Article 3.1.k) of Law 54/1997 of 27 November of the Electrical Sector establishes, among the powers that correspond to the General Administration of the State, to approve by means of Resolution of the Secretary General of Energy (currently Secretary of State of Energy) the market rules and procedures of operation of an instrumental and technical character necessary for the economic and technical management of the system.

For its part, the Royal Decree 2019/1997 of 26 December, for which the electricity production market is organized and regulated, establishes, in Article 31, that the system operator and the National Energy Commission may propose, for approval by the Ministry of Tourism and Trade, the technical and instrumental operating procedures necessary to carry out the appropriate technical management of the system, which will resolve the National Energy Commission.

The additional provision of Royal Decree 485/2009 of 3 April 2009, which regulates the implementation of the supply of last resort in the electricity sector, provides that the proposals for procedures for the technical and instrumental operations referred to in the preceding paragraph shall be accompanied by the report of the representatives of all the system subjects defined in Article 9 of Law 54/1997 of 27 November of the Sector Electrical.

Royal Decree 1623/2011, of 14 November, regulates the effects of the entry into operation of the link between the peninsular electrical system and the balar, and modifies other provisions of the electrical sector.

In the Additional Disposition Second Adaptation of the operating procedures and the rules of operation of the daily and intraday market for the production of electrical energy to integrate in the regulation the link between the Peninsular electric system and the electric system Balearic of the cited Royal Decree 1623/2011, of November 14, it is established that " within one month from the entry into force of this royal decree, the operator of the system will transmit to the Ministry Proposal for the amendment of the operating procedures for industry, tourism and trade of the peninsular electrical system and SEIE [...] the contents of which need to be modified to collect the effects of the entry into service of the link between the peninsular electrical system and the Balearic electrical system. '

On the other hand, Royal Decree 661/2007, of 25 May, which regulates the activity of the production of electrical energy under special regime, regulated certain technical aspects to contribute to the growth of these technologies, safeguarding the safety of the electrical system and ensuring its quality of supply, as well as to minimize the restrictions on production of this generation, which had not yet been introduced into the Operation Procedures of the Island and Extrapenisland Electrical Systems.

Royal Decree 1565/2010 of 19 November 2010 regulating and amending certain aspects relating to the activity of the production of electrical energy under special arrangements lays down a number of technical requirements additional to ensure the functioning of the system and to enable the growth of electric energy production technologies from renewable energy sources.

Royal Decree 1614/2010 of 7 December 2010 regulating and amending certain aspects relating to the production of electrical energy from solar and thermoelectric solar technologies established the guidelines on the restriction of the production of electrical energy from wind technology installations for the purposes of system security.

The Resolution of the General Directorate of Energy Policy and Mines of June 1, 2011, establishes the standard protocol to be used by the agents for their communication with the control centers of the system operator for the peninsular system.

On the other hand, the Resolution of 1 December 2011, of the Secretariat of State of Energy, approves the procedure of operation of the system 4.0 "Management of International Connections", which affects the information to exchange between the agents.

The operating procedures cited in the case develop the modifications to the electrical regulations cited above.

View Law 54/1997 of 27 November of the Electrical Sector and of Article 31 of Royal Decree 2019/1997 of 26 December on the organisation and regulation of the electricity production market.

View the proposal made by the System Operator of the operating procedures of the System P.O. -3.1 programming of the generation, P.O. -3.2 resolution of technical restrictions, P.O. -9 information exchanged by the System operator, P.O. -14.4 payment entitlements and payment obligations for system adjustment services and Operation Procedures of the Island and Extraceninsular Electrical Systems (SEIE): P.O. SEIE-1 operation of the Systems Electric Island and Extraceninsular, P.O. SEIE-2.2 demand coverage, Programming of the generation and high in the economic office, P.O. SEIE-3.1 programming of the generation in real time, P.O. SEIE-7.1 complementary service of primary regulation, P.O. SEIE-7.2 complementary service of secondary regulation, P.O. SEIE-8.2 operating criteria, P.O. SEIE-9 information to be exchanged with the system operator and new P.O. SEIE-2.3 programming of the exchange of energy for the electrical links connecting the Island and Extrapeninsular Electric Systems with the Peninsular Electrical System, after consideration of the comments of the representatives of all the system subjects.

This Secretary of State, prior to the report of the National Energy Commission, resolves:

First.

Approve the operating procedures of the System P.O. -3.1 generation programming, P.O. -3.2 resolution of technical restrictions, P.O. -9 information exchanged by the system operator, P.O. -14.4 collection rights and payment obligations for system adjustment services and procedures for the operation of the Island and Extraceninsular Electrical Systems (SEIE): P.O. SEIE-1 operation of the Island Electrical and Extractive Systems, P.O. SEIE-2.2 demand coverage, generation programming, and high office economic, P.O. SEIE-3.1 programming of the generation in real time, P.O. SEIE-7.1 complementary service of primary regulation, P.O. SEIE-7.2 complementary service of secondary regulation, P.O. SEIE-8.2 operating criteria, P.O. SEIE-9 information to be exchanged with the system operator and new P.O. SEIE-2.3 programming of the power exchange by the electrical link between the Balearic Electrical System and the Peninsular Electrical System, which are inserted below.

Second.

With regard to the operation of the Island and Extraceninsular Electrical Systems, the N-2 criterion will be evaluated in the electrical link that connects the Balear Electrical System with the Peninsular Electrical System, a the time to consider the security criteria for contingencies established in the P.O. P.O. SEIE-1 operation of the Island and Extraceninsular Electrical Systems, for a period of 3 months.

Third.

As of the date on which this resolution takes effect, the procedures for operating the IP System are without effect. -3.1 generation programming, P.O. -3.2 technical restrictions resolution, P.O. -9 information exchanged by the system operator and P.O. -14.4 payment entitlements and payment obligations for the system adjustment services, approved by the Resolution of 27 October 2010, by the Secretariat of State for Energy, by which the procedures for the operation of the system P.O. 3.10, P.O. 14.5, P.O. 3.1, P.O. 3.2, P.O. 9 and P.O. 14.4 for its adaptation to the new electrical regulations and the procedures for the operation of the Island and Extraceninsular Electrical Systems (SEIE): P.O. SEIE-1 operation of the Electrical and Island Systems and Extraceninsular, P.O. SEIE-2.2 demand coverage, programming of generation and high in economic dispatch, P.O. SEIE-3.1 programming of the generation in real time, P.O. SEIE-7.1 complementary service of primary regulation, P.O. SEIE-7.2 complementary service of secondary regulation, P.O. SEIE-8.2 operating criteria and P.O. SEIE-9 information to Exchange with the system operator approved by Resolution of 28 April 2006, of the General Secretariat of Energy, approving a set of procedures of a technical and instrumental nature necessary to carry out the appropriate technical management of island and extra-island electrical systems.

Fourth.

This resolution shall take effect on the day following that of its publication in the "Official State Gazette".

Madrid, July 24, 2012. -Secretary of State for Energy, Fernando Martí Scharfhausen.

INDEX

P. O. -3.1 Generation programming.

P. O. -3.2 Resolution of technical constraints.

P. O. -9 Information exchanged by the system operator.

P. O. -14.4 Collection rights and payment obligations for the system adjustment services.

P. O. SEIE-1 Operation of island and extra-island electrical systems.

P. O. SEIE-2.2 Demand coverage, generation programming and high in economic dispatch.

P. O. SEIE-2.3 Programming of the power exchange by the electrical link between the Balearic electrical system and the peninsular electrical system.

P. O. SEIE-3.1 Real-time generation programming.

P. O. SEIE-7.1 Supplementary primary regulation service.

P. O. SEIE-7.2 Supplementary secondary regulation service.

P. O. SEIE-8.2 Operation Criteria.

P. O. SEIE-9 Information to be exchanged with the system operator.

P. O. -3.1 Generation programming

1. Object

The purpose of this procedure is to establish the process of daily programming of the generation from the nominations of programs derived from the execution of bilateral contracts with physical delivery and the offers for the sale and purchase of energy in the daily and intraday market, so as to ensure the coverage of the demand and the security of the system.

The applicable criteria for the definition of the programming units (PU) used in the programming process of the generation and located in the Spanish electricity system are also incorporated in this procedure.

The programming includes the following successive processes:

a) The daily operating base program (PDBF).

b) The Interim Viable Daily Program (PDVP).

c) The secondary throttling reserve allocation.

d) Final schedules after successive intraday market sessions (PHF).

e) The application, if any, of the deviation management process.

f) The operational schedules set in each hour to the end of the programming horizon (P48).

g) The close program (P48REDRE).

2. Scope of application

This procedure applies to the following subjects:

a) System Operator (OS).

b) Market Subjects (SM).

In the content of this operating procedure, unless expressly stated to the contrary, all references to the subject holders of the programming units shall be understood as also applicable to the representatives of the subject holders of programming units.

3. Energy programmes, schedules, programming periods and non-working days

Power programs will correspond to MWh values with a maximum of one decimal number.

All schedules and scheduling periods (semi-open temporary intervals defined by their start time and end time) established in this operating procedure are referred to the European Central Time or CET (Central European Time) or CEST (Central European Summer Time).

For the purposes of the programming process established in this operating procedure, it will be business days: Saturdays, Sundays, holidays in the square of Madrid, 24 December and 31 December.

4. Definitions

4.1 Daily Operating Base Program (PDBF): It is the daily energy program, with breakdown by programming periods, of the different programming units corresponding to sales and energy acquisitions in the Spanish peninsular electrical system. This program is established by the OS from the program resulting from the appeal of the daily market communicated by the OM, and the information of execution of bilateral contracts with physical delivery communicated according to the established in the This operation procedure.

4.2 Provisional Viable Daily Programme (PDVP): It is the daily programme of programming units for energy sales and acquisitions in the Spanish peninsular electricity system, with a breakdown for periods of programming, incorporating the modifications made to the PDBF for the resolution of the restrictions on security of supply and the technical restrictions identified in application of the safety criteria and the modifications required for post-demand rebalancing.

4.3 Secondary Regulatory Reserve Allocation: Secondary Regulatory Reserve Bid Allocation Process performed by the OS on D-1 day to ensure availability on day D of the regulatory reserve secondary to up and down, required for system security reasons.

4.4 Final Schedule Program (PHF): It is the programming established by the OS after each of the successive sessions of the intraday market of programming units corresponding to sales and energy acquisitions in the Spanish peninsular electricity system, as a result of the aggregation of all firm transactions formalised for each programming period as a result of the daily viable programme and the appeal of offers on the intraday market once resolved, where appropriate, the technical restrictions identified and carried out rear rebalance.

4.5 Operating hours (P48): The operational programme of programming units corresponding to sales and energy acquisitions in the Spanish peninsular electricity system that the OS establishes in each period of programming to the end of the daily programming horizon. The operating schedule will incorporate all the program assignments and redispatches applied by the OS until publication, 15 minutes before the start of each hour.

4.6 Restriction by security of supply: A restriction by guarantee of supply to the production that is determined as necessary of those thermal units of production of electrical energy that use sources for the combustion of indigenous primary energy to ensure the security of supply up to the maximum limit laid down in Article 25 of Law 54/1997 of 27 November 1997 and take account of any safety programme limitations which, in accordance with the provisions of the operating procedures, they may be required.

For the resolution of these restrictions the mechanisms described in the operating procedures by which the resolution of the supply guarantee restrictions are established shall apply.

4.7 Technical Restriction: It is any circumstance or incident arising from the situation of the production-transport system that, by affecting the conditions of safety, quality and reliability of the established supply (a) Regulation (EC) No No 2014

the European Parliament and of the Council of the European Parliament and of the Council of the European Parliament and of the Council

In particular restrictions may be identified due to:

(a) Failure to comply with security conditions under permanent and/or contingency arrangements, as defined in the operating procedure establishing the operational and security criteria for the operation of the electrical system.

b) Insufficient secondary and/or tertiary regulation reserve.

c) Insufficient additional power reserve to ensure coverage of the expected demand.

d) Insufficient capacity reserve for voltage control in the Transport Network.

e) Insufficient capacity reservation for service replenishment.

For the resolution of these restrictions the mechanisms described in the operating procedures by which the resolution of the technical restrictions and the management of the services of adjustment of the system.

4.8 Consumption-consumption: These are the deviations caused by the differences between actual production and expected generation, variations in the demand for the system and/or forced modifications of the production programs. as to the existence of significant differences between the expected demand in the Spanish peninsular electricity system and the demand programmed after the results of the different sessions of the intra-day market.

For the resolution of these generation-consumption deviations, the mechanisms described in the operating procedures for the management of the frequency-power regulation services will be applied, and also, when this is applicable, the generation-consumption diversion management mechanism, which is also established in the operating procedures.

4.9 Closing programme (P48RENER): This is the programme which is established at the end of the daily programming horizon and which contains the programmes resulting from the daily operational programme and the different sessions of the In this context, the Commission will be in a position to take into account the changes in the programmes associated with the process of technical restrictions and the participation of the various units in the system and in the system. Generation-consumption deviation management process.

4.10 Nomination of programmes for the implementation of bilateral contracts with physical delivery: The nomination of programmes corresponding to the implementation of bilateral contracts with physical delivery consists of the communication by the Programming Unit of such bilateral contracts to the System Operator in the form and time limits referred to in this operating procedure.

The nominations of the energy programs corresponding to the execution of bilateral contracts with physical delivery will be made by the seller and the buyer, directly or indirectly, to the Operator of the System:

Direct Nomination: Each of the SM that is part of the bilateral contract with physical delivery nominates to the OS the program of energy of the programming units of which it is the holder (or to which it represents), and with which it wishes execute such bilateral.

Indirect Nomination: One of the SM that is part of the bilateral contract with physical delivery is responsible, prior to the corresponding authorization of the SM acting as a counterpart, to make the nomination of the energy program of each and every programming unit with which both SM plans to implement such a bilateral contract. The SM responsible for making the nomination will be called the Nominator Subject. The authorization of the Nominator, to be effective, must be communicated to the OS. The OS will inform the Nominee Subject of the date from which your authorization to nominate is effective. Once a Nominator has been authorised for a bilateral contract with physical delivery, the latter may only be the subject of indirect nomination. In the case of international bilateral contracts outside the scope of the Iberian Market, the indirect nomination may be made only by the incumbent SM (or the representative) of the UP located on the Spanish side of the corresponding interconnection.

5. Pre-day programming of operation

5.1 Integration of energy from primary energy emission auctions (SEP), when the exercise of the options is by physical delivery.

5.1.1 Establishment of bilateral contracts for the nomination of the exercise of the options awarded in the auction of primary energy emissions: Monthly, not less than three working days in advance for the first day of each month, the entity with aggregator function in the primary energy emission auctions (EASEP) shall communicate through the indirect nomination system to the OS:

The relationship of the SM holders of primary emission purchase options, arising from the award in such auctions and the possible bilateral transfers of such options, using for this identification the corresponding Energy Identification Code (EIC) codes.

The maximum power value associated with each buyer SM partner-SM seller, and the validity period of this information.

In this case, for the purposes of the indirect nomination of energy programs, the Entity Aggregator of the Primary Emission Auctions (EASEP) is considered to be part of the bilateral contracts with physical delivery (CBEP) in accordance with the arrangements established between this entity and the SM authorised to participate in the Primary Emission Auctions.

Once the above mentioned information of the entity with aggregator function in the primary energy emission auctions (EASEP) has been received, the OS will automatically generate the corresponding information system bilateral contracts with physical delivery associated with the holding of energy purchase options (CBEP), between each of the SM vendors and those SM holders of such energy purchase options, for the execution of the nomination process programs after the exercise of these primary energy purchase options.

The generated CBEPs will have a maximum power value equal to the maximum value communicated by the EASEP to the OS for each buyer-seller pair and will be valid during the period communicated by the EASEP and may be extended, or, to be modified in its maximum power by the successive communications of the EASEP, remaining unchanged the number of performance of the contract.

These CBEPs will use Generic Programming Units (UPG), both for the seller SM and for the buyer SM, units that will have been previously released, for such purposes, in the information system of the System. The discharge of these UPG shall be requested by the OS by the SM in accordance with the provisions established in this respect in the operating procedures, and shall be communicated to the OM through the means and deadlines established.

The OS will validate that the information received from EASEP refers to SM that has the corresponding UPG for the period of validity indicated in the communication. Otherwise, the communication sent by the EASEP will be rejected.

The OS, once released these CBEPs in your information system, will make available to each SM the information corresponding to these bilateral contracts, with respect to the established confidentiality criteria.

In case the EASEP communicates to the OS the early cancellation of a CBEP contract with an SM, the EASEP will no longer send to the OS, as of the date the cancellation is effective, the nomination of the affected CBEP.

In case the OS, as indicated in the operating procedures, suspends the participation in the market of an SM, it will apply what is established in the corresponding operating procedure with respect to the suspension of the SM on the market, in addition, this suspension, to the Market Operator and, where appropriate, to the entities empowered for the nomination of bilateral contracts. During the period of suspension, the daily nomination of bilateral contracts which were in force in force shall be prevented. When the suspension of the SM is complete, this will be again communicated by the OS to the aforementioned entities.

5.1.2 Nomination of bilateral CBEP contracts associated with the exercise of the energy purchase options of the primary emission auctions: The nomination to the OS of bilateral CBEP contracts associated with the exercise of the energy purchase options after the primary energy auctions shall be made by the EASEP, under the principle of indirect nomination, before 8:45 h of day D-1, in accordance with the arrangements established between EASEP, the SM sellers and the SM buyers forholders of energy purchase options arising from their direct award in the auctions of primary energy emissions, or the subsequent bilateral transfer of such options.

The OS will verify that CBEPs associated with the exercise of primary energy purchase options are nominated for each programming period for a value not exceeding the maximum power of the corresponding CBEP in that period. Otherwise, the nomination of this bilateral contract will be considered invalid and will be rejected. Following this verification, the OS will make available to the SM sellers and buyers the result of the valid nominations of the CBEP, made by the EASEP and corresponding to the exercise of the options for the purchase of energy by the subject holders of those options.

5.2 explicit daily sub-staff of the exchange capacity in the France-Spain interconnection and Interchanges of information prior to the MD concerning the programming of exchanges in such interconnection: Two working days before the day of supply, before 16:00 h, the OS will notify the subjects of the authorizations for the programming, relating to the physical rights of annual and monthly capacity.

The differences between the authorisations for the programming and the physical rights of capacity previously allocated will be the possible capacity reductions due to the identification of a congestion situation in the interconnection.

D-1 day, prior to the closing of the MD, and following the schedules fixed in the operating procedure establishing the resolution of congestions in the France-Spain interconnection and in the Joint Rules of Capacity allocation in the France-Spain interconnection, a series of successive processes will be carried out, in the sequence indicated below:

Before 7:45 h of day D-1, the OS will receive from the subjects the notifications of use of the physical rights of annual and monthly capacity that have been authorized.

The lack of notification of the use of authorised capacity by a market subject within the prescribed time limits shall be construed as an automatic resale in the daily auction of physical capacity rights. corresponding.

The operators of the French and Spanish electrical systems will then exchange information regarding the notifications of use received. On the basis of the results of such exchanges of information concerning the use of the authorised annual and monthly physical capacity, the two OS shall jointly establish the total value of physical capacity assigned and the use of which has been reported on both electrical systems.

The communication by the SM of the execution of one or more bilateral contracts between the Energy Sales Programming Unit for import (or the Unit) will be considered to be a notification of the use of physical capacity. Power purchase programming for export) and Generic Programming Units or Physical Programming Units.

Once the notifications of use of the assigned capabilities are exchanged on an annual and monthly basis, the non-notified usage rights will be automatically resold in the corresponding daily auction. In that same process, the two OS will apply the principle of overlapping firm transactions against management, thereby maximizing the use of the exchange capacity.

Before 08:15 h of day D-1, the OS will make available to the OM the information of the physical rights of capacity allocated in annual and monthly horizons and whose use has been reported in both electrical systems.

Once the above process has been carried out, the operators of both electrical systems will jointly publish the information corresponding to the capacity values that will be offered, in one and another sense of flow, in the Daily explicit auction.

Finally, the operators of both electrical systems will proceed to execute the explicit daily auction, then communicating the results of the same, and the corresponding authorizations for the programming, to all and each of the subjects that have resulted in the capacity to be awarded.

After the daily explicit auction, the OS will make available to the OM the exchange capacity value assigned as a result of the daily explicit auction for each subject in each direction of flow, to the object that it is information is taken into account for the acceptance of offers to the daily market.

5.3 Program Transfer of the Generic Programming Units in the PDBF: The net balance of all transactions associated with the Generic Programming Units of an SM in the PDBF must be null.

In order to cancel the balance of the program transactions of the generic programming units in the PDBF the SM vendors will be able to establish, with respect of the obligations established in the current regulations, the The following types of transactions:

Bilateral contracts with physical delivery between a Generic Programming Unit and one or more Physical Programming Units of the same holder or other subject subject to which a bilateral agreement has been established.

Purchase or power selling transactions established by participating in the daily production market for Generic Offering Units associated with these Generic Programming Units.

Bilateral contracts with physical delivery between Generic Programming Units.

In order to transfer the energy program of the Generic Programming Units through bilateral contracts, the SM will have to be discharged and in effect the bilateral contracts that are necessary, both between two generic programming units, such as between each Generic Programming Unit and the corresponding Physical Programming Units. These bilateral contracts for the transfer of program from the generic programming units to the physical programming units may be national and/or international and must be nominated by the SM according to the rules and deadlines of nomination established in this operating procedure.

5.4 Publication of prior information to the MD: At a time of not less than one hour from the closing of the period of submission of offers to the daily market, the OS will make available to all Market Subjects (SM) and of the Market Operator (OM), as indicated in the operating procedure establishing the exchange of information with the OS, the information concerning the forecast demand, the network situation foreseen for the day next, and for those borders where there is no coordinated capacity management mechanism the provision of exchange capacity on international interconnections (NTC).

At the borders for which there is a coordinated capacity management mechanism, the capacity information made available to the OM and the reporting deadlines for this information will be those indicated in the the procedures for dealing with the resolution of congestion at those borders.

In addition, the system operator will make available to each of the market subjects daily, possible updates of its weekly operating plan, published in accordance with the procedure laid down in the procedure. (a) the operation by which the process for the resolution of supply security restrictions is established, which must be considered as a reason for the development of the forecasts of demand and/or deliveries of production of renewable origin; and/or for over-sold inavailabilities of production facilities and/or elements of the network transport.

5.5 Daily Operating Base Program (PDBF): The OS sets the daily operating base program (PDBF) from:

The valid nominations of the programs corresponding to the execution of bilateral contracts with physical delivery made both before and after the daily market, in accordance with the provisions of this procedure operation.

The information received from the Market Operator concerning energy programmes resulting from the appeal of the tenders submitted to the daily production market.

5.5.1 Nominations of bilateral contracts with physical delivery before the daily market.

5.5.1.1 Primary energy emissions contracts, in the event that they are carried out by physical delivery: Not less than 20:30 hours in advance of D-2, in case the exercise of the options corresponding to the primary emission auctions shall be carried out by physical delivery of energy:

The EASEP will make the first submission to REE of the information needed for the nomination of CBEP programs for day D.

Before 8:45 hours of day D-1, or exceptionally before 8:55 hours, the OS will receive the nomination for:

Bilateral contracts with physical delivery (CBEP) for the exercise of primary energy purchase options. The nomination of programs of these bilateral CBEP type contracts established between the generic programming units (UPG) of the corresponding sellers and buyers, will be realized, under the principle of indirect nomination, by EASEP.

Before 08:50 hours of day D-1, or exceptionally before 9:00 hours, the OS will make available to the SM:

The information corresponding to the nominations of bilateral contracts with physical delivery of type CBEP, with respect to the criteria of confidentiality established in each case.

In the event of any anomaly in relation to the nomination of CBEPs, market subjects will have a deadline of 9:20 p.m. D-1 to be disclosed to EASEP.

In the event of nomination anomalies, EASEP may submit new nominations for bilateral CBEP-type contracts to the OS. The deadline for receipt in the OS of nominations for bilateral CBEP contracts is 9:30 hours of day D-1.

The OS will make available to market subjects the information corresponding to the nominations of bilateral contracts with CBEP-type physical delivery that have been received from the EASEP once the validation has been carried out. corresponding.

5.5.1.2 International contracts: Before 7:45 hours of day D-1:

The OS will receive from the subjects the notifications of use of the physical rights of capacity allocated as a result of the explicit annual and/or monthly auctions in the France-Spain interconnection carried out jointly by the operators of both electrical systems. To this end, the SM shall communicate the execution of bilateral contracts between Physical or Generic Programming Units and the Programming Unit for the purchase or international sale of its authorized entitlement to the SM in the interconnection France-Spain.

Before 9:35 hours of day D-1, the OS will receive the nomination for:

International bilateral contracts outside the scope of the MIBEL with physical delivery in interconnections where there is no coordinated capacity allocation procedure.

International bilateral contracts with physical delivery communicated prior to the daily market in use of the physical rights of capacity allocated in the daily auction in the France-Spain interconnection. The SM may communicate these international bilateral contracts through the use of physical programming units (PUs) or UPG-type Generic Programming Units.

The notifications of use of the physical rights of capacity allocated as a result of the explicit auctions in the Portugal-Spain interconnection carried out jointly by the operators of both electrical systems, once that these auctions have become operational.

These notifications will be made exclusively to the Spanish Electrical System Operator. To this end, the subjects will communicate to the Spanish electrical system operator the execution of bilateral contracts between a Generic Programming Unit located in the Spanish electricity system and a Generic Programming Unit located in the Portuguese electrical system. The Spanish Electrical System Operator will make this information available to the Portuguese Electrical System Operator.

5.5.1.3 National contracts: National bilateral contracts with physical delivery that have chosen the pre-market pre-market nomination option, which may be formalised between two UP, two UPG, or between a combination of both types of Programming Units.

5.5.2 Communication to the OM of the information concerning the bilateral contracts nominated before the daily market: Before 09:45 hours, the Portuguese OS, on behalf of both OS, will make available to the OM the following information on the nomination of bilateral contracts with physical delivery:

Bilateral contracts with physical delivery in the Portugal-Spain interconnection arising from the use of the physical capacity rights acquired in the explicit coordinated auctions between the two OS, once these auctions have taken place running.

Also, before 09:45 hours, the OS will make available to the OM the information regarding the nomination of bilateral contracts with physical delivery nominated to the OS prior to the daily market.

In the event that you notice that an incident has occurred, the OS, in coordination with the OM, will be able to perform the appropriate actions and, if necessary, new shipments of this information by altering the one already sent. In the event of this situation, the OM and the OS will take their best efforts to ensure that the sequence of operations takes place as soon as possible.

5.5.3 Communication to the OS of the outcome of the appeal by the OM: Before 11:00 hours of each day, the OS will receive from the OM the information regarding the result of the appeal of offers in the daily market of production corresponding to the supply units of the Spanish electricity system, with the energy programmes contracted on the daily market, including, where appropriate, the energy programmes resulting from the integration into the market of the contracts established on the market with the physical delivery of the energy, the order of merit of the offers of sale and the energy acquisition resulting from the appeal of tenders at that session of the daily market, and all the tenders submitted to that session.

The OS will also receive from the OM the information regarding the marginal price of the daily market corresponding to the Portuguese and Spanish electrical systems for each programming period.

5.5.4 Reception of nominations after the MD: Before 11:00 hours, or before 30 minutes after the publication of the information corresponding to the results of the procurement in the daily market corresponding to the supply units of the Spanish peninsular electrical system, on those occasions when the system is carried out after 10:30 hours, the OS will receive:

Nominations of programs associated with bilateral contracts:

Bilateral contracts with national physical delivery that have not chosen the pre-market firm nomination option. These bilateral contracts may be concluded between two PUs, two UPG, or any combination thereof. This group will include, among others, bilateral contracts with national physical delivery between marketing companies.

Amendments to national bilateral contracts that have chosen the pre-market pre-market nomination option, provided that this modification involves an increase in the firm energy programme previously communicated and not modify the UP and/or UPG with which the bilateral contract has been previously nominated.

Nominations of the programs contracted in the daily market by offer units (UOs) that have two or more programming units (UP):

A managed energy program on the daily production market for each of the programming units (UP) that make up that offering unit (UO).

Program Nominations associated with supply warranty restrictions:

Nominations of the production schedules per unit of programming of the thermal power plants included in the updated operation plan by solution of supply guarantee restrictions having two or more more programming units.

5.5.5 Communication of UP breakdowns and maximum hydraulic powers per UGH: Before 11:00 hours of day D-1, or before 30 minutes after the publication of the information for the the results of the procurement in the daily market:

The holders (or their representatives) shall provide the OS with the information corresponding to the program disaggregations of the programming units per physical unit and, if applicable, by units of equivalent production according to the program breakdown criteria that the OS has set specifically for that programming unit.

The holders of hydraulic management units (UGH) shall provide the OS with the information corresponding to the maximum total hydraulic powers per hydraulic management unit (UGH) which, in case they are For system security reasons, they can be supplied and maintained by each UGH for a maximum of 4 and 12 hours.

5.5.6 Elaboration and publication of the PDBF programme: The OS will verify the coherence of the nominations of programmes carried out, directly or indirectly, by the market participants and the information concerning the programmes contracted energy in the daily market, received from the OM.

In the event that as a result of the aggregation of the hiring in the daily market and the bilateral procurement, a marketing programming unit, will result with a vendor program, will proceed from the next:

1. The bilateral contracts between the market participants in which the marketing programming unit is involved shall be ordered in order to increase the volume of daily energy.

2. Bilateral contracts shall be withdrawn in the order indicated until the programme of the marketing unit is null or void at all times.

Also, if as a result of this verification any disparity was detected, among the nominations sent by the subject holders of the programming units or between them and the result of the appeal facilitated by The OM shall proceed, depending on the case, as follows:

Programming units with energy program associated with the execution of bilateral contracts: the minimum value of the programs resulting from the communications made by the different identified subjects will be considered as counterparties in that contract.

Programming units with energy program associated with the procurement in the daily production market that are part of other programming units of the same unit of supply: in those cases where the OS does not received the nomination of programs from the integrated programming units in the same offering unit, or having received such nomination, the total nominated value was different from the program of the corresponding offer unit Statement by the OM, will proceed as follows:

1. The programming units shall be ordered in descending order, taking into account their maximum power value.

2. In accordance with the order of paragraph 1 above, the programming units, the programme values up to a value at the limit equal to the hourly energy corresponding to the maximum power of each programming unit shall be allocated to the programming units, assign the program total of the associated offering unit.

3. If once the programmes have been allocated to all the programming units, in accordance with point 2 above, the programme of the unit of supply has not yet been allocated in its entirety, the difference which will be allocated to the programming unit with the largest maximum power value.

Before 12:00 hours of each day, or before 1 hour after the communication to the OS of the information of the results of the procurement in the daily market corresponding to the supply units of the system Spanish peninsular electric, on those occasions when it is performed after 11:00 hours, the OS will make available to all market subjects, and of the OM, the daily operating base program (PDBF) of the programming of the Spanish electricity system for the next day's programming.

From the making available of the daily operating base program (PDBF), the SM will have a maximum period of 30 minutes to make possible claims to the OS due to incidents and anomalies that could be These complaints are dealt with by the procedures laid down for this purpose. In exceptional cases, delays in the publication of the PDBF, or other circumstances as may be necessary, the OS may reduce the length of the period of receipt of possible claims to the PDBF programme, up to a minimum of 15 minutes, previously reporting this reduction of time through the Web of eSIOS Subjects.

In cases where the existence of an incident is verified, and it can be corrected without affecting the programming process of the generation, the OS, in coordination with the OM, will carry out the appropriate actions for its resolution and, where appropriate, will proceed with the publication of a new version of the PDBF, keeping the SM of these actions informed at all times, through the website of the eSIOS Subjects. In the event of this situation, the OM and the OS will take their best efforts to ensure that the sequence of operations takes place as soon as possible.

5.6 Information receipt after PBF: Before 30 minutes since the publication of the PDBF, the SM must communicate to the OS the energy sales program established in the PDBF necessary for the consumption of gas. (a) Steel of those units of ordinary scheme, not included in Annex II to Royal Decree 134/2010 of 12 February 2010, and which they use as part of the fuel for the generation of steel gas.

5.7 Interim Viable Daily Program (PDVP): Once the PDBF is published, the OS will consider open the bid receipt period for the technical constraint resolution process. This period of receipt of tenders shall be kept open for 30 minutes.

Taking into account the program limitations that may be required for the safety of the electrical system, the OS will first proceed to make the necessary program modifications to include, the thermal generation with the programming units corresponding to the autochthonous coal plants in accordance with the weekly operating plan for supply guarantee restrictions, in their case up to date.

Next, the OS, taking into account the best forecasts of demand and production of wind origin in the Spanish peninsular electrical system and the expected availability of the network facilities and the production, will apply a security analysis on the daily operating base program (PDBF) to detect possible technical constraints and their possible solutions, selecting those that, resolving the restriction with a margin of adequate security, imply lower cost to the system. The OS will do so to make the modifications of the program that are precise for the resolution of the detected restrictions, and will also establish the limitations of program for safety that are necessary to avoid the appearance of new technical restrictions on subsequent processes and markets, in accordance with the procedure laid down in the operating procedure for establishing the process of resolution of technical restrictions.

In this same process, the OS will introduce the required modifications in the PDBF that have been requested by the distribution network managers in those cases where they identify and communicate in a reliable manner to the OS the existence of technical restrictions on the network which is the subject of its management, in accordance with the procedure laid down in the operating procedure for the resolution of technical restrictions.

Following the resolution of the supply guarantee restrictions and the subsequent resolution of the identified technical restrictions, the OS will proceed to apply a reduction of the programmed values to compensate for that energy. incorporated for the resolution of the restrictions by guarantee of supply which has not already been directly compensated by the modifications of the programme for the solution of technical restrictions the net balance of which represents a reduction of the PDBF respecting the limitations of the programme established for safety reasons, by means of the mechanism established in the procedure for the resolution of supply-guarantee restrictions.

Finally, the OS will proceed, if necessary, to make the necessary additional program modifications to obtain a balanced program in generation and demand for the remaining volume, in accordance with the procedure for the resolution of technical restrictions, while respecting the programme limitations established for safety reasons.

The resulting PDVP program will maintain the existing energy flow between the Spanish and Portuguese systems as a result of the daily market's appeal process.

The program PDVP of the programming units located in the Spanish peninsular electrical system resulting from this process will be published by the OS no later than 14:00 hours, or, before they have elapsed 2 hours from the publication of the PDBF, where the publication of the PDBF is carried out after 12:00 hours, in accordance with the procedure laid down in the procedure for the exchange of information with the OS.

From the making available of the provisional Viable Daily Program (PDVP), the SM will have a maximum period of 30 minutes to make possible claims to the OS due to incidents and anomalies that could be imputable. to the latter, dealing with these complaints in accordance with the procedures laid down for this purpose. In exceptional cases, delays in the publication of the PDVP, or other circumstances as necessary, the OS may reduce the length of the period of receipt of potential claims to the PDVP programme, up to a minimum of 15 minutes, previously reporting this reduction of the deadline via the eSIOS Subject Web.

In cases where the existence of an incident is verified, and it can be corrected without affecting the programming process of the generation, the OS, in coordination with the OM, will carry out the appropriate actions for its resolution and, if necessary, will proceed with the publication of a new version of the PDVP, keeping the SM and the OM of these actions informed at all times, through the website of the eSIOS Subjects. In the event of this situation, the OM and the OS will take their best efforts to ensure that the sequence of operations takes place as soon as possible.

5.8 Intraday explicit auctions of the exchange capacity in the France-Spain interconnection.

5.8.1 First Intraday Auction of Capacity: Once the PDVP is published, the operators of the French and Spanish electrical systems will exchange, among other things, the information concerning the exchange programs international interconnection between France and Spain, which have been nominated by market participants using the physical rights of capacity allocated in the explicit daily auction jointly implemented by the operators of both electrical systems.

After the exchange of information with the operator of the French electrical system the OS will make available to the OM the capacity effectively nominated in the French and Spanish electric systems to the object that it is information is taken into account in the process of accepting bids in the first-to-fifth sessions, including the intraday market.

On the basis of the results of these programme nominations information exchanges, the two OS will jointly establish the exchange programmes foreseen in the interconnection between France and Spain.

Once these exchange programs are established, the OS will apply the "used or lost" rule to the capabilities assigned on a daily basis and have not been nominated. In that same process, the two OS will apply the overlap of existing firm programs against management, thus maximizing the utilization of the exchange capacity.

Once the above process has been carried out, the operators of both electrical systems will jointly publish the information corresponding to the unused capacity values that will be offered in one and another sense of flow in the first explicit intra-day auction.

Once the explicit intra-day auction is performed, the operators of both electrical systems will proceed to the communication of the results of the same to each and every subject that has been awarded the capacity in the same.

The OS will make available to the SM the total value of the authorizations for programming after such an explicit intra-day auction, indicating the authorized exchange capacity for each subject in each direction of flow.

The OS will make available to the OM the authorizations for the programming established after such an explicit intra-day auction, indicating the total authorized exchange capacity for each subject in each direction of flow, to the the purpose of this information to be taken into account in the process of accepting bids in the first-to-fifth sessions, including the intra-day market.

5.8.2 Second Intraday Auction of Capacity: Once the PHF for the fifth session of the Spanish production market is published, the operators of the French and Spanish electric systems will exchange, the information relating to the international exchange programmes in the interconnection between France and Spain, which have been nominated within the time limits set by the market participants using the physical rights of capacity allocated in the first explicit intra-day auction held jointly by the operators of both electrical systems.

On the basis of the results of these programme nominations information exchanges, the two OS will jointly establish the exchange programmes foreseen in the interconnection between France and Spain.

Once these exchange programs are established, the OS will apply the "used or lost" rule to the capabilities assigned in the intraday horizon and have not been nominated. In that same process, the two OS will apply the overlap of existing firm programs against management, thus maximizing the utilization of the exchange capacity.

Once the above process has been carried out, the operators of both electrical systems will jointly publish the information corresponding to the unused capacity values that will be offered in one and another sense of flow in the second explicit intra-day auction.

Once this second explicit intraday auction is performed, the operators of both electrical systems will proceed to the communication of the results of the same to each and every one of the subjects that have been awarded capacity in the same.

The OS will make available to the SM the total value of the authorizations for the programming as a result of this second explicit intra-day auction, indicating the authorized exchange capacity for each subject in each flow sense.

The OS will make available to the OM the authorizations for the programming established after this second explicit intra-day auction, indicating the total capacity of the authorized exchange to each subject in each direction of flow, to the the purpose of this information to be taken into account in the tender acceptance process for the first four hours of the first session and the sixth session of the intraday market.

5.9 Secondary Regulatory Reserve Requirements: Each day, the OS will set the secondary regulatory reserve requirements for each of the next day's programming periods, as set forth in the the operating procedure for which the reserve for frequency-power regulation is established.

These secondary regulatory reserve requirements required for each programming period of the following day shall be published by the OS before 14:00 hours of day D-1.

5.10 Secondary Regulatory Reserve Allocation: Once the secondary regulation reserve requirements have been published, the OS will open the process of receiving bids for the provision of the secondary regulation service, the process to be closed at 15:30 hours, except for another indication of the OS which will be communicated in advance to all the MS holders of regulatory zones qualified for the provision of this service.

With the secondary regulation reserve offers received, the OS will allocate the provision of the secondary regulation service with minimum cost criteria, following the process described in the operating procedure whereby the provision of the secondary regulatory service is established.

No later than 16:00 hours of day D-1, the OS will publish, in accordance with the procedures set out in the operating procedure establishing the exchange of information with the OS, the allocation of reserve of regulation secondary for each and every programming period of the next day.

From the making available of the secondary reserve allocation, the SM shall have a maximum period of 30 minutes to make possible claims to the OS for incidents and anomalies that may be attributable to the OS, These complaints are dealt with by the procedures laid down for this purpose. In exceptional cases, delays in the publication of the secondary reserve allocation, or other circumstances as necessary, the OS may reduce the length of the period of receipt of possible claims to the allocation. of secondary reserve, up to a minimum of 15 minutes, and previously reporting this reduction of the deadline via the eSIOS Subject Web.

In those cases where the existence of an imputable anomaly to the OS is verified, and the OS can be corrected without affecting the programming process of the generation in an important way, the OS will perform the appropriate actions. for its resolution and will proceed with the publication of a new version of the secondary reserve allocation, keeping the SM of these actions informed at all times, through the website of the eSIOS Subjects.

5.11 Tertiary Regulatory Reserve Requirements: Each day, the OS will establish the tertiary regulatory reserve requirements for each of the next day's programming periods, as set out in the operation procedure whereby the reserve is established for frequency-power regulation.

These tertiary regulatory reserve requirements required for each programming period of the following day shall be published before 21:00 hours of day D-1.

5.12 Tertiary Regulation Offers: Before 23:00 hours of day D-1, the SM will have to present offers of all the tertiary regulation reserve that have available both to increase and to decrease for the entire horizon of the next day's programming, in accordance with the procedure laid down in the operating procedure laying down the conditions for the provision of the tertiary regulatory service. These offers must be continuously updated by the SM whenever modifications are made in the programming or availability of their production units, the offer of the entire reserve of tertiary regulation being obligatory. available on each drive.

6. Intraday (MI) Market

In the schedule set out in Annex I, the OS shall make available to the OM the information relating to the total exchange capacity allocated for each subject in each direction of flow, established after the explicit auction capacity intraday in the France-Spain interconnection applicable to that IM session, in order to ensure that such information is taken into account in the process of acceptance of offers to that IM session.

Programming units affected by bilateral contracts with physical delivery will be able to make program adjustments through the presentation of sales and energy acquisition offerings in the various IM sessions.

According to the schedules set out in Annex I of this procedure, the OS will receive from the OM the information regarding the result of the appeal of offers in the intra-day market of production corresponding to units of the supply of the Spanish electricity system with the energy programmes contracted on the intraday market, the order of merit of the offers of sale and the purchase of energy resulting from the appeal of tenders in that session of the intraday market; and all tenders submitted to that session.

In addition, the OS will receive from the OM the information regarding the marginal price of each of the sessions of the intra-day market corresponding to the Portuguese and Spanish electrical systems for each programming period.

After the communication by the OM of the program resulting from the appeal of offers, for the units of offer located to the Spanish peninsular electrical system, of each of the sessions of the IM, the OS will receive from the subjects holders, the same information provided by them for the preparation of the PDBF:

Program nominations per programming unit (UP), in cases where two or more programming units are integrated into a single offering unit (UO). The nominated programming unit programmes shall respect, where appropriate, the constraints established by security.

In the event that the offering unit has multiple programming units, either the program nomination of the programming units that compose it is not received, or the program nominations are available these programming units, the total nominated value is different from the associated offer unit program communicated by the OM for the corresponding IM session, will proceed as follows, distinguishing between these two possible cases:

A) The offering unit sells energy in the IM:

1. The programming units shall be ordered in descending order, taking into account their maximum power value.

2. In compliance with the order of paragraph 1 above, the programming units, the programme values up to a value at the limit equal to the hourly energy corresponding to the maximum power or the maximum power limit set shall be allocated to the programming units. their case, by system security for each programming unit and thus allocate the total of the associated offering unit program.

3. If once the programmes have been allocated to all the programming units, as referred to in point 2 above, the programme of the unit of supply has not been allocated in full, the difference which will be allocated to the programming unit with a higher maximum power value.

B) The offer unit buyback energy in the IM:

1. The programming units shall be ordered in descending order on the basis of their programmed energy value.

2. In compliance with the order of point 1, the energy of the programming units shall be reduced to a value equal to zero or equal to that of the minimum power limit set, where applicable, by system security or to the allocation of the total of the the program of the associated offer unit married in the corresponding IM session.

Program breakdowns by physical units or, if applicable, by equivalent production units.

The OS, taking into account all the above information, will perform a security analysis to identify any technical restrictions and, if necessary, resolve them by selecting the withdrawal of this process. The Court of First Instance is of the view that the Court of First Instance does not have the right to provide the Commission with a view to the decision of the Court of Justice of the European Union. additional Spanish necessary for the subsequent rebalancing of the resulting programme that session of the IM.

The PHF program of programming units located in the Spanish peninsular electrical system will be established by the OS from the result of the aggregation of all the firm transactions formalized for each period of programming as a result of the daily viable programme and the appeal of tenders on the intra-day market, after having resolved, where appropriate, the technical restrictions identified and the subsequent rebalancing. The PHF programme will maintain the existing energy flow between the Spanish and Portuguese systems as a result of the intra-day market appeal process.

The OS will publish the final schedule (PHF), with a notice of no less than 15 minutes before the start of the horizon for the implementation of the corresponding IM session, in accordance with the procedure of the the operation by which information exchanges with the OS are established.

In cases where the existence of an incident is verified, and it can be corrected without affecting the programming process of the generation, the OS, in coordination with the OM, will carry out the appropriate actions for its resolution and, where appropriate, will proceed with the publication of a new version of the PHF, keeping the SM of these actions informed at all times, through the website of the eSIOS Subjects. In the event of such a situation, the OM and the OS shall take the necessary steps to ensure that the sequence of operations is carried out as soon as possible.

In cases where, for some delay or other operating condition, the publication of the corresponding PHF is not possible before the beginning of the horizon of application of an IM session, the OS will suspend the application of the PHF at that time, communicating this fact to the SM, to the OM, to the appropriate effects.

7. Information exchanges after the intraday market for the programming of international exchanges

In order to establish the final values of the exchange programs per subject that will be considered for the establishment of the adjustment value of the frequency-power regulation system in charge of control the exchange of energy between the two electrical systems that share each electrical interconnection, only those energy programs that have been correctly nominated will be considered, and with respect to the deadlines set.

After each session of the IM, the OS will exchange with the operators of the neighboring electrical systems the information of the nominations of energy programs of the SM, in order to establish jointly the the end values of the exchange programs in the corresponding pipeline.

This same exchange of information will also be carried out in cases where a congestion situation has been identified in an international interconnection during the operation in real time, to proceed with the resolution of such congestion through the implementation of a reduction of the planned exchange programmes.

8. Management of deviations

The deviations between generation and consumption over the inavailabilities of the generating equipment and/or modifications in the forecast of the demand and/or in the forecast of the production of special regime not manageable and/or significant differences between the expected demand and the envisaged demand in the market resulting from the market may be resolved by the application of the diversion management mechanism, provided that the conditions for the application of the system are met. the mechanism set out in the operating procedure for which the process of solution of generation-consumption deviations.

The solution of these deviations will cover up to the start time of the application horizon for the next IM session.

9. Real-time programming

9.1 Operational schedules (P48): The P48 are the schedules that result after the incorporation of all the assignments made in firm up to the time of the publication of these programs of the units programming located in the Spanish peninsular electrical system.

Each of the P48 shall be published in accordance with the procedure laid down in the operating procedure establishing the exchange of information with the OS, at a time of not less than 15 minutes in advance of the change of time.

9.2 Immediate actuations to imbalances in real time: At the time when an incident occurs with an imbalance between generation and consumption, the immediate action of the primary and secondary regulation to correct the imbalance, with consequent loss of regulatory reserve.

If the secondary regulation reserve is reduced below desirable levels for system security reasons, the OS will require the use of tertiary regulation reserve to regenerate the secondary reserve, by applying the procedure for the operation whereby the provision of the tertiary regulatory service is established.

9.3 Modifications of the P48: The modification of a P48 from the previous one may be motivated by:

(a) Amendments to the energy sales and procurement programmes carried out in the IM sessions, or by the application of the diversion management procedure, or by the allocation of tertiary regulation offers.

b) Over-come inavailabilities of the physical units of production in the period between the communication of two consecutive P48.

c) Forecasts of the evolution of demand and/or production of wind origin until the next session of the IM, carried out by the OS, and which differ from the total demand and/or the programmed wind production resulting from the previous IM session.

d) A solution for real-time restrictions alert situations.

e) Fehaciente communication of the subject of a production unit, or of a unit of pumping consumption, of the existence of deviations on the program due to the technical impossibility of fulfilling the program, certain discharges, etc.

f) The operator of a neighbouring electricity system operator of the total or partial non-compliance of the energy exchange programme which is intended to be carried out by a market subject.

9.4 Resolution of restrictions detected in real time: The modification of the programming for the resolution of the restrictions identified in real time will be carried out according to the procedure of operation sets the technical constraint resolution process.

10. Close Program (P48DRERE)

After the end of the daily programming horizon, the OS will make available to the subject holders of programming units the closing program (P48REDRE) corresponding to the final production and consumption programs. resulting from the different markets and from the participation in the system adjustment services.

11. Information to the OM and market subjects

All exchanges of information between the OS and the OM and the SM carried out in the framework of the process of programming of the generation, will be carried out using the means and the structure previewed in the current editions of the the procedure laid down for the exchange of information on the OS with the market participants and the joint procedure agreed between the OS and the OM, in accordance with the procedure laid down in the operating procedure for which the information exchanges with the OS.

12. Programming units in the Spanish peninsular electricity system

The process of daily programming of generation is based on the management of the energy programs of the different programming units corresponding to the sale and the acquisition of energy in the electrical system Spanish peninsular. Some terms associated with the management of the programming units are defined and described in detail below.

12.1 Programming Unit Definition: The Programming Unit is the elementary unit of representation of the energy programs defined in this Operation Procedure.

The Programming Units allow the integration into the Spanish peninsular market of the programs of sale or acquisition of energy corresponding to an individual installation, to which it will be called Physical Unit (UF), or a set of them according to the criteria set out in Annex II to this procedure. They also allow the integration into the market of the import and export programs of energy made through international interconnections.

In Annex II of this procedure, the Generic Programming Unit (UPG) is defined for:

The integration into the energy production market from the primary energy emission auctions (SEP), in case the exercise of options is performed by physical delivery.

The notification of capacity usage in the pipeline with France.

The integration into the production market of engaged generation in physical bilateral contracts.

The Programming Unit (UP) and, where appropriate, the Generic Programming Unit (UPG) is also the elementary unit for the recording of the payment entitlements and the payment obligations that correspond to it in the Register of System Operator Account Log.

The identification codes for these units will be provided by the System Operator once accepted as the Programming Unit and/or the Spanish Electrical System's Generic Programming Unit.

A single Programming Unit and/or Generic Programming Unit may have associated energy programmes corresponding to the different forms of procurement (managed transaction in the organised market and one or more transactions affecting bilateral contracts with physical delivery).

In the case of shared ownership units, the Programming Unit will be unique, and the co-owner who acts at each moment as the controller of the control center of the same will be able to vary in time.

In the case of special regime production units, the Programming Units shall be composed of one or more Physical Units. These Physical Units will be composed in turn by a set of special regime generation units that share the same RAIPRE code (Administrative Register of Special Regime Production Facilities Code) and also the the economic arrangements for the sale of energy. Each of these generation units shall be identified by its CIL code (Installation Code for the purposes of the Settlement). The OS shall periodically provide the National Energy Commission with the existing relationship between Physical Units, Generation Units and CIL Codes.

12.2 Programming Unit Holder: The Head of the Programming Unit (and/or Generic Programming Unit) will be the market Subject responsible for the Programming Unit (and/or Generic Programming Unit) in the Spanish production market.

In the case of Programming Units corresponding to production facilities or to direct consumers on the market, the operator of the Programming Unit shall be the owner of the installation, understanding as such subject to the holding of the operating rights of the facility, or the co-owner who exercises at each time as the controller of the control centre of the facility.

In the case of the aggregator Programming Units, which are defined in Annex II, corresponding to the Subject of Representatives, Traders of Last Resource or Traders, the holder of the same shall be the Subject Representative, Last Resource Marketer, or Marketer.

In the case of Programming Units used to integrate into the market the transactions of import or export of energy made through international interconnections, the holder of the Programming Unit shall be the subject of the market which has been authorised for such international exchanges.

In the case of Programming Units used for the integration into the market of energy production from the auctions of primary energy emissions (SEP), the holders of the General Programming Units will be, respectively, the SM seller and the SM holder of power purchase options.

In the case of Generic Programming Units used for the communication of international transactions firm in the interconnection with France the holder of the Programming Unit will be the Subject of the market that has been approved for the implementation of such international exchanges.

It will be up to the Subject Subject:

a) The request for high, low, and communication of modifications relative to the programming unit in the OS information system.

b) Where appropriate, the communication to the OS of the designation of a Representative Subject (RST) for the day-to-day management of that Programming Unit.

c) Communicate to the OS the schedules of energy of that Programming Unit, communicating, in addition, in their case, the Programming Units acting as counterparties in the case of transactions corresponding to contracts bilateral with physical delivery.

(d) to provide to the OS the programmes disaggregated by physical units and/or, where appropriate, equivalent production units, in accordance with the criteria for unbundling of programmes which have been set up by the OS in a specific manner; The Programming Unit.

e) Interlocution for the exchange of information with the OS.

12.3 Representative of the Programming Unit: The Representative of a Programming Unit shall be a subject designated by the titular subject of the Programming Unit to act on behalf of the holder, either in his own name or on behalf of others, on the Spanish Production Market using the same Programming Units as the holder of the holder except in the cases set out in Annex II.

The designation of the Representative of the Programming Unit shall be made by the holder's presentation to the OS of the corresponding power of attorney that accredits this fact.

The Representative of the Programming Unit shall be responsible for the execution of the functions listed in the preceding paragraph in points (a), except for the communication of ups and downs to be performed by the subject (b) the holder of the programming unit, (b) in the case where the representative is no longer representing the holder and (c) to (e), both inclusive.

