The transition of the electricity system towards decarbonization: the need for change in the market regime

Abstract

The mainstream community of energy experts is not aware of the long-term impacts that carbon policies directly concerned with promoting the development of low-carbon technologies produce on the electricity market regime. Long-term market coordination should be replaced by public coordination with long-term arrangements. The current market coordination makes carbon pricing ineffective in orienting investors towards capital-intensive low-carbon technologies. Fossil fuel generation technologies are preferred because their investment risks are much lower in the market regime, even with a high but unstable carbon price. Thus, in order to avoid delaying investment that is aimed at the decarbonization of the electricity system, a number of new market arrangements that lower the investment risk of low-carbon technologies and provide output-based subsidization have or are being selected by governments. As the use of low-carbon equipment to produce electricity develops, long-term market coordination for other technologies (e.g. peaking units, combined cycle gas turbine) will fade away because they alter the market price setting. Thus it is likely that, in the future, public coordination and planning will replace the decisions of market players not only for low-carbon technologies but also for every other type of capacity development.

Policy relevance

The development of renewables as promoted by both feed-in tariffs and green certificate obligations, which answer to different market failures, is well known. Similar long-term arrangements, which both subsidize and de-risk low-carbon investments for every small-sized and large-sized technology, shift learning costs and risks onto consumers. Energy experts and regulators have ignored that the expansion and generalization of these arrangements are changing the coordination function of the electricity markets. Apart from those in the UK, they are still unaware of the impacts that such technology-focused policies produce on the electricity market regime. The transition from market coordination to public coordination, which is inconsistent with the market principles of European electricity legislation, and long-term contracting is inevitable and should be anticipated.

Keywords:

• clean energy obligation
• decarbonization
• electricity system
• feed-in tariffs
• low-carbon technology
• market coordination
• public coordination
• renewable energy

Notes

Given the non-storability of electricity, to achieve the optimal technology mix it is efficient to use a set of different technologies, with a specialization in low-capital-intensive ones for peak load and capital-intensive ones for the base load in the former utility optimization approach.

It is noteworthy that the scarcity rent during extreme peak periods provides benefits to every type of equipment and is on the top of their infra-marginal rents, but with much more relative importance for the peaking units.

It is much less the case in hydro-dominant or nuclear-dominant systems (in particular when they are not interconnected with a thermal-dominant system).

In the market regime, the weighted average capital cost is close to 10%, whereas in the regulated utility regime it is close to 5%. This increases the levelized cost of nuclear or CCS equipment by approximately 30%.

Using a portfolio approach for generation assets development, Roques et al. (2008) have shown that even risk non-neutral investors tend to choose an ‘all gas’ strategy (or very close to this). A portfolio approach allows one to take into account the complementarities in the risk-return profiles of the portfolio of assets that a generation company operates. Introducing nuclear in a gas-dominant portfolio could mitigate the likelihood of making large losses due to gas and carbon price uncertainty, without major negative impacts on the expected Net Present Value. Investors therefore choose a trade-off between maximizing expected returns and lowering the risk exposure of their investment. A utility could choose to go for one of the intermediary technology mixes, preferring to have lower expected profits in return for a lower probability of loss.

Common sense might suggest that in any capital-intensive industry, large-sized investments (e.g. a $5 billion of offshore oil development, a $1 billion car manufacturing plant) are. But in the electricity industry in particular, investors can choose between capital-intensive equipment, on the one hand, and low-capital-intensive and self-hedging equipment (such as CCGTs) on the other. Indeed, the only way that one can succeed and preserve one's market share in the automobile industry is to invest in a large-sized and risky project in oil or in the automobile industry.

This market failure has been studied extensively in Chao et al. (2008), who examined the market architecture of the electricity market. These authors have become pragmatic observers of contracting activity in the electricity market. See also Glachant et al. (2011).

This problem has also been analysed in Read (2004) and Michaels (2006), who have criticized the electricity market reforms (which restrict vertical integration between generation and supply) because long-term contracting has resulted in market failure and there have been no consumer benefits.

To analyse this point, Blyth et al. (2007) have developed a real options model of investment decisions for different generation technologies (coal-, gas-fired power plants and CCS technologies) and subjected it to uncertain future climate policy. They have shown that policy uncertainty creates a risk premium for power generation, with an increase in electricity prices needed to invest in gas and coal plants. Moreover, the option to retrofit equipment by CCS is made much more difficult to implement, as is reflected in the fact that the carbon price increase needed to stimulate this option is higher by 16% for a CCGT and 37% for a coal thermal plant compared to a situation of perfect certainty.

A loan guarantee of 80% of the investment cost of a nuclear or CCS plant helps to reduce the levelized cost by around 30% by decreasing the weighted average capital cost by 3% (Deutch et al., 2009).

The German institutional model for decarbonization of the electricity system combines FITs, reformed balancing mechanisms related to intermittent production development, demand response, and electricity saving measures. Offshore wind power will develop with generous FIT arrangements in some countries, while in others, such as Germany, France, and the Netherlands, long-term contracting after tendering will be preferred.

These regulated-based FIT arrangements are generally applied to decentralized RES-E, but could be extended to large-sized LCTs (e.g. offshore wind power in Germany).

In the RPSs of some US jurisdictions, advanced nuclear and CCS are considered eligible resources.

It is noteworthy that in the Californian RPS, the RES target – which increases from 20% in 2010 to 33% in 2020 – will be further increased to 50–55% in 2030.

The Electricity Market Reform also includes complementary measures that overlap with the incentives provided by long-term fixed-price contracts. These measures are a carbon price floor, which is to rise in 2015 from GB£20/tCO₂ to £70/tCO₂, and a decreasing carbon standard on new coal plants to encourage the rapid adoption of CCS. This is explained by the UK government's firm commitment to its decarbonization policy and its strong belief in the importance of deploying large-sized LCTs to achieve its decarbonization objectives.

This situation has already been observed in the Spanish and German markets. Indeed, because of their important wind-power capacities, cases where electricity prices are zero or even negative have alerted the electricity community to the risk of investing in any technology, and in particular in CCGT (Eurelectric, 2010). (Negative prices were caused by bids by operationally rigid generators who were aiming to stay dispatched while, importantly, increasing flows of wind power were injected into the system.)

Hedging does not protect against this risk of dispatch during the running hours in which CCGTs achieve their revenues on the market.

In Europe it is the increased share of wind-power production that is presently incentivizing the implementation of capacity mechanisms.

Christina Hood (2011) from the IEA's Climate Change Unit has raised this issue in a short but incisive article.