Christina Hood, Climate Change Unit
The energy and climate-policy communities are becoming more concerned about the suitability of current wholesale electricity market designs for decarbonisation of the power sector. This discussion is most advanced in the United Kingdom, where the government has announced proposals for significant market reform. Two key issues are under debate: i) whether current market structures are lower risk for fossil fuel plants due to the way electricity market prices track fuel costs; and ii) whether the prospect of zero- or low-price periods in the market - arising from a large penetration of renewable and nuclear energy - is a risk for investors. Delayed investment will raise the cost of decarbonisation, so policies to address risk may be needed as part of a least-cost response. A number of policies are being explored to address these issues.
Decarbonisation of the power sector will require a significant change in investment patterns. The IEA 450 Scenario indicates that early decarbonisation of the power sector is necessary to achieve the global goal of stabilising temperature rise to 2°C, as agreed in Cancun (December 2010). In the 450 Scenario, investment in low-carbon generating capacity (renewables, nuclear, and fossil-fuel plants with carbon capture and storage) comprises 55% of total new capacity from now until 2020, and 91% from 2020 to 2035. In OECD countries, the proportion of low-carbon investment is even higher: 70% of new capacity to 2020 and 95% of new capacity from 2020 to 2035 (IEA, 2010).
In countries with liberalised electricity markets, power sector investment decisions are decentralised, and therefore are influenced rather than directed by government policies. Investors will assess the expected costs (plant capital costs, operation and maintenance, fuel and carbon) against anticipated returns from the electricity market and any other support measures. Uncertainties and risks in both costs and returns will also play a significant role in investment decisions (IEA, 2007).
To date, much analysis of power sector decarbonisation has focused primarily on policy interventions to support the development and deployment of low-carbon technologies, to bring down their costs and so reduce the long-term costs of decarbonisation. Now, however, there is a growing focus on risk as well as cost. In particular, there is a question of whether current electricity market designs make low-carbon investment, which typically has high up-front capital costs, riskier than continued investment in fossil-fuel plants. The concern is that this elevated risk could deter investment in low-carbon generation, even where carbon pricing or other policy interventions have made it cost-effective.
Delayed investment will raise the cost of decarbonisation (IEA, 2007), so policies that address risk may be needed as part of a least-cost response. Equally, where policies are in place to reduce risks for low-carbon generation, there are concerns about how these affect the rest of the electricity market.
This paper discusses the key concerns identified, and current ideas being proposed to adapt electricity markets to provide better support to capital-intensive generation.
Standard wholesale electricity market design and its risks
In standard wholesale electricity market design, "marginal pricing" determines the spot-market price of electricity. Generators offer capacity into the market at a price sufficient to recover their short-term running costs (including fuel and carbon costs). Capacity is dispatched starting with the lowest-price offer, moving up to more expensive options until demand is met. Under normal conditions, the offer price of the last unit of generation dispatched (the "marginal" unit of generation) sets the market price for electricity, which is paid to all generation dispatched irrespective of their individual offers.1 In many markets, gas-fired generation generally sets this spotmarket clearing price. At times of peak demand, higher-cost generation options are needed, so the market price for electricity is higher. Whenever the spot-market price is higher than a generator's offer price, the generator receives extra revenues (called "infra-marginal rents") that are used to help cover the plant's capital investment costs.
1. In the balancing mechanism of the United Kingdom market, generators are paid based on offer prices, but in this case the market price would still be expected to tend towards the marginal price due to generators adjusting their offers (Baldick, 2009).
At times of exceptional demand or network congestion, market prices can rise well above the short-term running costs of any generator operating. This "scarcity pricing" is a normal component of the market, and is necessary for all generators to recover their capital costs, particularly those that run only at peak times. If prices were prevented from rising sufficiently at peak times, generators would not be able to fully service their capital investments.
One optional market design feature is that of "capacity mechanisms" as an alternative way of ensuring adequate generating capacity to meet peak demand (Joskow, 2008; de Vries, 2008; Batlle and Rodilla, 2010). In some jurisdictions, it is seen as preferable to fund the capital costs of peaking plants though separate payments, rather than through the more volatile prices associated with energy-only markets. Capacity mechanisms can provide greater investment certainty for peak-load investors, but they also require regulators to determine appropriate levels of capacity and payment. Payments can be made to all generators in the system to ensure their availability at peak times, or can be targeted to a smaller subset of plants dedicated to peak use. The value of capacity mechanisms is debated because of the trade-off of greater certainty of prices and remuneration for potentially higher costs due to imperfect regulatory decisions.