In those cases where a trader integrates in the market national production of ordinary regime, the trader shall act for all purposes as a representative of the holder of the said Units of Programming.

13. Testing new information systems

Before any new exchange of information is put into operation, the system operator will propose a prior stage of carrying out the relevant information exchange tests between all the subjects. affected

ANNEX I

Schedules set for information exchanges

1. Schedules for publication of programs and other information exchanges

Concept	Time
Notification to SM authorisations for programming relating to the physical rights of capacity allocated in explicit auctions in the France-Spain interconnection and, where applicable, in the Portugal-Spain interconnection (D-2 or previous day).	D-2 < 16:00 hours
Nomination to the OS of the allocated capacity at the explicit annual and monthly capacity auctions in the France-Spain pipeline.	< 7:45 hours
	The OS makes available to the OM and the SM the information of the physical rights of capacity obtained in annual and monthly horizons for the France-Spain interconnection whose use has been notified in both electrical systems.	< 08:15 hours
In your case, EASEP makes an indirect nomination of CBEPs with formalized physical delivery between UPG of the SM seller and buyer.	< 8:45 hours
appropriate, the OS makes available to the SM the information corresponding to the nominations of bilateral contracts with physical delivery of type CBEP.	< 08:50 hours
Publication by the OS of the Prior to MD.	< 09:00 hours
Communication by SM to OS of bilateral contract nominations:	< 9:35 hours
bilateral contracts with physical delivery through interconnections outside the scope of the MIBEL in which it is not established a coordinated capacity allocation procedure
applicable, the notifications of use of the physical rights of capacity allocated in the explicit auctions in the Portugal-Spain interconnection carried out jointly by the operators of both electrical systems.
Contracts National bilateral with physical delivery who have chosen the pre-market firm nomination option
appropriate, the Portuguese OS on behalf of both OS will make available to the OM:	< 9:45 hours
regarding the nomination of bilateral contracts with physical delivery in the pipeline Portugal-Spain arising from the use of the physical rights of capacity acquired in explicit auctions.
The maximum usable capacity values in the bidding process in the Daily and Intradiary (ATC) Market
Puesta a Provision of the OM of information concerning bilateral contracts nominated to the OS prior to the MD, and of the capacity allocated in daily auction on interconnections with coordinated capacity allocation procedure	< 09:45 hours
PDBC Publish.	< 11:00 hours
by SM to OS of program nominations per unit of programming:	< 11:00 hours (in any case, up to 30 min after PDBC publication)
Contract Nominations after the MD.
Nominations for UP programming, integrated with other UP in a single offering unit
Nominations of the production programs by UP of the thermal power stations included in the operating plan updated by solution of supply warranty restrictions that have two or more of the UP.
the SM to the OS of the program for:
UP disaggregations in UF.
PDBF Publication.	< 12:00 hours
Presentation of offers for technical constraint resolution processing.	12:30 hours (in any case, up to 30 min after PDBF publication)
Making available to the SM and the OM of the results of the auction of capacity bilateral contracts with physical delivery made, in the event of congestion, on interconnections, outside the scope of the MIBEL, without coordinated capacity allocation procedure	< 14:00 hours
PDVP Publication.	< 14:00 hours
Reservation Requirements secondary.	< 14:00 hours
Secondary Regulatory Offerings Presentation.	< 15:30 hours
Reservation Allocation secondary.	< 16:00 hours
Tertiary Regulation Reserve Requirements.	< 21:00 hours
Presentation of tertiary regulation offerings.	< 23:00 hours

Notes:

D: Programming Day. Except for another indication, all previous schedules correspond to day D-1 (day immediately prior to the operation).

In cases where the existence of an incident is verified, and it can be corrected without affecting the programming process of the generation, the OS, in coordination with the OM, through the corresponding specific messages and deadlines for submission, shall carry out appropriate action for its resolution and, where appropriate, shall publish new versions of these publications (Communication from bilateral, PDBF, PDVP and PHF), keeping informed at all times to the SM of these actions, through the Web of the eSIOS Subjects. In the event of this situation, the OM and the OS will take their best efforts to ensure that the sequence of operations takes place as soon as possible.

In case of delays in any other publication, schedules are modified as described in the text of the Operation Procedure. If, as a result of these delays, the sequence of programming of the operation is affected, the OS will inform the SM in a timely manner using the Web page of the Market Subjects, the eSIOS.

2. Release schedules for PHFs after intraday market sessions

Logout

	Session 1.	Session 2.	Session 3.	Session 4.	Session 5.	Session 6.
16:00	16:00		21:00	1:00	4:00	8:00	12:00
17:45	21:45	1:45	4:45	8:45	12:45
Cassation	18:30	22:30	2:30	5:30	9:30	13:30
nominations by UP and program disaggregations	19:00	23:00	3:00	6:00	10:00	14:00
Analysis. Recuse after constraints.	19:10	23:10	3:10	6:10	10:10	14:10
	PHF Publication	19:20	23:20	3:20	6:20	10:20	14:20
Programming Horizon.	28 hours	24 hours	20 hours	17 hours	13 hours	9 hours
(Time periods).	(21-24)	(1-24)	(5-24)	(8-24)	(12-24)	(16-24)

3. Schedules of the coordinated system of explicit daily and intra-day capacity auctions in the France-Spain interconnection

Exchange of Nominations between OS

	Daily Auction (D-1)	1. Intra-day Auction (D-1)	2. Intraday Subasta (D)
Preacquired Capacity OS Nomination Limit	7:45	15:00	10:25
7:55-8:05	15:35-15:40	10:35-10:40
Publication of the auction specification	8:35	16:05	11:05
Opening period receipt bids	8:45	16:15	11:15
Receive Period Bids	9:15	16:45	11:45
Communication from the Auction to SM	9:30	17:00	12:00
Communication to the SM and the OM of the assigned capabilities	9:30	17:15	12:15

ANNEX II

Programming units located in the Spanish peninsular electrical system

1. Programming units for energy acquisition

These are the corresponding to the last resort, direct consumers in the market, consumption of pumping, marketers, representatives in their own name, consumption of producers and export of energy to systems external.

a) Programming Unit for the acquisition of energy by marketers of last resort: Each Subject Merchant of last resort with supply at tariff or last resort shall be the holder of a single Unit of Programming for the provisioning of your clients for last resort provisioning.

b) Programming unit for direct energy acquisition by direct consumers on the market: Each Direct Consumer Subject in Market will be the holder of a single Programming Unit for all its supplies within the Spanish peninsular electrical system of which it is a Liquidation Subject.

c) Programming Unit for the acquisition of energy for pumping consumption: Each Producer Subject owner of a pumping facility shall be the holder of a single Programming Unit for the acquisition of energy for pumping consumption of the set of groups coupled in the same knot of the Transport or Distribution Network.

This Programming Unit for pumping consumption of that set of groups, will be different from the Programming Unit that will be assigned to the same installation for the production programming corresponding to the process of turbination of that same set of pumping groups.

(d) Programming Unit for the acquisition of energy for supply to domestic consumers by marketers or representatives on their own behalf and on behalf of others: Each Representative in his own name and on behalf of his/her An employee or a marketer shall be the holder of a single Programming Unit for the supply to all its direct consumer customers within the Spanish peninsular electricity system.

In the event that a direct consumer on a market with a representation on behalf and on behalf of the market operator chooses to be represented, the corresponding representative may use the programming units with which the direct consumer would act on the market.

e) Programming Unit for the acquisition of energy by producers (auxiliary consumption): Each Producer may be the holder of a Programming Unit for the acquisition of energy for the supply of all those ancillary services of its facilities that are not fed from its own production units, with ancillary services being understood as the electrical energy supplies needed to provide the basic service in any of the operation of the plant (load, start, stop and emergency), including supplies to electrical equipment and drives associated with the various processes of the plant, control facilities, telecommunications, mechanical installations and power and lighting.

f) Programming Unit for the acquisition of energy for export from the Iberian electrical system to external systems: Each authorized subject for the export of energy from the Iberian electrical system to systems (a) shall be the holder of a Programming Unit for the integration into the market of the energy export programme through each of the international interconnections for which it has the relevant authorisation, or authorized a transit of energy representing an export operation through such interconnection.

g) Programming unit for the acquisition of energy on the market with the intention of exporting to the French electricity system without having capacity rights: Each Subject authorised for the export of energy to France shall also be the holder of a Programming Unit for the acquisition of energy on the market, without the provision of capacity rights and with the intention of its export to the French electricity system.

h) Programming unit for the acquisition of energy in the market for the supply of energy from the peninsular electrical system to the electric system for the Balearic: Each subject of the electric system to be authorized to the Energy acquisition in the peninsular electrical system will be the holder of a Programming Unit for the integration in the market of the energy program through the link between the peninsular electrical system and the electric system Balearic.

2. Programming units for the sale of energy

These are those for domestic production facilities, belonging to the ordinary regime and special arrangements, imports and sales in the daily market for the excess of the term purchases of the latter resource.

(a) Programming unit for the sale of energy corresponding to the production of ordinary power plants: a Programming Unit shall be set up for each thermal power plant, on the basis of the thermal power plant an electrical power production facility that can operate separately from the other production facilities with which it can share the same connection knot to the Transport Network or the Distribution Network.

A Thermal Programming Unit shall normally be composed of a single physical unit, except in the case of multi-axle power plants, such as certain combined cycle groups (X plus gas turbines and steam turbines), which integrate as many physical units as the number of turbines make up them.

The holder of these Programming Units shall be the same producer as the owner of the plant, or the co-owner who acts at each time as the controller of the control centre of the plant, in the case of central shared ownership.

In case the owner of an ordinary regime production facility decides to establish a marketing contract with a Marketing Subject to integrate its production into the market, this marketer act with the same programming units as the Owner Subject would do.

b) Programming unit for the sale of energy corresponding to the production of hydraulic management units of ordinary regime: A Programming Unit to be called Hydraulic Management Unit (UGH) for each set of hydroelectric power plants belonging to the same hydraulic basin and to the same holder.

The holder of this Programming Unit shall be the Producer Subject itself which owns this set of plants, or the co-owner who acts at each time as the controller of the control centre of the assembly. in the case of shared ownership power stations.

In case the owner of an ordinary regime production facility decides to establish a marketing contract with a Marketing Subject to integrate its production into the market, this marketer act with the same programming units as the Owner Subject would do.

(c) Programming unit for the sale of production of reversible central pumping stations: A Programming Unit shall be set up for each set of groups associated with a reversible pumping station which to evacuate in a certain node of the Transport or Distribution Network and is owned by the same Producer or set of producer subjects.

This Power Selling Programming Unit will be different from the Programming Unit that will be assigned to the same installation for the programming of the pumping consumption of that same set of groups.

The holder of this Programming Unit shall be the Producer Subject itself which owns this set of plants, or the co-owner who acts at each time as the controller of the control centre of the assembly. in the case of shared ownership power stations.

In case the owner of an ordinary regime production facility decides to establish a marketing contract with a Marketing Subject to integrate its production into the market, the marketer act with the same programming units with which the Owner Subject would do so that their performance will be similar to that of a Representative Subject.

(d) The unit for the production of special arrangements for the production of the market in the production market through the producer subject: a production planning unit will be set up. special market regime for each Producer and type subject to the operational classification established by the System Operator and published on the website of the eSIOS market participants. In this way, each producer subject will, at least, have as many special regime programming units as production types, make up their generation park so that each Programming Unit will integrate into the market the production of a single type.

The generation of a special managed character of the same type and producer subject will be assigned to two Programming Units; one that will group that generation enabled for participation in the adjustment services of the potestative system, and another that will group that other generation not enabled for the provision of these potestative services.

In the event that the specific features of any installation make your treatment individualized by the System Operator, the Producer Subject will have the corresponding Programming Unit.

e) Special regime production sales aggregator unit in an integrated market economic regime integrated in the production market through the Subject Marketer or Representative in its own name: Each Subject A marketer or a representative acting in his own name and on behalf of an employed person shall, at least, hold as many special regime programming units under market economic arrangements as rates, in accordance with the operational classification established by the OS, make up the generation park with which you have established contracts of marketing or representation on behalf of an employed person, in such a way that each of its aggregating Programming Units integrates into the market the production corresponding to a single type.

The generation of special managed-character regime of the same type will be assigned to, two Programming Units; one that will group that generation enabled for participation in the adjustment services of the Pothestative character, and another that will group that other generation not enabled for the provision of these services.

In the event that the specific features of any installation make it necessary to be treated individually by the System Operator, the Producer Subject will have the corresponding Programming Unit, which will be integrated into the system by its Representative or Marketer Subject.

Each Marketing Subject or Representative in his own name and on behalf of others may also act with the same programming units with which the Producer Subject would participate in the production market.

f) A special regime production sales aggregator unit under the economic regime of an integrated tariff on the production market through the Producer Subject, Representative on its own behalf or Marketer. Each Subject Owner or Representative acting in his own name and on behalf of an employee or a trader shall be the holder of, at most, three units of Programming for the sale of special arrangements under the economic tariff regime for each of the the types of programming units established and published by the System Operator on the website of the eSIOS market subjects, which make up the special regime generation park at the rate of the market. The first one will integrate the production of power generation units of less than 10 MW of the same type that are exempt from the payment of the cost of deviations, the second will integrate the production of power generation units of less than 10 MW. of the same type that are not exempt from the payment of the cost of diversion and the third shall integrate the production of power generation units equal to or greater than 10 MW. In this way, each of its aggregating Programming Units will integrate in the market the production corresponding to the production of the same type, power range and of the same way of liquidation of the deviations.

Upon justified request of the Owner or Representative Subject, authorized by the OS, or by direct initiative of the OS, the Programming Units integrating the production of the power generation units equal to or more than 10 MW may integrate the production of power generation units of less than 10 MW not exempt from the payment of the cost of diversion.

As an exceptional case with respect to the provisions of paragraph 12.1 in relation to the composition of the Special Regime Programming Units, the Programming Units that make up the production of generation units power less than 10 MW not exempt from the payment of the cost of diversion and the Programming Units integrating the production of power generation units of less than 10 MW exempt from the payment of deviations shall be integrated, each, by a Single Unit Physical Unit whose total power will correspond to the sum of the powers of the generation units that make up the said Physical Unit.

Each Marketing Subject or Representative in his own name and on behalf of others may also act with the same programming units with which the Producer Subject would participate in the production market.

g) a special scheme production selling programming unit for installations which do not apply to them any of the options set out in Article 24.1 of Royal Decree 661/2007 of 25 May 2007, regulating the activity of the production of electrical energy under special arrangements, through the Subject Producer or Representative on its own behalf.

According to the current regulations, the market price economic regime is applicable to the facilities during its operation in tests (art. 14.2 of Royal Decree 661/2007, of 25 May), to the facilities that have been definitively registered in the Administrative Registry of Production in Special Regime after the date of completion established for its technology (art. 22.2 of Royal Decree 661/2007, of May 25) and other facilities in terms that can be established by regulation.

Two Special Scheme Production Programming Units shall be constituted under the market price economic regime for each Producer and type subject in accordance with the operational classification established by the Operator of the System and published on the website of the eSIOS market subjects. The first of them will integrate the generation of the same type that is in evidence and the second, will integrate the rest of the same type of generation. In this way, each Producer will be the holder of so many Special Scheme Programming Units, which do not apply to them any of the options set out in Article 24.1 of Royal Decree 661/2007, of 25 May, as types of production compose your generation park and test situation.

Each individual representative on his own behalf and on behalf of others may also act with the same programming units with which the Producer Subject would participate in the production market.

h) Energy sales programming unit for the import from external systems to the Iberian electricity system: Each authorized subject for the import of energy from external systems to the Iberian electricity system will be the holder of a Programming Unit for the integration into the market of imported energy through each of the international interconnections for which it has the relevant authorisation for the import of energy; or has authorized a power transit that represents an import operation through such interconnection.

i) Programming unit for the sale of energy on the market with the intention of importing from the French electricity system without having capacity rights: Each authorised subject for the import of energy from France shall also be the holder of a Programming Unit for the sale of energy on the market, without the provision of capacity rights and with the intention of importing it from the French electricity system.

Facilities that have temporarily suspended the economic regime that they apply to them, either because of the non-compliances referred to in Articles 18, 23.6 and 50 of RD 661/2007 (non-compliance with the the obligation to attach to control centres, non-compliance with the documentary record or fraud in the percentages of hybridization and non-compliance with equivalent electric performance), or by application of the voluntary request for suspension established in Article 49 of RD 661/2007, shall remain under the Programming Unit corresponding to the option of sale they would have previously chosen.

3. Generic programming units

a) Generic Programming Units (UPG): Generic programming units used for:

The integration into the energy production market from the primary energy emission auctions (SEP), in case the exercise of options is performed by physical delivery.

The notification of capacity usage in the pipeline with France.

The integration into the production market of engaged generation in physical bilateral contracts.

ANNEX III

Programming units located in the Portuguese continental electrical system

The programming units located in the Portuguese electrical system shall be established on the basis of the criteria established by the Portuguese electrical system operator.

ANNEX IV

Statement of high bilateral contracts with physical delivery to the system operator

Bilateral contracts with physical delivery may be established among market subjects (producers, marketers, direct consumers on the market and marketing of last resort) using the physical or generic programming as set out in Annex II.

The declaration of bilateral contracts will be made from the SM Web page.

After the high bilateral contract request, the OS will review if the information about the contract is correct and complete and will proceed to communicate the date of discharge to the requesting SM.

International bilateral contracts for the import of energy in the scope of the MIBEL shall be associated only as a selling unit for the corresponding programming unit for the import of energy.

International bilateral energy export contracts in the scope of the MIBEL shall be associated only as a purchasing unit for the corresponding programming unit for the export of energy.

The nomination of these declared contracts to the System Operator shall be in accordance with this procedure and shall respect the schedules of communication to the OS set forth therein.

P. O. -3.2 Resolution of technical constraints

1. Object

The purpose of this procedure is to establish the process for the resolution of the technical restrictions identified in the Spanish peninsular electrical system in the daily program base of operation (PDBF) and in the programs resulting from the different intra-day market sessions, as well as those that can be identified later during the real-time operation.

2. Scope of application

This procedure applies to the following subjects:

a) System Operator (OS).

b) Market Subjects (SM).

In the content of this operating procedure, unless expressly stated to the contrary, all references to the subject holders of the programming units shall be understood as also applicable to the representatives of the subject holders of programming units.

3. Resolution of technical restrictions on the daily market

3.1 Reception of the programme resulting from the appeal of the daily market and the nominations of the programme: Within the time limit set in the operating procedure for the programming of the generation, the OS receive from the OM the information concerning the result of the appeal of tenders in the daily production market, with the energy programmes contracted in the daily market, including the energy programmes derived from the integration into the market of the contracts established in the market within the period under the option of the physical liquidation of the energy.

Within the time limit set in the operation procedure for which the generation schedule is established, or before 30 minutes after the publication of the information corresponding to the results of the generation of the generation, On the daily market, when the contract takes place after 10:30 hours, the OS will receive from the subject holders, for the process of analysis and resolution of technical restrictions, the nominations of the schedules of the energy related to the implementation of bilateral contracts with physical delivery, according to with what is set in the operation procedure by which the generation programming is set.

3.2 Disaggregation of the programmes of the sales and energy acquisition programming units and the communication to the OS of other information needed for the security analysis: the operating procedure for which the generation programming is established, the subject holders of programming units shall provide the following information to the OS:

Information for unbundling in physical units of the power program for each programming unit:

The subject holders of each and every programming unit integrated by more than one physical unit shall provide the OS with the information concerning the disaggregations of the energy programmes allocated to each of them. of the physical units that make up each programming unit, so that this information can be taken into account in the system security analysis.

This breakdown of programs will be applicable, in the case of power sales programming units, to all units composed of more than one physical unit and corresponding to:

Sales units corresponding to a thermal power plant (UVT) composed of several physical units (multi-axis thermal units).

Hydraulic Management Units (UGH).

Energy sales units for reversible pumping stations (UVBG).

Energy sales units corresponding to the production of a manageable special regime (UVREG) from non-renewable sources (UVREGNR) and renewable sources (UVREGR).

Energy sales units corresponding to non-manageable special regime production (UVRENG) from non-renewable sources (UVRENGNR) and renewable sources (UVRENGR).

For power acquisition programming units, this program breakdown will include all units composed of more than one physical unit and corresponding to:

Pump Consumption Corresponding Acquisition Units (UAB).

To perform this process of disaggregation of program nominations by physical units, the OS will be able to define and communicate previously to the subject holders of programming units, the criteria, bases and codes use for the realization of these disaggregations. These criteria may be a function of the characteristics of the different programming units and may define the OS for this purpose, equivalent production units comprising a set of physical units of registered net power. less than a certain value, disaggregations by technologies, disaggregations by knots of the network model used by the OS in the security analyses, and combinations of the previous ones.

The holders of hydraulic management units (UGH) shall provide the OS with the information corresponding to the maximum total hydraulic powers per UGH which, in case they are required for safety reasons of the system, can be supplied and maintained by each hydraulic management unit for up to a maximum of 4 and 12 hours.

3.3 Offers for the technical constraint resolution process.

3.3.1 Period for receipt of tenders: Once the PDBF has been communicated, the OS will consider open the period of receipt of offers for the process of resolution of technical restrictions, period that will be closed 30 minutes later of the PDBF communication.

The OS will be able to extend this deadline for receipt of tenders, only in exceptional cases and after communication to all the SM through the SM Web page of the eSIOS system, communication in which the new closing time will be indicated of the period of receipt of tenders, and the specific causes on which the decision to extend the period of acceptance of tenders has been based.

3.3.2 Presentation of offers.

3.3.2.1 Energy Sales Units: The holders of energy sales units, associated with both market transactions and affections to bilateral contracts with physical delivery, corresponding to:

Ordinary regime production.

Non-renewable manageable special regime production.

Energy imports from external electrical systems in which a coordinated system of exchange capacity management is not in place. The existence of a coordinated system for the management of the exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree 2019/1997 is developed, is reviewed. December 26, by which the electricity production market is organized and regulated.

They will present the following offer types:

Power sales offerings that will have a character:

Required for all subjects who hold programming units that, in application of the current regulations, are obliged to make sales offers for each programming period. This obligation shall apply to all the available power in the corresponding programming unit in addition to that programmed in the PDBF, and independently of the fact that its procurement on the production market is carried out through the management of the energy programme in the daily market or through the execution of bilateral contracts with physical delivery.

The production units affected by bilateral contracts with physical delivery, the object of which is the export of energy through electrical interconnections without a coordinated system for the management of the exchange capacity, shall be submit energy sales bids for all the available power in the corresponding production unit, and this independently of the energy sales programme committed in the PDBF, as this PDBF programme, in case of a congestion in the exporting sense in such interconnection, could be reduced or even to be nullified.

Potestative for energy sales units corresponding to energy imports from those external electrical systems in which a coordinated system of exchange capacity management is not in place. The existence of a coordinated system for the management of the exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree 2019/1997 is developed, is reviewed. December 26, by which the electricity production market is organized and regulated.

Power purchase bids that will be mandatory for all sales units with respect to the energy sales program established in the PDBF for the corresponding power sales unit.

The production units of the renewable special management regime (UVREGR) and the non-manageable special regime production units (UVRENG), both non-renewable (UVRENGNR) and renewable, are exempted from this obligation. (UVRENGR), and the units of sale of energy on the market with the intention of importing from the French electricity system without the availability of capacity rights, which will not be able to present specific energy purchase offers.

3.3.2.2 Energy Acquisition Units: The holders of power acquisition units for pumping consumption, associated with both market transactions and affections to bilateral contracts with physical delivery, submit the following offer types:

Energy sales offers that will be mandatory in relation to the corresponding energy acquisition program for the pumping consumption programmed in the PDBF (reduction to the cancellation of the pumping consumption program) of the PDBF).

Power purchase offerings that will have a potestative character, for the increase with respect to the PDBF of the unit's pump consumption program.

3.3.2.3 Generic programming units (UPG and UPGSD): Generic programming units will not participate in the resolution of technical restrictions, not accepting the submission of offers of restrictions for these generic programming units.

3.3.3 Characteristics of the tenders: The tenders for the process of resolution of technical restrictions shall be, in general, simple tenders, and must be submitted by the subject holder of the relevant unit, and (a) irrespective of whether such a unit of sale or acquisition may be partially or wholly affected by one or more bilateral contracts with physical delivery for which its execution has been communicated for the following day.

The following information will be specified for each offer:

Offer type (production, import, or pump consumption).

For each programming period, and with respect to the energy programmed in the PDBF, it will be indicated:

Power to upload:

Block N.: Divisible blocks of rising prices, in order of 1 to 10 (maximum number of blocks).

Energy (MWh).

Power price offered.

Energy to go down:

Block N.: Divisible blocks of decreasing prices, in order of 1 to 10 (maximum number of blocks).

Energy (MWh).

Power price offered.

Code for the definition of the order of precedence to consider for the impact of the possible power redispatches to be applied on a unit of consumption of pumping, and of the possible redispatches of energy to be lowered applied on a unit of sale, if the unit itself participates simultaneously in a market transaction and in the execution of one or more bilateral contracts with physical delivery (priority reduction of the programme corresponding to the market transaction and subsequent reduction of bilateral contracts by pro rata between them, reverse priority, or application of the pro rata rule over the entire transaction set.)

Power sales units for thermal power plants may present complex offers that will consist of four terms:

Revenue to keep the drive coupled for an hour.

Revenue per unit of energy produced.

Cold start revenue.

Revenue by hot start.

In the process of solution of technical restrictions these complex offers may be considered only in cases where the corresponding unit of sale of energy has a schedule null in all and each of the periods constituting the daily programming horizon, or has only one or more energy programmes in one or more of the first three periods of time of that horizon, as a downward ramp of load associated with a drive uncoupling process.

In the case of multi-axle cycles, the hot start of the complex offers may be taken into account in cases where the programme of the unit corresponds to the mode of operation of the a gas turbine and a steam turbine and, by system security requirements, that multi-axle combined cycle group is required in the technical restriction solution processes, the start of an additional gas turbine.

In cases where the complex offer is applicable, upon verification of the above condition, the use of the same shall be performed under the following criteria:

The unit will be considered to remain engaged in a given programming period as long as its production schedule is greater than zero in that period.

The term corresponding to the revenue per unit of energy produced will be specified by a single block.

Hot start: Scheduled start and/or performed by the production thermal unit so that the time interval from the last hour with the allocated program and the time the program is scheduled and/or performed the start is less than 5 hours; and the scheduled start and/or performed by the second and successive gas turbines of a multi-axis combined cycle, in response to a specific request from the OS.

Cold start: Any other scheduled boot and/or performed by the production thermal unit that does not meet the previous condition.

Subject-holders of programming units to which the submission of tenders for the process of resolution of technical restrictions apply may send offers of restrictions by default according to the provided in the operating procedure for establishing the exchange of information with the OS.

3.4 Resolution processing of the technical constraints of the daily operating base program (PDBF): This process consists of two distinct phases:

Phase 1: Modifying the PDBF program by security criteria.

Phase 2: Rebalance of production and demand.

3.4.1 Phase 1: Modifying the PDBF program by security criteria.

The objective of this phase is to determine the technical constraints that may affect the execution of the PDBF, identifying those program modifications that are necessary for the resolution of the restrictions. detected techniques, and establishing the necessary security program limitations to avoid the occurrence of new technical restrictions in the second phase of the technical restriction resolution process and in subsequent markets.

3.4.1.1 Identification of technical constraints.

3.4.1.1.1 Preparation of case studies: Security analysis for the identification of technical restrictions will take into account the following information:

The production and international exchange programs included in the PDBF.

Program breakdowns for:

Power sales units associated with multi-axis thermal power plants (UVT), hydraulic management units (UGH), and reversible pumping stations (UVBG).

Non-manageable (UVREG) and non-manageable (UVRENG) production power sales units, both from renewable sources and non-renewable sources, participating in the market through the corresponding subjects holders or representatives of the same.

The demand predicted by the OS.

The best wind production forecast available on the OS.

The best information available in relation to:

Inavailabilities both programmed and oversold that affect network elements.

Inavailabilities both programmed and oversold that affect the physical units of production and the procurement units for pumping consumption.

The demand will be considered distributed in the different nodes of the network model used by the OS for the performance of the security analyses. This distribution of the demand for knots will be performed by the OS, using the applications of the energy management systems, and the IT applications and Databases specifically designed for the analysis and the resolution of technical restrictions.

3.4.1.1.2 Technical Restriction: It is any circumstance or incident arising from the situation of the production-transport system that, due to the safety, quality and reliability of the established supply (a) Regulation (EC) No No 2014

the European Parliament and of the Council of the European Parliament and of the Council of the European Parliament and of the Council

In particular restrictions may be identified due to:

(a) Failure to comply with security conditions under permanent and/or contingency arrangements, as defined in the operating procedure establishing the operational and security criteria for the operation of the electrical system.

b) Insufficient secondary and/or tertiary regulation reserve.

c) Insufficient additional power reserve to ensure coverage of the expected demand.

d) Insufficient capacity reserve for voltage control in the Transport Network.

e) Insufficient capacity reservation for service replenishment.

For the resolution of these restrictions the mechanisms described in the present operating procedure and those other for which the management of the corresponding adjustment services of the system.

3.4.1.1.3 Safety analysis: On the basis of the above, the OS will carry out the necessary security analyses for the entire programming horizon and identify the technical constraints affecting the PDBF, the safety, quality and reliability criteria contained in the operating procedure establishing the performance and safety criteria for the operation of the electrical system.

These cases of study used for the performance of the PDBF security analyses will be made available to market subjects in RAW format of the PSS/E application after the time period has elapsed. established, where appropriate, for reasons of confidentiality of the information, as indicated in the operating procedure establishing the exchange of information with the OS.

3.4.1.1.4 Resolution of technical restrictions: Before proceeding with the solution of the technical restrictions identified in the Spanish electrical system, the OS will resolve, if necessary, the congestions identified in the PDBF that affect interconnections with neighbouring electrical systems without a coordinated mechanism for the management of the exchange capacity, as laid down in the rules and in the operating procedures in force.

3.4.1.1.5 Resolution of technical restrictions and guarantee of supply in the Spanish electricity system: Once the non-existence of congestion is verified in the international interconnections in which a Coordinated system of management of the exchange capacity, the OS will analyze the security conditions of the Spanish peninsular electrical system and will resolve the restrictions for guarantee of supply that affect the Spanish electricity system agreement with the procedure of operation for which the resolution of restrictions is established by security of supply. In the case of identifying internal technical constraints to the Spanish electrical system in the PDBF, the OS will study for each set of consecutive programming periods in which it has identified technical constraints, possible solutions that they are technically resolved by an appropriate margin of safety.

3.4.1.1.5.1 Means for the resolution of technical restrictions: To resolve the technical restrictions identified in the PDBF affecting the Spanish peninsular electrical system, the OS may establish increases or reductions of the programmed energy in the PDBF.

Increased scheduled power in the PDBF:

Using the power sales offerings presented to the technical constraint resolution process by:

a) Power sales units associated with production facilities:

Units for thermal groups (UVTs).

Hydraulic management units (UGH) and reversible pumping stations (UVBG).

Non-renewable manageable special regime production units (UVREGNR).

(b) Sales units corresponding to energy imports through the electrical interconnections with Community countries (UVICs) without a coordinated system of exchange capacity management.

Reduced power programmed in the PDBF:

The reduction of the programmed energy in the PDBF for the resolution of the technical restrictions identified in the Spanish electricity system, will be carried out without direct use of offers to these effects, being considered these program reductions of the corresponding program provided in the PDBF.

These program reductions for the solution of the technical constraints identified in the PDBF may be applied to the following types of units:

a) Sales units associated with production facilities:

Units for thermal groups (UVTs).

Hydraulic management units (UGH) and reversible pumping stations (UVBG).

Managed Special Regime Production Units (UVREG) and non-manageable (UVRENG), both from non-renewable and renewable sources.

b) Sales units corresponding to energy import programmes through the electricity interconnections with Community countries (UVICs) without coordinated system of capacity management of exchange.

c) Power acquisition units for pumping consumption (UAB).

In the event that other means are not available in the Spanish peninsular electricity system, or there is a certain risk for the supply in the national peninsular territory, the reductions of the programmed energy in the PDBF will be can also extend to:

(d) Acquisition units corresponding to energy export programmes through interconnections with neighbouring electrical systems (KAUs) where a coordinated system of management of the system is not in place. ability to exchange.

In exceptional situations, either by lack of means in the Spanish peninsular electricity system or by a certain risk to guarantee the supply in the Spanish peninsular territory, for the resolution of the technical restrictions identified in the PBF, the OS will be able to request the neighboring electrical systems interconnected with the Spanish electrical system, increases and/or reductions of energy programs in units located in their system.

The existence of a coordinated system for the management of exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree is developed, is revised. Decree 2019/1997 of 26 December 1997, for which the electricity production market is organised and regulated.

3.4.1.1.5.2 Selection and application of resolution media.

Solution of technical constraints by increasing the programmed energy in the PDBF: In the event of necessary increases of the programmed energy in the PDBF, and to exist more of a technically valid solution and of Equivalent effectiveness, the OS will carry out an economic assessment of the possible solutions and choose the one that represents a lower cost. At the same cost for several equivalent solutions in terms of technical effectiveness for the resolution of the identified restrictions, the OS will select the one that represents a lower energy movement with respect to the PDBF.

Programme increases for the resolution of the technical restrictions identified in the PDBF will be carried out through the implementation of energy redispatches, resulting in new energy programmes that will be established, whenever possible, in whole MWh values, programmes which, in the case of production units, shall be of value not less than the technical minimum of the corresponding unit, nor greater than the maximum power available in the unit, power that at the limit will be equal to the net active power recorded for the same.

Program increments for PDBF that are applied for resolution of technical constraints will be valued on the basis of the offer submitted for the constraint resolution process.

In the case of multi-axle combined cycles, where the programme increases in respect of the PDBF require a change in the mode of operation of a multi-axle combined cycle leading to the start of one or more gas turbines, In addition, the scheduled and realized start of each turbine shall be considered according to the hot start of the complex offer of restrictions that has been submitted.

Solution of technical restrictions by reducing the programmed energy in the PDBF: For the application of reductions of the energy programs provided in the PDBF for the resolution of the technical restrictions identified in the Spanish electrical system will be taken into account the influence that the energy program of each unit has on the technical restrictions identified, using to these effects the factors of contribution to the restrictions techniques obtained in the applied security analyses.

Thus, in the case of multiple units with an equivalent influence on the technical restrictions identified, the resolution of these units will reduce the programs of these units by applying the rule pro rata on their corresponding energy programmes.

In the event that the effects of the programs of these units on the identified restrictions are not equivalent, the modification of programs of the different units will be carried out, in the first place, the program of the unit which has the greatest contribution factor, respecting the minimum production schedule which may be required in this programming unit for the purposes of system security, by applying the following reductions according to the order of decreasing contribution factors obtained in the security analysis applied.

In the event that in the process of resolution of technical restrictions, congestion is identified in the evacuation of production of both ordinary and special regime, being necessary, for reasons of safety of the system, the reduction of the total production program to a certain value, the solution of the technical restrictions identified by the application of the process indicated below:

Identification in the first place of set A of sales units corresponding to production, both ordinary and special arrangements, whose contribution factor to the technical restrictions identified exceeds a certain minimum threshold.

Establishment, from the previous set, of a subset A1 consisting of each and every unit of sale of ordinary regime production (UVT + UGH + UVBG).

Reduction of the programs of the sales units that constitute the A1 subset in order of decreasing contribution factors.

Once applied to the A1 subset, the maximum reduction of programs compatible with the limitations established by reason of the security of the system, in case of persisting the situation of congestion, the OS will proceed to reduce additional production by modifying the programmes of the energy sales units corresponding to the production of special arrangements in accordance with the following order of priority, provided that the security of the system so does allow:

Non-renewable source manageable special regime production units (UVREGNR).

Renewable source manageable special regime production units (UVREGR).

Non-manageable special regime production units from non-renewable sources (UVRENGNR).

Non-manageable special regime production units from renewable sources (UVRENGR), last reducing those units whose technological adequacy, in accordance with the requirements of the operating procedures, contributes to a greater extent to ensure the security and quality of supply conditions for the electrical system.

Program reductions for the solution of the technical constraints identified in the PDBF will be made by applying power redispatches on those units.

This will reduce, first, the programs of the units with the greatest contribution, respecting the minimum production programs that may be required in these units for reasons of system security, and the order of priority referred to above in those cases where the identified technical restrictions have a contribution to both ordinary regime production units and special regime production units.

This process of reduction of programs will, in all cases, give rise to new energy programs that will be established, provided that this is possible, in whole MWh values, programs that, in the case of the units of production, shall have a value not less than the technical minimum of the corresponding unit, and shall not exceed the maximum power available in the unit, the power at the limit shall be equal to the net active power recorded for the unit.

To this end, once the energy sales programmes have been reduced in accordance with the relevant contribution factors to the identified restrictions, or the application, where appropriate, of the pro rata rule for such reduction, a rounding of those programmes shall be established by applying the International Standard ISO 31 B so that all the resulting programmes are expressed in whole MWh values.

The programme reductions for the PDBF that are necessary for the resolution of the identified technical restrictions applied to both energy sales units and procurement units (pumping consumption and, where applicable, (exports) shall be considered as cancellations of the corresponding programme provided for in the PDBF.

Solution of technical constraints due to insufficient power reserve to be raised: In those cases where, once the redispatches have already been incorporated by guarantee of supply, according to the procedure of operation of (i) the resolution of restrictions on security of supply and, the redispatches and security constraints on the PDBF programme necessary for the resolution of technical restrictions, the existence of an insufficient reserve of power is identified; The OS will adopt the following measures in the resulting programme:

Apply minimum program limitations to a value equal to their technical minimum over all the thermal groups scheduled in the PDBF.

Apply maximum program limitations on pump consumption units.

Apply in each electrical interconnection with Community countries a comprehensive minimum programme limitation on all the programming units corresponding to energy imports through the interconnection, for a value equal to the minimum between the overall value of the set of import programmes and the value of the intended exchange capacity and published in the importing sense.

When the above measures are not sufficient to ensure an adequate margin of power reserve to be raised, the OS will schedule the start and coupling of additional thermal groups taking into account for this purpose. the power reserve to be raised that each of the available and uncoupled thermal groups would, where appropriate, contribute to the system, the minimum cold or hot start time, as the case may be, and of the programming declared by the unit (from order to up to a minimum of technical boot), as well as the cost associated with starting and programming coupling of each of them, in order to ensure the additional reserve of power to be raised with the minimum associated cost.

In this process of starting and coupling additional thermal groups, the OS will take into account the possible modes of operation of the multi-axis combined cycles.

The programming cost of a thermal group due to insufficient power reserve to be available will be calculated as the ratio between the programming cost of the group to a technical minimum at all time periods with insufficient power reserve to be raised and, the maximum available power of the group for the number of time periods in which additional thermal group programming is required.

The power reserve provided by each thermal group shall be determined according to the maximum active power available in the unit, the value of which shall be equal to the net active power recorded for that unit of the production.

For this programming of the starting and coupling of additional thermal groups due to the insufficiency of the power reserve to be made available, a specific code of redispatch will be used, preferably, to the object of be able to account individually, both the volume of these redispatches due to an insufficient reserve of power to be uploaded to the system, and the cost associated with the application of the same.

Solution of technical constraints due to insufficient power reserve to be lowered: In those cases where, once the redispatches and safety limitations on the PDBF program necessary for the (i) a reduction in the number of technical restrictions, the identification of the existence of an insufficient reserve of power to be reduced in the resulting programme, the OS may proceed to apply programme limitations on the acquisition units concerned; pumping consumption up to a value equal to that of your program in the PDBF, in order to avoid possible subsequent reductions of this pump consumption program.

3.4.1.1.5.3 Practical implementation of the resolution of restrictions: For the establishment of the energy redispatches necessary for the resolution of the technical restrictions, the corresponding values will be respected the minimum and maximum powers of the generating groups, and the nominal powers of the pumping units, according to the information contained in the Administrative Registry of Electrical Power Production Facilities (RAIPEE) and other supplementary information (power corresponding to the minimum technical unit of production, nominal power of consumption of pumping, etc.) which, if it is not contained in the RAIPEE, shall make it easier for the OS to hold the relevant programming units in a feisty form and in accordance with the procedure laid down in the procedure for the operation of the exchanges of information with the OS. In addition, the possible transitional limitations of these power values shall also be taken into account by the subject holders of these units to the OS.

They will not be taken into consideration, on the contrary, other distinct limitations, own of each production unit, such as the maximum ramps of rise and drop of load of the thermal groups, among others, that must be managed on the intraday market, where necessary, by the holders of the relevant units.

The OS at the time of applying energy redispatches to be up on sales units corresponding to reversible pumping stations will take into account the capacity of the upper vessel of the central bank, both in terms of the feasibility of the total energy sales programme which may be required for the resolution of the technical restrictions of the PDBF, as in terms of the feasibility of the necessary pumping programme to be able to take account of that programme for the sale of energy resulting from the resolution of the technical restrictions. This pump consumption program must be established directly by the subject holder of the unit by participating in the intra-day market.

The energy increases programmed over the PDBF for the resolution of technical restrictions in the Spanish electricity system, which can be applied on sales units corresponding to energy imports through interconnections with Community countries without a coordinated system for the management of the exchange capacity shall always take into account the expected and published maximum exchange capacity values for the relevant interconnection and flow direction. The existence of a coordinated system for the management of the exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree 2019/1997 is developed, is reviewed. December 26, by which the electricity production market is organized and regulated.

Once selected, among the set of technically valid, and equally effective, solutions that represent a lower overall cost, the OS will establish, taking into account the increases of the corresponding programs the resolution of restrictions on security of supply, in accordance with the procedure for the operation of the resolution of restrictions on security of supply, the amendments to the programmes corresponding to the resolution adopted, indicating for each unit affected by such modification the type and magnitude of the redispatch which is applicable to you in a specific way, for which the following qualifications will be used:

UPO (Unit with Obtained Program):

Power sales unit for which the coupling or increase of your sales program is required with respect to the PDBF.

Pump consumption unit, or where appropriate, energy acquisition unit corresponding to an export through interconnections with neighbouring electrical systems without coordinated system of capacity management exchange, for which a reduction of its acquisition program with respect to the PDBF is required.

UPL (Limited Program Unit):

Power sales unit for which a reduction in your sales program is required with respect to the PDBF.

Energy redispatches corresponding to the resolution of technical constraints on the daily market, once incorporated into the PDVP, will be considered firm, remaining unchanged in the energy programme even in the the conditions that have resulted in the technical restriction are removed.

In all cases where the resolution of technical restrictions has associated the coupling, increase or decrease of production of specific physical units, incorporated in a given unit of sale of energy, and In addition to the programming unit concerned by the energy redispatch, the physical units and the requirements applicable to each individual unit of the energy sales unit, the OS shall define, in addition to the programming unit concerned, a total change of the programme of the energy sales unit concerned. of them in detail, incorporating these complementary data into areas (a) process of information that will be part of the exchange of information pertaining to the redispatches and security limitations communicated by the OS as part of the PDBF technical restrictions resolution process.

In cases where power redispatches are applied to a programming unit that is integrated by more than one physical unit, security constraints may also affect the same as indicated before. for redispatches, only to part of the physical units that make up the redispatch without considering, in these cases, that these limitations are necessarily applicable to the entire set of the corresponding programming unit.

In the case of the application of redispatches to be lowered on units of sale of energy corresponding to units of production or to imports, or on units of acquisition for consumption of pumping or in its case exports, By participating in the corresponding unit simultaneously in a market transaction and in the execution of one or more bilateral contracts with physical delivery, the OS will distribute the corresponding redispatch on the different transactions in which the unit is involved, taking into account the definition of the order of precedence incorporated in the tender submitted by the holder of that unit for the resolution of the technical restrictions. In the event that the said code has not been included in that offer, the priority reduction of the programme corresponding to the market transaction and the subsequent reduction of all bilateral contracts shall be considered as the default option. in which the same unit is involved by applying prorrata between them, when they are more than one.

In the case of the application of program reductions on units of purchase of pumping consumption or, where applicable, exports, associated with a bilateral physical contract, they will be applied after, in a coordinated manner, applicable, redispatches of energy to be lowered on the sales units associated with that bilateral, in accordance with the provisions of paragraph 3.4.2.1.

3.4.1.1.5.4 Setting of security limitations: As part of the process of resolution of technical restrictions, the OS must establish the necessary limitations, for reasons of system security, on the programmes of the different energy sales units and on the procurement programmes for pumping consumption and, where appropriate, on the programmes corresponding to energy exports through interconnections with the electrical systems neighbors.

The application of these security constraints will aim to avoid the emergence of new restrictions on subsequent processes (rebalance generation-demand, intra-day market, secondary regulation markets, and tertiary, generation-consumption diversion and real-time operation).

The OS will set these program limitations for security according to the following classifications:

LPMI (Minimum Program Limitation or Lower Limit) applicable to:

Power sales unit programmed in the PDBF and/or the PDVP where, for system security reasons, one or more of the physical units that integrate it must maintain a certain minimum energy sales program.

Power acquisition unit programmed or not in the PDBF and corresponding to a pumping consumption or, where appropriate, an export of energy through interconnections with neighbouring electrical systems, in which for reasons Your energy acquisition program cannot exceed a certain value.

LPMA (Maximum Program Limitation or Upper Limit) applicable to:

Power sales unit programmed or not in the PDBF, or programmed in the PDVP where, for system security reasons, your energy sales program cannot exceed a certain value.

Power acquisition unit programmed in the PDBF and corresponding to a pump consumption where for system security reasons its power acquisition program cannot be less than a certain value.

The allocation of security program limitations will impose restrictions on subsequent energy sales and/or energy acquisition programs for pumping consumption and, if applicable, export through the interconnections with the neighbouring electrical systems, for the programming units, or in their case physical units, on which these safety limitations have been applied.

The modification of the energy programs with respect to the PDBF, through the application of energy redispatches of type UPO (unit with program obliged) and UPL (unit with limited program), for the resolution of the restrictions identified techniques, will result in an automatic allocation of security constraints:

(a) The application of power redispatches for the assignment of a required program (UPO) over a particular power selling unit will result in the application of a minimum program limitation (LPMI), limitation that only allow the power redispatches to be applied after the unit (energy sales program increments).

(b) The allocation of a required programme (UPO) on a power acquisition unit for pumping consumption will result in the implementation of a minimum programme limitation (LPMI), a limitation which will only be applied after on this unit redispatches of energy to be raised (reductions of the power acquisition program for pumping consumption).

(c) The allocation of a limited programme (UPL) on a unit of energy sales will result in the implementation of a maximum programme limitation (LPMA), a limitation which will only allow for the implementation of this unit energy to be lowered (reductions in the energy sales program).

The application of security program limitations that set minimum program limits (LPMIs) or maximum program limits (LPMA) on the program of a power sales unit or on the consumer acquisition of pumping or, where appropriate, of export through interconnections with the neighbouring electrical systems without coordinated system of management of the capacity of interchange, will only allow the application of redispatches that respect the limits of power maximum to be lowered or raised, respectively, for them.

These program limitations established for system security reasons may disappear only in those cases where the OS removes or adjusts the corresponding security limitation applied to that unit, the situation of the system-transport system has been modified and the conditions imposing such a programme restriction are no longer present.

When minimum program security (LPMI) or maximum program (LPMA) limitations are associated with particular physical drives and not the unit of sale set, the program limitations for later security markets will also be associated with these physical units and not the energy sales unit as a whole.

In cases where the minimum program limitation (LPMI) or maximum program limitation (LPMA) affects a set of production units or a set of procurement units for pumping consumption, located in the same location, geographical area or international interconnection, the OS shall preferably establish these security constraints in a comprehensive manner, for application to a particular location, geographical area or international interconnection. These global limitations may coexist with minimum program limitations (LPMIs) and/or maximum program (LPMA) limitations applied to one or more of the units to which the global limitation affects.

When on a transient basis, due to an over-coming cause, associated with problems in the operation of the computer applications used for security analysis, or other possible causes affecting the determination and/or treatment of these global limitations, the OS will set these program limits for individual security. For the establishment of such individual limits, on the basis of a level of technical criteria, the OS will use the merit order of the tenders submitted to the technical restrictions resolution process. Irrespective of their contribution to the restriction, they shall be exempted from the application of these programme limitations, provided that the security of the system so permits, all production units of a manageable special scheme renewable (UVREGR) and non-manageable special regime (UVRENG), both from non-renewable and renewable sources.

3.4.1.1.5.5 Treatment of the resolution of technical restrictions in the Distribution Network: In the process of resolution of technical restrictions will be analyzed and resolved the restrictions identified in the transport network, in accordance with the safety, quality and reliability criteria contained in the operating procedure establishing the performance and safety criteria for the operation of the electrical system.

However, in those cases where the distribution network manager identifies the existence of a safety problem on the network under the production plan, the distribution system operator may request the OS to introduction of the modifications that are required in the PDBF to ensure safety in the affected distribution network.

In this case, the distribution system operator shall communicate to the OS, in accordance with the operating procedure for the exchange of information with the OS, the existing risk in the distribution network which is the object of its operation. management, the days and periods of programming affected, the measures to be taken, and the changes required in the production programmes, in the event that they are necessary. In this communication, the distribution system operator must explain in detail those requirements, the risk existing in the distribution network and the impossibility of adopting other alternative measures (topological measures or application of the the contracts for the sale of energy by the undersigned with the holders of the production facilities under special arrangements, among others) which could avoid, or at least reduce, the introduction of modifications to the daily base programme intended operation.

In cases where the distribution system operator identifies the existence of restrictions on the network which is the subject of its management as a result of the scheduling of a discharge on the transport network or on the network of distribution, such a manager must communicate this fact to the OS as far as possible, in order to enable such information to be part of the communication of network inavailabilities with influence in the production program that the OS communicates each day prior to the daily market, in accordance with the provisions of the operating procedure for the that information exchanges with the OS are established.

In cases where the above is not possible, for unwanted delays in the communication of such information, or other unanticipated causes, or where the technical restriction is directly associated with the plan itself production provided for in the PDBF, the distribution system operator shall communicate to the OS the existence of such a technical restriction at a time of not less than one hour in respect of the time limit set for the publication of the PDVP of the day in which the programming is carried out and, in any case, prior to the publication by the OS of the energy redispatches and the constraints necessary for security reasons for the resolution of the technical restrictions identified in the PDBF, so that these additional modifications to the PDBF programme can also be taken into account account in the generation-demand rebalancing process.

According to this information, the OS will introduce the required modifications to the PDBF and inform the distribution network manager of the introduction of these redispatches and program modifications. associated, as well as program limitations applied to the security of the distribution network.

For these redispatches and safety limitations applied to the PDBF program for safety reasons of the distribution network, the OS will, preferably, use specific codes in order to be able to establish precisely, their volume, as well as the costs associated with them.

3.4.1.1.5.6 Treatment of congestion identified in the generation evacuation: When in the process of resolution of technical restrictions a situation of congestion due to an excess of production is identified in a a zone with regard to the capacity for evacuation of the same, depending on whether such congestion is already identified in the case-study basis, or that it appears only in the case of certain contingencies, that it will be carried out as indicated below:

a) Condemarches in the case of study and/or identification of conditions of transient post-contingency instability.

Production shall be limited in the area affected by congestion in such a way that at no time on the evacuation lines and transformers the maximum load limits set in the operation procedure shall be exceeded. the operating and security criteria of the system operation.

This same performance will be carried out in cases where, in the event of contingency, dynamic analyses show the existence of situations of transient instability in a certain area of the electricity system. is weakly attached to the rest of the system or, even at the extreme, practically isolated from it, with a strong production-demand imbalance in the area, which would put the security of supply at risk in the area.

The reduction of the energy programme with respect to the PDBF of the units whose contribution to the identified technical restrictions exceeds a certain minimum threshold shall be made on the basis of their contribution to the restriction the identified technique, taking into account the criteria already mentioned in paragraph 3.4.1.1.5.2.

Thus, in the case of several units whose contribution to the identified technical constraints is equivalent, the energy to be reduced among all of them will be extended according to their planned programme in the PDBF, and in the Other cases for the implementation of these programme reductions shall be taken into account for the factors contributing to the restriction referred to above.

In this process of reducing the energy program with respect to the PDBF, the technical minimum of the thermal groups will be respected. If, once the production of all the groups involved in the congestion has been reduced to the technical minimum, an excess of production will persist in the area, the stop of thermal groups will be programmed, according to the order of merit of the energy purchase offers (reduction of the PDBF programme) submitted for the process of resolution of technical restrictions by the holders of those sales units, initiating the scheduling of the stop of those units which have submitted a higher price on your power purchase offer.

When matching offers at the same price, the thermal group stop will be programmed based on their technical minima, starting with that group with a higher technical minimum, provided the safety of the electrical system so allows it.

In this process of scheduling the stop of thermal groups, the minimum cold start and programming time of the unit (from boot order to technical minimum) must be taken into account, thus being programmed in first place the group stop with a shorter start and/or programming time.

In the particular case where a congestion situation is identified in the production evacuation in which several units belonging to the same SM are involved with a contribution equivalent to congestion, it shall be prorated preferably the energy to be reduced for the congestion solution between the sum of the PDBF program of all the production units belonging to the same SM, and the order of priority communicated to the OS by the corresponding SM will be taken into account for their units when applying the reduction of programs to the production units of each subject, in accordance with the provisions of the operating procedure establishing the exchange of information with the OS and, provided that the security of the system so permits.

