Claude Crampes and Thomas-Olivier Léautier
The past two decades have witnessed a succession of electricity market reforms in many countries. Policy makers are clearly struggling to find the “right” architecture for the industry. In France, policy makers’ attempts to reconcile market prices and regulated rates figures prominently among the reasons which explain the sector’s institutional instability. While this post tells essentially a “French story”, its lessons apply to other countries as well.
From public monopoly to market
Until the late 1990s, the French electricity industry was by and large a monopoly. EDF, a government-owned corporation, sold electricity to its customers at a rate set by the government. This model was shared by most other countries, and continues to survive in some. In this case, the regulated rate covers the full costs of production, transport, distribution, and sale of electricity. As these costs are relatively stable over time, the rates paid by consumers generally change only slightly from one year to the next. They increase, for example, if fuel prices increase, and if the regulated company invests more assets than it depreciates.
The deregulation of European electricity markets, implemented following directive 96/92/EC[1], separated transport and distribution, which remain regulated monopolies, from production and supply activities, which are now competitive. It is therefore necessary to separate the price of megawatt hours, which is the subject of this post, from the cost of transporting and distributing them. Deregulation introduced a new benchmark for the value of megawatt hours: the price set on wholesale markets. The main market is a day-ahead market: each day, sellers and buyers meet and determine the price at which megawatt hours will be bought and sold for each hour of the next day. Futures markets for the week or month to come as well as intraday markets have also developed. As electricity is different from raw materials in that it cannot be stored, electricity markets are not structured like other commodity markets. For example, in some countries, markets for ancillary services have developed, in particular the reserves necessary to preserve the immediate supply-demand balance of the electricity system. Despite these differences, wholesale electricity markets obey the same laws as other markets: prices increase when demand increases and supply decreases.
One of the great successes of the “liberalisation” of European electricity markets has been the creation of an integrated wholesale market across the entire continent. Today, a German supplier can sell megawatt hours to a French customer, thereby guaranteeing that European citizens’ demand is served at the lowest cost, given the existing production facilities. The creation of this integrated market has taken twenty years and remains to be perfected, but it is an undeniable success.
From price to rate and rate to price
Two mechanisms to determine the price of megawatt hours currently co-exist: regulatory rules and the market. This duality explains the shifting organisation of the French electricity industry, the recent history of which can be read in the price curve below:
At the beginning of the 2000s, on the left of the graph, the European market was slightly in overcapacity. Fuel prices were low (in 2001, the Brent barrel sold for an average of $23.12) and electricity wholesale prices were lower than the full production cost, and thus lower than the regulated rate. French industrial consumers, the only consumers authorised to change suppliers at the time, therefore opted for offers indexed on the market price. The situation reversed between 2004 and 2006: demand and fossil fuel prices increased and several German electricity units were closed, leading to a rise in wholesale prices. To protect companies which had “gone off the regulated rate”, the French government implemented a transitory regulated market adjustment rate from 1st January 2007, better known by its acronym, TaRTAM.
Initially, TaRTAM should have only been in place for two years. Unfortunately, electricity wholesale prices continued to rise. By the end of 2008, the wholesale price was significantly higher than the full cost, and thus higher than the regulated rate. Through EDF, a company in which it held an 85% stake, the French state was therefore selling electricity below its market price to industrial users located in France. This was a state subsidy, and an enquiry was opened by the European Commission.[2] In October 2008, the French government tasked a commission headed by Paul Champsaur to propose a solution to this problem, without increasing consumers’ bills. The Champsaur commission squared the circle: it suggested that EDF sell electricity produced by its existing nuclear reactors to its competitors at a regulated price. This proposal was implemented in December 2010, by a law bringing in a new organisation of the electricity market (NOME). A new acronym appeared in an already abundant electricity glossary: regulated access to historic nuclear energy (ARENH). Its price, which was regulated, became pivotal to the competition between EDF and its competitors for sales to end consumers. It was intended to be used to compute the regulated rate as of 2016. Given the importance of the ARENH price, it is not surprising that its determination was the subject of long discussions.
From 2011-2012 onwards, the European electricity market found itself in overcapacity, and wholesale prices fell. In France, the wholesale price remained close to the level of the ARENH throughout 2014, then finally dropped below it at the end of the year. The new regulated rate proposed by the government at the end of October 2014 took advantage of this evolution:[3] the stated aim of the regulated rate was no longer to cover EDF costs, but to ensure comparability with the market. Including the market price in the formula to determine the rate limited its increase. Finally, as the wholesale price remained under the ARENH price, its sales collapsed in 2015[4].
