fixed service fee by the host government in lieu of sharing profits or paying royalties. The service fee is typically sized to cover a sponsor’s costs in developing and operating the field and to generate some predetermined profit for the sponsor.

14.12  Certain host governments have preferred utilizing Service Contracts (and, to some extent, PSCs) for political purposes, because the host country government retains sovereignty and full ownership rights over the nation’s natural resources. From the host government’s perspective, the Service Contract strikes the advantageous balance of maintaining ownership of the field (and, in most cases, the hydrocarbons produced) while also benefiting from the sponsor’s technical expertise and capital investment. Venezuela, Mexico, and numerous other Latin American countries, and Kuwait and certain other Middle Eastern countries, (p. 391) have, at various stages, implemented a Service Contract to allow sponsors to develop oil and gas reserves.

Licence regimes

14.13  As an alternative to the contract-based regimes described previously, some host governments will, pursuant to applicable legislation, grant the sponsor a licence to develop a licensed area. The most well-known example of this is the UK government granting licences in developing their North Sea oil and gas reserves. A licence can cover multiple fields and be issued to multiple parties who will work together to develop the particular licensed area; the terms of the licence would be subject to prevailing statutes which are in effect. As is the case with contract-based regimes where development plans and annual budgets must be approved by the host government, the licensee under the licence regime will similarly often only have discretion to develop the licensed area on the terms set forth in the licence and upon the approval of the licensor.

Host government agreements

14.14  In the event the sponsor needs to develop infrastructure such as a new pipeline to transport the hydrocarbons to market (and there is no existing pipeline network or operator), the sponsor may seek to enter into a Host Government Agreement (an ‘HGA’). In the case of a pipeline, an HGA is entered into with the government of the country in which the hydrocarbon reserves are located and also with a host government of any other country through which the pipeline must run in order to transport the hydrocarbon from the point of production to an export port. One notable example of such a pipeline is the approximately 1,768 kilometre Baku–Tbilisi–Ceyhan pipeline that runs from land-locked Baku in Azerbaijan via Georgia to Ceyhan on the Mediterranean coast of Turkey and which, reportedly, has transferred nearly 3 billion barrels of crude oil from its offshore terminal in Ceyhan since 2006.

14.15  An HGA for a pipeline typically includes the right to build and operate the pipeline for an agreed term (usually the same term as the underlying contract or licence with the host government), the right of free passage for the hydrocarbons being shipped, and certain protections against any changes in law, expropriation, and environmental and social matters. Many HGAs will also require the sponsor to address environmental and social impacts of such pipelines—whether they relate to displaced local nationals, replanting forestry, or limiting emissions. Similarly, an inter-governmental agreement (an ‘IGA’) may be entered into, although such agreements tend to be much more project specific and often address matters such as assurances of free transit and non-interference, guarantees of performance by any host government entities involved in the project, and protection from expropriation.

14.16  Even with an HGA or an IGA in place though, such pipeline routes are often exposed and vulnerable to uneven political risks and can involve risk factors of national, regional, and even global significance. This is not just because pipelines have tended to run through countries that are geopolitically challenging, but also because the pipeline is the principal means for one country to export hydrocarbons to the market (and, as such, their means to receive sales revenue), and so other ‘host countries’ have used that to create additional leverage for other matters or as a means of gaining influence. The Baku–Tbilisi–Ceyhan pipeline and the Chad–Cameron pipeline provide two good examples of this occurring. Similarly, even in the more advanced North American market, the development of the (p. 392) Keystone pipeline has been highly policitized. Conversely, there are other examples of a host country objecting to a neighbour building, or agreeing to host, additional pipelines as these might create competition and additional capacity in the market that may have adverse impacts for the existing project’s economics. A good example of this would be the tension in Eastern Europe around the two rival pipelines—the Nabucco–West pipeline and the South Stream pipeline.

Joint ventures and joint operating agreements

14.17  Due to the significant costs in exploring and developing oil and gas projects, sponsors normally seek to share investment risks by teaming up with other oil companies, trading companies, and utilities to sponsor the development of the project. In the context of upstream projects, in particular, it is fairly common for each sponsor to invest in the project through a wholly owned subsidiary that, together with wholly owned subsidiaries of the other sponsors, will form an unincorporated joint venture to develop the project.

14.18  The motivation for adopting such an approach stems from a number of reasons, including:

  1. (1)  accounting reasons so that the sponsor can ‘book’ its interests in the hydrocarbon reserves within the total aggregate consolidated reserves of the sponsor group;

  2. (2)  tax reasons so that any losses (most likely to arise in the capital-intensive early stages of developing a project) can be passed through to, and set off against profits made by, the consolidated sponsor group; and

  3. (3)  a desire to retain operational and financial flexibility and control as regards the manner in which the sponsor participates in the project.

14.19  Alternatively, it is also quite common for sponsors to invest in a downstream project by incorporating a project company. The relative rights and responsibilities of each sponsor with respect to the project and the project company will then be governed pursuant to a shareholders’ agreement. The decision to utilize a project company structure is often driven by a number of factors—namely, minimizing tax exposure, limiting liability, and limiting bankruptcy concerns, to name a few. Incorporating a project company, rather than utilizing an unincorporated joint venture, may often be a condition from the lenders in order to secure adequate funding as well.

14.20  The participants in the unincorporated joint venture will govern arrangements between themselves through a joint operating agreement (a ‘JOA’) (as opposed to a shareholders’ agreement adopted where the project vehicle is an incorporated project company). Pursuant to the JOA, the unincorporated joint venture participants are treated as ‘tenants in common’, each having an undivided interest in the licence or contractual arrangements with the host government, the project assets, and any hydrocarbons produced, in each case, in proportion to their participating interest in the unincorporated joint venture.

14.21  A JOA will appoint one participant as the operator who will lead the construction and operation of the project, including the scheduling and loading of the hydrocarbons produced. The operator will take instructions from an operating committee which usually consists of one representative from each participant. Each representative will typically have a voting right on the operating committee that is proportionate to its participating interest in the unincorporated joint venture.

(p. 393) 14.22  The operator leads the development of the project and enters into contractual commitments as agent on behalf of the participants. In order to cover the costs of such commitments, the operator will make cash calls on each participant in proportion to each participant’s participating interest in the project. Each participant is severally responsible for its share of the cash call, and, if a participant does not fund its share, its right to receive any production will (after delivery of certain notices and expiration of certain cure periods) be suspended and, typically, if the non-payment remains unremedied, then the defaulting participant’s interests in the JOA could be bought out, or sold, by the other participants on a discounted basis.

14.23  In order to ensure that the operator has the necessary funds to continue to implement the project though, the other participants are typically also obliged to meet a proportionate share of any unpaid cash call to the extent there is a non-payment from a defaulting participant. Failure to pay such additional amounts may also ripen into a default on the part of such other participants too. Cash calls paid on behalf of a defaulting participant will be reimbursable by the defaulting participant which can be recovered through an increased share of hydrocarbons being allocated to the non-defaulting participants as well as having a direct claim against the defaulting participant and, ultimately, the right to enforce the sale of, or to buy out, the defaulting participant’s interest.

14.24  JOAs also include provisions relating to assignments (including by way of security) and changes of control. Typically, assignments will only be permitted with the consent of each participant and will also be subject to a corresponding assignment of interests under the applicable framework agreement or licence as well, which also gives the host government a consent right over all proposed assignments (including by way of security). Each participant will usually also grant pre-emption rights to the other participants in connection with a direct sale of a participant’s interests in the project or in the event of a change in control of a participant (so that it ceases to be owned by the original sponsor). It is also not an uncommon feature in the oil and gas sector for participants to grant their co-participants a charge, or other similar security, over their interests in the JOA and the unincorporated joint venture (including the underlying licence or framework agreement). Such a charge will rank in priority to other security interests, if any, granted in favour of a participant’s lenders and this can give rise to complexities in developing a deed of priority to govern the competing security interests and claims that a participant and a lender may have against the particular participant.

Sales Contracts

14.25  Participants in an oil and gas project implemented under an unincorporated joint venture are typically granted an entitlement, in proportion to their participating interests, to production and the participants will typically take turns to lift their entitlement to hydrocarbons produced (so-called equity lifting). The operator will organize a schedule for lifting cargos by each participant, and each participant will then sell such product into the open market and retain the proceeds of sale itself; the participant will continue to be obliged to meet cash calls made by the operator, but the participant manages the sale of product and retains the sales proceeds—this is different to projects where the product is sold by, and proceeds received by, a project company.

(p. 394) 14.26  In the event that a participant fails to lift (or waives its right to lift) all or part of the cargo, the other participants will have a right to lift during that period and indeed a participant is usually required to lift such product to avoid the project being required to shut down. The arrangements governing the coordination of lifting schedules and management of inventory in storage (including short-term borrowing and lending of each participant’s portion of product in storage to allow participants to lift product in full cargos) amongst the various participants are set out in a Lifting and Balancing Agreement. Project participants and their lenders are able to take comfort that there is a deep and liquid market for the offtake of oil giving confidence that all project production will be sold.

LNG offtake

14.27  Since the construction of project facilities for each link in the LNG value chain requires significant capital investment, participants have tended to desire long-term commitments that will generate stable cashflows to cover the cost of developing such facilities (including allowing the participants or project company to service its debt obligations).

14.28  Accordingly, long-term LNG sale and purchase agreements (an ‘LNG SPA’) have been a key feature of LNG production projects. LNG SPAs have typically been structured on a take or pay basis between the buyer and the seller for a defined minimum annual contract quantity (the ‘ACQ’), such that if the quantity taken by the buyer at the SPA delivery point during a contract year is less than the ACQ (other than as a result of force majeure or failure of the seller to supply), then the buyer will still be required to pay for the shortfall that it failed to take, usually at the average contract price for that contract year.

14.29  In addition to the take or pay provisions, there will also usually be under delivery provisions in the SPA that require the seller to make payments to the buyer in the event the project fails to deliver the ACQ to the buyer in a contract year (other than as a result of force majeure). The costs of such under delivery payments are usually tied to the cost to the buyer in procuring replacement cargoes in its end market (or, if such a replacement price is not easily identifiable, it will be calculated pursuant to a fixed price formula).

14.30  Historically, LNG projects were developed, and financing raised, on the basis of a long-term take or pay contract with a utility buyer that would import the ACQ under the LNG SPA for use at its own facilities. Utility buyers have become more reluctant to enter into long-term commitments for the sale and purchase of LNG (although it is still recognized that to underpin a new greenfield project, development contracts for the duration of the project finance debt are essential). The onset of new LNG production (in particular from shale gas production in North America) has increased LNG liquidity and led to greater flexibility in contract terms; governmental policy (including shifting away from coal to clean energy such as gas to supplement renewable power) has resulted in the emergence of new gas buyers (being either national oil companies in new gas consumer economies or private sector developers of receiving gas facilities looking to supply gas to the domestic market or as a fuel for power generation). The credit profile of such buyers is vastly different from that of the traditional utility buyers and this has been a new feature in assessing the bankability of LNG liquefaction projects.

14.31  This combination of factors means that there is a ‘new world’ for LNG. Buyers require greater flexibility in managing their portfolio of supplies, being able to reduce their (p. 395) ACQ and seek flexibility to allow a buyer to divert cargos for delivery elsewhere; sometimes this is limited to a certain number of cargos or to limited markets (and, in some cases, host governments have used these provisions as a means of ensuring that LNG produced in their host country is sold in a particular market to enhance political ties and to help develop the particular market). Gas trading companies (including IOCs trading LNG) have now entered the market to purchase LNG for sale into whichever market would generate the best price; these companies have the ability to manage a portfolio of on sales (on a spot or short-term basis) to end buyers, resulting in greater liquidity and flexibility of terms and thereby playing further on the disparity between prices between the relevant markets. Many of the new wave of LNG projects will be structured solely on the basis of equity lifting by the sponsors; lenders will therefore need to modify their approach to financing such LNG projects to understand the new issues that arise.

Petrochemicals projects

14.32  Sales from petrochemical projects have, depending on the relevant market, been structured either on the basis of sales to customers pursuant to short-term or spot sale contracts or on the basis of long-term offtake or marketing agreements entered into with the sponsors or key offtakers. The nature of such offtake arrangements depends on the nature of the product and the markets into which the project is intending to sell products, and the economic analysis is different for an export-driven project located in the Middle East as compared to a project that intends to sell its products into the domestic market. In each case though, lenders to such projects will likely need comfort that the necessary volumes of products will be sold each year to cover the debt and will seek contractual support arrangements (in the absence of long-term take or pay commitments) to give comfort that a certain minimum volume will be successfully sold. In larger petrochemical projects, the diversity of products that a project can produce, which will likely include some expected to sell at higher margins into smaller markets and others that are more ‘commoditized’, spreads the market risk such that lenders are less prescriptive about the project’s marketing strategy and offtake arrangements.

Key Risks in an Oil and Gas Project

14.33  Raising financing for oil and gas projects can be challenging given the multiple components involved. Furthermore, given the huge capital costs of oil and gas projects and the fact that such projects are often implemented in challenging locations (either geographically or geopolitically) it has become necessary for sponsors to raise finance from a variety of funding sources such as Export Credit Agencies and Multilateral Agencies, as well as financiers in the bank and bond markets. To a certain degree, the strength of the sponsor and the extent of the existing commercial relationship with such a sponsor often dictates the ability of an oil and gas project to raise funds, the mix of funds chosen, and the financing terms relevant thereto.

14.34  An oil and gas project shares many of the same features that can be found in other types of projects, although, in addition to the contractual and legal elements already addressed, there (p. 396) are also a number of technical features that are particular to the sector. In implementing an oil and gas project financing, project lenders will need to conduct detailed due diligence (working with independent consultants) on the technical, environmental, insurance, market, legal, and financial elements of the project. Oil and gas sector-specific risks include:

Reservoir risk

14.35  The lenders need to evaluate the risk of the quantity and production profile of the hydrocarbon reserves regardless of whether the project is upstream or downstream. The viability of an upstream project will depend on there being sufficient reserves that can be extracted to produce hydrocarbons for sale. The viability of a downstream project will depend on the sufficiency of one or more sources of feedstock and certainty that such feedstock will be supplied throughout the life of the project. In some cases, a government entity will supply gas to the project (and so the question relates to the size of the reserves of the host government); in other cases, gas is produced from a particular defined production area (often by an entity related to the downstream project company) so that the project is integrated as a whole.

14.36  The lenders will employ an independent reserves consultant to conduct diligence and establish the level of proven reserves, probable reserves, and possible reserves in the field. These reserve levels will then determine, in part, the tenor of any debt that lenders will be willing to provide, as they will want to be confident that their loan will be repaid no later than the date when only, say, 30 or 25 per cent of the proven reserves remain available. This is known as the reserve tail.

14.37  The lenders will also typically require, as a condition precedent to loan drawdown, that the reserves consultant provide (a) a certification of the estimate of reserves and (b) a confirmation that the production profile, and production costs, as set out in the base case model, are reasonable. An update or reconfirmation of the estimate of the reserves and the likely production profile which is acceptable to lenders may also be required to be delivered as a condition to meeting the completion test (and, therefore, the release of any completion support that is provided by sponsors). Material depletion of reserves is often treated as a force majeure event under the LNG SPA.

Construction risks

14.38  The construction phase of a project is generally considered to be the time when something is most likely to go wrong with the project. While a turnkey construction contract to build the project is a common feature in the construction of project infrastructure, including power stations, this is not often possible because of the complex nature of the specialized technology involved in, for example, an LNG or petrochemical project. The development of such projects will involve a number of technical components, such as the use of drilling equipment, the construction of production platforms, floating production storage and offloading (FPSO) units, pipelines, liquefaction, or petrochemical production plants and potentially LNG tankers and regasification plants. No single contractor would profess to have expertise to construct all such elements and, historically, it has not been practicable (or economically feasible) for sponsors to pay a single contractor to wrap the entire construction risk. The sponsors therefore employ different contractors to implement (p. 397) each element of the project and manage the integration process themselves or through the services of a project management contractor.

Completion test

14.39  Due to the complexity of coordinating the construction and integration of each phase of an oil and gas project, in situations where there are multiple phases of a project employing a multitude of contractors, or where each phase is dependent on the completion and operation of another, lenders have traditionally required sponsors to provide a completion guarantee or debt service undertaking to cover the loans until the project achieves ‘completion’.1

14.40  Although sponsors clearly accept greater potential liability as a result of providing a guarantee to pay the loans if the project company is unable to do so, the sponsors enjoy certain benefits too, as loan pricing tends to be cheaper and lenders’ due diligence on (and monitoring and consent rights for changes during the construction phase) will be lighter.

14.41  A completion test, for release of the sponsor support, will focus not only on physical ‘completion’ of the facilities under the construction contracts but also on production of a specific amount of oil or gas over a testing period (such that certain base case assumptions in the financial model are met or, subject to a ramp-up, are likely to be met), the delivery of a specified number of cargoes, and, sometimes in the context of LNG projects, completion of the regasification terminal so that the lenders are assured that all of the elements in the LNG value chain will perform as planned. In certain projects, there may also be a need to update the reserve consultant’s report on the size and production profile of the reserves. In addition, non-technical matters such as the absence of an event of default, compliance with environmental and safety requirements, insurance being in place, and account reserves being fully funded will also be required. Similarly, in the context of petrochemical projects, lenders will likely be very focused on the reliability testing regimes for the purposes of the completion test; the multiplication of units producing different products, particularly where those units are integrated such that one produces a feedstock for another, can result in highly sophisticated tests requiring deep technical and financial analysis of the risks involved with, and the value to the project of, the different units.2

Operation risk

14.42  Lenders can easily contemplate the impact of construction phase risks preventing or delaying the completion of the project. However, once the project starts operation, the lenders will rely on their legal and technical due diligence on the project documents to ensure that the contractual regime in place is robust and sustainable. Lenders find comfort in knowing that proven technology is being used, the operator has ‘best in class’ operating experience, and, most importantly, that the project will be operated at a level of performance that, at a minimum, will meet operating costs and service the debt. Examples of tools that lenders may use to effect these results include retaining approval rights over operating budgets and operating costs, consent rights over changes to the operator or dilution by the (p. 398) sponsors of their investment in the project, and consent rights over material changes to the project documents.

Pricing risk and projected production levels

14.43  Unlike an infrastructure project or a power project which benefits from long-term (and relatively) stable tariff cashflows, pricing is a sensitive topic in an oil and gas project.

14.44  Pricing in oil projects tends to be set by reference to published benchmarks. Platts is one of the most widely used providers of energy information and a source of benchmark price assessments for oil sales contracts. Many petrochemical products similarly benefit from a deep and liquid market, with numerous benchmarks, including Platts, offering transparent pricing.

14.45  The price for LNG varies depending on regional markets with oil indexation being prevalent. For example, if LNG is sold into the US market, it is typically linked to Henry Hub prices, while the Japanese Customs Cleared (JCC)3 benchmark—defined by reference to the average price of customs-cleared crude oil imported into Japan—is the commonly used index in LNG SPAs in Asia. The UK LNG price is linked to the domestic price for gas (the so-called National Balancing Point Price), but much of the rest of Europe tends to link their pricing to a crude oil/pipeline gas index. As market liquidity for LNG sales improves, and LNG projects may be seeking to sell into different markets, it may be necessary for lenders to rethink their approach to modelling project cashflows for the tenor of their debt.

14.46  The pricing of petrochemical projects is more variable again. As noted, certain products are relatively commoditized, but higher margins are likely available in less commoditized products, which incentivizes sponsors to enter more speculative markets. Lenders will therefore likely be very focused on receiving detailed and credible market information from specialist consultants when determining the bankability of the relevant project.

Transportation risks

14.47  In the event that the project exports hydrocarbons through a pipeline that crosses international borders, additional jurisdictional and geopolitical issues will need to be carefully considered. Lenders will need to be comfortable with the protection afforded to the project company under the HGA, the IGA, or other agreements with the relevant governments of the countries through which the pipeline runs.

Other risks

14.48  Numerous other risks will also need to be considered such as tax risks, currency risks, political risks, regulatory risks, insurance risks, and environmental risks. If possible, such risks should be allocated to a participant who is best placed to assume them. On top of this, the lenders will need to be satisfied that the contractual rights afforded to them and to the project will be enforceable on their terms.4

(p. 399) Financial Consideration

14.49  Certain features of an oil and gas project also lead to differences that sponsors need to negotiate with their lenders as compared to other infrastructure sector projects. It is not uncommon to see the following features in the financing of an oil and gas project.

Changes to the project

14.50  While the scope and capacity of an infrastructure or power project is often fixed at the outset—for example, a road project is fixed by reference to the location and the number of lanes comprised in the road, and a power project is fixed by the generation capacity required under the power purchase agreement—it is not unusual for sponsors to want to change the scope of an oil and gas project during the development phase. For example, to expand the project to exploit additional oil and gas discoveries within the production period so as to increase overall hydrocarbon production, or to bring new capacity into the existing LNG plant by adding one or more additional LNG production trains, or to add additional petrochemical processing plants.

14.51  The project company may also be required, pursuant to applicable law or prevailing good industry practice, to make periodic capital expenditures to comply with new environmental emission standards or to maintain productivity and competitiveness at the project. As a result, loan documents will often give the project company, subject to satisfying certain conditions, the ability to implement such changes in the project and, subject to meeting relevant conditions, to incur more secured debt to finance the cost of implementing such changes. Without such flexibility, the project company would need to obtain lender consent to such changes and that can be particularly challenging in a multi-sourced financing involving a wide variety of financiers.