The production of special arrangements will also intervene in the resolution of these technical restrictions, in the event that the security of the system so requires, once already reduced to the minimum values compatible with safety of the system, the production schedules of the ordinary system units, following in this process the different phases described in paragraph 3.4.1.1.5.2. of this procedure.

b) Condemarches in post-contingency situations.

Once there is no evidence of the existence of congestion in the case study, or of conditions of temporary instability that require a priori reduction of production in the area, having already been resolved Case, they would have been identified, then the possible existence of post-contingency congestions will be analyzed.

In the event of such congestion detection, your resolution will be analyzed by adopting corrective measures that will only apply in case of contingencies that cause technical constraints.

Where the adoption of post-contingency corrective measures is not possible, or the implementation of these measures requires a time higher than the time allowed for the consideration of transient overloads in transport elements, In accordance with the procedure laid down in the operating procedure laying down the criteria for operation and safety for the operation of the system, the necessary preventive measures shall be laid down, by means of the reduction of the units of production in the area, applying the same criteria as above for the resolution of congestions in the base case.

c) Teleshots in production units.

In the case of congestion in the production evacuation of a zone limited to post-contingency situations, the production units that may be affected by a reduction, or even by the preventive annulment of the the energy programme envisaged for them in the PDBF, will be able to avoid, or at least reduce, this decrease in their programme, by activation, after authorization by the OS, of a generation tele-firing automatism acting in case of present any of the contingencies that cause unacceptable post-contingency overloads. These automatic generation-firing automatisms may result in the disconnection of the production unit and the complete loss of production of the unit, or a rapid and partial reduction in the production of the unit without disconnection from the production unit. same.

The above will be applicable as long as these tele-firing automatisms act with the required response speed, meet the technical conditions set and are thus enabled by the OS to perform this function, the safety of the electrical system is guaranteed at all times.

In cases where the congestion solution requires the activation of a number of remote-generation tele-firing automatisms to the existing ones, for activation of the same the OS will establish a shift system rotating in the definition of which the holders of the production units of the area provided with telephoto systems may take part.

In the event that the activation of a tele-shot allows to avoid the reduction of the production schedule by such a amount that the reduction requested of the unit that activates said telephoto is exceeded, said additional margin Production will be distributed among the remaining units of production, giving preference to those units which, having a remote-firing system, have not been required, however, the activation of the system is not necessary.

The subject holder of each programming unit shall communicate to the OS, without delay, any change or modification that may affect the operation or operation of these telefiring automatisms.

d) Application of limitations to avoid congestion in later markets for increased production with respect to the PDVP.

In the event that there are no congestions in the baseline case or in post-contingency situation with the energy sales programs in the PDBF corresponding to these production units, but these congestions could if the production units in the area increase their production in subsequent markets (intra-day market, diversion management and tertiary regulation), on top of a certain value, the OS will proceed as follows:

It will determine by horariously, what is the maximum production value that can be allowed in the zone, identifying whether the restriction would be presented only in post-contingency situation, or whether it would correspond to a congestion in the case base.

If possible congestion is identified only in post-contingency situation, it will be determined what is the maximum allowable production value in the area taking into consideration the teleshots of the area groups, these assumptions groups with the same PDVP energy programs.

Once established in both cases the maximum production increase over the programs provided in the PDVP, acceptable for system security reasons, the additional capacity value available (whichever is more In the case of a limited number of groups in the area with influence on congestion, it will be allocated, preferably in the form of a zonal limitation, and alternatively, in the form of an individual limitation on each group of the zone with influence on the congestion, according to order of increasing prices of the offered offers for the process of resolution of technical restrictions by the holders of these energy sales units. In the case of equal price in the offers of two production units, the allowable production increases shall be established by giving preference to the operation of those groups for which their corresponding systems of production have been activated. teleshooting.

3.4.1.1.5.7 Treatment of programme modifications requested by neighbouring electrical systems: The transmission system operators of neighbouring electrical systems interconnected with the Spanish electricity system will be able to ask the OS for the introduction of the modifications that are accurate in the PDBF to ensure security on your network.

In such a case, the transmission system operator of the neighbouring electricity system shall be directed in writing-by fax or e-mail-to the OS, informing them of the risk on the transport network which is the subject of its management; and further detailing, the days and periods of programming affected, the measures to be taken, and the modifications required in the production programmes, in the event that they are necessary. In this communication, the transmission system operator of the neighbouring electricity system must provide a detailed justification for these requirements, the risk on its network and the impossibility of taking other alternative measures (topological measures or modification of programs in units of their electrical system, among others) that could avoid, or at least reduce, the introduction of requested program modifications.

This information must be communicated by the transmission system operator of the neighbouring electrical system to the OS as far as possible and, in any case, prior to the publication by the OS of the redispatches of energy and the constraints necessary for security reasons for the resolution of the technical restrictions identified in the PDBF, so that these additional modifications to the PDBF programme can also be taken into account in the Generation-demand rebalancing process.

According to this information, the OS will introduce the required modifications to the PDBF and inform the transmission system operator of the electricity system of the introduction of these redispatches and the associated program modifications, as well as program limitations applied to the security of your transportation network.

For these redispatches and safety limitations applied to the PDBF program at the request of the neighboring electrical system, the OS will use, preferably, specific codes to the object of being able to establish with precision, both its volume, such as the costs associated with them which will be borne by the neighbouring electricity system which has made the corresponding application.

3.4.2 Phase 2: Reequilibrium generation-demand: Once the technical restrictions identified in the PDBF have been resolved and, where appropriate, the restrictions for security of supply in accordance with the operating procedure whereby the resolution of restrictions by guarantee of supply is established, the OS will proceed to make the necessary modifications of program in order to obtain a balanced program in generation and demand, respecting the limitations established, system security reasons, in the first phase of the resolution process technical constraints, and the expected and published values of the exchange capacity in international interconnections.

3.4.2.1 Partial or total reduction of the energy sales programmes for bilateral contracts with physical delivery the demand for which has been reduced in Phase 1.

The OS will first proceed to partially or even totally reduce the energy sales programs of those programming units that are enabled to participate in the restriction resolution process. (a) technical, bilateral contracts with physical delivery whose corresponding demand has been reduced in the first phase of the PDBF technical restrictions resolution process.

According to the provisions of the first phase of the PDBF technical restrictions resolution process, this demand will correspond to pumping consumption units and, when there are no other means to resolve the restrictions or there is a certain risk for the supply in the national peninsular system, to units corresponding to export transactions through the interconnections with the neighbouring electrical systems in which a coordinated system of management of the exchange capacity. The existence of a coordinated system for the management of the exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree 2019/1997 is developed, is reviewed. December 26, by which the electricity production market is organized and regulated.

In the event that the energy sales program associated with that bilateral contract has also been reduced as a result of the solution of restrictions in the first phase of the process, the OS will determine such a reduction. by comparing the following values:

Decrease (D) required in the unit of sale program by the first phase of the technical constraint resolution process.

Partial or total reduction (R) of the unit of sale program associated with the rebalancing of the bilateral contract with physical delivery after the reduction of the acquisition unit program in the first phase of the technical constraints.

This way:

If the decrease (D) is greater than the reduction (R):

The energy sales unit program will be cancelled in accordance with the reduction of the reduced acquisition unit program in PHASE 1 (R) (ECOCBV redispatch).

The difference between the decrease (D) and the reduction (R) will generate a power redispatch to be lowered (D-R) that will be applied on the unit of sale, as a consequence of the resolution of technical constraints by safety criteria (redispatch UPLPVPV).

If the decrease (D) is lower or the limit equal to the reduction (R):

The energy sales unit program will be cancelled in accordance with the reduction of the acquisition unit program applied in PHASE 1 (R) (ECOCBV redispatch).

No power will be generated to be downloaded to the sales unit.

3.4.2.2 Partial or total reduction of energy acquisition programmes corresponding to a pumping consumption or an export through interconnections without a coordinated system of exchange capacity management associated with bilateral contracts with physical delivery the generation of which has been reduced in Phase 1.

The OS will reduce, or even cancel the energy acquisition programs corresponding to pumping consumption or to exports through interconnections without coordinated system of management of the capacity of exchange which are associated with bilateral contracts with physical delivery, the corresponding generation of which has been reduced in the first phase of the PDBF technical restriction resolution process. The existence of a coordinated system for the management of the exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree 2019/1997 is developed, is reviewed. December 26, by which the electricity production market is organized and regulated.

In the event that the energy acquisition program associated with that bilateral contract has also been reduced as a result of the resolution of restrictions in the first phase of the process, the OS will determine that reduction by comparing the following values:

Decrease (D) required in the acquisition unit program by the first phase of the technical constraint resolution process.

Reduction (R) of the acquisition unit program associated with the rebalancing of the bilateral contract with physical delivery after the reduction of the unit of sale program in the first phase of the technical restrictions process.

This way:

If the decrease (D) is greater than the reduction (R):

The energy acquisition unit program will be cancelled in accordance with the reduction of the reduced unit of sale program in PHASE 1 (R) (ECOCBV redispatch).

The difference between the decrease (D) and the reduction (R) will generate a power re-dispatch (D-R) that will be applied on the acquisition unit, as a result of the resolution of technical constraints by criteria of security (UPOPVPB redispatch).

If the decrease (D) is lower or the limit equal to the reduction (R):

The energy acquisition unit program will be cancelled in accordance with the reduction of the reduced unit of sale program in PHASE 1 (R) (ECOCBV redispatch).

No power will be generated to be downloaded to the sales unit.

3.4.2.3 Obtaining a balanced program generation-demand.

Media for generating-demand rebalancing: To restore balance generation-demand, the OS may proceed to the allocation of the simple bids submitted and accepted for the process of resolution of restrictions techniques for the increase or reduction of the programmed energy in the PDBF by the holders of the following types of units:

a) Power sales units associated with production facilities:

Units for thermal groups (UVTs).

Hydraulic management units (UGH) and reversible pumping stations (UVBG).

Non-renewable manageable special regime production units (UVREGNR).

Non-manageable special regime (UVREGR) and special regime (UVRER) production sales units will not participate in this process.

b) Sales units corresponding to energy imports through interconnections with neighbouring electrical systems without a coordinated system of exchange capacity management (UVI (interconnections with systems) Community electricity and third countries). The existence of a coordinated system for the management of the exchange capacity will be taken into account once the Annex to Royal Decree 2351/2004 of 23 December 2004, for which Article 12 of the Royal Decree 2019/1997 is developed, is reviewed. December 26, by which the electricity production market is organized and regulated.

(c) Units of sale of energy on the market with the intention of their import from the French electricity system without having capacity rights, will not participate in this process.

d) Power acquisition units for pumping consumption (UAB).

The bidding blocks to be allocated will, if any, be the following for those already used in the security criteria constraint resolution process.

Selection and application of the means for generating-demand rebalancing: The OS will determine the modifications to be made to the daily operating base program (PDBF), following the inclusion of the modifications established in the first stage of the process of resolution of technical restrictions which have not been compensated in the process of the resolution of restrictions by security of supply, in accordance with the procedure for the resolution of restrictions for security of supply, in order to obtain a balanced programme in generation and demand in each and every programming period, with the view that these modifications have the least possible economic impact, and in all cases respect the safety programme limitations set out in the first stage of the process and the capacity of exchange in international interconnections.

In case it is necessary to resolve in this phase an excess generation created in the first phase, the OS will determine the units that will be modified its program according to the application of the following criteria:

Allocation of program modifications, first of all, to those units that are required to submit energy offers to be lowered for the process of resolution of technical restrictions, have not been addressed obligation:

In case the modification, compatible with the compliance of the safety criteria, of the programs of this set of units that have not attended to the requirement to present their offers to the OS, exceed the needs In order to reduce energy demand, the programme modifications will be distributed among them by means of a pro rata distribution among all of them.

In the event that after the modification of each and every one of the programs of the units that have not attended to the requirement to present their offers to the OS, still persist a certain imbalance generation-demand, the OS will proceed to the allocation of the energy purchase offers for the reduction of the PDBF programme submitted to the process of resolution of technical restrictions, offers to be allocated according to decreasing offer prices and taking into account the point of operation of the unit.

In the event that a generation deficit resulting from the modification of programmes in the first phase needs to be resolved at this stage, the OS will determine the units that will be modified by the programme according to the implementation of the programmes. following criteria:

Allocation of program modifications, first, to those units that are required to submit energy offers to be uploaded for the resolution of the technical restrictions, have not yet presented these offers:

In case the modification, compatible with the compliance of the safety criteria, of the programs of this set of units that have not attended to the requirement to present their offers to the OS, exceed the needs (i) energy to be increased for the generation-demand rebalancing, the programme modifications will be distributed among them by a pro rata distribution among all of them.

If after the modification of each and every program of the units that have not attended to the requirement to present their offers to the OS, still persist a certain imbalance generation-demand, the OS will proceed to the the allocation of the energy sales offers (increase of the programme of the sales units and/or reduction of the programme of the procurement units corresponding to the pumping consumption) submitted to the process for the resolution of technical restrictions, offers to be allocated based on growing offer prices.

In both cases, if at the end of the assignment there was a price match on more than one offer, not being able to be fully allocated said set of offers of the same price, the allocation will be made by a distribution to prorrata between that set of offers of the same price.

In this apportionment, only the technical minima of those units on which they have been applied, for reasons of system security, minimum program limitations (LPMI), will be respected.

Once a balanced generation-demand programme has been obtained, the OS will proceed to the publication of the provisional Viable Daily Programme (PDVP), in accordance with the schedules set out in the operating procedure under which the programming of the generation.

3.5 Inavailabilities of production units with influence on security, reported after the PDBF has been published: In the case of partial or total unavailability for the programming day of a unit of scheduled or limited production for the resolution of restrictions of the PDBF, if the communication of such unavailability is made at an advance of not less than one hour with respect to the time limit set for the publication of the PDVP in the (i) the implementation of the programme for the implementation of the programme for the implementation of the programme. the restrictions of the PDBF, according to the latest available information regarding inavailabilities of generation.

If the communication of the unavailability is received after the limit time indicated in the preceding paragraph, or, if still known before that time, the reported unavailability affects the Resolution of the restrictions of the PDBF in such a measure that the consideration of the PDBF could delay the publication of the PDVP, and affect subsequent markets, the OS will proceed to publish the PDVP without considering such unavailability generation, addressing the resolution of the technical restriction associated with the existence of this unavailability, once the PDVP has been published.

In order to establish the solution of the technical restrictions, the OS will take into account both the inavailabilities that have been communicated to it by the respective subject holders of programming units through the registers of unavailability, such as other information that has been transmitted to it by the subject holders through other possible means of communication provided with systems of registration.

Once the unavailability of a production unit has been declared, and the unavailability of the PDBF technical restriction resolution process has been taken into account, it has not been applied to this unit. redispatches or program limitations for security, the subject holder of the unit may go to the intraday market and/or participate, if necessary, in a diversion management session to buy back the energy program provided in the PDBF and not can produce, in order to avoid incurring a detour in front of its PDBF program.

In the event that to avoid major delays in the release of the PDVP, the OS has maintained security limitations, and in its case redispatches of power over a production unit for which the holder has communicated an unavailability for the next day, the OS immediately after the release of the PDVP will proceed to enter the detour log for unavailability on the program of said unit, according to the records of unavailability sent by the titular holder, remaining unchanged the limitations by security applied to that unit.

In case of an advance of the availability of the unit on the schedule initially planned, the OS will proceed to the elimination of the log by the declared unavailability, maintaining the unit the program PDVP established for the resolution of the technical restrictions of the PDBF, and the security constraints associated with such programming.

In the event that this advance of the unit availability on the schedule initially planned, occurs however after the production unit has reduced, or even, reached to cancel the affected program by the unavailability by its participation in the intra-day market, or in a call for management of deviations, that production unit may only participate in the programming through the submission of tenders on the market intra-day or, if applicable, a detour management session.

3.6 Information to the OM and market subjects: As a result of the PDBF's technical restrictions resolution process, the OS will make available to the OM and market subjects, as set out in the the procedure for establishing the exchange of information with the OS, the following information:

Information that the OS will make available to the OM:

The security constraints applied to the programs of the sales and energy acquisition units to prevent further technical constraints from being generated in subsequent processes and markets.

The PDVP Interim Viable Program.

Information that the OS will make available to market participants:

The above information made available to the OM.

Energy redispatches applied on the units affected to international bilateral contracts included in the PDBF, resulting from the auction of exchange capacity for the resolution of the identified congestions, where appropriate, in those international interconnections where a coordinated capacity management system is not in place.

The hourly marginal prices resulting from the exchange capacity auctions between international bilateral contracts with physical delivery, applied in those international interconnections in which it is not implemented a coordinated capacity management system.

Energy redispatches applied on market transactions corresponding to imports and/or exports of energy with neighbouring electrical systems, for the solution of congestion in interconnections International interconnections identified in the PDBF in those international interconnections where coordinated capacity allocation systems are not deployed.

The redispatches applied to the programs of the sales and energy acquisition units to resolve the technical constraints identified in the PDBF, associated with both market transactions and contracts bilateral.

The redispatches applied to the sales and energy acquisition units for the generation-demand rebalancing, associated with both market transactions and bilateral contracts.

The OS will also make available to the OM and/or the market subjects any updates to the files previously made available to them in the process of resolution of technical restrictions that has been required.

These exchanges of information will be carried out through the means and with the structure defined in the current versions of the procedure established for the exchange of information of the OS with the subjects of the market and the the joint procedure agreed between the OS and the OM.

3.7 Failure and complaint resolution regarding the PDBF technical restrictions resolution process: The possible identification of anomalies and/or claims submission to the restriction resolution process The PDBF techniques could lead to the repetition of this process in case the solution of the anomaly so makes it necessary, provided that this is possible, with due respect to the maximum permitted time limits established and published by the OS, to ensure that the subsequent processes of the programming of the generation.

Once the PDVP or any of the information media associated with the resolution of the PDBF technical restrictions has been published, the subject holders of the programming units may submit claims to this process, within the time limit set in the operating procedure by which the generation programming is established, by means of the Application of Claims Management made available to these effects by the OS, and may advance the information concerning the existence of this claim, by telephone, fax or electronic mail, where necessary, in any event, the existence of a formal communication expressed through the application of the IT application of claims management, or by a written means (fax or e-mail), for its consideration as formal claim.

4. Resolution of technical restrictions on the intraday market

The OS will communicate each day, in conjunction with the PDVP, and in accordance with the procedures set out in the operating procedure establishing the exchange of information with the OS, the security limitations applicable to both individual programming units such as, where applicable, sets of programming units (zonal constraints), which are to be considered applied on the programmes of the production units, and in their case of importation, and on the programmes of the pumping units and, where appropriate, exports, in order not to change the expected system security conditions.

Throughout the day, the OS will modify these security limitations, and/or incorporate new ones, according to the actual situation of the existing system at any time.

The OS will make available to the OM, before the opening of each session of the IM, the information regarding the security limitations so that these can be taken into account in the process of acceptance of offers of each of the intra-day market (MI) sessions, in the case of security constraints applicable to individual programming units, or within the internal market appeal process itself, in the case of security constraints applicable to the a set of programming units.

Once the outcome of the appeal of each session of the IM is communicated by the OM, the OS shall receive the nominations of programs per unit of programming, in those cases where in the same unit of offer are integrated two or more programming units.

The subject holders of programming units shall provide the OS with the information corresponding to the disaggregations in physical units and/or equivalent production units of the sales and acquisition programmes of the energy, contracted or adjusted in that session.

4.1 Receiving and loading of the result of the appeal from the IM: As a step before the security analysis is carried out, the OS will verify that the program resulting from the appeal of offers in the relevant market session Intraday respects the ability to exchange international interconnections, as well as the security program limitations established by the OS and made available to the OM prior to the opening of the corresponding IM session they are respected, or at least do not keep the solution of their compliance away. If the above does not apply, the OS shall return to the OM, where appropriate, the programme resulting from the appeal of tenders in the IM.

In the event that the obtaining of a program that does not present congestion in the international interconnections was delayed for a time such that it could be affected very important the programming process itself of the generation, there is a high risk of having to suspend the application of the results of that session of the intraday market in some hour, the OS will proceed to solve these congestions, whenever possible, in the own process of solution of technical restrictions of the intra-day market.

4.2 Intraday Market Technical Restrictions Resolution Process: The OS, in the event of identifying any technical constraints that prevent the program resulting from such an intraday market session, also held in the programme nominations per unit of programming communicated by the subject-holders, shall be carried out in compliance with the safety and operational criteria laid down in the relevant operating procedure; selecting the set of offers to be removed that resolve the constraints On the basis of the order of economic precedence of the offers married in the intraday market communicated by the OM, provided that the withdrawal of such offers can be compensated by the withdrawal of other married offers in the same session and also located in the Spanish electricity system, in such a way that it is possible to obtain a balanced program in generation-demand.

The general-demand balance will be re-established by the withdrawal by the OS of other tenders submitted to the intra-day market session, in accordance with the economic precedence of the offers allocated in the that session.

As a result of the process of resolution of technical restrictions on the intraday market, the OS will make available to OM and market subjects the following information:

Information that the OS will make available to the OM:

The Final Schedule Program (PHF) established by the OS as a result of the aggregation of all firm transactions formalized for each programming period as a result of the daily viable program and the Intra-day market after resolution, where applicable, and whenever possible, the technical restrictions identified and the subsequent rebalancing.

Information that the OS will make available to market participants:

The above information made available to the OM.

The power redispatches required to resolve the identified technical constraints.

The power redispatches needed for the subsequent rebalancing of production and demand.

The publication of the Final Schedule Program (PHF) will be performed according to the schedules set in the operation procedure that establishes the generation schedule.

The OS will also make available to the OM and/or the market subjects any updates to the files previously made available to them in the process of resolution of technical restrictions that has been required.

These exchanges of information will be carried out through the means and with the structure defined in the current versions of the procedure established for the exchange of information of the OS with the subjects of the market and the the joint procedure agreed between the OS and the OM.

5. Real-time technical constraint resolution

5.1 Security Criteria Modifications: The OS will permanently analyze the actual and anticipated security status of the system throughout the entire programming horizon and detect any restrictions that may exist. in each programming period. The resolution of the restrictions will cover the entire programming horizon even if only the energy redispatches will be incorporated in the existing programming periods until the beginning of the programming horizon of the next session of the Intraday market. For the remainder of the period, the necessary limitations for safety reasons shall be established: zonal limitations applicable to a set of individual programming units and/or limitations applicable to a unit of sale or to a unit of energy acquisition, or, to one or more of the physical units that make up the unit.

For the establishment and real-time updating of the safety limits necessary for the resolution of technical restrictions, the same criteria as referred to in paragraph 3.4.1.1.5.2. of the (a) this procedure, thus respecting the values corresponding to the minimum and maximum technical powers of the generating groups and the possible transitional limitations of these power values, without considering any other limitations, such as maximum ramps for loading and lowering the load of the thermal groups, between other, as long as they can be managed on the intraday market by the subject holders of the programming units corresponding to those groups.

Thus, the OS will only program the ramp up/down load of production thermal units when the resolution of technical constraints has been programmed for a programming period such that the subject holder of such a programming unit has no effective possibility to participate in the intraday market session corresponding to the incompatibility of the schedules of that session and the programming period for which the change of the programme of the programming unit for the resolution of the technical restrictions identified in real time.

For the resolution of a real-time technical restriction requiring modification of one or more units ' generation programs, the OS will adopt the resolution representing the minimum cost, using the Tertiary regulation offers that are available at that time.

In the event that the allocation of tertiary regulation offers for the resolution of the restriction is insufficient, this allocation will be supplemented by the allocation of increases and reductions in programmes under the the allocation of the tenders and/or the corresponding offer blocks submitted for the PDBF technical restrictions resolution process, and where applicable, the offer of updated restrictions, with the allocation of the latter modification of programs among the set of units that resolve the constraint, according to the price order of the tenders submitted, the pro rata rule being applied in the case of an equal bid price. In this process of allocation of the offer of restrictions presented, the complex offer may be considered only in cases where the corresponding unit of sale of energy has a zero final schedule in all and each of the periods constituting the programming time horizon, or it has only energy programme in the first three periods of time of the horizon, as a downward ramp of load associated with a process of uncoupling the unit.

In cases where the allocation of programme increments requires a change in the mode of operation of a multi-axle combined cycle leading to the start of one or more gas turbines, the start shall be considered programmed and made of each turbine according to the hot start of the complex offer of restrictions that has been presented.

From the publication of the secondary regulation reserve allocation, market subjects will be able to proceed to update continuously for day D, the offers of restrictions presented for the solution process of technical restrictions of the PDBF, once the necessary computer applications are developed and in accordance with what is established in the procedure of exchange of information with the OS. The OS may delay the opening time for the update of tenders when there are delays in the markets that make it necessary. The SM will be informed through the SM Web of the eSIOS.

In the event that the solution of the real-time restriction requires a reduction in production, inter alia, inter alia, renewable and non-manageable managed special regime production units, these units of production shall maintain its programme without modification, except where the security of the system so requires, once it has been reduced to the minimum values compatible with the safety of the system, the programmes of the other production units intervening in that restriction and taking into account the order of priority set out in the paragraph 3.4.1.1.5.2 of this procedure.

In the event that to ensure system security is accurate the activation of telephoto during the operation in real time, it will apply, if any, the system of rotating shifts established, or in its absence, used as an order criterion to require its activation, that of the tenders submitted for the process of the solution of technical restrictions of the PDBF, except in the case of special regime production, for which activation is required of the telephoto system, only last and following the order of priority set out in the 3.4.1.1.5.2 of this procedure.

The energy redispatches corresponding to the resolution of technical restrictions in real time that have not been effectively executed, will not be considered firm, that is, they will be able to leave without effect the allocations not yet executed when the conditions that gave rise to such a technical restriction are removed.

In cases where the distribution system operator identifies in real time the existence of restrictions on the network which is the subject of its management, in order for the solution to be modified, the production programmes envisaged must be modified. The information referred to in paragraph 3.4.1.1.5.5 of this procedure shall be communicated to the OS, as soon as possible, by all the measures at its disposal by the distribution system operator, as soon as possible.

When the transmission system operator of an electrical system interconnected with the Spanish peninsular electrical system identifies in real time the existence of restrictions in the network object of its management, for which solution It is necessary to amend the production programmes provided for in the Spanish electricity system, once all the measures at its disposal have already been adopted by the neighbouring electricity system, it must inform the OS as soon as possible of the information identified in the Paragraph 3.4.1.1.5.7 of this procedure. The OS shall also proceed as set out in that paragraph of this procedure.

5.2 Treatment of the reductions/cancellations of the capacity to evacuate the production of generator groups due to the over-coming of elements of the Transport Network or the Distribution Network: Due to a breakdown or a fortuitous unavailability is reduced or prevented the ability to evacuate the production of a generator group, being the group available and operating in real time, the OS will proceed to solve the congestion identified in real time by the implementation of a power redispatch on the planned programme for the unit, in such a way that this reduction or cancellation of the capacity for evacuation does not involve a diversion of the actual production of the unit in respect of the planned programme for the unit.

This redispatch will apply from that moment when the capacity for evacuation is affected until the moment when this capacity is already partially or totally restored, proceeding in the first case the OS to adapt the the program of the unit so that it conforms to the actual available evacuation capacity.

In the case of thermal groups, the limitation or, where appropriate, the cancellation of the program of the unit shall be maintained, if necessary, after the capacity of evacuation has been restored, for a period of time equal to the minimum time hot start declared by the unit (from start to sync), or at most, to the start of the application horizon of the next session of the Intradiary Market, in order to allow the unit to recover its program or at least manage the modification of the program in an intraday market session.

5.3 Resolution of restrictions due to insufficient reserve of power to be lowered: When during the operation in real time the existence of an insufficient reserve of power is identified to be reduced in the resulting program, the OS may take the following measures:

Increase the power program of the procurement units for pumping consumption.

Reduce the production schedule of energy sales units for thermal groups up to their minimum allowable power, for safety, or at the limit up to the technical minimum of the unit.

Schedule the stop of thermal groups while respecting the minimum program limitations established by security on the groups and, taking into account the start and programming time of each group. On the basis of technical criteria, the OS will establish a rotating shift system to schedule this stop of thermal groups per reserve of power to fall short.

In the event that the above measures are not sufficient to ensure an adequate margin of power reserve to be lowered in the system, the OS will proceed to reduce the production program of energy sales units. corresponding to the production of a special arrangement, up to its minimum permissible power by security, or in the limit up to the technical minimum of the unit, in accordance with the following order of priority:

Special regime production units manageable from non-renewable sources.

Special regime production units manageable from renewable sources.

Non-manageable special regime production units from non-renewable sources.

Non-manageable special regime production units from renewable sources.

5.4 Resolution of restrictions by action on demand: When during the operation in real time it is not possible to resolve a technical restriction whose solution requires an increase of program of the units production, because these resources have been exhausted or require excessive time, the OS will have to resolve the restriction, or at least alleviate it, by adopting the following measures applied to the demand. This will follow the following order:

Reduction/cancellation of the pumping consumption that might be coupled in the zone.

Reduction/cancellation of export capabilities to other external systems external systems without coordinated mechanism of exchange capacity management and, in case of force majeure, external systems with mechanism coordinated management of the swap capacity.

Application of interruptibility to clients with this type of contract, including what is foreseen in the operating procedure by which the operating measures are established to ensure the coverage of the demand in situations Warning and emergency.

Within each category, market criteria shall be applied, whenever possible, conditional on the compatibility of the time required for the application of each of these measures.

Reduction of pumping consumption: For the use of pumping consumption units to solve technical constraints identified in real time, the order of economic precedence of the offers of regulation will be considered It would be up to the holders of such units to upload to the OS, provided that there is no technical condition which prevents the order from being taken into account.

Application for the reduction/cancellation of export capacities: In the event that the above measures are insufficient, and in the area there are energy export programmes through interconnections with the Neighbouring electrical systems, the OS will proceed to the /cancellation of the export capacity.

The operator of the affected neighbouring system will be notified of the reasons for the modification of the swap capacity, the new export capacity value being agreed between the two operators, as well as the hour and minute of the establishment of the new global exchange programme in the adjustment of the frequency-power system regulator regulating the exchange of electricity in such interconnection and, where appropriate, the new exchange programmes authorised in the two senses of flow.

The new exchange capacity will be published in the SIOS, adapting it to the physical reality of the electrical system, and information will be provided on the reasons for the modification.

Reducing export capacity will result in:

Coordinated balance sheet action in those interconnections with coordinated management mechanism, except in case of force majeure, to ensure the intended export programmes.

Reduction of planned exchange programmes, by pro rata, in case of interconnections without coordinated mechanism or in case of force majeure.

Application of the Demand Interruptibility System: The OS will determine the application of the appropriate demand interruptibility to the existing operating circumstances, in terms of type, duration, power and scope of application.

The OS will inform the Management Authority with powers in terms of energy, the NEC and the affected market subjects, on the order of interruptibility given and the reasons for its application.

5.5 Reequilibrium generation-demand after resolution of technical constraints in real time: In the process of solving technical constraints in real time, after the modification of programs by criteria of Security, no systematic process of rebalance generation-demand is established. The possible generation-demand imbalances caused by the real time resolution of the identified restrictions will be resolved, along with the other deviations communicated by the subject holders of programming units, the deviations between the actual and the expected demand for the OS, and the deviations between the actual and the expected wind production, by the use of secondary and/or tertiary regulation energy, or in the event that the required conditions are verified, through of the deviant management mechanism.

6. Settlement of the technical restrictions resolution process

This section describes in general terms the main aspects of the process of resolving technical constraints that have a direct impact on the settlement of this system tuning service.

The calculation of the receivables and the payment obligations arising from the process of settlement of restrictions is defined in the operating procedure whereby payment entitlements and payment obligations are established. by the system tuning services.

6.1 Liquidation of the provision of the technical restriction resolution service: The settlement of the provision of the technical restriction resolution service is established on the basis of the energy released and the prices incorporated in these redispatches, applied in the PDBF technical restrictions resolution process, in the intraday and in real time market, and in cases where applicable, in accordance with the energy measures.

6.1.1 Liquidation of energy programs: The redispatches and prices incorporated in the same applicable to each of the units of sale and acquisition that have modified their program as a consequence of the processes of PDBF Technical Restrictions Resolution, Intradiary Market Technical Restrictions Resolution and Real-time Technical Restrictions Resolution, are specified in the Annex to this procedure.

6.1.2 Liquidation according to energy measures: Settlement with measures shall apply only to:

Power sales units for which, for system security reasons, their coupling and start-up, or an increase in their PDBF programme for the resolution of technical restrictions, have been scheduled identified in this programme (FASE 1), or for the resolution of the technical restrictions identified in real time.

Energy acquisition units on which the costs arising from the technical constraint resolution process are passed on.

6.2 Distribution of cost overruns arising from the process of resolution of technical constraints: Overruns of the PDBF technical restriction resolution process and in real time will be calculated and passed on an agreement with the criteria specified in the operating procedure establishing the payment entitlements and the payment obligations for the system adjustment services

7. Exceptional resolution mechanism

In the event that, in the event of emergencies or for reasons of urgency, either because of the absence of offers due to force majeure or otherwise of an unanticipated or controllable nature, it is not possible to resolve the restrictions by means of the mechanisms provided for in this procedure, the OS may adopt the programming decisions it considers to be more appropriate, justifying its subsequent actions to the affected operators and the NEC, without prejudice the economic settlement of the same as applicable in each case.

ANNEX I

Redispatches and pricing applicable to the provision of the technical constraint resolution service

1. Scheduled redispatches

1.1 Technical restrictions resolution process of the daily operating base program (PDBF).

1.1.1 First phase: PDBF modifications by security criteria.

a) Sales units that increase the programmed energy in the PDBF for the resolution of technical constraints (Unit with Oblinked Program).

Energy redispatches scheduled for the resolution of technical restrictions of the PDBF will incorporate the prices of the simple offer presented by the corresponding unit of sale, except in the case of a group thermal for which the holder of the unit has submitted a complex offer to the process of resolution of technical restrictions, and this is applicable in accordance with the criteria set out in paragraph 3.3.3 of this procedure.

Scheduled units in the PDVP through a simple offer: The UPOPVPV-type power redispatches scheduled in the PDVP on power sales units for resolution of technical constraints will incorporate the price of each of the energy blocks of the simple offer used in whole or in part for the establishment of such redispatch.

Scheduled units in the PDVP through a complex offer: In those cases where the UPOPVPV redispatches are assigned to thermal groups that have submitted a complex offer and this is applicable according to the criteria laid down in paragraph 3.3.3 of this procedure, the energy redispatches shall incorporate the lower price between the following two:

a) The result of applying the complex offer to the program assigned in the PDVP by constraints.

b) The result of applying the complex offer to the final schedule of the unit after its participation in the different sessions of the intraday market and deducting from it the income associated with the valuation to the corresponding one the marginal price of your PDBF programme in descending loading ramp during the first three hours, and the net income (balance between income and payments) resulting from your participation in the various intra-day market sessions.

The calculations made for determining the price that will be incorporated in these redispatches will be applied in both cases on the set of periods that constitute the daily programming horizon, in addition to account, as appropriate, of cold or hot start of the production unit.

Programming with no offer existence for this process, or insufficient existing offering (UPOPVPMER): In cases where the OS has to schedule the entry into operation or an increase of the program of a unit of Energy sales for the resolution of technical restrictions of the PDBF, by means of a redispatch of energy of type UOPPVPMER, not being affected the unit by an unavailability that prevents the realization of the program assigned for safety, and not existing offers submitted for that unit for the constraint resolution process technical, the energy redispatches programmed in each hour will incorporate a price equal to the result of applying a coefficient of majority KMAY, of value equal to 1.15, on the corresponding marginal price of the daily market.

b) Acquisition units and, where applicable, exports to external systems that reduce the programmed energy in the PDBF for the resolution of technical constraints (Unit with Oblinked Program).

UPO-type power redispatches scheduled in the PDVP, respectively, on energy acquisition units or, if applicable, exports, for the resolution of technical constraints, shall be considered equivalent to cancellations of the corresponding programme. Thus, depending on the type of transaction on which they are applied, they will result in the following program modifications:

Daily market transaction (UPOPVPB or UPOPVPE redispatch):

Reduction of the unit acquisition program in the same magnitude as the redispatch applied, incorporating a price equal to the corresponding marginal daily market rate.

Transaction associated with the execution of a bilateral contract with physical delivery (redispatch UPOPVPCBB or UPOPVPCBE):

Reduction of the energy program of the unit of sale and acquisition affects the bilateral contract, in the same magnitude as the redispatch applied, not incorporating this price.

c) Sales units that reduce the programmed energy in the PDBF for the resolution of technical constraints (Limited Program Unit).

UPL-type power redispatches scheduled in the PDVP on power sales units for the resolution of technical constraints, will be considered equivalent to cancellations of the corresponding program. Thus, depending on the type of transaction on which they are applied, they will incorporate the following prices:

Daily Market Transaction (UPLPVPV Redispatch):

Reduction of the energy program of the unit of sale at the same magnitude of the redispatch applied, incorporating this redispatch of program reduction a price equal to the corresponding marginal price of the market journal.

Transaction associated with the execution of a bilateral contract with physical delivery in which the acquisition unit corresponds to a national consumption (UPLPVPCBN redispatch):

Establishment in the PDVP of an energy acquisition program for the unit affects the bilateral contract, through the application on that unit of the corresponding redispatch, incorporating this a price equal to the corresponding marginal daily market time price.

Transaction associated with the execution of a bilateral contract with physical delivery in which the acquisition unit corresponds to a pumping consumption or, where appropriate, an export of energy to external systems (redispatch UPLPVPCB):

Reduction of the energy program of both the unit of sale and the acquisition unit affected to the bilateral contract at the same magnitude of the redispatch applied, not incorporating this price.

1.1.2 Second Phase: General Rebalance-Demand.

a) Sales units with programs associated with bilateral contracts with physical delivery whose demand has been reduced in Phase 1, and which reduce the programmed energy in the PDBF to obtain a balanced program in generation and demand.

ECOCBV energy redispatches scheduled in the PDVP on energy sales units corresponding to bilateral contracts whose demand has been reduced in the first phase of the restriction resolution process PDBF techniques shall not incorporate any price.

(b) Acquisition units corresponding to a pumping consumption or an export through interconnections without a coordinated system of exchange capacity management with programmes associated with bilateral contracts with physical delivery the generation of which has been reduced in Phase I, and which reduces the programmed energy to obtain a balanced programme in generation and demand.

ECOCBV energy redispatches scheduled in the PDVP on energy acquisition units (pumping consumption or, where appropriate, export via international interconnections without a coordinated system of management of the exchange capacity) corresponding to bilateral contracts, the generation of which has been reduced in the first stage of the PDBF's technical restrictions resolution process, shall not include any price.

c) Sales units that increase the programmed energy in the PDBF to obtain a balanced program in generation and demand, and pump consumption acquisition units that reduce the programmed energy in the PDBF with the same end.

Energy redispatches to be uploaded in the PDVP to solve a generation deficit and thus obtain a balanced generation-demand program, applied on a daily market transaction (ECO redispatch) or on a the acquisition unit associated with a bilateral contract with physical delivery (ECOCB redispatch), will incorporate the price of the corresponding block of the offer of energy to be raised by that unit for the process of resolution of restrictions techniques and used in whole or in part for the establishment of such redispatch.

In the case of acquisition units that have not submitted the corresponding offer of energy to be raised for the process of resolution of technical restrictions, being however obliged to do so, the redispatch applied will pass to be referred to as ECOSSO redispatch, if associated with a market transaction, and ECOSCBSO redispatch, if it is associated with a bilateral contract with physical delivery, incorporating in both cases such redispatch a price equal to that resulting from applying a KMIN minoring coefficient, of equal value to 0.85, on the corresponding marginal price daily market time. For these purposes, a default price of the energy supply shall be considered to be raised for the resolution of technical restrictions of the corresponding unit of value equal to 85% of the corresponding marginal daily market time price.

d) Sales units that reduce the programmed energy in the PDBF to obtain a balanced program in generation and demand, and acquisition units that increase the programmed energy in the PDBF for the same purpose.

Power redispatches to be dropped programmed in the PDVP to resolve an excess generation and thus obtain a balanced program generation-demand, applied on a daily market transaction (ECO redispatch) or on a the unit of sale associated with a bilateral contract with physical delivery (ECOCB redispatch) shall incorporate the price of the corresponding block of the energy supply to be lowered submitted by that unit for the process of resolution of technical restrictions and used in whole or in part for the establishment of such redispatch.

In the case of sales units that have not submitted the corresponding offer of energy to be lowered for the process of resolution of technical restrictions, being however obliged to this, the redispatch applied will become referred to as ECOBSO, if it is associated with a market transaction, and the ECOBCBSO redispatch, if it is associated with a bilateral contract with physical delivery, incorporating in both cases a price equal to that resulting from the application of a KMAY, a value equal to 1.15, on the corresponding marginal price of the daily market. For these purposes, a default price of the energy supply to be lowered for the resolution of technical constraints of the corresponding unit of value equal to 115% of the corresponding marginal daily market time price shall be considered.

e) Redispatches applied to obtain a balanced program in generation and demand in the case of insufficient offers to run this process.

In cases where the OS has to schedule power redispatches to go up or down to solve a deficit or excess generation, respectively, and thus obtain a balanced program generation-demand, and once already the redispatches on all the units of both sale and acquisition that are obliged to the submission of offers, have not attended, however, this requirement, and also assigned all those offers presented for the process of resolution of technical restrictions, compatible with the respect of limitations applied for safety, and not yet sufficient allocation to restore the balance generation-demand, the redispatches which, if any, can be applied by the OS by MER, will bear the following prices:

Power Redispatch to Rise (ECOSMER Redispatch): Price equal to that resulting from applying a KMAY mayorance ratio equal to 1.15, on the corresponding marginal daily market time price.

Power Redispatch to Go Down (ECOBMER Redispatch): Price equal to the result of applying a KMIN minoron coefficient, of equal value to 0.85, on the corresponding marginal daily market time price.

1.2 Process of Resolution of Technical Restrictions on the Intradiary Market: The redispatches applied for the withdrawal of offers of sale or purchase of energy from the intradiary market, for the resolution of the the technical restrictions identified in the programme resulting from such an appeal (RTIMO redispatch) or for the subsequent rebalancing of the generation-demand programmes (redispatch ECOMI), shall incorporate the corresponding marginal time-price Intraday market session.

1.3 Process of Resolution of Technical Restrictions in Real Time: Energy redispatches applied for the resolution of technical restrictions identified in real time will incorporate the price of the offers used to these effects: Tertiary regulation offers supplemented by the tenders submitted for the process of resolution of technical restrictions.

1.3.1 Redispatches applied by using the tertiary regulation offering.

1.3.1.1 Sales units that increase your energy program for the resolution of real-time technical constraints and acquisition units that reduce your energy program to the same end.

Power redispatches to upload of type UPOTRT scheduled in real time for the resolution of technical constraints, will incorporate the price of the tertiary regulation offer to be used for these purposes.

1.3.1.2 Sales units that reduce your energy program for the resolution of technical constraints in real time.

Power redispatches of type UPLTRT down scheduled in real time for the resolution of technical constraints, will incorporate the price of the tertiary regulation offer to be used for these purposes.

1.3.1.3 Pump consumption acquisition units that increase your energy program for real-time technical constraint resolution.

The increase of the pump consumption program of a procurement unit for the resolution of technical constraints in real time will be associated with a power redispatch to drop of type UPLTRT. This redispatch shall have an energy equal to the magnitude of the increase in the programme, incorporating a price equal to the sum of the price of the tertiary regulation offer to be used for these purposes, and of the result of applying a KBO coefficient, of a value of 0,70, on the corresponding marginal daily market price.

1.3.2 Redispatches applied by using the submitted offer for the technical constraint resolution process.

1.3.2.1 Sales units that increase your energy program for the resolution of real-time technical constraints and acquisition units that reduce your energy program to the same end.

Power redispatches to upload of type UPOTROR scheduled in real time for resolution of technical constraints, will bear associated the price of the offer of energy to be uploaded for that unit to the process of resolution of technical restrictions and used for these purposes.

1.3.2.2 Sales units that reduce your energy program for real-time technical constraint resolution.

Power redispatches of type UPLTROR to be scheduled in real time for the resolution of technical constraints, will be associated with the price of the offer of energy to be lowered presented for this unit to the process of resolution of technical restrictions and used for these purposes.

1.3.2.3 Pump consumption acquisition units that increase your energy program for real-time technical constraint resolution.

The increase of the pump consumption program of a procurement unit for the resolution of technical constraints in real time will be associated with a power redispatch to be lowered of type UPLTROR. This redispatch will have an energy equal to the magnitude of the increase in program, incorporating a price equal to the sum of the price of the offer of energy to be lowered presented for that unit to the process of resolution of technical constraints and used for these purposes, and for the result of applying a KBO coefficient of 0,70 on the corresponding marginal daily market time price.

1.3.3 Real-time applied redispatches not covered with tertiary regulation offerings or offers submitted for the technical constraint resolution process: In cases where the OS has to schedule redispatches of energy to be raised or lowered for the resolution of technical restrictions identified in real time, without any offers of tertiary regulation, or offers submitted for the process of resolution of technical restrictions, or These are insufficient to cover fully the redispatches applied by the security in real time, the redispatches which, if any, can be applied by the OS by MER, will bear the following prices:

Power Redispatch to Rise (UPPER type): Price equal to the resulting from applying a KMAY shift coefficient, equal to 1.15, over the corresponding daily market time marginal price.

Power Redispatches to Go Down (UPLMER type): Price equal to that resulting from applying a KMIN minoron coefficient, of equal value to 0.85, on the corresponding daily market time marginal price.

In the case of pump consumption acquisition units, the increase of your program for the resolution of technical constraints in real time will bring two energy redispatches to be reduced of type UPLMER. These redispatches will each have an energy equal to the magnitude of the increment of the program, incorporating one of them a price equal to the result of applying a coefficient of minoría KMIN, of value equal to 0.85, on the corresponding price marginal daily market time, and the other a price equal to that resulting from the application of a KBO coefficient, of 0,70, on the corresponding marginal daily market price.

2. Effective execution of scheduled redispatches according to measures

The OS shall determine in accordance with the measures, in those cases where applicable, the modifications that are necessary for the prices incorporated in the scheduled redispatches, taking into account the starts and the type specific starting (cold or hot) scheduled, and the fact that they have been produced effectively in accordance with the measures received, as well as the actual energy measured for the unit and the energy for it programmed by criteria security (Phase 1).

In the event that the energy measured in an hour for a unit of sale is lower than the security programmed, the unfulfilled energy shall be valued at the price resulting from the difference between the weighted average price of the whole energy programmed to rise for the resolution of technical constraints and the corresponding marginal daily market time price.

P. O. -9 Information exchanged by the system operator

1. Object

The purpose of this Procedure is to define the information to be exchanged by the System Operator (OS) with the purpose of performing the functions entrusted to it, as well as the form and time periods in which it must communicate or publish it.

This information includes, inter alia, the information on the structural data of the installations of the electrical system, the data relating to the real time situation of the electrical system (state, measures, etc.), the information exchanged for the proper operation of the system, the information necessary for the compilation of the statistics relating to the operation of the system, the information required for the analysis of the effects of the electrical system, as well as the information referred to to the data for the settlement of the transactions carried out on the production market of electrical power.

It is established in this Procedure, with the detail that comes in each case, the way in which the exchange of information between the OS and the different subjects of the Spanish electrical system will be carried out, the way of access to the information, how to structure and organise it (databases), its character (public or confidential) and its subsequent treatment (analysis, statistics and reports).

2. Scope of application

Within the scope of the Peninsular Electrical System:

System Operator (OS).

Market Operator (OM).

Distribution network managers.

Single carrier and distributors who are exceptionally holders of transport facilities.

Market subjects and other system subjects defined in the electrical sector regulation

3. Information management processes in which the system operator intervenes

The information exchange processes in which the OS is involved can be grouped as follows:

a) Structural Data of the Electrical System.

b) SIOS: System Operation Information System.

c) Main Electrical Measurement Concentrator.

d) SCO: Real Time Operation Control System.

e) Other information to be sent by system subjects.

f) Statistics and Public Information regarding the System Operation.

g) Analysis and incident information in the electrical system.

h) Liquidation under the responsibility of the OS.

As far as the headings b, c, d e and f are concerned, the system subjects shall be responsible for depositing in the OS information systems the information contained in this Procedure, as well as for providing the information. necessary communication mechanisms and take charge of their costs.

The subjects will ensure that:

a) The information provided is correct.

b) The information is available to the OS with the minimum time delay and with the appropriate time stamp.

c) Communications systems are redundant, reliable, and secure.

d) The transmission of information conforms to the characteristics of communication protocols and frequency of sending information defined by the OS.

4. Structural data for the electrical system

It is the data of the installations of the transport network and the observable network, as well as of the generating groups, consumers and control elements, that the OS requires to exercise its functions facilitating the analysis of safety and performance studies of the electrical system.

4.1 Responsibilities: The OS is responsible for collecting, maintaining, and updating the electrical system's structural data. The information is structured and organized in the Structural Data Base of the Electrical System (BDE).

The holders or representatives of the programming units for the sale of energy on the production market, the consumers connected to the transport network, the single carrier, the distributors (including those who In exceptional cases, the operators of the distribution networks shall be obliged to supply the OS with the necessary information on the elements of their property or to those they represent in order to maintain the content of the updated and reliable BDE.

4.2 Content and structure of the Database: The BDE will include the records of all the elements discharged into the electrical system managed by the OS. It shall also include the records of elements in project and construction and of planned elements, with the available values, although these shall be considered provisional until they are put into service. These last records will be released to facilitate the conduct of the transport network planning studies and the different forecasts analysis of the electrical system.

The contents of the BDE will respond to the following structure:

• Production System.

-Embalses.

-Common system and hydraulic groups.

-Ordinary-speed thermal units.

-Special regime units.

• Transport Network.

-Substations.

-Parks.

-Lines and cables.

-Transformers.

-Active or reactive power control elements.

• Consumer installations connected to the Transport Network.

• Observable Network.

-Substations.

-Parks.

-Lines and cables.

-Transformers.

-Reactive power control elements.

A detailed relationship of the different fields in which the BDE is structured is included in Annex 1.

4.3 Load processing: The OS will define the computer support used and enable the templates of the data entry tabs with the required formats.

The OS will complete the fields contained in the above sheets with all the information available to them about each item and make them available to the owner or representative of the item to which the information.

The subjects will carry out a check of the information of the files relating to their installations and modify them, if appropriate, with the best information available, filling in the fields that appear empty.

Once the tokens are completed and validated by each subject, the subject will communicate the outcome of the review to the OS.

4.4 Information Update: The update of the information contained in the BDE can be facilitated by any of the following three circumstances:

For design modifications to some element.

By high or low of some element.

Because a bad value has been detected in some field.

When any of the above three circumstances occur, the subject who owns the corresponding item or the subject acting in its representation shall communicate to the OS the necessary modifications to be incorporated.

The OS will periodically make available to each subject the data of the elements of their property or those to whom it represents collected in the database in order to enable the subjects to check their proper correspondence with the actual data of the installations and, where appropriate, communicate to the OS the necessary modifications to be made.

4.5 Confidentiality of information: The information contained in the BDE will be confidential for all subjects except for:

The NEC, which will be able to have all the information.

The competent energy administration, which will be able to have all the information.

The distribution network managers, who will be able to have the data from the facilities located in the distribution network under their management scope.

Those third parties to whom the OS has the need to give information for the exercise of its functions and obligations, minimizing, in any case, the volume of information transmitted, and always counting with the authorization of the holders of the generated information and the signing of a confidentiality agreement between the information receiver and the OS.

All Subjects who may have the data relating to the facilities in service of the transport network.

5. System operator information systems

The data that, in the performance of its functions, the OS must manage to carry out the processes it has entrusted, starting from the communication of the bilateral contracts established before the daily market, the (i) an appeal to the market on the daily and intraday horizon, bilateral contracts with physical delivery communicated to the OS after the daily market and programmes on international interconnections, including, processes associated with the allocation of capacity on these interconnections, up to Each of the time schedules and the allocation of the system adjustment services shall be managed by the System Operator Information Systems (SIOS).

The e-sios Information System will perform the processes, auction, calculation, recording and file of intermediate data and results of the processes indicated above.

The e-Sica Information System will perform explicit auctions for capacity allocation in those international interconnections in which this process is applicable.

The SIOSbi Information System will perform the file, management, and publishing of the historical information associated with the previous processes.

Information managed and stored by SIOS will also be used later in the settlement processes that are the responsibility of the OS.

SIOS constitutes the only means of the OS for the realization of the exchange of information with the subjects of the market of electrical energy production (SM), the OM and other subjects of the electrical system.

In the execution of the processes and exchanges of information indicated in the preceding paragraph, the SIOS shall ensure:

a) Absolute confidentiality and all evidence of information owned by each market subject (SM).

b) Receipt of receipt to each market subject of their offers, with timestamp.

c) Remote, fast, reliable and easily usable access system.

In order to ensure maximum availability, SIOS Information Systems are redundant systems. In addition the e-sios will have a backup system in a different location of the main system. The OS will inform users of the access modes to both systems.

