Key Benefits:
Attended the session: Philippe de LADOUCETTE, Chairman, Olivier CHALLAN BELVAL, Hélène GASSIN, Jean-Pierre SOTURA and Michel THIOLLIÈRE, Commissioners.
Introduction
Third rates for the use of public electricity networks " TURPE 3 " Entered into force on 1 August 2009, pursuant to the decision of 5 May 2009 approving the tariff proposal of the Commission for the Regulation of Energy (CRE) of 26 February 2009
Methodology for the development of the tariffs for the use of a public electricity network in the HTB voltage domain and set the tariffs referred to " TURPE 4 HTB " To apply as of 1 August 2013.
The rates for the use of a public electricity network in the HTA or BT voltage domain will be the subject of a separate decision to take account of the reasons for the decision of the Council of State On November 28, 2012 cancelling the TURPE 3 as it set the rates for the use of public distribution networks. The CRE will take into account the effects of these tariffs on the cost of access to the public transportation network for distribution system operators. The CRE will take into account, at the time of the development of the HTA/BT tariffs, the questions raised by some stakeholders on the synchronization of annual changes in HTB tariffs, on the one hand, and HTA/BT on the other.
Framework Legal
Articles L. 341-2, L. 341-3 and L. 341-4 of the Energy Code frame the powers of the CRE in determining the rates of use of public electricity transmission and distribution networks (TURPE).
Article L. 341-3 provides the following provisions:
" The methodologies used to establish the tariffs for the use of public electricity transmission and distribution networks shall be fixed by the Energy Regulatory Commission. [...] The Energy Regulatory Commission shall decide [...] on developments in the tariffs for the use of public transmission and distribution networks [...]. It may provide for a multiannual framework for the evolution of tariffs and Appropriate incentives, both in the short term and in the long term, to encourage transmission and distribution system operators to improve their performance, in particular with regard to the quality of electricity, to promote Integration of the internal electricity market and the security of Procurement and productivity efforts.
The Energy Regulatory Commission takes into account the energy policy guidelines indicated by the administrative authority. It shall regularly inform the administrative authority during the rate-setting phase. It shall, in accordance with the manner in which it determines, consult the stakeholders of the energy market.
The Energy Regulatory Commission shall transmit to the Administrative Authority for publication in the Official Journal of the French Republic, Its reasoned decisions on developments, in terms of level and structure, of the tariffs for the use of public transmission and distribution networks, [...] on the dates of entry into force of these tariffs. "
Article L. 341-2 of the Energy Code provides that" The tariffs for the use of the public transport network and public distribution networks shall be calculated in a transparent and non-discriminatory manner, in order to cover all the costs incurred by the managers of these networks in the measure Where these costs correspond to those of an effective network manager. "
Article L. 341-4 of the Energy Code states that" The structure and level of the rates for the use of transmission and distribution networks shall be fixed in order to encourage customers to limit their consumption to periods when the consumption of all consumers is the most
order to establish these new tariffs, the CRE also took into account the legislative and regulatory framework related to the 3rd Energy Package, which sets out the independence obligations required for TENs in the context of the implementation of the Independent transmission system operator ("model") ITO "). One of the main purposes of the model " ITO " Is to make investment decisions, taken by TENs, independent of the specific interests of the integrated group to which it belongs. To this end, Article L. 111-19 of the Energy Code specifies that the operator of the public transport network shall have all the financial resources necessary for the exercise of its transport activity. Thus, the vertically integrated undertaking EDF (1) must, as a shareholder, make available to the manager of the public transport network the appropriate financial resources for future investment projects and/or Replacing existing assets. In accordance with Article L. 111-13 of the Energy Code, it is the responsibility of the supervisory board of the public transport network manager to make the decisions " On the approval of its annual and multi-annual financial plans, its level of indebtedness and the amount of dividends distributed to shareholders. "
Tariff Works
RTE requested new rates on July 27, 2012. This demand led to a tariff increase of + 5.2 % on 1 August 2013 and then to annual developments from 2014 to 2016 equal to inflation plus 1 %.
The CRE carried out analyses of the forecast loads presented by RTE and Supported by various studies carried out by external firms:
-an international comparative study of incentive regulatory mechanisms;
-a study on the cost structure of public electricity transmission and distribution networks;
-a study on pricing methods Public electricity networks;
-a study on incentives for the development of interconnections and the forecast trajectory of revenue related to interconnections management mechanisms (also called revenue Auction);
-a study of the weighted average cost of capital Electricity and natural gas infrastructure.
The CRE conducted four public consultations on the following topics:
-the structure of the rates for the use of public electricity transmission and distribution networks (15 July 2010 and 6 March 2012);
-the framework for the regulation of the tariffs for the use of public electricity networks (7 June 2012) ;
-charges to be covered by the rates of use of public electricity networks, regulatory framework, structure and tariff rules (6 November 2012).
Syntheses of these consultations have been published (2) on the website of the CRE.
CRE has auditioned several times RTE, its shareholder, and All market participants in July 2012 and in December 2012.
Finally, in accordance with the provisions of Article L. 341-3 of the Energy Code, the ERC took into account the energy policy guidelines provided by the Minister for Energy. Ecology, sustainable development and energy by letter of 10 October 2012. These guidelines address the incentive tools for the development of interconnections and the improvement of the level of food safety and the seasonal structure of rates and the rate of injection. These guidelines are available on the CRE website.
Main developments
On the basis of all these elements, the CRE is, by strengthening it, renewed the existing multi-annual regulatory framework for TENs. Improve the control of its costs and the quality of service provided to users. The CRE introduces a financial incentive for the development of interconnections and a follow-up of the actions undertaken by RTE to control the volume of losses. It also puts in place a regulatory framework favourable to research and development (R&D).
With regard to the structure of tariffs, this tariff decision makes important changes, in particular by introducing a Differentiation of the prices of the subscribed power and the use of this power according to the periods of the year and the hours of the day, in order to encourage users to limit their demand for power during peak demand, In accordance with the provisions of Article L. 341-4 of the Energy
. Price developments, the CRE held an increase of 2.4 % on 1 August 2013 and then indexation on inflation, excluding possible differences between the forecast trajectories and realized on posts included within the scope of the Expense and product control account (CRCP).
The rate increase for 2013 (+ 2.4 %) (3) is mainly due to the following factors:
-the increase in operating and capital charges (contributing to the 3.1 % increase);
-changes in the level and structure of consumption by voltage level (for + 2.7 %);
-the effects of taking Account for the same reference period for expenses and revenue (for + 1.4 %);
-the decrease in CRCP's annual fees, which is offset by the charges to be covered (for + 3 %) partly offset by the rate changes resulting from the The clearance of the CPR during the period of TURPE 3 (for-2.3 %) (4);
-these factors are Partially offset by the downward effects on the rate of increase in forecast auction revenues and the change in their tariff treatment (for-5.5 %) (5).
The differences between the selected tariff increases By the CRE and those requested by RTE are mainly related to the following parameters:
-the failure to take into account the TEN requests for the determination and remuneration of assets: Compensation for a mid-year asset base, current capital assets at the weighted average cost of capital and subsidized assets;
-revisions to the assumptions used for certain expense items, including purchases related to Compensation for losses on networks, service of interruptibility, external purchases and taxes.
The Higher Energy Council, consulted by the ERC on the proposed tariff decision, delivered its opinion on February 21, 2013.
TARIFFS METHODOLOGY
A. -METHODOLOGICAL PRINCIPLES
In order to set transport rates, the CRE establishes in the first stage a forecast revenue revenue.
The CRE also lays down a regulatory framework which aims, on the one hand, to limit Posts of pre-defined loads or products the financial risk of the operator and/or the user, via regulatory accounts and, on the other hand, to encourage the operator to improve its performance and to promote market integration and Security of supply through the introduction of incentive mechanisms. The financial impact of these devices is accounted for either in the calculation of the estimated tariff revenue, or ex post.
The estimated tariff income is broken down between users in the form of tariffs. There are several tariff components that meet different purposes. Nevertheless, those which constitute the main part of the turnover of the operator are the rates of recirculation. The latter consist of different coefficients, all of which are designated by the term tariff structure.
Taking all of these factors into account allows for the establishment of tariffs on their effective date.
Definition of estimated revenue revenue
The CRE defines the operator's forecast tariff income over the period considered on the basis of a business plan (6) transmitted by The operator.
This forecast tariff revenue consists of the charges for Capital and net operating expenses as well as the impact of the regulatory accounts.
RT1 = CNE1 + CC1 + A
with:
RT1: forecast tariff revenue over time;
CNE1: net operating expenses Forecast for the period;
CC1: forecast capital charges over the period;
A: clearance of throttling accounts for the period.
Estimated capital expenses include remuneration and amortization of the Regulated asset base (BAR). BAR is determined on the basis of the net book value of the locked-in assets, net of grants and contributions received from third parties.
Estimated capital expenses = forecast depreciation + BAR forecast × CMPC
The method used to set the rate of pay for assets is based on the weighted average cost of capital (CMPC) to normative financial structure. The level of remuneration of the operator must, on the one hand, enable it to finance interest charges on its debt and, on the other hand, to provide it with a return on its own funds comparable to that which it could obtain for Investments with comparable levels of risk. This cost of own funds is estimated on the basis of the methodology known as the " Financial asset valuation model " (MEDAF).
Net operating expenses include net operating expenses (mainly composed of external purchases, staff costs and taxes), and purchases related to the electrical system, net of Extratarifarious revenues (mainly composed of revenue related to the management of interconnections).
The level of operating expenses retained is determined from the full range of costs involved. The activity of a network operator to the extent that These costs correspond to those of an effective network manager. The set of forecast data provided by the operator shall be subject to detailed analysis and corrections where appropriate. In particular, with regard to net operating expenses, the CRE is committed to retaining an operating load trajectory that integrates productivity efforts.
Regulatory Framework
Operator activity is Framed by different devices that make up what is called the " In
first place, the provisions of the regulatory framework make it possible to adapt the forecast tariff income according to the inflation achieved in order to immunise the trader against the risks associated with the inflation weighing In
second place, the provisions of the regulatory framework make it possible to correct, a posteriori, the forecast tariff revenue for pre-defined posts, eligible for the said expense and product control account (CRCP), the Variances between forecast revenues and revenues on the one hand, and
Finally, in order to encourage the operator to effectively manage the network, the ERC puts in place incentive mechanisms. These provisions concern different areas of activity of the network manager: control of these operating expenses, the quality of food offered to users, the management of losses on the network, the development of the Interconnections and research and development activity. Some of these devices are accompanied by financial incentives (in the form of positive or negative premiums) which, as the case may be, increase or reduce the forecast tariff income during the period.
RTN = RT ' 1 + EN-1 + IN - 1
with:
RTN: tariff revenue for year N;
RT ' 1: forecast tariff revenue for year N corrected for inflation achieved;
EN-1: variance of year N-1 charged to CRCP balance;
IN-1: Incentives for year N-1.
Price Structure
Sdrawing rates are constructed to encourage each user to adopt consumer behaviour that minimizes long-term network costs. The methodology for the construction of tariffs also takes into account the provisions of Article L. 341-4 of the Energy Code which provide that tariffs shall be fixed in order to encourage customers to limit their consumption to periods when Consumption of all consumers is the highest.
In order to do this and from the forecast data on the distribution of flows and consumption provided by the operator, the methodology for the construction of the rates of recirculation is Based on an analysis of the distribution of network costs between the different hours of And allocates these costs to users based on their respective consumption characteristics.
B. -EFFECTIVE DATE OF TARIFFS
Third rates for the use of public electricity networks (TURPE 3) entered into force on August 1, 2009 and apply until July 31, 2013.
These tariffs are intended to Apply as of August 1, 2013.
These rates have been designed to apply over a period of approximately four years.
C. -DEFINITION OF FORECAST TARIFF INCOME
1. Capital charges
Capital charges include a share of depreciation and a share of the financial remuneration of capital assets. In order to calculate the capital charges to be covered by the tariffs, the CRE retains the estimated investment amounts presented by RTE. The rate of pay for the regulated asset base is maintained at 7.25 %, nominal before tax.
1.1. Investment Trajectory
The CRE retains the investment path proposed by RTE:
| Investment Trajectory | 1500 | 1 609 | 1 711 | 1 769 |
1.2. Regulated Asset Base
The valuation principles for the regulated asset base (BAR) retained since the TURPE 2 are rolled back. In the context of TURPE 4, the value of the BAR is calculated from the net book value of the assets, reduced investment subsidies and products recognised in advance by the subsidiary Arteria de RTE, according to the principles outlined By the deliberation of the ERC of 7 December 2006 on the audit of the development activities of the fibre optic network and the upgrading of Arteria's high points for the financial year 2005. Capital assets that benefited from the 1976 revaluation are included in the BAR at their acquisition value (excluding revaluation).