14.52  Lenders are typically concerned that the proposed change or major capital expenditure will not have a negative impact on the existing project and its production levels. In addition to receiving a certificate from an authorized officer of the project company certifying the absence of such adverse impact, lenders will usually require a confirmation from an independent consultant as to such matters. Moreover, in the context of an expansion at an LNG or a petrochemical facility, long-term LNG SPAs and other offtake agreements may need to be put in place for all, or a high percentage of, the new production (just as is required when the initial financing is provided).

14.53  Having achieved the flexibility to make changes to the project, the project company will need to negotiate the means to finance the costs of such change. A key tension will be the ranking in the cashflow waterfall (that determines the ranking of various payments to be made by the project company vis-à-vis the payments to be made for the project debt) of payments associated with such project changes;5 borrowers typically want such payments to be made near the top of the cashflow waterfall (in priority to debt service) while lenders prefer payments to come after debt service and, optimally, at the level at which restricted payments are made to the sponsors after satisfying various restricted payment conditions.6

(p. 400) Additional debt

14.54  In addition to using its own revenues to pay for a change or an expansion to the project, the project company may wish to incur new debt to finance the cost of changes or expansion to a project. The sponsors may also seek to replace existing debt with new debt available on more favourable or cheaper terms. Conditions typically imposed upon a project company before it can incur additional debt include the absence of a default under the loan agreement, satisfaction of a debt service coverage ratio and loan life coverage ratio, the tenor being no shorter than the existing debt, and so on. In some cases, lenders seek to cap the amount of debt that can be incurred, but a wise project company would negotiate against an arbitrary cap given that future costs of a change cannot be predicted and the true benchmark for incurring new debt should be the ability to meet debt service cover ratios.

Restricted payments

14.55  Typically in an infrastructure project the project company is only permitted to make restricted payments of dividends to the sponsors after the project has achieved ‘completion’ (which is when the revenues of the project company start).7 However, in an oil and gas project, significant revenues can be generated prior to the date when the entire project is operated because LNG production trains or petrochemical processing plants come online in succession. Accordingly, sponsors seek to obtain flexibility to allow the project company to pay restricted payments to sponsors before the project is completed as a whole and the completion test is met.

Financial ratios

14.56  As oil and gas projects can be exposed to significant price fluctuations, financial coverage ratios have also tended to be higher than, for example, projects in the infrastructure sector where the main revenue-generating contract includes a predictable tariff payment during the entire tenor of the debt. Given the volatility of the price of product produced in an oil and gas project, it is also not uncommon to require mandatory prepayment to the lenders out of excess cashflows (when the price of the product is high) as a mitigant to the risk of down cycles in product prices.

Other market trends

14.57  Other current market trends include the following:

  1. (1)  The volatility in commodity prices over recent years has had a meaningful impact on the oil and gas industry in a number of ways. Fewer large-scale projects have achieved a ‘final investment decision’ because cashflow projections (during the low price environment) often did not generate the necessary levels to justify sanctioning the major capital expenditure required to develop a project; moreover, the projections did not generate cashflows to meet the cover ratios required by lenders to support a debt financing of a project.

  2. (2)  Uncertainties compounded by the massive and sudden drop in oil prices as well as teething problems encountered by many projects achieving completion during such (p. 401) low price environment made banks cautious about embarking on new projects in the sector when many of their existing projects were under stress.

  3. (3)  Contractors and service providers in the oil and gas industry have seen diminishing workload and reduced margins. This pricing pressure has resulted in rigs, LNG vessels, and construction equipment being less than fully utilized.

  4. (4)  Downward pressure on pricing in offtake/sales contracts has been commonplace with assertive buyers looking for shorter-term LNG SPAs or more flexible pricing arrangements to reflect increased market liquidity.

  5. (5)  Consolidated and joint venture activity has become commonplace across the market. For example, Shell acquired British Gas in February 2016 and ExxonMobil acquired InterOil in February 2017.

14.58  However, the negative trend appears to be reversing. The global appetite for energy continues to grow unabated and, as oil prices continue to creep upwards, and the consequences of fewer new oil and gas projects being commissioned are felt, it may be that sponsors look again to take advantage of cheaper construction costs, with banks and other financiers wanting to provide financing as confidence in the oil and gas sector resumes.

Section B—Mining Projects

Alexander Borisoff, Manzer Ijaz, and Emily Whittaker, Milbank LLP

General Overview

14.59  The previous chapters have surveyed the principles of project finance in their broadest sense. In this section, focus turns to their application in a specific sector: mining. While these broad principles are, of course, applicable to mining, there are, naturally, features unique to the mining sector that require that those principles be tailored to meet the specific challenges that projects in this sector present.

14.60  The key features that distinguish projects in the mining sector include that they:

  1. (1)  can have a material impact on the physical and social fabric of the locality in which they are situated;

  2. (2)  generally combine a range of technologies and encompass significant civil works, often subterranean, and thus it is often impracticable to allocate completion risk onto a single contractor or consortium;

  3. (3)  are frequently located in remote parts of the globe, often in jurisdictions that feature untested legal regimes and that lack political stability; and

  4. (4)  are generally exposed to the market price of their commodities, which are frequently subject to short-term volatility as well as changes that mirror macro-economic cycles.


14.61  Thought of, traditionally, as the extraction and production of industrial and precious metals and minerals, mining is well suited for project financing. It requires vast amounts of (p. 402) capital, it takes a long period of time for mines to reach productive capacity, and the scope of the industry is global. When undertaken on a large scale, mining can have far-reaching and long-term environmental and social impacts, and can carry significant political risk. Further, it is complex to plan, construct, and operate a mine, with a single project often involving multiple owners, numerous sources and providers of financing, various methods of risk allocation (including political risk insurance), and different buyers in target markets the world over.

14.62  Historically, international project finance has grown largely out of financing mines, and one can look all the way back to 1299 ad for an early, primitive example. The English Crown took out a loan, from an Italian merchant bank known as Frescobaldi, in order to finance the development of the Devon silver mines. Frescobaldi was granted a one-year concession, with its loan to be repaid from the output of the mines.8 Suffice it to say that both project finance and the mining industry have come a long way since then.

Environmental and Social Impact

14.63  Most large-scale projects entail some degree of environmental and social impact on the locality in which they are situated. Mining projects in particular, due to the size, scope, and intensive nature of mineral extraction, can have extensive long-term environmental and social impacts. Dramatic change to the area will likely be apparent from the start of construction due, among other things, to the clearing of what may be large swathes of land that, in turn, may involve the displacement of whole communities.

Environmental impact

14.64  The construction, operation, closure, and abandonment of a mine, as well as the processing of ore removed from a mine and the shortcomings of tailings storage facilities, often have a severe and long-term impact on the environment.

14.65  Mining frequently requires the use of explosives and hazardous materials and, as a result, can lead to significant contamination of soil, groundwater, and surface water, as well as the degradation of drinking water quality, soil quality, and fertility in the region. Further, the sheer volume of material involved in strip or surface mining makes the impact on the environment especially acute, including overburden and waste rock disposal problems. Underground mining, meanwhile, causes vast amounts of waste earth and rock to be brought to the surface, which, again, must be disposed of.

14.66  Mines are often located in remote areas and can require significant deforestation and the construction of roads and other means of transportation in previously undeveloped areas. In conjunction with the mine itself, this can directly and indirectly have a severe adverse impact on local flora and fauna, which, in turn, can affect the ecosystem and its stability, as many species are impacted due to toxicity of water and soil, loss of habitat, and leached trace elements.

(p. 403) 14.67  Even after the decommissioning or closure of a mine, short- and long-term action and monitoring may be required to ensure the area mined is returned, so far as is possible, to its original state. Reclamation of these areas can be costly and difficult after a mine ceases operation. Although reclamation seeks to return vegetation and wildlife in previous mining lands to the state before mining began, surrounding areas can often be rendered unsuitable for future industrial, agricultural, or residential usage due to erosion, leaching, the failure to reclaim, or otherwise. Repairing damage done to the environment can be a long, arduous, and problematic task. Nonetheless, the damage can often be undone, or at least prevented or limited, through proper mitigation, planning, and action.

14.68  Mining projects, by their extractive nature, tend to fall into Categories A or B of the Equator Principles,9 and can require a comprehensive assessment of the environmental impact and an environmental action plan spanning the entire life cycle of a mining project. The nature and degree of the impact should be taken into account when planning a mine.

Acid mine drainage (AMD)

14.69  AMD refers to the movement of acidic water, containing hazardous materials, flowing from current, abandoned, and closed mines. It can disrupt the growth and reproduction of aquatic plants and animals; corrode local infrastructure; contaminate drinking water, rendering it unfit for consumption; and lead to toxicity to humans and wildlife exposed to it. The Iron Mountain Mine in California, which began operations in the 1890s and closed in 1963, provides one such example of the potential adverse impacts of AMD. Water passing through the mine site is estimated to have caused the death of one hundred thousand or more fish on separate occasions in 1955, 1963, and 1964, with at least forty-seven thousand trout having died during one week in 1967 (that is, post-closure of the mine). Although significant efforts have been made to address the issue of AMD at the site, US Geological Survey scientists estimate that the former mine could continue to produce AMD for 2,500–3,000 years, until the estimated 12 million tonnes of sulphide deposits have weathered away.10


14.70  One of the most notable pollutants associated with mining is tailings. These are the residual materials left over once the valuable fraction of an ore has been separated from the uneconomic fraction, often taking the form of slurry (though composition will vary depending upon the type of mining and the method of processing). Controlling and ultimately disposing of tailings is a crucial consideration in mining. Most commonly, a disposal facility will take the form of a tailing pond, whereby a dam is constructed so as to stem the flow of tailings, and the hazardous materials are collected in one place. However, as with dams in any context, there is the risk of failure, and tailing dam failures can be catastrophic, leading to landslides and toxic contamination. Although safety standards have by and large improved over time, there are nonetheless recent examples of failure. One such instance occurred in Canada, where Imperial Metals’ Mount Polley mine’s tailings dam broke in 2014, (p. 404) flooding Lake Polley, Hazeltine Creek, and Quesnel Lake with 24 million cubic meters of mining waste.11 In Brazil in 2015, the Samarco dam failure released 50 million tons of toxic iron tailings into the Doce River, killing nineteen people and leaving more than 500 miles of the Doce River contaminated in what has been described as Brazil’s ‘worst environmental disaster ever’.12

Climate change

14.71  Climate change is already having an impact on the mining industry and such impact is likely to become ever-more significant in the future.

14.72  Flooding can devastate mines, and climate change is liable to increase the instances of catastrophic floods. Those mines situated in coastal areas will be particularly vulnerable to a rise in sea levels, while mines in all areas could potentially be affected by an increased risk of flooding due to the growing frequency and severity of extreme weather events. Beyond flooding, climate change has the potential to increase the duration of droughts and heatwaves. Damage to infrastructure and, specifically, transport links, by extreme weather events could disrupt supplies to mines and increase the risk of tailing dam failures.

14.73  Since the spotlight on climate change has only intensified in recent years, the risks mentioned were not generally taken into account during the design, construction, and operation of most mines. Existing mines, and particularly those dating back many years, were likely not designed to cope with extreme weather patterns and other risks that were not of such imminent concern at the time of construction. Increasingly stringent regulatory changes are therefore likely to be implemented in the near future, including, at the bare minimum, a strong focus on tailing ponds and open pit design, with the intention of creating safeguards against extreme weather.

Social impact

14.74  Along with the environmental impacts discussed previously, mining projects may also adversely affect the local community from a health and safety standpoint. Further, given the social change such projects entail, relations with the community need to be carefully managed and can, at times, become fraught.


14.75  A mine can have a profound impact on local inhabitants. First and foremost, construction may involve displacement and resettlement of people. Where this is compulsory, particularly with respect to indigenous communities who may attach significant cultural and spiritual value to the land, resentment and opposition to the project is a foreseeable consequence. This will be exacerbated if displaced residents are resettled in an area in close proximity to the mine and are therefore directly exposed to any pollution, contamination, or other health hazards.

(p. 405) Water usage

14.76  Mining typically requires vast quantities of water. The mining industry has been estimated to use between 7 and 9 billion cubic metres of water per year, which is equivalent to the amount of water that an entire country such as Nigeria or Malaysia uses in total in the same period.13 This level of usage forms part of the wider discussion regarding competing needs for water worldwide.

14.77  In those areas of the world where water is in short supply, competing needs for water can give rise to opposition to new and existing mining projects, and relations with farmers in particular are likely to be put under strain where fresh water is diverted away from farming activities and instead used in connection with the mine. By way of example, the Tia Maria copper project in Peru was suspended in 2011 and again in 2015, following deadly protests by local farmers and residents fearing the contamination of regional water supplies.14 An injunction blocking the development of the project was lifted in 2018, and production is expected to begin in 2021.15

14.78  In an effort to solve fresh water supply issues, mining companies increasingly view seawater desalination plants as key features of their operations. This is, perhaps, most notable in the notoriously dry Atacama Desert of Chile, where each of the Esperanza, Sierra Gorda, Antucoya, and Spence copper mining projects incorporated a desalination component. BHP, for instance, built a seawater desalination plant for use in its Spence mine, which is expected to add 50 years to the mine’s productive life.16

Employment and population growth

14.79  One of the principal benefits of mining is that it often boosts employment within the surrounding area. Yet one should consider the sheer scale of upheaval such a project is likely to entail. Where an area is disproportionately reliant on a mine, that may be the only employer in a region (or at least the only employer regarded as stable and paying competitive wages) which is likely to attract economic migrants. According to the International Institute for Environment and Development, after construction of the Grasberg mine in Indonesia, the local population rose from less than 1,000 in 1973 to over 100,000 by 1999: there has been speculation that this rapid rise in population was among the factors leading to violent uprisings in the area during that period.17

(p. 406) Public health

14.80  An increase in population (particularly one that occurs rapidly) will have implications for local health. Notwithstanding the possible improvement of health standards over time (owing to increased access to medicines and new or enhanced health infrastructure to cater for mine workers), an influx of workers may bring with them a range of diseases to which the indigenous population may be particularly vulnerable.

14.81  Focusing specifically on HIV/AIDS, the general view in Southern Africa is that there is a correlation between the spread of these diseases and the operation of a mining project. However, given the contrasting findings from various reports and the lack of available and reliable data generally, it is difficult to comment on the veracity of such a view.18 In any case, the perception persists.

14.82  Turning to the impact of the Ebola epidemic in 2014, across Liberia, Guinea, and Sierra Leone—three nations at the epicentre of the outbreak and whose economies are closely-tied to mining—iron ore mines run by AcelorMittal, Vale, and London Mining were shut down and employees were evacuated or put on leave.19 The impact of the Ebola outbreak on the mining sector (exacerbated by other factors such as a global fall in commodity prices) contributed to significant contractions in the economies of Liberia, Guinea, and Sierra Leone.

Safety concerns

14.83  One should also not lose sight of the fact that mining always has been and, despite enhanced safety standards, remains a potentially dangerous venture, particularly where underground activities are concerned. Where subterranean mines are poorly ventilated, miners can be exposed to very high temperatures, harmful gases, and dust, which can lead to severe injuries and, in extreme cases, death. The noise generated by equipment, particularly in such confined spaces, can also lead to hearing difficulties. In addition, as one might expect given that mining involves the displacement of rock, there is a persistent risk of cave-ins and rock fall.

Industry responsibility

14.84  Though it will be a feature of any significant project across all sectors, there is intense focus on, and scrutiny of, the environmental and social impact assessment report in mining projects. Naturally, host governments will be keen to secure assurances from the project company that it will adhere to strict environmental and social guidelines and limit the impact of the project to the maximum extent possible. Such governments may find powerful allies in commercial lenders, export credit agencies (ECAs), multilateral agencies, and development finance institutions,20 for these institutions, too, have a strong interest in ensuring that the project complies with the most stringent environmental and social standards. On the one hand, there is a simple commercial consideration: environmental and social issues are costly and time-consuming to remediate, (p. 407) while sponsors and lenders will want revenues to be used to service debt and to generate equity returns. At the same time, however, this is a matter of reputation. A lender will understandably not wish to be associated with a project regarded to be environmentally and socially harmful. It is, therefore, unsurprising, in the context of 197 countries signing up to the Paris Agreement on climate change21 and non-governmental organizations, such as ‘US Beyond Coal’ and ‘Europe Beyond Coal’, becoming more vocal in their missions to promote awareness of climate change and to tackle coal pollution, with goals to ensure a coal-free Europe, and a coal-free US power grid by 2030,22 that prominent lenders and an increasing number have recently distanced themselves from the coal industry. However, as the project company and its sponsors share similar concerns in respect of reputation and corporate social responsibility, at least theoretically, the interests of all parties should be aligned.

14.85  As with other industries, compliance with the Equator Principles and IFC performance standards is now, in effect, a prerequisite when seeking to syndicate a financing, and project finance documentation will often contain comprehensive environmental and social covenants.23 Additionally, the project company will be aware of its corporate social responsibility. It is arguably the latter, a form of ‘soft’ self-regulation, which provides greatest reassurance in practice to the population. Where mining companies follow mandatory or voluntary environmental and social guidelines, and take the time to engage in meaningful and lengthy consultation with local communities, they are able to gain credibility and demonstrate that the project is intended to be of mutual benefit rather than a one-way street. This should, of course, be a proactive and ongoing process, taking place at the earliest stage possible with communication on a regular and continuing basis.

14.86  In terms of the image of the industry, efforts have been made to increase transparency. The Extractive Industries Transparency Initiative (EITI)24 is an organization that has been set up to improve openness and accountability within the extractive industries. Many countries and companies are implementing the EITI, which seeks to ensure full disclosure of taxes and other payments made by companies in the extractive industries to governments, with the intention being to enable the population to see exactly the value of the industries. Further, by setting out payments in black and white, it should assist identification of any alleged impropriety.

Completion Risk

14.87  There are many practical difficulties in exploring a site, developing and constructing a mine and associated infrastructure, operating it, and, ultimately, reclamation and closure. (p. 408) Setting up a mine is not an endeavour to be undertaken lightly: it is expensive, labour-intensive, and takes years to achieve.

14.88  The practical difficulties are put sharply into focus when one contrasts a mining project with a relatively simple power project, whereby the required equipment can be sourced from one contractor who will also be able to undertake construction. In such circumstances, a turnkey contract should be attainable. Conversely, mining frequently requires the use of highly complicated technology, and equipment may need to be sourced from multiple disparate suppliers. As such, the mining company might find that an EPC contract is either unavailable or, in any event, prohibitively expensive because no single contractor or consortium is prepared to take responsibility for the design, construction, testing, and commissioning of the entire project. Consequently, mining projects often rely on engineering, procurement, and construction management (‘EPCM’) contracts pursuant to which construction activities are managed by a single third party (or the sponsor itself). As an EPCM contractor provides a professional service but does not itself take direct and sole responsibility for the overall execution of the construction process, such constructs work well where the sponsor absorbs completion risk.

14.89  As completion risk must sit somewhere to the lenders’ satisfaction in order to have a bankable project, in mining projects, it is common for sponsors to be required to provide completion guarantees.25 Naturally, the terms will be negotiated carefully. The criteria used to ascertain completion will be crucial: the lenders will not want to release the sponsors from their obligations unless they are certain that completion has been achieved, while the sponsors understandably will want such a liability to be released as soon as possible. Because it takes time for a mine to ramp up production, it is difficult to assess when it is ‘complete enough’, and inevitably there is tension in ascertaining this important point in the life of the project. Lenders will generally wish to be reassured as to, inter alia: output projections; reliability of operation; compliance with environmental and social obligations; completion of relevant security filings; funding of required reserve accounts; and the adequacy of the full marketing chain, with each element to be tested rigorously.

14.90  As an alternative form of completion support, the sponsor may provide a debt service undertaking. Both completion guarantees and debt service undertakings are intended to cover debt service when due and only allow the debt to be accelerated in certain limited circumstances. However, lenders sometimes view the latter as a less ‘absolute’ form of completion support. This is because the effect of a typical debt service undertaking is that, if the project does not achieve ‘completion’ by the required backstop date, the loan to the project company effectively becomes a loan, that is, sponsor recourse from that point onwards. Most typically, the sponsor assumes such obligations, either in accordance with the current debt repayment schedule subject to the imposition of further financial covenants or on an accelerated basis. The extent to which debt service undertakings will be acceptable to lenders will depend in large part on the identity of the sponsor in question, its negotiating power, and the commercial dynamics of the particular transaction.

14.91  In some cases, particularly in financings where ECAs or multilateral agencies either provide loans directly or provide political risk cover in respect of commercial bank loans, sponsors (p. 409) may seek relief from their obligations in respect of completion support if the inability of the project company to complete the project or service its debt results directly from certain specified political risks. There is not, however, a market-standard for ‘political risk carve-out’ regimes of this sort. In general, lenders will expect sponsors to assume the country risks associated with the location of a mine; the circumstances in which such a carve-out might be obtained would likely be where there are specific instances of heightened risk.

Reserve Estimates and Market Risks

14.92  Successful project financings rely on the generation of revenues being sufficient to repay debt. Therefore—as is true not just in mining deals but also in power, infrastructure, and oil and gas projects—factors that may affect the reliability of revenues will be of concern to lenders. This may be a truism but is nonetheless worth stating as a fundamental principle when analysing risk. While unforeseen issues will inevitably arise over the course of any project, particular characteristics of the mining industry and commodity markets render certain risks foreseeable at the outset.

Uncertainty of the reserve

14.93  It is important, first, to distinguish between two concepts: resource and reserve.

14.94  A mineral resource is a solid material (including precious metals, coal, and diamonds) of economic interest in or on the Earth’s crust in such form, grade, or quality and quantity that there are reasonable prospects for eventual economic extraction. Resources are categorized by the level of confidence which geologists have in them, ranging (in ascending order of confidence) from ‘inferred’, through ‘indicated’, and up to ‘measured’.