With a periodicity to be established by the OS, the processes performed by the e-sios will be executed in the backup center, being the responsibility of subjects of the market for the production of electrical energy (SM), the OM and other subjects of the Electrical system the media availability with this backup center using the access modes defined by the OS.

5.1 Databases of System Operator Information Systems: The OS will maintain in its databases all the information necessary for the proper management of the operation programming, the adjustment services of the system and the management of international exchanges that are under your responsibility.

The SIOS databases will meet the following requirements:

a) Dimensioning appropriate to allow the storage of all information.

b) All the information in the databases will be validated.

c) The referential integrity of the recorded data.

d) Historical management associated with all information.

5.2 Access to the SIOS: Access to the SIOS by the market subjects, the OM, other subjects of the electrical system or the general public, will be done according to the character of the information to which you have access, either public or confidential in accordance with the criteria set out in paragraph 5.3.

5.3 Information Exchange Media: The communication between the OS, the OM and the Market Subjects and other participants or entities participating in the production market, as well as the disclosure of free public information access shall be made by electronic means of exchange of information, using at any time the technologies which, in accordance with the requirements set out in paragraph 5, are more appropriate.

The adoption of new electronic means of exchange of information, as well as the suspension of the use of any of the existing ones, will be communicated to the users in good time in such a way that they can carry out appropriate modifications to their information systems.

The OS will publish the electronic means of exchange of information available and its characteristics, those new ones that will be implemented and those that will be suspended, as well as the deadlines foreseen for this.

5.4 Communications: For the realization of information exchanges, the OS will have several alternative means of common use to access both the main and the backup system and will communicate to the users the Technical details required for access and performance procedures in case of switching between the two systems.

The installation, maintenance and configuration of the communication channels to access the SIOS will be the responsibility and will be borne by the users, except bilateral express agreement. The OS shall indicate in each case the rules and procedures applicable to the equipment to be installed on its premises.

5.5 Access Services: According to the type of information, there will be two access services: Private and public.

Private service will be reserved only for market subjects, OM and other electrical system subjects.

The electronic addresses of private and public access services will be provided by the OS.

Access services, both private and public, will use the most appropriate technologies in each case.

For the use of the private access service, a personal certificate issued by the OS will be required according to the regulations in force. No certificate type will be required for the use of the public access service.

5.5.1 Private Access Service Security: Currently, the private access service security system is based on the use of the following items:

a) The encrypted communication channel to ensure the privacy of the information exchanged.

b) Use of digital certificates for authentication when making connections to SIOS, the signature of electronic documents constituting information exchanges and ensuring the non-repudiation of such documents.

c) Use of smart cards. For the same purpose as the certificates in paragraph (b) above, the SM and other production market entities and subjects may own one or more smart cards, where their digital certificate is stored, as well as their data identification and code to prevent misuse in case of theft or loss. The depositaries of these cards will be responsible for the management of this code, being able to modify it when they create it convenient. Likewise, in case of theft or loss, they must communicate this fact as soon as possible to the OS, in order for the OS to discharge the associated certificates.

Digital certificates will be issued by the OS acting as a Certificate Authority. Users recognize the OS as a trusted Certificate Authority for the sake of using the digital certificate or smart card.

Digital certificates will be issued with an expiration date. It shall be the responsibility of the user of the certificate to check that expiry date and to request, where appropriate, the renewal of the certificate in advance not less than 5 working days from the expiry date.

It will also be the responsibility of the SM or market entity to request the cancellation of the certificates when they consider it appropriate (e.g. cessation of activity of responsible users of the certificates)

5.6 Information Management: The OS will be able to establish with the outside information exchanges in both ways:

• Information communicated by the OS.

• Information communicated to the OS.

• The information exchanged by the OS may have different character.

• Public.

• Confidential in terms of paragraph 5.3.4.

5.7 Information Exchanges: All information exchanges will be made using electronic documents of specific content and format, which will be published by the OS in the SIOS. Using these electronic documents, the SM, OM and other subjects or entities participating in the Spanish production market shall transmit to the SIOS the corresponding information, by the means to be established, and at the times specified in the corresponding Operation Procedures.

Electronic documents exchanged with the Market Subjects and other subjects and entities in the electrical market, their content, format and deadlines for publication or receipt by the OS are described in a single document called "Exchange of Information with the System Operator", organized in a series of volumes:

• Volume 1. Production Markets.

• Volume 2. Liquidations.

• Volume 3. Tension Control.

These volumes and their modifications will be published, in good time before their entry into force, on the public website www.esios.ree.es of the OS Information System.

Electronic documents exchanged with participants in capacity allocation processes in interconnections through explicit auctions will be published in the e-music system: www.esica.eu.

The documents exchanged with the Market Operator its content, format and time limits for publication or receipt by the OS are described in the document called " Model of Ficheros for the Exchange of Information between the OS and the OM " to be published jointly by the OS and the OM by the means that each operator establishes.

5.8 Information Advertising Criteria: The criteria for advertising the information managed by the OS on the processes related to the Electricity Production Market are those established in the Royal Decree-Law 6/2000 On 23 June, in the CNE's 1/2001 report on the proposals for amendments to the Rules of Procedure of the Market in order to adapt them to the Royal Decree-Law 6/2000, in the Rules on the Functioning of the Market adopted by Resolution of the Secretary of State for Economic Affairs, Energy and Small and Medium-sized Enterprises, dated 5 April 2001, published in the B.O.E. dated April 20, 2001, and in the Written of the Directorate General for Energy Policy and Mines dated November 19, 2004.

These criteria are as follows:

• The OS will make public the result of the processes of operation of the electrical system, being these objects of its responsibility.

• The OS, in the field of its competence, will make public the comprehensive aggregated data of volumes and prices, as well as the data relating to the commercial capabilities, intra-Community and international exchanges interconnection and, where applicable, by electrical system, as well as the corresponding aggregate supply and demand curves.

• All information that the OS provides to a subject on another, and which is not motivated by the existence of a claim, must be provided to the general public.

• In any event, the OS shall ensure the confidentiality of the confidential information made available to the market by the market participants, as provided for in paragraphs 2f and 2k) of Articles 27 and 30 respectively, of RD 2019/1997.

5.9 Public Information: Information that the OS makes public about the operation processes of the electrical system.

This information, which depends on the period to which the information is affected and the time it is made public, will be published on the public website of the eussians (www.esios.ree.es).

5.9.1 In real time: The information that the OS will release as soon as available is as follows:

• The forecast of the demand of the Spanish peninsular system with a horizon of 30 hours.

• The forecast of the wind production of the Spanish peninsular system with a time horizon between the hour following that publication and the final time period of the next day.

• The programmable capacity of the link between the peninsular electrical system and the current real-time Balearic electrical system.

• The ability to exchange updated international interconnections in real time.

• The updated raw and international exchange aggregates in real time.

• The aggregate result of the solution of real-time technical constraints and the communication of other annotations (inavailabilities and deviations) performed during the real-time operation.

• The aggregate result and marginal price of the markets for the adjustment services of the tertiary regulation system and the management of deviations.

• Disaggregated Operational Time schedules (P48) resulting from the incorporation of all realtime assignments.

5.9.2 Daily: The following information will be published on a daily basis:

• The aggregated specifications and results of the daily and intra-day explicit coordinated auctions of interconnection capacity with France, in the form and time limits laid down in the operation procedure relating to the resolution of congestions in the France-Spain interconnection.

• At a time of not less than one hour before the closing time of the period for the submission of offers to the daily market, the following day information for:

-Capacity to exchange international interconnections.

-Demand for the Spanish peninsular system.

-The forecast of the wind production of the Spanish peninsular system

• After the corresponding market or technical management process:

-Added result of the energy program through the Peninsula-Balearic link.

-The aggregate output of the swap capacity auction between physical bilateral contracts for those interconnections where there is no coordinated capacity allocation mechanism.

-Aggregate results of the solution of supply and technical guarantee restrictions in the PDBF and after each of the intraday market sessions.

-Aggregate result and marginal price of the secondary throttling power reserve allocation.

-Added result of the daily allocation of additional resource offerings for the transport network voltage control.

• Day D + 1 the information corresponding to day D:

-Aggregate result and marginal price of secondary regulation energy.

5.9.3 At three days: After three days from day D in which the supply is made, the information broken down by type of subject/transaction and unbundling shall be published, where applicable, and by technology/frontier.

The information to be published on day D + 4 corresponding to the time schedule of the day system adjustment service markets in the D day system will be broken down by the following types:

Nuclear.

Carbon.

Fuel-Gas.

Combined cycle.

Conventional hydraulics.

Pumping turbination.

Consumption pumped.

Energy imports and exports.

Special Hydraulic Regime.

Non-Renewable Thermal Special Regime.

Special Renewable Thermal Regime.

Special Wind Regime.

Special Solar Photovolic Regime.

Termic Solar Special Regime.

Other renewable special arrangements (Geothermal, Marine Hydraulic, ...)

Special scheme with pay at added regulated rate.

Special regime participating in the aggregate production market.

Ordinary Regime with Prima.

Last Resource Marketer (CUR) acquisitions corresponding to the national last resort supply.

Acquisitions of marketers destined for domestic consumption in the free market.

Direct consumers on the market.

Auxiliary services of production units.

Generic Programming Units.

5.9.4 Weekly: The OS will publish on its website the power of electrical generation available under ordinary system aggregated by generation technologies (nuclear, coal, hydraulics, fuel oil, combined cycles).

Before 18:00 on every Thursday, the Spanish System Operator's public website will publish the expected exchange capacity values for each programming period of the two immediate electric weeks. (from Saturday to Friday), beginning at 00:00 a.m. on the following Saturday, aggregated by border state and for each power flow direction.

Also before 18:00 on every Thursday, the Spanish System Operator's public website will publish the exchange capacity values foreseen for the following mobile year, with time resolution, added by Border state and differentiating each sense of flow.

5.9.5 Monthly: On a monthly basis, the demand forecasts for full months will be published, in the first 15 days of the month preceding the one referred to in the forecast.

The OS will publish the aggregated specifications and results of the monthly explicit coordinated auctions of capacity for interconnections with France and Portugal, in the form and deadlines set out in the Operation relating to the resolution of congestion on the France-Spain and Portugal-Spain interconnections, respectively.

The OS will publish on its website the power of electric generation available under ordinary system aggregated by generation technologies (nuclear, coal, hydraulics, fuel oil, combined cycles)

Also, monthly payments will be published monthly per subject obtained as a result of the system's markets or operating processes.

The first day of the month M + 2 will be published the quotas per subject in month M on the following markets or system operation processes:

Solution of supply warranty restrictions in the Base Operating Program (PBF).

Solution of technical constraints in the Base Operating Program (PBF).

Solution of technical constraints on the intraday market.

Real-time technical constraint solution.

Managing deviations between generation and consumption.

Secondary throttling power reserve.

Energy used for secondary regulation.

Tertiary Regulatory Energy.

Additional resources allocated for reactive power.

Reactive energy.

5.9.6 Quarterly: The OS will publish on its website the power of electric generation available in ordinary system aggregated by generation technologies (nuclear, coal, hydraulic, fuel oil, combined cycles).

The specifications and aggregated results of the quarterly explicit coordinated auctions of capacity for interconnection with Portugal, in the form and time limit laid down in the operation procedure for the resolution of congestion at the Portugal-Spain interconnection.

5.9.7 At three months: After three months from the day it relates, the confidential information contained in paragraph 5.10.2 that is communicated to each market subject (SM), including the offers, will be published. submitted by the SM to the system tuning services.

5.9.8 Annually: The following information will be published:

The specifications and aggregated results of the annual explicit coordinated auctions of capacity for interconnections with France and Portugal, in the form and deadlines set out in the operating procedures concerning the resolution of congestion on the France-Spain and Portugal-Spain interconnections, respectively.

The power of electrical generation available under ordinary system aggregated by generation technologies (nuclear, coal, hydraulics, fuel oil, combined cycles)

5.10 Confidential Information: Confidential information is the one that is communicated to the system subjects individually without access to the system by the other subjects, up to three months after the timing of their communication in a confidential manner, in accordance with the previous paragraph.

This information refers to the programming processes of the operation of the system, to the system adjustment services and to the information regarding the international exchange programs, processes all established in the Operation Procedures:

International exchange programs.

Solution of supply warranty restrictions (redispatches).

Solution of technical constraints (limitations and redispatches).

Managing deviations between generation and consumption.

Secondary secondary regulation service.

Complementary tertiary regulation service.

Supplemental transport network voltage control service.

Other annotations made during real-time operation (inavailabilities, statements, etc.).

The communication criteria to be adopted according to the subjects or participating in the operation markets are as follows:

5.10.1 To Market Operator (OM): You will be notified of all necessary information for the proper management of the daily and intraday market and that other additional in compliance with the provisions of the legal regulations in effect.

5.10.2 To market subjects: The detailed information for the units of their property, or those they represent, shall be communicated to them.

To owners of shared production units that are not however responsible for sending bids on the operating markets will be communicated the information of the outcome of the operating markets but not the information on the related offers associated with these markets shall be communicated to them.

To the owners of units affected by international physical bilateral contracts that are not, however, responsible for the communication of offers for the auctions of capacity to exchange those interconnections in Those that do not yet have a coordinated capacity allocation mechanism shall be communicated only to the outcome information of the technical restriction solution process on those interconnections.

The participants of explicit exchange capacity auctions will communicate the detailed information corresponding to the outcome of their bids.

Weekly, to owners or representatives of programming units associated with plants using autochthonous coal as fuel included in Annex II to Royal Decree 134/2010, of 12 February, and in the regulations The OS shall communicate the information corresponding to the operating plan for the following immediate electrical week (including 0.00 hours each Saturday and 24:00 p.m.). the following immediate Friday hours), according to the procedure of operation by which provides for the resolution of restrictions by security of supply. On a daily basis, the OS will make available to each SM, the possible updates of its weekly operating plan that need to be considered a function. the evolution of the forecast demand, the forecast of production of renewable origin and/or the over-sold inavailabilities affecting production units and/or network elements.

The OS daily will make available to each of the plants involved in the process of resolution of restrictions by guarantee of supply, the maximum volume of production that can be programmed as the difference between the maximum production volume fixed for each plant annually by Resolution of the Secretary of State for Energy and the energy actually produced in each of the plants from the first day of the corresponding year.

The OS will publish on a monthly basis the indicative plan for annual aggregate production of the plants referred to in Annex II to Royal Decree 134/2010 establishing the procedure for the resolution of restrictions by security of supply.

The OS shall make available to the market subjects holding of production units connected to the transport network the expected situation of the transport network, which shall include scheduled and fortuitous inavailabilities.

The OS will also make PSS/E (software for the analysis of electrical power systems) used for the analysis of technical restrictions of the Operational Base Program available to market participants. (PBF) before three working days from day D of operation.

5.10.3 To other subjects or entities participating in the operation programming process.

5.10.3.1 aggregating entity of the Energy Primary Emission Auction (EASEP): The OS will communicate to EASEP the updated information for Market Subjects in the production market and Programming Units Generic requirements for participation in the Primary Emission Auction, when the exercise of the purchase options is for physical delivery.

Monthly, EASEP shall communicate to the OS the relationship of the SM holders of primary emission purchase options, arising from the award in such auctions and the possible bilateral transfers of such options and the maximum power value associated with each buyer SM-SM seller, when the exercise of the options is by physical delivery.

On a daily basis, the OS will receive from EASEP the nomination of bilateral CBEP contracts associated with the exercise of the energy purchase options after the primary energy auctions, when the exercise of the options is by physical delivery.

5.10.3.2 To the distribution system operators: The information of the registered net power generation facilities of more than 50 MW and of the network facilities corresponding to the network under its control shall be communicated to them. management and the network observable by themselves. The generation information will be broken down per unit and will include the inavailabilities of groups. Information on the status of the network shall include the inavailabilities both programmed and fortuitous.

They shall also be provided with the information corresponding to the programming units that integrate the generation of production facilities with a registered net power of less than or equal to 50 MW in the production market. as the associated inavailabilities, if applicable.

The OS, in case of considering the inclusion of information that does not correspond to the area of the manager of a distribution network, will present to the National Energy Commission for approval by the Directorate General Energy Policy and Mines, your network proposal observable for this manager, including the explanatory statement for which the inclusion of this additional information is deemed necessary.

The OS, on a monthly basis, will make it easier for the distribution system operators to whom the transitional provision of Law 54/97 does not apply to them, the information concerning the subscription to the control centres of the facilities registered in such centres.

5.11 Measures Data Exchange: Information that is exchanged between the Main Electrical Measurement Concentrator and the OS SIOS.

5.12 Structural Information Management: For the proper functioning of the services and processes managed by the OS it is necessary to know and maintain information regarding the Market Subjects (SM), Programming Units (UP), Offer Units (UO) and Physical (UF), Bilateral Contracts, as well as a number of additional data and technical parameters required for the programming of the system operation. All this information is collected under the Structural Data name.

The treated data will be grouped as follows:

Market Subject Information: data of the subjects on the market and, where appropriate, of subjects acting on behalf of others.

Information on Programming Units and their relationship to the Offering Units used in the daily and intraday markets (including Generic Programming Units).

Information about programming units and their unbundling in physical units and equivalent physical units.

Different character information: Market types, drive types, security cards.

Various types of parameters, which affect the system.

Information about the different sessions that make up and define the different markets managed by the OS.

5.13 Display of structural information: Using the Web page of e-sios Market Subjects: https://sujetos.esios.ree.es, the SM will be able to access the confidential structural information corresponding to:

Programming Units (including Generic Programming Units) of your property or those that represent on the production market.

Physical units of your property or those that you represent in the production market.

Bilateral contracts involving the Programming Units of your property or those representing them on the production market.

Tension Control Service Delivery Units.

Also, through the e-sys public website: http://www.esios.ree.es, the SM will have access to the non-confidential structural information of other SM, corresponding to Programming Units, Physical Units, Regulation and Market Subjects of the Spanish electricity system.

5.14 Request for structural information modification: The modification of the structural information will be requested through the submission to the OS of the corresponding form available on the Web page of SM completed by the SM and accompanied by documentary support supporting the change.

Once the modification requested by the SM has been revised, the OS will communicate to the SM the date for which the requested change will be made, or, if necessary, the reason for the failure to do so.

6. Main power hub hub

The Main Hub of Electrical Measures is the system with which the OS manages the information of measures of the Spanish electrical system in accordance with the requirements laid down in the current legal regulations.

6.1 Content of the Main Electrical Measurement Concentrator database: The Main Hub database collects the data necessary for the management of the measurement system and will be at least the following:

a) The structural information resident in the Main Hub for borders of which the OS is in charge of reading:

Measurement Points.

Border points.

Measure point relationships with border points.

Counters.

Registrars.

Measure transformers.

b) The information of measures resident in the Main Hub for borders of which the OS is in charge of reading:

Time measures on measurement points.

Hourly data for measures calculated at the border points.

Hourly data for measures calculated in the Programming Units.

c) The structural information resident in the Main Hub for borders of which the OS is not in charge of the reading.

Client points types 1 and 2 (CUPS).

Customer measure point and special regimen types 3, 4, and 5.

d) The information of measures resident in the Main Hub for borders of which the OS is not in charge of the reading.

Hourly measures in customer CUPS types 1 and 2.

Hourly data for aggregate customer and special regime measures.

e) Additionally will have other information that will include at least:

Hourly data for measures calculated in the Programming Units.

Transport network losses.

Accumulated between activities.

Consumer profiles.

6.2 Access to the Information of the Main Hub of Measures: The OS manages access to the information of measures resident in the Main Concentrator according to the rules in force.

6.3 Free Access Information: The OS publishes various general reports made from the energy and inventory data available at the Main Hub.

This information is available from the Internet address of the OS (http://www.ree.es).

6.4 Information for measurement system participants: The information contained in the Main Electrical Measurement Concentrator is of a restricted nature, so that only each participant in the measurement system You can access data from the border points and/or aggregations from which you are involved.

Each participant in the measurement system may consult at least the following information residing in the Main Electrical Measurement Concentrator:

Time measures of the measurement points for which the OS is in charge of reading.

Time measures of the border points on which the OS is responsible for reading.

Setting up the border points of which the OS is in charge of reading.

Inventory of the measurement points from which the OS is in charge of reading.

Time measures in CUPS types 1 and 2.

Aggregations time measures types 3, 4, and 5.

The OS Internet address indicates the requirements and procedure to be followed for the use of such secure access to the Main Electrical Measurement Concentrator.

In addition, the OS will publish and exchange information of measures with the secondary concentrators according to the protocol defined in the Operation Procedure P.O. -10.4 and users of the Main Hub. The content and format of the different data of measures exchanged by the participants of the measurement system will be the latest version of the document "Ficheros for the Exchange of Measures Information". The wording of this document is the responsibility of the OS and will be available on its website.

6.5 Information Management: The Main Hub receives and manages the information exchanged between the border points of the Spanish electricity system in accordance with the requirements laid down in the legal regulations in effect.

6.6 High of border points, aggregations and other structural data: The high, low and/or modification of borders and aggregations along with the rest of structural data will be carried out according to the legislation in force the development documents "Ficheros for the exchange of Information on Measures" and "Information for holders of special regime installations" published on the OS website.

6.7 Main Concentrator Measures Receiving: Sending measurement data to the main hub will be done according to the means, protocols, and deadlines set forth in the current legislation.

6.8 Other considerations on the information of measures: Information on electrical measures will be available at the Main Concentrator for a minimum period of six calendar years from 1 January of the year. year following the date of each measure. Access to information more than two years old may require a special procedure.

7. SCO (Real-time operation control system)

The OS will need to receive all information from the transport and production facilities, including the generation under special regime and the observable network, in its real time Operation Control System. -as defined by the latter in the procedure of operation P.O. 8.1 by which the networks operated and observed by the OS are defined-that is precise to operate in the electrical system. To do this, the OS will have the corresponding Operation Control System Database (BDCO).

7.1 Production Facility Control Centre: The real time information relating to the production facilities of an ordinary and/or special system of net power exceeding 10 MW (or of those installations of power equal to or less than the power and forming part of a pool whose total amount of powers is greater than 10 MW) shall be captured by means of its own and provided to the OS through the connections with the generation control centres. For the purpose of this function these control centres of generation may be owned or of third parties representing the owner of the installation, in accordance with the regulations of the electrical sector in relation to the representation in the In the case of the participation in the potestative adjustment services (secondary regulation, tertiary regulation and management of deviations), the Iberian production market. The real-time information to be provided to the OS is specified in Annex II.

Each installation must be associated with a single control center. In the case where the production facility is integrated into a regulatory area, its control centre shall be the office of generation of the owner of that regulatory area.

7.2 Sending telemetry of production facilities less than or equal to 10 MW not forming part of a pool of more than 10 MW: All installations with installed power greater than 1 MW, or less than 1 MW but forming part of a pool of facilities of which the sum of powers is greater than 1 MW, shall send telemetry to the system operator, in real time, individually in the first case or aggregate in the second case. These telemedidas shall be transmitted by the owners of the facilities or by their representatives, and may be transmitted through the control centers of the distribution company if they so agree with it.

7.3 Content and structure of the SCO Database (BDCO): The information given below will be received in the SCO Database and the technical specifications that are also reflected.

7.4 Technical Requirements: The exchange of information in real time with the system operator will be performed using the standard communications protocol called ICCP-TASE2, through the exchange blocks of information defined as 1 and 2.

To carry out such an exchange of information, the Control Center communicating with the OS, will establish with each of the Centers of Control of the OS (Principal and Backing) two lines of communication of the type point to point, They are redundant with each other and dedicated exclusively to the exchange of this information. The technical characteristics of these 4 lines shall be identical and shall be completely dried and isolated from the internet. The system operator shall provide prior information to the establishment of the additional technical information by developing the above.

A control center may not share its control system or communications with the OS or personnel that constitute the closed operation shift with another control center. The operation shift shall be physically in the postal address communicated by the control centre to the OS.

The periodicity of the information to be exchanged for secondary regulation data shall be equal to or less than the master regulator cycle. The rest of the real-time information will be exchanged with a periodicity to be determined by the OS with each market subject, which in no case will exceed 12 seconds.

The OS will maintain the confidentiality of the information received. However, it may send to market subjects such information as they request, provided that such information is necessary to ensure the development of their functions as regards the operation of the market. system (voltage control, safeguard plans, emergency and replacement of the service) and the authorisation of the holder of the information generated.

7.5 Required Information: Information about the facilities listed below will be required:

Transport Network.

Observable network.

Generation Facilities.

Level of filling of reservoirs in pumping stations.

7.5.1 Definition and general criteria for standard collection of signals and measurements: In this procedure, the set of the elements associated with line, transformer, reactance, bars or coupling of bars that are accurate for maneuver and operation.

The (open/closed) state of the switches and dryers will be given by 2 bits. The rest of the signals will be given with one.

Given their uniqueness, the Synchronous and Condenser Compensators have been separately considered.

The following considerations have been taken into account in the way the signals are captured:

(a) Under the heading of transformers, they are considered even those of groups and consumption.

b) The following classification of the information has been performed to fetch:

Senalizations: Includes states (open/closed) or indications of devices that do not constitute failures or malfunctions. Included here are the topological states of the network (open/closed states of switches and dryers).

2. Measures: Includes analogue or digital measures for discrete numerical magnitudes of the installation (e.g. indication of transformer sockets).

7.5.2 Quality Validation Criteria for Active Power Generation Telemededas Received in Real Time: The information to be sent to the OS must have a minimum quality to establish compliance with the requirements set out in paragraphs 7.1 and 7.2 of this procedure.

In general, the determination of the validity of the real-time telemedidas received in the control centers of the OS will be carried out monthly determining its error with respect to the monthly accumulated of the time energies liquidable registered in the measuring equipment which complies with the provisions of the unified regulation of the measurement points of the electrical system, hereinafter the time measurement equipment.

It is defined for an installation/pool:

Integrated time frame for hour h (THIh): It is the integral time of the active power telemetry received in real time by the OS during the hour h, and therefore represents the energy produced by the installation/pool on the calculated h hour from the real-time telemedides.

Time Energy recorded for hour h (EHRh): It is the time energy recorded by the hourly measurement equipment calculated as the difference between the "exported energy" AS and the "imported energy" AE.

Total Hours (H): Total Set of Hours of Month m.

Logged Hours (I): Subset of the hours of the month m that is available for the registered liquidable time-energy measurement installation/pool.

The OS will consider that the quality of the telemedidas of the month m for a given installation/pool is valid only if each and every one of the following conditions are met:

For each settlement period referred to in the measures procedures, the OS shall inform the control centres of the non-compliance with the validation of the quality of the power telemetry or if it does not fulfil the conditions for the validation of the same. It shall also inform the NEC for the appropriate effects if these non-compliances occur for 3 months.

In addition, the OS will be able to carry out the verifications that it deems appropriate and are within its reach to ensure that the telemetry sent correspond to the profile of the productions actually made. In the case of identifying, at the discretion of the OS, fraudulent manipulation of the submitted telemetry, this situation will be brought to the attention of the CNE for the appropriate effects.

8. Other information subjects should send to the system operator

The OS will be responsible for collecting all other information regarding the operation of the system described in this section.

It is the responsibility of the producers, the single carrier and the distributors who are exceptionally operators of transport facilities, and of the distribution system operators to provide the information to the OS that it requires it and that it is derived from the operation of the premises of its property or under the scope of its management. Dispatch to the OS, by distributors (including those who are exceptionally holders of transport facilities) and the single carrier, of the list of special arrangements for facilities connected with their services shall be compulsory. networks.

In addition, the distribution system operators shall collect from the generators in particular their scope, the information necessary for the operation and send it to the OS with the frequency specified.

In case of not being able to dispose of some of this data, they will cause to the OS their best estimate of them.

The following data will be sent to the OS in the form of daily aggregated values, in three time horizons: At three days (day D + 4, where D is the programming day), before the 20th day of the month M + 1, and before on the 20th of the month of January of each year in order to maintain the statistical series relating to the energy balance sheets and the operation of the system, as well as for the provision of security coverage and analysis.

8.1 Data to be sent to the three days: The system subjects will provide the OS with all the data necessary for the elaboration of the official statistics, using the established information exchange channels. All values of the magnitudes listed below will be given with the greatest possible disaggregation in physical units.

• Daily production forecasts with hourly breakdown and by technologies of all special rate regime facilities that choose to cede electricity to the distribution company and are connected to the network of transport, in accordance with the provisions of the Transitional Provision Sixth of RD 661/2007

• Productions of thermal groups on alternator bars (b.a.)

• Productions of hydraulic power plants (CHCHH) (b.a.) if this measure is available.

• Maximum hydroelectric power that can be maintained by each hydraulic management unit for four consecutive hours.

• We consume own generation.

• Consumption of pumping stations.

• Cumulative energy available for generation in pumping stations.

• Fuel consumption in thermal power stations.

• Fuel stocks in thermal power plants.

• Hydrological information:

Hydroelectric reserves by reservoirs (in hm³ and MWh), taking into account the total capacity of the basin.

Spills.

• Incidents in the Transportation Network.

8.2 Data to be sent before day 20 of month M + 1: The monthly data indicated below will be sent to the OS before the 20th of the following month with the maximum level of disaggregation possible in physical units:

Gross daily production of thermal groups.

Hydroelectric daily production (CHCHH) (b.a.) if this measure is available.

Loss of turban in power plants.

We consume your own generation.

Consumption and production of pumping stations.

Accumulated energy available for generation in pumping stations.

Hydroelectric reserves by reservoirs (in hm³ and MWh), taking into account the total capacity of the basin.

Fuel entry in power plants/thermal groups (in tonnes and termine (PCI and PCS)) broken down by coal or fuel oil classes at the plants of this type.

Fuel consumption in power plants/thermal groups (in tonnes and termine (PCI and PCS)) broken down by coal or fuel oil classes at the plants of this type.

Fuel stocks in power plants/thermal groups (in tonnes and termine (PCI and PCS)) broken down by coal or fuel oil classes at the plants of this type.

Lower calorific power (PCI) and higher (PCS) of each of the fuels used in the generation.

Planned plan for reduced deliveries of guaranteed coal for the next twelve months (expressed in tonnes and in termine (PCI and PCS) and quantities of the current year actually delivered to date.

Foreseeable variations in the availability of production groups (thermal, hydraulic and pumping), as indicated in the procedure for establishing the maintenance plans of the production units production.

8.3 Annual data: The maximum capacity data for each reservoir, taking into account the total capacity of the basin, will be sent to the OS before the 20th of the month of January each year.

9. Statistics and public information regarding the operation of the system

The OS will publish the data that is later indicated on the operation performed, including the behavior of the transport network and the generation media.

9.1 Daily Information: The information that the OS will publish daily is as follows:

System load curve.

State of the hydroelectric reserves.

9.2 Information at three days: The OS will publish D + 4 the information of the production power balance broken down by technologies, corresponding to day D.

9.3 Monthly Information: The OS will publish the following information:

Electrical System Operation Statistics.

Availability of the generation thermal equipment.

Rate of unavailability of lines, transformers, and reactive energy compensation elements (reactances and capacitors) of the transport network.

Incident statistics.

Non-supplied power quality (ENS) and average interrupt time (TIM) service quality.

9.4 Annual information: The OS will publish the following information annually:

Electrical System Operation Statistics

Availability of the generator equipment.

Availability of the transport network.

Annual evolution of the shorting power at the knots of the transport network.

Quality of Service (ENS and TIM).

Seasonal thermal limits of the transport network.

In addition, the OS will keep historical and available strings available from:

Power installed on the system.

Energy generated by technologies.

Energy generated by the ordinary regime and by the special regime.

Pumping consumption.

International exchanges.

Demand for the electrical system.

Hydroelectric producible.

Hydroelectric reserves.

The availability rates for the generator equipment.

Transport network availability rates.

10. Analysis and incident information

10.1 Incidents: The events that define those incidents of the electrical system that are the object of information, in the scope of this procedure, by the subject holder of the installations affected or the responsible of the supply to the final consumers concerned are as follows:

(a) The loss of one or more transport facilities and/or other elements of the electrical system (generation and/or transport-distribution transformation) where this results in a violation of the operating criteria and electrical system security as set out in the relevant operating procedure or direct loss of supply.

b) Any other circumstances that result in:

a. Major damage to any of the elements of the electrical system.

b. Failure, degradation, or improper performance of the protection system, automatisms or any other system that does not require manual intervention by the operator.

c. Any act that may be suspected of being caused by electronic or physical sabotage, terrorism directed against the electrical system or its components with intent to disrupt the supply, or reduce the reliability of the electrical system in its set.

10.2 Communication to the System Operator: In the event that there is an incident as defined in the previous paragraph, the subject holder of the facilities or responsible for the supply concerned shall provide the OS with and within 2 hours the best information available on the causes and effects of the event. This information which constitutes the preliminary report of the incidence shall contain at least the aspects (a), (b), (c) and (d) listed in Annex 3 which are applicable.

The OS may, when it deems necessary, carry out additional consultations in order to clarify the content of the preliminary report, leaving the issuer of the same obligation to attend the consultation at that time or as soon as have the required additional information.

When the OS determines that the event constitutes a significant incident for the electrical system, it shall notify the holder or representative of the installation or the person responsible for the supply to the consumers. The final Such a subject shall submit a written report to the OS within a period not exceeding 15 working days from the request. This report shall review and complete the information referred to in the preliminary report (Annex 3) and include any actions identified by the subject to avoid or minimise the effect of similar incidents that may occur in the future.

10.3 System Operator Communication: When an incident occurs as defined in section 10.1, the OS will include the corresponding information in a "Daily Incident Party" that will be made available to the market subjects within 12 hours of the day following the occurrence of the market.

When the OS considers an incident of special relevance, it will produce a written report, once the final information of the report is available. This report shall include the measures to be taken to avoid repetition of the impact or the minimisation of its consequences in the event of a similar situation in the future. This report shall be forwarded to the subjects concerned, to the NEC and to the Ministry of Industry, Energy and Tourism, within a period not exceeding 60 working days after the occurrence of the incident.

Reports corresponding to the most significant incidents will be presented and analyzed at the meetings of the Incident Analysis Group that will convene the OS.

10.4 Joint Research: For those incidents in which the OS considers it necessary because of its importance or nature, it will propose as soon as possible the realization of a joint analysis with the other subjects involved or affected. The results of that analysis will be incorporated into the report that the OS produces on the incident.

11. System operator liability clearance information

11.1 Confidential Information: The confidential information relating to the settlements made by the OS is the one that communicates to the market subjects individually without access to the rest of the market of subjects.

All processes associated with this information are defined in the liquidations procedures.

11.2 Public Information: The aggregate settlement information made available to the subjects shall also be made available to the general public on the same day.

ANNEX I

Structural database content

General notes and abbreviations

As a general rule, data must be expressed in units of the international system unless otherwise expressly stated.

The impedance data should indicate the voltage to which they are referred or the base values, if any.

Annex I structure

This annex is organized according to the following structure:

1. Production system.

1.1 Embalses.

1.2 Central and regular hydraulic groups.

1.2.1 Installation general and hydraulic data.

1.2.1.1 Power stations less than or equal to 10 MW and not connected to the transport network.

1.2.1.2 Central to more than 10 MW of power or connected to the transport network.

1.2.2 Data for each group and primary regulatory teams.

1.2.2.1 Power stations less than or equal to 10 MW and not connected to the transport network.

1.2.2.2 Central over 10 MW of power or connected to the transport network.

1.2.3 Secondary regulation data (in the case of generation units participating in the secondary secondary regulation service).

1.2.4 Main data for voltage control equipment (in the case of power stations of more than 10 MW or connected to the transport network).

1.2.5 Supplementary voltage control service (in the case of connection to the transport network).

1.2.6 Data required for service replacement plans (in the case of power stations over 50 MW of power or connected to the transport network).

1.2.7 Data for group transformers (in the case of power stations of more than 50 MW or connected to the transport network).

1.2.7.1 Central over 50 MW of power not connected to the transport network.

1.2.7.2 Central attached to the transport network.

1.2.8 Data from the evacuation line or cable (in the case of power stations of more than 50 MW or connected to the transport network).

1.2.8.1 Central over 50 MW of power not connected to the transport network.

1.2.8.2 Central attached to the transport network.

1.2.9 Data from the Protections.

1.2.9.1 Power stations less than or equal to 50 MW that are not connected to the transport network.

1.2.9.2 Central over 50 MW of power or connected to the transport network.

1.2.9.3 Additional data in the case of power stations connected to the transport network.

1.2.9.3.1 Protections of the Central.

1.2.9.3.2 Protections associated with the link installation.

1.2.9.3.3 Telefiring against network contingencies.

1.3 Ordinary-speed thermal units.

1.3.1 General installation data.

1.3.1.1 Power stations less than or equal to 10 MW and not connected to the transport network.

1.3.1.2 Central to more than 10 MW of power or connected to the transport network.

1.3.2 Data for each generator.

1.3.2.1 Power stations less than or equal to 10 MW and not connected to the transport network.

1.3.2.2 Central over 10 MW of power or connected to the transport network.

1.3.3 Data for each group and primary regulatory teams.

1.3.3.1 Power stations less than or equal to 10 MW and not connected to the transport network.

1.3.3.2 Central to more than 10 MW of power or connected to the transport network.

1.3.4 Secondary regulation data (in the case of generation units participating in the secondary secondary regulation service).

1.3.5 Data for programming and tertiary regulation.

1.3.6 Main data for voltage control equipment (in the case of power stations of more than 10 MW or connected to the transport network).

1.3.7 Complementary voltage control service (in the case of connection to the transport network).

1.3.8 Data required for service replacement plans (in the case of power stations over 50 MW of power or connected to the transport network).

1.3.9 Data for group transformers (in the case of power stations of more than 50 MW or connected to the transport network).

1.3.9.1 Central over 50 MW of power not connected to the transport network.

1.3.10 Central connected to the transport network. Data from the evacuation line or cable (in the case of power stations of more than 50 MW or connected to the transport network).

1.3.10.1 Central over 50 MW of power not connected to the transport network.

1.3.11 Central connected to the transport network. Data from the protections.

1.3.11.1 Power stations less than or equal to 50 MW that are not connected to the transport network.

1.3.11.2 Central over 50 MW or connected to the transport network.

1.3.11.3 Additional data in the case of power stations connected to the transport network.

1.3.11.3.1 Protections of the Central.

1.3.11.3.2 Protections associated with the link installation.

1.3.11.3.3 Teleshooting at network contingencies.

1.4 Special Regime Units.

1.4.1 Photovoltaics larger than 50 kW and up to 1 MW of power.

1.4.2 Production facilities based on synchronous generators directly connected to the network larger than 1 MW of power or connected to the transport network or participating individually or in a grouped manner in the services system tuning.

1.4.2.1 Installation and group data.

1.4.2.1.1 General.

1.4.2.1.2 Additional data in the case of generators or pool of generators of more than 10 MW of total power-reception of the special regime plus non-reception-or connected to the transport network.

1.4.2.1.2.1 General.

1.4.2.1.2.2 Data for each group and primary regulatory teams.

1.4.2.1.2.3 Additional data in the case of connection to the transport network.

1.4.2.2 Secondary regulation data (in the case of generation units participating in the secondary regulation service).

1.4.2.3 Data for tertiary programming and regulation (in non-hydraulic groups and in case of participation in system adjustment services).

1.4.2.4 Data required for service replacement plans (in case of generators or pool of generators of more than 50 MW of total power or connected to the transport network).

1.4.2.5 Data for group transformers (in the case of generators or pool of generators of more than 50 MW or connected to the transport network).

1.4.2.5.1 Central or pool of more than 50 MW of total power not connected to the transport network.

1.4.2.5.2 Central attached to the transport network.

1.4.2.6 Data from the evacuation line or cable (in the case of generators or pool of generators of more than 50 MW or connected to the transport network).

1.4.2.6.1 Central or pool of more than 50 MW of total power not connected to the transport network.

1.4.2.6.2 Central attached to the transport network.

1.4.2.7 Data from the Protections.

1.4.2.7.1 Power stations less than or equal to 50 MW that are not connected to the transport network.

1.4.2.7.2 Central over 50 MW or connected to the transport network.

1.4.2.7.3 Additional data in the case of power stations connected to the transport network.

1.4.2.7.3.1 Central Protections.

1.4.2.7.3.2 Protections associated with the link installation.

1.4.2.8 Main data of the voltage control equipment for each group of plants of more than 10 MW of power or connected to the transport network.

1.4.2.9 Supplementary voltage control service for plants of more than 10 MW of power.

1.4.3 Wind, photovoltaic and in general installations all production facilities whose technology does not employ a synchronous generator connected directly to the network.

1.4.3.1 Features of each installation.

1.4.3.2 Network connection transformer data.

1.4.3.3 Network connection cable or line data.

1.4.3.4 Data from the Protections.

1.4.3.4.1 Installation Protections.

1.4.3.4.2 Protections associated with each generating unit (wind turbine, inverter, etc.).

1.4.3.4.3 Protections associated with the link installation.

1.4.3.5 Additional data for installations connected to a transport network.

1.4.3.5.1 Features of each installation.

1.4.3.5.2 Supplementary voltage control service.

1.4.3.5.3 Installation evacuation transformer data.

1.4.3.5.4 Data from the evacuation line or cable for each installation.

1.4.3.5.5 Network connection transformer data.

1.4.3.5.6 Evacuation line or cable data.

1.4.3.5.7 Data from the Protections.

1.4.3.5.7.1 Production installation protections.

1.4.3.5.7.2 Protections associated with the link installation.

1.4.3.5.7.3 Telefiring against network contingencies.

1.4.3.6 Main data for voltage control equipment for installations of more than 10 MW.

1.4.3.7 Supplementary permanent regime voltage control service for installations of more than 10 MW.

2. Transport network.

2.1 Substations.

2.2 Parks.

2.3 Lines and cables.

2.4 Transformers.

2.5 Active or reactive power control elements.

3. Consumer installations connected to the transport network.

4. Observable network.

4.1 Substations.

4.2 Parks.

4.3 Lines and cables.

4.4 Transformers.

4.5 Reactive power control elements.

1. Production System

1.1 Embalses.

• Name of the reservoir.

• Enterprise or business owners or concessionaires.

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Basin (river).

• Situation: Province, municipal term, place or land.

• Date of termination.

• Capacity in electrical energy (MWh).

• Historical series of partial contributions to the reservoir in monthly and weekly terms (m³).

• Maximum volume (hm³).

• Minimum volume (hm³).

• Curva cote of reservoir based on useful volume (minimum 3. degree).

• Maximum farm (m).

• Minimum farm (m).

• Ecological minimum flow to keep downstream.

• Regulatory Coefficient (days), defined as the ratio between the reservoir volume and the average annual contribution to the reservoir.

• Reservoir emptying time (hours) with turban at full load of the plant itself.

• Usage (Hydroelectric, Mixed).

• Operating constraints (detettions, waterings, etc.).

1.2 Central and regular hydraulic groups.

1.2.1 Installation general and hydraulic data.

1.2.1.1 Power stations less than or equal to 10 MW and not connected to the transport network.

• Name of the Central.

• Home of the Central: Municipality, postal code and province.

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Enterprise or exploitative companies:

• Name.

• NIF/CIF.

• Address.

• Basin (river) in which the plant is located.

• Associated reservoir.

• Substation/network connection park (Name, kV).

• Hydraulic Management Unit to which you belong, if any.

• Number of groups.

• Nominal power.

• Nominal flow (m³/s).

• Nominal net high (m).

1.2.1.2 Central to more than 10 MW of power or connected to the transport network.

• Name of the Central.

• Home of the Central: Municipality, postal code and province.

• Geographical location (requests for access to the transport network or distribution network with influence on the transport network): Planes (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

• Install UTM of the installation (give a reference point).

• Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 100 kV with influence over the network of the network). transport).

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Enterprise or exploitative companies:

• Name.

• NIF/CIF.

• Address.

• Basin (river) in which the plant is located.

• Hydraulic subsystem scheme.

• Associated reservoir.

• Substation/network connection park (Name, kV).

• Hydraulic Management Unit to which you belong, if any.

• Estimated unavailability rates for maintenance.

• Estimated rates of unavailability for other causes.

• Driving channel/pressure gallery (SI/NO). If yes, length (s) and diameter (s).

• Deposit or charging chamber (SI/NO). If yes, volume.

• Forced piping (SI/NO). If yes, length (s) and diameter (s).

• Number of groups.

• Nominal power.

• Nominal flow (m³/s).

• Nominal net high (m).

• Maximum turbination flow (m³/s).

• Minimum flow rate (m³/s).

• Maximum gross high (m).

• Minimum gross (m).

• Maximum net high (m).

• Minimum net high (m).

• Losses in flow-based pipelines.

• Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

• In the case of reversible or pumping groups:

• Nominal power.

• Nominal effective height (m).

• Nominal flow rate (m³/s).

• Maximum pump flow (m³/s).

• Minimum pumping flow (m³/s).

• Loss in aspiration and drive based on flow rate.

• Performance curves based on the pumped flow and the manometric height (alternative: Power tables for different manometric heights and different flow rates for each manometric height).

• Pump accumulation index (%), defined as the ratio of the electrical energy that can occur with the water accumulated by pumping and the energy consumed for its elevation.

• Additional data in the case of power stations connected to the transport network:

• Physical diagram (general scheme at site) of the link installation.

• One-to-one detail diagram of power equipment from the different generation units to the point of connection to the network.

• Unifilar installation protection scheme.

1.2.2 Data for each group and primary regulatory teams.

1.2.2.1 Power stations less than or equal to 10 MW and not connected to the transport network.

• Identification number in the RAIPEE (Administrative Registry of Electrical Power Production Facilities).

• On or off date (forecast if applicable).

• Apparent power in alternator borns (MVA).

• Nominal power in turban (MW).

• Nominal flow (m³/s).

• Nominal Jump (m).

• Net technical minimum, that is, in central bars (MW).

• In the case of reversible or pumping groups:

• Nominal power.

• Nominal effective height (m).

• Nominal flow rate (m³/s).

• Availability of primary regulation or speed regulation (SII/NO). If yes, indicate:

• Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

• Regulatory voluntary dead band (mHz): confirm that the adjusted value is zero.

• If you do not have your own primary regulation, provide documentation that provides proof of service delivery by another generating unit, indicating:

• Unit that provides the service.

• Confirmation of insensitivity not exceeding 10 mHz.

• Null voluntary dead band confirmation.

1.2.2.2 Central over 10 MW of power or connected to the transport network.

• Identification number in the RAIPEE (Administrative Registry of Electrical Power Production Facilities).

• On or off date (forecast if applicable).

• Type of turbine.

• Nominal speed (rpm).

• Nominal power in turban (MW).

• Nominal flow (m³/s).

• Nominal net high (m).

• Net technical minimum, that is, in central bars (MW).

• Maximum turbination flow (m³/s).

• Minimum flow rate (m³/s).

• Maximum gross high (m).

• Minimum gross (m).

• Maximum net high (m).

• Minimum net high (m).

• Losses in flow-based pipelines.

• Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

• In the case of reversible or pumping groups:

• Type of pump.

• Nominal power.

• Nominal speed (rpm).

• Nominal effective height (m).

• Nominal flow rate (m³/s).

• Maximum pump flow (m³/s).

• Minimum pumping flow (m³/s).

• Loss in aspiration and drive based on flow rate.

• Performance curves based on the pumped flow and the manometric height (alternative: Power tables for different manometric heights and different flow rates for each manometric height).

• Apparent power in alternator borns (MVA).

• Maximum full-load reactive (MVAr) generation in b.c.

• Maximum Technical Minimum Reactive Generation (MVAr) in b.c.

• Maximum load-reactive (MVAr) absorption in b.c.

• Maximum technical minimum reactive absorption (MVAr) in b.c.

• Nominal power factor.

• Capability as synchronous compensator (SI/NO).

• Absorbed power in operation as synchronous compensator (MW).

• Main turbine data and primary regulatory equipment.

• Turbine characteristics: manufacturer and model.

• Primary regulation availability or speed regulation (SI/NO).

• If you do not have your own primary regulation, provide documentation that provides proof of service delivery by another generating unit, indicating:

• Unit that provides the service.

• Confirmation of insensitivity not exceeding 10 mHz.

• Null voluntary dead band confirmation.

• In case of self-regulation, please indicate:

• Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ..

• Permanent statism:

• range of tuning.

• adjusted value.

• Telemetry capability of the adjusted value.

• Speed of power variation in MW/s, by frequency variation. Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

• Regulatory Voluntary Dead Band (mHz):

• range of tuning.

• adjusted value: Confirm that it is zero.

• Telemetry capability of the adjusted value.

• Regulator characteristics: Manufacturer, type of control (PID series compensator, resupply compensation using transient staticism, ...) and technology (hydraulic, electrohydraulic ...).

• Dynamic compensations: dynamic compensation transfer function (transient staticism, series compensator, ...). The range of each parameter and its setting or watchword value must be specified.

• The turbine-speed regulator block scheme and the corresponding values of the parameters that are represented in the schemas. This information will be provided as follows:

• Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

• or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect elaborated by the OS.

• In both cases, it must be accompanied by a validation report on the suitability of the model to represent the speed-turbine regulator according to the conditions set out in the document to the effect produced by the OS.

• Nominal generation (kV).

• Maximum generation voltage (kV).

• Minimum generation voltage (kV).

• Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis in machine base (Xd, Xq, X'd, X'q, X'' d, and X'' q. Symbology as standard UNE-EN 60034-4).

• Transitional and transient time-short constants for both direct and transverse axis (s) (T' d, T' q, T '' d and T '' q. Symbology as standard UNE-EN 60034-4).

• Transient and transient time constants open circuit for both direct and transverse axis (s) (T' d0, T' q0, T '' d0 and T '' q0. Symbology as standard UNE-EN 60034-4).

• Inertia Constant (s) of the rotating assembly: Electrical machine, exciter and turbine.

• Unsaturated leakage reactance (p.u.) (Xl).

• Saturation of machine to voltage 1.0 p.u., as shown in Figure 1.

• Saturation of machine to voltage 1.2 p.u., as shown in Figure 1.

• P-Q capacity curves (generator operating limits).

Figure 1. Saturation factors

1.2.3 Secondary regulation data (in the case of generation units participating in the secondary secondary regulation service).

• Regulatory zone to which you belong.

• Detailed information on the connection of the regulatory system with automatic generation control (AGC): characteristics of the signal signal, signal processing, limits, ...

• Maximum and minimum active power of regulation in b.a. (MW).

• Limitations on upload and load drop on MW/min: Adjustment range and delivery values for continuous ramp and step.

1.2.4 Main data of voltage control equipment (in the case of power stations of more than 10 MW or connected to the transport network).

• Brief description of the voltage regulator-excitation, which will include the name and type of the regulator.

• Block scheme, and the corresponding values of the parameters that are represented in the schemes, of the voltage regulators-excitation and of the power stabiliser system (PSS), if they have this device. This information will be provided as follows:

• Through a model included in the list of dynamic models supported by the OS, and which will be provided by the OS itself,.

• either through a model not included in the previous list provided it meets the characteristics and conditions set out in document to the effect elaborated by the OS,.

• In both cases, it must be accompanied by a validation report on the suitability of the model to represent the voltage regulator and the power stabiliser system (PSS), in accordance with the conditions set out in document to the effect developed by the OS.

1.2.5 Supplementary voltage control service (in the case of connection to the transport network).

• explicit declaration of compliance with mandatory stress control requirements set out in the operation procedure in which the Supplementary Tension Control Service or non-compliance is described, in its case, and its justification.

• In the case of reversible generator/motor groups, complete the data required in Annex 1 of PO 7.4 for each of the modes of operation.

• In the case of generating groups and reversible groups that have the capacity to function as synchronous compensators, the technical operating requirements shall be indicated, and the time required for their entry into operation.

• The possibility, if any, of telemandar the groups should be indicated so that the excitation slogan and/or the takes of the output transformer of the group can be modified from the office of generation of the subject holder or group representative, or from the appropriate control center.

1.2.6 Data required for service replacement plans (in the case of power stations over 50 MW of power or connected to the transport network).

• Stand-alone boot capacity.

• Own media to energize the auxiliary services needed for startup:

• Battery.

• Diesel Group.

• Other.

• Unifillar diagrams.

• Autonomy time (hours).

• Boot type:

• By remote control.

• Local operation (staff time availability will be indicated).

• The minimum guaranteed operating time continued at full load during the replenishment process (minimum water reserves).

• Possibility of performing a certain number of consecutive starts in a given time (in case of possible shots during the replacement process): Number of start and stop cycles, and duration of the cycle.

• Minimum number of groups to operate in parallel.

• Cascade startup capability for a set of groups.

• Operating capacity on island. Minimum market bag that is capable of feeding the group in island situation.

• Ability to remain stable after a disconnect from the outside network with sudden loss of full load, only feeding its own consumption.

1.2.7 Data for group transformers (in the case of power stations of more than 50 MW or connected to the transport network).

1.2.7.1 Central over 50 MW of power not connected to the transport network.

• Nominal power (MVA).

• Primary and secondary nominal voltage (kV).

• Connection group.

• Loss due to load (kW).

• Short circuit voltage (%).

• Homopolar impedance (% on machine base).

1.2.7.2 Central attached to the transport network.

• See transport transformers.

1.2.8 Data from the evacuation line or cable (in the case of power stations of more than 50 MW or connected to the transport network).

1.2.8.1 Central over 50 MW of power not connected to the transport network:

• See observable network lines and cables.