The conventional date of entry into the BAR is January 1 of the year following their release. Service. BAR is progressing at the rate of investments in service and is reducing the amount of write-offs that are covered by the rates.
In addition, the principle of compensation for fixed assets at the cost of the debt is being renewed. The rate of remuneration retained for the current capital assets of RTE is equal to the cost of the debt retained in this deliberation (cf. Section 0).
The forecast trajectory for BAR over the 2013-2016 period is as follows:
| Regulated Asset Base | 11 654 | 12 114 | 12 688 | 13,332 |
1.3. Rates of Pay for Assets
As with each new tariff, the CRE has reviewed the various parameters involved in the calculation of the CMPC and the resulting ranges of values. It also:
-entrusted a study to an external consultant on the CMPC for electricity and natural gas infrastructure. This study was conducted during the summer of 2011;
-conducted regularly in-house evaluation work on CMPC parameters;
-auditioned the operator who commissioned an external consultant to study the profitability analysis of Electricity transmission activity;
-auditioned the shareholder;
-taking into account changes to the tariff framework.
In the context of these tariffs, the CRE retains the value of 7.25 %, nominal before tax, on the basis of ranges Values for each of the parameters involved in the CMPC formula.
The Estimates for each of these parameters are shown in the table below.
| Nominal Risk Rate | 4.0 % | |||
| Spread of Debt | 0.6 % | |||
| Prime Market | 5.0 % | |||
| Beta Assets | 0.33 | |||
| Capital Beta | 0.66 | |||
| Levier (debt/[debt + fund Clean]) | 60 % | |||
| Corporate Tax Rate | 34.43 % | |||
| Cost of Debt (*) | 4.6 % | |||
| Equity Cost (*) | 11.2 % | |||
| Weighted Average Capital Cost (*) | 7.25 % | |||
| (*) Pre-tax Nominal | ||||
1.4. Capital Expense Level
The capital charge path is as follows:
| Compensation for assets in service | 845 | 878 | 920 | 967 |
| Current Capital Compensation | 62 | 72 | 79 | 86 |
| Rate Covered by Rate | 661 | 696 | 728 | 772 |
| Total Capital Expenses | 1 568 | 1 646 | 1 727 | 1 824 |
2. Net operating expenses
Article L. 341-2 of the Energy Code provides that " The tariffs for the use of the public transport network and public distribution networks shall be calculated in a transparent and non-discriminatory manner, in order to cover all the costs incurred by the managers of these networks in the measure Where these costs correspond to those of an efficient network manager [...] ".
The cost coverage actually incurred by the network manager is accompanied by incentives to make the best use of the tariff resources available to it
The operating expenses to be covered by the tariffs were Determined on the basis of all the operational costs necessary for the operation of the public transport network. To set the level of these charges, the CRE has relied inter alia on:
-the trajectory proposed by RTE for 2013-2016;
-the data from the TEN social accounts for the years 2009, 2010 and 2011 and the forecast data for 2012;
-the return of experience of TURPE 3 and the results of the analyses carried out by the CRE on the operating expenses of RTE for the years 2009 to 2016.
The average net operating expenses retained by the CRE for RTE, for The next tariff period is € 2,789 million. The expected average annual growth rate of these net operating expenses between 2013 and 2016 is + 1.4 %.
| Expenses Net operating | 2 753 | 2 756 | 2 778 | 2 866 |
| Operating net charges | 1 995 | 2 045 | 2 062 | 2 116 |
| electrical system-related charges | 1 094 | 1,048 | 1 052 | 1 087 |
| Extracarifarian products | -351 | -351 | -349 | -350 |
| Others | 16 | 15 | 15 | 14 |
2.1. Net operating expenses
Operating expenses consist of other purchases and services, security expenses, personnel expenses, taxes and other charges and operating products After deduction of locked-in production.
2.1.1. Other purchases and services
| Other purchases and services, excluding security | 656 | 683 | 708 | 725 |
| Adjustments retained by CRE | 5 | 10 | 15 | 20 |
2.1.2. Charges for the mechanical security program for the public transport network
| Expenses related to Trust program | 196 | 173 | 123 | 101 |
2.1.3. Staff expenses
The TEN assumptions in terms of enrolment and pay changes have been retained in the trajectory of net operating expenses for the period 2013-2016. The staff expense item represents an average of € 850 million per year over the period of the TURPE 4, which is on the increase compared to the period of TURPE 3, in particular:
-additional manpower requirements induced by new activities (internalisation and development of R&D, evolution of regulation, deployment of a promotional training device) which translate into a An increase of € 12 million on average per year over the period;
-to take account of changes in social charges (increase in the social package, increase the rate of social security contributions and increase their base of calculation), which are reflected in Additional costs to the operator of about € 24 million on average per year over the period.
In addition, the ERC analysed the productivity efforts proposed by RTE in terms of retirees of the previously described scope evolutions. The results of this analysis are presented in Section C. 2.1.5.
2.1.4. Taxes
| Taxes | 478 | 502 | 525 | 550 |
| Adjustments Selected by CRE | 2 | 4 | 6 | 8 |
2.1.5. Productivity Objectives
Article L. 341-3 of the Energy Code sets out the principles of incentive regulation to encourage operators to improve their performance, in particular by searching for productivity efforts.
In This framework, the CRE analysed in detail the trajectory of the net operating expenses of RTE between the year 2011, the final year for which final results were available, and the forecasts for the period 2012-2016
The application of this productivity objective, the CRE, first, Distinguished:
- (1) loads of a nature " New " In relation to those taken into account in the context of TURPE 3 (mainly the burdens linked to the new regulatory constraints, the additional staff induced by the new TEN activities and developments in rates and rules) Social expense base).
- (2) specific charge stations for which the application of a productivity objective is not relevant. These items correspond mainly to taxes, security expenses and other miscellaneous expenses and products (such as insurance charges, expenses of the " Agent rate " And the products of the penalties charged by RTE under the system service contracts and the adjustment mechanism).
The analysis of these charges is detailed in the preceding sections concerned (sections C. 2.1.1 to C. 2.1.4). The CRE has made adjustments where appropriate on the level of the charges to be covered by the operator for these charges, but considers that it is not relevant to apply a productivity target on these loads.
In contrast, the other operating expenses of RTE are considered to fall within a constant activity perimeter (3) in relation to the period of the TURPE 3. This scope mainly includes expenditure on "other purchases and services" And " Staff costs ". The CRE considers that, for the part relating to this constant activity perimeter, the trajectory of the selected net operating expenses must incorporate productivity efforts.
The details of the calculation of the constant activity perimeter on which the CRE conducted its analysis below:
| Total net operating expenses-RTE request | 1 855 | 2 006 | 2 062 | 2 092 | 2 152 |
| New charges (1) | -9 | -83 | -111 | -128 | -148 |
| Other purchases-section C. 2.1.1 | -9 | -50 | -76 | -91 | -109 |
| Personnel charges (new payroll and new payroll) - section C. 2.1.3 | 0 | -33 | -35 | -37 | -39 |
| Other specific nodes (2) | -778 | -813 | -816 | -801 | -813 |
| Tax and Tax-Section C. 2.1.4 | -441 | -480 | -505 | -532 | -558 |
| Secure expenses-section C. 2.1.2 | -196 | -196 | -173 | -123 | -101 |
| Other products and loads | -141 | -138 | -138 | -147 | -154 |
| Total "Payloads" Perimeter of constant activity " (3) | 1 067 | 1 111 | 1 135 | 1 163 | 1 190 |
| Other purchases and Services (4) | 443 | 465 | 468 | 478 | 481 |
| Personnel charges (5) | 624 | 646 | 667 | 685 | 709 |
| Total net operating expenses-RTE request | 1 855 | 2 006 | 2 062 | 2 092 | 2 152 |
| ERC adjustments detailed in sections C. 2.1.1 to C. 2.1.4 | | -7 | -14 | -21 | -28 |
| Additional productivity efforts on the constant activity scope retained by the CRE | | -5 | -4 | -9 | -7 |
| Total net operating expenses retained by CRE | 1 855 | 1 995 | 2 045 | 2 062 | 2 116 |
2.2. Expenses related to operating the
2.2.1 power system. Purchases related to compensation for losses on the network
In accordance with the provisions of Article L. 321-11 of the Energy Code, RTE negotiates freely with producers and suppliers of its choice the contracts allowing for the Loss coverage, in accordance with competitive, non-discriminatory and transparent procedures, such as public consultations or the use of organised markets.
Implementation of regulated access to nuclear electricity ARENH for the compensation of losses, introduced by Article L. 336-1 of the energy code and specified by the provisions of decree n ° 2011-466 of 28 April 2011, offers RTE a new opportunity to buy the energy needed for the Compensation for losses. This new arrangement reduces the average unit cost of offsetting losses by about 18 % over the period 2013-2016.
The CRE analysed the cost trajectory of the losses proposed by RTE and made adjustments by Operator request report:
-downward revision of the ARENH price evolution path;
-taken into account of the November 19, 2012 Order Amending the Order of November 25, 2011 fixing the schedule for opening ARENH rights for losses;
-taken Account of a cost estimate for the guarantee of capacity which will be borne by the suppliers of losses for the winter 2015-2016 in application of the Decree n ° 2012-1405 of 14 December 2012.
All of these adjustments represent a Average decrease in position " Loss purchases " EUR 23 million per year for the period of TURPE 4 compared to the demand for RTE.
The estimated levels of energy losses and charges related to the compensation of these losses retained by the CRE for the period 2013-2016 are as follows:
| Volume (TWh) | 11.5 | 11.8 | 11.8 | 11.9 |
| Cost (current M€) | 677 | 607 | 607 | 632 |
2.2.2. System Services
These rates cover the related costs:
-the creation of primary and secondary reserve-setting reserves;
-the constitution of primary and secondary reserves of Voltage adjustment-reactive power;
-adjustments for rebuilding system services;
-synchronous compensation.
The CRE has analyzed the system service loads proposed by RTE. Price developments are consistent with the price indexation of the model contract for participation in the system services. The CRE retains the trajectory proposed by RTE:
| Frequency Tuning | 206 | 211 | 217 | 224 |
| Voltage adjustment | 125 | 127 | 129 | 132 |
| Total Cost | 331 | 338 | 346 | 356 |
2.2.3. Other charges related to the operation of the electrical system
These rates cover the costs related to congestion, the exchange contracts between transmission system operators, the inter-manager compensation mechanism of Transport network (ITC) and the service of interruptibility.
The CRE has analysed the forecast loads proposed by RTE and carried out on this basis an adjustment of the trajectory of the charges related to the service of interruptibility:
-taken into account of the Decree of 10 December 2012 adopted pursuant to Article L. 321-19 of the Energy Code setting out in particular the arrangements for the remuneration of the mechanism of interruptibility;
-taking into account the time limit for placing the Interruptibility service that generates charges from 2014.
These adjustments result in an average decrease in the number of posts." Other charges related to the operation of the electrical system " € 11 million per year for the period of TURPE 4 compared to the demand for RTE.
For the period 2013-2016, the forecast trajectory of the charges for system purchases excluding losses and system services retained for the definition of the level Tariff is as follows:
| Other charges related to operating the electrical system | 86 | 102 | 99 | 100 |
2.3. Extratarifaires
Forecast revenue regardless of network utilization rates is deducted from the operating expense forecast to be covered by the rates. The main issue is revenue TENs related to the mechanisms for managing interconnections. A study was commissioned by the ERC to an external consultant to assess the revenue trajectory associated with the interconnection management mechanism. The trajectory proposed by RTE is in line with the results of this study.
As a result, the CRE retains the estimated extratarifarious revenue trajectory proposed by RTE:
| Extratarifaires | 351 | 351 | 349 | 350 |
| Recipes for interconnections management mechanisms | 280 | 280 | 280 | 281 |
3.
3.1 regulatory accounts. Apure of the Interconnect Financing Regulated Account
The Interconnections Financing Regulated Account (CRFI) is a specific account set up within the framework of TURPE 3. The objective of this mechanism was to allocate part of the revenue related to the allocation of the interconnection capacity to the financing of investments to maintain or increase interconnection capacity as proposed by Article 16 of the European Regulation (EC) No 714/2009 of 13 July 2009. The total amount of auction revenue allocated in the framework of TURPE 3 to the financing of interconnections was 202.9 million.