14.95  A mineral reserve is the economically mineable part of a measured or indicated mineral resource, demonstrated by a preliminary feasibility study or a feasibility study. The reserve includes diluting materials and allowances for losses that may occur when the mineral is mined. As with the resource, the reserve is categorized according to confidence, ranging in this case (again, in ascending order) from ‘probable’ to ‘proven’.26

14.96  ‘The resource is the basis of the reserve estimate, which is the prime tool used by [lenders] to judge if a project can be debt financed’,27 but, problematically, and despite highly sophisticated modelling, estimating the reserve is an inherently uncertain exercise. Indeed: ‘The levels of accuracy associated with preliminary feasibility studies are often quoted in the range of plus 50% to minus 30%.’28 Thus lenders find themselves in the unenviable (p. 410) position of extending (often vast) sums of debt based on a value which is uncertain, yet of critical importance.

Volatility of commodity prices

14.97  As the prices of established mining products pick up following a decade of negative trends,29 we see the focus of the mining sector turning away from the restructurings of existing mines in Africa and Latin America, towards the development and financing of greenfield mines in, amongst other jurisdictions, Chile, Ecuador, Panama, Peru, Guinea, Mauritania, South Africa, Canada, Australia, and the UK.30

14.98  Mining activity correlates strongly with rises and falls in commodity prices, which are renowned for being highly volatile. In other words, common sense dictates that the risks of undertaking a mining venture can be more easily justified when the prospect of reward is great, owing to high prices; however, when a mine comes into operation and the project company is selling its product, the inevitable cyclicality and frequent volatility of commodity prices will (absent offtake arrangements or hedging whereby the project company is insulated from market risk) often result in uncertain and fluctuating revenues.

14.99  Mining is therefore unique in that the parties embark upon a project without knowledge, or even a strong indication, of what revenues will be generated. This can be contrasted with a power deal (in which the project company enters into a long-term power purchase agreement with a creditworthy offtaker) because, whereas in such a deal the lenders will feel confident that repayments will be met, they will be more cautious where a mining project is concerned: price volatility represents a significant risk which often cannot be mitigated. As a result, lenders will generally focus much attention on revenue forecasts, applying significant discounting to current and forecast price projections to determine the prudent level of debt capacity for the project under assessment.

14.100  This volatility is evident not just in more common base and precious metals (e.g. copper; gold), but across the spectrum of different minerals. Recently, there have been forecasted surges in demand for cobalt and lithium (the key components of lithium-ion batteries) which has led to miners rushing to produce these two commodities.31 The price of antimony, used to make lead-acid batteries, has also been increasing,32 as has the price of tin, used for electronics.33

(p. 411) 14.101  The demand for lithium is predicted to increase more than threefold between 2017 and 2025, to 669 kilotons lithium carbonate equivalent (LCE), from 214 kilotons LCE.34 Likewise, the demand for cobalt (formerly extracted as a byproduct of copper and nickel) is predicted to increase by 60 per cent over the same period, rising to 222 kilotons refined metal equivalent from 136 kilotons refined metal equivalent.35 This is largely driven by the ‘electric vehicle revolution’ and the gravitation towards a world powered by renewable energy. For example, China, the world’s largest automobile market, is pushing forward with its intention of becoming a global leader in the manufacturing and consumption of electronic cars. It has introduced quotas and incentives for consumers and manufacturers of ‘green cars’ and aims to make one-fifth of its 35 million annual vehicle sales new energy vehicles by 2025.36 Meanwhile, Saudi Arabia is in the process of constructing ‘Neom’, a 26,500 square kilometre futuristic city, powered entirely by renewable energy and serviced by artificial intelligence and automated vehicles. It is important to note, however, that demand for specialty minerals is subject to new developments and the impact of disruptive technologies: although the value of zinc, for example, has been predicted by the World Bank to decline in the coming years,37 should zinc-air batteries overtake lithium-ion batteries in popularity38 this may not continue to be the case.

Resource Nationalism and Political Risk

14.102  The one feature of a mine that cannot be contracted or even wished away is its location: clearly, minerals can only be mined where they are located. If this means that companies must engage in business in locations that pose logistical, political, or security risks, then these are risks that must be assessed and mitigated. However inconvenient, no project can be divorced from its geopolitical context. For instance, in 2018 the Supreme Court of Panama overturned Law 9—the basis for the concession to Minera Petaquilla SA (also known as ‘Minera Panama’) for the development of its Cobre Panama copper project—following a claim that the law was unconstitutional. The ruling may not affect the validity of the concession,39 which was renewed for another 20 years in 2017,40 but it does highlight the interrelation between mining projects (notwithstanding the solidity of concession agreements) and geopolitics.

(p. 412) 14.103  Similarly, where mining is concerned, the historical context should not be ignored: the shadow of colonialism hangs over the industry. Although the circumstances are entirely different, in that nowadays mining companies negotiate with host governments in order to obtain concessions just as other companies strike commercial deals with their counterparties, governments will nonetheless be sensitive to a recent past where matters were one-sided.

Resource nationalism

14.104  Essentially, resource nationalism encapsulates the idea that a resource (such as minerals) should be for the benefit of the local population. Therefore, where mining companies are granted concessions, the government granting such concessions should be focused on securing the best terms for the benefit of the local population. This should, of course, not be surprising: in any commercial negotiation, each side will wish to secure favourable terms for itself and its stakeholders. Of greater concern in this particular context, however, is how such resource nationalism sometimes manifests itself over time.

A global phenomenon

14.105  At the 2014 ‘Investing in African Mining Indaba’, the Chief Executive of Randgold Resources, Mark Bristow, stated that: ‘[T]he mining code reviews of the past few years and those currently underway in a number of African countries have undoubtedly aggravated … uncertainty by creating the impression that their governments not only want a bigger slice of the pie; they want to take that before the pie is even baked.’41 In the Democratic Republic of Congo, for example, a new mining code introduced in June 201842 removed a stability clause that exempted mining license-holders from having to comply with changes to the country’s fiscal and customs legislation for ten years, introduced a 50 per cent tax on windfall profits, and gave power to the mines minister to increase royalties on ‘strategic’ minerals.43 The cobalt-rich nation introduced these reforms as the demand for the mineral surged to make batteries for electric vehicles.44 Tanzania also introduced legislative reforms to its Mining Act in 2017 which limited foreign ownership of mining projects, temporarily suspended the issuance of mining licences, and banned exports of metal concentrate, forcing companies like gold-producer Acacia Mining to scale back operations, which resulted in millions of lost earnings.45 In April 2018 the power to issue mining licences was reinstated in the newly formed Mining Commission,46 which will also oversee the changes to the Mining Act. The Mining Commission has since (p. 413) approved thousands of mining licences, including to foreign mining companies47—though it is unclear what action (if any) will be taken to reduce the impact of the legislative reforms on foreign investors.

14.106  Yet, it is important to note that while these examples are current, governments may change course depending on market developments, responses from commercial and civil interests, and the political landscape. Furthermore, one should not labour under the misapprehension that such concerns only apply to investment in less economically developed countries. Well-established and stable democracies, with a strong tradition of the rule of law, may also aggressively seek to protect their own interests, taking whatever actions they deem necessary. Australia’s resource super-profits tax is an example of this. In 2010 the government of the day proposed a 40 per cent tax on ‘super profits’ (i.e. those exceeding a certain level), but was met with a fierce lobbying response and threats from mining companies to postpone or cancel investment altogether. This resistance created political pressure, prompting the government, in effect, to dilute its plans and introduce instead a mineral resource rent tax (MRRT), with a lower headline rate of 22.5 per cent and targeted only at iron and coal projects,48 before eventually repealing the tax altogether in September 2014.49 The Australian example serves to demonstrate that the mining lobby does have a powerful voice but that even efforts at compromise do not go far enough for some. It is clear that resource nationalism is a global issue.

Interrelationship with the cyclicality of commodity prices

14.107  Higher commodity prices might be thought to increase the appetite of governments to intervene in mining projects.50 To some, this will appear nakedly opportunistic. Adherents to such a view would emphasize the importance of having struck a deal at the outset, the terms of which should be sacrosanct. However, the counterargument would be that it is impossible to set in stone at the very beginning of the project terms which will remain fair to both parties as the project progresses over decades; circumstances will change dramatically and renegotiation in such cases might be regarded as equitable and sensible. In any case, whatever one’s view as to the legitimacy of such actions, the reality is that host governments are challenging vulnerable long-term commercial agreements in a variety of ways. The government may introduce rules whereby state-controlled entities must, by law, have an equity stake in project companies. Alternatively, governments may increase existing, or introduce new, taxes. On the most extreme end of the interventionist spectrum, a state may even confiscate assets of the project company or bring a private enterprise, or part thereof, into state ownership. This was the case in Bolivia in July 2012, when president Evo (p. 414) Morales announced the nationalization of South American Silver’s Malku Khota silver-indium mine.51 Similarly, in 2018 the nationalization of Indonesian gold-copper mine, Grasberg,52 was announced; 51 per cent of the ownership interests in the mine were expropriated from Freeport-McMoRan and Rio Tinto who were running it as a joint venture and given to state-owned mining company, Inalum.53

14.108  However, cyclicality entails both rises and falls in prices and the latter too can cause issues. Given that commodity prices can be said to be a function of global economic activity, which is beyond the control of individual states, governments can find themselves under pressure when faced with declining revenues, particularly if they have committed themselves to increased expenditure which can no longer be sustained. Compounding matters, countries which find themselves reliant on the trade of commodities can be afflicted by what is known as ‘Dutch disease’, a phenomenon whereby exchange rates strengthen and, in turn, the stronger currency has an adverse effect on the rest of the economy (the manufacturing sector, in particular). To insulate themselves, at least to some degree, against such risks, governments will seek to diversify their economies. Yet this is easier said than done. Even in countries which appear to have more balanced economies, such as Australia, there is an acknowledgement of the need to guard against it.

14.109  The previous paragraphs focus on the impact of cyclicality from the perspective of the host government. However, mining companies will of course be acutely aware of commodity prices and what they mean to their business. Companies will focus on attempts to cut costs during periods when revenues are reduced, with the most effective method of achieving this being either reduction in the scope of projects, delay, or even cancellation. Known as ‘capital strike’, such paring back of operations is liable to place a strain on the relationship with the host government, who may in turn retaliate by threatening to withdraw mining licences. Attempts to reduce labour and other costs are similarly likely to prove controversial. Labour disputes relating to pay and conditions have been common in recent times,54 (p. 415) while budget constraints in other areas may have a detrimental effect on the social and environmental performance of the mine, which can only have a further adverse effect on relations with the local population.

Political risk mitigation

14.110  Project documentation will frequently seek to put in place protections against such expropriatory measures. In some cases, the concession agreement may feature change of law provisions, so that the host government is obligated to compensate the project company where it introduces new, or amends existing, laws or regulations which adversely affect the project company’s interests. While in theory this should offer protection, such provisions are likely to be controversial and, if triggered, likely to be the subject of dispute. No government will want to cede, or be seen to cede, sovereignty to foreign companies. The government will insist that it retains the right to make new laws and, a fortiori, new governments will not want to be bound by the terms of a deal struck by a previous administration.

14.111  The participation of ECAs and multilateral agencies as lenders in and of itself can be viewed as a risk mitigant. For example, ECAs often provide guarantees in respect of losses arising as a result of political risk events. Multilateral agencies, on the other hand, purport to enjoy ‘preferred creditor status’, ensuring de facto preferential access to foreign currency should a foreign exchange crisis afflict the host country. As a result, loans from multilateral agencies (including those portions sub-participated to commercial lenders) may be exempted from sovereign debt reschedulings.55 At a more general level, involvement of such institutions may be said to offer protection against expropriation, owing to the influence that they have with host governments.

14.112  In addition to that which can be provided by ECAs and multilateral agencies, political risk insurance (‘PRI’) is also available in the specialized private insurance market. To claim under a PRI policy, the insured will, however, often be required to demonstrate that the governmental action or inaction that gave rise to the political risk event falls within the coverage of the policy, prove causation of loss, the inapplicability of exclusions, and show that it complies with its obligations under such PRI policy. So, although a traditional risk mitigant, PRI most certainly should not be viewed as a panacea, irrespective of the insurer, given the sometimes time-consuming process of making a claim and its limitations.56

14.113  Risk mitigation is further bolstered where investment treaties are in place. Such treaties will frequently provide for fair and equitable treatment of foreign investments and against expropriation and generally discriminatory measures, while a notable benefit of falling within the scope of such treaties is that they may enable private investors to initiate arbitration proceedings (even where not provided for in project documentation).57

(p. 416) Terms of a Mining Financing

14.114  The previous paragraphs highlight many of the risks that a mining project entails, of which lenders will be acutely aware. Although no two deals are the same, there are certain matters that need to be addressed in every mining deal and, therefore, there is a degree of commonality with respect to the documentation underlying project financings across the sector.

14.115  It is impossible to set out, definitively, the scope of a mining project at the outset: parameters will change. For example, mining companies will be acutely aware of economic conditions and commodity prices, and, where circumstances dictate that it would be favourable, may seek to expand operations (which might require the use of different technology and equipment). This will require capital and, in the event that the sponsors cannot, or would rather not, provide this themselves, further debt will need to be incurred. Sponsors will often seek assurance in the finance documentation that flexibility will be afforded to them to accommodate the evolution of the mine in the face of changing market and technical dynamics.

Financial ratios in a mining context

Use of LLCRs and DSCRs

14.116  As discussed in further detail in paragraph 14.117, the determination as to which (if any) financial ratios58 lenders may require and when they will require these to be applied, must be considered in the context of whether the project is sponsored by mining ‘majors’ or ‘juniors’, as well as other factors including the resource life, geopolitical risk, or the metal being produced. The key assumptions as to commercial matters that will affect the financial performance of the project company, and thereby influence the choice and levels of these ratios when applied, are generally (i) the cost of mining and processing the resource, (ii) the experience of (and financial resources available to) the project company and/or the sponsors, and (iii) the market value of the output of the mine, all of which will be the subject of expert technical, financial, and market reports. The projected loan life coverage ratio (LLCR) and minimum and average debt service coverage ratios (DSCRs) are examples of financial ratios that form part of the options in the lenders’ ‘toolbox’, which are often taken into consideration due to the foregoing risk criteria.

14.117  Financial tests will be a reference point in respect of the following:

  1. (1)  Conditions precedent: Coverage ratios will sometimes be tested as a condition precedent to financial close and perhaps also to each loan utilization. Given the nature of the risks discussed in the preceding paragraphs, lenders tend to require more robust economic projections, and thus higher financial ratios, than in comparison to projects across other sectors. Additionally, the debt to equity ratio will need to be determined. Not only will the relative amounts of debt incurred by the project company influence the DSCRs and LLCRs, but the relative amount of equity committed to the project also shows the level of sponsor commitment in what is a cyclical business with inevitable downsides.

  2. (2)  Establishment of reserves, debt deferral, and prepayments: Virtually every project financing entails the establishment of a debt service reserve account, designed to (p. 417) provide a dedicated source of funds in circumstances in which revenues do not cover both operating costs and debt service. In addition, some financings may envisage the funding of reserves to pay for major maintenance, or to ensure liquidity during periods of anticipated reduced revenues due to market or other conditions. In determining the size of the required reserves, lenders will generally run various down-side sensitivities in the financial model to assess the resultant financial ratios. Although in the first instance these sensitivities will frame the question of how much debt the project company can prudently service, to the extent that the projections show that the risk of not satisfying debt service is restricted to limited periods, the concern might be capable of being addressed by the funding of adequate reserves, rather than simply reducing the aggregate debt level. The sponsors may also seek to persuade the lenders to agree to the deferral of principal payments, at least for a limited period, to help mitigate the risk of revenue cyclicality. Where there is projected excess cash and cash sweeps or cash sharing mechanisms form part of the financing package,59 the sponsors may seek flexibility to reduce exposures over specified repayment periods by prepaying selective debt instalments in order to ensure that during periods with reduced revenues (e.g. due to mine plan and ore grade variations, projected market conditions, or other factors) the project company will have lower debt service burdens. Lenders, however, will often seek to limit a project company’s ability to selectively prepay individual principal instalments in order to mitigate the risk of the project company changing its mine plan in a manner designed to generate excessive excess cash and distributions (e.g. through ‘high-grading’) when market prices are higher.

  3. (3)  Distribution testing: On an ongoing basis, lenders will generally seek to condition the making of distributions to shareholders on satisfying minimum historical and, in some cases, minimum coverage ratio forecasts (generally, but not always, limited to relatively short-term forecasts).

  4. (4)  Mine Plan Changes/Expansions: The lenders will want to be reassured that the project is running smoothly before allowing the project company to incur additional debt required as a result of changes to the scope of the project. Lenders may rely on coverage ratio tests, such as minimum projected DSCRs and LLCRs, to assess the overall projected ‘health’ of the project and to measure the circumstances under which major project changes can be undertaken.

  5. (5)  Cash sweeps and cash sharing: Where ratios exceed a specified level, there may be provision for cash sweeps, whereby excess revenues are mandatorily applied to pay down debt, or for cash sharing, whereby if the project company elects to make a distribution (often by way of dividend and subject to a cap) a proportion of such revenues must simultaneously be used to pay down debt. These prepayment mechanics represent some degree of mitigation against the inherent risks of reserve uncertainty and price volatility (discussed earlier). Mining companies will naturally be inclined to mine rapidly or mine only high-grade materials when commodity prices spike, but lenders may favour greater stability as regards the rate at which reserves are depleted, given the long-term tenor of the debt. Cash sweeps and cash sharing mechanics guard against such risk, because they disincentivize mining companies from ramping up operations (p. 418) during peaks in the price cycle: sponsors will be aware that any benefits from increased activity would have to be shared with the lenders.

Reserve tail

14.118  In addition, to address the risk that there may be reduced revenues or increased costs during the life of the project, the lenders will often seek confirmation from a technical consultant that the reserve is sufficient to provide a ‘reserve tail’ (i.e., lenders will want to be reassured that there is a ‘buffer’ in the shape of reserve available after the scheduled maturity of the debt). The reserve tail ratio, therefore, is a measurement of the reserve remaining to be mined after maturity against the total reserve. Although this is generally tested at financial close, where a mine’s life is shorter or there is a limited reserve tail following debt maturity, the lenders may look to assess the continuing existence of an adequate reserve tail at release of the completion guarantees and other points in the financing.

Other mining-specific considerations

14.119  Where a mine is to produce specialized products, the lenders may insist that long-term offtake arrangements are put in place so as to ensure reliable revenues with which to repay debt. In such cases, covenants and defaults, tailored to such arrangements, will be drafted. Conversely, where a mine produces products for which demand is strong and widespread, more latitude may be afforded in respect of marketing arrangements: the lenders may be more comfortable with regard to market liquidity and therefore impose fewer restrictions.

14.120  It is worth distinguishing between mining ‘majors’ (household names with worldwide reputations, principally involved in bulk mining, developing mineral deposits, and selling them on the open market) and mining ‘juniors’ (thinly capitalized companies that search for new deposits but more rarely develop these on their own) in the context of a project financing; because lenders are likely to adopt different approaches in junior and major mining deals, the suite of covenants will vary accordingly. In projects where juniors are involved, lenders are likely to insist upon a wide and tightly drafted set of covenants, reflecting caution as to the ability of the borrower to address all eventualities. Juniors, after all, will not have the same resources or experience as majors, to whom lenders will generally show more deference, given their reputation and the expectation that they will be able to manage a major project.

14.121  The status of the sponsors and how much ‘skin in the game’ they have (as measured, for example, by the debt to equity ratio) will be particularly relevant in relation to the degree of control the lenders may seek to have over the mine plan and any adjustments thereto. Generally, where the mine plan is concerned, lenders will be more likely to defer to the long-established expertise of majors.

Streaming Agreements, Royalty Agreements, and other Alternative Finance Options

14.122  For sponsors that can afford to invest their own capital in new projects, debt financing is attractive because it allows them to leverage their equity, and thus enhance their internal rate of return, and at the same time to share political and operational risk with others. For (p. 419) less well-capitalized sponsors, accessing both equity and debt from third parties (often through project financings and equity raises) is simply a precondition to undertaking a development project.60 Yet, as traditional sources of equity finance have been less accessible to sponsors in recent times, the use of alternative sources of funding, such as from streaming and/or royalty investors that are willing to essentially monetize resources ahead of their physical extraction, has become more prevalent among junior to mid-size mining companies. Where sponsors seek to merge one or more of these alternative quasi-equity finance options together with traditional sources of debt financing (which often involve a combination of commercial lenders, ECAs, and multilateral agencies), the need to address intercreditor arrangements (discussed further in paragraph 14.130) has become an important consideration.

How do streaming agreements and royalty agreements work?

14.123  Streaming investors make upfront capital payments (and/or a series of payments based on development milestones) to the mining company in exchange for an amount, or the right to purchase an amount (typically calculated as a percentage), of the mine’s total metal output over specified periods (the ‘stream’). Typically, the ‘stream’ is a precious metal produced as a by-product of the main metal being exploited by the mining company’s operations but it can also be a related mineral, or a portion of the principal production of the mine.

14.124  There are several ways streaming agreements can be structured. Most commonly this is either: (i) by way of a forward sale agreement whereby the streaming investor pays an upfront amount in return for actual deliveries of the metal that is the subject of the stream; or (ii) as financial settlements based on the production and/or sales of the stream. In a typical streaming agreement, the streaming investor pays a fixed price for each unit of metal or mineral delivered, often at a significantly discounted market price. A common (but not essential) feature of metal streaming agreements is for any portion of the upfront payment that has not been credited and reduced to zero prior to the termination of the agreement to be repayable in cash to the investor.