1.2.8.2 Central attached to the transport network:

• See transport lines and cables.

1.2.9 Data from the Protections.

1.2.9.1 Power stations less than or equal to 50 MW that are not connected to the transport network.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

• Minimum frequency protection: adjustments and compliance with the procedure for establishing Safety Plans.

• Overfrequency protection. Adjustments.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

• Short-circuit protection scheme in the network-main transformer section.

• Compliance with the General Protection Criteria.

1.2.9.2 Central over 50 MW of power or connected to the transport network.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

• Minimum voltage gels: Adjustments.

• Minimum frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection. Adjustments.

• Disarrest for over-speed. Firing value.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

• Short-circuit protection scheme in the network-main transformer section.

• Compliance with the General Protection Criteria.

• Unifilar installation protection scheme.

1.2.9.3 Additional data in the case of power stations connected to the transport network.

1.2.9.3.1 Protections of the Central.

• Protection of support for short circuits in the network: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with network protections.

• Protection from loss of synchronism: Indicate type of protection, number of slides for the shot and if the group is left over auxiliary.

• Over voltage: Adjustments.

• Reverse sequence protection: Indicate the coordination state of this protection with the single-phase reengagement and the network pole discordance relays.

• Sync conditions for coupling. Existing automatisms and settings.

1.2.9.3.2 Protections associated with the link installation.

• Protection of support for short circuits in the network: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with network protections.

• Short-circuit protection scheme in the network-generation transformer section. Compliance with the General Protection Criteria.

• Minimum voltage Rele: Adjustments.

1.2.9.3.3 Telefiring against network contingencies.

• Teleshooting capacity (SI/NO).

• Tele-firing time since the signal is received.

• Teleshooting logic and switches or selectors that includes.

1.3 Ordinary-speed thermal units.

1.3.1 General installation data.

1.3.1.1 Power stations less than or equal to 10 MW and not connected to the transport network.

• Designation of the plant.

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Enterprise or exploitative companies:

• Name.

• NIF/CIF.

• Address.

• Identification number in the RAIPEE.

• Home of the plant: municipality, postal code and province.

• On-or-off date (forecast, if any).

• Main and alternative fuels.

• Substation/network connection park (Name, kV).

1.3.1.2 Central to more than 10 MW of power or connected to the transport network.

• Designation of the plant.

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Enterprise or exploitative companies:

• Name.

• NIF/CIF.

• Address.

• Identification number in the RAIPEE.

• Home of the plant: Municipality, postal code and province.

• On-or-off date (forecast, if any).

• Main and alternative fuels.

• Substation/network connection park (Name, kV).

• Geographical location (access requests): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

• Install UTM of the installation (give a reference point).

• General configuration of the installation, indicating in its case characteristics of coupling between elements (e.g. gas turbines, steam turbines and alternators), as well as modularity and operating flexibility.

• Estimated unavailability rates for maintenance and other causes (annual and seasonal indices if applicable).

• Fuel consumption structure at startup: percentage in terms of consumption of each of the fuels used.

• Start consumption formula: Expression that allows this consumption to be calculated based on startup time (the elapsed since the last stop).

• Ct = C0 x (1-e-t/τ).

• Thermal consumption in cold start of each thermal unit and of the set (termine) C0.

• Net efficiency (net specific consumption) referred to PCI for each thermal unit and the set for different load regimes (kWh/kcal).

• Maximum primary and alternate fuel storage capacity (T).

• Power reserve (fuel storage park) (MWh) for primary and alternative fuels.

• Maximum number of operating hours at full load without external supply for primary and alternative fuels.

• Planned operating system.

• Additional data in the case of power stations connected to the transport network.

• Unifile diagram with all the components of the network link installation (access requests).

• Physical diagram (general scheme at site) of the link installation.

• One-to-one detail diagram of power equipment from the different generation units to the point of connection to the network.

• Unifile installation protection schemes up to the point of connection to the network, including auxiliary and transformer start-up services, if any.

1.3.2 Data for each generator.

1.3.2.1 Power stations less than or equal to 10 MW and not connected to the transport network.

• Apparent power installed (MVA).

• Net active power installed in b.c. (MW).

• Technical minimum in b.c. (MW).

• Maximum Technical Minimum Reactive Generation (MVAr) in b.a.

• Maximum technical minimum reactive absorption (MVAr) in b.a.

1.3.2.2 Central over 10 MW of power or connected to the transport network.

• In the case of generators dependent on each other, as the combined cycle members can be, also contribute the active and reactive power data, for the different possible configurations of operation permanent as short duration, for example, with off-duty steam turbine.

• Apparent power installed (MVA).

• Nominal generation (kV).

• Maximum generation voltage (kV).

• Minimum generation voltage (kV).

• Active power installed in b.a. (MW).

• Net active power installed in b.c. (MW).

• Active net active power of winter in b.c. (MW).

• Active net active power of summer in b.c. (MW).

• Technical minimum in b.a. (MW).

• Technical minimum in b.c. (MW).

• Special technical minimum in b.a. (MW).

• Special technical minimum in b.c. (MW).

• Time that the minimum special technician (h) can be maintained.

• Maximum load-reactive (MVAr) generation in b.a.

• Maximum Technical Minimum Reactive Generation (MVAr) in b.a.

• Maximum load-reactive (MVAr) absorption in b.a.

• Maximum technical minimum reactive absorption (MVAr) in b.a.

• Consumption of auxiliary services in b.a. at full load, active power (MW).

• Consumption of auxiliary services in b.a. at full load, reactive power (MVAr).

• Consumption of auxiliary services in a technical minimum, active power (MW).

• Consumption of auxiliary services in a minimum technical, reactive power (MVAr).

• Nominal power factor.

• Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis in machine base (Xd, Xq, X'd, X'q, X'' d, and X'' q. Symbology as standard UNE-EN 60034-4).

• transient and subtransient time-short constants for both direct and transverse axis (s). (T' d, T' q, T '' d and T '' q. Symbology as standard UNE-EN 60034-4).

• Transient and transient time constants open circuit for both direct and transverse axis (s). (T' d0, T' q0, T '' d0, and T '' q0. Symbology as standard UNE-EN 60034-4).

• Inertia Constant (s) of the rotating assembly: Electrical machine, exciter and turbine.

• Unsaturated leakage reactance (p.u.). (Xl).

• Saturation of machine to voltage 1.0 p.u., as shown in Figure 1.

• Saturation of machine to voltage 1.2 p.u., as shown in Figure 1.

• P-Q capacity curves (generator operating limits).

Figure 1. Saturation factors

1.3.3 Data for each group and primary regulatory teams.

1.3.3.1 Power stations less than or equal to 10 MW and not connected to the transport network.

• Primary regulation availability or speed regulation (SI/NO).

• If you do not have your own primary regulation, provide documentation that provides proof of service delivery by another generating unit, indicating:

• Unit that provides the service.

• Confirmation of insensitivity not exceeding 10 mHz.

• Null voluntary dead band confirmation.

• Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

• Regulatory Voluntary Dead Band (mHz):

• range of tuning.

• adjusted value: Confirm that it is zero.

• Telemetry capability of the adjusted value.

1.3.3.2 Central to more than 10 MW of power or connected to the transport network.

• In the case of multi-axis combined cycles, the information requested here will be sent separately for each gas and steam turbine.

• Gas turbine characteristics (if any): Manufacturer and model.

• Steam turbine characteristics (if any): Manufacturer and model.

• Primary regulation availability or speed regulation (SI/NO).

• If you do not have your own primary regulation, provide documentation that provides proof of service delivery by another generating unit, indicating:

• Unit that provides the service.

• Confirmation of insensitivity not exceeding 10 mHz.

• Null voluntary dead band confirmation.

• In case of self-regulation, please indicate:

• Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ...

• Permanent statism:

or range of tuning.

or adjusted value.

or telemetry capability of the adjusted value.

• Speed of power variation in MW/s, by frequency variation.

• Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

• Regulatory Voluntary Dead Band (mHz):

or range of tuning.

or adjusted value: Confirm that it is zero.

or telemetry capability of the adjusted value.

• Characteristics of the regulator (or regulators, if any): Manufacturer, type of control (PID series compensator, compensation for feedback via transient staticism,.) and technology (hydraulic, electrohydraulic.).

• Dynamic compensations: Dynamic compensation transfer function (transient staticism, series compensator,.). The range of each parameter and its watchword value must be specified.

• A block scheme of the regulator (or the regulators, if any) of the turbine-speed and the corresponding values of the parameters that are represented in the schemas. This information will be provided as follows:

or Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,.

or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect developed by the OS.

• In both cases, it must be accompanied by a validation report on the suitability of the model to represent the speed-turbine regulator, in accordance with the conditions set out in the document to the effect produced by the OS.

1.3.4 Secondary regulation data (in the case of generation units participating in the secondary secondary regulation service).

• Regulatory zone to which you belong.

• Detailed information of the connection of the regulatory system with the AGC: characteristics of the signal signal, processing of the signal, limits, ...

• Maximum and minimum active power of regulation in b.a. (MW) for different stable operating points, if applicable.

• Limitations on upload and load drop on MW/min: adjustment range and slogan values for continuous ramp and step.

1.3.5 Data for programming and tertiary regulation.

In the case of generators dependent on each other, as may be the combined cycle members, also contribute the requested data, for the different possible configurations of both permanent and of short duration, for example, start of the second gas turbine in case it is operating with a gas turbine and steam turbine.

• Boot time:

• cold (from boot order to ready for synchronization).

• Hot (from boot order to ready for synchronization).

• Minimum programming boot time.

• from synchronization to minimum technical (min).

• from synchronization to full load (min).

• Minimum programming stop time (from full load to disconnection) (min).

• Maximum up-ramp of tertiary regulation (MW in 15 min).

• Top down ramp of tertiary regulation (MW in 15 min).

1.3.6 Main data for voltage control equipment (in the case of power stations of more than 10 MW or connected to the transport network).

In the case of multi-axis combined cycles, the information requested here shall be sent separately for each gas and steam turbine generator.

• Brief description of the voltage regulator-excitation, which will include the name and type of the regulator.

• Block scheme, and the corresponding values of the parameters that are represented in the schemes, of the voltage-excitedess and the stabilizer system (PSS), if they have this device. This information will be provided as follows:

• Through a model included in the list of dynamic models supported by the OS, and which will be provided by the OS itself,.

• either through a model not included in the previous list provided it meets the characteristics and conditions set out in document to the effect elaborated by the OS.

• In both cases, it must be accompanied by a validation report on the suitability of the model to represent the voltage regulator and the power stabiliser system (PSS), in accordance with the conditions set out in document to the effect developed by the OS.

1.3.7 Complementary voltage control service (in the case of connection to the transport network).

• explicit declaration of compliance with the mandatory stress control requirements laid down in the procedure for describing the Complementary Tension Control Service of the transport network; defaults, if any, and their justification.

• In the case of generating groups and reversible groups that have the capacity to function as synchronous compensators, the technical operating requirements shall be indicated, and the time required for their entry into operation.

• The possibility, if any, of telemandar the groups should be indicated so that the excitation slogan and/or the takes of the output transformer of the group can be modified from the office of generation of the subject holder or group representative, or from the appropriate control center.

1.3.8 Data required for service replacement plans (in the case of power stations over 50 MW of power or connected to the transport network).

• SSAA power.

• Simplified schema and description of the SSAA power process in the following assumptions:

• Normal.

• Boot.

• Other Alternatives (Diesel/Battery/Otras).

• SSAA power supply.

• Consumption of auxiliary services in b.a. for group stop, active power (MW).

• Auxiliary services consumption in b.a. for group stop, reactive power (MVAr).

• Consumption of auxiliary services in b.a. for boot, active power (MW) Specify different possibilities: Cold start/Hot start.

• Auxiliary services consumption in b.a. for startup, reactive power (MVAr) Specify different possibilities: Cold start/Hot start.

• Stand-alone boot capacity.

• Own media to energize the auxiliary services needed for startup:

• Battery.

• Diesel Group.

• Other.

• Unifillar diagrams.

• Autonomy time (hours).

• Boot type:

• By remote control.

• Local operation (staff time availability will be indicated).

• The minimum guaranteed operating time continued at full load during the replacement process (minimum fuel reserves).

• Possibility of performing a certain number of consecutive starts in a given time (in case of possible shots during the replacement process): number of start and stop cycles, and duration of the cycle.

• Cascade startup capability for a set of groups.

• Reconnection of the group to the network.

• Minimum cold start time (since the SSAA power is received until ready for synchronization).

• Minimum hot start time (since power is received in the SSAA until ready for synchronization).

• Maximum stop time for the boot to be hot.

• Ability to remain stable after a disconnection from the outside network with sudden loss of full load, feeding only its own consumption. (YES/NO. Description).

• Operating capacity on island. Minimum market bag that is capable of feeding the plant in island situation.

• Sync conditions for coupling. Existing automatisms and settings.

• Other data.

• Characteristics of the engines and loads of auxiliary services and data on protections and adjustments, if any.

• Dependence on non-fuel supply infrastructures for the replacement process.

1.3.9 Data for group transformers (in the case of power stations of more than 50 MW or connected to the transport network).

1.3.9.1 Central over 50 MW of power not connected to the transport network.

• Nominal power (MVA).

• Primary and secondary nominal voltage (kV).

• Connection group.

• Loss due to load (kW).

• Short circuit voltage (%).

• Homopolar impedance (% on machine base).

1.3.9.2 Central attached to the transport network.

• See transport transformers.

1.3.10 Data from the evacuation line or cable (in the case of power stations of more than 50 MW or connected to the transport network).

1.3.10.1 Central over 50 MW of power not connected to the transport network.

See observable network lines and cables.

1.3.10.2 Central attached to the transport network.

• See transport lines and cables.

1.3.11 Data from the Protections.

1.3.11.1 Power stations less than or equal to 50 MW that are not connected to the transport network.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

• Minimum frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection. Adjustments.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

• Short-circuit protection scheme in the network-main transformer section.

• Compliance with the General Protection Criteria.

1.3.11.2 Central over 50 MW or connected to the transport network.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

• Auxiliary services, minimum voltage and/or minimum frequency relays: Indicating adjustments and for the minimum voltage relay phases in which it measures and trigger logic.

• Minimum group frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection (yes/no). Adjustments, if any.

• Disarrest for over-speed. Firing value.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

• Short-circuit protection scheme in the network-main transformer section.

• Compliance with the General Protection Criteria.

1.3.11.3 Additional data in the case of power stations connected to the transport network.

1.3.11.3.1 Protections of the Central.

• Protection of support for short circuits in the network: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with network protections.

• Auxiliary services, minimum voltage and/or minimum frequency relays: Indicating adjustments and for the minimum voltage relay phases in which it measures and trigger logic.

• Protection from loss of synchronism: indicate type of protection, number of slides for the shot and if the group is left over auxiliary.

• Over voltage: Adjustments.

• Reverse sequence protection: Indicate coordination status with the single-phase reengagement and network pole discordance relays.

• Sync conditions for coupling. Existing automatisms and settings.

1.3.11.3.2 Protections associated with the link installation.

• Protection of support for short circuits in the network: Indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with network protections.

• Short circuit protection scheme in the network-group transformer section. Compliance with the General Protection Criteria.

• Minimum voltage Rele: Adjustments.

1.3.11.3.3 Teleshooting at network contingencies.

• Teleshooting capacity (SI/NO).

• Type of telephoto (generation switch or fast-valve opening).

• End power and time of descent in cases of rapid reduction of load (fast-valve) and in general in non-instantaneous processes, such as in combined cycles, the response of the steam turbine to the telephoto partial gas turbines.

• Tele-firing time since the signal is received.

• Teleshooting logic and switches or selectors that includes.

1.4 Special Regime Units.

1.4.1 Photovoltaics larger than 50 kW and up to 1MW of power.

• Name of the center.

• Catastral number of the farm.

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Identification number in the RAIPRE.

• Home of the plant: Municipality, postal code and province.

• On-or-off date (forecast, if any).

• Distributor Company.

1.4.2 Production facilities based on synchronous generators directly connected to the network of more than 1MW of power or connected to the transport network or participating individually or in a grouped manner in the services system tuning.

1.4.2.1 Installation and group data.

1.4.2.1.1 General.

• Name of the center.

• Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Percentage of participation.

• Identification number in the RAIPRE.

• The offering unit to which you belong, if any.

• Home of the plant: Municipality, postal code and province.

• On-or-off date (forecast, if any).

• Central type.

• Grant date in Special Regime.

• Final year of the concession.

• Applicable rules.

• Distributor Company.

• Substation/network connection park (Name, kV).

• Type of installation according to Royal Decree 661/2007 or alternative regulations that are applicable.

• Number of groups.

• Fuel.

• For hydraulic groups:

• Jump (m).

• Maximum flow (m³/s).

• Regulatory regime (fluid, daily, weekly).

• Basin (river).

• Data from energy storage systems and support through complementary fuel in the case of manageable or manageable thermal power plants:

• Energy storage method (steam, oil, salts ...).

• Recovery time curves for stored primary energy.

• Stored primary energy loss curves.

• Type of support with complementary fuel, power supply with said fuel and autonomy thereof (in hours at rated power).

• Maximum power that can be provided by the maximum storage and power system that you can accumulate.

•% of the plant's over-dimension for storage.

• Apparent power installed (MVA) of the generating units.

• Welcome to the R.D. 661/2007 or alternative regulations that are applicable (MW).

• Non-host power (MW).

• Net active power and minimum technical (MW) available for the network: statistical distribution by tenths of powers or time energies poured into the network since the plant became operational or estimated.

• For generations: Maximum electrical consumption (MW) of the plant, including industrial consumption.

• Availability of primary regulation or speed regulation (SI/NO). If yes, please indicate:

• Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

• Regulatory voluntary dead band (mHz): confirm that the adjusted value is zero.

• If you do not have your own primary regulation, provide documentation that provides proof of service delivery by another generating unit, indicating:

• Unit that provides the service.

• Confirmation of insensitivity not exceeding 10 mHz.

• Null voluntary dead band confirmation.

1.4.2.1.2 Additional data in the case of generators or pool of generators of more than 10 MW of total power-reception of the special regime plus non-reception-or connected to the transport network.

1.4.2.1.2.1 General.

• Install UTM of the installation (give a reference point).

• Unifile diagram with all the components of the network link installation.

• Planned operating system (daily, weekly, seasonal cycles, if applicable).

• Estimated unavailability rates for maintenance.

• Estimated rates of unavailability for other causes.

• Maximum load-reactive (MVAr) generation at the point of connection to the network.

• Maximum technical minimum reactive (MVAr) generation at the point of connection to the network.

• Maximum load-reactive (MVAr) absorption at the point of connection to the network.

• Maximum technical minimum reactive absorption (MVAr) at the point of connection to the network.

• Hydraulic subsystem scheme.

• Associated reservoir.

• Hydraulic Management Unit to which you belong, if any.

• Driving channel/pressure gallery (SI/NO). If yes, length (s) and diameter (s).

• Deposit or charging chamber (SI/NO). If yes, volume.

• Forced piping (SI/NO). If yes, length (s) and diameter (s).

• Number of groups.

• Nominal flow (m³/s).

• Nominal net high (m).

• Maximum turbination flow (m³/s).

• Minimum flow rate (m³/s).

• Maximum gross high (m).

• Minimum gross (m).

• Maximum net high (m).

• Minimum net high (m).

• Losses in flow-based pipelines.

• Performance curves based on flow rate and net jump (alternative: Power tables for different net jumps and different flow rates for each net jump).

• In the case of reversible or pumping groups:

• Nominal power.

• Nominal effective height (m).

• Nominal flow rate (m³/s).

• Maximum pump flow (m³/s).

• Minimum pumping flow (m³/s).

• Loss in aspiration and drive based on flow rate.

• Performance curves based on the pumped flow and the manometric height (alternative: Power tables for different manometric heights and different flow rates for each manometric height).

• Pump accumulation index (%), defined as the ratio of the electrical energy that can occur with the water accumulated by pumping and the energy consumed for its elevation.

1.4.2.1.2.2 Data for each group and primary regulatory teams.

• Nominal tension (kV).

• Maximum generation voltage (kV).

• Minimum generation voltage (kV).

• Nominal speed.

• Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis in machine base (Xd, Xq, X'd, X'q, X'' d, and X'' q. Symbology as standard UNE-EN 60034-4).

• transient and subtransient time-short constants for both direct and transverse axis (s). (T' d, T' q, T '' d and T '' q. Symbology as standard UNE-EN 60034-4).

• Transient and transient time constants open circuit for both direct and transverse axis (s). (T' d0, T' q0, T '' d0, and T '' q0. Symbology as standard UNE-EN 60034-4).

• The inertia constant (s) of the rotating assembly: electric machine, exciter and turbine.

• Unsaturated leakage reactance (p.u.) (Xl).

• Saturation of machine to voltage 1.0 p.u., as shown in Figure 1.

• Saturation of machine to voltage 1.2 p.u., as shown in Figure 1.

• P-Q capacity curves (generator operating limits).

• Main turbine data and primary regulatory equipment.

• Turbine characteristics: Manufacturer and model.

• In case of self-regulation, indicate:

• Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ..

• Permanent statism:

or range of tuning.

or adjusted value.

or telemetry capability of the adjusted value.

• Speed of power variation in MW/s, by frequency variation. The insensitivity of the regulator (mHz) must not exceed 10 mHz.

• Regulatory Voluntary Dead Band (mHz):

or range of tuning.

or adjusted value: Confirm that it is zero.

or telemetry capability of the adjusted value.

• Regulator characteristics: Manufacturer, type of control (PID series compensator, resupply compensation using transient staticism,.) and technology (hydraulic, electrohydraulic.).

• Dynamic compensations: Dynamic compensation transfer function (transient staticism, series compensator,.). The range of each parameter and its current value must be specified.

• The turbine-speed regulator block scheme and the corresponding values of the parameters that are represented in the schemas. This information will be provided as follows:

• Through a model included in the list of dynamic models supported by the OS, and which will be provided by the OS itself,.

• or through a model not included in the above list provided that it meets the characteristics and conditions set out in document drawn up for the purpose by the OS.

• In both cases, it must be accompanied by a validation report on the suitability of the model to represent the speed-turbine regulator, in accordance with the conditions set out in the document to the effect produced by the OS.

• Type of turbine.

• Nominal power in turban (MW).

• Nominal flow (m³/s).

• Nominal net high (m).

• Net technical minimum, that is, in central bars (MW).

• Maximum turbination flow (m³/s).

• Minimum flow rate (m³/s).

• Maximum gross high (m).

• Minimum gross (m).

• Maximum net high (m).

• Minimum net high (m).

• Losses in flow-based pipelines.

• Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

• In the case of reversible or pumping groups:

• Type of pump.

• Nominal power.

• Nominal speed (rpm).

• Nominal effective height (m).

• Nominal flow rate (m³/s).

• Maximum pump flow (m³/s).

• Minimum pumping flow (m³/s).

• Loss in aspiration and drive based on flow rate.

• Performance curves based on the pumped flow and the manometric height (alternative: Power tables for different manometric heights and different flow rates for each manometric height).

1.4.2.1.3 Additional data in the case of connection to the transport network.

• Installation data at the point of connection to the network.

• Physical diagram (general scheme at site) of the link installation.

• Single-line diagram of detail with all the components of the link installation from the different generation units to the point of connection to the network.

• General configuration of the installation, indicating in its case characteristics of coupling between elements (e.g. gas turbines, steam turbines and alternators), as well as modularity and operating flexibility.

• For generations: See consumption facilities connected to the transport network.

• Unifilar installation protection scheme.

1.4.2.2 Secondary regulation data (in the case of generation units participating in the secondary secondary regulation service).

• Regulatory zone to which you belong.

• Detailed information of the connection of the regulatory system with the AGC: characteristics of the signal signal, processing of the signal, limits, ...

• Maximum and minimum active power of regulation in b.a. (MW) for different stable operating points, if applicable.

• Limitations on upload and load drop on MW/min: adjustment range and slogan values for continuous ramp and step.

1.4.2.3 Data for tertiary programming and regulation (in non-hydraulic groups and in case of participation in the electricity production market).

• Minimum programming boot time.

• from synchronization to minimum technical (min).

• from synchronization to full load (min).

• Minimum programming stop time (from full load to disconnection) (min).

• Maximum up-ramp of tertiary regulation (MW in 15 min).

• Top down ramp of tertiary regulation (MW in 15 min).

1.4.2.4 Data required for service replacement plans (in the case of generators or pool of generators of more than 50 MW of total power, or connected to the transport network).

• SSAA power (except CCHH).

• Simplified schema and description of the SSAA power process in the following assumptions:

• Normal.

• Boot.

• Other Alternatives (Diesel/Battery/Otras).

• SSAA power supply.

• Consumption of auxiliary services in b.a. for group stop, active power (MW).

• Auxiliary services consumption in b.a. for group stop, reactive power (MVAr).

• Consumption of auxiliary services in b.a. for boot, active power (MW) Specify different possibilities: Cold start/Hot start.

• Auxiliary services consumption in b.a. for startup, reactive power (MVAr) Specify different possibilities: Cold start/Hot start.

• Stand-alone boot capacity.

• Own media to energize the auxiliary services needed for startup:

• Battery.

• Diesel Group.

• Other.

• Unifillar diagrams.

• Autonomy time (hours).

• Boot type:

• By remote control.

• Local operation (staff time availability will be indicated).

• The minimum guaranteed operating time continued at full load during the replacement process (minimum fuel reserves).

• Possibility of performing a certain number of consecutive starts in a given time (in case of possible shots during the replacement process): number of start and stop cycles, and duration of the cycle.

• In the case of CCHH: Minimum number of groups to operate in parallel.

• Cascade startup capability for a set of groups.

• Reconnection of the group to the network (except CCHH).

• Minimum cold start time (since the SSAA power is received until ready for synchronization).

• Minimum hot start time (since power is received in the SSAA until ready for synchronization).

• Maximum stop time for the boot to be hot.

• Ability to remain stable after a disconnection from the outside network with sudden loss of full load, feeding only its own consumption. (YES/NO. Description).

• Operating capacity on island. Minimum market bag that is capable of feeding the plant in island situation.

• Sync conditions for coupling. Existing automatisms and adjustments (except CCHH).

• Other data (except CCHH).

• Characteristics of the engines and loads of auxiliary services and data on protections and adjustments, if any.

• Dependence on non-fuel supply infrastructures for the replacement process.

1.4.2.5 Data for group transformers.

1.4.2.5.1 Central or pool of more than 50 MW of total power not connected to the transport network.

• Nominal power (MVA).

• Primary and secondary nominal voltage (kV).

• Connection group.

• Loss due to load (kW).

• Short circuit voltage (%).

• Homopolar impedance (% on machine base).

1.4.2.5.2 Central attached to the transport network.

• See transport transformers.

1.4.2.6 Data from the evacuation line or cable.

1.4.2.6.1 Central or pool of more than 50 MW of total power not connected to the transport network.

• See observable network lines and cables.

1.4.2.6.2 Central attached to the transport network.

• See transport lines and cables.

1.4.2.7 Data from the Protections.

1.4.2.7.1 Power stations less than or equal to 50 MW that are not connected to the transport network.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

• Minimum frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection. Adjustments.

• Automatic replacement devices often: Confirm that they do not exist or that they are disabled.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

or Short-circuit protection scheme in the main network-transformer stretch.

or Compliance with the General Protection Criteria.

1.4.2.7.2 Central over 50 MW or connected to the transport network.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

• Minimum frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection. Adjustments.

• Automatic replacement devices often: Confirm that they do not exist or that they are disabled.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

or Short-circuit protection scheme in the main network-transformer stretch.

or Compliance with the General Protection Criteria.

• Minimum voltage gels: Adjustments.

• Disarrest for over-speed. Firing value.

1.4.2.7.3 Additional data in the case of power stations connected to the transport network.

1.4.2.7.3.1 Central Protections.

• Protection of support for short circuits in the network: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with network protections.

• Over voltage: Adjustments.

• Sync conditions for coupling. Automatisms and adjustments.

1.4.2.7.3.2 Protections associated with the link installation.

• Unifilar installation protection scheme Teleshooting against contingencies on the network.

• Teleshooting capacity (SI/NO).

• The tele-firing time since the signal is received (also indicate switch opening times).

• Teleshooting logic and switches or selectors that includes.

1.4.2.8 Main data of the voltage control equipment for each group of plants of more than 10 MW of power or connected to the transport network.

• For each group:

• Brief description of the voltage regulator-excitation, which will include the name and type of the regulator.

• Block scheme, and the corresponding values of the parameters that are represented in the schemes, of the voltage regulators-excitation and of the power stabiliser system (PSS), if they have this device. This information will be provided as follows:

• Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

• either through a model not included in the previous list provided it meets the characteristics and conditions set out in document to the effect elaborated by the OS.

In both cases, it must be accompanied by a validation report on the suitability of the model to represent the voltage regulator and the power stabiliser system (PSS), in accordance with the conditions set out in the document to the effect developed by the OS.

1.4.2.9 Supplementary voltage control service for plants of more than 10 MW of power.

• In the case of generating groups and reversible groups that have the capacity to function as synchronous compensators, the technical operating requirements shall be indicated, and the time required for their entry into operation.

• The possibility, if any, of telemandar the groups should be indicated so that the excitation slogan and/or the takes of the output transformer of the group can be modified from the office of generation of the subject holder or installation representative, or from the appropriate control center.

1.4.3 Wind, photovoltaic and in general installations all production facilities whose technology does not employ a synchronous generator connected directly to the network.

1.4.3.1 Features of each installation.

• Name of the installation.

• Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

• Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 100 kV with influence over the network of the network). transport).

• Owner company:

• Name.

• NIF/CIF.

• Address.

• Identification number in the RAIPRE.

• Date of granting of the Special Regime.

• On-or-off date (forecast, if any).

• Installation address: Municipality, postal code, and province.

• Park polygonal UTM coordinates, orchard, etc.

• Distributor Company.

• Installed power: Gross (MVA) and net active (MW). The apparent power must include all of the installation's reactive compensation.

• Substation/network connection park (Name, kV).

• Availability of primary regulation or speed regulation (SI/NO). If yes, please indicate:

• Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

• Regulatory voluntary dead band (mHz): confirm that the adjusted value is zero.

• If you do not have your own primary regulation, provide documentation that provides proof of service delivery by another generating unit, indicating:

• Unit that provides the service.

• Confirmation of insensitivity not exceeding 10 mHz.

• Null voluntary dead band confirmation.

• Planned operation regime of the installation:

• Hours of use (at full power) referred to on an annual and seasonal basis.

• Active power curve depending on the primary resource (wind speed in the case of wind plants, irradiance in the case of solar orchards, etc.) including indication of the maximum wind speeds for which wind turbines, panels, parabolic catchers, etc. stop providing power.

• Compliance with voltage gap response requirements (yes/no).

• Data for each model of each generating unit (wind turbine, inverter, etc.):

• Number of generating units of the same model.

• Manufacturer and model.

• Technology: Squirrel cage induction or asynchronous machine, variable-slip induction or asynchronous machine, induction machine or double-fed asynchronous, wind turbines with total power conversion (full converter), investors, etc. In case of other technologies not indicated, provide brief description.

• Active power installed on each generating unit (kW).

• Apparent power installed from each generating unit (kVA) including, if applicable, its internal reactive compensation.

• Reactive power curve depending on the active power considering, where appropriate, the internal reactive compensation of each generating unit.

• In the case of installations of more than 10 MW or connected to the transport network, a model shall be provided for the installation which must describe its dynamic behaviour from the point of view of the electrical system to which it is connected, in the face of any disturbance in the same. This information will be provided as follows:

• Through a model included in the list of dynamic models supported by the OS, and which will be provided by the OS itself, or through a model not included in the previous list as long as it meets the characteristics and conditions set out in document for the effect produced by the OS.

In both cases, a validation report of the suitability of the model shall be accompanied by the conditions set out in the document to the effect developed by the OS.

• Reactive compensation in bornas of each generating unit excluding, if applicable, internal compensation:

• Static compensation and reactive power dynamics (nominal values in MVAr).

• Possibility of regulation.

• Reactive compensation in bornas of the installation excluded, if any, the one associated with each generating unit:

• Static compensation and/or total reactive power dynamics (nominal value in MVAr).

• Possibility of regulation.

• Condenser Batteries (yes/no).

• Total power (MVAr).

• Number of steps.

• Type of control of the steps.

or Power Electronics-based Continuous Clearing or Regulatory Systems (FACTS) (yes/no).

• Total power installed (MVAr).

1.4.3.2 Network connection transformer data.

• Enterprise or proprietary companies:

• Name.

• NIF/CIF.

• Address.

• Nominal power (MVA).

• Primary and secondary nominal voltage (kV).

• Connection group.

• Loss due to load (kW).

• Short circuit voltage (%).

• Homopolar impedance (% on machine base).

1.4.3.3 Network connection cable or line data.

• See observable network lines and cables.

1.4.3.4 Data from the Protections.

1.4.3.4.1 Installation Protections.

• Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the park (yes/no). Indicate particularities, if any.

• Minimum voltage Rele: Indicate phases in which it measures and adjustments.

• Over voltage: Adjustments.

• Minimum frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection. Adjustments.

• Automatic replacement devices often: Confirm that they do not exist or that they are disabled.

1.4.3.4.2 Protections associated with each generating unit (wind turbine, inverter, etc.).

• Minimum voltage Rele: Indicate phases in which it measures and adjustments.

• Over voltage: Adjustments.

• Minimum frequency protection: Adjustments and compliance with the procedure for establishing the Safety Plans.

• Overfrequency protection. Adjustments.

• Automatic replacement devices often: Confirm that they do not exist or that they are disabled.

• Disarrest for over-speed in your case. Firing value.

1.4.3.4.3 Protections associated with the link installation.

• Minimum voltage Rele: Adjustments.

• In case the critical time in the connection node to the network is less than 1 second, indicate:

• Short-circuit protection scheme in the network-main transformer section.

• Compliance with the General Protection Criteria.

1.4.3.5 Additional data for installations connected to the transport network.

1.4.3.5.1 Features of each installation.

• Physical diagram (general scheme at site) of the link installation.

• One-to-one detail diagram of power equipment from the different generation units to the point of connection to the network.

• Short-circuit intensity contributed by the installation to a short circuit at the point of connection to the network.

• Report with maximum guaranteed harmonic distortion content:

• well through an installation-level forecast, as indicated in IEC 61000-3-6, of the voltage and intensity harmonics (magnitude and order of 2 to 50) and the harmonic distortion rate.

• well perform measures at the level of installation of the harmonics of tension and intensity (magnitude and order of 2 to 50) and the rate of harmonic distortion, in minimum periods of one week as indicated in IEC 61000-4-30.

• Level of voltage (kV) of the internal network of connection of the generating units.

• Unifilar protection scheme for the production installation and the link installation.

1.4.3.5.2 Installation transformer data (if this is the network connection transformer, see point 1.4.3.5.4).

• Nominal power (MVA).

• Primary and secondary nominal voltage (kV).

• Connection group.

• Loss due to load (kW).

• Short circuit voltage (%).

• Homopolar impedance (% on machine base).

1.4.3.5.3 Data from the line or escape cable of each installation (if this is the line or cable connection to the transport network, see point 1.4.3.5.6).

• See observable network lines and cables.

1.4.3.5.4 Network connection transformer data.

See transport transformers.

1.4.3.5.5 Data from the evacuation line or cable (if any).

See transport lines and cables.

1.4.3.5.6 Data from the Protections.

1.4.3.5.6.1 Production installation protections.

Sync conditions for coupling. Automatisms and adjustments.

1.4.3.5.6.2 Protections associated with the link installation.

• Short circuit protection scheme in the main network-transformer section. Compliance with the General Protection Criteria.

• Protection of support for short circuits in the network: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with network protections.

1.4.3.5.6.3 Telefiring against network contingencies.

• Teleshooting capacity (SI/NO).

• The tele-firing time since the signal is received (also indicate switch opening times).

• Teleshooting logic and switches or selectors that includes.

1.4.3.6 Main data for voltage control equipment for installations of more than 10 MW.

The OS will be able to request a description of the physical implementation of the permanent regime voltage control set in the installation showing how the fundamental dynamics of the individual generators participate. (investors in their case) as well as the dynamics of the control at the point of connection to the network of the production facility. In this case, the corresponding block schemes will be contributed with the corresponding values of the parameters that are represented in the schema.

2. Transport network.

2.1 Substations.

• Name of the substation.

Home: Municipality, postal code, and province.

• On-or-off date (forecast, if any).

2.2 Parks.

• Name of the substation.

• Tension (kV).

• Park UTM (give a reference point).

• Configuration.

• Owner of each position.

• Owner of each bar.

• Maximum allowable short circuit intensity of the various elements of the park.

• Nominal cutting power in circuit breakers.

• Uniform protection and measurement schemes.

• On-or-off date (forecast, if any).

• Protections:

• Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

• Short circuit protection scheme. Critical time contemplated.

• Support protection against external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

• Unifilar protection and measurement scheme.

• Minimum voltage gels: trigger logic and switches on which they operate.

2.3 Lines and cables.

• Name of the line.

• End parks of the line.

• Number of circuits and length in km.

• Owner or set of owners and participation in your case.

• On-or-off date (forecast, if any).

• Nominal operation and maximum service voltage of each circuit (and projected in case of variation) for each of the circuits or sections thereof with homogeneous characteristics.

• Direct sequence resistance (Ω).

• Direct sequence reactance (Ω).

• Direct Sequence Susceptance (μS).

• Homopolar sequence resistance (Ω).

• Homopolar sequence reactance (Ω).

• Homopolar sequence susceptance (μS).

• Additional data for transport network lines and cables only, as such:

• Seasonal values (summer, autumn, winter, spring) of:

• Nominal line transport capacity (MVA).

• limiting element.

• Permanent thermal limit of the driver (MVA).

• Maximum operating temperature of the driver (° C).

• Length in shared supports, if any (in a same ditch or gallery, if isolated cables are treated).

• Setting up the line.

• Conductor: Name/material/total section (mm2).

• Land tables: Denomination/material/total section (mm2).

• Setting up grounding (for isolated cables only): Type/length of sections.

• Number of drivers per phase.

• Protections:

or Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

or Short-Circuit Protection Scheme. Critical time contemplated.

o Protection of support for short-circuit external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

or Unifilar protection and measurement scheme.

or Network or telecoupling devices: existence and adjustments.

or Synchronism Gels: existence and settings. Break down, if necessary, between monitoring of reengagement and voluntary closure.

or Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

or Automatic Reorder Devices: Indicate if they exist and describe their behavior, if any.

or Rehook:

■ Rehitler position under normal operating conditions (not active/mono/mono + tri/tri).

■ Extremism that throws tension into three-phase reengagement.

■ Synchronism monitoring in triphasic reengagement (SI/NO).

or Teleshot:

■ Telefiring at voluntary opening (SI/NO).

■ Telefiring at switch aperture (SI/NO).

2.4 Transformers.

Transformers that feed loads and those connected to non-observable networks are treated under the heading "Consumer installations".

• Name of the substation and park of the highest voltage level.

• Order number.

• Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

• Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 100 kV with influence over the network of the network). transport).

• Physical diagram (general scheme at site) of the link installation.

• One-to-one detail diagram of the power equipment of the network link installation.

• Owner or set of owners and participation in your case.

• On-or-off date (forecast, if any).

• Type of transformer: configuration (three-phase or bench), autotransformer/transformer, magnetic circuit (n. number of columns).

• Nominal power of each winding (MVA).

• Cooling type.

• Nominal tension of each winding (kV).

• Maximum service voltage of each winding (kV).

• Connection group.

• Type of regulation in each winding: load or vacuum, automatic regulation (SI/NO) and block before collapse (Yes/NO).

• Number of shots in each winding and extension of takes (%). Number of the main shot (corresponding to the nominal voltage of the transformer), the usual intake (vacuum regulation) and the maximum intake. For generation transformers, in addition, numbers of the usual take (vacuum changer) or of the most frequent (shift-in-load-changer).

• The primary and secondary transformation relationship for each of the possible transformer or autotransformer takes.

• Loss in transformer:

■ Losses due to load between each winding pair (kW).

■ Empty losses (kW).

■ Losses in auxiliary equipment (kW).

• Short circuit tension between each pair of windings in the main, maximum and minimum takes in their case (%). Main takeaway in generation transformers.

• Homopolare impedances between each winding and its neutral borne in the main, maximum and minimum takes in its case (% on a machine basis). Main takeaway in generation transformers.

• Additional data for transformers in the transport network and the observable network, as such:

or Protections:

■ Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

■ Short circuit protection scheme. Critical time contemplated.

■ Protection of support against external circuits: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with the protection of other elements.

■ Unifilar protection and measurement scheme.

or Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

or For observable network transformers:

■ An explicit declaration of compliance with the mandatory stress control requirements laid down in the 7.4 operation procedure in which the Supplementary Tension Control Service or non-compliance is described; where appropriate, and their justification.

2.5 Active or reactive power control elements.

• Name of the substation and park in which it is located.

• Type (Reactance or Capacitor or Dynamics; information will be replicated in case of elements with inductive and capacitive compensation possibilities).

• Order number.

• Nominal tension (kV).

• Nominal power (MVAr).

• Connection Tension (kV).

• Situation (transformer bars or tertiary).

• Owner.

• Iron losses (kW).

• Copper losses (kW).

• Total additional losses included (kW).

• Connection type.

• Number of steps.

• For each step:

• No. of blocks.

• Nominal power of each block (MVAr).

• On-or-off date (forecast, if any).

• In the case of FACTS devices (Flexible AC transmission system): the characteristics of the transformer of connection to the network, nominal voltage of the compensating equipment, characteristic V/I of the compensation system, and scheme of blocks with the corresponding values of the parameters that are represented in the schema. This information will be provided as follows:

or Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself.

or through a model not included in the above list provided that it meets the characteristics and conditions set out in the document drawn up for the purpose by the OS.

• In both cases, it must be accompanied by a validation report on the suitability of the model to represent the FACTS device, in accordance with the conditions set out in the document to the effect developed by the OS.

• In the case of active power control elements, the associated data will be provided based on the corresponding configuration.

• Protections:

or Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

or Short-Circuit Protection Scheme. Critical time contemplated.

o Protection of support for short-circuit external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

or Unifilar protection and measurement scheme.

• Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

or Automatic Reorder Devices: Indicate if they exist and describe their behavior, if any.

3. Consumer installations connected to the transport network.

As far as processors are concerned, the present epigraph is applicable to those who feed loads and those connected to unobservable networks. The observable network transformers are dealt with in the Network Observable chapter.

• Designation of the installation.

• Order number.

• Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

• Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 100 kV with influence over the network of the network). transport).

• One-to-one detail diagram of the power equipment of the network link installation.

• Owner.

• Installation address. Municipality, postal code and province.

• On-or-off date (forecast, if any).

• Load type (distribution network, auxiliary services, consumer).

• Substation and network connection park (Name, kV).

• General installation configuration, modularity, and operating flexibility.

• Estimated unavailability rates for maintenance and other causes (annual and seasonal indices if applicable).

• Planned operating system. Consumption forecast (MW, MVAr) at the point of network connection in significant time and seasonal situations, as well as annual estimated energy.

• Network connection transformer.

• Type of transformer: configuration (triphasic or bank), autotransformer /transformer, magnetic circuit (number of columns)

• Nominal power of each winding (MVA).

• Nominal and maximum service voltage of each winding (kV).

• Connection group.

• Loss due to load (kW).

• Short circuit voltage (%).

• Homopolar impedance (% on machine base).

• Main characteristics of the load composition (if applicable):

or Proportion of induction engines (% on total load).

• From the rest of the load that does not correspond to induction engines:

or Equivalent to constant power load (%).

or Equivalent to constant impedance load (%).

or Equivalent to constant intensity load (%).

• Tension control:

or explicit declaration of compliance with the mandatory stress control requirements laid down in the procedure for describing the Complementary Tension Control Service or non-compliances, if any, and justification.

• Additional information for arc furnaces in alternating current:

or High Tension (kV).

or Medium Tension (kV).

or Low Tension (kV).

or oven power (MVA).

or Reactive compensation: type, rated power (MVAr), and connection sweep.

or Short circuit impedance and power of the MT-BT transformers.

or Impedance of the serial reactance, if any.

or Impedance of the low voltage cables, the electrode, and any additional ones that may exist from the point of connection to the network to the electrode.

or Cos φ of the previous impedances.

• Additional information for arc furnaces in continuous stream:

or High Tension (kV).

or Medium Tension (kV).

or Low Tension (kV).

or rectification power (MW).

or Number of pulses.

or Reactive compensation: type, rated power (MVAr), and connection sweep.

or Short circuit impedance and power of the MT-BT transformers.

or Impedance of the low voltage cables, the electrode, and any additional ones that may exist from the point of connection to the network to the electrode.

o Cos φ of the impedance of the low voltage cables.

or Harmonic Filters: A harmonic order that each filter and unit power (MVAr) is tuned to.

• Additional information for high-speed trains (TAV) and unbalanced loads:

or Nominal Tension (kV).

or Nominal power (MVA) and phases between which it loads.

o Characteristics of the imbalance compensation team, if any.

• Additional information for induction engines of more than 10 MW or loads with special dynamic characteristics, in the face of the voltage or frequency, not indicated above, if they are not characterised by the main characteristics of the load composition defined above and if the OS considers it relevant:

• A model will be provided that should describe the dynamic behavior of the installation from the point of view of the electrical system to which it connects, in the face of any disturbance in it. This information will be provided as follows:

or Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect developed by the OS.

• In both cases, a validation report of the suitability of the model to represent this type of loads should be accompanied, in accordance with the conditions set out in the document to the effect produced by the OS.

• Line or cable connection to the Transport Network (if applicable):

or Number of circuits and length in km.

or Owner or set of owners and participation in your case.

or On or off date (forecast, if any).

or nominal operating voltage and maximum service of each circuit (and projected in case of variation) for each circuit or tranches thereof with homogeneous characteristics.

or Direct Sequence Resistance (Ω).

or Direct Sequence Reactance (Ω).

or Direct sequence (μS) Susceptance.

or Homopolar Sequence Resistance (Ω).

or Homopolar Sequence Reactance (Ω).

or Homopolar Sequence Susceptance (μS).

• Protections:

or Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

or Short-Circuit Protection Scheme. Critical time contemplated.

o Protection of support for short-circuit external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

or Unifilar protection and measurement scheme.

or Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

or Frequency Relay Features and Tuning:

or Frequency: adjustment range, stagger, and adjustment value (Hz).

or Timing: Adjustment Range and Adjustment Value (s).

or Reorder mechanism (SI/NO). If yes, confirm your non-enablement.

or Minimum and maximum loads disconnected by the relay (MW).

o Identification of the switch on which the relay acts.

or Automatic reorder devices not associated with the frequency relay: Indicate if they exist and describe their behavior, if any.

4. Observable network.

4.1 Substations.

• Name of the substation.

Home: municipality, postal code and province.

• On-or-off date (forecast, if any).

4.2 Parks.

• Name of the substation.

• Tension (kV).

• Settings. Single-line detail.

• Owner of each position.

• Owner of each bar.

• On-or-off date (forecast, if any).

4.3 Lines and cables.

• Line name.

• End parks of the line.

• Circuit number and length in km.

• Owner or set of owners and participation in your case.

• On-or-off date (forecast, if any).

• Direct sequence resistance (Ω).

• Direct sequence reactance (Ω).

• Direct Sequence Susceptance (μS).

• Homopolar sequence resistance (Ω).

• Homopolar sequence reactance (Ω).

• Homopolar sequence susceptance (μS).

• Additional data in case of lines and cables of the observable network, as such:

or Nominal line transport capacity (MVA), seasonal values (summer, fall, winter, spring).

4.4 Transformers.

• Transforms connected to the transport network are dealt with in the "Transport Network" chapter.

4.5 Reactive power control elements.

This item is applicable to elements directly connected to knots of the observable network.

• Name of the substation and park in which it is located.

• Type (Reactance or Capacitor or Static).

• Order number.

• Owner.

• On or off date (forecast if applicable).

• Nominal tension (kV).

• Nominal power (MVAr).

ANNEX II

Information to be sent to the OS in real time

Transport network and observable network

Switches

Senalizations

Positiven of the switches.

Sectors

Senalizations

Position dand sectionators.

Lines

Measures

Poteactive ncia (MW).

reactive power (MVAr).

Transformers (includes transport, generation and consumption), reactances and capacitors

Senalizations

Posicion of the switches

Position of the dryers

Automatic voltage control (transformers only)

Measures

Transformer primary active power (MW)

Transformer Primary Reactive Power (MVAr)

Transformer secondary active power (MW)

Transformer Secondary Reactive Power (MVAr)

Transformer tertiary active power (MW)

Transformer Tertiary Reactive Power (MVAr)

Take the regulator into load (transformers only)

Vacuum regulator position (if any and only transformers)

Reactive Power in Reactances (MVAr)

Coupling of bars

Senalizations

Position of the switches

Position of the dryers

Measures

Active Power (MW)

Reactive Power (MVAr)

Bars

Measures

Tension by bar section (kV)

Frequency metric on selected selected bars (Hz)

Thermal groups and hydraulic groups with regulatory capacity

Senalizations

Group Regulatory Local/Remote Status

Type of regulation, control/no control

Thermal groups in ordinary regime

Senalizations

Group Switch Position

Measures

Machine transformer (MW) high active power

Machine Transformer High Reactive Power (MVAr)

Machine transformer (MW) low active power

Low Reactive Power of Machine Transformer (MVAr)

Generation Voltage

Hydraulic groups in ordinary regime

Senalizations

Group Switch Position

Measures

Machine transformer (MW) high active power

Machine Transformer High Reactive Power (MVAr)

Central Bar Voltage Measurement (kV)

Pure pumping groups

Senalizations

Group Switch Position

Measures

Machine transformer (MW) high active power

Machine Transformer High Reactive Power (MVAr)

Central Bar Voltage Measurement (kV)

Reservoir drops

Special-regime generation facilities to which paragraph 7.1 applies to them

Senalizations

Connection status of the installation with the distribution or transport network of each of the power generation units exceeding 10 MW.

Measures

Active power produced (MW) for each of the power generation units exceeding 10 MW and the pooled active power of the power generation units equal to or less than 10 MW

Reactive power produced/absorbed (MVAr) for each of the power generation units exceeding 10 MW and the reactivated power of the power generation units equal to or less than 10 MW.

Central bar voltage measurement (kV) for power generation units exceeding 10 MW.

In the case of wind farms: wind speed (intensity and direction) (m/s and sexagesimal degrees) and temperature (° C).

Special-regime generation facilities to which paragraph 7.2 applies

Measures

Active power produced (MW)

Synchronous compensators

Senalizations

Connection Status

Analog measures

Reactive Power (MVAr)

Voltage (kV)

ANNEX III

INCIDENT REPORT

The contents to be included in the report on an incident are those that are applicable to the following:

a) The date and time of the incident.

b) Transport facilities and/or electrical system elements directly involved in the incident (and not only affected by the incident), duration of loss of service (with indication of whether it is data or forecast)

c) Direct impact to final consumers, for each border point with the affected transport network: location, type and number of customers affected, demand (in MW) interrupted, energy not supplied (in MWh) and duration of the interruption (with indication of whether it is data or forecast). In addition, the details of the replacement of the service, indicating the powers and the interruption times for each stage of the replacement, shall be given as detailed as possible.

d) Affecting to generation: affected group or groups, interrupted generation (MW) and duration of disruption (with indication of whether it is data or forecast). Damage reported.

e) Description of the incident (chronology of events, action of protection systems and automatisms, ...).

P. O. -14.4 Collection rights and payment obligations for system adjustment services

1. Object

The purpose of this procedure is to determine the payment entitlements and the payment obligations arising from the adjustment services of the system for the purposes of the settlement process, as set out in the Operation 14.1 and in the Operation Procedures relating to those services.

System tuning services include:

(a) The resolution of supply security restrictions as set out in P.O. 3.10.

b) The resolution of technical restrictions of the PBF, the intraday and real-time market established in the Operation Procedure 3.2.

c) The generation-consumption deviation resolution set forth in Operation Procedure 3.3.

d) The secondary regulatory services provided in the Operation Procedure 7.2.

e) Complementary tertiary regulation services established in Operation Procedure 7.3.

f) The deviations between the measurement in central bars and the program.

2. Scope

This procedure applies to the System Operator and the Electrical Power Production Market Subjects.

3. General criteria

3.1 Sign Criteria. The sign criterion adopted in the formulas of this procedure is as follows:

a) Energy production and import have a positive sign. Energy consumption and export have a negative sign.

b) The energy to go up has a positive sign. Energy is defined to be raised as increases in energy production or import and decreases in energy consumption or export.

c) The energy to be lowered has a negative sign. Energy is defined to be lowered as decreases in energy production or import and increases in energy consumption or export.

d) The receivables have a positive sign. Payment obligations have a negative sign.

3.2 Measures. The quantities referred to in the texts and formulae of this procedure shall be read as follows:

(a) The energy quantities shall be understood as expressed in MWh with the number of decimal places in which the energy allocation or measurement is carried out in each case and up to a maximum of three decimal places.

(b) The power quantities shall be understood to be expressed in MW with the number of decimal places where the allocation or measurement of power is carried out in each case and up to a maximum of three decimal places.

(c) Energy prices shall be understood as expressed in euro per MWh with the accuracy with which they are determined on each market.

(d) Power prices shall be understood as expressed in euro per MW with the accuracy with which they are determined on each market.

e) The percentages will be understood already divided by 100.

