First, they generally took place under regulated market structures, in which public utilities were able to pass on the cost of stranded plants to their customers or have it borne by taxpayers. In the current environment of wholesale electricity markets the question of who will bear these costs is unclear, as discussed further below.
Second, these transitions were driven by external shocks in generating costs - both fuel and technology costs - which the industry had no choice but to manage. By contrast, the transition to a low-carbon generating mix will be driven largely by policy decisions, and achieved either through carbon pricing or regulation (or some combination). Because government policy can be reversed, or exemptions or compensation granted, this future transition will not offer the same clarity for investors.
Policy-driven retirement of plants is already taking place around the world, in varying contexts. In the United States and Europe, air quality regulations are expected to lead to the retirement of a significant share of aging coal-fired plants (Celebi etal., 2010 ). The Chinese government aims to close all coal-fired power plants with capacities below 50 MW, and to close power plants up to 100 MW unless they are converted to cogeneration of heat and power (Gupta, Vlasblom and Kroeze, 2001; Cao, Garbaccio and Ho, 2009). This policy targets reduction of sulphur dioxide (SO2) emissions, but has co-benefits in terms of CO2 emissions reduction since small power plants generally have lower fuel conversion efficiencies.
Carbon pricing, market structure, investment behaviours and uncertainty
Carbon pricing, either through taxes or emissions trading systems, is a cornerstone policy in climate change mitigation strategies. It can shift a region's electricity generating fleet to a lower-carbon mix in three basic ways:
F Influencing the dispatch of existing plants, shifting running hours from coal- to gas-fired generation. This sort of short-run fuel-switching is a significant factor in setting the current European Union Emission Trading Scheme (EU ETS) price of around EUR 15/tCO2 (Deutsche Bank, 2010).
F Affecting the relative economics of new plants installed to meet demand growth or replace retired plants. In the current EU ETS, new gas-fired generation would be favoured over new coal-fired generation at a price of around EUR 25/tCO2 (Deutsche Bank, 2010).1
F Pushing old, high-emission plants out of the market when the carbon price increases to the point at which the running costs or short-run marginal costs (fuel, carbon, fixed and variable operations and management) become higher than the costs of new investment (long-run marginal costs, including the cost of capital) in lower-carbon plants.2 This may involve the retirement of plant before the end of its technical life, and potentially even before it has recovered its capital costs.
Only the third option involves early retirement of plants. Because a new plant has to recover capital costs in addition to running costs, this means that some old, fully-depreciated plants have a profit margin that can accommodate a significant carbon price before they become uneconomic. A modest carbon price could mean that gas (rather than coal) generation is more economic for any new build required to meet demand growth, while a much higher carbon price may be needed to prompt the replacement of existing coal with new gas-fired plants.
Although a simple, levelised cost analysis would imply that a plant be retired as soon as it becomes uneconomic, in reality investment behaviour is more complex. Decisions to retire plants, and to build new plants, are also influenced by uncertainties in future fuel and carbon prices, the role that a particular plant plays in an electricity company's fleet of power stations, and uncertainties in forward climate policies (IEA, 2007).
Electricity market structure and dynamics are also important factors in driving investment decisions. Deregulation of electricity markets, for example, has presumably made affected generators more sensitive to environmental compliance costs than they were in a world of rate-of-return regulation (when such compliance costs could typically be passed on to ratepayers). Another significant uncertainty arises from the structure of current wholesale electricity markets. Decarbonisation is likely to change the nature of price recovery in these markets, with increasingly long periods during which nuclear or wind energy set the market price at low or zero prices, interspersed with very high peak prices (see Hood in this volume for further discussion). This uncertainty around the distribution of future prices raises risk for investors, and poses a further risk to recovery of capital costs (Redpoint Energy, 2009). Investors also perceive significant political risk associated with the possibility governments will not follow through on climate targets or will implement policy that changes electricity markets during the life of their investments.