14.125  Royalty investors provide funding to the mining company in a similar way to streaming investors. A key difference between streaming agreements and royalty agreements is that streaming investors make payments to the mining company in exchange for a right to purchase the physical product, whereas royalty investors receive a specified share of the production or value of the mine (either in metal form or in monetary form). Where royalty investors share in a monetary form, they will receive revenue generated by their share of production either on a gross basis or after deducting smelter or other costs. Royalties are also often structured so that they are akin to deeded interests that run with the land, whereas streams are linked to production and/or sales of the stream.61

The positives

14.126  Streaming and/or royalty investments can be provided alongside other forms of financing and are often treated as a replacement or supplement for equity. In many ways streaming (p. 420) and royalty investors are considered preferable by the sponsors over equity providers, as their participation avoids equity dilution and/or the dilution of the mining company’s other assets (including future discoveries or acquisitions). The stream is often not counted as debt or equity in the books of the project company. As streaming investors will have undertaken a comprehensive due diligence process before committing to the project, their participation may also be viewed by the market as an independent endorsement of the project. Furthermore, depending on the capital structure of the project, streaming agreements may be covenant light when compared with traditional debt financings, enabling the mining company to retain a greater level of control over its operations. There will be no debt covenants to be tripped, no on-going debt service and related payments and, as the streaming investor’s interests are aligned with that of the mining company, they are arguably less likely than traditional debt providers to force repayment if production is delayed. Streaming agreements and royalty agreements are also generally quicker and relatively inexpensive to arrange.

The potential pitfalls

14.127  The main concern for the other parties participating in a financing involving streaming investors is the potential for the streamed metal price to be fixed considerably below market value, particularly if the mining company has not negotiated the option to buy back a proportion of the stream. On the other hand, streaming investors sometimes seek protection against the loss of their investments should the mine underperform, for example, by requiring cash repayments of any proportion of the upfront payments that have not been credited and reduced to zero by metal or mineral deliveries prior to the term of the streaming agreement. This is because the repayment structure (described earlier) relies on the mining company benefiting from the upside of production. Moreover, until the streaming investor has received full delivery of such product, cashflows will be diverted away from the revenues of the operation.

14.128  It is also possible that unless streaming and royalty arrangements include a cap on revenues, these investors could inadvertently benefit from higher levels of return than anticipated if the mining company makes new discoveries or outperforms original projections.

Security arrangements

14.129  The streaming/royalty investor’s rights to its returns can be secured in different ways depending on the specifics of the transaction. Where local laws permit, it is common for royalties to be registered against title to property, with the consequence that such rights remain attached to the mine regardless of the identity or solvency of the owner. As a right to purchase cannot be registered, streaming investors often seek to contractually secure the continuance of this right in insolvency. Whether a streaming investor’s right will trump that of any senior lenders also a party to the transaction is to be negotiated as part of the intercreditor arrangements.

Intercreditor considerations

14.130  Traditional project finance senior lenders certainly have experience of navigating the intricacies of intercreditor relations across different tranches of senior debt, and there are customary means to address the contingent rights of additional creditors, such as hedge providers. But it is a relatively new phenomenon for traditional senior lenders to be asked to negotiate intercreditor terms with hybrid participants who seek what in the leveraged (p. 421) finance market might be characterized as mezzanine debt rights.62 The following, non-exhaustive set of issues, are those which are generally considered to be the most fiercely negotiated with streaming investors; the outcomes being tailored to the unique credit and asset profile of each mining company:

  1. (1)  Cashflow priority: If the terms of the stream are such that it may be viewed more similarly to debt (with repayments of such debt being made by the crediting of an implied ‘coupon’ derived from the discount on the market price for the metal), as is the focus of this section, discussions will likely revolve around the ability to defer (in whole or in part) deliveries of the stream. The intention is that deliveries become capable of deferral if there is a shortfall in production, or where revenues from other metals sales are insufficient (due to, inter alia, low market prices) to cover operating costs and/or debt service (or arguably replenishment of the debt service reserve account). However, if the stream is structured akin to a forward sale agreement, it will be paramount to the streaming investor that the mining company’s sales of metals in respect of the stream are made prior to (or the very least, pari passu with) all other metals sales. The streaming investor’s focus will be that its deliveries are uninterrupted on the understanding that it has already ‘purchased’ the product from the mining company; hence, any quantities subject to the stream ‘do not belong’ to the seller. The streaming investor will often want any funding from the project that may be used to settle the stream (e.g. where the mining company is required to purchase the streamed metal from the market to meet its agreed deliveries) to be treated as operating costs.

    Consequently, in these types of streaming arrangements, intercreditor discussions will often focus on whether there are circumstances in which other lenders or the project may take priority (e.g. in an enforcement scenario).

  2. (2)  Security: Discussions with the lenders will often focus on the streaming investor’s rights with respect to the specific volumes of metal being purchased. One such discussion may be whether the streaming investor will be entitled to first priority interests in the subject matter of the stream; the mined metal, metal still in the ground, or both. Another such discussion may be whether the streaming investor will be entitled to a second priority or a pari passu security interest in other project collateral.

  3. (3)  Survival of a stream: Streaming investors may seek to have the stream survive lender enforcement and transfer of the mining company shares or assets. Discussions usually relate to the streaming investor’s right to approve transferees in the event of equity foreclosure, with a focus on the transferee having the capacity to effectively maintain and operate the mine. Such discussions can often be a focal point for senior lenders as the survival of a stream could reduce the value of the asset in a foreclosure context.

Challenges in the Future

14.131  Historically, mining has never been an inexpensive or straightforward venture. Yet it seems that the future will likely prove ever more costly, technological, and complex.

(p. 422) Costs

14.132  The costs of mining are only heading in one direction and the reasons for this are threefold: rising marginal costs; increased overheads; and greater risk across the industry.

14.133  A mining project requires essential inputs, the costs of which have been rising in recent years. For instance, the rising costs of water, steel, and the necessary machinery have contributed to a higher marginal cost base. When coupled with rising overheads, in the shape of higher wages (exacerbated by a global shortage of workers equipped with the necessary skills), the imposition of windfall taxes and/or increases in existing taxes and the cost of compliance with rigorous environmental standards, the costs of production grow greater still. Once both the significant political risk, as well as the impact which potential disruptions can have (take, for example, the much-publicized strike by platinum miners in South Africa, estimated as at May 2014 to have cost approximately US$2 billion in lost revenue63), are factored in, it becomes clear that there is upwards pressure on costs. In turn, these put upwards pressure on prices.

Technology and the mining industry

14.134  Adding to the above costs is the prevalent role of technology in the mining sector. With efforts to improve productivity, efficiency, and the bottom-line margin of mining projects, the use and implementation of digital technologies is not a new occurrence but it has certainly become more widespread across the industry. EY’s recent poll to this effect concluded that over 700 industry representatives ‘revealed the majority [of mining corporations] have started the digital journey’.64 This digital journey frequently begins with an outsourcing of technology services procurement to design and implement applications to, amongst other things: analyse data to enhance assessment management, improve consistency, and manage predictive capability; introduce distributed ledger technology such as blockchain for contract automation; identify cost-reduction opportunities; and run improved real-time sales to match production profiles.65

14.135  The above technological solutions, however, result in heightened exposure and vulnerability to cyber-attacks and data breaches, making cyber-security a more talked about challenge as we enter 2019. As such, it is now imperative for mining companies that are undertaking a digital transformation to be cognizant of these cyber risks, to choose the correct technology services provider or technology platform, and to build appropriate protections into their outsourcing and technology services contracts.

Remoteness and complexity

14.136  As global population grows, demand soars, while the supply of minerals is necessarily scarce given that they are a finite resource. As already discussed, mining companies cannot (p. 423) pick and choose where to conduct operations: they must go where the minerals are located. If such locations present serious practical challenges, then the technology utilized must be adequate to meet such challenges.

14.137  Mining is, therefore, taking place in ever-more remote jurisdictions, giving rise to a number of issues. Logistically, constructing and operating a mine in Madagascar (such as the Ambatovy nickel and cobalt mine) or in Mozambique (for instance, the Benga coal deposit) is completely different to undertaking a project in less risky and more developed locations. These pioneering greenfield projects require infrastructure to be put in place at great cost, and, as many of those projects which could be considered ‘low-hanging fruit’ have been developed, by necessity projects will become harder and more expensive to develop and operate in the future. When one looks to the Oyu Tolgoi copper mine in the Gobi desert in Mongolia, one can see how projects carried out in such challenging situations require innovation and sophistication in respect of technology. In addition to open pit mining operations at the site, Oyu Tolgoi has implemented the use of drones and makes use of a method known as ‘panel caving’, whereby the ore body is accessed via underground shafts and tunnels in order to exploit ore bodies too deep for open pit mining.66 Thus, the logistics can be highly complex and seem likely to grow ever more so.


14.138  The picture painted in this section is one of a notoriously cyclical industry in which fractious relationships between host governments and mining companies must be handled delicately. Moreover, the future will present a number of challenges owing to global population growth, a depletion of finite resources, and the need to embark upon ever-more complex and expensive projects.

14.139  This is most certainly not, however, a picture of doom and gloom. In the longer term, increased investment in research and development could lead to technological improvements, which in turn would facilitate a broader scope for, and greater efficiency of, mining activities.

14.140  In the immediate term, the prevalence of alternative sources of funding is becoming a mainstay in the mining industry. In addition to the royalty and stream investors discussed earlier, sponsors are considering private equity and the capital markets to be attractive alternatives to traditional loans. ECAs have recognized this and are sometimes supporting these structures, for example, by providing ECA backed bond products, but also by highlighting the benefits of traditional lending structures where traditionally longer tenors and a willingness to act as a project ‘partner’ rather than as a mere financial investor can prove beneficial to sponsors. This is of particular importance when coupled with the context that ECAs are becoming increasingly focused on securing natural resources for their ‘national’ offtakers: one only needs to consider the large pool of offtakers to deduce that this could be largely beneficial for sponsors seeking funding.

(p. 424) 14.141  The reality is that there will inevitably continue to be tension between host governments and mining companies, but one should not lose sight of the fact that there is mutual interest in cooperation and therefore an inherent check on interventionism. Governments, being rational actors, are aware both that foreign investment is critical to the development of their countries and, further, that exploitation of a mine may in effect be a once in a lifetime opportunity to secure a healthier economy and better conditions for their people. The art of compromise is vital in what should, ultimately, be a symbiotic relationship.

Section C—Conventional Power

James Murray and Andrew Gibb, Milbank LLP


14.142  Despite the focus in recent years on environmental concerns and the setting of emissions targets by national governments and multilateral agencies to discourage its use and instead promote renewable energy, conventional, fossil fuel fired power , it is likely to remain a central part of the electricity generation mix of most countries for the foreseeable future. Indeed, while the emissions targets call for the proportion of fossil fuel power investments to be reduced to 40 per cent of total power producing investments by 2030, the proportion actually rose slightly in 2017—to 59 per cent. The International Energy Agency has also estimated that renewables investments declined by 7 per cent in 2017. In the short term, this decline was largely a result of fewer onshore wind and hydropower plants being commissioned—offsetting the record levels of spending on solar PV—combined with a reduction in the capital costs of renewable technology. (The costs of solar PV and offshore wind manufacturing declined by nearly 15 per cent and 5 per cent respectively, in 2017 as compared to 2016.) More generally, however, three diverse factors have slowed (or even stalled) the move away from fossil fuel generation in many countries:

  1. (1)  the reduction (or reversal) of renewables subsidies in some markets;

  2. (2)  the cancellation of nuclear power new build in others as a result of the Fukushima incident in March 2011; and

  3. (3)  the increased availability of natural gas at historically low prices (although this has seen something of a reversal in recent times—with, for example, China’s mandate to source 10 per cent of its energy production from gas by 2020 (up from 7 per cent in 201767) leading to an increase in demand which has continued to boost the prices of LNG in 201868 ).

The IPP Model

14.143  The project-financed IPP was originally developed in the US power markets following the introduction in 1978 of the US Public Utility Regulatory Policies Act (‘PURPA’). (p. 425) PURPA established a legislative platform for ‘Qualifying Facilities’ to sell energy and capacity to state utilities for a price equivalent to the relevant utility’s avoided cost. Historically, the initial IPPs were most often structured to fit within regulated markets; long-term PPA structures created a stable generation base in energy markets in which there was a single, often state-owned, power purchaser responsible for balancing system-wide supply and demand. IPPs were put out to competitive tender; in the UK and a number of European jurisdictions, competition was fierce and lenders’ appetites for appropriately structured projects strong. The initial IPPs developed in the UK included Drax, Barking, Teesside, Sutton Bridge, and others. Other countries including Portugal, Bulgaria, Hungary, India, Pakistan, Indonesia, China, Australia, Thailand, and the Philippines followed suit. Regional utilities or state-owned offtakers entered into PPAs with developers whose balance sheets were often insufficiently strong to take the full completion risk associated with the development and construction of power projects. As a result, much of the construction risk was allocated to the construction contractors under turnkey EPC contracts.69 Following commissioning of the power plant, the PPA entered into effect with the relevant creditworthy utility or industrial host, and provided the project company with the required revenue stream to repay the lenders, service the debt, pay operating costs, and enable the sponsors to receive a return on their equity investment.

14.144  The structuring of traditional IPPs is relatively conservative in order to achieve bank finance because of the nature of the risks faced by the IPP, both pre- and post-completion. Prior to first utilization, the lenders need to be satisfied that the project budget will be sufficient to meet the project company’s obligations under the EPC Contract and that the construction contractor will, as far as possible, be responsible for achieving project completion. Construction costs (including interest during construction paid to the lenders) need to be competitive if the project company is to be able to offer a competitive electricity tariff to the utility or power offtaker.

14.145  Many countries have now benefited from the closing of IPP financings, with the IPP model spreading from the US to the UK and European markets and then to emerging markets in Latin America, Asia, Africa, and the Middle East. Countries like Saudi Arabia, with growing power demand and creditworthy offtakers, have developed highly successful and competitive independent power programmes which have been banked by commercial banks, ECAs, and multilateral agencies.

14.146  However, the application and financeability of IPPs very much depends upon the structure of the relevant market, government policy and creditworthiness of offtakers, and the relevant regulatory framework. Electricity market liberalization has, however, reduced the number of new IPPs under development, and market reform has reduced the availability of long-term PPAs in many jurisdictions (particularly in more developed markets). The market dominance of a handful of large electricity utility companies in much of Europe has also contributed to a sharp decline in the use of the IPP model in many European countries over the last decade or so. Contrast this with the huge appetite from state utilities in countries like Saudi Arabia and Indonesia, where the IPP model continues to provide the (p. 426) bedrock for the procurement of much-needed power, and in the case of the Middle East, desalinated water.

Overview of Power Markets

14.147  There follows a brief overview of a cross-section of some of the key power markets highlighting the impact of economic, government policy, and regulatory factors which have had a material influence on the evolution of the power sector in these markets:

United States

14.148  The US has traditionally been highly reliant on conventional power to satisfy its electricity needs. Natural gas has been the leading source of fuel used for electricity production in the US for a number of years now and in 2017 it accounted for 32 per cent of the electricity generated (up from 30 per cent in 2012). Coal remained the second largest energy source in 2017, accounting for 30 per cent of the electricity generated, however, this is down from 38 per cent in 2012 and the rapid decline of coal is expected to continue. Renewable energy sources produced approximately 17 per cent of electricity generated, and nuclear energy produced 20 per cent.70

14.149  In 2017, approximately 9.3 GW of new natural gas-fired capacity came online. However, for the first time in a decade, no new coal-fired generators were added. Coal-fired plants struggle to compete with natural gas-fired plants in terms of merit order based dispatch, environmental emissions, and in their ability to secure investment and debt finance. The total nuclear generating capacity at the end of 2017 was approximately the same as in 2013. As of 2018, two new reactors are under construction, and are expected to come online between 2019 and 2020. The International Energy Agency expects that nuclear energy’s share of electricity production in the US will nevertheless decline due to capacity retirements and derating of some reactors.71

14.150  The International Energy Agency expects wind power to become the predominant source of renewable energy production by 2019, mainly due to factors such as precipitation and snowpack affecting hydropower generation.72 Going forward, the share of renewable energy in electricity production is likely to increase—solar and wind projects make up approximately 62 per cent of new power construction in 2017. About 2.9 GW of new renewable energy projects were initiated in 2017, while in 2018, approximately 12.5 GW of coal plant capacity is expected to shut down.73

United Kingdom

14.151  The UK is also highly reliant on conventional power to satisfy its electricity needs. One-fifth of the UK’s current generation plants are scheduled to close by 2020; long-term (20 years plus) electricity demand is, however, forecast by the Department of Energy & Climate Change (DECC) to double, mainly as a result of a long-term shift towards (p. 427) electrification in transport and home heating. The 2016/2017 agreement between HM Government and EDF of the key commercial terms for the Hinkley Point C nuclear plant was seen as paving the way for the introduction of the UK’s first nuclear new builds for 20 years, which would form a major component of the required increase in generation capacity. However, the economic terms of the Hinkley Point C agreement (a CPI-linked £92.50/MWh (or £89.50 if EDF constructs two or more plants)) for a 35-year term, plus the requirement for significant UK Treasury support for the necessary debt, and the prospective co-ownership of Chinese companies, attracted significant adverse press and political comment. Furthermore, plans for a new nuclear power station at Moorside in Cumbria (which would have provided about 7 per cent of UK electricity) have recently been scrapped after Toshiba announced it was winding up NuGeneration, the UK unit behind the project (following Toshiba’s withdrawal from nuclear power after Westinghouse’s bankruptcy74 and KepCo’s decision not to proceed with a proposed acquisition of NuGeneration.75 The failure of NuGeneration and the Moorside project is seen as evidence of the riskiness of investing in nuclear, particularly as renewables are becoming more cost-effective. Overall renewable energy generation increased in2017; in particular, wind power generation capacity increased by 14 per cent due to the significant number of offshore wind turbines coming online in 2017.76

14.152  Energy policy, and in particular, energy pricing for industrial and domestic consumers, has become a major political and social issue in the UK (as it has in many parts of Europe); and UK manufacturers argue that the comparatively high energy prices paid in the UK put them at a significant competitive disadvantage to US manufacturers. (Similar arguments have led to a reduction in renewables subsidies and even policy reversal in other parts of Europe—renewables investors have in recent years been on the receiving end of adverse policy and regulatory change across a number of European jurisdictions ranging from Spain to Bulgaria.)

14.153  The UK introduced wide-ranging Electricity Market Reform (‘EMR’) in 2013. This was a set of arrangements aimed at ensuring that low carbon generation is an attractive and viable investment opportunity and that the UK has secure, affordable electricity supply over the longer term. The cornerstone of the EMR was a Contracts for Difference (‘CfD’) regime which came into force in 2014 (with a transitional period until 2017) and replaced the previous renewable energy subsidy system, Renewable Obligations. Whereas Renewable Obligations placed an obligation on electricity producers to source a greater proportion of their supply from renewables, CfDs were designed to encourage investment in low carbon technologies through certainty of the strike price. Generators receive revenue from selling their electricity into the market as usual; however, if the market price is below the relevant CfD strike price they also receive top-up payments from suppliers for the difference between the strike price and the market price. Conversely, if the reference price is above the strike price, the generator must pay back the difference between the strike price and the market reference price. This, in theory, should reduce developers’ exposure to the volatility (p. 428) of the market and, therefore, reduce their cost of capital. However, as of 2017, the government has announced plans to replace the existing system with a new set of controls77 —Control for Low Carbon Levies—under which it has formulated plans to announce an effective moratorium until 2025 on support measures for new low-carbon electricity generation. This means that decisions over additional new nuclear schemes beyond Hinkley C, the Swansea Bay tidal lagoon, and onshore wind or solar projects will all be on hold unless they can proceed without government support.78 (The UK government is looking at funding new domestic nuclear power stations through new, cost-effective models such as a regulated asset base (RAB) model—under which, in contrast to the Hinkley project, risks would be shared between parties—and direct investment in projects such as the Wylfa plant.79 ) Further, as of October 2018, it remains unclear if the UK will maintain the EU energy and climate targets post Brexit.


14.154  The cancellation of nuclear power programmes in Germany and Italy following the Fukushima incident in Japan highlights the unusual status of France in both a Western European and global context in terms of power generation. As a result of the 1973 oil crisis France moved from a reliance on oil generation (and dependence on oil imports) to nuclear power in little more than 11 years (from 20 per cent nuclear generation to approximately 80 per cent). As of 2017, France derives about 75 per cent of its electricity from nuclear energy, which represents approximately the same share as in 2012. The share of nuclear energy remains high due to its long standing policy based on energy security and underpins France’s position as one of the largest net exporters of electricity due to its low generation costs. Conventional (non-nuclear) power contributes less to the French grid than the renewables sector. Renewables account for 18.5 per cent of electricity produced.80

14.155  France seeks a gradual reduction in its dependence on nuclear energy. It is promoting a move towards renewable energy through state subsidies in the form of price regulation based on ‘feed in tariffs’, where, for a defined term, the generator is provided with a compensation payment between the market price and an agreed price for the relevant sector. Unlike in the UK under the CfD regime (where the generator may be obliged to pay back the difference), in France these extra costs are not borne by the government through an increase in taxes, but constitute additional costs which are passed through to the consumer’s bill.