In theory, under the marginal pricing market model, all types of plants will recover their operating and capital costs over the long run; and investors obviously would not commit to building a plant unless they foresaw its costs being covered. However, the risks attached to the recovery of capital costs vary considerably. Uncertainty is not new: it is an intrinsic part of the market, but the low-carbon transition adds significant political and policy-related risks that are difficult for investors to accurately assess. Further, in the absence of particular policies (such as feed-in tariffs) to reduce investment risk, current electricity market structures are inherently riskier for low-carbon investment (Grubb and Newberry, 2007).
As long as the gas-fired generator sets the marginal price, its profits are not strongly exposed to fluctuations in the price of gas or carbon.
Conversely, the profitability of a plant that has high capital investment costs but very low short-term running costs (such as a nuclear or solar thermal power station) is more strongly exposed to uncertainty in gas or carbon prices because these set the market price of electricity while the generator's costs remain fixed. The revenue available to cover the high capital costs of these plants is therefore more volatile over time (Figure 1 ).2
Figure 1 shows costs for hypothetical gas and low-carbon plants both running as base-load, compared to average spot prices. Net revenues are roughly equal over the time period, but returns from the low-carbon plant are more volatile.3
The exposure of low-carbon generators to the uncertainty of future price paths for both fossil fuels and carbon allowances may encourage continued investment in gas-fired plants, even if low-carbon plants are cost-effective.
Risk 2: Investor exposure to low market prices driven by decarbonisation
With decarbonisation of the power sector, low-carbon plants with high initial capital cost and low running cost (such as nuclear and wind generation) will form a growing proportion of the generating mix. There will increasingly be times when fossil-fuel plants are not needed to meet demand, so these plants will no longer set the electricity price. Instead, the spot-market price at such times will drop to the much lower running costs of the nuclear and renewable generators. Such periods of low, zero, and even negative prices are already being seen in the German and Spanish electricity markets due to the increasing proportion of government-supported wind power.4
Risk 1: Investor exposure to uncertainty in fossil fuel and carbon prices
Perhaps surprisingly, nuclear and renewable generators can be more exposed to fuel and carbon price uncertainty than fossil-fuel generators under marginal pricing. A gas-fired combined-cycle plant that often sets the marginal price, for example, will generally recover its operating costs (including fuel and carbon) because the electricity price adjusts to cover these costs. It will also benefit from higher prices during peak periods when more expensive plants set the marginal price, helping it recover its modest capital costs.
2. This simplistic analysis assumes that generators sell their electricity via the spot market, whereas in many markets the majority of generation will be covered by long-term contracts. The willingness of buyers to enter into long-term purchase agreements will ameliorate this price volatility.
3. The tracking between generation costs and average spot prices is not exact for gas plants, as these do not set the marginal price all the time: at peak periods more expensive plants will set the spot price.
4. In these markets, renewable generators receive additional payments based on electricity generated, for example through feed-in tariffs. It can therefore be worthwhile for them to offer generation at a negative market price, distorting efficient price formation. Similarly, some base-load plants (particularly nuclear) would face significant costs to stop generating, so find it more cost-effective to pay the market to take their electricity rather than withdraw their supply and face the higher cost of stopping generation.
Schematic representation of profit variability from electricity generation
Schematic representation of profit variability from electricity generation
With increasing periods of low or zero market prices, the concern has been raised that the loss of infra-marginal rents will make it more difficult for low-carbon generators, whose revenues rely on market prices, to recover their capital costs. While higher peak prices could theoretically compensate for this, the highly uncertain and volatile revenue stream would make these investments riskier and more difficult to finance.
Additionally, it is unclear in this case how much benefit low-carbon generators will derive from carbon-pricing revenue as the system decarbonises. When fossil-fuel plants are setting the market price, all generators receive the carbon cost passed through into the market price for electricity. At times when only low-carbon plants are running, however, the price of electricity falls and there is therefore no carbon-price component to the electricity price. While the carbon price is still useful in making high-emissions generation less competitive, at these times it is no longer providing revenue to help low-carbon generators recover their investment costs. In modelling work for the UK government, Redpoint (2010) found that as the electricity system decarbonises, the effect of a carbon price on electricity prices erodes, weakening its usefulness as a support measure for low-carbon generation over time.
Low-price periods are not only a risk for the economics of low-carbon investment, they also raise significant uncertainty for the expected returns from fossil-fuelled plants. Continued investment in flexible fossil-fuelled plants may well be needed to balance supply and demand in a system with a large share of variable or intermittent renewables (particularly wind), and investors may be reluctant to commit if it is unclear how many hours these plants will run as the system decarbonises.