1. Even in the absence of a carbon price, gas-fired generation may be favoured over coal-fired for new builds for a range of reasons, in particular the inherent flexibility that makes gas-fired a better capital response to uncertain public policy.
2. If there is already surplus generating capacity, plant retirements may instead be prompted by electricity prices being too low to cover generators' costs. In either case, the retirement of plants will change the mix of generation, stimulating a corresponding change of price formation in the market.
All these uncertainties affect investor behaviour. Coupled with the potentially large quantity of underutilised old capacity kept in the system, they could lead to delayed investment in new plants (IEA, 2007). For owners, there is also value in retaining (rather than retiring) a plant to maintain reserve margins, or so that it can be restarted if electricity prices increase, or is available for use during peak periods. Both these effects would be expected to slow the rate of retirement when compared to simple predictions based on levelised costs in a situation of certainty. As a result, a higher carbon price would be needed to achieve the anticipated rate of capital turnover and CO2 mitigation.
While carbon pricing is clearly a key policy tool, it will no doubt lead to increases in energy prices - which are of concern to consumers and governments.3 As such, it is reasonable to ask whether supplementing the carbon price with additional decommissioning policies could drive the low-carbon transition at a lower carbon, and therefore lower electricity, price. Moreover, in the absence of a clear forward carbon price, there could be a rationale to supplement the carbon price with other policies as a means of improving plant owners' understanding of retirement and investment needs. In effect, supplementary policies would attempt to correct for the lack of clarity in current forward policy goals for CO2 reductions (and hence the lack of robust forward price paths for emissions).
As discussed above, because older plants have more fully recovered their capital costs (and may thus require a high carbon price to prompt retirement), governments may wish to consider whether a regulated phase-out of older plants has merits for consumer costs, as long as it is clear that certain plants need to be retired to meet a CO2 reduction objective. In this case, the carbon price needed could be lower, and allow for reduced electricity costs. The benefits of a lower carbon price would need to be weighed against the potential loss of efficiency (and potentially higher economic cost) of not allowing the carbon pricing to drive the lowest-price actions.
The complex interaction between carbon price and retirement should be carefully considered when suggesting supplementary policies to prompt plant retirement. Electricity prices in the German energy market, for example, are currently low due to an excess of generating capacity arising from, in part, government renewable energy mandates. Forecasts are that more than 20 GW of fossil-fuelled capacity will need to be retired to return margins to sustainable levels (Deutsche Bank, 2011).
3. Under marginal pricing, the same market clearing price is paid to all generators; this price is determined by the most expensive generating plant operating, usually a fossil-fuelled plant. Introducing a carbon price therefore increases the cost of every unit of electricity sold, whether it is of high- or low-carbon origin.
However, because carbon prices are currently low, these retirements are expected to be in older black coal and gas-fired plants, rather than in higher-emitting lignite facilities that have lower fuel costs. If a higher carbon price were present, a different set of plants might be candidates for retirement.
Early retirement of plants comes at a cost: the question is who will bear it? Modelling exercises assume that owners (and their shareholders) will bear the losses of plants that are made uneconomic by climate policy. Governments need to consider if this is a reasonable expectation.
The recent Australian debate about a previously proposed emissions trading scheme prompted significant discussions around compensation for the losses of brown coal generators, whose profits would have been affected (Australian Department of Climate Change, 2008). The debate reflected a tension between the concern that unforeseen regulatory change might increase the risk profile for new investors (by increasing their borrowing costs and prices for consumers), and the concern that low-carbon investment could be undermined if thermal investors were to be compensated - at a cost to consumers - for lack of appropriate foresight.
When considering the case for compensation, governments should remember that the intent of carbon pricing is to change the relative economics and, therefore, the actual operation of plants: it is expected that there will be winners and losers. Many generating assets will see increased returns as the carbon price increases; if a power company has diverse assets, it may see no impact or even a positive gain overall (Burtraw and Palmer, 2008). Thus, a decision to compensate all losses could easily undermine the purpose of the scheme.