In order to avoid double remuneration for assets deemed to be financed by auction revenue and included in BAR, the TURPE 3 intended to reduce the charges to be covered by the rates of an annuity equal to the capital charges corresponding to those assets. This annuity was equal to the remuneration of the starting stock of the year and the amortization on the basis of a standard length of forty years.
In the context of TURPE 4, the whole of the auctioning proceeds will be deducted from the tariffs (cf. Section D. 3). An annual monitoring mechanism for investments to maintain or increase interconnection capacity, as described in Section D. 3, is set up.
At the end of 2012, as a result of the assignments and amortization carried out in the Framework of the TURPE 3, the credit of the CRFI is € 194 million in favour of users. In view of the termination of the mechanism, this balance, initially intended to be cleared over forty years, will be totally cleared over the period of the TURPE 4.
The discount rate used for clearance is the risk-free rate fixed for the period of the TURPE 4 (cf. Section 0). The four-year annuity resulting from this balance is € 54 million in favour of users. It will be deducted from the charges to be covered.
3.2. Apurely of the
expense control account and the products from the previous tariff periods
TURPE 3 provided for the balance of the TURPE 2 CRCP balance over five years. At the end of 2012, the non-affixed balance of the TURPE 2 CRCP amounts to € 306 million in favour of users. In particular, the balance of the TURPE 2 CRCP was explained by revenue related to the management mechanisms of the interconnections considerably higher than the forecast and the absence of clearance over the period of the TURPE 2.
Starting from the TURPE 3, an annual CRCP clearance mechanism was put in place. This approach has allowed the discrepancies between the forecast and the actual data to be cleared more regularly. Taking into account the balances of the years 2009, 2010, 2011 and the forecasts made mid-2012 for 2012, the balance of the TURPE 3 CRCP stands at-€ 0.6 M€ at the end of 2012 in favour of RTE.
As foreseen in the framework of TURPE 3, the amounts resulting from The application of the incentive mechanisms on controllable operating expenses, the cost of purchasing losses, and the continuity of food are charged to the CPRC balance at the end of the tariff period. At the end of 2012, the balance of the CRCP incentives amounts to € 5 million for users.
| controllable operating expenses | 0.0 | 0.0 | 3.0 |
| Loss Purchase Cost | -0.5 | -1.0 | -2.4 |
| Continuity Power | 8.3 | 4.2 | -7.5 |
| Total (excluding compensation) | 7.8 | 3.2 | -6.9 |
| Compensation | 1.0 | 0.3 | -0.3 |
| Total | 8.8 | 3.5 | -7.2 |
| CRCP TURPE 2 | 306 |
| CRCP TURPE 3 | -1 |
| CRCP incentives | |
| Late 2012 Commitments | 311 |
4. Estimated Rate Revenue
The level of charges to be recovered by the rates is as follows:
| Net operating expenses | 2 753 | 2 756 | 2 778 | 2 866 |
| Capital charges | 1 568 | 1 646 | 1 727 | 1,824 |
| CRCP Annuity | -82 | -82 | -82 | -82 |
| Apure CRFI | -54 | -54 | -54 | -54 |
| Payable | 4 185 | 4 266 | 4 369 | 4 555 |
D. -REGULATORY FRAMEWORK
1. Annual price developments
Starting in 2014, tariffs are mechanically adjusted every August 1 of the following percentage:
ZN = IPCN + kN
ZN: percentage change, rounded to the nearest tenth of one percent Close to the tariff schedule in effect as of August 1 of year N in relation to the one in effect the previous month;
IPCN: Percentage of evolution, between the average value of the monthly index of non-tobacco consumption prices over the calendar year N-1 and the average value of the same index for the calendar year N-2, as published by INSEE (identifier: 000641194) ;
KN: the CRCP clearance factor for the year N, calculated on the basis of the CRCP balance as at December 31 of year N-1 and the transfers already made. The absolute value of the KN coefficient is capped at 2 %.
2.
2.1 product and load throttling account. Principles
Given the duration of the tariffs, set at approximately four years, the CRE bases its present tariff relief on short-and medium-term trends in charges and products.
For some Categories of loads and products that are difficult to predictable or difficult to control, the CRE redirects the mechanism of the product and product control account (CRCP), set up in the framework of TURPE 2, to measure and Compensate, for previously identified positions, the differences between the
The CRCP is also the vehicle used for the financial incentives resulting from the application of the incentive control mechanisms.
CRCP is an account Where, where applicable, the overpayments and shortfalls to be earned from RTE are charged. Its clearance is effected by an adjustment of the tariff schedule during the annual evolution. The contribution of the CRCP clearance to the annual variation of the fee schedule is limited to 2 % or more.
2.2. Scope
The charge and revenue entries that are subject to this mechanism are:
-charges related to loss compensation on networks;
-certain charges related to the management of interconnections, namely international congestion costs and net externalized expenses related to management costs Mechanisms to allocate capacity for interconnections, provided that they can be audited;
-liabilities related to the net book value of demolished capital assets; and
-revenues collected for all Tariff components according to the following terms;
-revenue related to Mechanisms for managing congestion at the interconnections of the transport network with neighbouring countries. These revenues are net of the allowances paid by RTE in the event of reduced capacity for interconnections;
-revenue from contracts between transmission system operators;
-financial incentives for the various Incentive regulatory mechanisms;
-R&D operating expenses (as set out in Section D. 4.3.1);
-capital charges.
In addition, the results of the audits conducted by the ERC will be taken into account in The CRCP scope.
2.3. Operating Rules
For each position identified as eligible for the CRCP, the calculation of variances is done according to the rules described below.
1. For each of the posts of eligible expenses or products, excluding products collected on the whole of the tariff components, the calculation of the deviations carried over to the CRCP shall be carried out on the basis of the comparison of the reference value of the Forecasts of annual expenses or products and the amounts realized from these expenses or products for each of the years of the tariff period.
The rate grid being indexed to the consumer price index (CPI) excluding tobacco, RTE is covered Against the risk of inflation on all its expenses. However, the evolution of the posts covered by the CRCP mechanism, such as compensation for energy losses on networks or capital charges, is not necessarily linked to the evolution of the CPI. To correct this bias, the CRE adapts the reference values used in the calculation of the CRCP balance.
These reference values, necessary for the calculation of the CPRC of year N, are therefore calculated on the basis of forecast values expressed in Euro constant 2013 and annually reassessed on the basis of changes in the CPI selected for the calculation of the tariff schedule for the year N and prior years.
The forecast values, expressed in constant 2013 euros, for the Different operating expense and capital expense items, are fixed Below:
| Network Loss Compensation Charges | 677 | 597 | 584 | 596 |
| International Cost of Congestion | 3 | 3 | 3 | 3 |
| Net externalized expenses for managing interconnections capacity allocation mechanisms | 3 | 3 | 3 | 3 |
| Net Book Value of demolished assets | 24 | 23 | 23 | 22 |
| Operating Expenses | 706 | 626 | 613 | 624 |
| Interconnect Congestion Management Mechanisms Revenue | 280 | 275 | 270 | 265 |
| Contract Revenue between Transport Network Managers | 0 | 0 | 0 | 0 |
| Operating Products | 280 | 275 | 270 | 265 |
| Capital charges | 1 568 | 1 617 | 1 663 | 1 722 |
| Expected Rate Income | 4 182 | 4 297 | 4 397 | 4 495 |
3. Interconnections Funding Regulated Account
As indicated in Section C. 3.1, the Interconnections Financing Regulated Account (IMRC) is a specific account set up within the framework of TURPE 3. The objective of this mechanism was to allocate part of the revenue related to the interconnection capacity allocation to the financing of investments to maintain or increase interconnection capacity under Article 16 of the European Regulation (EC) No 714/2009 of 13 July 2009.
Since the CRFI is an extractable account, the amounts allocated to it were not deducted from the operator's result and were therefore subject to corporate and levy taxes Dividends. The amount actually available to finance interswitching investments was similarly reduced.
This scheme did not allow for an efficient allocation of financial resources for the implementation of interconnections. In order to ensure compliance with Article 16 of Regulation (EC) No 714/2009 of 13 July 2009, an annual follow-up will be made to ensure compliance with Article
of Regulation (EC) No 714/2009. Investment to maintain or increase exchange capacity will be achieved. It will ensure that, over the tariff period, the amount of investment that helps to maintain or increase trading capacity is in line with the auctioned revenues. TEN will have to provide, within the framework of the annual TEN investment programme, the quantitative and qualitative elements to justify the contribution of projects to cross-border exchanges.
4.
4.1 incentive. Operating expenses
The trajectory of the net operating expenses of RTE is defined in the period 2013-2016 (cf. Section C. 2). It incorporates a productivity target on the net operating expenses at a constant level of activity relative to the previous tariff period.
The regulatory framework for TURPE 3 provided for an asymmetric system in which RTE retained 50 % of productivity gains achieved relative to the fixed trajectory and assumed 100 % of productivity losses. For the period of the TURPE 4, the CRE holds a symmetrical system in which RTE retains 100 % of the additional productivity gains and losses. The CRE thus wishes to reinforce the incentive for RTE to control its costs.
4.2. Interconnection investments
Article 37 of the European Directive 2009 /72/EC of 13 July 2009 and Article L. 341-3 of the Energy Code provide that the ERC may provide for appropriate incentives, both in the short term Long-term, in order to encourage transmission and distribution system operators to promote the integration of the internal electricity market.
Development of new infrastructure to improve exchange capacities Cross-border is one of the conditions for the emergence of a European market Integrated energy. Interconnections also allow the optimisation of the resources of the electrical system in a context of strong development of electricity generation from intermittent energy sources. Interconnections are at last involved in the consolidation of security of supply.
The implementation of interconnection projects also requires specific efforts on the part of TENs, in particular to overcome difficulties connected with Coordination with its counterparts in neighbouring countries, obtaining administrative authorisations, local acceptability of works and technical challenges in overcoming natural barriers.
The CRE has conducted several studies for Consider the appropriateness and feasibility of an incentive mechanism in the Development of interconnections based on the evaluation of the usefulness of the works. The CRE also consulted with stakeholders on the interest of such an incentive and on the envisaged mechanism.
The present deliberation introduces a regulatory framework to encourage TENs to develop interconnections. The incentive mechanism thus created is consistent with the guidelines provided by the Minister for Ecology, Sustainable Development and Energy, by contributing to the development of border exchange capacities, in agreement with the European and national perspectives for the development of the network.
The incentive mechanism is based on the assessment of the value of the new interconnection infrastructure for the European electrical system and aims to:
-stimulate the realization of interconnecting projects useful to the community;
-encourage RTE to carry out the investments in the best possible terms and conditions of costs;
-encourage TENs to operate effectively The newly created interswitching structure, in particular as regards the additional commercial flows provided by the work.
RTE will provide to the ERC, at least seven months before the commitment decision, the elements for assessing the interest The interconnection it wishes to achieve. The ERC will, where appropriate, decide to grant incentives and set out detailed rules for calculation in an ad hoc tariff decision.
The financial incentive for the implementation of interconnection investments is Materialise through the allocation of an annual fixed premium expressed in euros, the amount of which will be defined upstream of the investment decision according to the interest of the interconnection to the community.
Incentives to minimise Costs and time limits for interswitching, as well as The incentive to use it, will take the form of variable premiums which will be added every year to the annual fixed premium. The parameters used for the calculation of these premiums will be set out in the CRE ad hoc decision on each project.
4.2.1. Payment of Premiums and Payment Terms
The premium amounts will be set in accordance with the following principles:
-the sum of annual premiums will be positive or zero;
-the cost premium may, if positive, be retained in full by RTE regardless of the levels of the other premiums, which reinforces the incentive for RTE to Control costs;
-the sum of annual premiums (fixed and variable) will be capped depending on the value of the interconnection to the community and the amount of the investment.
Due to the positive nature of the premium, RTE is Assured to receive at least compensation equal to the current CMPC. The incentive mechanism therefore does not introduce any additional risk for RTE.
The full amount of the premiums will be paid to RTE after the interconnection has been in service for a maximum of ten years, by means of a credit to the CPRC of RTE.
The calculation of the various premiums is described in the following sections.
4.2.2. Terms and conditions of calculation of incentives
a) Incentives for the realization of useful investments for the community.
The level of the fixed premium allocated to RTE will be determined taking into account the interest of the interconnection for the European electrical system, which will include quantifiable elements but which can also take into account qualitative elements such as security of supply.