It should also be remembered that nuclear and renewable generation are not the only low-carbon possibilities under development. If carbon capture and storage technologies are eventually widely adopted, a different market dynamic could unfold because the higher short-term running costs of these plants will set the marginal electricity price and tend to keep market electricity prices higher. The balance of nuclear, renewable and fossil-fuel plants with carbon capture and storage could therefore have a significant impact on electricity market prices - hence on the economic viability of all these investments. Future market designs may therefore need to be robust in all these regimes.
Risk 3: Rising consumer prices
Electricity price rises are politically and publicly contentious, so there is a natural concern that policy changes should not raise consumer prices by more than is necessary. As such, the concern to ensure generators recover the costs of new investment has a corresponding concern that they should not benefit from excessive returns.
In the short to medium term, fossil-fuelled generation will continue to set the electricity market price most of the time as the system decarbonises. For example, modelling for the UK Committee on Climate Change showed that gas generation is still expected to set the market price 85% of the time in 2030, even though it will only be 10% of the generation mix (Redpoint, 2009). The market electricity price will therefore pass through the gas generators' carbon price, which will be paid by consumers on every unit of electricity purchased even though the system will be predominantly renewable. While investors in new plants will need this additional margin to cover their costs, it could result in significant windfalls for those generators with existing low-carbon plants, such as historical nuclear plants (Ellerman, Convery and de Perthuis, 2010; Keppler and Cruciani, 2010).
Under carbon pricing, rising electricity prices are intended to make cleaner generation more profitable; increased infra-marginal rents to some existing generators are a natural result of the marginal pricing market system. Allowing prices to rise to the level needed for marginal investment ensures that investment and consumption decisions are made efficiently and in theory leads to optimal cost-effectiveness. Because opposition to rising electricity prices may stall action on climate change, governments may begin to explore alternative policies to achieve decarbonisation with lower price rises or, alternatively, the recovery of some of the windfall revenue from existing generators (Finon and Romano, 2009). These solutions may involve some loss in overall economic efficiency.
The increase in electricity prices from CO2 pricing works in the opposite direction to the suppression in prices from the penetration of low-carbon generation discussed as "Risk 2" above (see Philibert in this volume for further discussion). The way in which these effects will interact over time as systems decarbonise will be complex, and warrants further detailed study.
Solutions being explored to improve market arrangements for decarbonisation
The issue of alternative market designs for decarbonisation is only beginning to be considered in academic and policy circles. Among governments, the United Kingdom's recent announcements on market reform provide an example of the market and related policy adjustments being considered (see box below).
Proposals being suggested fit into two broad categories: those that establish a separate market for low-carbon generation, and those that seek to make reforms market-wide so that a high-capital-cost plant is better able to recover its costs.
The most commonly proposed method to provide greater certainty for low-carbon investment is to provide separate payments to these generators, outside the main electricity market. These typically build on the support schemes that have already been implemented for renewable energy, and take one of two forms:
F Feed-in tariffs, structured either as fixed payments, premium payments on top of the market electricity price, or financial contracts for differences against the market price (Newberry, 2010a; 2010b; Hiroux and Saguan, 2010).
F Establishing a market for clean energy by imposing quantity obligations on suppliers. The United Kingdom and Australia have created markets for renewables obligations, and the United States is currently considering extending this approach to a "clean-energy obligation".
In practice, these approaches often overlap. Feed-in tariffs can be restricted to a fixed quantity of generation, with the payment price determined by tender or auction. In this case, they take on some of the properties of a quantity-based obligation. Similarly, renewables obligations have typically been tiered to provide different levels of support to different technologies, acquiring some of the price-based characteristics of a feed-in tariff. The costs and benefits of these types of support schemes are explored in detail in Deploying Renewables: Principles for Effective Policies (IEA, 2008).
From the perspective of the wider electricity market, however, these schemes pose a fundamental problem. As the share of low-carbon generation increases, the size and liquidity of the conventional market shrinks. Investors in fossil-fuel plants, which may still be necessary to ensure security of supply, will experience heightened uncertainty over the running hours and electricity prices these plants will realise. The solution generally proposed is to provide supplementary funding for these plants as well, in the form of capacity payments. In this scenario, plants would receive some payment for being available to generate when required for system balancing or meeting peak demand, and receive further payment through the market for actual generation.
Ultimately, if all generation is receiving top-up payments through clean energy contracts, tradable certificates or capacity payments, the significantly broader role of the system regulator will potentially include determining the quantities of various types of generation required for decarbonisation and security of supply, and perhaps also the prices for these. This marks a significant shift away from current market design, where investment decisions are made by market participants based on price expectations -though of course with key cost and risk elements influenced by the regulator.