This simplified history provides a perfect illustration of the problem facing the French government: how does one make regulated electricity rates reflecting historic costs, which are relatively stable, co-exist with electricity market prices, which are necessarily cyclical? When market prices exceed the regulated rates, consumers demand the protection afforded by regulated prices, while the same consumers buy from the market when it is more attractive than the regulated rate. The problem does not only affect France. In the United States, some states, in particular in the south-east, have kept regulated rates, while others, for example, in the north-east, have adopted a market approach. When the price in the restructured states is higher, or increases more rapidly than in the regulated states, consumers bitterly regret having gone down that road, while they are satisfied when the reverse occurs.[5]
Which solutions to this problem?
The simplest approach is to abandon regulated electricity rates. Competing suppliers will offer a variety of contracts to their customers: some will offer fixed prices for several years, others a peak/off-peak structure etc. The French government has adopted this position for industrial, commercial and tertiary consumers (around 60% of megawatt hours consumed in France). The political challenge is twofold: in the short-term one must explain to voters that the price of electricity, like the price of fuel, air travel, bread and tomatoes is determined by the supply-demand balance on the European electricity system, and not by a group of bureaucrats, as benevolent as they may be. In parallel, one must resist the permanent pressure from assorted users groups, who demand subsidies and exemptions from the application of the market price. The subsidies requested by intensive electricity users, discussed in a previous post, are an excellent example.
One difficulty in the disappearance of regulated rates is that some consumers, for various reasons, do not want to actively choose their supplier, and prefer to leave things as they are. One solution, adopted by several American states, is to implement a “default” electricity supply offer in which consumers who do not wish to change supplier are enrolled. The historic operator is responsible for organising calls for tender to fulfil this obligation.
Another possibility is to maintain a regulated price based on wholesale prices rather than costs. An independent regulator determines the average wholesale price for megawatt hours supplied to customers, and uses this figure to calculate the regulated rate. This solution creates a few technical problems. For example, what wholesale price should be used: the future price for the coming year? or the average of future prices to take into account hedging strategies? What load profile should be selected? As the supply of a customer who essentially consumes during peak hours is more costly than for a customer who essentially consumes off-peak, the average demand profile must be determined for customers who remain on the regulated sale rate. These solutions do not create insurmountable difficulties but they require detailed regulatory work.
Credibility of commitments
More difficult yet is the policy makers’ ability to commit to following the rules once they have been established. The example of natural gas is striking: the French government refused several times to grant GdF the rate increases required by the formula it had developed, leading to a series of legal challenges. Since May 2013[6], a new mechanism has been in place: every 1st July, the government determines the indexation formula for the regulated rate. During the year, the values used for the calculation are revised each month.
The natural gas example suggests that governments (at least in France) will be tempted to revise the electricity rate calculation formula. For example, what will be the share of wholesale price in the rate when it goes back above full costs?
In parallel, irrespective of the chosen approach, policy makers can attempt to limit the amplitude of the cycles, i.e. coordinate producer forecasts and investments, in order to limit the impact of periods over- and under-capacity. This is one the objectives of the capacity mechanisms, the advantages and disadvantages of which have been discussed in a previous post.
* * *
The virtual impossibility of having market prices and regulated rates coexist harmoniously illustrates two difficulties which limit the impact of public policies, and have already been mentioned in this blog. First, politics is the art of compromise; unfortunately, combining a little market and a little regulation does not systematically produce satisfactory results. Often one must make a decision and defend it. Second, policy makers find it difficult to commit, i.e., to be credible when they promise to follow a rule. They will be tempted ex post to modify the rule, in order to benefit from changes in market conditions. Investors anticipate promises being broken, and are thus hesitant to invest to provide the expected services.[7]
Experience shows that policy makers will be incapable of overcoming these difficulties. The disappearance of regulated rates, along with provisions to protect the fuel poors, therefore seems to be the best solution.
[1] http://eur-lex.europa.eu/legal-content/FR/TXT/PDF/?uri=CELEX:31996L0092&from=FR
[2] The enquiry opened in June 2007 and ended in June 2012 with the approval of these subsidies. http://europa.eu/rapid/press-release_IP-12-595_en.htm?locale=en
[3] http://www.legifrance.gouv.fr/affichTexte.do;jsessionid=?cidTexte=JORFTEXT000029672773&dateTexte=&oldAction=dernierJO&categorieLien=id
[4] http://www.cre.fr/newsletter/preview/13008/1/0/cre_fr/cre
[5] https://ei.haas.berkeley.edu/research/papers/WP252.pdf
[6] http://www.acqualys.fr/uploads/documents/519c8fe87fe0e.pdf
[7] The discrepancy between electoral mandates which last a few years, and investments which are supposed to last several decades can also be an issue.