14.156  France generates a very small proportion of its electricity from natural gas. Many other European countries in contrast view natural gas as a relatively climate-friendly non-renewable energy source. However, for many European countries gas comes (if at all) at a high political price; disputes between Russia and the Ukraine have been a material factor in the development of gas pipeline projects in north and south Europe. More recently, the 2014 Russian/Crimean crisis has caused those European countries which are dependent (p. 429) on Russian gas to rethink their strategies (and is causing key ECAs to reconsider their support for Russian LNG and pipeline projects at present). For some (Poland, Ukraine, and Turkey, for example), concern over energy security has possibly become a greater priority than achieving carbon emissions targets.


14.157  Japan is the world’s largest liquefied natural gas (LNG) importer, second largest coal importer, and third largest net oil importer as a result of its lack of domestic energy resources. It is highly dependent on conventional power for its electricity generation. In 2017, natural gas and coal respectively accounted for approximately 39 per cent and 30 per cent of total power produced in Japan, whereas renewables and nuclear accounted for 16 per cent and 3 per cent respectively. Japan, as part of its commitment to the Paris climate agreement, has vowed to achieve 26 per cent reductions in carbon emissions by 2030 and 80 per cent reductions by 2050 from 2013 levels.81 By 2030, the Japanese government plans to have 22 to 24 per cent of energy needs met by renewable sources, with nuclear energy providing more than 20 per cent of the country’s energy needs.82 Consequently, even though the Fukushima incident in 2011 precipitated the shutdown of all nuclear reactors in Japan, as of April 2018, eight reactors had resumed service.

14.158  As the world’s largest importer of LNG for power supply, Japan constantly seeks to procure stable sources of natural gas through diversification of supplier sources and countries, and participation in upstream natural gas projects around the world. It is also promoting other energy sources from within (including the renewal of nuclear power as described previously) and has offered a programme of government support for renewable energy including ‘feed in tariffs’, under which Japanese electric power companies are obliged to purchase electricity generated from renewable sources at a fixed price.83 Japan’s electricity market is dominated by ten privately owned integrated power companies, with regional monopolies accounting for 80 per cent of the country’s total installed generating capacity. Under the current government’s electricity reforms, the aim is to unbundle the generation, transmission, distribution, and supply businesses within these ten monopolies to improve competition and reduce electricity prices for the consumer. Japan is likely to look to recent reforms in comparable markets including the UK in connection with the reshaping of its domestic energy markets.

South Korea

14.159  South Korea has traditionally been highly reliant on conventional power and this continues to be true today. As of 2017, South Korea generates 40 per cent of its electricity from coal, and 17 per cent from natural gas. There is also a well-established nuclear industry, which as of 2018 includes twenty-three reactors operating and a generation capacity representing 29 per cent of total electricity consumption. Although the share of electricity produced from renewables has increased over the years (from a base of 1 per cent in 2012), it remains relatively low at approximately 6 per cent of total electricity produced.

(p. 430) 14.160  Historically, South Korea has directed significant resources towards developing its nuclear power industry. Its contractors have an excellent record of achieving completion of nuclear power developments on time and on budget; and until the change of government in 2017, 14 additional reactors were scheduled to be completed by 2024, with the goal of generating nearly half of the country’s overall power supply from nuclear sources. However, the recently-elected government of President Moon has announced plans to gradually phase out coal and nuclear power, and expand renewable energy’s share of total energy to 20 per cent by 2030. Consequently, six planned nuclear reactors have been cancelled and the government plans to close all existing nuclear reactors by 2080.84 Under the Moon government’s plans, electricity generated from coal-fired power is expected to decline from 40 per cent to 21 per cent by 2030 and nuclear power will decline from 30 per cent to 22 per cent and be replaced by gas and renewables. On the renewable side, South Korea replaced its ‘feed in tariff’ mechanism in 2012 with a renewable portfolio standard, which requires the 14 state-run and private power utilities with capacities greater than 500 MW to generate 4 per cent of energy from renewables.85


14.161  Indonesia has historically been the most important IPP market in South East Asia. This dates back to the Paiton coal-fired IPP project, which closed in 1995 involving international sponsors and support from a number of major export credit agencies, and set the benchmark for a successful PPA-backed model. (With the government-owned power distribution company, PLN, being the power offtaker under the PPA.) However, the IPP sector was put under considerable stress with the onset of the Asia financial crisis in 1997, which saw a rapid drop in the value of regional currencies and the collapse of the Indonesian Rupiah. The resulting dramatic escalation in PLN’s US dollar-indexed tariff obligations under PPAs, which were designed to cover capital costs funded in US dollars, meant that PLN’s Rupiah-denominated revenue stream from domestic power sales was insufficient to cover liabilities. The aftermath saw PLN dependent on government handouts for its survival, but also a number of IPPs restructured and in some cases tariffs were renegotiated downward under pressure from PLN. International investors maintained a wary stance on PLN credit risk in subsequent projects—and for many years this served to maintain a relatively conservative PPA risk allocation framework, accompanied by government guarantees of (or other forms of support for) PLN’s obligations. Investor concerns remain in some quarters, although they have generally waned with time. In 2014 Genting closed the Banten IPP project, the first internationally financed IPP in Indonesia to close a non-recourse project financing without a government guarantee of PLN’s PPA obligations.

14.162  Attempts to deregulate the power market in the early 2000s and break up responsibility for power generation, transmission, and distribution were held to be unconstitutional and PLN continues to be responsible for all offtake of power from IPPs to this day. PLN continues to deploy a largely traditional IPP/PPA-backed model, although this has been undergoing significant change in recent years—for example, with regulations enacted in (p. 431) 2016 and 2017 mandating new PPA risk allocations and PLN subsidiaries assuming majority ownership in IPP vehicles (similar to structures used by ADWEA in the UAE). As of 2018, a new generation of coal- and gas-fired projects are being developed amidst this evolving policy framework, and we may be seeing the beginning of a new and more relaxed paradigm for IPP risk allocations in the country.

14.163  Conventional power remains the major focus of Indonesia’s power market, with continuing investment in new coal-fired IPPs due to the abundance of readily accessible high grade coal in the country. As of 2016, coal constituted 55 per cent, gas constituted 26 per cent, and renewables constituted 12 per cent of the total installed power capacity in Indonesia.86 There is growing investment in gas-fired IPPs and a recent trend towards combined LNG/gas to power projects. Geothermal is also an important sector, with several new major geothermal IPPs having achieved financial close since the Sarulla project in 2014, and there are a number of dam storage and run-of-the-river IPPs. In the long term, Indonesia intends to generate 23 per cent of power from renewable sources, and as of 2017, there have been more than 70 project development contracts signed by government to develop renewables power.87

Saudi Arabia

14.164  Saudi Arabia is currently almost entirely reliant on oil and gas for power generation and is a focal point for the buoyant independent water and power project (or ‘IWPP’) market which is responsible for the development of significant generation capacity across the Middle East. Saudi Arabia and other Middle Eastern countries’ reliance on fossil fuels for domestic consumption is considered unsustainable and comes at a huge cost, in particular with respect to the resulting reduction in potential exports as domestic demand increases. Saudi Arabia forecasts a sharp rise in its electricity demand driven by population growth, an expanding industrial base (mainly in the petrochemical sector), and an increase in demand for air conditioning. Saudi Arabia has the largest electricity generation expansion plan in the Middle East—it plans to increase generating capacity from 55 GW to 120 GW by 2020,88 with further increases planned by 2032, whilst reducing its reliance on fossil fuels. The country is looking to invest heavily in renewables—particularly solar—in the coming years, spurred on by the reduced installation and operation costs of solar and wind farms. It aims to invest up to US$7 billion in solar and wind farms, and hopes renewables will provide 10 per cent of its power by the end of 2023.89 Saudi Arabia is aiming to award its first wind farm—a US$500 million project at Dumat Al Jandal (in northern Saudi Arabia)—in December 2018,90 with EDF Renewables/Masdar likely to be one of the bidders.91 (p. 432) Major near-term investment in nuclear power (led by KA-CARE92) in solar power and in other renewable sources is proposed.


14.165  From 2013 through October 2018, the Brazilian National Electric Energy Agency (Agência Nacional de Energia Elétrica—ANEEL) has auctioned power purchase agreements specifically for new gas-fired thermal projects with a total capacity of 7.1 GW. Bidders compete on the power price they are willing to accept, and in the case of auctions for new builds the bidders undertake to initiate operation by a date certain.

14.166  Brazil has historically relied heavily on hydro power, which accounts for 64.3 per cent of the generation in the country according to the Ministry of Mines and Energy (Ministério das Minas e Energia). In recent years, faced with severe droughts and in order to balance the increase in intermittent energy sources such as wind and power, the Brazilian federal government has turned more and more to thermal projects to ensure generation is reliable and consistent. Given the lower carbon dioxide emissions compared to oil- or coal-fuelled plants, gas-fired plants have been receiving special attention and have been replacing many of the older oil-fuelled plants in the country. In its 2018 Energy Outlook, BP estimates that demand for natural gas in Brazil will double by 2040, with the share of gas-sourced power increasing from 11 per cent to 16 per cent.

14.167  Due primarily to current infrastructure constraints on the transportation and distribution of natural gas produced domestically or imported from Bolivia, a significant portion of the gas-fired power capacity to be built over the next five years is expected to be sourced from liquefied natural gas (‘LNG’) exported from the US or otherwise from the portfolios of international oil majors such as BP, Shell, and Exxon, which have shown considerable interest in the Brazilian power sector as an outlet in the currently over-supplied global LNG market.

14.168  According to the National Agency of Oil, Natural Gas and Biofuels (Agência Nacional de Petróleo, Gás Natural e Biocombustíveis—ANP), the domestic production of natural gas in Brazil has more than doubled since 2000, and production from the Campos and the Santos Basins is expected to ramp up considerably in the next few years and could provide a lower-cost alternative for plants relying on LNG. The main hurdle for that to become a reality in the medium term is the need to expand the gas transportation infrastructure in the country, historically reliant primarily on investments from Petrobras. Over the last few years the federal government has been studying changes in regulations to make this sector more dynamic and remove some of the key barriers for the entrance of private investors. In 2016, Brazil created the Gas for Growth (Gás para Crescer) programme, an initiative to develop a new regulatory framework to allow for the expansion of the gas transportation infrastructure.

(p. 433) Mexico

14.169  In 2017,93 the Mexican National Electrical System (Sistema Eléctrico Nacional—SEN) had a total installed capacity of 75,685 MW, comprising approximately 70.5 per cent conventional power and 29.5 per cent renewable power. Conventional power installed capacity increased by 1,027 MW (2 per cent) from 2016, due to the expansion of combined-cycle and internal combustion plants (by 810 MW and 182 MW, respectively). Actual power generation in 2017 amounted to 329,162 GWh (a 3.1 per cent increase on 2016), with 78.9 per cent being produced by conventional power plants (a 2.1 per cent increase on 2016). Combined-cycle and thermoelectric plants made up approximately 80.1 per cent of conventional power generation. Combined-cycle plants are the predominant source of conventional power generation in Mexico, with the eighty-three such plants in operation having a combined total installed capacity of 28,084 MW (around 37 per cent of the country-wide installed capacity). Other important sources of conventional power generation include thermoelectric (around 17 per cent of the country-wide installed capacity), coal-fired, and turbo-gas single-cycle facilities (each with around 7 per cent of the country-wide installed capacity).

14.170  The Mexican Ministry of Energy (Secretaría de Energía—SENER) has estimated that, to meet the country’s 2018–32 prospective demand, an additional 66,912 MW of installed capacity will be required (approximating a US$83 billion investment at a MXP$20.5 per US$ exchange rate)—45 per cent of which is expected to be satisfied by conventional power sources (mainly combined-cycle gas-fired plants, amounting to around 28,105 MW). In parallel, as part of Mexico’s efforts to curtail its greenhouse gas emissions, there is also a focus on gradually decreasing production from other conventional power generation sources (namely, thermoelectric, turbo-gas single-cycle, oil-fired and coal-fired facilities, which accounted for approximately 18 per cent of the total greenhouse gas emissions in 2017).

14.171  The 2014 Mexican energy reforms, and recently enacted legislation and policies incentivizing the use of natural gas in power generation, laid the groundwork for the ongoing transition to cleaner energy sources. As a consequence, Mexico has taken significant steps to develop and expand its natural gas transportation and storage infrastructure while serendipitously benefiting from a generally low natural gas price environment. The 2015–19 National Natural Gas Transportation and Storage Plan has been recently revised to consider a 3,354 km expansion in the country’s pipeline infrastructure, comprising ten new pipelines, seven of which will be operated by the Mexican Federal Electricity Commission (Comisión Federal de Electricidad or CFE). Given that nearly 60 per cent of Mexico’s natural gas demand is for electricity generation, and the gradual decrease in PEMEX’s natural gas production levels (an approximate 9.2 per cent decrease between 2015 and 2016), there has been a corresponding increase in Mexico’s dependency on US-sourced natural gas (with imports increasing by 17.5 per cent between 2015 and 2016). In this regard, it (p. 434) is important to note that the United States–Mexico–Canada Agreement (in replacement of NAFTA) is expected to retain NAFTA’s free trade provisions with respect to exports/imports of natural gas between the US and Mexico.

14.172  While the CFE has historically played a controlling role in the Mexican power generation industry, a slow and gradual privatization process started with the first contracted IPP public bids carried out in the early 1990s. Such IPP public bids were curtailed under the 2014 energy reforms, which instead provided for the formation of a wholesale electricity market. Approximately 29 IPPs nevertheless continue to be bound by the Electricity Public Service Law (Ley del Servicio Público de Energía Eléctrica or LSPEE), which was repealed in 2014, and operate as contracted (legacy) plants maintaining long-term power purchase agreements with CFE (with a combined approximate offtake of 12,953 MW per year as of 2015). Pursuant to the recently enacted Electric Industry Law (Ley de la Industria Eléctrica or LIE) and its regulations, these legacy plants may elect to maintain their status as IPPs or migrate their existing IPP generation permits so as to participate in the newly formed wholesale electricity market (either in the short-term capacity market or in mid- and long-term capacity auctions).

IPP Risk Allocation and Contractual Structure

14.173  Having considered the economic and regulatory factors which influence the application of the IPP model, in this section we consider the project contract framework which underpins the financeability of the IPP. Figure 14.1 depicts the project contract structure which is typical in independent power projects.(p. 435)

Figure 14.1  Project contracts for a typical IPP

Offtake, power purchase, and similar agreements

Types of offtake arrangements

14.174  As stated previously, the majority of IPPs have been developed in regulated markets and have traditionally entered into fixed long-term contracts for all, or most, of their capacity and output. However, different types of power projects use different forms of offtake or power purchase structures depending on the location, regulatory background, and primary intended purpose of the relevant type of power project. Where the bulk of a plant’s output is intended to provide power and ancillary services such as steam to an adjacent industrial complex, a ‘tolling’ structure (under which a power purchaser will be responsible for fuel supply in addition to purchasing much or all of the capacity and energy generated by the project itself) may be appropriate—see for example the dedicated PetroRabigh power plant in Saudi Arabia, where the majority of the plant’s output is dedicated to the PetroRabigh petrochemicals plant. In contrast to the thermal power sector, generators involved in generating nuclear power will require a comprehensive legal and regulatory platform which enables them to operate on a base-load basis and which fully recognizes their inflexibility and inability to operate in a liberalized market in which there is, for example, an electricity balancing and settlement system. Renewables projects (in particular, solar and wind) may not have a power purchase agreement at all—they may receive revenues for delivered power through the regulatory basis underpinning the particular renewable sector in the relevant jurisdiction, sometimes on a ‘feed in tariff’ basis and sometimes on a partially contractual and partially statutory/regulatory basis.

14.175  As markets in the US and Europe have deregulated, there have been attempts to finance power projects (particularly older plants which may have recovered much or all of the core economic costs associated with construction) on a ‘merchant’ or uncontracted basis. These plants need the flexibility (in terms of operations and financial structure) to compete in relatively free markets with other types and sources of generation; they are normally partly or fully exposed to market pricing. In many jurisdictions, financing these plants has become extremely challenging in the post credit crunch era.

Typical PPAs

14.176  A typical power purchase agreement or equivalent offtake arrangement is usually the cornerstone of any fully contracted power or power-related (for example, power and desalination, power and steam, or CHP) project. It is the contract under which (subject to successful completion and commissioning of the power plant) all revenues are paid; the parties to a typical power purchase agreement will normally be the generation company (the project company for the purposes of most power projects) as power seller and (in regulated markets) a state-related entity as a power purchaser.

Power purchasers

14.177  In many jurisdictions (particularly in emerging markets), state-owned entities are often regulated monopoly power purchasers. This can make the negotiation of comprehensive long-term offtake arrangements relatively simple in contractual terms (in that there is a single point of contact for a generator in relation to its power sales); given the great importance of these contracts in economic and political terms, however, they are often very heavily negotiated. Long-term offtake contracts are subject to overriding political considerations. In EU countries, and countries looking at the possibility of EU accession, potential major hurdles include: (1) the need to comply with the Third Energy Package (a legislative (p. 436) package that came into force on 3 September 2009 for an internal gas and electricity market in the EU, which stipulates that the ownership of a company’s generation and sales operations must be separated from their transmission networks); (2) the establishment of a National Regulatory Authority for each member state and European-wide Agency for the Cooperation of Energy Regulators; and (3) the risk of long-term power purchase agreements being treated as ‘state aid’ (i.e. an advantage in any form whatsoever conferred on a selective basis to undertakings by national public authorities). Since the Third Energy Package, significant steps have been taken for the establishment of an internal energy market—including the Energy Union strategy, the goal of which is to transform the EU’s energy system into one unified EU-wide framework.94

Changes in fuel policy

14.178  Emissions regulation and the commitment of many governments to reduce emissions over forthcoming periods has resulted in many older-style power plants looking to diversify from burning ‘dirty’ coal to limit their emissions or even to close down completely. Most Western jurisdictions have required fossil-fuelled generators to retrofit flue gas desulphurization equipment to older power plants. Clean coal technologies are being trialled in many countries. In those jurisdictions with the ability to choose between fuel sources there has been a movement away from emissions of heavy coal through to subsidized biomass (see, for example, the ongoing conversion of the Drax coal plant in the UK to biomass, a 4th unit of which was converted to biomass as of the end of 2018).95 Increasingly, this is being manifested as plans to phase out coal-fired plants altogether: the UK is scheduled to end all coal burning by 2025; France plans to phase it out by 2022, and the Netherlands and Italy have proposed to close all coal-fired plants by 2030 and 2025, respectively.96 In other jurisdictions (in particular, Eastern Europe) the easy availability of emissions-unfriendly but abundant and cheap lignite has shaped government policy towards finding a way of maximizing ongoing generation using these sources, notwithstanding the difficulty in complying with EU and global emissions standards.

Key terms of a typical power purchase agreement

14.179  A typical power purchase agreement will contain the following provisions:

  1. (1)  Term: A PPA will typically be relatively long term—perhaps as long as 20 or 25 years. Lenders will expect the term of the PPA to exceed the maximum tenor of the debt by a ‘tail’ of a number of years—this will cater for possible delays in construction/operating difficulties and/or changes in economic circumstances which could result in the debt not being repaid on time. Typically the term of a PPA will commence following completion of construction, commissioning and testing. The power offtaker will often have the right to attend the commissioning tests and will satisfy itself that the plant is capable of being operated safely, within the design parameters, as required under environmental permits and to a level of performance which will be consistent with the relevant bid or direct appointment criteria.

  2. (p. 437) (2)  Price for capacity and energy: A traditional power purchase agreement will normally not commit the power purchaser to take power on a continuous basis from the generator—a typical state-owned power purchaser will have an overriding statutory or similar obligation to manage and balance its generation assets and its transmission, supply, and distribution networks so as to achieve the efficient and reasonably priced delivery of power to end-users—and to minimize power shortages. Subject to exceptions in the case of base-load plants and other ‘must run’ systems, such as hydropower plants, a monopoly power purchaser will therefore not undertake a firm legal obligation to take energy from a generator. Often the tariff payable by a power purchaser under a typical power purchase agreement will be split between payments for ‘capacity’ or ‘availability’ of the plant, and payments for delivered energy. Normally, the capacity or availability payment will be structured so that it is sufficient, all other things being equal, to ensure that the generator is able to cover its fixed operating costs, its debt service costs, and some level of pre-agreed return for its sponsors or shareholders even if it is not dispatched.

    In this type of structure additional ‘energy’ payments will be payable for delivered energy and will normally cover the variable operating costs of the relevant generator, plus (often on a ‘pass through’ basis) fuel and related costs associated with active generation.

  3. (3)  Availability and outages: Normally, a generator will be required to forecast on an annual, monthly, weekly, and daily basis the likely availability of its plant. A power purchaser will use this information as part of the data inflow required to balance its purchase commitments against its distribution and supply commitments to end-users. Accordingly, if a generator suffers an unforeseen outage or fails for any reason to make available the availability notified to a power purchaser for a particular time period, penalties will be payable. A generator will typically factor into its availability forecast for any given period any known likely outages—whether for maintenance or for other reasons. A power purchase agreement may contain a minimum average availability requirement on the generator which would typically operate on a year-by-year basis; any such schedule would recognize the typical scheduled outages the type of plant requires in order to be adequately maintained and to achieve optimal operating characteristics.