The quantifiable component of the utility of interconnection for the system The electricity will be estimated by taking into account in particular:
-an estimate per year of additional trade flows not generated;
-a forecast of market prices in each of the two interconnected countries after the work is commissioned;
-an estimate of costs This
will be taken into account as an indication of the value created by the project for the community, a fraction of which will constitute the incentive granted to RTE.
Where relevant, the usefulness of the The interswitching structure may be evaluated by taking into account the boundaries between the France and several countries. These same borders will be used to calculate the variable premium for flows.
b) Incentives to make investments in the best cost conditions.
RTE will provide the ERC with its best estimate of costs Of the proposed interconnection project. Following the commissioning of the work, RTE will receive a premium, all the more important as the costs incurred will be low and even lower than they will be high. The cost premium will be expressed in terms of the difference between the estimated budget and the budget and will translate the change in the gain to the community caused by a change in the investment costs.
If RTE Would obtain a subsidy from the European Commission for the realisation of an interswitching investment, it would be taken into account in calculating the performance of RTE by deducting from the budget achieved.
(c) Inciting to the proper operation of the interconnection.
After the interconnection is made In service, the commercial streams brought by the interconnection will be compared to the flows announced by RTE before the investment decision for the year concerned. The premium attributed will be, in the same way as the cost allowance, a function of the variation in utility for the community caused by variation in cross-border flows. The bonus granted to RTE will be all the higher because the flows recorded will be higher than those predicted by RTE.
d) Incentives for the realization of the investments as soon as possible.
The cost of the capital of RTE is already covered by the Remuneration for BAR at the CMPC, financial incentives will be an economic benefit for RTE. Financial incentives will have more value for RTE if it succeeds in obtaining them early. Incitement to the making of investments as soon as possible is thus implicitly contained in the condition that the payment of the fixed premium and the premiums relating to costs and flows on the date of implementation of the Interconnect.
4.3. Research and development
This Decision introduces a device to give RTE the means to carry out the R&D and innovation projects needed to build the electricity networks of the future by guaranteeing In particular the lack of a tariff brake on R&D projects or innovative investments. It also puts in place a monitoring mechanism designed to give actors in the electricity sector greater visibility on the R&D projects carried out by RTE.
4.3.1. Tariff Treatment of R&D Expenditures
RTE reported, for the period from 2013 to 2016, the following R&D expenditure trajectory:
| R&D Expenditures | 23.7 | 25.6 | 28.6 | 30.7 | 108.6 |
4.3.2. Developing the visibility of the TEN R&D programme
The CRE introduces into the framework of TURPE 4 a monitoring of R&D projects. This monitoring will materialise through the transmission by RTE to the CRE, before the end of the first quarter of each calendar year, of a balance sheet for the previous year, including in particular the following:
-a description of projects with associated expenditures and results;
-a list of current and future projects with expected results;
-amounts spent over the past year;
-forecasts for Expenditure per year up to the end of the tariff period;
-the number of full-time equivalents associated with the R&D programs
In addition, the CRE will publish a report on the innovation and R&D policy conducted by RTE every two years. This report will complement the communication tools already put in place by the ERC, in particular in the field of intelligent electricity networks. It is intended to give players in the electricity sector visibility into the research and innovation policy conducted by RTE and financed by the TURPE. The first report will cover the years 2013 and 2014.
A description of the RTE R&D programs is provided in the appendix.
4.4. Power continuity
Article L. 341-3 of the Energy Code states that the CRE " May provide [...] appropriate incentives, both in the short term and in the long term, to encourage transmission and distribution system operators to improve their performance, in particular as regards the quality of Electricity [...] ".
To this end, the CRE is leading the way by strengthening the incentive mechanism for food continuity in the framework of TURPE 3.
The strengthening of incentives is based on:
-an extension of the scope of the incentives to the average cutoff frequency;
-an increase in the incentive limit.
The CRE decides to maintain a high requirement level in terms of the average cut-off duration in Redriving the 2.4 minute value adopted by the TURPE 3.
The parameters of the incentives on the average cut-off time and on the average cutoff frequency correspond to 50 % of the values used in network planning (these Last being 26 €/kWh and 3 €/kW respectively). These elements lead to an incentive over the average cut-off time of € 10.4 M€/minute (compared to 9.6 M€/minute in the previous rates) and an incentive on the average cutoff frequency of 72.0 €/cutoff.
The amount of the Ceiling of incentives is set at € 30 million, consistent with the parameters of the incentives.
Notwithstanding the provisions of this section, TENs may be required to send to the ERC other indicators of the quality of the public transport network, In particular as part of the TENs Activity Report. In addition, RTE can also transmit quality indicators for the public transport network to the stakeholders concerned, and in particular to users.
4.4.1. Incentive Schema Parameters
The average cutoff time and the average cutoff frequency are calculated on the perimeter of the consumer installations and the public distribution networks directly connected to the public network Transport.
The average cut-off time of year N (DMCN), expressed in minutes, is given by the following formula:
DMCN = Total END of the year N × 60
Total END of year N × 60
DMCN =
PMDA (excluding losses) of year N
END: Undistributed energy, expressed in MWh. Undistributed energy is determined out of incidents as a result of exceptional events (cf. Definition below). The calculation of undistributed power includes offload for causes related to the public transport network;
PMDA: average power routed, expressed in MW. The routed average power is obtained by dividing the value of the routed energy (excluding losses) in the year by 8,760 hours (or 8,784 hours if the year N is a leap year).
The average cut-off frequency of year N (FMCN), Expressed as a number of cuts, is given by the following formula:
FMCN = Number of installations as of December 31 of year N
Number of long and brief cuts in year N
FMCN =
Number of installations at 31 December of year N
Long-cut: Power outage of an installation for a duration of more than 3 minutes;
Clipping brief: power outage of an installation for a period of 1 second to 3 minutes.
The number of long cuts and Brief is determined out of incidents as a result of exceptional events (cf. Definition below).
The financial incentive level for year N is given by the following formula:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
IN: financial incentive of year N, expressed in M€, which can take negative values. The absolute value of the annual IN incentive is capped at 30 M€;
DMCréf: the average annual reference cut-off time, expressed in minutes. Its value is set at 2.4 minutes for the entire duration of the tariff period;
FMCréf: the annual average cut-off frequency, expressed as a number of denominations. Its value is set at 0.6 cutoff for the duration of the tariff period.
4.4.2. Power continuity tracking
Before the end of each calendar quarter, RTE passes the following information for the previous quarter to the CRE:
-undistributed power for all causes;
-undistributed non-event non-event energy;
-undistributed power when undistributed;
-undistributed power when undistributed for cause-related causes Public transport network;
-the number of long and brief cuts for all causes;
-the number of long and short breaks out of exceptional events;
-for each exceptional event: Any element to justify the exceptional nature of the event, the undistributed energy, the number of short and short cuts at the event and any element to assess the speed and relevance of the measures RTE to restore normal operating conditions
Before the end of the first quarter of each year, RTE forwards to the CRE the following information relating to the previous year:
-the average annual blackout time for all causes;
-the average annual non-event blackout time;
-the annual average break-out duration;
-the average annual outage Consecutive clipping for public transport network causes;
-the annual average cut-off frequency for all causes;
-the annual average frequency of non-event break-outs.
4.4.3. Exceptional events
In the framework of the incentive regulation of the continuity of food, are considered as exceptional events:
-the destruction caused by acts of war, riots, looting, sabotage, attacks, criminal attacks;
-damage caused by accidental and non-controllable incidents by third parties, such as fires, explosions, Falling of aircraft;
-natural disasters within the meaning of Act No. 82-600 of 13 July 1982 as amended;
-sudden, fortuitous and simultaneous unavailability of Several production facilities connected to the public network Transport, provided that the power unavailable is greater than the application of the safety rules referred to in Article 28 of the specification for the concession of the public electricity transmission network (annexed to Decree No. 2006-1731 of 23 December 2006);
-releases of works decided by the public authorities for reasons of public safety or police when this decision does not result from the behaviour or inaction of the manager of Public electricity grid;
-atmospheric phenomena of a magnitude Exceptional, with regard to their impact on the networks, characterised by an annual probability of occurrence of less than 5 % for the geographical area concerned as soon as, on a single day and for the same cause, at least 100 000 consumers Services supplied by the public transport network and/or public distribution networks are deprived of electricity.
4.5. Losses on networks
In order to contain the charges attributable to the coverage of losses on the public transport network, an incentive control mechanism for the cost of purchasing losses had been introduced in the framework of the TURPE 3. The Historic Nuclear Electricity Regulated Access Facility (ARENH) calls into question the relevance of this incentive mechanism to the extent that, as of 2014, the energy purchases made by RTE outside this regulated device will be strongly Limited. As a result, the CRE does not renew this device for the period of application of the TURPE 4.
During the period 2013-2016, the purchase of the energy required to compensate for the losses will account for nearly 15 % of the expenses to be covered by the present Rates. In order to minimise the operating costs of the public transport network, the CRE consulted the stakeholders on the appropriateness of introducing an incentive to control the volume of losses on the public transport network. The mechanism adopted under these tariffs provides for the monitoring of the actions undertaken by TENs in order to contain the rate of losses on the network it operates, without, however, submitting these actions to a financial incentive. Indeed, the exchanges with TENs show that the network manager's room for manoeuvre in controlling the rate of losses on the public transport network is relatively small. This observation is shared by the stakeholders who have spoken on this subject in the context of the public consultations of the CRE.
The mechanism adopted is based on the annual transmission by RTE to the CRE of the following indicators:
-monthly volume of operating loss savings in MWh;
-qualitative elements on the nature of the actions undertaken during the year to limit operating loss volumes;
-associated loss volumes Major investment projects in MWh;
-rate of loss on the public transport network.
E. TARIFF STRUCTURE AND RULES APPLICABLE TO
USERS OF HTB TENSION DOMAIN
Article L. 341-3 of the Energy Code provides that " The methodologies used to establish the tariffs for the use of public electricity transmission and distribution networks shall be fixed by the Energy Regulatory Commission ". It is supplemented by Article L. 341-2 of the same Code which provides that " The tariffs for the use of the public transport network and public distribution networks shall be calculated in a transparent and non-discriminatory manner, in order to cover all the costs incurred by the managers of these networks in the measure Where these costs correspond to those of an effective network manager." Finally, Article L. 341-4 states that: The structure and level of the rates for the use of transmission and distribution networks shall be fixed in order to encourage customers to limit their consumption to periods when the consumption of all consumers is the most
Within the framework of the legislative provisions cited above, the ERC conducted extensive work on the cost structure of network infrastructure and the cost of losses, which account for the majority of total costs to Be covered by the tariffs. The methodology used and the results of this work were presented to the stakeholders in the framework of the public consultations of the CRE on 6 March 2012 and 6 November 2012, the summaries of which are available on the website of the CRE.
The new pricing methodology takes into account the temporal differentiation of network costs according to the hours of the year and allocates these costs to the different users on the basis of their characteristics Consumption. Users who consume a lot during periods when the consumption of all users is the strongest, therefore, bear a significant share of network costs. They are therefore encouraged to move their consumption of the hours charged for the networks to the least charged hours for the networks, thereby minimising the charges associated with the use of public electricity networks.
This New tariff structure responds both to the principle of non-discrimination of the tariffs laid down in Article L. 341-2 of the Energy Code and to the will to control the demand for energy provided for in Article L. 341-4 of the same code
This new methodology for the construction of tariffs, the CRE introduces tariffs to Temporal differentiation for voltage domains HTB 2 and HTB 1. The CRE maintains a concave tariff for the HTB voltage domain 3.
Before detailing the methodology used to construct these rates, the CRE recalls the general principles underlying its structure decision. Rates.
1. General Principles
To base its tariff decision, the CRE is based on the following general principles.
1.1. Rates independent of distance
In accordance with Article 14, paragraph 1, of Regulation (EC) No 714/2009 of 13 July 2009, which provides, inter alia, that network access charges are not a function of Distance between a producer and a consumer involved in a transaction, the CRE maintains the principle of so-called "pricing". Postage stamp ", which consists of charging the support at the same price regardless of the origin of the electricity consumed and to charge the injections regardless of the destination of the electricity produced. Pricing " Postage stamp " Does not exclude the possibility of geographical differentiation of tariffs.
1.2. Identical rates across the territory
These rates are the same across the territory.
