1. the regulateD sales tariffs
fOr hOusehOlD eleCtriCity
COulD inCrease By 30%
By 2017
In its first report on the operation of the energy retail markets, the CRE made provision for a significant increase in electricity prices for all consumers over the next five years, all things being equal. According to its projections, the increase between 2012 and 2017 in the average bill of a customer on a blue tariff (reserved for individuals and small business), with consumption being equal, will reach 28.2% in current euros, including 10.4% inflation and the contribution to the public service electricity (CSPE), which accounts for approximately 5.1% per year. This exercise is based on the cost stacking principle as set out by the law, and hypotheses on the development of costs to be covered over time.
In evaluating the additional cost for supplying electricity on the wholesale market, the CRE bases its calculations on the weighted average price of the volumes listed on the stock exchanges for the 2013 calendar product, and on OTC from 2010 to 2012. For the following years, it assumes 1%
inflation (i.e. an annual increase of 3%). The CRE also assumes that marketing costs will increase by less than 1% of the 28.2% overall increase, and assumes additional costs1 of around F2/MWh for small consumers. Inflation is taken into account at a rate of 2% a year.
The main hypotheses on the development of costs to be covered (TURPE, ARENH and CSPE) are detailed below.
1.1. system operators will have to deal with continued growth in investment The networks are entering a period of high investment
The public electricity transmission and distribution networks require significant work to successfully integrate the markets, connect new generation facilities, strengthen weak areas in the electricity supply, and upgrade the network. The increase in investment amounts, which began 1 – Additional costs mainly correspond to the costs of discre- pancies (which a supplier has to pay to offset consumption uncertainties in their portfolio, which place a burden on the supply-demand balance) and the various costs involved in accessing the market.
Base B0 -29.6% B1 -2.9% +2.7% B2I B2S TEL -0.4% +1.1% +0.4% 100 90 80 70 60 In % ¯ Coverage of costs under the regulated electricity tariff - blue, yellow and green - on 1 August 2012. Source: EDF – Analysis: CRE
˘ Coverage of costs under the regulated natural gas tariffs, by tariff, on January 2013. Source: GDF SUEZ Analysis: CRE 100 95 90 85 80
Blue tariff Yellow tariff -3.6%
Green tariff -0.6% +0.5%
In %
¯ Projected investments by RTE and ERDF (including delivery of work). Source: CRE
in the mid-2000s, is expected to continue in the coming years.
Investments will have a growing impact on tariffs over the years
Tariffs for the use of the public electricity grids cover the system operators’ capital costs, which include depreciation on investments on the one hand, and remuneration of fixed assets (which form the regulated asset base) on the other. These capital costs are spread over the entire life of the structures, so the user pays a tariff for the existing network rather than just the investments made in that year. That is why the impact of rising investments on tariffs is not immediately obvious, but is felt cumulatively over time.
As the regulated asset base grows, capital charges are experiencing strong growth, corresponding to the development of new infrastructure on the one hand, and the replacement of old structures on the other. These are most often depreciated by more expensive structures because of the increase in commodity prices, changes in technology such as landfill, or additional integra- tion costs linked to the social acceptability of the structures.
Moreover, development investments are by necessity accompanied by an increase in operating and maintenance charges for the newly created structures.
The stabilisation of electricity demand, if it continues, will lead to growth in the TURPE per unit in constant euros
During the last major wave of investment in the electricity sector in the 1970s-1980s, unit tariffs did not change much in constant currency, as the growth in demand offset the increase in charges to be covered.
Currently, growth in withdrawals is very limited due to the effects of the economic crisis on industrial demand, which is not offset by the increase in consumption of the domestic and tertiary sectors. Furthermore, the diversification of energy for heating and energy efficiency measures will contribute towards moderating the increase in electricity demand. This should result in a pincer effect: in the coming years, the system operators’ rising capital costs will, in all probability, be higher than the growth in user withdrawals. The TURPE per unit is therefore destined to increase in constant euros.