  4. (4)  Force majeure: A typical power purchase agreement will contain force majeure provisions which protect both the generator and the offtaker from the consequences of an inability to perform obligations as a result of matters beyond the relevant party’s control. Force majeure is a concept which applies on an obligation-by-obligation basis—force majeure affecting a generator will often be very different from force majeure affecting an offtaker. Force majeure events affecting a generator typically include unforeseen outages resulting from plant breakdown, fire, flood, and natural disaster. Force majeure events affecting an offtaker may relate to a problem with the grid or issues in the supply and distribution markets. PPAs often contain complicated compensation provisions reflecting the appropriate allocation of risk as between generator and offtaker in the many different force majeure type scenarios which an operating power plant is likely to encounter through a twenty- or thirty-year lifecycle—by way of example, where a state-owned offtaker is unable to take power as a result of the political action (or inaction) of a governmental authority, it is likely to benefit from limited, or no force majeure protection in relation to its payment obligations. In contrast, a conventional PPA is likely to require the offtaker to continue to make some level of capacity payments (p. 438) in those circumstances. Payment obligations themselves are usually expressly excluded from force majeure.

  5. (5)  Breach and termination: A typical power purchase agreement will contain provisions policing breach and non-performance by either party. From the generator’s perspective, the most important obligation a power offtaker is likely to have is the obligation to make capacity and energy payments; there are many recent examples of PPAs being defaulted as a result of the inability (or failure) of a state- or privately owned power offtaker to fulfil its payment obligations as and when they fall due. In theory, breaches of this type would ultimately entitle a generator to terminate a PPA; in practice this very rarely happens because a power plant is often in effect a ‘stranded’ asset with only one route to market—therefore, terminating a power purchase agreement in circumstances where there may not be an alternative market for, or means of selling, capacity and power on a long-term stable pricing basis may for a typical generator be a theoretical remedy only.

    From the offtaker’s perspective, it is essential that the generator maintains the plant at a high level of availability and in a safe, environmentally compliant, and optimized operational condition. In many jurisdictions, the offtaker and/or the relevant energy regulatory body will regularly inspect the power plant and alongside the relevant regulatory body will ensure that the generator is complying with environmental and regulatory requirements at all times.

  6. (6)  Security and lender ‘step in’ rights: A typical project-financed power plant will be subject to comprehensive ‘going concern’ security arrangements by the generator in favour of its lenders. The lenders will fully recognize the core importance of the power purchase agreement and (in addition to formal legal security) are likely to seek a ‘direct’ agreement and ‘step in’ rights as against the power purchaser. These would (in theory at least) entitle lenders to ‘step in’ and operate, or to step in and sell the power plant as a going concern without triggering termination of the power purchase, fuel supply, and other key agreements in appropriate default scenarios. Careful negotiation of all key project contracts is necessary to achieve ‘going concern’ security; it may be particularly difficult in some jurisdictions to ensure that all relevant permits, consents, and licences remain available in the event of step in and/or sale by the lenders or their nominee.

EPC contracts


14.180  Engineering, procurement, and construction (EPC) contracts are used in most independent power projects to procure the design and construction of power plants. Under a typical EPC contract, a lead contractor is required to select, organize, and manage a number of subcontractors so as to deliver to the project company a complete and working project by a specified target completion date at a pre-agreed price. In conventional independent power projects these are often described as ‘turnkey’ contracts—the employer or owner should in theory be able on completion to turn a key to start up the successfully completed power plant.

14.181  The key concerns which arise in relation to any EPC contract and which are of particular focus in the context of an IPP are:

  1. (1)  Time—ensuring the contract contains sufficient incentives and penalties to get the project completed on time;

  2. (p. 439) (2)  Cost—ensuring the contract contains sufficient incentives and penalties to get the project completed at a cost which does not exceed that anticipated in the overall project budget and financing ‘base case’; and

  3. (3)  Quality—ensuring that the project when completed has the output, efficiency, and quality stipulated in the design specifications.

14.182  A discussion on the application of EPC contracts is set forth in Chapter 5.97 As alluded to previously, in the context of an IPP, the financing is often structured around a tight project budget, with relatively small contingencies (in comparison to, for example, natural resources projects) and with more limited, or often, no recourse to the sponsors beyond their equity commitments. Therefore, lenders are much more focused on the management of completion risk through the employment of a reputable and creditworthy EPC contractor. In the context of an IPP, it is particularly important that the following parameters apply:

  1. (1)  Single point of responsibility: A well-drafted EPC contract will require the contractor to be solely responsible for all design, engineering, procurement, construction, commissioning, and testing activities. The contractor is the sole conduit for bonding warranties (and compensation where relevant). Often the contractor will be a consortium comprising several entities—in these circumstances the EPC contract would ideally state that those entities are jointly and severally liable to the project company for performance under the EPC contracts.

  2. (2)  Fixed contract price: The risk of cost overruns and the benefit of any cost savings must, in a well-drafted EPC contract, be for the contractor’s account. The contractor will often have a limited ability to claim additional money which is limited to circumstances where the project company or the power offtaker has delayed the contractor or has ordered variations to the works.

  3. (3)  Fixed completion date: EPC contracts will normally provide for a guaranteed completion date which is either a fixed date or a fixed period after the commencement of works under the EPC contract. If this date is not met, the contractor should be liable for liquidated damages for delay. These are designed to compensate the project company for loss and damage (including debt servicing costs) suffered as a result of late completion of the plant.98

  4. (4)  Consistency between the EPC and other key project agreements: It is important that the EPC contract fits properly with the other core project agreements. Key interfaces will be with the PPA (or equivalent offtake agreement) in particular and will include:

    1. (a)  completion date;

    2. (b)  bonding: ensuring that the bonding obligations of the EPC Contractor also cover the project company’s bonding obligations to the power offtaker;

    3. (c)  liquidated damages mechanisms need to mesh with the project company’s liabilities under the PPA;

    4. (d)  caps on overall liability and indemnities: the relevant provisions of the PPA need to be passed through to the EPC contractor as well as any requirements of the project company;

    5. (p. 440) (e)  entitlements to extensions of time: the provisions need to be drafted on a back-to-back basis with the equivalent provisions in the PPA;

    6. (f)  force majeure provisions need to be drafted (as far as possible) on a back-to-back basis with the PPA;99

    7. (g)  access to the transmission grid to enable the EPC contractor to facilitate connection of the power plant to the offtaker’s electricity transmission grid;

    8. (h)  commissioning and testing procedures need to reflect the equivalent provisions set forth in the technical schedules in the PPA; and

    9. (i)  fuel specification: both the fuel type (including any backup fuel) and the specification of such fuel need to be meshed with the requirements under the PPA.

  5. (5)  Commissioning and testing: A well-drafted EPC contract will include detailed testing regimes and specify clearly the consequences of failing to reach the required levels of power plant performance (performance-related liquidated damages). The contract should set out the methodology, the equipment, the tolerances, and the base case ambient conditions assumed for testing. Power projects typically rely on the following three main testing regimes:

    1. (a)  Functional tests: discrete testing of the functionality of the parts of the power plant, which would not normally result in the payment of liquidated damages;

    2. (b)  Emissions tests: these are critically important tests—failure to comply with environmental requirements could result in the power plant being legally inoperable and/or the incurrence of large fines by the project company and/or contractor; and

    3. (c)  Performance tests: these govern the minimum guaranteed levels of performance required by the power plant. Minimum performance levels will be granted by the contractor; if the required minimal levels are not met, the payment of performance liquidated damages will be required. Failure to achieve the minimum performance levels will undermine the power project’s economics and may prevent the plant being viable or result in a need to restructure the project’s debt repayment obligations.

Operation and maintenance agreements

14.183  The operation and maintenance of the project will be of critical importance to the sponsors and the lenders, as it will determine the productivity of the power plant, its compliance with contractual and regulatory requirements (including in particular, environmental requirements such as SO2 and NOX emissions), and thereby the ability of the project to generate consistent revenue. The operation and maintenance role may be undertaken by the project company itself or outsourced to a contractor, often referred to as an ‘operator’. It is also possible that the project company may decide to separate the operation role from the maintenance role in respect of particular key components of the power plant—for example, it is common for the maintenance of the turbine generators to be serviced by the turbine supplier. In power projects, it would be common for the project company to contract with a related third party such as an affiliate of one of the sponsors or for the sponsors to establish a joint venture company to carry out the operation and maintenance roles.100

(p. 441) Feedstock, fuel, and other supply agreements

14.184  The supply and transport of feedstock, fuel, or other raw materials to the power plant is another critical aspect of a project. Without a reliable source of fuel supply, a power plant is unable to operate; where a generator is constructing a power plant in a jurisdiction where the relevant coal or gas supply market is regulated (often the case in emerging markets) it is essential that there is a very good fit between the fuel supply agreement and PPA (and that fuel availability for reasons beyond the generator’s control is a risk passed back to the offtaker under the PPA).

14.185  Typical fuel supply arrangements for a power plant will:

  1. (1)  provide for the committed supply of a specified volume of the relevant fuel;

  2. (2)  provide a detailed specification of the type and quantity of fuel to be delivered;

  3. (3)  specify the manner of delivery—typically a pipeline for gas, and rail, conveyor, or truck for coal; and

  4. (4)  provide for a minimum volume commitment—sometimes on a ‘take or pay’ basis.

It is essential that there is full pass through or similar back-to-back contractual protection for any such commitment in the PPA.

14.186  Regardless of the nature of the resources being supplied, all power projects which rely on the supply of feedstock, fuel, or other raw materials from a third party will likely have similar concerns, namely (a) consistent access to an adequate supply of resources; (b) certainty of transportation arrangements; and (c) in many cases, stability in relation to the cost of the resources. For example, with respect to a coal-fired power plant, sufficient reserves of adequate quality coal need to be available, as well as a long-term supply contract and viable transportation arrangements from the coal mine mouth to the project site.

14.187  A power project’s relative sensitivity to supply and transportation arrangements will ultimately depend upon the availability (and substitutability) of the feedstock or fuel being used by such project. For example, a gas-fired power plant may be able to run on an alternative fuel supply such as fuel oil for a limited period of time in the event of a shortage of natural gas.

14.188  The key issues associated with a fuel supply agreement are similar to those associated with the project’s power offtake agreement, namely, the structure of the contract (e.g. take or pay, or tolling), the term of the contract, the agreement of minimum delivery obligations and whether damages are payable in the event of non-performance, pricing provisions (including any escalation indices or other price adjustment mechanisms), clarity on the circumstances or events which would relieve the fuel supplier from its obligation to deliver, and each party’s termination rights. A principal objective in any negotiation of the supply arrangement is to ensure that the terms match, as closely as possible, the terms of the project’s PPA and the project’s revenue projections.

Key Risks in an Independent Power Project

14.189  When originally developed, the traditional IPP Model had the major benefit for state-owned vertically integrated power companies of introducing private sector capital to defray (p. 442) the very significant new build costs of generation plants. Appetite for those projects in stable jurisdictions on the part of both equity and debt was strong; due diligence was generally thorough, and the core contractual platform extensively researched and exhaustively negotiated. So what have been the main challenges well-structured IPPs have encountered in practice?

Capacity and energy pricing and currency risk

14.190  International lenders will usually require the tariff payable under a PPA or equivalent offtake agreement to be expressed wholly or partly in a hard, normally foreign, currency. The end-user, however, is typically an industrial or private consumer whose earnings are largely or wholly based in the local currency. If over time the local currency depreciates against the reference foreign currency, even the best structured and drafted PPAs may become impossible to perform for a power purchaser whose revenues are primarily in the (depreciated) local currency. A key case in point was Enron’s Dabhol Project in Maharashtra, India. Despite robust concession and PPA agreements between the state, central government, and the foreign developer, it became apparent as the Indian rupee depreciated against the dollar (on which the capacity and energy tariffs were based) that the project was simply uneconomic and unaffordable for the state-owned offtaker. Extensive arbitration and litigation followed; the core project documents were upheld by the courts, but the fact remained that the project could not support the cost of capacity and energy those documents required. Similarly, in Indonesia in 1997–8 the collapse in value of the Indonesian rupiah against the dollar resulted in the state-owned power purchaser (PLN) being unable to meet the hard currency cost of power required under the PPAs entered into with foreign developers. State and/or government guarantees may (as in the Dabhol case) provide the foreign investor with some level of protection against currency risk, but ultimately, if a project becomes wholly uneconomic, the outcome of dispute resolution (and even, as in the Dabhol example, extensive litigation) is likely to be the renegotiation of the core project contracts and/or some form of negotiated buy-out of the foreign equity and restructuring of the project’s debt finance.

Changing markets/market deregulation

14.191  PPAs entered into in IPP projects have traditionally been long term. They are, however, written and agreed to fit the relevant electricity market as it stands at the time the project structure as a whole is agreed between the parties. PPAs will always contain ‘Change in Law’ and ‘Change in Tax’ protection for the benefit of IPP developers and their lenders; the effect of these provisions is not to prevent an adverse change in law from taking effect, but instead to provide economic or other compensation to the developer and the lenders against the consequences of the relevant changes in law.

14.192  The introduction in most countries of stricter emissions limits forced coal burning IPPs to retrofit flue gas desulphurization equipment to older IPPs; in many cases the IPP was able to pass some or all of the related cost back to the state-owned power purchaser under the relevant PPA, and to obtain tariff increases to compensate it for the capital costs it incurred. Other market and regulatory changes have proved more difficult for older IPPs to accommodate—the shift in European jurisdictions to freer markets and different dispatch rules as a result, amongst other things, of the introduction of EU-wide energy-related directives (p. 443) has, despite robust change in law protection in project documentation, led to the renegotiation of a number of long-term PPAs.

Privatization and restructuring of power purchasers

14.193  Similarly, the restructuring of state-owned vertically integrated power purchasers to reflect market changes (and, in the EU, EU directives) has led to credit concerns for sponsors and lenders—many power purchasers in emerging markets are effective organs of the state which do not prepare independent accounts, and may rely largely or wholly on state subsidy and credit in order to operate and fund themselves. Deregulation, privatization of parts of the energy market, and restructuring of utilities to separate generation from transmission, supply and distribution, may have a material effect on the stability, creditworthiness, and financial stability of these entities.

EPC contractor delay or non-performance

14.194  The margins EPC contractors have been able to charge for turnkey EPC contracts for IPP projects over the years have fluctuated significantly. As a general rule, an equity investor in, or lender to, an IPP will need to achieve an EPC structure which is competitive as regards pricing, but which contains sufficient margin for the contractor to ensure that the contractor is and remains fully incentivized to fulfil its obligations. Retentions, bonding, liquidated damages, and similar provisions also help police performance; it is important, however, even in a closely contested competition for an IPP EPC contract, to ensure, if possible, that EPC pricing is not so keen that the EPC contractor is likely to find itself ‘out of the money’ and lose its upside and margin as a result of minor delays or non-performance. A disincentivized or out-of-the-money contractor may feel that further delay or poor performance is immaterial; from the perspective of all the stakeholders it is essential that the project is completed as soon as possible (even if late) in that an incomplete project will not be able to earn PPA revenues, and contractor liquidated damages for delay are likely to constitute only a short-term protection against revenue loss.

Failure to achieve required performance levels

14.195  Every IPP EPC contract will require the achievement of minimum performance parameters as a precondition to taking over of the plant as a whole, the occurrence of completion, and the release of milestone payments. A long-term inability in a power plant to achieve target (as opposed to minimum) performance standards may result in a permanent reduction in revenues under the PPA; as a result, equity returns (which are policed by means of the distributions-related covenants in the finance documents) may be reduced or even blocked. EPC contract performance related liquidated damages should provide some protection against this risk, but are unlikely to mitigate it in whole over an extended period. Resolving this type of problem may require additional capital expenditures and downtime—this will inevitably be seen as a sponsor risk by the IPP lenders.

Failure by power purchaser/state to construct and maintain transmission lines and related infrastructure

14.196  Any IPP in an emerging market is likely to require the provision by the state utility or third parties of interconnection and other facilities. It is essential that the PPA identifies and allocates the risks of delay or non-performance of this type of obligation to the offtaker—until (p. 444) connected, the IPP will not be able to undertake commissioning and performance testing, and will be incapable of commercial operation. The PPA and related documentation must provide for adequate compensation to be paid to the IPP if there is delay in completion of these facilities, or if the facilities are improperly maintained.

New technology

14.197  Conventional IPPs generally benefited from relatively well-known, and tried and tested, turbine, boiler, ash disposal, and related technology. The introduction of new technology for clean coal, new low emission, and carbon capture plants is likely to be an issue which lenders will evaluate carefully and conservatively. The usual approach taken by lenders on financing new technology is to undertake thorough technical and operational due diligence, but also to require equity and cashflow buffers to absorb much of the related performance, completion delay, and increased maintenance risk. So new technology IPPs are likely to see tighter restrictions on cashflows and distributions, detailed commissioning and performance testing regimes, and higher debt service and maintenance reserves.

Financing Considerations

14.198  In many ways, conventional IPP financings which do not involve new technology will be more straightforward than financings associated with mining or petrochemical projects. A typical IPP financing will normally relate to a single asset; it is possible (though relatively unusual) for expansion of the initial capacity to be contemplated (in which case the construction and use of common and shared facilities may need to be considered), but ordinarily the financing will contemplate a single asset, a single PPA, and a single generation licence. By contrast, lenders to a petrochemicals project will often be faced with requirements from sponsors to ‘hard wire’ into the initial financing the possibility of expansions to the project, which normally requires incurrence of major additional capital costs, the construction and sharing of common facilities, and the introduction of material new debt. Often in a conventional IPP, there will only be one class of debt—senior debt, enjoying the benefit of fixed and floating security on all project assets. Pricing of capacity and energy is likely to be fixed in the PPA—so the project should not be directly exposed to market risk through the term of the PPA, as long as the PPA is fully performed.

Cost overruns or delay

14.199  Cost overruns or delay are probably the two greatest concerns for lenders on a typical IPP. Cost overruns and delay can be attributable to any one or more of a number of factors, including the following:

  1. (1)  EPC contractor non-performance or delay;

  2. (2)  power purchaser/state entity non-purchase or delay;

  3. (3)  force majeure; and

  4. (4)  unavailability of construction or operating permits and licences.

14.200  Typically, the lenders will need to see committed equity funding in place at the outset covering the equity share of an agreed ‘base case’ set of costs. The sponsors are often also required to provide contingency funding commitments to cover a negotiated level of additional cost resulting from delays or additional capital costs, in achieving completion.

(p. 445) 14.201  The Financing Documents will typically contain:

  1. (1)  a condition precedent to each disbursement requiring the project to be fully funded and on track to achieve completion before the completion long stop date;

  2. (2)  covenants requiring the project to be completed no later than a specified long stop date; and

  3. (3)  events of default triggered by cost overruns beyond committed funding and/or a projected inability to complete by a specified long stop date.

Single purpose, single asset company

14.202  The financing documents will normally require the project company to be a single asset, single purpose company and will restrict its entry into any other commitments, activities, or business which could adversely affect the project by introducing liabilities which are unconnected with the core project.

Project agreements and project counterparties

14.203  The financing documents will usually set out an exhaustive list of the key project agreements and documents. Material breaches of these agreements will trigger default. Similarly, the financing documents will list the key project counterparties (the offtaker, EPC contractor, O&M contractor, and fuel supplier) and will police performance by those counterparties of their obligations under those project agreements—material breach will usually trigger default.

14.204  It is essential that the key project documents are negotiated and drafted so as to provide full back-to-back protection for the project company and lenders. A mismatch between the PPA and EPC contract as regards testing, completion, and/or plant performance may have disastrous consequences for equity and debt. Similarly, the interface between the liabilities and responsibilities of the EPC contractor for defects liability and plant performance, and the obligations of the O&M contractor under the O&M agreement, will be very important.


14.205  A conventional power project with index-linked capacity and power pricing built into its PPA should, assuming that physical completion is achieved on budget (or within pre-agreed contingencies) and that tested performance and reliability are sound, enjoy a stable and sustainable cashflow. Debt service cover ratios are normally used to test actual and forecast cashflows for a variety of purposes, including payment of distributions and (at the opposite end of the scale) triggering default. Loan life cover ratios may, depending on the debt finance structure, also be applied to ensure the project is able to repay the whole of its debt within the anticipated repayment schedule.


14.206  This chapter begins with a brief overview of the current American, UK, French, Japanese, Korean, Saudi Arabian, Indonesian, Brazilian, and Mexican power markets focusing on current electricity generation mix policies in these markets and the current and future place of conventional power therein. This chapter then identifies the key project contracts (p. 446) relating to a typical coal- or gas-fired power project: Offtake Agreements, Power Purchase Agreements, EPC contracts, O&M contracts, and feedstock, fuel, and other supply agreements. Concentrating on these key contracts, the specific provisions and terms specific to the conventional power sector are drawn out and how these differ from other types of project finance structures is further explored.

Section D—Renewable Energy

Allan Marks and Jenna Darler, Milbank LLP


14.207  Renewable energy projects largely utilize the financing structures and contractual risk allocations commonly used for conventional power projects, with highly leveraged, limited recourse or non-recourse debt financing available, secured by fairly predictable cashflows from a bundle of project contracts that control revenues and costs in a regulated, competitive wholesale power market. However, the special characteristics of renewable energy sources require some variation from the basic model. For instance, the often intermittent nature of energy production and lower efficiency and capacity factors compared to, for example, natural gas, can alter power purchase agreement terms and may limit debt capacity. Assessing technology risks may be more critical for newer or more experimental devices which are more commonly encountered in a sector still developing innovative ways to capture energy more effectively and efficiently. Key technology (like wind turbine generators or solar power components) may be provided under a master procurement contract, perhaps covering multiple projects, separate to the contract to build the balance of the plant (like civil works and control and interconnection facilities), instead of using a single EPC wrap. Finally, though the resource itself may be intermittent, renewable projects benefit from the lack of fuel price volatility and fuel supply risk encountered by conventional power projects.