In the context of a strong increase in network investment needs, particularly in response to the Development of new means of production and in the context of European objectives in this field, the issue of the relevance of a location signal to producers has been raised. A location signal, which could take the form of a geographically differentiated injection rate, could improve coordination between investments in networks and in the means of production, and thus reduce Long-term network costs.
This topic was the subject of initial analysis, the results of which were presented to stakeholders in the framework of the public consultation of the CRE on 6 March 2012. The geographical differentiation of the injection tariff is only one tool among others to improve the coordination of production and transport investments. Other options are possible, such as the introduction of locational signals on the wholesale electricity market (nodal prices) or in terms of determining the cost of a connection. Each of these options has advantages and disadvantages that merit further consideration. This issue is also the subject of discussion at European level. In view of this context, the CRE considers it necessary, before considering the implementation of such a location signal for producers, to assess the effects of the tools already in place to improve this coordination (7) and To know the guidelines the European Commission could adopt on this issue of location signals, in accordance with the provisions of Article 18 of Regulation (EC) No 714/2009 of 13 July 2009.
The heterogeneity of the positions of the Actors who have spoken on these issues and policy directions By the Minister of Ecology, Sustainable Development and Energy by letter of 10 October 2012 further reinforced the idea that it was premature to commit to a geographical differentiation of the tariff Injection.
1.3. A breakdown of HTB network costs between
texts based on European texts
Thearticle 4 of Decree No. 2001-365 of 26 April 2001 specifies, on this point, that the " Tariffs shall take account of measures adopted within the framework of the European Union in order to harmonise the tariffs applicable to international energy trade and facilitate international trade in electrical energy." The European guidelines on injection tariffs and the clearing mechanism between transmission system operators for transits, as laid down in European Regulation No 838/2010 of 23 September 2010, set out the criteria to be met. From which the level of the injection tariff should be set. These criteria are met in these rates.
2. Pricing Methodology
The new pricing methodology is based on the following steps.
2.1. Rates based on hourly unit costs
These rates, whether or not they propose different time classes, are defined on the basis of hourly unit costs of use of the networks. The consideration of these hourly unit costs in the construction of tariffs is carried out in two steps described below.
2.2. Distribution of Costs on Different Hours of the Year
The same volume of sprinting does not generate the same network costs according to the time of the year in which the draw occurs. The examination of network costs shows that, during the hours during which transits are important on the networks, a surplus of recirculation generates incremental costs of loss and development of the larger infrastructure than During less busy time for networks.
Network costs are spread over the different hours of the year. For each voltage domain, unit network utilization costs are calculated for each hour of the year. These hourly unit costs are calculated as the sum of the hourly unit costs of infrastructure and the hourly unit costs of losses. The hourly unit costs of infrastructure are calculated from the average incremental cost induced by the growth of the load at each hour of the year. The hourly unit costs of losses are calculated from the profile of the spot price of electricity in the French market, adjusted for multi-year trends.
2.3. Allocation of hourly costs between users of the various
voltage domains pro rata to the network-induced energy flows
Based on the forecast flow matrix transmitted by RTE for the period 2013-2016, It is observed that the energy is injected mainly in very high voltage to be consumed in large part by users of the fields of downstream tension. Energy takes successively portions of networks at decreasing voltage levels. Consequently, users of downstream networks contribute, through the energy flows that they induce, to a large proportion of the costs incurred by RTE for the management of upstream networks. That is why tariff revenues collected from a user contribute to cover not only the costs of the voltage domain to which it is connected but also part of those of the upstream voltage domains.
The calculation of this Contribution of the support of an area of tension to the costs of the upstream tension domains is based on the forecast flow matrix and the distribution of accounting costs by voltage domain, also transmitted by RTE to the CRE.
The allocation of the costs of an area of tension on the fields of downstream tension being carried out Time, the temporal differentiation of network costs is well reflected to all users.
Once this allocation of hourly costs is achieved between users of different voltage domains, it is possible to For each voltage domain, deduct an overall cost envelope to be covered by all users of this voltage domain. This global envelope is then distributed among the users of this voltage domain according to the consumption characteristics of the latter.
2.4. Tariffs based on user consumption characteristics
All users in the same voltage domain do not consume the same way. User consumption characteristics are used to allocate the overall cost envelope assigned to the voltage domain to which they are connected. The costs that each type of user generates within the same voltage domain depend, in particular, on the rate of use of the subscribed power (which can be translated in terms of duration of use) and the temporal distribution The
of use of the subscribed power makes it possible to determine a variable share of the energy consumed and a fixed share of the subscribed power. While subscribed power is a determining variable for network costs, it alone is not sufficient to determine the costs incurred by a user on the networks. It is also important to know how this underwritten power is used: a consumer who uses the full amount of power subscribed to the most charged hours for networks generates more network costs than a
use of hourly network costs makes it possible to take into account, in the process of allocating network costs, the profile of the redrawing of different users. Thus, for the same annual volume of consumption, a user who consumes during the hours during which the network costs are high will contribute more to the recovery of the tariff charges than a user who consumes during the Hours during which the network costs are low.
For each voltage domain, the overall cost envelope is divided among the users connected to the voltage domain considered according to the level of their power Of the total volume of energy that they submit on the year and the The distribution of their subscribed power and the volume of energy drawn on the different hours of the year.
Time-differentiated rates are defined by dividing the costs between the different time classes. In particular, the share " Energy " Of each time class is defined so that it is proportional to the average unit cost of the relevant time class
2.5. Form of grids
The time classes of the rates offered to users of the HTB 2 and HTB 1 voltage domains are designed to maximize the homogeneity of the hourly unit costs within each class while maximizing The heterogeneity of hourly unit costs between classes. The objective of readability of the tariffs, which the actors put forward in their replies to the public consultations of 15 July 2010 and 6 March 2012, also requires limiting the number of time classes and allocating them in a manner
The users of the HTB 2 and HTB 1 voltage domains can choose between three fare options. Each of these tariff options consists of five time classes. The time classes of the rates applicable to the tension domains HTB 2 and HTB 1 are defined as follows:
| 9 a.m. to 11 a.m. and from 6 p.m. to 8 p.m. on January, February and December working days | From 7 a.m. to 9 a.m., from 11 a.m. to 6 p.m. and from 20 to 23 hours the working days of January, February and December; from 7 a.m. to 23 p.m. on November and March working days | From 23 hours to 0 hours and from 0 hours to 7 hours the working days from November to March; all day on non-working days from November to March | From 7 to 23 hours the working days of April to October | From 23 hours to 0 hours and 0 hours to 7 hours from April to October; all day non-working days from April to October |
3. Rules Applicable to Users of the HTB Voltage Domain
The rules contain thirteen sections. The first two define the concepts used and the structure of the tariffs. Sections 3 to 12 describe the tariff components. Section 13 specifies the transitional provisions applicable to the subscription of the power of users of the HTB network.
The rules laid down in the framework of TURPE 3 are essentially carried out. However, in view of the return of experience provided by the network operators and the contributions received during the public consultation of the CRE on 6 November 2012, certain provisions of the tariff rules are amended or supplemented. In addition, the introduction of time-differentiated rates for the tension domains HTB 2 and HTB 1 implies a substantial modification of section 6 of the rules which specifies the provisions governing the definition of components Annual support and monthly components of power exceedances subscribed to the HTB voltage domains.
3.1. Definitions
Definitions of terms " Bindings " And " User " Are completed to clarify the terms and conditions of these tariffs.
3.2. Fee Structure
Section 2 contains a description of the different categories of charges covered by these tariffs, the structure of the rates established to reflect these different categories of charges and the manner in which these types of charges are reflected. Apply the different rates at each connection point.
3.3. Management
The billing arrangements for the management component of TURPE 3 are renewed, namely the explicit invoicing of management fees in the form of a fixed term applied to all users (producers, consumers and network operators) based on their connection voltage domain.
In order to better reflect the costs incurred by the network manager, billing for the annual management component is carried out By connection point and access contract.
Contract management costs Consist of costs related to the hosting of network users, the management of user records, invoicing, recovery, and arrears.
3.4. Count
The metering component pricing for users of the HTB voltage domains depends on the meter ownership regime.
The count component covers, for the users who own their Metering device, costs:
-verification of the proper operation of counting equipment performed at the initiative of the network manager;
-succession or telemetry (including subscription and communication costs);
-measurement, calculation and Recording of count data;
-validation, correction, and provision of validated count data.
Count data is transmitted to the user, or to a third party authorized by the user, according to a Minimum frequency defined according to the domain of tension and the power of the sprinting that it has Subscribed and/or the maximum injection power of the connection point.
For users whose counting device is the property of the network manager or the licensors, the count component also covers Costs:
-capital charges for counting devices, net of the share of connection contributions for counting devices;
-maintenance of metering devices;
-for the renewal of equipment of Count;
-if any, synchronization of counting devices.
By contrast, this count component does not include the cost of changes to metering devices made at the request of the user or a third party Authorized by the user, which are the subject of specific invoicing within the framework of Tariff rules for ancillary benefits under the network manager's monopoly.
3.5. Injection
Since France is a net exporter of electrical energy, the net contribution of RTE to the European clearing mechanism between transport networks for transits is positive. French network users must not bear the burden of this contribution, the responsibility of which lies with the exporters.
The injection tariff is set at 19 €/MWh over the entire tariff period for producers This amount takes into account the contribution of TENs to the European mechanism for compensation between transport networks.
3.6. Stamping
The rules applicable to the calculation of the components used for the invoicing of the underrun and the underwritten overflows are adapted as a result of the introduction of time-differentiated rates for the Users of the HTB 2 and HTB 1 voltage domains 1.
The subscribed monthly power surge components (CMDPS) are calculated in such a way that a user exceeds 10 % of its subscribed power for one hundred hours of the same class Time pays the same invoice as if it had subscribed a higher power of 10 %. The extension of this calculation method maintains the same incentive for users to purchase optimal power.
3.7. Additional and backup feeds
For additional or backup links, only dedicated parts are invoiced. This billing method takes into account the fact that, having regard to the rules for the sizing of the network in " N-1 ", it is not possible to distinguish an additional cost associated with the provision of complementary or emergency capacity.
A power overrun factor for the uninterruptable power supply, where it is connected to a UPS. Voltage domain different from that of the main power supply, is introduced. This provision ensures that the incentive given to the user to subscribe to the optimum power also involves the choice of power purchased for its UPS.
3.8. Conventional cluster of connection points
The grouping mechanism in effect since January 1, 2006, is renewed for the period of application of TURPE 4.
3.9. Tariffs for Managers of Public Distribution Systems
Managers of public distribution networks have specific features that are defined by law and regulation. In order to take account of these specificities in the rates applicable to the various areas of tension, the following specific arrangements shall be maintained:
-the use of the transformation works is charged according to the direct average loads of the transform stations;
-the compensation for the operation of connections to the same voltage as the upstream public network is established at From the difference between the rates in the field of supply voltage and the area of tension immediately lower, reduced by the amount of the component of use of the works of transformation and weighted by the shares of those links Exploited by the different network managers;
-the Monthly oversupply invoices for distributors are allowed in the event of severe cold, under the same conditions as those provided for in the TURPE 2.
The definitions of terms l1 and l2, used for the calculation of Compensation for operating connections to the same voltage as the upstream public network, are clarified.
3.10. Point-of-use
To take into account certain situations in which network capabilities are capable of delivering demand for short periods of time without prejudice to other users, the device Billing of scheduled one-time exceedances (PPD) as defined in TURPE 3 is renewed. These exceedances, which must be agreed in advance with the network manager, are charged to the average price of energy by a user with a usage rate of 25 %.
The DPP's request is conditional on the completion of the Work on the applicant's electrical installations.
The PLR mechanism is transitive in order not to penalize public distribution system operators.
3.11. Reactive energy
The specific pricing applied to the reagent transits at the point of connection of the public transmission networks to the public transport network is renewed, in order to stabilise the volume of the park HTA capacitors and thus preserve the production capacity of reagent on public distribution networks.
A fixed scale of penalties for excursions outside a range of " Phi tangent " Contractually agreed between the parties with respect to rules recorded in the reference technical documentation of the public transport network manager.
In the absence of agreement between the parties, these tariff rules Specify the method of determining the upper bound of the range of " Tangent phi ". This method is based on the use of historical values and provides for the introduction of a floor value.
This floor value is justified in particular by the rapid development of decentralised production and the upward trend Natural of " Phi tangents " On public distribution networks and prevents excessive processing between connection points.
