Getting the investment-risk balance right
Nations with the most attractive subsidy and policy frameworks for low-carbon assets will have the greatest success attracting investment, write Ingrid Holmes and Tony White, senior associate and senior adviser, Climate Change Capital
LOW-CARBON power-generation assets are expensive. For a UK offshore wind farm, for example, capital spending is likely to amount to £1bn ($1.5bn) or more per gigawatt of capacity. Such projects cannot be undertaken without state subsidies and a policy framework that delivers a deal pipeline.
In addition, financing is scarce: whereas at the height of the debt boom perhaps one or two banks might have taken on the financing risk associated with such projects, the shortage of capital is creating a greater need for a project-finance approach to funding construction. In turn, this requires a syndicated approach to financing projects – just at a time when trust between banks is low. In addition, the high-costs of low-carbon projects have been exacerbated by unfavourable exchange rates, as developers such as Centrica and E.On have said.
The UK solution, announced in the Budget on 22 April 2009, was to increase the support available to offshore wind from £75 a megawatt hour (MWh) to £100/MWh for a short period only. This was combined with a promise of access to European Investment Bank funds, either to projects or to banks wishing to lend to projects. The response of the market has been mixed - developers that have signed supply contracts in the past few weeks are extremely unhappy, while others have described the action as a welcome, targeted response to what it is hoped will prove to be a temporary problem.
However, the UK offshore wind market's financing problems highlight the problems facing the low-carbon sector in general: high costs, a shortage of capital and the need for strong supportive policy frameworks – especially when the technology has not yet been demonstrated. Carbon capture and storage (CCS), for example, faces the same difficulties. These technologies will develop most rapidly in regions that recognise and address these issues most effectively – creating an attractive environment for international investors.
Role of oil prices
Conventional economic theory suggests that high oil prices should ease the transition to a low-carbon economy: the higher the price of fossil fuels, the lower the incentives required to promote the switch should become. But the situation is not that straightforward: high oil prices have, especially when combined with a financial crisis, led to a reduction in demand and a subsequent collapse in both fossil fuel prices and the price of carbon allowances in the European Emissions Trading Scheme (EU ETS). This volatility has made investors wary of projects in which returns are highly dependent on fossil fuel prices.
The problem, especially for investments based on the price of emissions allowances, is that the value of these allowances is dependent not only on price differentials between gas and coal, but also on the markets' assessment of the political appetite for climate-change legislation. As a result, recent oil-price patterns have, if anything, increased investors' required return for low-carbon assets, effectively increasing their cost.
This situation has occurred at a bad time; achieving goals such as the European Commission's 20-20-20 target (to reduce greenhouse-gas emissions, increase the share of renewables in the energy mix and cut energy waste – all by 20% and all by 2020), will require considerable investment, particularly in power infrastructure, over a very short period. For the past two decades, European energy policy has been based on the assumption that markets are best able to provide secure supplies of energy at lowest cost – resulting in the partial liberalisation of the power sector.
On the whole, the system has worked well and new plants have been commissioned. However, since the late 1990s, concerns have been raised about the ability of open competitive markets to provide sufficient capacity for peak demand. Indeed, with the impending closure of older fossil-fuel power stations, required by the Large Combustion Plant Directive, the possibility that the market will fail to deliver new capacity is increasing in probability. Moreover, although incumbent market participants are promoting less carbon-intensive forms of generation, very little is under construction. It is as if the market is not signalling sufficiently clearly the imperative either for additional capacity or emissions reductions.
Indeed, with hindsight, it is clear that a fully liberalised market has yet to deliver any new plant in the UK. The power stations constructed during the dash for gas were all built on the back of market power; either the incumbent energy suppliers provided long-term contracts to independent power projects, confident they could pass the costs on to their domestic customer base, or they were built by incumbents with significant market share.
Little new capacity added
Since 2000, only vertically integrated players have ordered new plants – Centrica, E.On, Scottish and Southern Energy and RWE, all using comparatively low capital cost combined-cycle gas-fired technology, as they could be confident of being able to pass their full costs to their customers.
Merchant new entrants have not been seen at any large scale. The reason for their absence, despite the impending supply shortfall, is that the market is, paradoxically, working properly. A power market that sets prices based on the half-hourly balance of supply and demand would tend to produce highly volatile prices. Prices tend to fall close to the marginal costs of generation during periods of surplus capacity, but to rise significantly when demand approaches the available supply.