■ ERDF ■ RTE 2011 2012 2013 2014 2015 2016 2017 Million eur os 5,000 4,000 3,000 2,000 1,000 0
1.2. the price of arenh will be a decisive factor in tariff development
Created by the NOME law, regulated access to historic nuclear power (accès régulé à l’électricité nucléaire historique - ARENH) entitles suppliers to buy electricity from EDF, in volumes determined by the CRE, at a regulated price. During a transitional period ending on 7 December 2013, the price of ARENH is decreed by the Ministers of Energy and the Economy, after the CRE has issued its reasoned opinion. After that date, ministers must decree a new price based on a proposal by the CRE.
The Energy Code states that in order to ensure fair remuneration for EDF, the price of ARENH must be representative of the economic conditions of electricity generation at its historic nuclear power plants, for the duration of the mechanism. A decree by the Conseil d’État must specify the conditions under which the price of ARENH is fixed.
As this text had not yet been published on the date of the CRE’s deliberation, in order to give its opinion of 5 May 2011 on the price of F42/MWh planned for 1 January 2012, the CRE had to
establish an appropriate method of identifying and accounting for costs that reflected the economic conditions of historic nuclear power generation.
This calculation method is based on consideration of the following:
– the capital invested in EDF’s nuclear plants, which will be reimbursed through an asset base amortised over the life of the ARENH mechanism at the weighted average cost of EDF company’s capital. This asset base will include amounts initially invested in the historic nuclear plants which have not yet been amortised, as well as all or part of the capital that EDF invested and still has to invest in order to cover its long-term nuclear costs (dismantling, deconstruction, waste management, etc.) in application of law no. 2006-739 of 28 June 2006;
– operating costs relating to the nuclear plants, which will be reimbursed as and when they are recorded, based on a forecast and its correction ex post;
– investments in maintenance and extension of the term of the operating license that will be included in the ARENH price as they are incurred by EDF, based on a forecast and its correction ex post.
Investments in maintenance and extension of the term of the operating license will be included in the ARENH price as they are incurred by EDF, based on a forecast and its correction ex post. ¯ Work on the stator of nuclear unit 1 at the nuclear power plant at Tricastin during the ten-yearly inspection in June 2009. © EDF – C. Helsly
˘ Teams from the SIR (Service inspection réglementation - Inspection and Regulation Department) at work on pressure equipment, including the steam ring (shown here) at the nuclear power plant at Penly. © EDF – P. Eranian
d42/MWh
The CRE took a stable ARENH price of J42/MWh until 2013 inclusive as a working hypothesis, along with an increase at the rate of inflation from 2014 onwards.This method, which was applied at the time to data forwarded by EDF, had led the CRE to set the price of ARENH within a bracket of F36/MWh to F39/MWh. The difference from the F42/MWh price is justified by the government by anticipated consideration of the investment required to improve the safety of nuclear plants - as a consequence of the Fukushima accident - which the CRE is not able to decide upon, and which the CRE stated should be taken into consideration as they are incurred.
The Cour des Comptes’ (Court of Auditors) report on the costs of the nuclear power industry, published on 31 January 2012, and the Autorité de sûreté nucléaire (French Nuclear Safety Authority) report, published on 3 January in the same year, provide insights into these issues. They will be taken into account in the next ARENH price and in the upcoming decree. While we await the publication of this text, in order to be able to calculate the prospective development of electricity prices in France, the CRE worked on the hypothesis of a stable ARENH price of F42/MWH until 2013 inclusive, and an increase in line with inflation from 2014 onwards.
Variations in the ARENH price influence the level of the energy share in supply offers made to end customers. The effect is, however, significantly
different for different categories of consumers. Indeed, the theoretical right to ARENH available to a supplier depends on the consumption2 of its customers during certain specified hours in the year. With the electricity purchased from EDF at the ARENH price, providers must be able to cover a share of their customers’ consumption equivalent to the share of nuclear production in total French consumption. For example, for the year 2013, the energy share of a residential customer’s bill will be approximately 80% ARENH3, and that of an industrial customer will be about 90% ARENH.
2 – Terms of calculation defined by the decree of 17 May 2011 on the calculation of rights to regulated access to historic nuclear power.
3 – ARENH rate defined as the volume ratio of ARENH obtained by the looking at the customer’s load curve, determined following the method defined by the regulatory texts and the customer’s total consumption. It is used to define the volume of electricity supplied under ARENH for a given consumption profile.