The implications of market structure for investors' risk will also depend on the degree of aggregation within the industry. While impacts may be significant for individual plants, for large firms with a portfolio of generation the impact is smaller overall (Burtraw and Palmer, 2008).
Given that targeted policy measures to support low-carbon generation may result in system-wide interventions in the long term, it is worth considering whether reforming market-wide structures might be preferable to creating a separate market for low-carbon generation.
As part of early work towards the United Kingdom's market reform proposals, a range of whole-of-market reforms were considered, from enhanced carbon pricing at a minimum through to replacing the market with a central purchaser of electricity at the extreme (Ofgem, 2010; HM Treasury, 2010a).
Carbon pricing is a standard policy tool for improving the economics of low-carbon investment. Tightening emissions caps (and hence raising carbon prices), or moving to carbon taxes for greater certainty, would clearly attract more investment in low-carbon compared to fossil-fuelled plants. As pointed out by Hogan (2010), accurate pricing of the emissions externality allows appropriate decentralised investment decisions to be taken. However, higher and more certain carbon pricing alone will not address all the risks discussed above: low-carbon generators would still have to manage fuel-price uncertainty, and all generators would still face the prospect of low-price periods undermining returns as the system decarbonises. In the United Kingdom analyses, enhanced carbon pricing was seen as a useful step, but insufficient on its own (HM Treasury, 2010a).
Market-wide regulatory standards could also be considered, such as emissions performance requirements that tighten over time. Again, while these would provide support for low-carbon plants, they do not address the market issues of fuel price uncertainty and low-price periods. Regulated approaches are also generally less efficient than carbon pricing, achieving emissions reductions at higher cost (OECD, 2009).
A more comprehensive, though also more speculative, solution would be to attempt to extend capacity mechanisms to cover all generation in the market, rather than only peak-load generation. This could help all generators (low-carbon as well as fossil-fuelled ones needed to balance the system) cover their capital costs. Generators would be paid separately for having capacity available in the market, while the electricity market would cover their running costs when the plant is dispatched. As current capacity mechanisms only address supply security concerns and tend to favour fossil-fuelled capacity, they would need to be restructured to meet the dual objective of supporting low-carbon investment. Detailed proposals for such a mechanism are yet to emerge, but the concept is under discussion (Boot and van Bree, 2010; Gottstein and Schwarz, 2010; KPMG, 2010). Given that existing wholesale markets are already flanked by supplementary markets to provide ancillary services such as spinning reserve, voltage support and frequency regulation, moving to a further supplementary market for capacity would not necessarily be a radical departure.
Finally, there exists the option of retreating from the market model to a system where the regulator contracts for all new generation (a "central purchaser" model). Here, the regulator determines system requirements for new generation in lieu of the competitive price-based investments of market players. This would be a significant departure from fully liberalised market structures, and essentially represent a return to a pre-reform model. While floated in the early UK policy discussions, it was discarded due to the desire to retain the efficiencies delivered by the wholesale market.
Proposals for reform of the United Kingdom electricity market
The UK government is currently consulting on options for reform of its electricity market to better facilitate the decarbonisation of the power sector (DECC, 2010; HM Treasury, 2010b). This is the culmination of work since 2009 by the Committee on Climate Change (CCC, 2009; 2010), the Office of Gas and Electricity Markets (Ofgem, 2010), the UK Treasury (HM Treasury, 2010a) and the Department of Energy and Climate Change.
The package of measures proposed consists of:
► Carbon price support. The carbon price from the EU emissions trading system would be supplemented by an alternative tax (the climate-change levy) to guarantee a minimum carbon price in the electricity market.
► Long-term contracts for all low-carbon generators, structured as contracts-for-difference against the market electricity price. This guarantees returns for low-carbon investors, while maintaining market incentives for efficient operation.
► Targeted capacity payments for flexible plants needed for system balancing and meeting peak demand.
► Emissions performance standards for new fossil-fuelled plants, as a backstop minimum emissions requirement.
Following consultation, the government intends to issue a white paper in April, so that any changes to the system can be settled quickly to avoid investment uncertainty.
Due to the heightened risk wholesale market structures pose for investors in high-capital-cost, low-running-cost generation, these market structures may not be optimal for decarbonisation. Delays in investment would raise the cost of decarbonisation, so policies to address risk may be needed as part of a least-cost response.
A key question for policymakers will be whether to use targeted measures to ensure capital cost recovery for low-carbon investments, or whether to introduce (or modify) market-wide policies such as capacity payments that cover all generation. Given the early stage of policy development, it is not yet clear which solutions are likely to be best.
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