3.12. Rate Grid Indexing
The set of coefficients for the rate grid, with the exception of the assumed power weight factors, of the coefficient c of the valve component applicable to voltage domain HTB 3 And the injection component are indexed during annual rate changes.
3.13. Transitional Provisions
A learning period for power subscription is defined. The aim of this learning period is to allow, in the first months of application of TURPE 4, the invoicing of a catching-up term to limit the consequences of the loss of revenue caused by the introduction of the Time differentiation rates instead of concave rates.
This transitional provision allows users who have effectively modified their redrawing behaviour in response to the horosaisonalized signal to benefit from All of the induced tariff benefits.
Two dates of Regularisation is defined: on 31 December 2013 and 31 March 2014 (the last day of the winter period) in order to facilitate the accounting management of the device and to enable the users benefiting from a possible clause " Cold hardness " Record the corresponding rate reduction on the 2013 accounting year.
F. APPENDICES
1. RTE R&D Program
RTE plans to conduct, over the next tariff period, R&D projects structured according to four programs.
Program " Environment " Aims to meet societal expectations and is structured around the following axes: further research on the interaction between electromagnetic fields and health; research on biodiversity, particularly in the submarine field; study of tools And methods to reduce the environmental footprint of RTE activities and pursue academic work in the sociological field to improve the adherence of stakeholders to development or upgrading projects of the network. Projects in this program can be cited as:
-a demonstrator of " Sustainable development electric station " In the Somme to reduce the environmental footprint throughout the life of the work, which will be completed in 2014;
-a research project to increase knowledge of the threshold for the onset of physiological effects under Exposure of a magnetic field. The results of this project, expected in 2015, will make it possible to better control the exposure of workers, in particular during work operations under stress;
-a project to propose methods and tools for dialogue with the Stakeholders in the development of network projects, the results of which are expected in 2015
Asset management and maintenance " Aims to develop innovative tools and methods to optimize the technical policies for upgrading and renewing the network and to drive optimized maintenance for maximum network availability. Among the projects of this program can be cited:
-Smartlab: development of tools for simulating the phenomena of component aging and optimization of asset management scenarios;
-drone and robotics: this project Provide service operators with tools to facilitate the diagnosis by ensuring their safety. The first results for the diagnosis of the deterioration of the sleeves, the state of conductors with cut strand will be validated at the end of 2013. The next steps will extend the use spectrum of robots and drones.
The program " Electrical system " Intends to support the development of methods and tools to ensure the optimisation of an electrical system incorporating a greater share of intermittent renewable energies. Among the projects of this program can be cited:
-iTesla: an innovative approach to the analysis of network operation safety by an extended probabilistic approach. Risk analysis models and tools are planned for the end of 2014 and the final delivery of the toolbox at the end of 2015;
-models for forecasting intermittent production: the results for photovoltaics are expected in 2013, for Offshore wind power in 2015. Studies are also conducted on common modes in order to analyze the correlations between the photovoltaic energy, wind energy, and hydro-energy forecasting models to generate refined forecasts. The results of these studies are also expected in 2015. These tools are essential to contribute to the control of the balance between supply and demand;
-SmaRTE: this simulation platform enables the development of tools and methods to anticipate phenomena related to the insertion of Complex components in electrical grids, such as static reactive power compensators, long-distance cable links, or continuous/alternative current conversion stations. The development of new models in 2013 will allow to refine the integration studies of the continuous current link between France and Spain in the network.
The programme " Network of the future " Aims to anticipate and accelerate the development of innovative technologies prefigurating the network of tomorrow. Projects in this program can be cited as:
-Twenties: to lift certain technological locks to the development of a mesh continuous current network. In 2013, a prototype of a continuous-current circuit breaker laboratory will be tested;
-Smartpost: Smart grid project aimed, through the extensive integration of process scanning, to facilitate the integration of renewable energies on The network. This demonstrator is scheduled to be put into service in 2016.
In addition, RTE is an active participant in scientific societies and international standardization work, in particular in CIGRE, IEEE, CIS and CENELEC
Thematic Smart grid is carried by the programmes " Electrical system " And " Network of the future ". The annual monitoring will incorporate a summary of the progress made in the field of Smart grid resulting from the concatenation of different projects.
As a guide, RTE states that R&D expenditure by thematic area will be broken down as follows: (in current M€):
| Environment | 1.2 | 1.4 | 1.4 | 1.5 | 5.5 |
| Asset Management and Maintenance | 9.2 | 9.4 | 10.2 | 10 | 38.8 |
| Electrical System | 6.9 | 7.9 | 9.1 | 9.2 | 33.1 |
| Future Network | 5.8 | 6.3 | 7.3 | 9.3 | 28.7 |
| Standardization & learned societies | 0.6 | 0.6 | 0.6 | 0.7 | 2.5 |
| Total | 23.7 | 25.6 | 28.6 | 30.7 | 108.6 |
2.
Rate Grid Summary Management Component
| HTB | 7 884.80 | 7 884.80 |
Count
Count Devices property of the
Public Network Manager Electricity or licensors
| HTB | Weekly | Overflow | Measuring Curve | 2 726.22 |
Count Appliances Users
| HTB | Weekly | Overflow | Measuring Curve | 489.43 |
Injections Component
| HTB 3 | 19 |
| HTB 2 | 19 |
| HTB 1 | 0 |
Support Component
Rate for voltage domain HTB 3
| HTB 3 | 4.75 | 19.25 | 0,856 |
Rate for voltage domain HTB 2
Average
| a2 (€/kW/an) | 8,60 |
| Energy Weight Coefficient (c€/kWh) | 0.61 | 0.54 | 0.40 | 0.36 | 0.27 |
| Power Weight Coefficient | 100 % | 94 % | 68 % | 44 % | 19 % |
Long use
| a2 (€/kW/an) | 11.26 |
| Energy weighting factor (c€/kWh) | 0.50 | 0.44 | 0.32 | 0.29 | 0.20 |
| Power-weight coefficient | 100 % | 95 % | 69 % | 45 % | 19 % |
Very long use
| a2 (€/kW/an) | 14.42 |
| Energy Weight Coefficient (c€/kWh) | 0.43 | 0.37 | 0.27 | 0.24 | 0.17 |
| Weight Coefficient of Power | 100 % | 95 % | 69 % | 46 % | 20 % |
Tariff for the domain Tension HTB 1
Medium use
| a2 (€/kW/an) | 14.33 |
| Energy weight (c€/kWh) | 1.25 | Align="center"> 1.08 | 0.78 | 0.66 | 0.47 |
| Power-weight coefficient | 100 % | 94 % | 67 % | 41 % | 18 % |
Long
| a2 (€/kW/an) | 15,72 |
| Energy Weight Coefficient (c€/kWh) | 1.22 | 1.04 | 0.74 | 0.62 | 0.43 |
| Power Weight Coefficient | 100 % | 94 % | 67 % | 42 % | 18 % |
Very long use
Border="1">
| Energy weighting factor (c€/kWh) | 1.16 | 0.97 | 0.68 | 0.57 | 0.39 |
| Power-weight coefficient | 100 % | 94 % | 67 % | 43 % | 18 % |
TARIFFS FOR USE OF
ELECTRICITY NETWORK
IN HTB
1. Definitions
For the purposes of these rules, the terms listed below have the following meanings.
1.1. Reactive Power Absorption
The electrical energy transit that is reactivated by the connection point to serve the public electricity network user.
1.2. Feeds
When a user is connected to the public network by multiple feeds, it is appropriate to control the naming of its primary, complementary, and backup power supplies with the network manager Public to which it is connected.
1.2.1. Primary Power (s)
The primary power supply (s) of a user doi (ven) t be used to provide the user with the power of recirculation that he or she has subscribed to and/or the maximum power An agreed upon injection into the normal operating system of the user's electrical works. The normal operating system is contractually agreed between the user and the manager of the public network to which he is connected, in accordance with the quality commitments contained in the relevant access contract.
1.2.2. UPS
A power supply of a user is a UPS if it is powered on, but is not used for power transfer between the public network and installations of one or more Users only if all or part of its main and complementary power supplies are unavailable.
The dedicated portion of a UPS is the portion of the public network that is traversal only by flows that have Destination one or more connection point (s) of one or more The standby power (s) of this user or another user.
The streams taken into account to establish the dedicated portion of the emergency supplies are those that are established under the operating system in the event of an unavailability of all or Part of its other power supplies, of the electrical works of the user (s) agreed contractually with the manager of the public network to which he is connected, having regard to the topology of the public network and whatever the manoeuvres Operation to which its handler can operate.
1.2.3. Additional Power
Power supplies for a user that are not primary and uninterruptable power supplies are the additional feeds for this user.
The Dedicated Power Party Complementary to a user is the part of the public network that is traversal only by flows originating or for destination one or more connection points (s) of this user.
The flows taken into account to establish the dedicated part Complementary feeds are those that are established under the Normal operation of the electrical works of the user agreed contractually with the manager of the public network to which he is connected, taking into account the topology of the public network and whatever the operating manoeuvres To which the manager can perform.
1.3. Cell
A cell is a set of electrical apparatus installed in an electrical station and includes a primary cutoff apparatus (usually a circuit breaker), one or more sectioners, measurement reducers, and Protective devices.
1.4. Time class
For any utility rate for public electricity networks, the time class is called the set of hours of the year during which the same rate factor applies.
1.5. Network access contract
The contract for access to the network is the contract referred to in Articles L. 111-91 to L. 111-95 of the Energy Code which is intended to define the technical, legal and financial conditions of a user's access A public transport or distribution network for drawing and/or injection of electrical energy. It is concluded with the public network manager either by the user or by the provider on behalf of the user.
1.6. Measure curve
The measurement curve is the set of measured mean values of a measured quantity, over consecutive periods of integration and the same duration. The load curve is a measurement curve of the active power welded.
The integration periods are consecutive time intervals of the same duration during which the average values of a varying electric quantity are calculated. Over time. When these rules provide that sizes are calculated by period of integration, the value of these quantities is reduced during each integration period to their average value during this period.
1.7. Counting device
The counting device consists of all the active and/or reactive energy meters at the counting point considered, cabinets, boxes or related panels, and, where applicable, The following additional equipment dedicated to it: BT measuring reducers, tariff signal receivers, synchronization devices, metering data pricing apparatus, meter reporting communication interfaces, control devices for limiting meters Demand, test boxes.
1.8. Voltage Domain
The voltage domains of the public transport and distribution systems in ac power are defined in the following table:
| A ≤ 1 kV | BT | Low Voltage Domain | |
| 1 kV < A 40 kV | HTA 1 | Domain HTA | High voltage domain |
| 40 kV < A 50 kV | HTA 2 | | |
| 50 kV < One 130 kV | HTB 1 | HTB Domain | |
| 130 kV < One 350 kV | HTB 2 | | |
| 350 kV < One 500 kV | HTB 3 | | |
1.9. Reactive power supply
Transit of electrical energy reactivated by the connection point for the power supply of the public electricity network.
1.10. Index
Energy indexes represent the temporal integration of effective values of a power, independently for each quadrant, from a selected time origin.
1.11. Active Power Injection
Transit power that is active by the connection point for the power supply of the public electricity network.
1.12. Bar Set
Three-phase set of three metal rails or three conductors, each of which consists of a set of points, the same voltage, common to each phase of a three-phase system and which allow the connection of the Installations (instruments, lines, cables) between them. A bar set is not a binding (as defined below) within the meaning of these tariff rules.
1.13. Binding
A link consists of a circuit, a set of conductors and, where appropriate, a guard cable.
However, when a transformer and a set of bars are located within the same electrical station or in the The two power stations, the circuit connecting the transformer to the bar set, is not a binding within the meaning of these tariff rules, but is an integral part of the processing works.
1.14. Transformation Structures
The transformation works are the works of public electricity networks that are located at the interface between two different voltage domains.
1.15. Connection Points
The connection point (s) of a user to the public network coincides with the property boundary between the electrical works of the user and the electrical works in the public network and corresponds (ent) Usually at the end of an electrical work, materialized by a cut-off organ. A "cut-off" means an apparatus installed on an electrical network to interrupt a non-zero current that circulates between the two ends of this device.
For a user with multiple connection points to the Public network, for the purposes of these Rules, it is considered that all or part of these points are confused if, in the normal operating system of the electrical works of the user agreed contractually with the manager of the Public network, they are connected by electrical works of this user to the Connection voltage.
1.16. Active Power (P)
Active power P means, at any point in the power grid, the average energy flow in an established system.
1.17. Apparent Power (S)
Apparent power S represents the amplitude of the instantaneous power signal at any point in the power grid.