During the deregulation of electricity markets, there was extensive debate over whether and how to compensate utilities for stranded costs (Baumol and Sidak, 1995; Boyd, 1996; Brennan and Boyd, 1996; Kolbe and Tye, 1996; Maloney, McCormick and Sauer, 1997; Beard, Kaserman and Mayo, 2003). Subsequent analyses indicate that compensation outcomes were often decided on a political rather than economic basis. Deregulation in other sectors (e.g. telecommunications and airlines) did not necessarily follow the same pattern of compensation. In the case of plant closures caused by climate policy, governments need to be mindful of any precedent this would set. If initial compensation is to be paid, policies should seek to minimise the risk of claims for ongoing compensation.
In the WEO 2010 450 Scenario, early closure of plants would lead to USD 70 billion in unrecovered investment costs.
These plants are mainly in OECD countries,4 and are stranded by the rapid implementation of carbon pricing in this region. Globally, the amount at stake is only a few percent of the projected transition costs; in 2010-35, power-sector investment in the 450 Scenario amounts to USD 11.1 trillion, a net increase of USD 2.4 trillion compared with the Current Policies Scenario. But, at the scale of individual companies, it may represent a significant loss; according to the WEO 2010 analysis, early retirement represents 28% of the investment costs of the plants retired. This could lead to a situation similar to that seen during early implementation of emission trading systems when worries of competitiveness losses for a few strongly affected industries often justified free permit allocations to the entire industrial sector - at substantial cost to governments.
Alternative policies to avoid the need for early retirement?
To meet an ambitious climate change mitigation target, governments must face the tension between the challenges of stringent short-term action, and the risk that early plant retirement will be needed at a later stage if it becomes necessary to accelerate the emissions reduction rate. Rather than providing direct compensation for early retirement of plants, governments may be tempted to slow policy implementation or provide exemptions to existing generators (thereby increasing the burden on new generators). If existing plants are allowed to run longer, there will clearly need to be a more dramatic reduction in the carbon intensity of new investments to stay within the same emissions budget. This in turn implies a higher carbon price at an earlier date, or equivalent ambitious early action.
If early retirement is to be avoided, there is a short-term policy need to either strengthen and give more certainty in carbon price signals (to trigger more ambitious early action) or potentially to supplement carbon prices with additional policy to guide investments. Since current carbon price signals are weak and uncertain compared to the levels indicated necessary by the models, they are not generally clear enough to guide investor decision making.
There are alternatives to early retirement, including: retrofitting plants with state-of-the-art efficient boilers, turbines, etc., or with carbon capture and storage (CCS) technology; switching from coal to a lower-carbon fuel (such as gas); or using biomass in co-firing. In the United Kingdom, for instance, new fossil-fuel plants are required to make provisions for a future retrofit of CCS, and European investors are required to assess the potential for CCS retrofitting.
The rapid decarbonisation of power generation featured in many climate policy scenarios may require early retirement of many coal-fired plants, shortening their economic life to significantly less than their long technical lifetimes. Policy makers should consider this carefully when planning climate policies.
If early retirement is not seen as politically feasible in the coming decades, there may be a need to enact even tighter policy restrictions on new plants (implying higher carbon prices) in the short term, to compensate for the emissions from existing plants that will continue to operate instead of being retired.
If governments decide that early retirement is an option, they should adequately consider which policies are best to trigger and accompany this action, taking account of factors such as maximising certainty for investors and goverment over the transition period, and promoting flexibility and economically efficient outcomes. Uncertainty creates a bias towards retaining plants for peak periods or re-firing them if electricity prices increase. Moreover, old, fully-depreciated plants have a profit margin that can accommodate a significant carbon price before they become uneconomic. Quite high carbon prices may therefore be needed to displace existing capacity before the end of its technical life. If the related costs for electricity consumers are deemed to be a serious political issue, governments may wish to consider supplementary policies to assist the phase-out of older plants. Finally, goverments will need to decide whether and how to address claims for compensation of "stranded costs" for the firms that would retire plants.
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