(f) Payment entitlements and payment obligations shall be understood as expressed in euro with two decimal places, where necessary, the rounding necessary.

3.3 Formulas. The terms of the formulae of this operating procedure shall be construed as referring to values of one hour, except in other words.

The term "PMD" in the formulas of this Operation Procedure means Daily Market Price.

In the distribution formulas, the minimum error rounding method will be applied to obtain rounded results that add up the amount to be distributed.

3.4 Terms. In this procedure the term consumer direct refers to Direct Consumer in Market.

Marketing programming unit refers to the programming unit of a marketer for energy purchase for supply to its national customers on the peninsula.

Direct Consumer Programming Unit refers to the direct consumer programming unit for power purchase for consumption on the peninsula.

Acquisition unit for demand refers, in general, to the programming units of the two preceding paragraphs.

4. Restrictions for supply assurance and for technical restrictions of the PBF

4.1 PBF modifications by security of supply and by security criteria.

4.1.1 Technical restrictions on PBF to be moved up in phase 1 to sales units.

4.1.1.1 Simple offer. The allocation of energy to be raised for the resolution of technical restrictions of the PBF with the use of the simple offer, because the complex offer is not applicable, shall give rise to a right of recovery of the unit or, for each block of energy b allocated, which is calculated according to the following formula:

DCERPVPVOS_{u, b} = ERPVPVOS_{u, b} × POPPVPVOS_{u, b}

where:

ERPVPVOS_{u, b} = Energy to be uploaded from the simple offer block b of the unit or allocated in phase 1.

POPPVPVOS_{u, b} = Offerited price for simple offer for the u block b.

4.1.1.2 Complex Offering. The allocation of energy to be raised for the resolution of technical restrictions of the PBF with the use of the complex offer shall result in a right of collection of the unit or calculated according to the following formula:

DCERPVPVOC_u = ERPVPVOC_u × POPPVPVDAY_u

where:

ERPVPVOC_u = Energy to be uploaded from the unit or, in application of the complex offering

POPVPVDIA_u = Applicable price for all hours of the day resulting from the application of the complex offering and obtained as follows:

POPVPVDIA_u = minimum (IMPPVPu, IMPPHF_u)/ench ERPVPVOC_{u, h}

Being IMPPVP_u and IMPPHF_u the unit's daily income or resulting from the application of the complex offer to the program by constraints on the PVP and PHF respectively, as set out continuation:

IMPPVP_u = NAF_{u, pvp} × PAF_u + NAC_{u, pvp} × PAC_u + NHES_{u, pvp} × PHC_u + ERPVP_u × PEC_u

where:

NAF_{u, pvp} = Number of cold daily starts scheduled in PVP.

PAF_u = Cold start price in complex offering.

NAC_{u, pvp} = Number of hot daily starts scheduled in PVP.

PACu = Hot start price in complex offering.

NHES_{u, pvp} = Number of hours daily with power to go up for resolution of technical constraints of the PBF with use of the complex offering.

PHC_u = Price per hour in the complex offering.

ERPVP_u = Daily energy to be uploaded for the resolution of technical constraints of the PBF with the use of the complex offering.

PEC_u = Energy price in the complex offering.

It is considered that there is a scheduled start in PVP at hour h when in that hour there is no power allocated by PBF, there is power allocated by technical constraints to go up in phase 1 and in the previous hour there is no power allocated neither in PBF nor by technical restrictions in phase 1 to upload. If the block of previous and contiguous hours h with PBF zero program plus phase 1 to upload is equal to or less than four, the scheduled start will be hot. Otherwise it will be cold.

IMPPHF_u = NAF_{u, phf} × PAF_u + NAC_{u, phf} × PAC_u + NHR_{u, phf} × PHC_u + PHF_{u, phf} × PEC_u -IMDCBMI

where:

NAF_{u, phf} = Number of cold daily starts scheduled in PHF.

PAF_u = Cold start price in complex offering.

NAC_{u, phf} = Number of hot daily starts scheduled in PHF.

PAC_u = Hot start price in the complex offering.

NHR_{u, phf} = Number of hours per day with PHF greater than zero.

PHC_u = Price per hour in the complex offering.

PHF_{u, phf} = Daily PHF Energy on the day.

PECu = Power price in complex offering.

IMDCBMI_u = Sum of daily revenue in the first three hours on the daily market and bilateral contracts, calculated by marginal price valuation of the daily energy market of the PBF, and the daily balance of the Intra-day market sessions, phase 2 PBF restrictions and intra-day market restrictions.

If IMDCBMI < 0 then IMDCBMI = 0

If IMPPHF_u < 0, then IMPPHF_u = 0

A scheduled boot is considered to exist in PHF at hour h when in that hour there is no power allocated by PBF, there is power allocated by technical constraints in phase 1 to go up and in some previous hour there is no power assigned in PHF. If the block of previous and contiguous hours h with PHF zero program is equal to or less than four the scheduled boot will be hot. Otherwise it will be cold.

4.1.1.3 No offer or insufficiency of existing offering. The allocation of energy to be raised for the resolution of technical restrictions of the PBF by exceptional resolution mechanism shall result in a right of collection of the unit or calculated according to the following formula:

DCERPVPVMER_u = ERPVPVMER_u × 1,15 × PMD

where:

ERPVPVMER_u = Energy redeployed to upload by technical constraints of the PBF by exceptional resolution mechanism of the unit of sale or.

4.1.2 Technical constraints of the PBF to be moved up in phase 1 to export and pumping consumption units

4.1.2.1 Daily market transaction. The allocation of energy to be increased for the resolution of technical restrictions of the PBF to units of purchase of pumping and export consumption corresponding to transactions of the daily market, will be considered as a rectification of the Note in the Spanish production market equivalent to a right of collection of the unit or, which is calculated according to the following formula:

DCERPVPC_u = ERPVPC_u × PMD

where:

ERPVPC_u = Energy to be uploaded for resolution of technical constraints of the purchasing unit's PBF

4.1.2.2 Transaction associated with the execution of a bilateral contract with physical delivery.

The power allocation to be uploaded for the resolution of technical constraints of the PBF to the purchase and export consumption acquisition units of the transaction associated with the execution of a bilateral contract with delivery No financial settlement shall be given.

4.1.3 Technical restrictions on PBF to be lowered in phase 1 to sales units.

4.1.3.1 Daily market transaction.

The allocation of energy to be lowered for the resolution of technical restrictions of the PBF to units of sale corresponding to transactions in the daily market shall be considered as a correction of the account taken in the Spanish production market equivalent to a payment obligation for the unit or, which is calculated according to the following formula:

OPERPVPV_u = ERPVPVB_u × PMD

where:

ERPVPVB_u = Energy to be downloaded for the resolution of technical constraints of the sales unit's PBF.

4.1.3.2 Transaction associated with the execution of a bilateral contract with physical delivery in which the acquisition unit corresponds to a non-pumping national consumption. The allocation of energy to be lowered for the resolution of technical restrictions of the PBF to sales units corresponding to transactions associated with the execution of a bilateral contract with physical delivery in which the acquisition unit corresponds a national consumption, excluding pumping, shall result in a payment obligation calculated according to the following formula:

OPERPVPCBN_{u, cb} = ERPVPCBN_{u, cb} × PMD

where:

ERPVPCBN_{u, cb} = Energy to be downloaded for resolution of technical constraints of the unit's PBF or the bilateral cb contract.

4.1.3.3 Transaction associated with the execution of a bilateral contract with physical delivery in which the acquisition unit corresponds to a pumping consumption or an export. The allocation of energy to be lowered for the resolution of technical restrictions of the PBF to sales units corresponding to transactions associated with the execution of a bilateral contract with physical delivery in which the acquisition unit corresponds a consumption of pumping or an export shall not give rise to any economic settlement.

4.1.4 Breaches of starts or assignments to move up from phase 1. Scheduled starts shall be reviewed by checking that they have actually been carried out in accordance with the measures and the specific type of start (cold or hot) shall be checked, taking into account that a cold scheduled start, when revised, may become a hot start according to the measures received, but not the other way round. For this purpose, the measures of the unit shall be taken into account in the last 5 programming periods of the day preceding the day of liquidation.

If there is a reduction in the number of starts or variation of the boot type, the collection rights calculated in section 4.1.1.2 will be recalculated using the number and type of starts actually made.

In the event that at all hours of the day with power scheduled to rise in phase 1, the energy measured for the unit is equal to or greater than the security programmed in the PVP, the calculated charging rights will be maintained and reviewed according to the preceding paragraph.

In the event that the one-hour measure is less than the security programmed in the PVP, a payment obligation or a charge duty calculated according to the following formula shall be entered:

OPEINCPVP_u = EINCPVP_u × (PMEDPVPS_u -PMD) if PMEDPVPS_u > PMD

DCEINCPVP_u = EINCPVP_u × (PMEDPVPS_u -PMD) if PMD > PMEDPVPS_u

where:

EINCPVP_u = Unfulfilled power to move up in phase 1 of the unit or discounting the power-driven default to be lowered by real-time constraints.

PMEDPVPS_u = The weighted average price of all scheduled power to be uploaded for the resolution of technical constraints of the PBF in phase 1 of the u.

The unfulfilled power is calculated according to the following formula:

EINCPVP_u = MAX [-ERPVP_u, MIN (0, MEDRTR-PVP)]

where:

MEDRTR = MBC, if RTR ≥ 0 or if PVP ≤ PHF + TG

MEDRTR = MAX (PBF, MBC) + MIN [PVP-(PHF + TG),-RTR] if RTR < 0 and PVP≥ PHF + TG

MEDRTR: a measure used for the calculation of the power failure to move up from phase 1, in which the energy-driven default is ignored for restrictions in real time.

MBC: measured in central bars, as set out in paragraph 13.2.

TG: sum of tertiary regulation power, deviation management, and real-time constraints.

RTR: Sum of power of constraints in real time.

4.1.5 Energy withdrawn by congestion at international border. The withdrawal of the Operating Base Program from the units of sale or acquisition of transactions associated with a bilateral contract with physical delivery by congestion at international border shall not result in any economic settlement.

4.1.6 Restrictions on supply warranty.

4.1.6.1 Power programmed in PBF. In the event that one of the programming units from which they are required to participate in the process of the resolution of supply-guarantee restrictions as selling units has been programmed in the PBF and provided that there is no the maximum volume of production scheduled in the calendar year shall be assigned to the unit or a charge or a payment obligation calculated in accordance with the following formula:

If PSGSu > PMD:

DCEPBFGSu = EPBFGSu x (PSGSu-PMD)

If PSGSu < PMD:

OPOPPBFGSu = EPBFGSu x (PSGSu-PMD)

where:

EPBFGSU = Energy programmed in the base program of operation to the unit u, being one of the required to participate in the process of solution of restrictions by guarantee of supply and that does not exceed the value of energy of the published updated operating plan, EPFGSU, by the system operator.

EPBFGSu = MIN (PBFu, EPFGSu)

PSGSu = The unit time price or, corresponding to the unit cost of generation set for each central with the decimals that, if any, are set to be normatively set in euro/MWh.

4.1.6.2 Energy programmed for the resolution of supply guarantee restrictions in the PBF. The allocation of energy to be raised for the solution of supply security restrictions shall result in a charge that is calculated according to the following formula:

DCESGSu = ESGSu x PSGSu

where:

ESGSu = Scheduled power to be uploaded to the unit or in the supply warranty constraint resolution process

PSGSU = The time price of the unit or, corresponding to the unit cost of generation set for each central.

4.1.6.3 Obligation to pay for non-compliance with the production of the scheduled energy for security of supply. In the event that at all times of the day with energy programmed by security of supply, the energy measured for the unit is equal to or greater than the programmed energy, the collection rights calculated according to the previous paragraph shall be maintained.

In the event that the one-hour measure is less than the one scheduled for the supply guarantee in the PVP, a payment obligation or a charging right calculated according to the following formula shall be entered:

OPEINCGS_u = EINCGS_u × (PSGS_u -PMD) if PSGS_u > PMD

DCEINCGS_u = EINCGS_u × (PSGS_u -PMD) if PMD > PSGS_u

where:

EINCGS_u = Unfulfilled power to be uploaded by unit or unit supply assurance

EINCGS_u = MIN (0, MBCU-EPPVPGSu).

PSGS_u = Unit or unit time price, corresponding to the generation unit cost set for each central.

MBC_u = The measured output on central bars of the u.

EPVPGSu = (EPBFGSu + ESGSu).

EPBFGSU = Energy programmed in the base program of operation to the unit or with payment entitlements or obligations recorded under paragraph 4.1.6.1.

ESGSu = Scheduled power to be uploaded to the unit or in the process of resolution of supply warranty restrictions.

4.1.6.4 Net energy increase managed in the markets for diversion management, tertiary regulation and intraday market. During the period of application of the Final Disposition fifth of Royal Decree 1634/2011, from December 8 to December 31, 2011 both inclusive, a right of payment or obligation to pay to the net increase of the program will be recorded. managed in the markets for the management of deviations, tertiary regulation and in the intra-day market, produced effectively, and which does not exceed the updated daily operating plan and provided that the group has offered in accordance with sub-paragraph 2 of Annex I to Royal Decree 134/2010 of 12 February 2010.

This energy will be valued at a price equal to the difference between the unit cost of generation and the average price resulting from all its transactions in the markets for diversion management, tertiary regulation and in the market Intraday, resulting:

DCEGSP48u = ESGSP48u x (PSGSu-PGSP48u) If PSGSu > PGSP48u

OPEGSP48u = ESGSP48u x (PSGSu-PGSP48u) If PSGSu < PGSP48u

where:

DCEGSP48u = Right of charge for net increase of managed program in the markets for diversion management, tertiary regulation and in the intra-day market.

OPEGSP48u = Payment Obligation for Net Managed Program Increase in Deviation Management, Tertiary Regulation, and Intraday Market markets.

ESGSP48u = Net program increase managed in the diversion management, tertiary regulation and intra-day market, with the right to the perception of the regulated unit cost, produced effectively, and that exceeds the daily updated operation plan.

PSGSP48u = The average unit time price or, resulting from all transactions in the diversion management, tertiary regulation, and intraday markets.

Net program augmentation, ESGSP48u, is calculated according to the following formula:

ESGSP48u = MIN [MAX (0, (EPFGSU-PVPu)), MAX (0, TERGDVMIu), MAX (0, (MBCU-PVPu))]

Therefore, ESGSP48u > 0 if true:

SUM (MBCU) > SUM (PVPu) and SUM (EPFGSu) > SUM (PVPu) and TERGDVMIu > 0

and ESGSP48u = 0 if true:

SUM (MBCU) ≤ SUM (PVPu) or SUM (EPFGSu) ≤ SUM (PVPu) or TERGDVMIu ≤ 0

where:

TERGDVMIu = Net transaction balance in the intraday market, diversion management and tertiary regulation markets.

MBCU = Central bar measure, as set out in section 13.2

EPFGSU = The published daily operating plan energy.

PVPu = Scheduled Energy in the Interim Viable Program, following the result of technical constraints and restrictions by security of supply.

The average time price of the unit or, resulting from all transactions in the diversion management, tertiary regulation and intra-day market transactions is calculated according to the following formula for positive values of TERGDVMIu:

PSGSP48u = (EPRDS_{u, s} × PMPRDS_s + EPRDB_{u, s} × PMPRDB_s +

ETERS_u × PMTERS + ETERB_u × PMTERB +

Σs (EMISu × PMIs + EMIBu × PMIBGSs)/TERGDVMIu

Being the terms of price and energy the following:

PMIs = intraday market session s price s.

PMIBGSs = min (PMIs, PSGSu) This price applies in case of repurchase on the intraday market so that if the repurchase price is higher than the unit cost of generation set for each central, no such income.

EMISu, s = Energy scheduled to rise in intraday market s session.

EMIBu, s = Energy scheduled to be lowered in intraday market session s.

The rest of the terms are defined in the sections of this operating procedure relating to the management of deviations and tertiary regulation.

If the above price is negative with energy, ESGSP48u, positive, will be incorporated in the right to charge DCEGSP48u with its negative sign.

4.2 Generation-demand rebalancing. The energy assigned to be lowered, to obtain a balanced programme in generation and demand, to energy sales units corresponding to bilateral contracts whose demand has been reduced in the first phase of the process of technical restrictions of the PBF, shall not result in any economic settlement.

The energy assigned to go up, to obtain a program balanced in generation and demand, to units of energy acquisition (consumption of pumping or, export) corresponding to bilateral contracts whose generation has been reduced in the first stage of the process of resolution of technical restrictions of the PBF, it shall not result in any economic settlement.

4.2.1 Energy programmed to move up in phase 2 technical constraints

4.2.1.1 With simple offer presented. The allocation of energy to be raised to solve a generation deficit and thus obtain a balanced program generation-demand will result in a right of collection of the unit or, for each block of energy b allocated, that is calculated according to the formula next:

DCERECOOSS_{u, b} = ERECOOSS_{u, b} × POECOS_{u, b}

where:

ERECOOSS_{u, b} = Power of the single-offer b block of the unit or allocated in phase 2.

POECOS_{u, b} = The price of the simple power supply to be uploaded from the block b of the u, for the process of resolution of technical constraints.

4.2.1.2 No simple offer presented.

4.2.1.2.1 Acquisition Units. The energy assigned to rise to solve a generation deficit and thus obtain a balanced program generation-demand to units of acquisition that have not submitted the corresponding offer of energy to go up for the process of resolution of technical restrictions, shall give rise to a charge which is calculated according to the following formula:

DCERECOS_u = ERECOS_u × 0.85 × PMD

where:

ERECOS_u = Energy to be uploaded to the unit or in phase 2, no offer available

4.2.1.2.2 Sales Units. The energy assigned to rise to solve a generation deficit and thus obtain a balanced program generation-demand to units of sale that have not presented the corresponding simple offer of energy to go up for the process of resolution of technical restrictions, shall give rise to a charge which is calculated according to the following formula:

DCERECOSOS_u = ERECOSOS_u × 0.85 × PMD

where:

ERECOSOS_u = Energy assigned to upload to the unit or, with no offer presented.

When allocations are made by exceptional resolution mechanism, it will result in a charging right that is calculated according to the following formula:

DCERECOMERS_u = ERECOMERS_u × 1,15 × PMD

where:

ERECOMERS_u = Energy assigned to upload to the unit or, with no offer available.

When all bids submitted are allocated, allocations by exceptional resolution mechanism will be made, resulting in a charging right that is calculated according to the following formula:

DCERECOMERS_u = ERECOMERS_u × 1,15 × PMD

where:

ERECOMERS_u = Energy assigned to upload to the u, no available offering

4.2.2 Energy scheduled to be dropped in phase 2 technical constraints.

4.2.2.1 With simple offer presented. The allocation of energy to be lowered in order to resolve an excess generation and thus obtain a balanced program generation-demand will result in an obligation to pay the unit or, for each block of energy b allocated, which is calculated according to the formula next:

OPERECOOSB_{u, b} = ERECOOSB_{u, b} × POECOB_{u, b}

where:

ERECOOSB_{u, b} = Energy to be lowered from block b of the simple offer of the unit or allocated in phase 2.

POECOB_{u, b} = Price of the power supply to be lowered from the block b of the u, for the process of resolution of technical constraints.

4.2.2.2 No offer presented.

4.2.2.2.1 Acquisition Units. The energy assigned to be lowered to solve an excess generation and thus obtain a balanced program generation-demand to units of acquisition when assigned all the offers presented, are made allocations by exceptional mechanism resolution, will result in a payment obligation that is calculated according to the following formula:

OPERETRADE_u = ERETRADE B_u × 0.85 × PMD

where:

ERETRADE B_u = Energy to be dropped in phase 2 to the unit or, no offer available

4.2.2.2.2 Sales Units. The energy assigned to be lowered in order to resolve an excess generation and thus obtain a balanced program generation-demand to sales units that have not submitted the corresponding offer of energy to go down for the process of resolution technical restrictions shall result in a payment obligation calculated according to the following formula:

OPERECOSOB_u = ERECOSOB_u × 1,15 × PMD

where:

ERECOSOB_u = Energy to be dropped in phase 2 to the unit of sale or, with no offer presented.

4.2.3 Energy programmed to be lowered for resolution of the imbalances between generation and demand after the resolution of supply-guarantee restrictions. The planned energy allocation to be lowered will result in an obligation to pay the daily market price.

OPEBGS_u = EBGS_u x PMD

where:

EBGS_u = Scheduled energy to be lowered to resolve the imbalances between generation and demand after the resolution of supply warranty restrictions. This value is negative.

4.3 Overlay by the technical constraints of the PBF. The cost of the technical restrictions of the PBF (SCPVP) is calculated as the sum of all the payment entitlements and payment obligations of paragraphs 4.1.1 to 4.1.4 and paragraphs 4.2.1 and 4.2.2.

The cost of the technical restrictions of the PBF will be borne by the units of purchase, in proportion to their measured consumption to central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

The payment obligation for each ua acquisition unit corresponding to the cost overpayment due to the technical constraints of the PBF is calculated according to the following formula:

OPSCPVPua = SCPVP × MBCua/Uua MBCua

4.4 Economic Balance of Supply Warranty Restrictions. The economic balance of the supply guarantee restrictions is calculated as the sum of all the payment entitlements and payment obligations of paragraphs 4.1.6 and 4.2.3.

This balance shall be borne by the balance resulting from the difference between the income from the financing of the payments by capacity and the costs of its remuneration before its liquidation to the National Commission of the Energy. The remaining balance shall be considered as income or liquidable cost of the system for the purposes set out in Royal Decree 2017/1997.

5. Secondary Regulatory Band

5.1 Secondary regulation band. The secondary regulation band power allocation shall result in a charging right for each unit or assigned band that is calculated according to the following formula:

DCBAN_u = BAN_u × PMBAN

where:

BAN_u = Secondary throttling band assigned to the u.

PMBAN = The marginal price of the secondary throttling band.

In cases where regulatory band is assigned by exceptional resolution mechanism, the price to be applied will be the result of the product of 1.15 for the marginal price of the band in the corresponding time period or, in its defect, for the maximum band price of the same time in the previous seven days.

Energy reissues to be raised or lowered to obtain the band allocated by exceptional resolution mechanism will, respectively, result in a charge or a payment obligation. The price to be applied will be the result of the product of 1.15, if it is energy to go up, or of 0.85, if it is energy to go down, for the marginal price of the daily market in the corresponding time period. The cost of this energy allocation will be the difference between the resulting amount and the result of valuing energy at the marginal price of the daily market.

5.2 Secondary regulation band variation by the operation of the secondary regulation in real time.

5.2.1 Penalization to the Regulatory Zone by the cycles in which it remains in "off". The cost of the penalty for cycles in which the z zone is in "off" will result in a payment obligation calculated according to the following formula:

OPOFF_z = OFF_z × PMBAN × KI

being:

OFF_z =-KA_z × [RNTS + RNTB] × TOFF_z /TRCP

where:

PMBAN = The marginal price of the secondary throttling band.

KI = Coefficient of non-compliance published by the System Operator, prior to the authorization of the CNE. At the entry into force of this procedure, the value will be 1.5.

KA_z = Coefficient of the z-regulation zone participation in the system reservation.

RNTS = Total nominal reserve to be uploaded from the system.

RNTB = Total nominal reserve to be lowered from the system.

TOFF_z = Cycles in "off" of the z throttling zone, with the exception of those that are per system operator indication.

TRCP = The number of active cycles of secondary throttling in the hour.

5.2.2 Bonification to the area of regulation per residual reserve higher than that allocated. The residual reserve allowance higher than the amount allocated shall give rise to a charge which is calculated according to the following formula:

DCRRS_z = RRS_z × PMBAN × KB

being:

RRS_z = (RRSP_z + RRBP_z)/TRCP

where:

PMBAN = The marginal price of the secondary throttling band.

KB = Bonus Coefficient that will be the same as the KI coefficient in paragraph 5.2.1.

RRSPz = Cumulative value of the positive difference between the residual reserve to be put up by the z-regulation zone and its rated power band to be raised allocated for the cycles in which the regulatory area is in active, inactive, or emergency.

RRBPz = Cumulative value of the positive difference between the residual reserve to be put down by the z-regulation zone and its rated power band to be lowered allocated for the cycles in which the regulatory zone is in active, inactive, or emergency.

5.2.3 Penalization to the area of regulation per residual reserve lower than that allocated. The cost of the lower residual penalty penalty, which has a negative value for RRSN_z and RRBN_z, will result in a payment obligation calculated according to the following formula:

OPRRIz = RRIz × PMBAN × KI

being:

RRI_z = (RRSNz + RRBNz)/TRCP

where:

PMBAN = The marginal price of the secondary throttling band.

KI = Default Coefficient that will be the same as the KI coefficient in paragraph 5.2.1.

RRSNz = The cumulative value of the negative difference between the residual reserve to be raised by the z-regulation zone and its rated power band to be assigned to the allocated amount obtained for the cycles in which the regulatory area is active, inactive or emergency.

RRBNz = Cumulative value of the negative difference between the residual reserve to be put down by the z-regulation zone and its rated power band to be lowered allocated for the cycles in which the regulatory zone is in active, inactive, or emergency.

5.3 Total Fixed Cost of Secondary Regulatory Band Allocation. The total fixed cost of the secondary regulatory band shall be the sum of the payment entitlements and payment obligations of paragraphs 5.1 and 5.2 except for the energy reissue derivatives referred to in paragraph 5.1, in which it shall be part of the total fixed cost the cost of the same.

The cost of the secondary regulatory band (CFBAN) will be borne by the acquisition units, in proportion to their measured consumption of central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

The payment obligation of each acquisition unit, au, corresponding to the payment of the band is calculated according to the following formula:

OPCFBANua = CFBAN × MBCua/Uua MBCua

6. Technical restrictions on the intraday market

6.1 Sale offers withdrawn for the solution of technical restrictions on the cross-market appeal or for subsequent generation-demand rebalancing. The withdrawal of an offer to sell energy included in the market appeal shall result in a correction of the taking into account in the Spanish production market equivalent to a payment obligation for the unit or calculated according to the following formula:

OPRTMI_{u, s} = ERVMI_{u, s} × PMI_s

where:

ERVMI_{u, s} = Energy removed to the unit or in the constraint solution process to the corresponding intraday market session s

PMI_s = The marginal price of the corresponding intraday market session s.

6.2 Acquisition offers withdrawn for the solution of technical restrictions on the appeal of the intra-day market or for subsequent generation-demand rebalancing. The withdrawal of an energy purchase offer included in the intraday market appeal shall result in a correction of the taking into account in the Spanish production market equivalent to a charge for the unit or which is calculated according to the following formula:

DCRTMI_{u, s} = ERCMI_{u, s} × PMI_s

where:

ERCMI_{u, s} = Energy removed to the unit or in the constraint solution process to the corresponding intraday market session s.

PMI_s = The marginal price of the corresponding intraday market session s.

7. Real-time technical constraints

7.1 Real-time technical constraints to upload.

7.1.1 Technical constraints in real time to rise with tertiary offer. The allocation of energy to be put up by real time restrictions using the tertiary offer will result in a charge right to the unit or per each block of energy b calculated according to the following formula:

DCERTRT_{u, b} = ERTRTS_{u, b} × POTERS_{u, b}

where:

ERTRTS_{u, b} = Energy to be uploaded from the tertiary offering block b to be uploaded from the unit or by real-time restriction solution.

POTERS_{u, b} = Price offered for tertiary to be uploaded for power block b.

7.1.2 Real-time technical constraints to upload with submitted bid for PBF technical constraint solution process. The allocation of energy to be raised by security in real time using the offer submitted for the process of solution of restrictions will result in a charge right for the unit that is calculated according to the simple offer or complex.

7.1.2.1 Simple offer. The right to charge the unit or for each block of energy b allocated is calculated according to the following formula:

DCERTROS_{u, b} = ERTROSS_{u, b} × POSS_{u, b}

where:

ERTROSS_{u, b} = Energy to be uploaded from block b of the unit's simple offer or by real-time restriction solution.

POSS_{u, b} = Simple offer price to upload for power block b.

7.1.2.2 Complex Offering. The right to charge for the energy allocated on units that have submitted a complex offer and this is applicable is calculated according to the following formula:

DCERRTROC_u = ERTROCS_u × POCDIA_u

where:

ERTROCS_u = Power scheduled to be uploaded to the unit or by real-time restriction solution, in application of the complex offering.

POCDIA_u = Applicable price for all hours of the day obtained by valuing PHF energy, deviation management, tertiary regulation, and technical constraints at the complex offer price and discounting net income positive results obtained by energy other than ERTROCS_u and by dividing the resulting amount between the ERTROCS_uenergy.

7.1.3 Real-time technical constraints to upload without offer. The right to charge for the energy allocated on units that have not submitted an offer or that have exhausted the existing offer is calculated according to the following formula:

DCERTRMER_u = ERTRMERS_u × 1,15 × PMD

where:

ERTRMERS_u = Power scheduled to be uploaded to the unit or by real-time restriction solution with no applicable offer.

7.1.4 Breaches of starts or realtime assignments to upload. Scheduled starts will be reviewed by checking whether they have actually been carried out in accordance with the measures and the specific type of start (cold or hot) will be checked, taking into account that a cold scheduled start when revised can become a hot start according to the measures received but not the other way round. For this purpose, the measures of the unit shall be taken into account in the last 5 programming periods of the day preceding the day of liquidation.

If there is a reduction in the number of starts or variation of the boot type, the collection rights calculated in paragraph 7.1.2.2 will be recalculated using the number and type of starts actually made.

In the event that in all hours with energy programmed to rise by constraints in real time, the energy measured for the unit is equal to or greater than the PHF discounting the energy management of deviations and tertiary regulation to lower the redispatches for security in real time, the collection rights calculated and revised according to the previous paragraph shall be maintained.

In the event that the measure is less than the energy programmed by restrictions in real time, the value of the unfulfilled energy shall be determined and a payment obligation calculated according to the following formula shall be recorded:

OPEINCRTR_u = EINCRTRS_u × (PMEDRTRS_u -PMD)

where:

EINCRTRS_u = Unfulfilled power of real-time constraints to be moved up from the u, zero value will be taken if the time constraints exist in real time to drop in the u.

PMEDRTRS_u = Average price of all scheduled power to be uploaded for real-time technical constraint resolution to the u.

The unfulfilled power will be calculated according to the following formula:

EINCRTRS_u = max [-RTR_u, min (0, MBC_u -(max (PHF_u + TGB, 0) + RTR_u))]

where:

MBC_u = measured in central bars, as set out in section 13.2.

TGB = sum of deviation management and tertiary regulation power to be lowered.

RTR = sum of constraints power in real time.

7.2 Real-time technical constraints to download.

7.2.1 Technical constraints in real time to lower with tertiary offering.

The allocation of energy to be lowered for security in real time using the tertiary offer will result in a payment obligation to the unit or per each block of energy b calculated according to the following formula:

OPERTRT_{u, b} = ERTRTB_{u, b} × POTERB_{u, b}

where:

ERTRTB_{u, b} = Energy to be lowered from the b block of the tertiary offering to be lowered from the unit or by real-time restriction solution.

POTERB_{u, b} = Bid price for tertiary to lower for power block b.

7.2.2 Real-time technical constraints to download with submitted offer for the constraint solution process. The allocation of energy to be lowered for security in real time using the offer submitted for the process of solution of restrictions, will result in a payment obligation for the unit or for each block of energy b allocated, which is calculated according to the following formula:

OPERTROS_{u, b} = ERTROSB_{u, b} × POSB_{u, b}

where:

ERTROSB_{u, b} = Energy to be lowered from block b from simple offer to drive down or by real-time restriction solution.

POSB_{u, b} = Simple offer price to download for power block b.

7.2.3 Technical constraints in real time to go down without offer. The obligation to pay for the energy assigned to be lowered on units that have not submitted an offer or that have exhausted the existing offer is calculated according to the following formula:

OPERTRMER_u = ERTRMERB_u × 0.85 × PMD

where:

ERTRMERB_u = Power scheduled to be lowered to the unit or by real-time restriction solution, with no applicable offer.

7.2.4 Real-time technical constraints to be lowered to pumping acquisition units. In the case of pump acquisition units, the allocation of energy to be reduced for security in real time shall result in an additional payment obligation for the energy reserves generated in the upper vessel of the pumping unit calculated according to the following formula:

OPERTRB_ucb = 0.7 × (ERTRTB_{u, b} + ERTROSB_{u, b} + ERTRMERB_u) × PMD

7.3 Sober of technical constraints in real time. The cost of the technical restrictions in real time shall be calculated as the difference between the sum of the receivables and the payment obligations of paragraphs 7.1 and 7.2 and the amount of the energy allocated by technical restrictions in real time valued at the marginal price of the daily market.

The cost of the technical restrictions in real time (SCRTR) will be borne by the units of acquisition, in proportion to their measured consumption to central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

The payment obligation for each acquisition unit (a) corresponding to the payment of the cost by the technical constraints in real time is calculated according to the following formula:

OPSCRTR_ua = SCRTR × MBC_ua /_ua MBC_ua

8. International exchanges

8.1 Support changes with price set for the same. Cross-system support exchanges performed by the System Operator through economic compensation for the energy supplied through the interconnections shall be recorded for each interconnection in the System Operator account as the right to charge, if it is in the importing sense, and as an obligation to pay, if it is in the exporting sense.

The cost of the support exchanges shall be calculated as the difference between the receivables and the previous payment obligations and the amount of energy from the exchange valued at the marginal price of the daily market.

The cost of the exchange of support with established price will be borne by the units of purchase, in proportion to their measured consumption to central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

The payment obligation for each acquisition unit, au, corresponding to the payment of the cost of the support exchanges (SCIA) is calculated according to the following formula:

OPPSCIAua = SCIA × MBCua/augua MBCua

8.2 Unpriced support exchanges. The exchange of support carried out by the System Operator by means of a return of energy shall be valued at the marginal price of the daily market by making an entry into an hourly compensation account for the purposes of its settlement in accordance with the established in the PO14.6. The annotation shall be a collection right, if the exchange is an importer and a payment obligation, if it is in the exporting sense.

The balance of this compensation account will be allocated to the acquisition units, in proportion to their hourly consumption, measured to central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

8.3 Power interchanges between electrical systems for system security.

Energy exchanges between electrical systems for safety, programmed by technical constraints of the PBF or by technical constraints in real time, will result in the following annotations according to the sense of the exchange:

Importer-wise exchange:

Right of collection in the System Operator account for the amount agreed with the neighbor system operator.

Obligation of payment result of prior amount between the units of acquisition in proportion to their consumption schedules measured to central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

Exporter exchange:

Payment obligation in the System Operator account equal to the sum of the receivables recorded to the units programmed for this energy exchange in technical constraints of the PBF or real time, as set out in paragraphs 4.1.1. and 7.1.

9. Managing deviations

9.1 Management of deviations to be uploaded. The power allocation to be uploaded by the deviation resolution procedure results in a charge right for each unit or in the session s that is calculated according to the following formula:

DCPRD_{u, s} = EPRDS_{u, s} × PMPRDS_s

where:

EPRDS_{u, s} = Energy assigned to be uploaded by the bypass resolution procedure to the u drive in the s.

PMPRDS_s = The marginal price of the power allocation to be uploaded by the bypass resolution procedure in the s session.

If the allocation is performed by exceptional resolution mechanism, the price to be applied will be the result of the product of 1.15 for the maximum marginal price of the allocation of deviations to be uploaded in the hour sessions or, in its defect, for the marginal price of the daily market.

9.2 Management of diversions to be downloaded. The power allocation to be lowered by the deviation resolution procedure results in a payment obligation for each unit in the session s that is calculated according to the following formula:

OPPRD_{u, s} = EPRDB_{u, s} × PMPRDB_s

where:

EPRDB_{u, s} = Energy assigned to be lowered by the bypass resolution procedure to the u drive in the s.

PMPRDB_s = The marginal price of the power allocation to be lowered by the bypass resolution procedure in the s session.

If the allocation is made by exceptional resolution mechanism, the price to be applied will be the result of the product of 0.85 for the minimum marginal price of the allocation of deviations to be lowered in the hour sessions or, in its defect, for the marginal price of the daily market.

10. Tertiary regulation

10.1 Tertiary Regulation to be uploaded. The energy allocation of tertiary energy regulation to be raised gives rise to a charging right for each unit that is calculated according to the following formula:

DCTER_u = ETERS_u × PMTERS

where:

ETERS_u = Tertiary energy assigned to upload to the u.

PMTERS = Marginal price of the tertiary assignment to be uploaded.

If the allocation is made by exceptional resolution mechanism, the price to be applied will be the result of the product of 1.15 for the marginal price of tertiary regulation to rise from the hour or, failing that, for the marginal price of the daily market.

10.2 Tertiary Regulation to be lowered. The energy allocation of tertiary energy regulation to be lowered results in a payment obligation for each unit that is calculated according to the following formula:

OPTER = ETERBu × PMTERB

where:

EterBu = Tertiary Energy assigned to drive down to the u

PMTERB = Marginal price of the tertiary assignment to download

If the allocation is made by exceptional resolution mechanism, the price to be applied will be the result of the product of 0.85 for the marginal price of tertiary regulation to fall from the hour or, failing that, for the price Marginal of the daily market.

11. Secondary regulation

11.1 Secondary Regulation to be uploaded. The contribution of secondary regulation energy to be raised by each regulatory area z gives rise to a charging right which is calculated according to the following formula:

DCSECz = ESECSz × PMSECS × CATS

where:

CATS = 1 if the tertiary ladder has not been exhausted to rise, otherwise, CATS will be equal to 1.15

ESECSz = Secondary regulation power to be uploaded by the z-regulation zone

PMSECS = marginal price of secondary throttling energy contributed to upload

11.2 Secondary Regulation to be lowered. The allocation of secondary regulation energy to be lowered results in a payment obligation for each z-regulation zone that is calculated according to the following formula:

OPSECz = ESECBz × PMSECB × CATB

where:

CATB = 1 if the tertiary ladder has not been exhausted, otherwise CATB will be equal to 0.85

ESECBz = Secondary throttling energy contributed to download by the z throttling zone

PMSECB = marginal price of secondary throttling energy contributed to download

12. Rpower consumption program education by power reduction orders

The reduction of the scheduled power consumption on the market for each acquisition unit due to power reduction orders shall be settled at the daily market price, as set out in Order ITC/2370/2007, of 26 July, regulating the service of management of the demand for interruptibility for consumers who acquire their energy in the production market.

In each hour with reduced power consumption of an acquisition unit, ua, due to power reduction orders, a charging right shall be entered for the au unit calculated according to the following formula:

DCSINTua = ERSINTua × PMD

where:

ERSINTua = High-to-Central-bar power of the time consumption reduction due to power reduction orders to consumers integrated into the ua unit.

PMD = Daily market marginal price.

13. Deviations between measure and settlement program

The detour will be calculated based on the measure on central bars (MBC) and the Schedule of Liquidation Schedule (PHL).

13.1 Schedule of Liquidation Schedule. The Unit or Unit's Settlement Schedule (PHL) Program will be calculated as the sum of:

End Time Program (PHF) Energy.

Energies assigned in the Operating Schedule Program, excluding the power of the communicated deviations.

Reduction of consumption due to ERSINTua power reduction orders.

13.2 Measure in Central Bars. The measurement on the central bars of the unit or shall be determined according to the following criteria:

(a) The measure in the central bars of the production programming units, the pumping consumption programming units and the auxiliary service consumption programming units, shall be the sum of the measures of the border points allocated to the production facilities that make up each programming unit.

In the case of the absence of measures of the production programming units, the value of the measure is considered to be zero. In the case of the absence of measures of the pumping consumption programming units, the value of the programme shall be considered as the value of the measure.

In cases where the measure of a border point collects the production of several production facilities, this value shall be apportioned in proportion to the individual measures or, in the case of the absence of an individual measure for the installation, proportionally to the value of the installed power.

(b) The measure in central bars of import programming units shall be the energy allocated to the unit in the exchange programme at the international border agreed by both system operators.

(c) The measure in central bars of export programming units shall be the energy allocated to the unit in the exchange programme at the international border agreed by both system operators, plus losses transport in the case of exports by borders with countries with which no reciprocal agreement has been signed, according to the following formula:

MBCuexp = PFIuexp × (1 + CPERfrint)

where:

MBCuexp = Central bar metric of the uexp export programming unit

PFIuexp = Energy assigned to the uexp export unit in the international border exchange program agreed by both system operators.

CPERfrint = Coefficient of general high voltage access rate loss for international border frint. The applicable value, in the case where the losses are applied, shall be that corresponding to the voltage level 'greater than 145 kV' except for the interconnection with Andorra which shall be, if applicable, the one corresponding to the voltage level 'greater than 72,5 and not more than 145 kV'. At the borders with the countries with which the reciprocal agreement has been signed, the value shall be zero.

(d) The measure in central bars of the marketing units and direct consumer units shall be calculated using the following formula:

MBCuc = nt herrant [MPFCuc, nt, ta × (1 + CPERnt, ta)]

where:

MPFCuc, nt, ta = Sum of the energy measures consumed at the consumer border points to the marketing or direct consumer programming unit at voltage level nt and access rate. This value will be negative.

CPERnt, ta = Loss Coefficient for access contracts on supply points to consumers with voltage level nt and access rate ta and for the corresponding tariff period for the time at the access rate. This value will be positive.

These coefficients shall be those laid down in the implementing rules for the transfer of energy supplied to consumers in their energy meters supplied in central bars for the purposes of the liquidations. provided for in Royal Decree 2017/1997 of 26 December.

The tariff periods shall be those set out in Order ITC/2794/2007. For two-and three-term fares, the 23-hour day will be the first day of summer and the 25-hour day will be the first of winter. For the six-term fee, national holidays for each year will be published by the System Operator as set out in P.O. 14.1.

In the event that complete measures are not available, and therefore no measures are available for the marketing programming units and direct consumers the measure in the central bars of these units will be the resulting value of the following formula:

MBCua = PHLua + SALDOENEua

where:

PHLua = Schedule of the acquisition unit's Liquidation Time Program, excluding the program fee corresponding to the central bar consumption of the type 1 clients of the ua unit to which the potestative settlement established in P.O. 14.1.

SALDOENEua = Allocation to the acquisition programming unit for the sum of the settled power balance of the programs and the measures available in central bars (SALDOENE). The allocation shall be carried out in proportion to the Schedule of Liquidation Schedule of each unit according to the following formula:

SALDOENEua = SALDOENE × PHLua/Uua PHLua

e) The measure of the generic programming units is zero.

13.3 Price of deviations. For the purposes of paragraph 13.5, the net balance sheet SNSB shall be calculated for the energy to be raised and lowered by the deviation-resolution procedure, by tertiary regulation and by secondary regulation.

SNSB= Usa, s (EPRDSu, s + EPRDBu, s) + envou (ETERSu + ETERBu) + uz z (ESECSz + ESECBz)

13.3.1 Price of deviations to be uploaded. They are defined as deviations to increase the deviations in the sense of the higher generation and the deviations in the sense of lower consumption.

If SNSB is negative, the time price of the deviations to be uploaded, for the purposes of paragraph 13.5, shall be calculated using the following formula:

PDESVS = min (PMD, PMPRTSB)

where:

PMPRTSB = weighted average price of the energy to be reduced as assigned by the deviation resolution procedure, by tertiary regulation and by secondary regulation according to the amounts recorded in accordance with the provisions of the paragraphs 9.2, 10.2, and 11.2 respectively, rounded to two decimal places.

If there is no value for PMPRTSB or, if SNSB is non-negative, the price of the deviations to be uploaded will be the marginal price of the daily market.

13.3.2 Price of deviations to be lowered. They are defined as deviations to lower the deviations in the sense of the lowest generation and the deviations in the sense of greater consumption.

If SNSB is positive, the time price of the deviations to be lowered, for the purposes of paragraph 13.5, will be calculated using the following formula:

PDESVB = maximum (PMD, PMPRTSS)

where:

PMPRTSS = weighted average price of the energies to be assigned by the deviation resolution procedure, by tertiary regulation and by secondary regulation according to the amounts scored according to the provisions of the paragraphs 9.1, 10.1 and 11.1 respectively, rounded to two decimal places.

If there is no value for PMPRTSS or if SNSB is non-positive, the price of the deviations to be lowered will be the marginal price of the daily market.

13.4 Deviation Calculation

13.4.1 Unsaw from the Regulatory Zones. The deviation of each z-regulation zone shall be calculated using the following formula:

DESVz = Usa (MBCU-PHLu) × PUZu, z-(ESECSz + ESECBz)

where:

MBCU = Central bar measurement of the programming unit or integrated in the z-regulation zone

PHLu = Programming Unit Liquidation Schedule Program or integrated into the z throttling zone

PUZu, z = The integration percentage of the programming unit or the z-throttling zone

ESSECz = Secondary regulation power to be uploaded by the z-regulation zone

EBSECz = Secondary regulation power to be brought down by the z-regulation zone

13.4.2 Unintegrated programming units in regulation zone. -The detour of each programming unit, or non-integrated in regulatory area, of each unit of demand acquisition, of each unit of import or export and generic units will be calculated using the following formula:

DESVu = (MBCU-PHLu)

where:

MBCU = High measure to central bars of each production or acquisition unit or, as set out in section 13.2

PHLu = Schedule of each unit of production or acquisition or of each unit, as set out in paragraph 13.1.

13.5 Rights of recovery and payment obligations for deviations. For the purposes of determining the payment entitlements and payment obligations for deviations, the deviations shall be calculated as follows:

The deviation of each regulatory area shall be the deviation calculated in paragraph 13.4.1.

The diversion of each Liquidation Subject to the special regime production activity shall be the sum of the deviations of its special regime programming units not belonging to the regulatory area. The deviation of each unit shall be that calculated in paragraph 13.4.2.

The diversion of each Liquidation Subject by the production activity under ordinary regime shall be the sum of the deviations of its non-regulatory units of ordinary regime programming units. The deviation of each unit shall be that calculated in paragraph 13.4.2.

The diversion of each Liquidation Subject to the marketing activity for domestic and acquisition customers for direct consumers will be the sum of the diversion of its programming units and the deviations of those (a) the acquisition programming units for domestic customers of other traders with whom it has made bilateral contracts and is the trading subject responsible for the system operator of its management, by virtue of the provisions of Article 20.6 of Royal Decree 2019/1997, as amended by the Royal Decree 1454/2005, and in the P.O.14.1. The deviation of each unit shall be that calculated in paragraph 13.4.2.

The diversion of each of the international borders of each authorized subject for international export exchanges will be the sum of the deviations of their export programming units at each border. The deviation of each unit shall be that calculated in paragraph 13.4.2.

The diversion of each of the international borders of each authorized subject for international import exchanges will be the sum of the deviations of their import programming units at each border. The deviation of each unit shall be that calculated in paragraph 13.4.2.

The deviation of each subject by the generic programming units that are instrumentally enabled in the current regulations will be the sum of the deviations of these units. The deviation of each unit shall be that calculated in paragraph 13.4.2, considering a measure value equal to zero.

13.5.1 Positive. If the deviation d calculated as set out in the initial paragraphs of paragraph 13.5 is positive, the price to be applied to the deviation d shall be the price of the detour to be uploaded, PDESVS, calculated as set out in paragraph 13.3. The amount shall be positive and shall be calculated using the following formula:

ECODESVd = DESVd × PDESVS

The amount will be supported by the programming units or regulatory zones that produce the d-deviation according to the following criteria:

(a) The unit (s) or zone (z) whose contribution to the diversion (s) has been negative (DESVuz, d < 0) shall have a payment obligation which shall be calculated using the following formula:

OPPDESVuz, d = DESVuz, d × PMD

b) The unit u or zone z that has contributed positively (DESVuz, p > 0) to the deviation d shall have a charging right which shall be calculated with the following formula:

DCDESVuz, d = DESVuz, d × PMD + DESVuz, d × DESVd × (PDESVS-PMD)/envou or DESVPuz, d

where:

either or DESVPuz, d = sum of positive detours DESVPuz, d = DESVuz, d > 0

As a result of the annotations in a and b above, equality is true:

ECODESVd = Uz DCDESVuz, d + Uz OPDESVuz, d

13.5.2 Negative. If the deviation d calculated as set out in the initial paragraphs of paragraph 13.5 is negative, the price to be applied to the deviation d shall be the price of the detour to be lowered, PDESVB, calculated as set out in paragraph 13.3. The amount shall be negative and shall be calculated using the following formula:

ECODESVd = DESVd × PDESVB

The amount will be supported by the programming units or regulatory zones that produce the d-deviation according to the following criteria:

(a) The unit (s) or zone (z) whose contribution to the diversion (s) has been positive (DESVuz, d > 0) shall have a charging right which shall be calculated using the following formula:

DCDESVuz, d = DESVuz, d × PMD

b) The unit u or zone z that has contributed negatively (DESVuz, d < 0) to the deviation d will have a payment obligation that will be calculated with the following formula:

OPPDESVuz, d = DESVuz, d × PMD + DESVuz, d × DESVd × (PDESVSB-PMD)/envou or DESVNuz, d

where:

either or DESVNuz, d = sum of negative detours DESVNuz, d = DESVuz, d < 0

As a result of the annotations in a and b above, equality is true:

ECODESVd = Uz DCDESVuz, d + Uz OPDESVuz, d

13.5.3 Zero Dismissed. If the deviation d calculated as set out in the initial paragraphs of paragraph 13.5 is zero, the economic amount shall be zero. The payment entitlements and the payment obligations of the programming units producing the zero deviation shall be calculated according to the following criteria:

a) The unit or positive deviation (DESVu, d > 0) will have a charging right that will be calculated using the following formula:

DCDESVu, d = DESVu, d × PMD

b) The unit or negative deviation (DESVu, d < 0) shall have a payment obligation which shall be calculated using the following formula:

OPPDESVu, d = DESVu, d × PMD

13.5.4 Cancellation of the cost of diversion of exempt facilities. In each programming period, the programming units which are exclusively part of the special arrangements which are completely exempt from payment of the cost of the deviations shall have a right of recovery in respect of the cancellation of the cost of the deviation to be calculated according to the following formula:

DCDSVEXu = Abs (DESVEXu) x Abs (PMD-PREDESVu)

where:

DESVEXu = Unexempted from the programming unit or calculated in accordance with paragraph 13.4.2 which shall be positive or negative as appropriate to greater or less production than the forecast. The exemption is limited to deviations from the installed power, in the case of a programme exceeding that power.

PREDESVu = Price of the payment entitlement or payment obligation of the programming unit or by deviation as provided for in paragraphs 13.5.1, 13.5.2 and 13.5.3, as a result of the ratio between the amount scored and the energy of the detour.

PMD = Daily market time price.

The sum of the receivables for cancellation of the cost of the deviations shall constitute the deficit of deviations exempt from the payment of the cost of deviations that will be settled from the balance of the surplus or deficit of valuation of the deviations of the paragraph 13.10 in which the sum of these receivables shall be included.

13.6 International systems between systems. International deviations between systems are calculated as a difference between the measurement at the border points with other electrical systems and the programme agreed between the operators of the systems. The marginal price of the day-to-day market shall be valued at an annotation in a time-clearing account for settlement in accordance with the provisions of the P.O.14.6.

In each hour, international deviations will be added for each international interconnection

DIR = frint frint DIRfrint

where:

DIRfrint = International Desvio at Frint Border,

If the sum of all international deviations from regulation is positive, a claim that will be calculated using the following formula shall be entered in the clearing account:

DCDIR = DIR × PMD

If the sum of all international regulatory deviations is negative, a payment obligation shall be entered in the clearing account that is calculated using the following formula:

OPDIR = DIR × PMD

The balance of this compensation account will be allocated to the acquisition units, in proportion to their hourly consumption, measured to central bars, MBCua. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

13.7 Coordinated Balance Sheet Actions with Other Systems. -Energy from coordinated balancing actions with other systems shall be valued from the Spanish system at the price of deviations set out in paragraph 13.3 that is applicable to the sense corresponding to the balancing action. An hourly annotation shall be performed for each interconnection in the System Operator account for use in accordance with the provisions of the P.O.4.1.

If the balance sheet action is in the importing sense (ABI), a collection right shall be recorded which shall be calculated using the following formula:

DCAB = ABI × PDESVS

If the balance sheet action is in the exporting sense (EBA) a payment obligation shall be entered in the following formula:

OPAB = EBA × PDESVB

13.8 Power Closure. In the closing of measures, the closing of energy in each hour, the REDRE, is calculated as the difference between the losses of transport and distribution and the calculated standard losses, according to the established in the Additional provision of Royal Decree 485/2009 of 3 April 2009 regulating the implementation of the supply of last resort in the electricity sector.

DRE = PRTD-unta nt [MPFCuc, nt, ta × CPERnt, ta]

where:

PRTD = PT + rind d PRDd

PT = Lost transport network measures. This value will be negative.

PRDd = Measures of the distribution network of the vendor d. This value will be negative.

The system power shutdown calculated according to the formula above will be valued at the daily market price.

The payment entitlements for positive closures and the payment obligations for negative closures shall be settled in the system operator's account. The resulting balance shall be considered as income or liquidable cost of the system for the purposes of Royal Decree 2017/1997 and as such shall be included in the liquidations of the regulated activities as provided for in the second provision of the Royal Decree 485/2009,.

13.9 Allocation of surplus or deficit in the valuation of deviations. As a result of the method of valuation of the deviations, the balance resulting from the collection of payment entitlements and payment obligations in one hour (SALDOLIQ) will be a surplus, or if any, a deficit.