1.18. Reactive power (Q) and reactive energy
Reactive power Q is equal to the active power multiplied by the tg w.
Reactive energy refers to the integral of the reactive power Q over a specified period of time. Reactive energy is stored as an electromagnetic field in the electrical network environment, but is not consumed by its users.
1.19. Tangent ratio phi (tg w)
The tangent ratio phi (tg w) measures, at any point in the electrical network, the phase shift of the voltage and intensity signals. The tg w report is an important parameter in electrical network driving and security.
1.20. Active Power Paging
The electrical energy that is active by the connection point to serve the public electricity network user.
1.21. User
A user of a public transport or distribution network is any natural person or establishment of a legal person, in particular the manager of public networks, directly supplying the public network or Directly served by this network. Interconnect circuits are not considered users within the meaning of these rules.
2. Structure of utility rates for public networks
The following tariffs are expressed outside of all levies or taxes applicable to the use of public electricity networks, including, in particular, the tariff contribution referred to In I of Article 18 of Act No. 2004-803 of 9 August 2004 as amended relating to the public service of electricity and gas and to Electrical and gas companies.
In accordance with Article L. 341-2 of the Energy Code, which states that " Tariffs for the use of the public transport network and public distribution networks shall be calculated in a transparent and non-discriminatory manner, in order to cover all the costs incurred by the managers of such networks, provided that These costs correspond to those of an effective network manager ", and toarticle 2 of Decree No. 2001-365 of 26 April 2001 They include, inter alia:
-the costs associated with the creation of operating reserves that include the costs associated with the acquisition by public network managers of voltage-maintenance system services and the costs of establishing primary reserves And secondary frequency maintenance;
-costs relating to the operation of the balancing device for consumption and/or electricity production sites with a connection point to the public networks of Transportation and distribution;
-cost of counting, controlling, reporting, The validation and transmission of the counting data;
-the share of the costs of the ancillary benefits carried out under the monopoly of the managers of public networks not covered by the rates of these services;
-the share of the costs Extension of public electricity networks not covered by contributions paid to public network operators when they are masters of the work of connection.
By exception, certain benefits specifically Identified, carried out at the request of the user or his act, shall be the subject of a Separately invoicing, in particular under the conditions laid down by the tariff (s) relating to the ancillary benefits carried out under the monopoly of the managers of public electricity networks in force, for the part of their costs Not covered by the rates of use of the electricity networks defined in Sections 3 to 11 below. The same applies to the use of interconnections with the transport networks of neighbouring countries which is invoiced according to the results of market mechanisms established pursuant to Regulation (EC) No 714/2009 of 13 July 2009 on conditions Access to the network for cross-border exchanges of electricity.
The network access contract specifies the connection point (s) of the user to the relevant public network and the tariff applied to it. For each connection point, it also specifies the domain of tension of connection, the power of redrawing subscribed by the user, the counting device used. The undersigned power (s) shall be defined at the beginning of a period of twelve consecutive months for the whole of that period, subject to the transitional provisions laid down in Section 13. The network access contract provides for the conditions under which the power of the underwritten can be changed during this period.
At each connection point, the price paid annually for the use of a public network Electricity is the sum of:
-the annual (GC) component (s);
-the annual count (s) component (s);
-the annual injection component (CI);
-the annual support component (CS);
-the components Monthly underwritten power overflows (CMDPS);
-the annual component of complementary and backup power supplies (CACS);
-the conventional clustering component (CR) component;
-for Public network managers, the annual component of the use of Processing (CT), compensation for the operation of connections to the same voltage as the upstream public network and the cold clipping;
-the annual component of scheduled one-time overruns (CDPP);
-the annual component of the Reactive energy (REBs).
These components apply notwithstanding any contrary provision of the specifications, concession agreements and contracts, in particular those relating to the charging of operating, maintenance and
The energy to be taken into account to calculate The annual injection and redrawing components at each connection point is the energy corresponding to the physical flow at the point of connection concerned, measured by period of integration by the contractually agreed counting device.
3. Annual Management Component (GC)
The annual network access contract management component covers user case management costs, users' physical and telephone greeting, billing, and Recovery.
The annual management component of an access agreement entered into by an exclusive supplier is also applicable:
-to consumers who have not made use of the faculty provided for in article L. 331-1 of the Energy Code;
-to users who are entitled to a purchase price prior to Law n ° 2000-108 of 10 February 2000 as amended on the modernization and development of the electrical utility.
The annual management component a1 is established For each connection point of one or more main power supply (s) and for each access contract according to table 1 below :
Table 1
| HTB | 7 884.80 | 7 884.80 |
4. Annual counting component (CC)
The annual count component covers the costs of counting, controlling, reporting, transmitting metering data (these are transmitted to the user or to a third party authorized by the user). According to a minimum frequency defined in tables 2.1 and 2.2 below) and, where appropriate, of rental and maintenance.
It shall be established, in accordance with the technical characteristics of the metering devices and services requested by The user, according to the rates below. The quantities measured by the user's measuring and control apparatus shall allow the calculation of the annual components of the utility rate of public networks.
The annual counting component shall be established for each Counting device according to tables 2.1 and 2.2 below according to the property regime of the counting device.
4.1. Metering devices owned by the
Manager of the public electricity network or the licensors
The annual metering component invoiced to users whose counting device is the property of the manager The public electricity network or the granting authorities shall be defined in table 2.1 below, depending on the field of tension, the power of the draw underwritten and/or the maximum injection power, its control and the quantities Measured (index or measurement curve).
Table 2.1
| HTB | - | Weekly | Overflow | Measuring Curve | 2 726.22 |
4.2. User Ownership Counting Devices
The annual metering component invoiced to the users owning their counting device is defined in Table 2.2 below, depending on the voltage domain, of the Subscribed and/or maximum injection power, control, and measured quantities (index or measure curve).
Table 2.2
| HTB | - | Weekly | Overflow | Measuring Curve | 489.43 |
5. Annual Intake Component (CI)
The annual injections component is established at each connection point, based on the active energy injected on the public network, as shown in Table 3 below:
Table 3
| HTB 3 | 19 |
| HTB 2 | 19 |
| HTB 1 | 0 |
6. Annual components of the support (CS) and monthly components
of the subscribed power exceedances (CMDPS) for the HTB
6.1 voltage domains. Annual support component (CS)
6.1.1. Price for Voltage Domain HTB 3
Users choose, in multiples of 1 kW, a subscribed power PSoussin for each of their points of connection to the tension domain HTB 3. In each of these connection points, the annual component of the support is determined according to the following formula:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Usage rate is calculated From the active energy Subunit in kWh for the period of twelve consecutive months considered, of the power subscribed to in kW and the duration D in hours of the year under the following formula:
= D. PSouswriting
Esouted
=
D. PSouswritten
The coefficients a2, b, and c used are as shown in Table 4 below:
Table 4
| HTB 3 | 4.75 | 19.25 | 0,856 |
6.1.2. Rate for tension domain HTB 2
For each of their points of connection to the tension domain HTB 2, users choose for each of the n time classes that it contains, by multiples of 1 kW, a power subscribed Pi, where i is the time class. Regardless of i, the subscribed powers shall be such that Pi + 1 ≥ Pi.
In each of these connection points, the annual component of the support shall be determined according to the following formula:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Ei is the active energy In the time class, expressed in kWh.
Weighted PSouswriting is the weighted underwritten power calculated according to the following formula:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Tariff time classes HTB 2 is defined as follows:
-Winter includes months from November to March;
-summer includes months from April to October;
-peak hours are fixed, from December to February inclusive, between 9 a.m. and 11 a.m. and between 18 hours and 20 hours;
-hours Solid is fixed between 7 hours and 23 hours, competing with the peak hours previously defined;
-the other hours of the day are defined as off-peak hours;
-Sundays, Saturdays and public holidays are entirely in Off-peak hours
For the establishment of the annual component of their HTB 2 voltage domain, users choose one of the following three pricing options:
-average usage;
-long use;
-very long use.
The user retains the tariff option during a Minimum duration of twelve months from the date of entry into force of the tariff option, and from the date of each subsequent amendment, other than transitional provisions described in Section 13. At the end of this twelve-month period, the user can change at any rate option.
The coefficients a2, di and ki used for the tariff option " Average usage " Applicable to the tension domain HTB 2 are those of Tables 5.1 and 5.2 below:
Table 5.1
| a2 (€/kW/an) | 8.60 |
Table 5.2
| Energy Weight Coefficient (c€/kWh) | 0.61 | 0.54 | 0.40 | 0.36 | 0.27 |
| Power Weight Coefficient | 100 % | 94 % | 68 % | 44 % | 19 % |
Table 6.1
| a2 (€/kW/an) | 11.26 |
Table 6.2
| Energy Weight Coefficient (c€/kWh) | 0.50 | 0.44 | 0.32 | 0.29 | 0.20 |
| Power Weight Coefficient | 100 % | 95 % | 69 % | 45 % | 19 % |
Table 7.1
| a2 (€/kW/an) | 14.42 |
Table 7.2
| Energy Weight Coefficient (c€/kWh) | 0.43 | 0.37 | 0.27 | 0.24 | 0.17 |
| Power Weight Coefficient | 100 % | 95 % | 69 % | 46 % | 20 % |
6.1.3. Rate for voltage domain HTB 1
For each of their points of connection to the tension domains HTB 1, users choose for each of the n time classes that it contains, by multiples of 1 kW, a power subscribed Pi, where i is the time class. Regardless of i, the subscribed powers shall be such that Pi + 1 ≥ Pi.
In each of these connection points, the annual component of the support shall be determined according to the following formula:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Ei is the active energy In the time class, expressed in kWh.
Weighted PSouswriting is the weighted underwritten power calculated according to the following formula:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Tariff time classes HTB 1 is defined as follows:
-Winter includes months from November to March;
-summer includes months from April to October;
-peak hours are fixed, from December to February inclusive, between 9 a.m. and 11 a.m. and between 18 hours and 20 hours;
-hours Solid is fixed between 7 hours and 23 hours, competing with the peak hours previously defined;
-the other hours of the day are defined as off-peak hours;
-Sundays, Saturdays and public holidays are entirely in Off-peak hours
For the establishment of the annual component of their HTB 1 voltage domain, users choose one of the following three pricing options:
-average usage;
-long use;
-very long use.
The user retains the tariff option during a Minimum duration of twelve months from the date of entry into force of the tariff option, and from the date of each subsequent amendment, other than transitional provisions described in Section 13. At the end of this twelve-month period, the user can change at any rate option.
The coefficients a2, di and ki used for the tariff option " Average usage " Applicable to the tension domain HTB 1 are those of Tables 8.1 and 8.2 below:
Table 8.1
| a2 (€/kW/an) | 14.33 |
Table 8.2
| Energy Weight Coefficient (c€/kWh) | 1.25 | 1.08 | 0.78 | 0.66 | 0.47 |
| Power Weight Coefficient | 100 % | 94 % | 67 % | 41 % | 18 % |
Table 9.1
| a2 (€/kW/an) | 15,72 |
Table 9.2
| Energy Weight Coefficient (c€/kWh) | 1.22 | 1.04 | 0.74 | 0.62 | 0.43 |
| Power Weight Coefficient | 100 % | 94 % | 67 % | 42 % | 18 % |
Table 10.1
| a2 (€/kW/an) | 19.20 |
Table 10.2
| Energy Weight Coefficient (€/kWh) | 1.16 | 0.97 | 0.68 | 0.57 | 0.39 |
| Power-Weight Coefficient | 100 % | 94 % | 67 % | 43 % | 18 % |
6.2. Monthly Components of Subscribed Power Exceedances (CMDPS)
The components of the subscribed power overflows are established on a monthly basis as follows:
You can consult The table in
JOn ° 150 of 30/06/2013 text number 37
Power overflows against the subscribed power ΔP are calculated by Ten minute integration period. The applicable factor for users connected to the HTB 3 voltage domain is defined in table 11 below:
Table 11
| HTB 3 | 19.46 |
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Power overflows by Ratio to the subscribed power ΔP are calculated by ten-minute integration period. The applicable factor for users connected to the HTB 2 and HTB 1 voltage domains depends on the user's chosen rate. The applicable factors for users connected to the tension domains HTB 2 and HTB 1 are defined in table 12 below:
Table 12
| Average Use Rate | 35.84 | 60,42 |
| Long-use Tariff | 47.10 | 65.54 |
| Very long-use rate | 60,42 | 79.87 |
7. Annual Supplementary and Emergency Food Service Component (CACS)
Additional and standby power supplies established at the request of users are invoicing in accordance with the following terms and conditions. The annual component of complementary and emergency supplies (CACS) is equal to the sum of these components.