Consequently, the profitability of generation in a competitive market is expected to be low for most of the time, and rise only at times of shortage. Because a developer will build new plant only if forecast prices will be sufficient to generate an acceptable return on capital, this implies plant will be ordered only when prices reflect an impending shortage. If prices are not sufficiently attractive, the developer will not be able to raise finance and this seems to be the situation in the UK.
Moreover, even if prices were to rise substantially, and the government did not intervene, developers would choose to build plant that is most easily financeable. Given the rather unpredictable profit stream that may be expected from the competitive power market, developers would favour generating capacity with a low capital cost and a short construction time over highly capital intensive forms of generation, even if the average lifetime generation costs of the capital-intensive technologies were lower. As a result, the claim that markets deliver the lowest-cost solution may not apply to a power generation market with prices defined every half hour, especially when the less carbon-intensive technologies – hydro, wind, nuclear, solar and CCS – are highly capital intensive.
Indeed, the market approach to emissions reductions would suggest that simply tightening the cap in the emissions-trading scheme would be sufficient to prompt the necessary large-scale investment in low-carbon generation technologies. However, experience from the EU ETS suggests that, although prices for the associated emissions allowances would be expected to rise, the necessary investment would not be forthcoming at a sufficient rate.
The price volatility exhibited by commodity markets leads to the providers of finance to these projects taking a conservative view of future prices when undertaking financial appraisals. That is why, despite oil prices exceeding $140 a barrel in mid-2008, few oil fields were developed that required prices greater than $50/b for financial viability. In the event, such caution was well placed as oil prices fell to under $40/b by December 2008. So it is not surprising that investors are taking a cautious approach to investments whose economic viability is dependent on the highly volatile price of emissions allowances. After all, investment is only one option; if the returns do not justify the reward, the projects will not be built.
Accelerating investment in low carbon assets
To accelerate investment in low-carbon assets, governments will need to understand and address the risks to deployment faced by developers. Conventionally, energy-project developers face four types of risk: construction, operation, timing and fuel prices. If governments wish to see investment accelerated they will need to provide convincing policy road-maps to assist the private sector in managing these risks - with a particular emphasis on timing and fuel-type risk, which can be addressed through appropriate subsidy and/or regulatory regimes.
Subsidies such as feed-in-tariffs, employed for example in Spain and Germany to incentivise solar photovoltaic, are favoured by investors as transparent and stable because they represent fixed sums of money paid for each MWh of power exported over long periods. These ensure customers shoulder the risks of timing and fuel prices, but that developers assume the risks associated with construction and operation. The German scheme runs for the first 20 years of a project, whereas the Spanish scheme lasts 25 years; in both cases the value of the subsidy declines with time.
The UK's market-based mechanism – the Renewable Obligation - is in some ways less attractive because it is a more volatile subsidy whose value is determined by the volume of renewable energy sold into the market at any one time. In this case, customers assume the risks associated with fossil fuel prices, but the developers assume construction, operation and timing risk. However, the returns are higher than available through the Spanish or German feed in tariffs and the scheme has the added benefit of providing a return to developers until 2027. In contrast, the US favours tax credits to incentivise wind energy along with loan guarantees and grants for construction facilities. The tax credits are generous, but run only to 2012/13, depending on technology.
Nations with the most attractive subsidy and policy-support frameworks for low-carbon assets will have the greatest success in attracting the largest amount of investment in their infrastructure. During the G20 meeting in London in April several governments made announcements about green fiscal stimulus packages. South Korea and China will spend around 80% and 37% of their stimulus packages on green measures, respectively, whereas the US, France and Germany have allocated only around 10%. In the UK, some 20% of budget spend focused on green initiatives.
But as the UK case demonstrates, demarginalising the economics of projects through policy support is not enough - in the short term there will have to be a wider focus on getting the financial markets moving to provide the confidence and debt capital needed to build a large number of projects.
The competition for capital is only just beginning as we move to an increasingly carbon-constrained world. The International Energy Agency estimates annual global investment of $1.7 trillion will be needed to put the world on a path to avoid the worst impacts of climate change by 2030. Governments around the world are waking up to the necessity of investing in low-carbon infrastructure assets - and the risks and opportunities it represents.
Overarching financability is the key: countries that take a co-ordinated approach to both aspects of the problem - and that appropriately allocate risk between government and private-sector stakeholders - will attract more investment and see the greatest level of success.