Renewable Energy Finance: Powering The Future

Powering the Future

Charles W Donovan

• Editorial: ICP
• Año: 2015
• ISBN:
  9781783267781
• Categoría: Biological Sciences
• Categoría: Science General

Renewable Energy Finance describes in rich detail current best practices and evolving trends in clean energy investing. With contributions from some of the world's leading experts in energy finance, the book documents how investors are spending over US$200 billion each year on financing renewable energy and positioning themselves in a global investment market that will continue to expand at double-digit growth rates through the end of the decade. The book describes with first-hand experiences the challenges of "keeping the lights on" amid rising conventional energy prices and looming environmental risks.

Chapters describe project financing vehicles for a range of renewable energy technologies including solar photovoltaic power plants, offshore wind farms, and bio-fuel refineries, as well as financing practices in a diverse set of countries such as the United States, the United Kingdom, India, and China. The book gives readers a unique insiders' perspective on how renewable energy deals actually get done, and is a go-to reference manual for understanding how to fund investment projects in renewable energy. Drawing together contributions from senior executives and academic thought-leaders, Renewable Energy Finance will serve an audience of readers craving a practitioner's perspective that avoids industry clichés, self-promotion, and grandstanding.

Contents:

• Section I:
  • Introduction to Renewable Energy Finance (Charles Donovan)
  • The Clean Energy Imperative (Jim Skea)
  • How Much Renewable Energy Will the Global Economy Need? (Guy Turner)
  • Investor-Specific Cost of Capital and Renewable Energy Investment Decisions (Thorsten Helms, Sarah Salm & Rolf Wüstenhagen)
• Section II:
  • Markets, Governments and Renewable Electricity (Richard Green, Alan Howard & Sabine Howard)
  • The Impact of Government Policies on Renewable Energy Investment (Gireesh Shrimali)
  • Mobilizing Private Sector Capital in Developing Countries (Alexandre Chavarot & Matthew Konieczny)
  • Renewable Energy Finance in China (Philip Andrews-Speed & Sufang Zhang)
  • Measuring the Carbon Delta of Investment Performance (Celine McInerney & Derek Bunn)
• Section III:
  • The Growing Role for Private Equity (Brian Potskowski & Chris Hunt)
  • Project Finance and the Supply of Credit from Commercial Banks (Alejandro Ciruelos Alonso)
  • The Untapped Potential of Institutional Investors (David Nelson)
  • The Spectacular Growth of Solar PV Leasing (Bruce Usher & Albert Gore)
  • Crowdfunding: Ready for the Big Leagues? (Karl Harder & Sam Friggens)

Readership: Advance economics undergraduates and postgraduates undertaking module in Environmental and Energy. Finance students undertaking Energy Finance modules. Researchers and interested financial professionals looking for a reference volume on clean energy investing.

Section II

Chapter Four

Markets, Governments and
Renewable Electricity

Richard Green, Alan and Sabine Howard Professor of
Sustainable Energy Business, Imperial College Business School

Introduction

The starting point of this chapter is that renewable electricity projects produce a valuable commodity which is traded on many markets around the world, but that they do so at a cost which is generally higher than the prices in those markets. Such projects can only be financially viable with some kind of support from a government, but will continue to interact with the market, even if they no longer rely on it for revenues. This chapter discusses those interactions and the main ways in which governments support renewable energy. It does not say much about carbon pricing, which could support renewable generation indirectly by raising the cost of competing technologies and hence the price that renewables have to beat. At present, most of the carbon prices seen around the world, whether in the form of taxes or from tradable emissions permits, are low relative to central estimates of the social cost of carbon and they are too low to make most renewable generators competitive without additional support. As described in the book’s Introduction, that support can be justified as a way of overcoming market failures in research and development (R&D) and in innovation, as well as in terms of the failure to price carbon properly.

When discussing renewable electricity generation, it is important to remember the key physical characteristics of electricity. These include the facts that it is hard to store, so demand and generation must balance at every moment in time, and that flows through the power grid are hard to control, so that the system must be operated as a coordinated unit. The traditional response to these facts, as described in the next section, was vertical integration and economic regulation; once some countries started to introduce electricity markets, they had to take these constraints into account. The choice between a fully regulated electricity industry and one with markets has significant consequences for renewable generators. It is relatively straightforward to instruct a regulated firm to introduce renewable power, but much harder to secure it in a market-based industry. Next, the chapter discusses the main ways in which governments provide additional revenue to renewable projects, in terms of their advantages and disadvantages for the project’s investors, and its interactions with the wider market. Those interactions are further considered in the following section, thinking about both the short-term impact on market prices and the longer-term effect on other generators. The section also asks whether present market designs can provide the right incentives for the transition to a low-carbon energy system, or whether a return to regulation offers better prospects. Brief conclusions also touch on this point, but in the context of the need to engage consumers and adopt new business models; something which a regulated system is unlikely to excel at.

How the Physical Nature of Electricity Shapes its Markets

For reasons that will be explored shortly, electricity generators must be operated as an integrated system. Traditionally, this meant that the industry was operated as a monopoly: sometimes nationwide but sometimes on a more local basis. The monopoly might be vertically integrated from the power station to the customer’s meter, but in many countries a large generation and transmission organisation would sell bulk supplies of power to local distribution companies. Large industrial firms were often allowed to run their own generators, and the electricity supply industry would accept their surplus output, but the underlying principle was that the electricity system should be organised in a way that reflected the tight central control required. If the industry was a natural monopoly, then it would be necessary to control its behaviour, either by public ownership or by government regulation.