The surplus (SALDOLIQ < 0) will be distributed to the acquisition units, in proportion to their measured consumption to central bars, MBCua as a minorage of the costs of technical and band restrictions. The production units, the units of purchase corresponding to the supply of auxiliary services of the production units and the units of purchase whose destination is the supply, are exempted from this allocation. outside the Spanish electrical system.

In case of surplus these units will have a right of collection in the time of adjustment that will be calculated with the following formula:

DCAJDVu =-SALDOLIQ x MBCua/either or MBCua

In the event that a deficit occurs in the hour (SALDOLIQ > 0) the previous units will have a payment obligation in the time of adjustment that will be calculated with the following formula:

OPOJDVu =-SALDOLIQ x MBCua/either or MBCua

14. Programming failure of the generic programming units

14.1 Obligation to pay for non-compliance with the zero balance obligation in PBF. -Following the mandatory report of the National Energy Commission, the non-zero balance of the energies of all the programming units generic of each market subject in the PBF will result in the following payment obligation:

OPUPGPBF= -abs (ug ENPBFug) × PMD × 1.3

where:

ENPBFug = Energy in PBF of the generic programming unit ug.

This payment obligation may be moderated in accordance with the circumstances of the case, taking into account the damage to the system and the diligence of the defaulting agent.

14.2 Obligation to pay for non-compliance with the zero balance obligation in the PHF. -Following the mandatory report of the National Energy Commission, the non-zero balance of the energies of all the programming units generic of each market subject in the PHF will result in the following payment obligation in each hour h:

OPUPGPHF= -abs (ug ENPHFug) × PMD x 0.15 × NS

where:

ENPHFug = Energy in the last PHF of the generic programming unit time ug.

NS = Number of valid intraday market sessions for hour h.

This payment obligation may be moderated in accordance with the circumstances of the case, taking into account the damage to the system and the diligence of the defaulting agent.

14.3 Surplus for payment obligations due to scheduling failures. The surplus generated by the payment obligations of paragraphs 14.1 and 14.2 shall be divided according to the method described in paragraph 13.9. Allocation of surplus or deficit in the valuation of deviations.

15. Communication for the purpose of settlement of the equivalent premium

The production facilities under special arrangements that have chosen the option of sale corresponding to Article 24.1 (a) of Royal Decree 661/2007, of 25 May will sell the premium to the National Energy Commission. equivalent.

As set out in Circular 4/2009 of 9 July, of the National Energy Commission, which regulates the request for information and the procedures for implementing the system of settlement of equivalent premiums, premiums, the incentives and additions to the electrical energy production facilities under special arrangements, the system operator shall communicate monthly to the National Energy Commission, the aggregate amount of the base for the settlement of the difference with the regulated tariff (Baldita) corresponding to the set of the installations of each representative and each holder who participates without a representative and who has chosen option (a) of Article 24.1 Royal Decree 661/2007.

The amount of the basis for the settlement of the difference with the regulated tariff, BALDITA, of each representative or rt holder in each month m shall be the sum of the amounts of the settlements referred to in Article 30.1 and the amount of the impact of the cost of the diversion referred to in Articles 30.1 and 34 of Royal Decree 661/2007. The value of this sum is calculated according to the following formula:

BALDITArt, m = MEDPMDrt, m + EMIPIDrt, m

Being:

MEDPMDrt, m = Value of the hourly measures, MEAMID, of the net energy actually produced by the facilities i of the representative or rt holder in the month m valued at the price of the daily market, PMD, in every hour h:

MEDPMDrt, m = Σi, h MEDBCi, rt, h × PMDh

EMIPIDrt, m = Value of the monthly gain or loss by the married energy at each session of the intraday market of hour h, EMI, by the facilities i of the representative or rt holder in the month m, integrated in the unit of Up-and-down programming, resulting from the difference between the price of the intra-day market session, PMI, and the daily price of the market:

EMIPIDrt, m = Σi, s, h EMIi, rt, s, h × (PMIs, h-PMDh) = Σup, s, h EMIup, rt, s, h × (PMIs, h-PMDh)

16. Settlement of the programming units of the link between the peninsular electrical system and the Balearic electrical systems

16.1 Technical constraints on the intraday market. The energy redispatches required to resolve the identified technical constraints or the generation-demand rebalancing shall be settled at the price of the relevant intraday market session.

16.2 Post-PHF program modifications. The amendments to the programme of the post-session liaison programming units of the intra-day market shall be settled at the price of the daily market.

The above annotations shall form part of the balance resulting from the set of payment entitlements and payment obligations in an hour that determine the balance (SALDOLIQ) referred to in paragraph 13.9.

16.3 Desvio of the program. -Net deviation of the power program of the power of the peninsular electrical system with the electric balance system will be calculated as a difference between the energy measured at the border point of the link with the peninsular system and the schedule of the net settlement of the scheduling units of the link and shall be settled at the price of the diversion set out in paragraph 13.3. The amount will be distributed proportionally between the programming units of the link according to your program.

The previous paragraph will not be applicable during the test period of the link. As set out in paragraph 2 of the second transitional provision of Royal Decree 1632/2011, the energy that runs through the link during the testing period shall be considered as losses of the peninsular electricity system. For this purpose, it shall be settled at the price of the daily market and shall be entered in the account of the system operator referred to in paragraph 13.8. The traders of last resort shall be given a right of recovery to compensate for the amount of energy acquired on the market as set out in paragraph 1 of the second transitional provision.

The above annotations shall form part of the balance resulting from the set of payment entitlements and payment obligations in an hour that determine the balance (SALDOLIQ) referred to in paragraph 13.9.

16.4 Effects on the liquidation of the Balearic Islands. The payment entitlements and payment obligations referred to in paragraph 16.1, 16.2 and 16.3, as well as the energy settled, shall be considered in the clearance of the office of the Balearic Islands, as set out in paragraph 2 of the Annex to the Royal Decree. 1623/2011.

As a result of the sum of the amounts settled in the peninsular system and of the amounts settled in the issue to the dealers of last resort, the final cost of acquisition of the commercializers of Last resort in the Balearic system will be the one established in the additional provision 15th of Royal Decree 485/2009 of April 3, which regulates the implementation of the supply of last resort in the field of electrical energy.

P. O. SEIE-1 Operation of island and extra-island electrical systems

1. Object

The purpose of this procedure is to establish the safety and functioning criteria to be applied in the operation of the Island and Extrapeninsular Electrical Systems (SEIE) and in the elaboration and execution of the security plans, with the aim of ensuring continuity of supply with the required safety and quality.

2. Scope

In this Procedure, they are set:

(a) The security and performance criteria to be applied in the SEIE operation, so as to ensure continuity of supply with the required safety and quality.

(b) The criteria to be used to determine the permissible load levels on the lines and transformers of the transport network.

(c) The conditions for the delivery of the energy at the border points of connection of the transport network with other networks or installations, in such a way as to ensure the quality of the service at those border points.

d) The necessary regulatory reserves to resolve technical constraints and imbalances between generation and consumption.

(e) General conditions for the establishment of safety plans to ensure the safe and reliable operation of the system and to enable the replacement of service after severe incidents.

3. Scope of application

This Procedure applies to the following subjects:

● System Operator.

● Single carrier and distributors who are exceptionally holders of transport facilities.

● Distributors and clients connected to the transport network.

● Marketers.

● Owned or operating companies of generating groups connected to or directly influencing the transport network.

● proprietary or operating companies of ordinary and special regime facilities.

● Distribution network managers.

● This Procedure affects the following installations belonging to any Spanish Electrical System located outside the peninsular territory and is not synchronously interconnected with the Electrical System Peninsular:

● Transport network installations.

● The substations where it is generated, that even without belonging to the transport network have influence over it.

● Production facilities connected directly to or with direct influence on the operation of the transport network.

● Special regime production facilities.

● Distribution facilities or clients connected directly to the transport network.

The System Operator will maintain at all times an updated listing of the facilities that make up each of the systems that make up each SEIE.

4. Definitions

Four possible electrical system operating states are defined:

4.1 Normal status. Situation in which all control variables that characterise the system state are within the normal operating margins as set out in paragraph 5.3.1 and the safety criteria for contingencies are met. referred to in paragraph 5.3.2.

4.2 Alert status. Situation in which all control variables that characterize the system state are within the normal operating margins as set out in paragraph 5.3.1, but the safety criteria for contingencies are not met. referred to in paragraph 5.3.2.

4.3 State of emergency. Situation in which one or more system control variables present values outside normal operating margins.

This state includes those cases where there is a disruption of local power supply.

4.4 Reorder status. Situation characterized by the loss of supply in an electrical zone (zero zonal) or in the totality of any of the systems that make up each of the SEIE (zero total), and in which the main objective is the orderly, safe and service fast.

5. Security and operating criteria for the operation of the Island and Extraceninsular Electrical Systems

5.1 Electrical system security control variables. -The variables that allow you to monitor the state of the electrical system are:

● Frequency.

● Tensions in the knots of the transport network.

● Load levels into the different elements of the transport network (lines, transformers, and associated apartaments).

● Available regulatory reserves (active and reactive power).

● The exchange program for interconnections between islands or with another electrical system.

5.2 Contingencies to be considered in security analysis. The contingencies to be considered in the security analyses are:

● Simple failure of any of the elements of the system (Criterion N-1): generator group, line circuit, and transformer.

The following contingencies shall not be considered, except in those cases, that due to adverse weather conditions or any other justified cause is determined by the System Operator:

● The failure of the largest group generating an area and the subsequent failure of one of its connection lines with the rest of the system or interconnections between islands or with another electrical system or other group in the same zone, when after the first simple failure (group or line) the system is in a state of alert and it is not possible to recover the normal operating state by using the available means for the real-time operation.

● Double circuit failure.

5.3 Margins of control variables in the operation.

5.3.1 Normal system operation.

5.3.1.1 Frequency. The assigned frequency of the system is 50 Hz. Normal frequency variations shall be those between 49.85 and 50,15 Hz, with intervals of less than five minutes being accepted with values outside the range of 49.75 to 50.25 Hz.

Also, in the event of disturbances the System Operator may decide, in accordance with paragraph 9 of this procedure and in the light of the criticality of the situation resulting from such disturbance, to order the load manuals are removed in order to maintain the stability of the system.

The frequency values considered here may be modified according to the future evolution of SEIE.

5.3.1.2 Tension. The System Operator shall annually draw up a Tension Control Plan (PCT) for the different systems of each SEIE in accordance with the applicable voltage control procedures of the transport network.

The PCT shall set the voltage slogans to be maintained in normal operation at the different nodes of the transport network.

PCT will take into account the site design margins reported by each owning company, as well as the desirable stresses for minimizing transportation losses.

In any case, in normal state, the voltage will be within the margins indicated in the following table:

	Minimum	Maximo
220 kV Level	210 kV (95%)	245 kV (111%)
kV level	125 kV (95%)	145 kV (110%)
Level of 66 kV	62 kV (94%)	72 kV (109%)

The System Operator will publish annually the ratio of the knots in which it operates outside the limits proposed by systematic depletion of the available resources in operation

Voltage contingency may vary as set out in paragraph 5.3.2.

5.3.1.3 Load. The load levels of the elements of the transport network shall not exceed the nominal capacity of the transformers, nor the permanent thermal capacity of the transport network lines defined for each seasonal period, according to the referred to in paragraph 6.

In any case, capacity on a permanent basis may be limited to a value lower than that indicated where it is necessary for reasons of dynamic stability, there is a risk of a stress collapse or any other situation so so requires. A supporting report should subsequently be sent to the competent authority and to the NEC within one month,

After contingency, the load of the elements of the transport network may reach the values set out in paragraph 5.3.2.

5.3.1.4 Active Power Regulatory Reserves. Chapter 8 of this procedure sets out the primary, secondary and tertiary regulatory reserve requirements.

5.3.1.5 Reactive Power Regulatory Reserve. In each system the reserve of sufficient reactive power must be available to deal with the contingencies considered without exceeding the limits laid down in this paragraph for the stresses in the knots and taking into account the structural limitations of each existing system at every moment.

5.3.2 Security criteria for contingencies. The system security control variables should remain within the limits set out below for the contingencies set out in paragraph 5.2, not being produced for such contingency supply disruptions, except for those resulting from the load-shedding, and in addition the specific conditions laid down in the current quality of service regulations shall be complied with.

5.3.2.1 Simple failure (Criterion N-1). No permanent overloads are permitted on the lines of the transport network, with respect to its operational thermal limit, with transient overloads of up to 15% with a duration of less than 20 minutes.

Permanent overloads are not permitted in the transformers, with the transient overloads indicated in paragraph 5.3.2.4. "Summary table of safety criteria against contingencies". In any case, the System Operator shall take the corrective measures in real time that are accurate to eliminate the transient overloads in the shortest possible time.

Tensions, after recovery of the permanent regime, must be within the following limits:

	Minimum	Maximo
220 kV Level	205 kV (93%)	245 kV (111%)
kV level	123 kV (93%)	145 kV (110%)
Level of 66 kV	60 kV (91%)	72 kV (109%)

5.3.2.2 Double-loop line failure. The same permissible values shall be considered for the overload of lines and transformers that have been established for the simple failure case.

Tensions after the permanent regime recovery must be within the following limits:

	Minimum	Maximo
220 kV Level	200 kV (90%)	245 kV (111%)
kV level	119 kV (90%)	145 kV (110%)
Level of 66 kV	56 kV (85%)	72 kV (109%)

5.3.2.3 Successive failure of the largest group generating an area and of a connection line of that zone or interconnections between islands with the rest of the system and with another electrical system. The same permissible values shall be considered for the overloads of lines and transformers and the same limits for the stresses in the knots that have been established for the case of double-circuit fault lines.

5.3.2.4 Summary of the safety criteria against contingencies. Below is the summary table of the security criteria against contingencies. In any case, it must be verified that:

● No tension zeros are produced in any knot of the Transport Network.

● The eventual supply disruptions are a consequence of the load-shedding.

● The frequency is within the set of margins, if any, after the performance of the disleches by frequency.

● The regulatory reservations set forth in this Procedure are available.

SECURITY CRITERIA SUMMARY TABLE

(1) On subsea or underground cables, overloads and permissible voltages shall be imposed by the specifications applicable to the equipment in each individual case.

(2) The permissible overload values shall be lower than those indicated in those transformers for which a specific limitation is declared by virtue of the constructive or operational singularities that exist in the machine.

5.3.2.5 Other considerations. In addition to the above criteria, the absence of a situation of instability of tensions that may result in a collapse of tension should be ensured.

In the case of knots in the transport network fed by only two lines in which, in the event of the failure or unavailability of one of them, the criterion N-1 would no longer be met, a Safeguard Plan must be established specific in collaboration with the affected agents, to reduce if possible the effects that might result from the subsequent failure of the other line.

For the scheduling of work with unavailability of one of these lines, the risk of failure of the other should be assessed, choosing, in any case, the time and the most appropriate conditions for the work, according to the Area Distribution Manager.

For jobs with unavailability of a bar from a double-embedded substation with differential bar protection, the effects of the other bar's failure will be analyzed and all circumstances that can be taken into account will be taken into account In each particular situation, the impact on the security of the system should be duly considered, and a Safeguard Plan should be established if possible, in order to reduce, if possible, the effects of the failure of the other bar.

For the planning and authorisation of the discarding of elements of the protection systems or modification of their adjustments, account must be taken of the level of criticality of the different nodes of the network and the critical times of The invention relates to a method for the protection of the protected element, which can be used to open the protected element or to take other measures, such as blocking rehooks, speeding up the protection of the protection system, separating the protection system from the protection system, and the removal of the protective elements. bars, or other actions on the topology that prevent a fault in those conditions from having a severe impact to the system.

In those situations where there are risks of dynamic system instability, a complementary stability study will be carried out in which the contingency considered will be a frank three-phase lack action of the protection systems. The fault shall be placed at the most unfavourable point of the line in question. A time of action of the protection shall be considered in the first area not less than 100 ms.

When there is a Safeguard Plan in which the operational measures are established after a certain contingency that minimises its consequences, the System Operator may accept values other than those set out in this Plan. Procedure for control variables.

5.4 Extraordinary security measures. The System Operator, in the face of special situations such as major public events, adverse weather conditions, etc., will take the necessary measures to ensure security of supply by applying, if it considers necessary, more stringent criteria than those described in paragraph 5.3, if appropriate, to the competent administration within one month. The report shall indicate the measures taken, the alternative proposals and the costs associated with the adoption of these measures.

6. Setting the permissible load levels

The System Operator and the owning companies of the transport network facilities shall apply the criteria set out below to establish the permissible load levels on the lines and transformers of the transport network. their property that is part of that network.

6.1 Thermal limits. It is defined as 'capacity' or 'seasonal thermal limit', the maximum transport capacity of a permanent or permanent line, associated with a given time period.

The owners of the transport facilities shall determine the permissible capacity of the lines and transformers of their property, using the methodology to be approved and published by the Operator. system.

For the calculation of the transport capacity of the lines, account shall be taken of the provisions of the Technical Regulation of High-Tension Air Lines to ensure the safety of persons and facilities.

As a general rule, seasonal thermal limits will be set for the following periods:

Seasonal Thermal Limit

Period
Spring.	Open-May.
Summer.	June to September.
Autumn.	October-November.
Winter.	December to March

For the unique climatology of the Canary Islands, it is considered that, with thermal limits, the environmental conditions are equivalent to spring-autumn throughout the year.

In the case of those installations that are equipped with monitoring means to determine their thermal capacity in real time, the information of these facilities may be taken into account in the security analysis of the system.

The System Operator, after informing the agents, the competent authority and the NEC, may temporarily modify the periods of application of the seasonal thermal limits when conditions are met. exceptional weather to justify it.

6.2 Calculation methodology. The calculation models used for the determination of the transport capacity of lines and transformers shall cover the following aspects:

6.2.1 Thermal model for the device. The equations governing the thermal behaviour of the device, the historical statistical data of temperatures and the maximum design temperature of the device shall be taken into account.

6.2.2 Thermal model for drivers. The equations that govern the thermal behaviour of the conductors, the historical statistical data of temperatures, the maximum design temperature of the conductor and the solar radiation will be taken into account. A wind speed of 0,6 m/s shall be considered.

6.2.3 Thermal model for transformers. The seasonal thermal limits applicable to processors shall be those which are deducted from the IEC 354:1991 plus the corrigendum of 1992 (Guide to loading for power transformers submerged in oil), which takes into account the environmental conditions and permissible overloads.

6.3 Periods of the calculation of the permissible levels of load. The updates of the thermal capacity of the transport facilities shall be carried out whenever there is any variation of the characteristics of the equipment, and shall be communicated to the System Operator in good time on the Planned date for implementation.

Additionally, the companies that own the transportation network will perform at least an annual update of the data of their facilities, communicating such a review to the Operator of the System before April 1 of each year. Such reviews shall be published by the System Operator upon validation.

7. Power delivery conditions at the points border with the transport network

The companies that own the transportation network facilities are responsible for operating their facilities following the instructions received from the System Operator, so that the conditions of the power delivery set out in this section.

In addition, the specific conditions to be established in the current quality of service regulations must be met in this procedure.

As regards frequency variations and tensions at the border nodes of the transport network, the provisions of paragraph 5.3.

7.1 Supply Disruptions and Voltage Gaps. The permissible values for supply disruptions and voltage gaps shall be determined in the current quality of service regulations.

7.2 Short circuit power. The System Operator shall publish annually the variation intervals of the short circuit power in the nodes of the transport network under its management.

8. Establishment of reserves for frequency/power regulation

The System Operator will set the necessary regulatory reserve levels in each SEIE to address the imbalances between actual generation and consumption.

Depending on the time scale in which your action takes place and the signal originating from your action, three levels of reservation are set:

● Primary throttling reserve.

● Secondary regulation reserve.

● Tertiary regulation reserve.

Without prejudice to this procedure for the regulatory reserves indicated, specific procedures for the management of the corresponding supplementary services shall be taken into account implementation, in which the aspects relating to this issue are fully developed.

The System Operator will determine the maximum power value for interconnections between islands or other electrical systems.

8.1 Primary Regulatory Reserve. For each SEIE system, the primary regulatory reserve in each schedule period shall be at least 50% of the highest net power allocated to a generator group among those scheduled in that time period. For this purpose, all members of a multi-axle combined cycle regardless of the type of turbine (gas or steam) shall be considered as individual generators. The reserve shall also be considered as providing the electrical links between islands or with other electrical systems with contingency N-1. The distribution of the primary reservation between the generators will be performed according to the Primary Regulatory Procedure.

The primary reserve value shall be reviewed, where appropriate, in the light of any modifications to the Automatic Load Download Plan or other external elements with influence on that value, thereby reporting to the competent authority and the NEC.

8.2 Secondary regulation reserve. The reserve to be kept in secondary regulation, in each SEIE system, shall be determined by the System Operator for each schedule period, depending on the expected temporary evolution of the demand, the probable failure of coupled generators and of the variability of wind production.

The sum of the primary and secondary reserves allocated in each schedule period, provided that the technical conditions permit, must equal at least 100% of the largest of the following amounts:

● The highest net power allocated to a generator among those scheduled in that time period. For this purpose, all members of a combined multi-axle cycle, however on ramp up of demand, shall be considered as individual generators, the generators moved by the gas turbines shall be counted as one and a half times their value. Scheduled power in the time period to consider the loss of load on the steam turbines associated with faults in the gas turbines.

● The expected growth in demand between the scheduling period of which the reservation is to be determined and the next.

● Power to provide electrical links between islands or with other electrical systems with N-1 contingency.

● The most likely loss by a decrease in the coupled wind power, which will be determined by the System Operator hourly, applying to the nominal total power of said generators a calculated reducing coefficient on the basis of their productive variability.

The secondary reserve to be lowered in each programming period, provided that the technical conditions permit, will be at least 50% of the reserve to be raised

The secondary reserve values considered here may be subject to modification in accordance with the future developments of SEIE.

8.3 Tertiary regulation reserve. The necessary reserve of tertiary regulation to be increased in each schedule period shall be, as a reference, equal to the largest of the following amounts:

● The highest net power allocated to a generator among those scheduled in that time period. For this purpose, all members of a multi-axle combined cycle shall be considered as individual generators, however, generators moved by the gas turbines shall be counted as one and a half times their programmed power in the the time period to consider the loss of load on the steam turbines associated with faults in the gas turbines.

● The expected growth in demand between the scheduling period of which the reservation is to be determined and the next.

● Power to provide electrical links between islands or with other electrical systems with N-1 contingency.

● To the most likely loss by a decrease in the coupled wind power, which will be determined by the System Operator hourly, applying to the nominal total power of said generators a calculated reducing coefficient on the basis of their productive variability.

The tertiary reserve values considered here may be subject to modification in accordance with the future developments of SEIE.

9. Establishment of security plans and operational measures

The Operator of the System will establish, with the collaboration of the owners of the affected facilities, and make available to all the agents, the safety plans that allow to deal with the different situations which may be present in the operation of the system in order to ensure their safety.

Security plans, depending on the operating situation to which they are applicable, are classified into: Safeguard Plans, Emergency Plans, and Service Reposition Plans.

9.1 Safeguard Plans. The Safeguard Plans will provide for the measures to be taken to prevent the system from being outside the normal state or, where appropriate, to recover that state in the shortest possible time, in order to prevent triggering incidents that could have an important negative impact on both the electrical supply and the operation of the generators.

The Safeguard Plans will be set:

● Post-contingency corrective actions, including generator telefiring plans, to be adopted by operators to return the system to the normal operating state.

● Accurate preventive actions for those cases where the repercussions could be serious for the system and possible post-contingency corrective actions cannot be made effective in a time that is useful for the operation (case of requiring, for example, the connection of a new thermal group in the same zone).

9.1.1 Telefiring plans for generators or other elements of the transport network. The System Operator may propose to the Directorate-General for Energy Policy and Mines to establish plans for telefiring of generators or other elements of the transport network in those areas where certain contingencies may cause significant overloads or the loss of stability of the groups in that area.

9.2 Emergency Plans. The purpose of the Emergency Plans is to minimize the scope and extent of the incidents once these have occurred, and to return the system to the normal operating state in the shortest possible time. Consequently, only the post-contingency corrective actions that are accurate in each case, including the performance of the load-shedding equipment by minimum frequency and the selective load-shedding, shall be considered as such plans. manual or by means of telefiring of lines and transformers.

9.2.1 Automatic load shedding. Given the condition of small-scale electric islands, in SEIE, sometimes and in the face of certain generation-demand imbalances, the burden-shedding will be considered as an acceptable and unavoidable operating practice.

The System Operator, considering the proposals made by the distribution companies, will propose for approval to the competent administration, prior to the report of the National Energy Commission, the Planes de Desballast Automatic Cargas necessary for cases where, due to a very severe incidence, the balance between the generation and the demand of the system cannot be restored by the implementation of other control actions.

These plans will be based on the performance of an automatic load-shedding system for minimum frequency, to achieve a controlled disconnection of such loads.

The Auto-Cargas Ballast Plans will establish a tiered ballast, disconnecting the pumping groups first, and subsequently, to lower frequency values, or higher rate of variation of the same, non-critical preselected load sets.

This disconnect will be performed according to the frequency thresholds, frequency variation rate, magnitude in load, and specification of the same to be set in the Auto Load Ballast Plans.

The distribution system operators and the customers connected to the Transport Network must install frequency relays whose performance is in accordance with the general criteria set out in this Procedure and those which are establish in the Auto-Cargas Ballast Plans that are in force at any time. The location, performance criteria and characteristics of these relays may not be modified without the prior agreement of the System Operator.

The production companies must ensure, provided that the protection of the internal equipment so permits, that the minimum frequency protection of the generating groups, including those covered by the special scheme, are coordinated with the automatic load-shedding system, and may only be disconnected from the network if the frequency falls below 47,5 Hz, for a period of 3 seconds or more. Those generators which were in service prior to the application of this procedure would not be technically equipped to do so.

The System Operator will be able to perform, activation simulations of these Automatic Cargas Ballast Plans for a minimum frequency, according to the protocols that are defined.

In the same way, the performance of automatic load-shedding or telefiring of lines and transformers may be envisaged, if, after the successive implementation of the relevant operational measures, such measures are necessary. The Commission shall, in accordance with the Commission's decision, take the necessary steps to ensure that the Commission is not in a position to do

.

9.2.2 Manual load-selective ballast. If after the successive application of the operating measures that are applicable in situations of alert and emergency of coverage of the demand, it is necessary to arrive at the disballast of selective charge for there is imminent risk for the continuity of the supply, the System Operator shall provide instructions for distribution companies to proceed to the indicated ballast.

By applying the manual load shedding, it is intended to avoid a larger disturbance.

In order to be able to apply this measure in the best possible conditions of control and minimisation of its impact on consumers, the distribution companies must have previously available the corresponding Plans of Load shedding, the effectiveness of which shall be evaluated by the System Operator. Accordingly, the distribution companies will refer to the System Operator the corresponding updated versions of these Plans.

The load shedding plans of each distribution company should consider maximum load blocks that will be defined for each system according to its characteristics, identifying the ballast sequence of each of the and the order of affectation for the case of rotatoriums. In the light of the above requirements, the load shedding plans shall at least include the following information:

● Island or Autonomous City.

● Township/Comarca.

● Nudo or electric knots of the transport network from which the load is fed.

● Estimated power-slip power in the knot or electric knots.

● Predominant load type fed by each transformer, transformer group or medium voltage lines (industrial, rural, services or domestic).

The unlastres should be produced according to the following considerations:

9.2.2.1 Unballast threshold. The control variables to be used to issue the ballast instructions shall be the frequency, the severe overloads on the transport or distribution network equipment that are critical to the system and the failure finding of manifest and sustained capacity to fuel consumption.

The System Operator will issue the ballast instructions when any of the following conditions are verified for the parameters associated with the control variables:

● Frequency

By thresholds or rate of frequency variation and insufficient manifest and sustained capacity to recover frequency to its assigned value.

The System Operator considering the best data available on the system and the analyses it performs on the basis thereof, will determine the effective frequency or frequency variation rate thresholds, which a time will result in load shedding orders.

● Overloads on transport or distribution network equipment

Existence of overloads that require to proceed to the load shedding in order to prevent their loss imminently and/or the occurrence of a disturbance. The magnitude of the allowable overloads will depend on the equipment and the adjustment of the protections.

9.2.2.2 Cargas affected by the ballast. The System Operator will determine:

● The knots of the transport network in which the load should be unloaded.

● The magnitude of the power to deslastrar and the supply distribution company of that power.

● The allocation of the power to be allocated by each distribution company will be a direct function of its market share for the last year in the affected area.

● Start time of the ballast and estimate of the period during which it will be maintained.

For the purposes of this procedure, a distribution company whose network is coupled to the network of another major distribution company shall be considered as a burden on the latter undertaking.

Distribution companies will make the choice of customers who must be affected by trying to minimize the impact on service users, avoiding, as far as possible, the involvement of essential services. and the reiteration of the debits on the same client or set of clients. For this purpose, if necessary, a rotating customer impact criterion will be applied.

If the burden to be charged is higher than that provided for in the Load Ballast Plans, or the time available to execute the debastres is not sufficient for the implementation of these Plans, the companies of distribution will proceed to load loads by complete knots of the distribution network, ensuring the compatibility of the tlesetres with the instructions issued by the System Operator.

9.2.2.3 Disballast Instruction Communication. The System Operator shall communicate the ballast instruction as far as possible to the control centres of the distribution companies.

This communication will take place by telephone, with subsequent confirmation by fax or e-mail, and must be recorded in a timely manner in such a way as to enable it to be verified later.

Without prejudice to the communication actions that the distribution companies carry out in order to inform their clients, the Autonomous Government and the competent local authorities as far as possible, the Operator the System shall inform the competent Ministerial Agencies, the Presidency of the Government and the Autonomous Government, who shall determine the subsequent actions of communication to the society and to the means that are relevant.

9.2.2.4 Disballast confirmation. The distribution companies shall confirm to the System Operator the execution of the load-shedding.

9.2.2.5 Normalisation of supply. When the control variables that were used to issue the ballast instructions are such that, with the coupling of loads, the existence of new violations of the ballast thresholds that put at risk the risk is not foreseeable. supply, the System Operator shall establish the replacement procedures or give instructions to the distribution companies to initiate the progressive replacement of the load (s) by indicating:

● The knots of the transport network in which you will need to replenish the load.

● The total power of the loads to be coupled.

The reorder process will be performed progressively to the total normalization of the power supply.

9.2.2.6 Confirmation of supply normalization. The distribution companies will confirm to the Operator of the System the normalization of the electrical supply, indicating the powers, time and energies finally not supplied, indexing this information with the list of the affected lines according to The corresponding Load Download Plan.

9.2.2.7 Information issued by the System Operator. Within one month, the System Operator will submit a report to the Ministry of Government, the Autonomous Government and the National Energy Commission, in which all the relevant aspects of the incident that have caused the incident will be detailed. load ballast.

9.2.2.8 Exceptional mechanism of action. Given the characteristics of SEEI, there may be situations where it is necessary to carry out three selective handbooks complementary to the automatic loading or preventionthree, in the face of imminent inavailability in the system, which for their own urgency they cannot be articulated as referred to in the above points, because of the over-coming causes which require immediate action and which, therefore, must be implemented by the distribution companies without prior order by the System Operator.

The application of these manual delectswill be reduced, therefore, only to these situations and will aim to avoid a wider disturbance. The action procedure shall be defined for the manual load-shedding in the preceding points, except as regards the prior order of the System Operator.

In these assumptions, if the incident affects a single distribution company, it will communicate it to the System Operator and will execute the ballast, or vice versa depending on the premurs in the execution of the same. In the event that the incident affects several distribution companies, the network management company which has detected the problem, depending on the urgency of the ballast, may communicate it to the Operator of the System who, in turn, will act as previously determined, or you may directly and fully execute it over the network of your property by communicating it to the System Operator "posteriori".

The company that applied for or executed the ballast must subsequently justify the convenience and need thereof within the time and form established by the System Operator.

9.3 Service Replenishment Plans. The Service's Reposition Plans aim to return the electrical system to the normal operating state after severe incidents that have caused supply disruptions in extensive areas of the system.

The processing and updating of the Service Replenishment Plans for each system is the responsibility of the System Operator. To do this it will have the collaboration of the distributors and generators present in each system, and of the CNE.

These plans will systematize the actions to be performed by the different control centers and local operating personnel in the substations in the event of a widespread incident.

In the event of a zonal or total incident, the control centers of the different producers, distributors and carriers will proceed to replace the service under the coordination of the System Operator, as set out in the corresponding Replenishment Plans.

In a general way the replenishment of the loads must be carried out by the agents in the terms that are established in the Plans of Service Reposition. These plans must also refer to the automatic replacement of service devices installed, in the event that their existence is authorized, and to their interrelation with the action of the aforementioned agents. Consequently, the autonomous performance of automatic load replacement devices shall be limited to the cases covered by those Plans.

The System Operator will be responsible for coordinating the replacement drills that take place.

PO.SEIE 2.2: Demand coverage, generation programming, and high in economic dispatch

1. Object

To analyze the demand coverage of the Island and Extraceninsular Electrical Systems (SEIE), and to program the precise generation resources to achieve this coverage with the lowest possible cost, respecting the criteria of security and quality of service contained in the procedure for the operation of the Insular and Extraceninsular Systems (P.O. 1 of SEIE), as well as establishing the requirements for the discharge of new agents in the economic office.

2. Scope

This procedure encompasses the processes for the coverage of each of the SEIE systems, in their annual, weekly, and daily horizons.

3. Scope of application

This procedure applies to the following subjects:

a) System Operator.

(b) Single carrier and distributors who are exceptionally holders of transport facilities.

c) Business owners or operators of the distribution networks.

(d) proprietary companies or operators of generators directly connected to the transport network or participating in the economic dispatch.

e) Marketers.

(f) Consumers who acquire the energy in economic dispatch.

4. Coverage with annual horizon

The purpose of this is to analyse the security of supply of the different electrical systems, taking into account the generation resources and the existing transport network, with an estimate of the generation costs. predictable.

4.1 Coverage and Security Analysis Plan. The System Operator shall, at least on a quarterly basis, draw up a forecast covering the demand for the system and a security analysis of that coverage with a mobile annual horizon, at least quarterly, by the first day of each month, information for months.

This will take into account the annual forecast of demand calculated according to the P.O. 2.1 of the SEIE and the information received from the agents, regarding the expected availability of the equipment, the state of the reserves hydroelectricity, where appropriate, and forecasts of fuel stocks.

4.2 Coverage report. As a result of the coverage security analysis and forecast, the report will include:

1. A balance sheet with the resulting coverage, taking into account the stochasticity of the failure of the generating units, of the wind contribution, of the rest of the special regime and of the hydraulicity, if they come. The coverage balance shall be broken down by months and by each SEIE system, indicating the foreseeable participation in the coverage of the different generation resources grouped by technology and fuel types. In the case of interconnected islands, an island breakdown will be made, detailing the interconnections. In the case of links to other electrical systems, the exchange of energy shall be detailed.

2. Monthly estimate of the variable coverage costs broken down according to the criteria of the previous point, in those plants that are subject to the economic dispatch of the System Operator.

3. Coverage rates of the different SEIE systems and risk of failure of supply, where appropriate. The analysis will assess the risk of supply failure that could result from the availability of the production resources themselves, using, as risk indices, the probability of non-coverage of demand, the expected value of energy and not supplied and the reservation margin.

4. A zonal analysis, when applicable, that will highlight the special needs for the availability of generation and transport equipment to avoid situations that result in the failure to meet the system's security criteria in certain geographical areas or particular areas of the network.

The report will be sent to the relevant central and regional authorities, the National Energy Commission and the agents involved.

4.3 Method of study. The following criteria shall apply to carry out the coverage forecast studies:

● The coverage will be performed based on the opportunity cost of the generation. For thermal power plants this cost will be determined by the variable costs defined in the current regulations. For reservoir hydraulic power stations, where appropriate, this cost of opportunity shall be the avoided cost of the replaced thermal generation.

● Stocks in coal parks and in fuel tanks will be declared by their owners at the beginning of each study period.

● The plans for the review of the plants will be the ones prepared by the System Operator based on the information received from the owners. However, as indicated in the procedure governing the maintenance plans of the production units (P.O. 2.5 of SEIE), the review dates will be subject to the approval and, if necessary, amended by the Operator of the System, based on guarantee of supply guarantee and minimization of cost of coverage.

● The Lower Calorific Power (PCI) consumption structure shall be that obtained from the operating data of the plants recognized by the competent Ministry.

● The energy to be ceded to the network by the producers of Special Regime will be estimated from historical data, trends and information from official agencies and declarations of the owners of the facilities.

Demand coverage, with the generation resources available in each electrical system, will be performed by minimizing the variable cost of production using an appropriate model that, if proven necessary, shall take into account the outstanding characteristics of the network in the form of transport restrictions. This minimisation of the cost of production will take into account the possibility of avoiding starts and/or stops of groups that result in a reduction in the final cost of coverage with an annual horizon.

On the other hand, the zonal analysis of the behavior of the transport network will use network calculation tools that will be applied to typical cases of operation of the systems. The results shall show the possible restrictions of each system and, consequently, the measures to be taken in each situation in relation to the operation of the systems.

4.4 Required information.

4.4.1 Hydraulic Central. Before the 20th day of each month or, where applicable, of the immediately preceding business day if that is a holiday, the companies shall send the System Operator the following information:

● Expected Caudals.

● Boots and volumes stored in reservoirs.

● Maximum hydroelectric power that can be maintained for twelve consecutive hours, once every week.

● Those restrictions on the exploitation of the regulatory reservoirs that may eventually exist.

● Predictable variations in the availability of hydraulic and pumping groups.

4.4.2 Coal thermal power stations. Before the 20th day of each month or, where applicable, of the immediately preceding business day if that is a holiday, the companies shall send the System Operator the following information:

● Coal stocks in tons, broken down by type, or in default in millozres of PCI termine.

● Structure of consumption and fraction of each type of fuel that needs to be mixed, if any, for environmental or other reasons.

● Coal supplies expected in the next six months specifying the quantities, expected delivery dates, lower calorific value and expected or administratively established prices for each consignment.

● Predictable variations of the availability of the groups, whatever their cause.

4.4.3 Central or fuel oil, diesel-oil, gas-oil or gas. Before the 20th day of each month or, where applicable, of the immediately preceding business day if that is a holiday, the companies shall send the System Operator the following information:

● Stocks of each fuel stored in tanks or in storage, classified by type and with specification of the groups to which it is intended, if any.

● Fuel types or, where appropriate, mixtures intended to be consumed by each group of the plant.

● Fuel supplies expected in the next six months specifying the quantities, expected delivery dates, lower heat power and expected or administratively established prices of the heat each type and item.

● Predictable variations of availability of different groups whatever their cause.

4.4.4 Central or special regime groups. Before the 20th of each month or, where appropriate, of the immediately preceding business day if that is a public holiday, undertakings shall send to the System Operator the information relating to foreseeable variations in the availability of the various groups. whatever their cause.

4.4.5 Demands for knots. The Operator of the System will proceed to make a distribution of the overall demand between the border of the transport-distribution.

5. Weekly coverage and programming

It is intended to determine weekly the plan of starts and stops of generating groups, minimizing the variable cost of production, meeting the criteria of guarantee and quality of supply prescribed in the procedures In addition to the relevant technical and environmental restrictions, the operation is also taking into account.

5.1 Coverage plan and weekly program. Before 15 hours each Thursday, the System Operator will draw up the expected demand coverage for the week starting at 0 h on the following Saturday and ending at 24 h on the following Friday.

The coverage plan will consist of the following documents:

1. Weekly schedule broken down by days and with a detailed schedule, specifying the load of the different generation groups that contribute in each hour to the corresponding demand coverage. The programme shall specify the energy of interisland interconnections, with their meaning, as well as the energy, with their meaning, in the links with other electrical systems.

2. An orderly relationship of groups to be started or stopped in place of possible breakdowns and inavailabilities of the units initially programmed or variations in demand.

3. Schedule of the planned reserves of regulation, primary, secondary and tertiary, with indication of the generating groups responsible for supplying them and explicit expression of the power in reserve in each of them.

4. Summary of variable production costs, by groups, and estimate of the cost of the regulatory reserve.

5.2 Method used for the elaboration of the weekly program. The System Operator shall carry out in each system the economic dispatch by variable costs of the generation, to cover the expected net demand, taking into account the restrictions mentioned above, and guaranteeing the Reserve availability as defined in P.O. 1 of SEIE.

This will take into account the technical parameters approved in each generator group, particularly the following:

● Net effective power and minimum technical power,

● Power up and down ramps,

● Start times and costs,

● Operating variable costs defined in the regulations based on load level,

● Contribution capacity to the primary, secondary, and tertiary regulatory rolling power.

You will add:

● Information communicated by the inavailabilities agents or additional restrictions on the operation of the generators.

● The schedules schedules and communicated by the special regime generators. The System Operator will review the planned programs and use the best available forecast in the dispatch, particularly in the unmanageable generation.

● The best time demand forecast available at the weekly level (P.O. 2.1 of SEIE).

The dispatch process will consist of at least two stages:

1. Initial dispatch with exclusively economic criteria: At this stage the generation and rolling stock of each generator group, for each of the hours, is assigned as a single knot.

A variable cost minimization model will be used to take into account the characteristics of the aforementioned input data. For this minimisation of the cost of production, consideration will be given to the possibility of avoiding starts and/or stops of groups that result in a reduction in the final cost of the weekly coverage programme.

In case of hydraulic equipment with reservoir, information from the value of water in reservoirs calculated in a longer-term optimization of the system will be incorporated as input data (section 4.3).

In the calculation of filling of the demand curve, the expected generation of special regime will be placed on the basis, without cost consideration.

2. Analysis of the possible restrictions imposed by the transport network on this base situation, for violation of the limits imposed in normal state of operation on the variables of control of the system, and in the face of the contingencies established in the P.O. Box 1 of SEIE.

A readjustment of the generation will be carried out if necessary, with security and economic criteria, identifying conditions for the forced operation of groups, and recalculating with these conditions the economic dispatch of the coverage of the best way to ensure compliance with the limits imposed by the normal operating safety criteria, according to P.O. 1 of the SEIE referred to above.

In case of the Balearic Electrical System, the specified in the PO SEIE 2.3., contemplating the connection between systems, provided that it is available, and with respect to the minimum technical load of the connection.

5.3 Weekly information to supply to the System Operator.

5.3.1 Generation:

5.3.1.1 Ordinary regime generators. Before 14 h of each Tuesday, or of the working day immediately preceding if that has been festive, the production companies shall make available to the Operator of the System, in the formats and means of communication established by the Operator of the System, the following information:

5.3.1.1.1 Hydraulic Central.

Quotas and volumes stored in reservoirs.

Expected flows.

Restrictions on the exploitation of regulatory reservoirs.

On each hydraulic system:

● Maximum hydroelectric power that, with the predicted flow rates, can maintain for 4 consecutive hours.

● Maximum hydroelectric power that, with the predicted flow rates, can maintain for 12 consecutive hours.

Total or partial inavailability of hydraulic and pumping groups.

5.3.1.1.2 Thermal Central. Where appropriate, the existence of any problems with fuel supplies.

Total or partial inavailabilities of the groups, whatever their cause, and variations in maintenance that might alter the annual plan.

Restrictions or variations in the operation of groups.

5.3.1.2 Special regime generators. Before 14 h of each Tuesday, or of the working day immediately preceding if that has been festive, the production companies shall make available to the Operator of the System, in the formats and means of communication established by the Operator of the System, information regarding total or partial inavailabilities of the groups, whatever their cause, and variations in maintenance that could alter the annual plan.

5.3.1.2.1 With participation in the economic dispatch or connected to the transport network. -Special regime generators involved in the economic dispatch of generation or connected to the transport network must communicate to the System Operator before 14 h of each Tuesday, or on the immediately preceding business day if that is a public holiday, the planned hourly energy programme of production, broken down by type of generation, during the week starting at 0 h on the immediate Saturday and ends at 24 h the following Friday. Such communication shall be carried out by the means and in the form specified by the System Operator.

5.3.1.2.2 No participation in economic dispatch.-Special regime generation representatives who do not come to the economic office, must report to the System Operator before 14 hours each Tuesday, or on the business day immediately preceding if that is a public holiday, the planned hourly energy programme of production, with breakdown by type of generation, during the week starting at 0 h on the immediate Saturday and ending at 24 h on the following Friday. Such communication shall be carried out by the means and in the form specified by the System Operator.

The System Operator may require those special-speed generators connected to the distribution network, with a significant size, the production schedule of the production schedule, to be sent to you before the 14 h of each Tuesday, or of the working day immediately preceding if that was a holiday. In this case such a programme shall not be included in that submitted by the distributor undertaking of its energy.

5.3.2 Demand:

5.3.2.1 Marketers. The marketing companies must notify the System Operator before 14 h of each Tuesday, or of the business day immediately preceding it, if it is festive, by means and forms specified by the Operator of the System, its demands System-estimated time, in central bars, for the week between 0 and 24 h on the following Friday.

5.3.2.2 Consumers who acquire the energy in economic dispatch. Consumers who purchase their energy directly from the office of generation must notify the System Operator before 14 h of each Tuesday, or of the working day immediately preceding it, if it is festive, by means and forms which specify the System Operator, its system-estimated time demands, in central bars, for the week between 0 and 24 hours on the following Friday.

5.4 Program Communication by the System Operator. Every Thursday before 15 h the System Operator shall communicate to the generating and distribution undertakings the complete programming, which shall include at least points 1, 2 and 3 of paragraph 5.1, by the procedure specified by the Operator of the System. System. If the schedule is festive on Thursday, the schedule will be advanced to the previous Wednesday or, if necessary, the most convenient day can be agreed.

6. Daily programming

Try to adapt the programs coming from the weekly horizon described above, to the known situation of the systems, both as regards the generation and the state of the network, the day before the first object of this programming.

Consequently, its object is to obtain, on day D, a program with a content similar to the weekly program described above and with the same requirements regarding the fulfilment of quality and safety criteria and minimisation of variable costs, including at least day D + 1.

6.1 Coverage Plan and Daily Program. Before the 14 h of each day D, or before the time limit set for the publication of the Provisional Viable Daily Program (PDVP) in the peninsular electrical system (SEP), in those systems electrically connected with the SEP, the Operator of the System shall draw up the coverage of the expected demand for at least day D + 1. The daily coverage programme shall only take into account the first three points of paragraph 5.1 above.

6.2 Method used for the elaboration of the daily program. The economic dispatch, the parameters used, and the calculation process, will follow the same guidelines as in the weekly coverage (section 5.2), for the time frame of the period D + 1.

6.3 Daily information to provision to the System Operator.

6.3.1 Generation:

6.3.1.1 Ordinary Regime Generators. Before 10 h of day D, the production companies shall make available to the System Operator, in the formats and media specified by the System Operator, the following information:

Update, by variations, of the required information for the weekly programming (section 5.3.1), on the horizon D + 1 at the end of the following Friday.

6.3.1.2 Special Regime Generators. Before 10 h of day D, the production companies shall make available to the System Operator, in the formats and means of communication specified by the System Operator, the information relating to the updating, by variation, of the information required for the weekly programming (paragraph 5.3.2), on the horizon D + 1 at the end of the following Friday.

6.3.1.2.1 With participation in economic dispatch or connected to the transport network. Special system generators which are involved in the economic dispatch of generation or which are connected to the transport network shall communicate to the System Operator before the 10th hour of the day the planned programme of production of energy time, with breakdown by type of generation, between 0 h of day D + 1 and 24 h of the following Friday. Such communication shall be carried out by the means and in the form specified by the System Operator.

6.3.1.2.2 No participation in economic dispatch. The representatives of the generation of special arrangements who do not come to the economic office shall report to the System Operator before the 10th day of the day of the planned time-energy programme of production, with a breakdown by type of generation, between 0 h of day D + 1 and 24 h of the following Friday. Such communication shall be carried out by the means and in the form specified by the System Operator.

The System Operator may require those special-speed generators connected to the distribution network, with a significant size, the production schedule of the production schedule, to be sent to you before the 10 h of every day. In this case such a programme shall not be included in that submitted by the distributor undertaking of its energy.

6.3.2 Demand:

6.3.2.1 Marketers. The marketing companies must notify the System Operator before 10 h of day D, by means and forms specified by the System Operator, their estimated time demands by system, in central bars, for the period the average time between 0 h of D + 1 and 24 h of immediate Friday.

6.3.2.2 Consumers who acquire the energy in economic dispatch. Consumers who buy their energy directly from the economic office of generation must communicate to the System Operator before 10 h of day D, by means and forms specified by the System Operator their time demands. estimated by system, in central bars for the time period between 0 h of D + 1 and 24 h of immediate Friday.

6.4 Program Communication by the System Operator. Every day before 14 h, or before the deadline set for the publication of the Provisional Viable Daily Program (PDVP) in the peninsular electrical system (SEP), in those systems electrically connected with the SEP, the Operator of the System shall communicate to the generating and distributing companies the full daily programming, by the procedure specified by the System Operator.

7. High in economic dispatch

7.1 High of new generators

7.1.1 Ordinary Regime Generators. The requirements necessary for the incorporation into the economic office of a new generating agent or ordinary regime generator group are as follows:

● Report to the System Operator of the corresponding authorization granted by the Autonomous Community or Autonomous City, as well as to present the corresponding provisional registration in the Administrative Registry of electrical energy production facilities of the competent Ministry, as specified in Article 6 of Royal Decree 1747/2003

● In case the generator connects in the transport network, meet the technical access requirements imposed by the System Operator as specified in the SEIE's Operation 12.1 Procedure

● Communicate to the System Operator the technical and economic parameters required for the coverage issue, which are validated and approved by Resolution of the General Directorate of Energy Policy and Mines in which establish the technical parameters with impact on the economic remuneration of the new generator group

● Perform the communication tests with the System Operator's information and measurement system without failure, according to the information exchange specifications set by the System Operator.

● Communicate to the System Operator the information specified in the SEIE Operation 9 Procedure, corresponding to the production units under ordinary regime.

● Meet the requirements set forth in the Unified Measurement Points Regulation and other applicable regulations.

After three working days from the fulfilment of the above conditions, the new entrant will be incorporated into the economic office at the following weekly schedule.

7.1.2 Special Regime Generators. The requirements for incorporation into the economic office of a new generating agent or special regime generator group are as follows:

Present to the System Operator the certificate of the competent Ministry where the provisional registration of the installation in the Administrative Registry of installations of production of electrical energy in the system is recorded special.

Obtaining the Certificate of the Operator of the Technical Adequacy System for the incorporation of special regime installations into the office of generation, which implies:

● Communicate to the System Operator the information specified in the SEIE Operation 9 Procedure, corresponding to the special-regime production units.

● In case the generator connects to the transport network, meet the technical access and connection requirements imposed by the System Operator as specified in the SEIE's Operation 12.1 Procedure.

● Meet the requirements set forth in the Unified Measurement Points Regulation and other applicable regulations.

● All special regime installations with a power exceeding 1 MW, or less than 1 MW but forming part of a pool of facilities with a power of more than 1 MW and those installations establishing the Corresponding Autonomous Community, they must be attached to a control center, which will act as interlocutor with the Operator of the System, sending him the information in real time of the facilities and making his instructions executed in order to ensure at all times the reliability of the electrical system.

● Perform, without failure, the communication tests with the System Operator's information and measurement system, according to the information exchange specifications set by the System Operator.

After three working days from the fulfilment of the above conditions, the new entrant will be incorporated into the economic office at the following weekly schedule.

7.2 High buyers. The requirements for incorporation into the economic office of a new buyer agent are as follows:

● Marketers

Report to the System Operator the requirements specified in Article 16 of Royal Decree 1747/2003

Meet the technical requirements imposed by the System Operator for access to the transport network if necessary, as specified in the SEIE's Operation 12.1 Procedure.

Perform the communication tests with the System Operator's information and measurement system without failure, according to the information exchange specifications set by the System Operator, if applicable.

● Consumers who acquire energy in economic dispatch

Report to the System Operator the requirements specified in Article 17 of Royal Decree 1747/2003

In case the consumer who acquires the energy in the economic dispatch connects in the transport network, meet the technical requirements of access imposed by the Operator of the System, as specified in the Procedure of Operation 12.1 of SEIGs

Perform the communication tests with the System Operator's information and measurement system without failure, according to the information exchange specifications established by the System Operator, if applicable.

After three working days from the fulfilment of the above conditionalities, the new entrant will be incorporated into the economic dispatch at the following weekly schedule

P. .SEIE 2.3: Programming of the power exchange by the electrical link between the Balearic electrical system and the peninsular electrical system

1. Object

To establish, within the framework of the provisions contained in Royal Decree 1623/2011, of 14 November, which regulates the effects of the entry into operation of the link between the Peninsular Electrical System (SEP) and the Balear (SEB), and in compliance with what is established in the additional provision second to it, the form of programming of the energy exchange in said electrical link, to incorporate this energy into the SEB's demand coverage.

2. Scope

This Procedure determines:

a) The way to set up the energy exchange program in the different programming horizons.

b) The methodology for the acquisition of energy in the Iberian electricity production market (MIBEL).

3. Scope of application

This Procedure applies to the following subjects:

System Operator (OS)

Proprietary companies or operators of generating groups participating in economic dispatch.