7.1. Additional feeds
The dedicated parts of a user's complementary feeds are invoiced for the electrical works that make up the user. This billing is based on the length of these dedicated parts according to the following scale:
Table 13
| HTB 3 | 94 206.98 | 8 927.23 |
| HTB 2 | 56 814.59 | Aerial links: 5 691.39 |
| | | Underground links: 28 455.94 |
| HTB 1 | 29 510.66 | Air Bindings: 3 377.15 |
| | | Underground links: 6,754.30 |
7.2. UPS
The dedicated parts of a user's uninterruptable power supplies are invoiced for the electrical works that make up the user. This invoicing is based on the length of these dedicated parts according to the scale of table 13 above. The power subscribed to the uninterruptable power supplies is less than or equal to the power subscribed to the main power supplies.
When a UPS is shared among multiple users, the parts invoicing Dedicated power supplies and traversed by flows for the connection points of multiple users is distributed among these users in proportion to the powers they have subscribed to on this power supply Backup.
When the UPS is in the same voltage domain as The main power supply and at the request of the user, it has been connected to a transformer of the public network different from the transformer used for its main power supply, the billing of the dedicated parts of the emergency supplies Is equal to the sum of the component resulting from the application of the scale of Table 13 above and the component established in accordance with the scale of Table 14 below, corresponding to the pricing of the transformation power reservation:
Table 14
| HTB 2 | 1.37 |
| HTB 1 | 2.62 |
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
Table 15
| HTB 3 | HTB 2 | 6.54 | 0.67 | 27.65 |
| | HTB 1 | 4.80 | 1.15 | 20.48 |
| HTB 2 | HTB 1 | 1.40 | 1.15 | 6.14 |
8. Aggregation Component (CR)
A user connected to a public network at multiple points of connection to the same public network in the same voltage domain HTB and equipped with meter-to-measure meters for each of these points may, If it so wishes, benefit from the conventional grouping of all or part of these points for the application of the fees described in Sections 5 and 6, subject to the payment of a grouping component. In this case, the annual component of injections (CI), the annual component of the support (CS), the monthly components of subscribed power exceedances (CMDPS), the annual component of programmed overruns (CDPP) and the Annual component of reactive energy (REBs) are based on the sum of the physical flows measured at the relevant connection points. The possibility of conventionally aggregating points of connection to the same public network is limited to the scope of the same concession or distribution control for public distribution network operators and to that of a public network. Same site for other users.
Reactive energy flow grouping of connection points is only possible in cases where these connection points meet the conditions mentioned in the reference technical documentation The Public Electricity System Manager.
The component of Regrouping (CR) is based on the length of the existing public electricity network that physically allows this grouping, irrespective of the operating conditions and the transit capacity available on the networks allowing the Grouping. The amount of this component shall be calculated according to the following formula, according to the consolidated PSousings, the power subscribed for all the points conventionally grouped and the smallest total length of the electrical works of the Concerned public network that physically allows the grouping.
CR = I. k.PSouswriting grouped
The k coefficient is defined by the following table 16:
Table 16
| HTB 3 | 5.12 |
| HTB 2 | Air Bindings: 13.31 |
| | Underground links: 51,20 |
| HTB 1 | Air links: 67.58 |
| | Underground links: 118.78 |
9. Specific provisions for the annual components of
distribution system managers (
)
9.1. Annual Manufacturing (CT) Utilization Component
A public distribution system operator that operates downstream of its point of connection one or more links, air or ground, to the same area of Voltage which the downstream tension of the transformer to which it is connected directly, without the intermediary of a link upstream of its connection point, may apply to benefit from the annual component of the support (CS) applicable to the domain of tension Directly above the one applicable to the connection point.
It must In this case pay an annual component of the use of the processing works, reflecting the cost of the transformers and the cells. This component is calculated according to the following formula, based on its subscribed strength.
CT = k.PSouswriting
The k employee coefficient is the one defined in Table 17 below:
Table 17
| HTB 2 | HTB 3 | 1.60 |
| HTB 1 or HTA 2 | HTB 2 | 3.44 |
| HTA 1 | HTB 1 | 6.09 |
9.2. Compensation for operation of links to the same voltage as the upstream public network
A public distribution network manager that operates downstream of its point of connection of the links to the same voltage domain as the links Upstream of this connection point benefits from this compensation when the pricing that is applied at the point of connection considered is that of the domain of tension of this point.
In this case, the annual component of the support (CS) Of this connection point is calculated using the following formula, with:
I11, the total length of the link (s) operated on voltage domain N by the distribution public network manager;
I2, the total length of the link (s) operated on voltage domain N by the manager of the Public network to which it is connected which is (are) strictly necessary to connect its connection point to the processor (s) of that necessary manager (s) to guarantee the power subscribed to the normal operating schema defined in the Reference technical documentation from the upstream public network manager;
CTN/N + 1 is the annual component of the transformation works between the N + 1 and N voltage domains defined in section 9.1.
CS = I1 + I2 CSN + I1 + I2 (CSN + 1 + CTN/N + 1)
I2
I1
CS =
CSN +
(CSN + 1 + CTN/N + 1)
I1 + I2
I1 + I2
9.3. Cold hardness
Managers of public distribution networks can benefit from the upstream public network manager to which they are connected by a stubbornness of their power overruns in the event of a cold. Very rigorous. This provision is implemented in a transparent and non-discriminatory manner.
10. Annual Scheduled Exceeding (CDPP) Component
For one-time overruns scheduled for work during the period from May 1 to October 31 and notified to the Public Network Manager, a user Where a connection point, not exclusively fed or served by a backup power supply (s), is equipped with a meter with a measurement curve and connected to HTB, may request the application of a specific scale for the calculation of its component Of oversubscribed power relative to this connection point.
In this case, during the period during which this schedule is applied, power overruns in relation to the subscribed power are the subject of the following invoicing, which replaces the billing of power exceedances As defined in Section 6.2. Power overflows with the subscribed power ΔP are calculated by ten-minute integration period.
For the HTB 3 voltage domain, the formula is as follows:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
For voltage domains HTB 2 And HTB 1, the formula is the following with ki the coefficient of power subscribed to the time class and the corresponding tariff option:
You can view the table in
JOn ° 150 of 30/06/2013 text number 37
The applicable factor is set In Table 18 below:
Table 18
| HTB 3 | 0.079 |
| HTB 2 | 0,156 |
| HTB 1 | 0,247 |
11. Annual reactive energy component (REL)
In the absence of counting devices to record the physical flow of reactive energy, public network managers can provide in their technical documentation
provisions of Sections 11.1 and 11.2 shall not apply to connection points located at the interface between two public electricity networks.
11.1. Subdrawing Flow
When the physical flow of active energy at a connection point is a draw flow, public network managers provide the reactive energy free of charge:
-to the tg wmax ratio set in Table 19 below, from November 1 to March 31, from 6 a.m. to 10 p.m. Monday to Saturday;
-by exception, for connection points where the user opted for a rate with Time differentiation, up to the tg wmax ratio defined in Table 19 below, during peak hours and peak winter hours;
-without limitation outside of these periods.
During periods submitted to Limiting, the reactive energy absorbed in tension domains HTB beyond the tg wmax ratio Is charged according to Table 19 below:
Table 19
| HTB 3 | 0.4 | 1.33 |
| HTB 2 | 0.4 | 1.42 |
| HTB 1 | 0.4 | 1.59 |
11.2. Injection Flow
When the physical flow of active energy at a connection point is injection flow, the installation is regulated in tension and the user does not benefit from a contract as provided for in item L. 321-11 of the energy code, the latter undertakes to maintain the tension at the point of connection of its installation in a range determined by the manager of the public network and fixed according to the rules published in the reference technical documentation From the public network manager to which it is connected.
On a tour of the Voltage outside of its contrupdated range, the user is charged according to table 20 below of the difference between the reactive energy that his installation actually provided or absorbed and that which he should have provided or absorbed for Maintain the tension in the contractual range of its operating agreement, within the limits of its constructive capabilities defined by the diagrams [U, Q] of its connection agreement. These elements are based on the rules published in the public distribution network manager reference technical documentation.
Table 20
| HTB 3 | 1.33 |
| HTB 2 | 1.42 |
| HTB 1 | 1.59 |
11.3. Specific provisions for the annual component of the reactive energy
between two public electricity network managers
At each connection point they share, public network managers commit themselves Contractually on the amount of reactive energy that they exchange, fixed according to the active energy transited, according to the rules published in the reference technical documentation of the public network manager or, in his absence from among the Contractors, injector manager.
Reactive energy Provided beyond the tg wmax ratio or absorbed below the tg min report is billed per connection point as shown in table 21 below.
Table 21
| HTB 3 | 1.33 |
| HTB 2 | 1.42 |
| HTB 1 | 1.59 |
12. Rate Grid Indexing
Let M the month anniversary of the effective date of these rates.
Each year N starting in 2014, the level of the components defined in Tables 1 to 2.2 and 4 to 21 above Shall be mechanically adjusted on the 1st day of the month M, with the exception of the power-weight coefficients of the redrawing components and of the coefficient c of Table 4.
The rate grid in effect from the 1st day of month M of year N Is obtained by adjusting the tariff schedule in effect the previous month of the evolution of The non-tobacco consumer price index and a clearance factor for the load and product control account (CRCP).
12.1. Evolution Rule
For the HTB voltage domain, the rate grid is mechanically adjusted by the following percentage:
ZN = IPCN + KN
ZN: percentage change, rounded to the nearest tenth of a percent, Of the tariff schedule in effect from the 1st day of month M of year N in relation to that in effect the previous month.
IPCN: Percentage change between the average value of the monthly non-smoking price index for the calendar year N-1 and the average value of the same index for the calendar year N-2, as published by INSEE (identifying: 000641194).
KN: the CRCP clearance factor for the year N calculated on the basis of the CRCP balance as at December 31 of year N-1 and of the previous transfers. The absolute value of the KN coefficient is capped at 2 %.
12.2. Rounding rules
When adjusting the rate schedules, the rounding rules are:
-the fixed parts coefficients of the annual components of the support, and the annual components of management and Count are rounded to the nearest euro cent;
-the other coefficients subjected to adjustment are rounded to the nearest hundredth of the unit in which they are expressed.
13. Transitional provisions applicable to tariffs for areas of tension HTB 1 and HTB 2
From the date of entry into force of these tariffs until the amendment of the contracts for access to the public electricity network, the arrangements for Modification of the subscribed power provided for in these contracts shall apply to the subscribed power of each time class independently of each other.
During a learning period, which extends from the effective date Of these tariffs until March 31, 2014, the rules relating to Underwriting power and the choice of the tariff option are those described in sections 13.1 and 13.2 below.
13.1. Fixing the Rate Option and the Subscribed Powers
At the beginning of the learning period, the user chooses a rate option.
During the learning period, each month, the user sets the power
In the absence of user-subscribed power, the assumed power of a time class is set by default as the higher of the following two values:
-the value of the subscribed power of this time class the previous month;
-the average of the 3 powers 10 minutes maximum reached on three different days of the month during this time class.
In all cases, The subscribed powers shall respect the order of the agreed powers referred to in sections 6.1.2 and 6.1.3.
At the end of the calendar year of entry into force of these tariffs, the user chooses a set of powers And a tariff option that will be deemed valid on the first day of The learning period. The different tariff components for the period from the first day of the apprenticeship to the last day of the calendar year are recalculated using this set of subscribed powers and this tariff option.
At the end of The learning period, the user chooses a new set of subscribed powers and a rate option that will be deemed valid on the first day of the learning period. The different tariff components for the entire apprenticeship period are recalculated using this new set of subscribed powers and this tariff option.
13.2. Application of the Cold Willing Clause
If a very severe cold spell occurs during the period from the first day of the learning period to the last day of the calendar year of entry into force of the These tariffs, the stubbornness of the corresponding power exceedances shall be calculated only at the end of the calendar year.
If a very severe cold period occurs during the period from the first day of the calendar year following the entry into Strength of these rates until the last day of the apprenticeship period, The stubbornness of the corresponding power exceedances shall be calculated only at the end of the learning period.
Pursuant to Article L. 341-3 of the Energy Code, this deliberation shall be published in the Official Journal of the Republic French.
Done at Paris, April 3, 2013.
For the Energy Regulatory Commission:
The President,
P. Of Ladoucette