Over time, however, it has been recognised that central control of how generators are operated need not mean unified ownership. In many countries, new generating plants have been built as independent power producers (IPPs), running the station and selling its output to the grid as the main focus of their business, rather than as the byproduct from an industrial process. The US Public Utility Regulatory Policies Act of 1978 allowed this, in order to encourage renewable generation and combined heat and power; in other countries, IPPs have access to capital markets that are not available to the incumbents and can be seen as a way of increasing capacity without breaching limits on public borrowing. International institutions such as the World Bank have encouraged many middle- and low-income countries to introduce IPPs as an alternative to state-owned monopoly generation.

The other model that combined central coordination without unified ownership was the power pool, through which a number of companies ran their power stations in ways intended to minimise the cost of the whole. Chile introduced a market based on a power pool in 1978 (although most financial flows were based on regulated prices and contracts) and the UK made a pool-based market the centrepiece of the electricity industry’s privatisation in 1990. The following year, Norway expanded the scope of its power pool to create a fully fledged market that grew into the world’s first international power market, Nord Pool. The success of these early markets encouraged many other countries to follow suit, with the EU adopting its first Electricity Directive in 1996, starting a process of liberalisation with the aim of creating a Single Electricity Market. In the US, several regional markets were created in the late 1990s, although the implosion of California’s badly designed restructuring was a significant set-back. The market designs have since been improved, and ten regional transmission organisations manage about 60% of the power delivered to US consumers. In the west and south-east of the country, however, the traditional model based around integrated and regulated utilities still dominates, albeit with some IPPs in every state.

While the electricity industry’s organisational forms differ around the world, the laws of physics do not. At the moment, electricity cannot economically be stored on a large scale, except where the local landscape allows a pumped storage hydro-electric station to pump water uphill when power is in surplus and therefore cheap, running it downhill through the turbines later to generate when the electricity will be scarcer and hence more valuable. If consumers try to take more (or less) energy out of the power system than generators are putting into it, the frequency with which every generator is turning will slow (or rise). A small deviation from the design frequency (50 cycles a second (Hz) in Europe, 60 Hz in North America) can be tolerated, but a large imbalance in either direction will cause the system to fail. Because power stations take time to start, the system operator must always maintain a spinning reserve of stations currently running at less than their full capacity and hence able to increase output very quickly. Other stations are contracted to start up and provide power at short notice, should demand be higher than expected or another generator fail. Some (typically large) customers are also able to reduce their demand on request and are paid for doing so, but the electricity market is complicated by the fact that the balance between demand and supply can change far more quickly than the prices which most customers see. The market for oil is kept in balance by producers and consumers autonomously changing their behaviour in response to price changes, and by adjustments to stocks; an electricity system requires a system operator that can quickly issue direct commands. Where there is an electricity market, these commands will need to be accompanied by appropriate payments, but they must be issued more quickly than a contract can be negotiated.

A second key fact about electricity is that current flows through all the lines on an interconnected system, in inverse proportion to the resistance (or strictly speaking, impedance) on each line. If one element fails, whether a power station or a transmission line, the flows will immediately reallocate themselves to reflect the new situation, even though this might mean that a line or transformer somewhere is overloaded. If it is, a circuit-breaker will be triggered to protect that asset, and the flows will change once more. If the new pattern of flows risks an overload elsewhere, it is possible for a series of failures to cascade through the grid, blacking out a large area. Recent examples include Ontario and New York State in August 2003, Italy in September 2003, much of Germany and its neighbours in 2006 and Denmark and southern Sweden, also in September 2003. The latter blackout is unusual in that it occurred as a result of two separate faults in quick succession. The system should always be run in ‘N minus one’ mode, so that it remains stable after any single problem (something that was not achieved before the other examples mentioned); even so, troubles do sometimes come in pairs¹.

These facts mean that the value of electricity depends upon when, and where, it is generated. Two popular measures of the relative cost of different technologies ignore this. The levelised cost of electricity (LCOE) simply divides the net present value of the power that a station might be expected to generate (running with a high load factor) by the net present value of its costs. It is inappropriate for comparing the cost of stations that would be expected to run for different times during the year. The second measure, grid parity, identifies the point when the cost per kWh of a technology, such as a solar PV panel, is equal to the price per kWh paid by the consumer thinking of installing it. This is the relevant calculation for that consumer, but ignores the fact that electricity prices also cover the fixed cost of the transmission and distribution grids, and those costs have to be paid by someone. Utilities may face a vicious circle if they try to cover those fixed costs from a declining sales volume, thus raising their prices and making it more attractive to install PV.

Electricity markets ought to reflect the differing value of power at different times. Electricity generated when demand is high is normally more valuable than at times of low demand — indeed, the market price of power at those times can even be negative. This is because many power stations cannot generate at low levels for sustained periods, but if they are switched off instead, they will then have to incur the fuel cost and the wear and tear of starting up again once demand has risen. Their owners are willing to pay to avoid a restart, and the market price of power can reflect this. Similarly, electricity which cannot be transmitted to distant customers without risking an overload on the grid is less valuable than power from a station close to the load, which can charge a premium price.

Electricity markets in the US (and some other countries) reflect these facts with a system known as locational marginal pricing, or nodal pricing. In the so-called day-ahead market, every generator in the market submits offers to sell power, or bids to buy back electricity that it has already committed to produce through a bilateral contract. Similarly, the load-serving entities responsible for meeting customer demands bid to buy power, or offer to sell it back if they had over-contracted for their needs through bilateral trading. The independent system operator (ISO) for the market combines these offers and bids, and its knowledge of the transmission system’s characteristics, to produce the least-cost schedule for the following day that would balance generation and demand while observing transmission constraints. The ISO calculates the marginal cost of increasing demand in each hour by a small amount at each node on the system in turn; this is the price for that node in that hour. Other prices are also calculated and paid for stations which provide reserve. Once the trades in this market have been published, generators are committed to provide the schedu...