Sources of Renewable Energy

14.208  Renewable energy is derived from natural resources that are not limited in supply, as opposed to fossil fuels that are considered non-replenishable natural resources. Wind turbines harness power from the wind through the use of wind turbine generators. Solar energy is captured through the use of either concentrated solar power (‘CSP’) or photovoltaic (‘PV’) installations. CSP installations capture solar heat which is utilized to create steam, which in turn rotates a steam turbine and produces electricity. PV installations, conversely, create electricity direct from sunlight. Hydroelectricity is created through the capture of energy from falling or flowing water, either from naturally flowing water (such as run of river hydropower) or through the use of dams to restrict water flows allowing energy to be captured as the stored water is released. Indeed, most stored energy reserves are in the form of water behind large dams. Geothermal power is produced from the collection and recycling of underground fluid naturally heated by the earth. Biomass-based power is typically produced by burning wood, wood pulp, or other biological material to generate electricity (p. 447) and heat, while biofuels are produced by creating fuel (such as liquid fuel to blend with or replace gasoline) from plants, for example, sugar cane or corn, or vegetable fats.

14.209  Renewable energy sources can largely be separated into intermittent and always available sources. Always available renewable energy sources are capable of producing electricity ‘on demand’ in a similar way to conventional power stations and include hydropower (where dam storage is used), geothermal, biomass, and biofuels. These resources can be dispatched on demand and can therefore be used as base-load generation facilities, comparable to coal or natural gas (and with more control over output than nuclear power). Conversely, intermittent renewable energy sources are those such as wind, solar power and run of river hydropower which can generate power only when weather conditions permit. As such, these intermittent resources have typically been used to supplement, rather than to replace, conventional base-load thermal energy sources (like coal and natural gas).

14.210  It should be noted, at this juncture, that advances in technology are changing this breakdown somewhat. For instance, pioneering utility-scale CSP projects have included limited storage of solar energy by using solar heat energy to create molten salt which is then, in turn, used to generate steam to power the steam turbine several hours later. The 150 MW Noor Ouarzazate III project in Morocco uses molten salt technology to store solar energy for 7.5 hours,101 allowing electricity to be generated when demand, and prices, are highest. CSP projects can also offer increased reliability, through having the flexibility to use the steam turbine to generate power from using gas rather than solar energy when necessary. Increased deployment of wind and solar power plants over large areas of the grid also provides a natural mitigant to this resource volatility, as available generation in one area offsets temporary shortages in other areas. Lastly, battery storage technology, able to smooth the output from wind and solar resources and ensure that energy availability mirrors demand, is developing. Effective battery storage technology is crucial if a shift of global reliance from fossil fuels to renewable energy resources for base-load capacity is to become a reality. Though the cost of the underlying energy generation technology has rapidly decreased in recent years, batteries are relatively high cost, with the rapid increase in demand for lithium-ion batteries, primarily in connection with electric vehicles (and primarily in China), resulting in soaring lithium, cobalt, and nickel prices. To offset the high costs involved in battery storage, and in order that reliance on renewable energy resources does not become prohibitively expensive, the World Bank Group announced, in September 2018, a global programme aimed at accelerating investment in battery storage systems in developing and middle income countries and committing US$1 billion of World Bank Group funding (which it hopes will stimulate a further US$4 billion of concessional debt and public and private investment) to that end.102 These advances in storage capability mean that it is becoming increasingly realistic for wind and solar projects to be used as a base-load electricity source.

(p. 448) Increased Market Penetration

14.211  Renewable and alternative energy sources are emerging alongside natural gas as the preferred means of new electricity generation and, in 2016, renewable energy sources accounted for almost two-thirds of net new power capacity around the world (almost 165 GW) and, for the first time, increases in solar PV capacity outstripped increases in capacity associated with any other fuel.103 This growth was dominated, in 2017, by developing economies104 including China, Brazil, and India which committed approximately US$177 billion to renewables against the approximately US$103 billion committed by developed countries. China alone accounted for approximately US$126.6 billion (roughly 40 per cent) of the global aggregate, largely through investment in solar PV.105

14.212  Historically, renewable energy sources like wind and solar power were more expensive to install than incumbent thermal electricity generation technologies like natural gas and coal and, as a result, they depended on environmental policies and incentives for stimulus. Increasingly, as renewable technology has matured (particularly onshore wind and solar PV) prices have decreased sharply and, in some circumstances and markets, the levelized cost of energy for utility-scale solar PV and onshore wind technologies is now at or below the marginal cost for conventional power.106

14.213  Growth in renewable and alternative energy sources is driven by many factors:

  1. (1)  Technology: First, due to technological improvements, renewable power projects (in particular, wind energy projects and solar power projects) have achieved greater efficiency, increased reliability, and economies of scale. Maturing technologies have significantly reduced the cost per kilowatt hour (kWh) to construct and operate renewable energy facilities.

  2. (2)  Energy security: Concerns over dependence on imported fossil fuels and the volatility of petroleum and gas prices, coupled with technological advances increasing the viability of renewable power generation, have heightened the global focus on the importance of the role of renewable energy as part of a diverse energy mix.

  3. (3)  Incentives: Tax incentives and other government subsidies, mandatory renewable electricity standards for utilities, special feed in tariffs, and other regulatory incentives have created new markets for renewable power in many regions. These regulatory preferences for renewable energy reflect more widespread concerns for the environment, including public concerns about greenhouse gas (‘GHG’) emissions and carbon accumulation in the atmosphere, contributing to global climate change.

  4. (4)  Pricing: Higher energy prices (especially for oil and natural gas) during much of the past decade made renewable and alternative energy sources more economically (p. 449) competitive (notwithstanding the significant government subsidies which continue to be available), as well as heightening the public perception that renewable energy enhances the reliability of national electricity supply, energy independence, and economic security.

  5. (5)  Environmental concerns: The contribution to increased atmospheric carbon density and global climate change caused by toxic air pollution and GHG emissions emitted through the continued use of conventional fossil fuels to generate power remains a critical global problem, and national and international targets to reduce carbon emissions are in place to reduce these. Such targets are key to driving utilities’ increased demand for renewable energy.

Incentives for Renewable Energy Investment

14.214  In recent years, the market for renewable energy investments has been strengthened by consumer interest, propelled by economic and market factors, and borne by improved technologies and industry consolidation. Though recently there have been several offshore wind ‘zero-subsidy’ auctions and, in 2017, record low tariffs arising out of renewable energy capacity auctions in Mexico,107 for now, the renewable energy sector remains largely dependent on government subsidies (including through feed in tariffs, tax incentives, and cash grants) and government mandates (like Renewable Portfolio Standards (‘RPS’)108 or quotas requiring that a minimum share of electricity generation come from renewable sources). While other energy sources like nuclear power and large-scale hydropower have long benefited from governmental incentives and subsidies, renewable power incentives are more recent and have become more visible to rate payers.

14.215  Feed in tariffs have been seen across a number of jurisdictions globally. Under such an arrangement, utilities are obliged to buy renewable electricity at rates set by the government which are above general market rates. The rate often differs significantly among the various forms of power generation and is subject to government modification. The preferential rate treatment afforded to renewable energy sources aims to compensate for their relative cost disadvantages. Feed in tariffs have been an important element of the revenue profile for renewables projects but ultimately they raise consumers’ electricity costs, as utilities pass on the tariff structure to consumers.

14.216  A negative unintended consequence of feed in tariffs is that they can disrupt the market price for renewable technologies. For example, relatively high prices for solar derived electricity in Europe kept the price for PV components artificially high. Feed in tariffs are also subject to the criticism that they artificially prefer certain technologies over others, but this too can be levelled against the tax credit and RPS regimes under which only certain technologies qualify.

(p. 450) 14.217  The effect of high quotas for renewable energy purchase by utilities, combined with subsidies and tax incentives, arguably has increased electricity costs for end-consumers. In an era of low natural gas prices (at least in North America), this perception is strong, whether the renewable energy regulatory regime relies on the use of feed in tariffs, which directly affect energy pricing, or tax credits and grants, which are ultimately funded by the taxpayer.

14.218  Increasingly, to counter this effect, rather than utilizing a feed in tariff structure, governments are opting to auction capacity, thereby incentivizing developers to cut costs wherever possible. Auctions have been highly effective at reducing renewable energy prices, resulting in a 700 MW Dutch offshore wind project that attracted bids with zero subsidy and a UK auction in September 2017 which concluded with the award of contracts for difference for 3 GW of offshore wind priced at £57 per MWh (roughly 50 per cent cheaper than the first auction in 2015).109 Successful auctions have also been concluded across developing economies including Egypt, Mexico, India, and Argentina. Whilst government incentives remain a key driver for growth, their necessity will inevitably reduce as technology improves and costs fall.

Development of Renewable Projects

Due diligence

14.219  Comprehensive due diligence and appropriate risk allocation is critical to the development of all projects and renewable projects are no different in this regard. At the outset of any project a feasibility study will be conducted to determine that the proposed project is technically and economically feasible, that it will be built and operated according to the agreed specifications and that it will be operated in compliance with the laws and regulations of all relevant governmental authorities. This feasibility study may require input from a host of expert consultants including insurance, environmental and geotechnical experts, market consultants, and of course the technical adviser.

14.220  A key element of a feasibility study in the case of renewable energy projects will be carried out by a resource consultant. The resource consultant will be engaged to evaluate the physical characteristics of the project site and thereby assess the potential energy input; in much the same way as a reservoir might be assessed in relation to an oil and gas project. In the case of a wind project, a wind consultant would be employed to model, amongst other things, the speed, direction, and variability of winds. Similarly, a solar consultant might analyse the timing and intensity of the sun’s radiation. In addition to establishing the potential resource available for capture, this will also drive the design of the project and determine the location and angling of wind and solar units.

14.221  Renewable resources are very much tied to their geographical location (whether this be a river, hillside, or offshore). This inflexibility of siting means that a significant factor in the development of any renewable project is the way in which that project will be interconnected with the grid, and the level of investment which may be needed to establish that infrastructure. Additionally, and particularly with wind and solar resources, (p. 451) considerations regarding the use of adjacent land and potential interference with the resource are critical.

Project documents and project risks

14.222  A comprehensive discussion of project risks is set out in Chapter 4 and renewable projects will encounter many of those same risks. Equally, many of the same considerations will apply to the project documents. Set out below is a brief description of the ways in which some of these general risks may apply in the context of renewable projects and, in particular, how these may impact, on those projects, such as wind projects, in which a turnkey EPC contract is not practical.

Power purchase agreement

14.223  Where a PPA110 is part of a renewable project’s contractual framework, it will form, as the source of revenues from a creditworthy offtaker, the foundation of the relevant project’s financeability, as is the case with many conventional power IPPs.

(1)  Offtake (revenue) risk

14.224  As with conventional power projects, the offtake contract is often central to the financeability of a renewable project, and a long-term offtake contract enduring beyond the term of the proposed financing with a sufficiently creditworthy party will be desired by lenders. Offtaker credit support or a guarantee from a creditworthy party to secure the offtaker’s performance under the offtake contract can be used where the offtaker itself lacks an acceptable credit standing.

14.225  In base-load thermal projects, the revenue stream from offtake contracts will typically comprise (a) a fixed capital cost component and a variable operating cost component, or (b) a capacity payment and an energy payment. The capacity payment is generally sized to cover fixed charges (such as debt service, equity return, fixed operating charges, taxes, insurance premiums, and administrative overheads), while the energy payment covers the variable operating costs of a project. Some renewable energy sources (like geothermal, waste to energy, or biofuels plants) have steady or controllable output, so this standard approach can be used, giving the project company (and the project lenders) comfort that sufficient revenue will be generated.

14.226  However, unlike PPAs for base-load thermal plants, PPAs for intermittent renewable energy resources like wind and solar power, where output may vary considerably depending on atmospheric conditions minute by minute, the PPA would not typically provide for capacity or availability payments and instead is more likely to be structured as an energy-only tariff. For example, almost all wind PPAs are structured on an ‘as available’, energy-only basis, or with contract payments dependent in part on meeting conservatively estimated minimum annual output.

(p. 452) 14.227  A very small number of wind energy projects have been financed without a long-term offtake contract or energy-hedging arrangement. These merchant power financings have involved either areas (like Chile) where competing power sources are quite expensive, or where power sales are being made into well-established, functioning, and liquid spot markets, where market forecasts reflect limited price volatility and a market clearing price that supports the economic viability of the project. In all cases, financing depends on demonstrating that the transmission arrangements do not pose a significant risk of curtailment or potentially subject the project to high imbalance penalties. The small group of lenders willing to finance such merchant wind power projects usually require significant levels of equity or contingent equity support and/or funded reserves, as well as cash sweeps, making debt capacity quite limited.

(2)  Pricing

14.228  The price under the PPA can be fixed or variable. Commonly, prices are indexed to inflation or to a wholesale power index (in some areas indexed to natural gas or based on a competitively bid market clearing price), and often are subject to a floor. Energy prices might also be adjusted to account for increases in construction costs, interest rates, operating and maintenance cost increases, as well as changes in law and taxes.

14.229  PPA prices might also include higher rates for incremental energy production as an incentive for the production of renewable power. Some PPAs also contain a ‘maximum delivery amount’ and, for energy deliveries in excess of (say) 115 per cent of the maximum delivery amount, the applicable tariff is reduced. Conversely, failure to produce electric power at the prescribed output can result in a decreased price, require payment of liquidated damages, or even give rise to a power purchaser’s termination rights. For this reason, minimum guaranteed deliveries in the PPA might be tied to a conservative (P99 or P90) forecast of output, on which the debt financing is also based, while the equity sponsors gauge potential returns using a more speculative (P50) forecast of wind and output in the hope of capturing incremental additional revenues.

14.230  Renewable energy projects may also be able to negotiate PPAs that reward production at times of peak electricity use, which can be beneficial for solar projects; particularly in the Middle East where energy use peaks during the middle of the day, when the sun is at its strongest. Solar power in areas with ample solar resource has an especially attractive load following profile. Under this variable pricing structure, projects may receive a bonus when renewable electric production is aligned with periods of peak usage. Lower prices, subject to a floor, are paid when electricity is produced in off-peak times. Absent the price floor, however, power plants (usually wind farms) that produce at off-peak times may be subject to penalties or curtailment. Successful project development requires a careful assessment of market demand and grid dispatch dynamics, together with transmission congestion, under all types of operating conditions, times of day, and seasons, taking competing generators and technologies into account.

14.231  Ultimately, the rate paid for energy under the PPA must be sufficient to cover fixed costs (including required debt service) and variable costs (including operation and maintenance expenses), and, if applicable, fuel costs (such as tipping fees for waste-to-energy projects). Providing that the revenue stream can be so established, the remaining concerns mirror those in conventional power PPAs in ensuring that the PPA remains in force during the entire term of the project loan and that the risk of force majeure and other adverse events is appropriately allocated and mitigated.

(3)  Product

(p. 453) 14.232  The PPA must be clear as to what is being sold—energy or renewable energy credits (‘RECs’),111 or both. PPAs for renewable energy projects often allocate rights with respect to the non-energy related characteristics of renewable power production, depending on local regulations. The power purchaser may elect to purchase all, some, or none of the non-energy related attributes of renewable power production, including such RECs or emissions credits as they exist or become applicable. Secondary markets operate in certain jurisdictions for RECs as utilities seek to meet regulatory requirements for renewable energy sourcing, and, in some cases, avoid costly penalties. Consequently, a utility offtaker often requires a bundled price for energy and all RECs, ancillary products, and environmental attributes associated with producing energy from a renewable energy source.

14.233  In addition to governing the allocation of RECs, the PPA can set out ownership rights with respect to emissions credits. In several jurisdictions, most prominently in the member states of the EU, renewable energy projects are awarded tradable emissions reductions credits which can provide a project with a valuable secondary product. The establishment of similar carbon tax or ‘cap and trade’ regimes have been discussed in other jurisdictions (such as the United States). Given the emerging regulatory framework, offtakers and project companies are incentivized to structure PPAs in a way that allows them to capture benefits from changes in law. The establishment of carbon taxes or a cap and trade regime in those jurisdictions where these measures are not in place at the project’s inception can have a substantial effect on the economics of the project; potentially increasing the price of non-renewable sources of electricity and making emissions credits from renewable energy projects significantly more valuable. These regulatory risks should be allocated in the PPA and be factored into an assessment of the appropriate price.

(4)  Liquidated damages

14.234  PPAs often contain provisions requiring payment of delayed liquidated damages if the project is not completed by a guaranteed date certain. Such provisions are equally likely in renewable PPAs, and this risk must be carefully managed where no turnkey EPC contract is available.

(5)  Change in law adjustment

14.235  Adjustments for changes in law are of particular relevance to renewable projects where the regulatory framework is still evolving and where the retroactive reduction of government support has occurred in some instances.112 The project developer must typically bear the risk of any changes in laws except for some specific foreseeable changes in law that may be negotiated to be borne by the offtaker (e.g. changes in imbalance costs). There have been generally two approaches to the allocation of change in law risk: (a) negotiated predetermined formulas and (b) a general obligation to negotiate in good faith at the time when the change occurs. If the effects of a change in law exceed an agreed upon threshold and the parties are unable to reach agreement upon a mutual amendment to the PPA, the affected party is often given the right to terminate the PPA. Offtakers might insist on broad termination rights for uncertainties associated with future (p. 454) but anticipated regulatory changes (such as migration of independent system operators to locational marginal pricing or nodal regimes) if such changes result in adverse economic consequences.

(6)  Force majeure definition

14.236  Most PPAs will contain a customary definition for force majeure as events and conditions which are outside a party’s reasonable control.113

14.237  Project developers and lenders will usually seek to ensure that transmission constraints are specifically included in the definition of force majeure for the purposes of the PPA, if the project company is not entitled to payment for any energy that would have otherwise been generated but for the occurrence of the relevant curtailment events. The trend amongst offtakers has been to allocate the transmission risks to the generator, either directly or through the force majeure clause, and in this case the offtaker must remain liable to compensate the project company for any discretionary backdown instructed by the offtaker.

Renewable resource assessments and feedstock supply contracts

14.238  Each project must have sufficient renewable energy resource to meet the project’s financial forecasts. This means that biomass projects, biofuels projects, and waste-to-energy projects must have a guaranteed and steady supply of fuel and raw materials (at a cost that does not significantly exceed the provision for those costs in the project’s financial forecasts or the cost recovery embedded in the PPA energy price). While wind, solar, and hydroelectric projects benefit in that nature provides their ‘fuel’ without cost, it is particularly important in a renewable energy project that the characteristics of the renewable energy resource be thoroughly studied, modelled, and analysed by the resource consultant during the due diligence process. To the extent that the project relies on a single source of supply, as may be the case, for example, with plants fuelled by the wind or the sun, investors are particularly focused on the availability of the project’s renewable energy resource.

14.239  In biomass and biofuels projects, the sufficiency and availability of feedstock meeting applicable specifications and the cost of such supply is critical to a project’s success in the same way as in a conventional power project. Therefore, the feedstock supply agreements must be structured to ensure that the price provisions, including any escalation indices or other price adjustment mechanisms, match the terms of the project’s PPA or other revenue projections. The feedstock contract should ideally guarantee the project a steady, uninterrupted supply of its entire requirements for fuel at fixed or predictable prices for a term at least equal to the entire life of the debt. Project lenders, however, understand that it is not always possible to achieve this ideal and will require that the project company have access to backup sources and alternative suppliers.

Procurement and construction contracts

(1)  Completion risk

14.240  Completion risk is the risk that a project will not be physically constructed on time or on budget and satisfactorily in accordance with applicable specifications and guaranteed performance criteria. Where available, turnkey construction contracts are the preferred option for sponsors and lenders, as they afford the sponsor the opportunity to shift as much completion-related risk as possible to the turnkey contractor. Turnkey construction contracts are commonly used in conventional power projects.114

(p. 455) 14.241  Turnkey construction contracts are not always available in connection with renewables projects due to the nature of the relevant technology, the diversity of technical expertise required to develop such projects, and differences in the market standard contracting arrangements. Wind power projects offer the best example of such an approach. Often the project is broken down into distinct packages, with two main contracts controlling the majority of the project’s development. First, under the Turbine Supply Agreement (or TSA), the wind turbine supplier designs, builds, and supplies the wind turbine generators (including towers, blades, rotors, and all associated equipment) and erects the turbines at the project site. Second, under the Balance of Plant (or BOP) Agreement, a civil contractor handles the civil works for the balance of the plant: the foundations and pads for the towers, access roads, collector systems, control buildings, and transmission and interconnection facilities. Offshore wind projects may further divide responsibility to different contractors for the marine works associated with those projects.

14.242  In other projects, the various components to be constructed are distinct. For example, solar PV projects may be assembled by a prime contractor or owner using various contracts to acquire the components (such as where the individual units are almost ‘plug and play’ like solar panels and PV modules, inverters, and racking) where there are significant differences across the package of required skills and technology.

14.243  As a consequence of having bifurcated agreements, the lenders’ independent engineer has an enhanced role in ensuring that there are no ‘gaps’ in the bifurcated scopes of services and that the interface points are adequately addressed.

14.244  Wherever turnkey contracts are not generally available in the marketplace, or to avoid the incurrence of a ‘turnkey’ premium that might render a project uneconomic, completion risk can be directly assumed by the sponsors through completion guarantees issued to the lenders or by affiliates of the sponsors which act as the turnkey contractor. These completion guarantees can be limited to ensuring physical completion of a project or can extend, for example, to ensuring the performance of the equipment during commercial operation.

(2)  Warranties

14.245  All construction contracts (and wind turbine supply agreements (if applicable)) will typically contain a warranty given by the contractor to repair or replace defective equipment or re-perform services (including design) for a period of one to five years following final completion. Where the applicable technology is unproven, additional warranties or guarantees of performance standards (such as availability and reliability) should be sought by the project company or may be purchased from vendors under long-term maintenance services contracts.

Project Site

14.246  In many respects, project financings are in essence complex real property transactions. Especially for renewable energy projects, the site attributes (chiefly the renewable resource assessments and proximity to transmission lines and interconnection points) create the value to be exploited by the developer. The project company and its lenders must consider all of the standard property issues, such as certainty of title to land and assurance that the lender’s mortgage will be first in priority, as well as issues of environmental liability and site conditions.

(p. 456) Environmental liability

14.247  As with any conventional power project, the project company should obtain environmental indemnification from the site seller or lessor in order that it is responsible for the clean-up of any contamination on the site that can be traced to the period before construction of the facility. Whilst not always a concern in the magnitude associated with fossil fuel powered projects, the construction and operation of renewable power facilities will still require permits and other authorizations to operate. Permitting is also an important factor, as both wind and solar projects utilize large areas of land. Environmental considerations will therefore also be as relevant to renewable projects as to others.115

Rights to the resource

14.248  In the wind energy sector, wind energy rights are most often allocated in land leases or grants of easements to the project company from landowners, and frequently royalties to landowners are tied to a nominal percentage of production. The scale of some wind and solar projects often results in a project company having to enter into agreements with many landowners, since the project site will be spread over large areas of land. For smaller distributed generation facilities, like rooftop solar installations, the host may also be the offtaker. In any event, it is important that the term of the lease or easement extends to the end of the project’s expected useful life and beyond the term of the debt. Effective negotiation of land contracts, leases, or easements with a variety of landowners can be complicated and time-consuming, and should be accomplished at the earliest stages of project development.

14.249  Wind projects must consider the potential for wind interference from the construction of neighbouring facilities, particularly adjacent projects. A neighbouring wind project with an upwind array can interfere with the availability of the wind resource at the project site. The danger of potential interference from neighbouring or future projects has given rise to the use of ‘build out agreements’ or other arrangements that restrict future development. Most commonly a build out agreement will provide for compensation to the project company for losses incurred due to the wind interference effect of any new facility. Potential detrimental impacts to the wind energy resource can also be mitigated by acquiring wind rights to adjacent lands if it is not possible to enter into build out agreements with neighbouring or planned projects. In cases where multiple projects (or subsequent phases of a single project that are separately financed) share facilities, such as transmission lines, substations, or interconnection facilities, a shared facilities agreement may allocate respective rights and responsibilities, including cost allocations and non-interference provisions.

Transmission and Interconnection

14.250  Renewable energy projects, in common with conventional power projects, are required to deliver energy to the offtaker at the applicable delivery point and, therefore, appropriate transmission and interconnection infrastructure must be in place to ensure that this can occur. However, unlike conventional thermal power projects, where the feedstock can be (p. 457) transported so that power can be generated in a location close to customers, many of the best sources of renewable power are in locations remote from load centres, like cities and energy-intensive industrial facilities. Consequently, development of utility-scale renewable power generation facilities requires concurrent heavy investment to upgrade and expand long-distance, high-voltage transmission lines.

14.251  To enable a project to be constructed, serviced, and operated—and to deliver electric power—it is therefore often necessary to build new road and transmission infrastructure. Adequate transmission availability is particularly challenging for remotely located renewable energy resources. Even where existing transmission lines do exist, it is important to investigate whether these can support additional electric current. A technical analysis from an engineering consultant of an existing transmission line’s capacity is crucial. Such analysis should address a variety of dispatch scenarios, as well as projected generation growth in the area and issues of potential congestion and curtailment risk.

14.252  New transmission lines are expensive and can take years to site, procure permitting approvals, and construct. Where they are required, these ancillary improvements are often completed by parties other than the project company. The risk that the necessary infrastructure will not be completed in a timely manner is critical for the project company’s ability to perform the PPA and must also be addressed. Securing the land rights to build new transmission lines to the point of interconnection (where title to the electricity is transferred) will typically involve many landowners. The transaction complexity of contracting with a number of landowners, combined with the additional regulatory and permitting difficulties associated with transmission construction and its high cost, is an important consideration when evaluating the potential exploitation of a renewable resource.

14.253  Where transmission and interconnection arrangements are not readily available, the project company may be expected to invest significant sums towards network upgrades and/or new interconnection facilities. Additionally, if the project is located in a capacity-constrained area, the project lenders and local utilities or regulators are likely to require an in-depth analysis of the potential curtailment risk that a project may be subjected to as a result of such constraints.

14.254  An interconnection agreement will typically provide for the construction of the required network upgrades and interconnection facilities by the relevant interconnection providers necessary to interconnect the project to the applicable grid and for a long-term interconnection service. The primary issue with such an agreement relates to completion risk. Interconnection agreements rarely include significant liquidated damages from the interconnection provider, so it is imperative that the project company manage this uncovered (uninsurable) risk in a manner acceptable to the project lenders.


14.255  In common with project financings in other sectors, successful renewable energy projects depend upon careful contractual risk allocation. Additionally, other particular concerns also need to be addressed, including: renewable resource availability, transmission constraints, available regulatory incentives or subsidies, and split contracting arrangements. Aligning all of the various components into a coherent package of rights and responsibilities is critical to assessing and achieving economic success.

(p. 458) Section E—Financing Nuclear Power Projects

Paul Murphy, Murphy Energy & Infrastructure Consulting, LLC, Clive Ransome, and Şeyda Duman, Milbank LLP


14.256  Perhaps the simplest description of project financing is to say that it is the long-term financing of a project based on the future cashflows of the project itself rather than the assets or creditworthiness of sponsors, to which there is limited or no recourse. Based on that description any reader who is a project finance purist will be surprised to find a chapter on nuclear power projects (‘NPPs’) in this book as any reader familiar with the history of financing within the nuclear power industry will already know that no NPP has ever been ‘project financed’. Despite a lack of project finance history in this sector, it is nonetheless relevant to address NPPs in the context of financing, considering that many project financing principles are applied to NPPs and that such principles heavily influence the thinking of prospective financiers to a project.

Challenges of Developing and Financing NPPs

14.257  In order to understand why no NPP has thus far been project financed, it is important to understand first why developing and financing NPPs has been very difficult, historically. In this chapter we look at the unique challenges of developing NPPs, these being:

  1. (1)  regulatory uncertainty;

  2. (2)  high capital costs;

  3. (3)  long development and construction periods;

  4. (4)  reputational risk;

  5. (5)  political commitment; and

  6. (6)  concerns relating to technology, fuel, and human resources.

We also look at the alternative financing structures which have been used in the absence of traditional project financing of NPPs.

Regulatory uncertainty

14.258  The regulatory environment within which NPPs must operate is a key factor in the development, financing, and operation of NPPs. There is a series of licensing events that are critical and unique to the nuclear industry. To begin, each country with an NPP has a national regulatory authority that is specifically dedicated to nuclear activities. If structured in accordance with the guidance from the International Atomic Energy Agency (‘IAEA’), such an entity is an independent regulatory body and, therefore, insulated (at least in theory) from political and other influences.

14.259  Such regulatory authority has a series of activities which influence the project development cycle. First, the site on which the NPP is to be located must receive a site permit. Second, the nuclear reactor design must have a design certification, which involves the regulator (p. 459) approving the base engineering design for the reactor technology. Third, prior to construction, the regulator must issue a construction licence, which allows key construction (beyond site preparation) to commence. Finally, prior to loading nuclear fuel in the reactor, the regulator must issue an operating licence, which both permits the operation of the facility and provides certification of the operator, who must demonstrate adequate technical and financial capability to operate the NPP.

14.260  The nuclear regulator continues to monitor the project through the construction and operation of the facility. Such monitoring includes the ability to halt plant activities and, in extreme cases, shut down the NPP. Lenders look to the regulator to be the ‘adult in the room’, as lenders have neither the technical capability nor the access to ensure that the NPP is being operated safely. Thus, a capable and independent regulator is a key precondition for financing an NPP, with a knowledgeable and authoritative regulator being a confidence-building measure for project participants.

14.261  The safety case is one of the critical issues for NPP development and operation. However, because of its importance and attendant scrutiny in respect thereof, the regulatory process has been an historical source of cost and schedule overruns on NPPs. Moreover, given this history and the lockstep process inherent to the licensing process, regulatory change (as evidenced after the accidents at Three Mile Island (1979), Chernobyl (1986), and Fukushima (2011)) and regulatory inexperience (for countries looking to commence nuclear power programmes) become key pressure points in the financing process. Lenders need to understand the regulatory process and the risk allocation among project participants in respect thereof.

14.262  Finally, with the emergence of both new reactor technologies and newcomer countries that wish to develop NPPs, the experience and technical capability of the regulator (or lack thereof in either case) become key risk factors in the financing process. Absent a proven track record for NPPs in general and/or specific reactor technologies, the financiers (and project developers) judge regulatory risk to be a major area of uncertainty in the project development, execution, and financing processes.

High capital costs

14.263  Current nuclear reactor designs are in excess of 1,000 MWe. Depending on the type of nuclear reactor design, an NPP (of the 1,000 MWe+ class) could have a capital cost in the neighbourhood of US$6–12 billion (depending on reactor type and site conditions). However, given the optimization/economies of scale to be achieved by dual unit construction, such projects are often grouped, resulting in a total project cost of around US$ 12 to 20 billion. Current trends toward four-unit projects (Barakah in the UAE, Akkuyu in Turkey, and El Dabaa in Egypt) result in further upward scaling, necessitating even larger debt and equity commitments.

14.264  Such significant project costs are not unique to the nuclear industry, considering the costs of developing large-scale petrochemical facilities, LNG facilities, and natural gas fields; however, as measured against the market capitalization of most of the utilities that would undertake such a project, an NPP has the potential to be a ‘bet the company’ project for the utility. At a minimum, rating agencies view NPPs as credit negative undertakings, and a significant ratings downgrade for a utility could have further negative implications for the utility’s ability to raise capital across all its business activities.

(p. 460) 14.265  This credit negative view from the ratings agencies is based on an historical analysis of the ability (or lack thereof) of developers/owners to deliver NPPs in an on-time/on-budget fashion. Financing, too, is burdened, by this history of cost overruns and delays. Examples include EDF’s Flamanville 3 Reactor, the cost of which ballooned to triple the original budget,116 and Areva’s Olkiluoto 3 reactor in Finland, which has been delayed by 11 years.117 Given the scale of NPPs, the risk of delays and cost overruns puts significant pressure on financing structures and the need for significant equity support to stand behind the project company and ensure completion of the project.

Long development and construction periods

14.266  These large-scale facilities have lengthy construction periods. From ‘first safety concrete’ through commercial operation, the construction period can run, on average, for 60 months for a stand-alone unit. First safety concrete is a relevant measuring point for the construction cycle because of the licensing process (discussed previously) that supports the overall construction schedule. Due to the unique nature of an NPP, the licensing process is particularly important. Issuance of the construction licence from the nuclear regulator having authority over the NPP is a key milestone in the construction process, and it is also a point prior to which financial close for the debt facility is unlikely.

14.267  From a financing perspective, the construction period represents the greatest risk for NPPs. With the aforementioned history of significant cost and schedule overruns, lenders and passive equity investors have been reluctant to finance NPPs; however, once commercial operation has been achieved and the unit has come out of its first refuelling outage (anywhere from 12 to 18 months after commercial operation), both lenders and investors have viewed NPPs as attractive assets historically. Such view is based on a recognition that NPPs are relatively cheap to operate, variability in nuclear fuel pricing has a negligible impact on the overall operating pro forma for the asset, the asset is a base-load form of generation, and the operating life can run for 60 years. Such qualities make the asset particularly attractive for investors with long investment horizons, such as pension funds and insurance companies, and these qualities similarly create interesting opportunities for refinancing (both debt and equity) after this initial period of operation. However, with premature shutdowns (and threats of shutdowns) of reactors in the US, due to deregulation of electricity markets and other economic factors (low natural gas prices; subsidies and dispatch preferences for renewable energy), such views about the long-term attractiveness of NPPs must also now be reconsidered, depending on the market conditions in which they operate.

Reputational risk

14.268  ‘Reputational risk’ is a topic that can encompass a number of concepts. Furthermore, it is a concept that is relevant to lenders involved in infrastructure projects, whether or not such project is an NPP. However, because of the unique characteristics of, and issues facing, NPPs, the idea of ‘reputational risk’ encompasses a wider range and more significant set (p. 461) of considerations. Of note, both ECAs and commercial banks have specific lending guidelines/policies for NPPs,118 and, at the extreme, the World Bank has an absolute prohibition on providing financial support to NPPs.

International standards and practices

14.269  Reputational risk encompasses the concept that the project will meet internationally recognized standards. This concept can be covered in financing documentation by the concept of ‘Prudent Industry Practice’. An example of a definition of Prudent Industry Practice is as follows:

‘Prudent Industry Practice’ means the standards, practices, methods, and procedures consistent with that degree of skill, diligence, judgment, prudence, and foresight which would ordinarily be expected from an international skilled and experienced owner, contractor, equipment manufacturer, or, as the case may be, operator, engaged in designing, engineering, constructing, developing, commissioning, repairing, refurbishing, operating, insuring, maintaining, and/or decommissioning a nuclear power plant, in each case taking into account and giving appropriate consideration to all applicable standards and guidelines and local conditions.

14.270  Part of the diligence process will be for the lenders to work with their technical adviser to ensure that the project complies with this requirement, especially given the sensitivities (both perceived and real) involved in an NPP.

Public acceptance

14.271  NPPs are surrounded by a heightened sensitivity by the general public. NPP risks and the safety case are often misunderstood, and it is incumbent upon project developers to work with the public in order to develop the necessary level of local support for the project. Of note, public opinion surveys of local communities around operating NPPs indicate very high approval rates; however, during project planning and development, NPPs suffer from a particularly high level of ‘NIMBY’ sensitivity. The negative consequences of failing to achieve public acceptance is underscored by the histories at Shoreham (Long Island, US), Bataan (the Philippines), Zwentendorf (Austria), Kudankulam 1 and 2 (India), the cancellation of Italy’s civilian nuclear power programme following Chernobyl (and the referendum in 2011 that blocked an attempt by Enel to restart the programme), and, most recently, Germany’s decision to shut down its 17 nuclear power stations by 2022 following Fukushima.


14.272  Sustainability considerations have risen in importance to the financial community, and lenders will want to see that compliance with local environmental laws and international standards (e.g. the Equator Principles and/or IFC guidelines) is observed. Such matters will necessarily bring project lifecycle considerations to the lenders’ analysis of the project, as lenders will look to see that the NPP planning includes a spent fuel/nuclear waste plan and a decommissioning plan, demonstrating the lenders’ desire to look beyond the tenor (p. 462) of the debt. Sustainability, in particular, is a combination of both art and science, where, oftentimes, there is no clear solution that is measurable and quantifiable; instead, the compliance plan can be qualitative, not quantitative, and, thus, much more difficult to resolve. Sustainability considerations can be applied through a number of mechanisms, with each a function of the financial institution and/or the location of the project.119

International agreements

14.273  The nuclear industry is subject to a set of international agreements, which lenders will assess vis-à-vis the commitments of the host country. These agreements fall into four key categories—safety (of generation), security (of the physical asset), safeguards (i.e. non-proliferation), and nuclear liability (to third parties in the event of a nuclear incident).120




  • •  Convention on Nuclear Safety

  • •  Convention on Early Notification of a Nuclear Accident

  • •  Joint Convention on the Safety of Spent Fuel Management and on the Safety of Radioactive Waste Management


  • •  Convention on the Physical Protection of Nuclear Material (and the Amendment to the same)

  • •  International Convention for the Suppression of Acts of Nuclear Terrorism


  • •  The Treaty on the Non-Proliferation of Nuclear Weapons

  • •  Agreement between [host country] and the IAEA for the Application of Safeguards in Connection with the Treaty on the Non-Proliferation of Nuclear Weapons

  • •  Protocol Additional to the Agreement with the IAEA for the Application of Safeguards in Connection with the Treaty on the Non-Proliferation of Nuclear Weapons

  • •  Comprehensive Nuclear Test-Ban Treaty and Protocol to the Comprehensive Nuclear Test-Ban Treaty

  • •  Nuclear Suppliers Group Export Guidelines

Nuclear Liability

  • •  Vienna Convention on Civil Liability for Nuclear Damage (‘Vienna Convention’) and Protocol to Amend the Vienna Convention on Civil Liability for Nuclear Damage (‘1997 Amendments’)

  • •  Convention on Third Party Liability in the Field of Nuclear Energy of 29 July 1960, as amended by the Additional Protocol of 28 January 1964 and by the Protocol of 16 November 1982 (‘Paris Convention’); and 2004 Protocol to Amend the Paris Convention

  • •  Convention of 31 January 1963 Supplementary to the Paris Convention of 29 July 1960, as amended by the additional Protocol of 28 January 1964 and by the Protocol of 16 November 1982 (‘Brussels Supplementary Convention’); and 2004 Protocol to Amend the Brussels Supplementary Convention

  • •  Joint Protocol Relating to the Application of the Vienna Convention and the Paris Convention

  • •  Convention on Supplementary Compensation for Nuclear Damage

(p. 463) 14.274  When comparing nuclear power to its peer group, this structure of international treaty commitments, as a means of holding the nuclear power industry accountable to a set of uniform obligations, is unparalleled. Moreover, the presence of an international body—the IAEA—which provides a pseudo governance function for the industry, has no comparison with other forms of power generation or infrastructure. This set of rules, coupled with the presence of the IAEA, provides lenders with a benchmark for assessing the quality of potential NPPs and the commitment of the host government to international best practices.

Nuclear liability and insurance

14.275  In the event of a nuclear incident at an NPP, where a radiological release occurs from containment, such release has the potential—in the case of a release on the scale of Chernobyl or Fukushima—to cause physical injury or property damage to third parties. As a precursor to this discussion, it is important to understand that an examination of nuclear liability does not involve damage to the asset itself. Such damage to the asset is covered within the contract for construction of the NPP. However, damage to third parties is outside the bounds of the contract and, due to a unique set of conditions, requires special treatment.

14.276  Under the nuclear liability conventions listed previously, there are several key principles which govern such conventions:

  1. (1)  Strict liability of the nuclear operator;

  2. (2)  All nuclear liability is channelled to the owner/operator of the facility, regardless of fault (known as ‘legal channelling’ and distinguishable from the US Price–Anderson system of ‘economic channelling’);

  3. (3)  All claims are afforded equal standing, regardless of nationality, domicile, or residence;

  4. (4)  Mandatory financial coverage of the operator’s liability;

  5. (5)  Exclusive jurisdiction (only courts of the member state in which the nuclear accident occurs have jurisdiction, and usually one specific court in such member state will be designated to handle nuclear liability cases);

  6. (6)  Limitation of liability in amount and in time; and

  7. (7)  Terrorism does not relieve an owner/operator of liability.121

14.277  Despite the breadth of such principles, two key concerns remain. First, no international nuclear liability convention has ever been tested in a court of law. Second, such conventions are only as effective as the membership covered thereunder (in other words, if cross-border damage occurs in a member state that is not a fellow treaty member, then legal channelling does not occur and the project participants are exposed to claims in such neighbouring jurisdictions and without the benefit of the limits of liability specified under the applicable treaty; we refer to this risk as ‘gap risk’).

14.278  Under any nuclear liability framework, insurance provides a means of mitigating risk. From a nuclear specific perspective, nuclear liability conventions and/or national legal regimes aid in attempting to specify the maximum exposure faced by the nuclear industry in the development and operation of a nuclear power facility. Insurance (carried by the licensed operator as a legal requirement under national law) then provides the means for covering such defined exposure in the event of a nuclear incident.

(p. 464) 14.279  Unique to the nuclear industry, however, is the limited availability and prohibitive cost of certain types of insurance. While insurance prior to fuel loading is generally readily obtainable (and commercially reasonable) for engineering, procurement, and construction contractors, their subcontractors, and technology and equipment providers, to include nuclear steam supply system suppliers (the foregoing parties collectively comprising the ‘Suppliers’), the insurance marketplace is limited in its coverage for nuclear damage after fuel loading has occurred. Insurers have limited capacity to provide nuclear damage insurance, recognizing that the amounts required by the nuclear industry to cover both third-party exposure and on-site property damage are commercially significant. The former is driven by national laws and by international conventions; the latter is driven by facility value. Furthermore, even though nuclear insurance premiums favourably reflect the nuclear industry’s successful operating track record, insurers still must carry such risk with a view towards the catastrophic potential of a nuclear incident (and, thus, limit their portfolio exposure). The marketplace is, therefore, comprised of nuclear insurance risk-sharing pools,122 which, effectively, are only available to owners/operators. Recognizing that owners/operators already will need to carry certain amounts of coverage for nuclear damage to the facility, coupled with the high value of such facilities, these insurance pools, in effect, are only able to maintain the capacity to support the owner/operator market.

14.280  As a consequence of this limited capacity, there is no meaningful insurance market for nuclear suppliers for the provision of post fuel load insurance to cover nuclear damage to the project and the facility site. The net effect of this market reality is that the owner/operator is best positioned to assume all liability for nuclear damage after fuel loading. While such responsibility, in respect of third-party claims, is imposed by law under any legal channelling regime, such responsibility in respect of on-site property damage is imposed as an economic reality. Without the ability to insure nuclear-related property damage risks after fuel loading, nuclear suppliers have historically refused to take responsibility for such risk, recognizing that, without an insurance backstop, pricing such risk into contracts would be prohibitive. With the assumption of such risk by the owner/operator, economic efficiency can be achieved, as risk is allocated to the one party that can insure against it. Furthermore, the owner/operator can spread the cost of such risk over the lifecycle of the project.