Direct traders and consumers of the SEB, without prejudice to the provisions of the first transitional provision of Royal Decree 1623/2011. In the context of the provisions of that transitional provision and as long as the revision provided for therein has not occurred, the references in this P.O. to the persons referred to above shall be construed as being made only to the traders of last resource.

4. Coverage with annual horizon

The OS will prepare a forecast for coverage of the system's annual demand, along with a security analysis of the system. This annual horizon coverage forecast will cover the energy exchange programme for the electrical link connecting the SEB to the SEP and to be determined as follows:

● The maximum allowable energy exchange shall be established on the link with the SEP, under normal conditions and in the event of an emergency situation in the SEB, respecting the established security criteria.

● Timing prices shall be allocated to the energy of the SEP on the basis of the average hourly values, by type of day, of the marginal price of the Daily Market in the last mobile year available.

● An economic office will be resolved, which will take into account the maximum allowable energy exchange under normal conditions from the SEP to the SEB, at its cost, with which the annual energy exchange programme will be obtained by the links to the SEP.

The previous exchange program will be part of the annual demand coverage program as set out in the SEIE 2.2 P.O..

5. CWeekly programming and programming

The OS will prepare a forecast of coverage of the weekly demand of the system, meeting the criteria of guarantee and quality of supply prescribed in the operating procedures and taking into account also the restrictions relevant techniques. This weekly horizon coverage forecast will cover the power exchange program for the electrical link connecting the SEB to the SEP and to be determined as follows:

● The maximum allowable energy exchange shall be established on the link with the SEP, under normal conditions and in the event of an emergency situation in the SEB, respecting the established security criteria.

● Time prices will be allocated to the energy of the SEP based on the hourly values of the marginal price of the Daily Market in a similar week.

● An economic office will be resolved, which will take into account the maximum allowable energy exchange under normal conditions from the SEP to the SEB, with its cost, with which the energy-time exchange program will be obtained weekly by the link to the SEP.

The previous exchange program will be part of the weekly demand coverage program as set out in the SEIE 2.2 P.O..

6. Daily coverage and programming

The OS will prepare a forecast of coverage of the daily demand of the system, fulfilling the criteria of guarantee and quality of supply prescribed in the operating procedures and taking into account also the restrictions relevant techniques.

For such daily horizon coverage, the OS will establish the maximum allowable energy exchange on the link with the SEP, under normal conditions and in the event of an emergency situation in the SEB, respecting the criteria of established security.

The OS will perform the economic dispatch defined in the SEIE 2.2 P.O.. Once calculated, for each hour, the variable cost of each generator considering the variable costs recognized, the cost of the programmed energy will be determined, without considering any link with the SEP. By incorporating the maximum permissible energy exchange values under normal conditions from the SEP to the SEB set out above, the OS shall perform a new economic dispatch and determine the quantities and the price of the energy to be transferred. by the link from the SEP to the SEB, considering the energies and the variable costs of production, in descending order, associated with the units of the SEB that can be replaced by energy from the SEP through the link, for their incorporation into the purchase offers to be presented at the MIBEL.

The OS shall communicate, in advance not less than 30 minutes before the end of the period for the submission of tenders in the daily market, to the marketers and direct consumers in the electrical system connected to the SEP and To the Market Operator (OMIE) the quantities and prices of the energy purchase offers that marketers and direct consumers in the electrical system connected to the SEP must present in the daily market for the programming of the exchange energy through the link to the SEP.

The amount to be offered for each marketer and direct consumer will be proportional to its share of demand in the SEB. The demand share will be calculated on the basis of the forecasts of the consumption of the electricity system received by the OS for the month M-2, being M the month in progress. This amount to be offered shall respect the minimum energy value set for participating in the production market.

Direct traders and consumers of the SEB will be required to present the energy purchase offers on the daily market, for the volumes and prices indicated by the OS. Each authorized subject of the SEB, for the acquisition of energy in the MIBEL, shall be the holder of a Programming Unit for the integration into the market of the energy program through the link between the SEP and the SEB.

The energy schedule program, as a result of the daily market, of all the Marketing Programming Units and direct consumers, will represent the energy schedule exchange program through the SEB link. with the SEP.

The OS will perform a new economic dispatch, incorporating the schedules of energy exchange schedules through the SEB link with the SEP, and the marginal prices resulting from the appeal of the daily market, amending, if necessary, the schedule of the production units of the ordinary regime in the SEIE.

7. Intraday programming

In the event that the economic dispatch carried out in the daily programming was significantly altered by causes such as the communication of inavailabilities of the links with the SEP, and/or the identification of restrictions (i) technical, and/or the communication of inavailabilities of production units, inter alia, the OS shall determine the time values of energy and the price of the offers of purchase or, where appropriate, of the repurchase of energy to be presented on the intraday market, for the modification of the energy programme through the link with the PMI resulting from the market daily, or the previous intraday market session. The process to be performed will be analogous to that set for the daily programming, but the offers on the intraday market may be acceptable when the modifications of the energy programme by the link are associated with the inavailability of the link and/or scheduling of the operating conditions of the link (minimum energy, ramps, etc.).

The energy program on the SEB-SEP link may be adjusted at each session of the MIBEL intraday market.

For this purpose the OS shall communicate, in advance not less than 30 minutes before the closing of the period of submission of the relevant intraday market session, to the traders and the direct consumers. in the electricity system and to OMIE the quantities and prices of the offers which marketers and direct consumers will have to present in the corresponding session of the intra-day market to adjust the program of exchange of energy through the link to the SEP.

Direct marketers and consumers of the SEB must present, the energy purchase offers on the intraday market, by the volumes and prices indicated by the OS.

The amount to be offered for each marketer or direct consumer will be proportional to its share of demand in the SEB connected to the SEP, calculated on the basis of the forecasts of consumption of the electric system received by the OS for the month M-2 being M the month in progress. This amount to be offered shall respect the minimum energy value set for participating in the production market.

Changes in the energy-time exchange programme by the link with the SEP resulting from the appeal of the tenders submitted to the intra-day market and, where appropriate, after the technical restrictions have been resolved Identified and rebalanced thereafter, they will be incorporated into the daily demand coverage programme.

8. Resolution of mismatches in the energy exchange program by the electrical links with the SEP in real time

In case the energy program readjustment is required on the SEB-SEP link in real time, the OS will set the corresponding real-time program modifications on the power programming units to through each link, according to decreasing order of programmed energy and, to equal value, according to alphabetical order.

Also, as set by the P.O. SEIE 3.1, the OS will identify and resolve deviations that may exist between scheduled generation and consumption and those that actually occur to ensure coverage of SEB demand. In the event of a detour between the programmed energy in the link with the SEP and the physical flow, either by means of diversion generation-consumption, or by inavailabilities fortuitous of the generating park, the OS will restore the physical flow of the link to its program value.

9. Information communication by the system operator

The annual, monthly and daily programming communication shall be as set out in the P.O. SEIE 2.2, and shall include the maximum permissible energy exchange programme under normal conditions by the link from the SEP to the SEB.

The OS will publish the final price of generation [PFG (h)] in the SEB resulting from the economic dispatch without considering the exchange of energy through the link with the SEP and the same final price, integrating in the economic dispatch the exchange of energy with the SEP, as well as the marginal price of energy in the daily market.

10. Exceptional resolution mechanism

In the event that, for reasons of urgency or unavailability of the computer systems or other justified cause, it is not possible to establish the programming of the power exchange in the existing power link between the SEB and the SEP by means of the mechanisms provided for in this procedure, the System Operator may take the necessary operating decisions to ensure the supply and delivery in safety at the lowest cost. possible. Such decisions shall be communicated to the competent authorities, the agents concerned and the NEC within one month, and must be made in such a reference to express both the causes of the exceptional situation, and to the reasons and priorities taken into account for the adoption of the concrete decision.

P. O.SEIE 3.1: Real-time generation programming

1. Object

The purpose of this Procedure is to establish the process for the resolution of real-time deviations between generation and consumption, as well as the resolution of technical restrictions that may appear in Electrical Systems. Islands and Strangers (SEIE).

2. Scope of application

This Procedure applies to the following subjects:

System Operator.

Single carrier and distributors who are exceptionally holders of transport facilities.

Distributors and clients connected to the transport network.

Marketers.

Proprietary or operating groups of generator groups.

Distribution network managers.

3. Resolution of generation-consumption deviations

3.1 Process definition. The System Operator will identify and resolve deviations that may exist between scheduled generation and consumption and those that actually occur to ensure the demand coverage of each system in each SEIE.

Producers must inform the System Operator as soon as possible of all the inavailabilities or program modifications presented in their generation equipment, making explicit their intended duration. Also, marketers must communicate to the System Operator, all variations that they foresee in their demand with respect to the one scheduled for the entire programming period.

The System Operator will perform demand forecasts that will be used to perform the generation programming and that together with the information communicated by the agents will result in the estimation of the deviations planned until the end of the programming period.

3.2 Generation-consumption. The System Operator will daily draw up a merit order based on a generation economic dispatch with all generation units available. This economic dispatch will be the reference for the allocation of the generation that is necessary to cover the deviations between generation and consumption.

For the resolution of the expected generation-consumption deviations, the System Operator will increase or reduce the generation, pumps and exchanges with other electrical systems, considering the results of the economic dispatch of the generation that has previously performed and will assign the program modifications that correspond to each unit, incorporating these modifications into the schedule schedule.

The allocation of time loads, depending on the average time value of the deviations, will comprise the entire schedule period of the schedule to be executed.

Assignments made in no case can cause a technical constraint.

When an over-come diversion between generation and consumption needs to be resolved, it will be solved by increasing or reducing generation, exchanges with other electrical systems and pumping available, resulting from the consideration of the economic dispatch of the generation previously carried out, assigning the modifications of the program corresponding to each unit, which will be incorporated in the schedule schedule. Such allocations may be scheduled for periods of less than one hour.

4. Process for solution of technical constraints in real time

4.1 Process definition. The System Operator shall continuously analyse the actual and planned operation of the system throughout the programming horizon and identify and resolve the technical constraints existing at any time.

4.2 Technical restrictions. For the resolution of a technical restriction requiring the modification of the generation programmes of one or more units, the System Operator shall take from among the solutions that resolve the restriction that which represents the minimum overrecovery, using the result of the economic dispatch of the generation.

5. Communication between the system operator and the agents

Agents shall communicate to the System Operator, as soon as possible, any incident that may affect the programming of the particular coverage and the operation of the system in general.

The System Operator will communicate to the affected producers the allocations made to resolve the demand and generation deviations and to resolve the technical constraints fifteen minutes before the time change.

Also, for schedules that do not include full time periods, the System Operator will transmit to the agents as soon as possible the instructions required for the programming of the coverage and the resolution of technical constraints.

The exchange of information will be done through a redundant telecommunications system that enables the IT processing of the same.

6. Exceptional resolution mechanism

Where, for reasons of urgency or unavailability of computer systems or other justified cause, it is not possible to resolve a diversion or a technical restriction by means of the mechanisms provided for in this Regulation. procedure, the System Operator may take the necessary operational decisions to ensure the supply and delivery of the system in a safe manner at the lowest possible cost. Such decisions shall be communicated to the competent authorities, the agents concerned and the NEC within one month, and must be made in such a reference to express both the causes of the exceptional situation, and to the reasons and priorities taken into account for the adoption of the concrete decision.

P. O.SEIE 7.1: Supplementary primary regulation service

1. Object

The purpose of this procedure is to determine the primary regulatory needs of the Island and Extraceninsular Electrical Systems (SEIE) and to establish their allocation to the generators that provide this service.

2. Scope of application

This procedure applies to the System Operator and the production companies.

3. Definitions

Primary regulation is a complementary service of a compulsory and unpaid character provided by the coupled generators. It aims to automatically correct the instantaneous imbalances between production and consumption. It is provided by the power variation of the generators coupled immediately and autonomously by the performance of their speed regulators in response to variations in frequency. This response is characterized by permanent staticism and must be effective in less than 30 seconds.

Permanent statism is the ratio between a quasi-stationary relative frequency variation in the network and the relative variation of generator power caused by such frequency variation.

R =-(f/fn)/(Pg/Pn)

where:

R = Estatism (p.u.).

f = network frequency.

fn = nominal frequency.

Pg = Generated Power.

Pn = Nominal generator power.

The primary reserve to be raised is the total power volume between all the coupled generators, resulting from the difference between the maximum available power coupled and the actual power generated, which can act in less than 30 seconds according to the groups ' statistics.

The primary reserve to be lowered is the total power volume between all the coupled generators, resulting from the difference between the actual power generated and the minimum available power coupled, which can act in less than 30 seconds according to the groups ' statistics.

The primary regulatory band is the power margin in which the set of the speed regulators can act automatically and in both directions, as a consequence of a frequency diversion.

In the case of the link between the Peninsular Electrical System and the Balear Electrical System, it may participate in the primary regulation in the way that the system operator determines it, in support of the regulation offered by generators.

4. Primary regulatory requirements

The primary regulation of the generator groups should allow the establishment of a staticism in its regulator between 2 and 5%. The insensitivity of the regulators of the groups must be less than + 30 mHz and the voluntary dead band null.

However, we admit to 7% and dead bands greater than + 30 mHz in those generators that were in service prior to the application of this procedure did not have the technical capacity to be adapted to meet this requirement.

5. Allocation of the regulatory reserve

The primary regulatory reserve allocation per schedule period for each SEIE system shall be established in accordance with the SEIE's P.O. 1 procedure.

The maximum and minimum primary regulatory reserve band for each system generator group shall be determined in proportion to their available net power and inversely proportional to their staticism and speed of response.

It should be noted that the secondary reserve will participate in the primary regulation even if it is not counted as a primary reserve. Therefore, in the event of an imbalance between generation and consumption, primary regulation will make use of part of the secondary reserve.

6. Mandatory service delivery

All production units must have primary regulatory capacity.

In the event that technically, a production unit cannot count on the appropriate equipment, the complementary service must be assigned, after authorization from the System Operator, to any of the other groups coupled to the same production company, or where appropriate, contracted directly by the operators of the facilities required to provide it to other operators who can provide it. The contract, which shall be regulated, shall be communicated to the Operator of the System, who shall certify the service actually provided for the performance of that contract and shall be liquidated by the parties at the price they have agreed.

7. Data communication

Generation companies must declare the characteristics of the primary regulators of the generators of their ownership, as well as the statism of each group before 30 November of each year.

Generation companies must communicate as soon as possible, any change in the technical characteristics of the generators that might affect their primary reservation.

8. Monitoring compliance with requirements

Statements made by means of audits and technical inspections shall be verified.

Inspections of all equipment will be carried out over a five-year cyclical period, by selecting a random system for the equipment to be reviewed every year.

P. .SEIE 7.2: Supplementary secondary regulation service

1. Object

The purpose of this procedure is to establish the method of allocation of the secondary regulation reserve in the Island and Extraceninsular Electrical Systems (SEIE) to the different production units participating in the the provision of this supplementary service, and the monitoring of its implementation.

2. Scope of application

This procedure applies to the System Operator and the production companies.

3. Definitions

Secondary regulation is the mechanism that, through a master control regulator, manages the power of generators included in that mechanism in order to eliminate permanent regime errors in the frequency (not corrected by primary regulation) to return the system to the nominal frequency in less than 15 minutes after an unbalanced event between generation and consumption.

By master regulator you can understand any control element, fully automatic (AGC) or semi-automatic (by operator intervention) that guarantees the control objective indicated in the previous paragraph.

In those systems that are electrically connected to other systems, it will be the operator of the system to implement a master regulator that sends the appropriate signals to the owners of the generation groups and to the links to the electrical systems to maintain the system in balance.

Secondary regulation is a compulsory and paid supplementary service.

The secondary reserve to be raised is the total power volume between all the coupled generators, under the control of the master regulator, resulting from the difference between the maximum available power coupled to meet the secondary regulation needs and the actual power generated.

The secondary reserve to be lowered is the total power volume between all the coupled generators, under the control of the master regulator, resulting from the difference between the actual power generated and the minimum power available Coupled to meet secondary regulatory needs.

It should be noted that, according to its definition, the secondary reserve will participate in the primary regulation even if it is not counted as a primary reserve. Therefore, in the event of an imbalance between generation and consumption, the primary regulation will make use of part of the secondary reserve, so that the master regulator will only have the reserve not used by the regulation. primary to replenish the nominal frequency.

4. Allocation of the regulatory reserve

The secondary regulation reserve allocation per schedule period for each system in SEIE shall be established in accordance with the SEIE's P.O.1 procedure.

For each schedule period, the System Operator will calculate and assign to each production unit, under the control of the master regulator, the secondary regulatory bands to both rise and fall together with the calculation of the economic dispatch in such a way as to minimise production costs, taking into account the safety criteria.

5. Mandatory service delivery

Each generator group in each system must have at least secondary regulatory capacity, proportional to its available net power, based on the system total secondary regulation reserve in each of the schedule schedule.

In the event that it is technically not possible to have the appropriate equipment, the complementary service must be provided by other generating groups of the same company or contracted directly by the holders of the facilities required for their benefit to another generating undertaking which can provide it. The contract, if applicable, which shall be regulated, shall be communicated to the Operator of the System, who shall certify the service actually provided in execution of that contract and shall be settled by the parties at the price which they have agreed.

6. Data communication

Before 30 November each year, generation companies must declare their ownership groups capable of providing secondary regulation band automatically or semi-automatically.

7. Assessment of the secondary regulation service

The assessment of the secondary secondary regulation service will be carried out by both the regulatory power band available and the use of the reserve according to the energy clearance procedure in SEIE in force.

8. Controlling the response of the regulation

The control of the secondary regulation response will be performed at the level of each system in each SEIE.

A failure to respond shall be considered to have occurred when, after 15 minutes from an unbalancing event between generation and consumption of magnitude equal to or less than the expected reserve, the frequency is not the normal operating margin of the system indicated in P.O. 1. of SEIE.

The band defaults and the lack of quality of the response will have an economic impact on the responsible company, leaving the total of the assigned band of secondary regulation to be perceived in the programming periods. times when a default occurs.

P. O.SEIE 8.2: Operation Criteria

1. Object

The purpose of this Procedure is to establish the actions for the operation of the network facilities under the technical management of the System Operator in the different states that the Electrical Systems can meet. Islands and Strangers (SEIE), as well as establishing the general criteria for the control of tension

2. Scope

In this Procedure, they are set:

The overall scope of the System Operator's actions on production and transportation system facilities.

The actions required for the operation of the network facilities under the technical management of the System Operator in the different states in which the electrical system can be found in relation to its security.

The operation of the system in relation to the voltage control of the transport network.

The exceptional operating measures that the System Operator may take, and which shall be carried out by the agents concerned to ensure the coverage of the claim when the electrical system is in a state of alert or coverage emergency.

3. Scope of application

This procedure applies to the following subjects:

a) System Operator.

(b) Single carrier and distributors who are exceptionally holders of transport facilities.

c) Managing companies of the distribution networks.

d) Marketers.

e) Customers directly connected to the transport network.

(f) proprietary or operating companies of generating groups connected to or having direct influence over the transport network.

4. Responsibilities

The System Operator is responsible for issuing the corresponding operating instructions to the transportation, distribution, and generation companies, and, where applicable, to the special regime control centers.

Transport, distribution, generation and special generators are responsible for the proper execution of the instructions issued by the System Operator, for which it will be necessary, if applicable, to the they are transmitted to the generators under special arrangements by the special control centres.

5. Control Center

To enable the issuance of real-time slogans by the System Operator, as well as the monitoring and control of production and transportation facilities, generating facilities larger than 1 MW or less than 1 MW but belonging to a pool of which the sum of powers is greater than 1 MW will be associated with Control Centres, which shall act as interlocutors of the System Operator Control Centres, executing the instructions received either directly or by transmitting them to the different owners who are integrated into it and ensuring its compliance. In the case of customers connected to the Transport Network, they may be prevented from being integrated into a Control Centre provided that the manoeuvrability of the network is not compromised.

Because of the basic management of the System Operation in real time, the Control Centers must be equipped with the appropriate technical infrastructure and human resources to ensure its functionality 24 h/day every day of the year and have real-time information on the facilities under their control. The technical characteristics of the connection with the control centers shall be that established in the PO SEIE 9 "Information to be exchanged with the System Operator". In order to ensure the correct issuance of real-time slogans, they will be able to communicate with the System Operator Control Centers in a verbal manner.

The verification of compliance with the above conditions will be performed by the System Operator. If such verification results in the refusal of the establishment of a Control Centre, the System Operator shall inform the National Energy Commission of who will resolve the technical dispute raised.

The Control Centers will adjust their operation to what is set up in the corresponding Operation Procedures.

6. Actions of the system operator on the facilities of the production and transport system

The System Operator, is responsible for issuing the necessary instructions to the generation and transport companies for the performance of the maneuvers of the elements of the production and transport system, including among others:

● Managing the topology, adapting it to the different circumstances of the operation.

● The management of the voltage control elements available, in particular the generation and absorption of reactive power by the generation units, the use of reactances and the batteries of capacitors and the regulators of processors.

● The approval and supervision, if any, of the work plans in the facilities, either scheduled or over, in the various temporary areas, both for preventive and corrective maintenance reasons.

● Approval and monitoring of plans required for commissioning of new facilities.

The instructions issued to the different agents must be duly registered in equipment provided for this purpose.

7. Operating the systems

Operation in normal state.

In this situation, the operation of each System must be directed to keep it at a point of operation that ensures:

● Maintenance of frequency within the set band.

● The safety margins, by applying the stress control plans and the adoption of the relevant preventive measures derived from the safety analyses carried out.

If an agent considers it necessary to perform a certain maneuver, it must first propose to the System Operator who, once analyzed, will give its conformity if it is appropriate.

If the initiative to perform the maneuver comes from the Operator of the System, it shall give the appropriate instructions to the company that owns the installation, or, where appropriate, to which the operation of the installation is assigned. If the agent operating the installation warned of any inconvenience to the maneuver, it must be communicated immediately.

Any manoeuvre to be performed on the system shall have the prior conformity of the System Operator, except those whose need arises from the existence of imminent risk to the safety of persons or persons. facilities. In this case, the company that has performed the maneuver must inform the System Operator later in the shortest possible time.

Operation in alert status.

In this situation all the actions carried out in the network will be aimed at returning the system to its normal state or to mitigate the consequences that could result from an unfavorable evolution of the state of the system. To this end, the System Operator will determine the most appropriate actions on the network topology and the state of the generation, and will instruct the agents responsible for the facilities to execute the necessary maneuvers.

The process of detecting and correcting an alert situation is as follows:

● Assessment of the potential risks that would arise if certain contingencies were to occur.

● Determination and analysis of possible corrective and preventive actions.

● Application of required corrective or preventive actions.

Assessment of potential risks.

Once the contingencies that would result in violations of the limits established by the security criteria will be determined, the possible repercussions on the electrical system will be identified for each one.

A special level of risk will be assigned to those contingencies that lead to large-scale incidents with very important potential consequences, in order to give rise to:

● A generalized incident (chain disconnections, tension collapse, unacceptable frequency variation, loss of stability that may lead to loss of a large part of the system, etc.)

● A very large incident, which without going to degenerate into a widespread incident can, however, affect a very important volume of market.

In the risk assessment of each contingency, special attention will be given to the circumstances that may increase the probability of occurrence of the contingency analyzed.

This will take into account, among other circumstances, the following:

● Adverse weather conditions (storms, wind, snow, etc.).

● Risk of fires that may affect facilities.

● Problems identified in installations equipment.

● Special warning against sabotage.

Determination and analysis of possible corrective and preventive actions

In all cases where certain contingencies could lead to widespread or widespread incidents, a safeguard plan must be drawn up to reduce as much as possible the consequences that will arise. derived from the contingencies indicated.

In these safeguard plans, the preventive and/or operational actions that should be implemented will be considered for each of the contingencies that pose serious problems for the security of the system in question. where appropriate in order to ensure the security of the system (re-dispatch of generation, emergency replacement of items in discharge, modification, where appropriate, of inter-island exchange programmes, application of interruptibility, load ballast, etc.).

When contingencies can cause a widespread incident or a large incident and possible post-contingency corrective actions cannot be made effective in a reasonably short time, it will be necessary. take preventive measures. These measures could be the coupling of new production units not included in the production programme. When multiple solutions are possible, the one that introduces a lower cost will be chosen.

Application of corrective and preventive actions.

When corrective or preventive measures are necessary, they should be implemented as soon as possible, in particular if special circumstances increase the likelihood of occurrence of other contingencies.

Once the System Operator has taken the decision to implement the above measures, it will provide the necessary instructions to the companies concerned, who will be responsible for their rapid compliance.

When the corrective action comes from the actions of the automatisms installed in the network, the agents involved, as soon as possible, will inform the System Operator of both the scope and the functioning of the automatic equipment.

If any difficulties arise in the implementation of these instructions, the responsible companies shall notify the Operator of the System as soon as possible.

Operation in a state of emergency.

During the operation, in the event that the system goes to a state of emergency, the System Operator will prioritize the urgent reset of security until the system is returned to its normal state.

In this situation, the System Operator will take the necessary measures, coordinating the actions on the production and transport system, in order to achieve as quickly as possible the control variables The safety of the electrical system will return to its normal state.

The guidelines for action will be completely analogous to those set out in point 7.3, on which the essential differentiator will be to give priority to measures which are more effective in the light of the speed of their action. Implementation is essential when the existing violations of the security criteria are serious.

Also, in the event of any interruption of the local power supply, motivated by an incident in the production and transport system, the System Operator will have to coordinate with the dispatches of the agents affected, replenishing the service.

Operation in Reorder Status.

The reorder process will be coordinated and directed at all times by the System Operator.

Once the loss of supply has been detected in an electrical zone (zero zonal) or in the entire electrical system (zero total), the System Operator will primarily address the urgent replacement of the electrical supply in the affected area.

The System Operator must inform the competent authorities of the existence of the disturbance and inform them of its evolution. It shall also inform the National Energy Commission and the system operators of its existence.

In order to replace the System Operator, with the competition of the carriers, the producers and the distribution managers, the actions on the elements of the network will be available as follows:

●-Will activate the corresponding Service Replenishment Plans (PRS), when these are applicable by the characteristics and/or extension of the incident, being able to complement or modify them when the circumstances so advise.

● If there is no PRS applicable to the situation presented, the System Operator will direct the replacement by giving the necessary instructions to the various carriers and, if necessary, to the producers and managers of the distribution, basing its decisions on the information provided by the agents, on their own experience and on the tools and aids available to them. The System Operator shall inform the competent authority within one month of the decisions taken.

● The precise measures will be taken to ensure the food of the auxiliary services of the power plants as a matter of priority

● Discharges in progress that may have an impact on the reorder process will be suspended.

Additionally, the control centers will take the necessary measures to ensure the correct functioning of the computer systems, the communications routes and the electrical supply to the control centers themselves and to the vital installations.

If a control center has been disabled to operate, it will be its backup control center, if it exists, who will temporarily assume the functions of the control center, informing the System Operator of this eventuality. Each control center shall establish the operating procedures for the proper operation of its backup control center.

Each control center will alert the checkpoints of the different facilities and services by the coordinated one to enable quick intervention.

8. Controlling the stresses on the system

The operating criteria for the control of the stresses of the nodes belonging to the transport network shall be those set out in the procedure P.O.1 and the Tension Control Plan.

The System Operator SOO will monitor in real time that the voltage at the nodes of the transport network is adjusted to the voltage and power factors resulting from the Tension Control Plan. It shall also ensure that the safety and performance criteria for the operation of the electrical system that are required are met, in accordance with the provisions of the P.O.1 procedure.

To do this, the System Operator will provide the service providers with the necessary instructions for the operation of the voltage control means of their property, namely:

● Maniwork of the connected reactive compensation elements in the transport network

● Changing the regulation sockets of the transformers.

● Modifying the tension slogans of the groups.

The companies that own voltage control elements must inform the System Operator as soon as possible of any circumstances that may affect the availability and use of the elements of the voltage control of your property.

9. Operational measures to ensure the coverage of demand in alert and emergency situations

This procedure indicates the operational measures that may be taken, regardless of whether their execution may result from the application of this or other operating procedures in force, depending on the situation Warning or emergency coverage to be presented.

By its very nature some of the measures will be applied simultaneously and others sequentially considering the order in which they are listed in this operating procedure which, in any case, will be considered to be indicative, The system operator shall determine the sequence of its application in the light of the actual operating conditions. Additionally, when applicable to the measures to be taken, the System Operator will implement the operation measures as far in advance as possible, within the process of daily programming of the generation, if this was feasible or, if applicable, in real time.

For this purpose, the System Operator will inform the subjects affected by the application of this procedure, as well as the National Energy Commission and the Public Administrations of the existence of a scenario of the operation in which the operation of the operational measures referred to therein is likely to be implemented. The notice with which it will be reported may be seven days, if the circumstances permit. Where appropriate, those measures shall be ratified on the day before their implementation and shall be confirmed in real time, where appropriate.

Short-Term Coverage Alert Situation

1. Rend the discarding in the transport and distribution networks for which that possibility exists, provided that this contributes to increasing the security of the system.

2. Set the precise limitations to the production of the generating and/or pumping groups based on the short-term supply guarantee.

The above limitations will be complementary to the limitations on these units for short-term security reasons, in application of other operating procedures in force.

3. º Modular hydraulic production (if any) to obtain maximum production capacity at peak times.

When there is a low level of water reserves, it will be necessary to schedule turbination in certain reservoirs in order to guarantee the existence of the precise cote in other dependents of those so that it is possible to produce the maximum hydraulic power in the hours of greatest demand.

4. Give instructions through the established means to require the generators in special arrangements to perform the delivery of their maximum available power and the coupling of all means of compensation reactive.

5. Apply the Interruptibility Demand Management service at the total or zonal level, as required, to the providers of this service.

Coverage emergency situation.

1. Adopt the precise measures to obtain the maximum possible operation in the critical substations previously identified by the Operator of the System and enable the autonomous starting of the plants contemplated in the Service Reposition Plans. The measures indicated may include an increase in the availability or mobility of the operating personnel and any other action deemed necessary.

2. Selective Manual Load Shedding. In the terms and conditions set out in the P.O.1 procedure.

In particular in the case of those operating measures for which there is a regulatory limitation that limits its application, as is the case with the application of interruptibility, the order indicated must be considered as orientation.

10. System frequency control

The System Operator will monitor the frequency values at all times, checking that they are kept on the established margins, for this purpose, will be treated as indicated in the procedure P.O. 1. and in the procedures P.O. 7.1, P.O.7.2 and P.O. 7.3 that develop the criteria for determining the necessary regulatory reserves in the system, to achieve the right balance generation-demand.

11. Exceptional resolution mechanism

In order to deal with situations not provided for in this proceeding or for any other duly justified reasons, the System Operator under its best discretion may take the necessary decisions to ensure the provision and delivery of the security at the lowest possible cost. Such decisions shall be communicated to the competent authorities, the agents concerned and the NEC within one month, and must be made in such a reference to express both the causes of the exceptional situation, and to the reasons and priorities taken into account for the adoption of the concrete decision.

P. O.SEIE 9: Information to be exchanged with the system operator

1. Object

The purpose of this Procedure is to define the information to be exchanged by the OS in order to perform the functions that you have assigned to it, as well as the form and deadlines in which you must communicate or publish it.

This information includes, inter alia, the corresponding structural data of the SEIE installations, the information on the real time situation of the SEIE facilities (state, measures, etc.), the information exchanged for the appropriate system operation, the information necessary for the compilation of statistics relating to the operation of SEIEs, the information required for the analysis of the impact of SEIE, as well as the data for settlement data of the electrical energy transactions performed.

It is established in this Procedure, with the detail that comes in each case, the way in which the exchange of information between the OS and the different subjects of SEIE will be conducted, the mode of access to the information, the way of structure and organize it (databases), its character (public or confidential) and its subsequent treatment (analysis, statistics and reports).

In addition to the information contained in this Procedure, account should also be taken of the information needs contained in the other Operation Procedures, which are described in more detail. processes required to perform the functions that the OS is entrusted with.

2. Scope of application

This procedure reaches the following electrical system subjects:

System Operator (OS).

Producers.

Distribution network managers.

Single carrier and distributors who are exceptionally holders of transport facilities.

Marketers.

Consumers connected to the transport network.

Qualified consumers who acquire their energy directly in economic dispatch.

3. Information management processes in which the System Operator intervenes

The information exchange processes in which the OS is involved are grouped as follows:

a) Structural Data of the Electrical System.

b) System of Operation and System of Settlement of Extraceninsular Systems.

c) Electrical Measurement Hub.

d) SCO: Real Time Operation Control System.

e) Other information to be sent by system subjects.

f) Statistics and Public Information regarding the System Operation.

g) Analysis and incident information in SEIE.

h) Liquidation under System Operator responsibility.

As far as the headings (b), (c), (d), (e) and (f) are concerned, the system subjects shall be responsible for depositing in the OS information systems the information contained in this Procedure and for providing the information. necessary communication mechanisms and take charge of their costs.

The subjects will ensure that:

a) The information provided is correct.

b) The information is available to the OS with the minimum time delay and with the appropriate time stamp.

c) Communications systems are redundant, reliable, and secure.

d) The transmission of information conforms to the characteristics of communication protocols and frequency of sending information defined by the OS.

4. Structural data of the electrical system

It is the data of the installations of the transport network and the observable network, as well as of the generating groups, consumers and control elements, that the OS requires to execute its functions facilitating the analysis of safety and performance studies of SEIGs.

4.1 Responsibilities. The OS is responsible for collecting, maintaining and updating the structural data of SEIE. The information is structured and organized in the Structural Data Base of the Electrical System (BDE).

Producers, including those of a special scheme, and consumers connected to the transport network the single carrier, distributors (including those who are exceptionally holders of transport facilities) and the Distribution network managers shall be required to provide the OS with the necessary information of the elements of their ownership or to those they represent in order to maintain the content of the updated and reliable BDE.

4.2 Content and structure of the database. The BDE will include the records of all the items released on the SEIE managed by the OS. It shall also include the records of elements in project and construction and of planned elements, with the available values, although these shall be considered provisional until they are put into service. The latter records shall be released in order to facilitate the conduct of the transport network planning studies and the different forecasts of SEIE.

The contents of the BDE respond to the following structure:

a) Production System.

Hydraulic groups.

Reservoirs.

Ordinary-speed thermal units.

Production units on special speed.

b) Transport Network.

Substations.

Parks.

Lines and cables.

Transformers.

Active or reactive power control elements.

c) Consumer installations connected to the Transport Network.

d) Observable Network.

Substations.

Parks.

Lines and cables.

Transformers.

reactive power control elements.

Annex I to this procedure includes a detailed relationship of the different fields in which the BDE is structured.

4.3 Load processing. The OS will define the computer support used and enable the templates of the data entry tabs with the required formats.

The OS will complete the fields contained in the above sheets with all the information available to them about each item and make them available to the owner or representative of the item to which the information.

The subjects will carry out a check of the information of the files relating to their installations and modify them, if appropriate, with the best information available, filling in the fields that appear empty.

Once the tokens are completed and validated by each subject, the subject will communicate the outcome of the review to the OS.

4.4 Update of information. The update of the information contained in the BDE can be facilitated by any of the following three circumstances:

● For design modifications to some element.

● By high or low of some element.

● Because the wrong value has been detected in some field.

When any of the above three circumstances occur, the subject who owns the corresponding item or the subject acting in its representation shall communicate to the OS the necessary modifications to be incorporated.

The OS will periodically make available to each subject the data of the elements of their property or those to whom it represents collected in the database in order to enable the subjects to check their proper correspondence with the actual data of the installations and, where appropriate, communicate to the OS the necessary modifications to be made.

4.5 Confidentiality of information. The information contained in the BDE shall be of a confidential nature for all subjects except for:

The National Energy Commission (CNE), which will be able to have all the information.

The Competent Administration, which will be able to have all the information available.

The distribution network managers that will be able to have the data from the facilities located in the distribution network under their management scope.

Those third parties to whom the OS has the need to give information for the exercise of its functions and obligations, minimizing, in any case, the volume of information transmitted and always counting with the authorization of the holders of the generated information and the signing of a confidentiality agreement between the information receiver and the OS.

All Subjects who may have the data relating to the facilities in service of the transport network.

5. System for the operation and settlement of extrapenisland systems

The data that, in the performance of its functions, the OS must manage to perform the processes it has entrusted, for the definition of each of the time schedules and the allocation of the complementary services to the various agents, they will be managed by the Information System of the Operation of the Extraceninsular Systems.

The system will perform the generation scheduling and dispatch processes, and the log and file of data and results required for the settlement process.

The system shall ensure in the execution of the processes and exchange of information indicated in the preceding paragraph the confidentiality in the processing of the information of its responsibility, taking into account the property for each Agent.

Information managed and stored by the System Operator Information Systems will also be used later in the settlement processes that are the responsibility of the OS.

5.1 System Databases. The OS will maintain in the database of the System of Operation and Settlement of the Extraceninsular Systems all the necessary information for the correct management of the processes of its responsibility.

5.2 System access. Access to the System of Operation and Settlement of Extraceninsular Systems by agents, other subjects of the electrical system or the Public in general, will be done according to the character of the information to which you have access, already is public or confidential in accordance with the criteria set out in paragraph 5.7.

5.3 Media for information exchange. The communication between the OS and the Subjects, as well as the dissemination of the public information of free access will be done by electronic means of information exchange, using at every moment the most appropriate technologies.

The adoption of new electronic means of exchange of information, as well as the suspension of any of the existing ones, will be communicated to the users in good time in such a way that they can make the necessary modifications to your information systems.

The OS will publish the electronic means of exchange of information available and its characteristics, those new ones that will be implemented and those that will be suspended, as well as the deadlines foreseen for this.

5.4 Communications. In order to carry out the exchange of information, the OS will have several alternative means of common use to access both the main and the backup system and will provide users with the necessary technical details for access and the performance procedures in case of switching between the two systems.

The installation, maintenance and configuration of the communication channels to access the System of Operation and Settlement of the Extraceninsular Systems will be the responsibility and will be borne by the users. The OS shall indicate in each case the rules and procedures applicable to the equipment to be installed on its premises.

5.5 Access Services. According to the type of information, there will be two access services: private and public.

Private service will be reserved only for the electrical system subjects.

The electronic addresses of the public and private access services will be provided by the System Operator.

Access services, both private and public, will use the most appropriate technologies in each case.

For the use of the private access service, a personal certificate issued by the OS will be required according to the regulations in force. No certificate type will be required for the use of the public access service.

5.5.1 Private access service security. -The OS can set up a private access service security system based on the use of the following items:

a) The encrypted communication channel to ensure the privacy of the information exchanged.

b) Use of digital certificates for authentication when making connections with the System of Operation and Settlement of Extraceninsular Systems, the signature of electronic documents constituting the exchanges of information and ensure the non-repudiation of such documents.

c) Use of smart cards. For the same purpose as the above (b) certificates, the system subjects may own one or more smart cards, where their digital certificate is stored, as well as their identification data and a code to prevent their misuse in case of theft or loss. The depositaries of these cards will be responsible for the management of this code, being able to modify it when they create it convenient. Likewise, in case of theft or loss, they must communicate this fact as soon as possible to the OS, in order for the OS to discharge the associated certificates.

Digital certificates will be issued by the OS acting as a Certificate Authority. Users recognize the OS as a trusted Certificate Authority for the sake of using the digital certificate or smart card.

Digital certificates will be issued with an expiration date. It shall be the responsibility of the user of the certificate to check that expiry date and to request, where appropriate, the renewal of the certificate in advance not less than 5 working days from the expiry date.

Also, it will be the responsibility of the SM to request the cancellation of the certificates when they consider it convenient (for example, cessation of activity of users responsible for the certificates)

5.6 Information Advertising Criteria. Generation programming is done through an economic dispatch process of the groups, so the data regarding the outcome of such programming is not confidential and is considered public for all agents.

The advertising criteria for OS-managed information are as follows:

● The OS will make public the result of the technical operation processes of your responsibility, as well as the demand curves and corresponding generation programs.

● In any case, the OS will ensure the confidentiality of the confidential information made available to you by the agents.

5.7 Public information. It is the information that the OS makes public about the processes of operation of the electrical systems.

This depends on the period it affects and the time it is made public.

5.7.1 In real time. The information that the OS will publish after each reprogramming process will refer to the new time-generation program, including rebooking and resolution of restrictions and general-demand imbalances, as needs and for the system that requires it.

All these processes are regulated and developed in the SEIE Operation Procedures. The information and time of communication about each of them are set out in the corresponding Operation Procedures.

5.7.2 Daily. The following information shall be published on a daily basis:

When you perform daily dispatch, the following day information for:

● Demand forecast for each SEIE.

● Schedule of generation for each SEIE, including allocated reservations.

● Daily shutdown of the final generation program.

On those systems electrically connected to other systems it will be published:

● Programmable capacity on existing links

● Program on existing links

● Value of the final price of generation, distinguishing between the marginal price of the energy in the daily market, the result of the economic dispatch before integrating the exchange and the corresponding one to the office economic with the energy exchange program through the links

5.7.3 Weekly. On a weekly basis, the coverage of the expected demand for the following week is prepared and the following information will be published:

● Demand forecast for each SEIE.

● Schedule of generation for each SEIE.

● Primary and secondary regulatory power reserve program.

● Tertiary regulation service program.

● Group boot order for replacement in case of failure or unavailability.

On those systems electrically connected to other systems it will be published:

● Programmable capacity on existing links.

● Program by existing links.

5.8 Structural Information Management. For the proper functioning of the services and processes managed by the OS it is necessary to know and to maintain information regarding the subjects of the system, Units of Programming (UP), and Physical (UF), as well as a series of additional data and technical parameters required for the programming of the system operation. All this information is collected under the Structural Data name.

The subjects must communicate to the OS the information needed to perform the generation programming function.

The information to provide is as follows:

● Group time availability (inavailabilities, maintenance, limitations).

● Rolling power reserve capacity.

● Demand forecast from dealers, marketers, and qualified consumers who purchase their energy directly from the generation office.

● Generation of generators on special speed.

In addition, the subjects must inform the OS of the following information in accordance with the current regulations:

● Net and minimum technical power.

● Rise and drop ramps.

● Cold start costs, hot start, and hot reserve.

● Group efficiency curve for economic dispatch.

The cost of each of the fuels used in SEIE will be that established by the Ministry of Industry, Energy and Tourism.

Agents must also additionally provide the information required in the various Operation Procedures.

5.9 Request for structural information modification. The modification of the structural information will be requested through the submission to the OS of the corresponding form available on the Web page duly completed and accompanied by documentary support supporting the change.

Once the modification requested by the system subject has been revised, the OS will communicate to the system subject the date for which the requested change will be made, or, where appropriate, the reason for the failure to do so.

6. SEIE Hub for Electrical Measures

The appropriate SEIE Electrical Measures Hub is the system with which the OS manages the measurement information in each SEIE in accordance with the requirements set out in the current legal regulations.

6.1 Content of the Electrical Measurement Hub database. The data required for the management of the measurement system is collected by the SEIE Concentrator database and will be at least the following:

a) The structural information resident in the SEIE Concentrator for Borders in which the OS is in charge of reading:

Measurement Points.

Border points.

Measure point relationships with border points.

Counters.

Registrars.

Measure transformers.

b) The information of measures resident in the SEIE Concentrator for Borders in which the OS is in charge of reading:

Time measures on measurement points.

Hourly data for measures calculated at the border points.

Hourly data for measures calculated in the Programming Units.

c) The structural information resident in the SEIE Measurement Hub for borders of which the OS is not in charge of reading.

Universal Point of Supply Types 1 and 2 (CUPS) codes.

Customer measure point aggregates types 3, 4, and 5.

Encoding facilities and special regime aggregations types 3 and 5.

d) The information of measures resident in the Border Measures Hub of which the OS is not in charge of the reading.

Time measures in CUPS types 1 and 2.

Time data for the aggregate measures of types 3, 4, and 5.

Hourly data for special regime aggregate measures types 3 and 5.

e) Additionally will have other information that will include at least:

Hourly data for measures calculated in the Programming Units.

Accumulated between activities.

6.2 Access to information from SEIE's Measurement Hub. The OS manages access to the resident measures information in the SEIE Hub of Measures according to the following:

6.3 Free access information. The OS publishes a number of general reports from the energy and inventory data available from the SEIE Hub.

This information will be available on the Internet address of the OS (http://www.ree.es).

6.4 Information for the measurement system participants. The information contained in the SEIE Electrical Measurement Concentrator is of a restricted nature, so that only each participant in the measurement system will be able to access the data from the border points, CUPS and/or aggregations of which it is participate.

Each participant in the measurement system may consult at least the following information in the SEIE Electrical Measurement Concentrator:

● Time measures of the measurement points from which the OS is in charge of reading.

● Time measures of the border points on which the OS is responsible for reading.

● Setting up the border points of which the OS is in charge of reading.

● Inventory of the measurement points from which the OS is in charge of reading.

● Time measures in CUPS types 1 and 2.

● Time measures of types 3, 4, and 5 aggregations.

The OS Internet address indicates the requirements and procedures to be followed for the use of such secure access to the Main Electrical Measurement Concentrator.

In addition, the OS will publish and exchange information of measures with the secondary concentrators according to the protocol defined in the Operation Procedure P.O. 10.4 and users of the Main Hub. The content and format of the different data of measures exchanged by the participants of the measurement system will be collected in the latest version of the document 'Ficheros for the Exchange of Measures'. The wording of this document is the responsibility of the OS and will be available on its website.

6.5 Information Management. The measurement concentrator receives and manages the information exchanged between the border points in accordance with the requirements set out in the current legal regulations.

6.6 High border points, CUPS, aggregations and other structural data. The high, low and/or modification of borders, CUPS and aggregations along with the other structural data will be performed according to the current legislation and taking into account the current version of the document " Ficheros for the exchange of information of Measures for SEIE in the Island and Extraceninsular Electrical Systems and Information for holders of special regime installations published on the OS website. The OS shall periodically provide the National Energy Commission with the existing relationship between Physical Units, Generation Units and CIL Codes.

6.7 Receiving of measures from the SEIE Hub. The sending of measurement data to the SEIE Hub shall be carried out according to the means, protocols and deadlines set out in the legislation in force.

6.8 Other considerations about measurement information. The information on electrical measures shall be available at the concentrator of measures for a minimum period of six calendar years from 1 January of the year following the date of each measure. Access to information more than two years old may require a special procedure.

7. Real-time Operation Control System (SCO)

The OS must receive in its Control System of the Operation in real time and automatically all the information of the installations of transport and production, including the generation in special regime and the observable net -as defined by the latter in the procedure of operation P.O. 8.1 of the SEIE by which the networks operated and observed by the OS are defined-that is precise to operate in SEIE. To do this, the OS will have the corresponding Operation Control System Database (BDCO).

7.1 Production facility control center. Real-time information relating to installations for the production of an installed power exceeding 1 MW (or of power plants of a power equal to or less than that and forming part of a pool of which the sum of powers is greater than 1 MW) must be captured by means of its own and provided to the OS through the connections with the generation control centres. These generation control centres may be owned or owned by third parties representing the operator of the installation in this function. The real-time information to be provided to the OS is specified in Annex II.

This generation control center will be responsible for sending to the OS all the real time information for the installation, as well as the caller by the installation in all communications with the OS. in relation to the operation of the facility, including all exchanges of information relating to the participation of the facility in the services of the system and in the economic dispatch.

7.2 Content and structure of the SCO Database (BDCO). The SCO Database will receive the following information and the following technical specifications:

7.2.1 Technical Requirements. The real-time exchange with REE will be performed using the standard communications protocol called ICCP-TASE2, by means of the information exchange blocks defined as 1 and 2.

To carry out such an exchange of information, the Control Center that communicates with the OS, will establish with each of the REE Control Centers in the corresponding SEIE (Principal and Backing) two lines of Point-to-point, redundant communication of the kind and dedicated exclusively to the exchange of this information. The technical characteristics of these 4 lines shall be identical and shall be completely dried and isolated from the internet. EEE will provide prior information to the establishment of the additional technical information by developing the above.

A control center may not share its control system or communications with the OS or personnel that constitute the closed operation shift with another control center. The operation shift shall be physically in the postal address communicated to the OS.

The periodicity of the information to be exchanged for secondary regulation data shall be equal to or less than the regulatory cycle. In terms of frequency measurements, the OS should receive at least one measure with mHz accuracy for each isolated SEIE system at a frequency of 1 second. The rest of the information in real time will be exchanged with a periodicity to be determined by the OS with each agent, and in no case will exceed the 12 seconds.

The OS will maintain the confidentiality of the information received. However, it may send the agents such information as they request, provided that such information is necessary to ensure the development of their functions as regards the operation of the system. (voltage control, safeguard plans, emergency and replacement of the service) and the authorisation of the holder of the information generated.

7.2.2 Required Information. Information on the facilities listed below will be required:

Transport Network.

Observable network.

Generation Facilities.

Level of filling of reservoirs in pumping stations.

7.2.3 Definition and general criteria for normalized signal and measurement collection. In this procedure, the set of the elements associated with line, transformer, reactance, bars or coupling of bars that are precise for their maneuver and operation is understood by position.

The (open/closed) state of the switches and dryers will be given by 2 bits. The rest of the signals will be given with one.

Given their uniqueness, the Synchronous and Condenser Compensators have been separately considered.

The following considerations have been taken into account in the way the signals are captured:

(a) Under the heading of transformers, they are considered even those of groups and consumption.

b) The following classification of the information has been performed to fetch:

1. Signs. Includes states (open/closed) or indications of devices that do not constitute anomalies or malfunctions. Included here are the topological states of the network (open/closed states of switches and dryers).

2. Alarms. It includes device or event action signalisations, which by the nature of the fetch are very short-lived pulses. This includes, but not exclusively, protective performances that cause circuit breakers to open.

3. Anomalies. Includes signalisations associated with normal/abnormal operating positions or states of equipment or elements. Each failure will be indicated by a closed state regardless of the physical state of the fetch device.

4. Measures. It includes the analogue or digital measures for discrete numerical magnitudes of the installation (e.g. indication of transformer sockets).

The detailed information for the signals to be captured is given in Annex 2.

7.2.4 Real-time received telemetry quality validation criteria for active power generation. The information to be sent to the OS shall have a minimum quality to establish compliance with the requirements set out in paragraph 7.1 of this procedure.

In general, the determination of the validity of the real-time telemedidas received at the System Operator control centers will be performed monthly determining their error with respect to the monthly accumulated of the liquidable time-energy recorded on the measuring equipment which complies with the provisions of the unified regulation of the measurement points of the electrical system, hereinafter the time measurement equipment

It is defined for an installation/pool:

● Integrated time frame for hour h (THIh): is the integral time of the active power telemetry received in real time by the OS during the hour h, and therefore represents the energy produced (1) by the installation/pool on the calculated h hour from the real-time telemedides.

● Time Energy recorded for hour h (EHRh): is the time energy recorded by the hourly measurement equipment calculated as the difference between the "exported energy" AS and the "imported energy" AE.

● Total Hours (H): Total set of monthly hours of the month m.

● Registered Hours (I): Subset of the monthly hours of the month m that are available for the registered liquidable time-energy measurement installation/pool.

The OS will consider that the quality of the telemedidas of the month m for a given installation/pool is valid if and only if each and every one of the following conditions are met:

In addition, the OS will be able to carry out the verifications that it deems appropriate and are within its reach to ensure that the telemetry sent correspond to the profile of the productions actually made. In the case of identifying, at the discretion of the OS, fraudulent manipulation of the submitted telemetry will be brought to the attention of the NEC for the appropriate effects.

8. Other information subjects should send to the system operator

The OS will be responsible for collecting all other information regarding the SEIE operation described in this section.

(1) The integral time of the telemedidas is done with its corresponding sign, so that a positive final value indicates produced energy, whereas if it is negative, it would represent an active energy consumption by of the installation/pool.

It is the responsibility of the producers, the single carrier and the distributors who are exceptionally operators of transport facilities and the distribution system operators to provide the information to the OS which it requires for the exercise of its functions. Dispatch to the OS, by distributors (including those who are exceptionally holders of transport facilities) and the single carrier, of the list of special arrangements for facilities connected with their services shall be compulsory. networks.

Also, the distribution managers shall collect from the generators in particular their scope, the information necessary for the operation and send it to the OS with the frequency specified.

In case of not being able to dispose of some of this data, they will cause to the OS their best estimate of them.

The following data will be sent to the OS in the form of daily aggregated values, in three time horizons: at three days (day D + 4, with day D being the day of programming), before the 20th day of the month M + 1, and before the 20th of the month of January of each year, in order to maintain the statistical series relating to the energy balance sheets and the operation of the system, as well as for the provision of security coverage and analysis.

8.1 Data to be sent to the three days. The SEIE subjects shall provide the OS with all the data necessary for the compilation of the official statistics, using the established information exchange channels for this purpose. All values of the magnitudes listed below will be given with the greatest possible disaggregation in physical units.

Production of the thermal groups in the alternator (b.a.) if this measure is available.

Production of hydraulic power stations (CCHH) (b.a.). if this measure is available.

We consume your own generation.

Consumption of pumping stations.

Accumulated energy available for generation in pumping stations.

Fuel consumption in thermal power plants.

Fuel stocks in thermal power plants.

Hydrological information:

● Hydroelectric reserves by reservoirs (in hm³ and MWh), taking into account the total capacity of the basin.

● Vertids.

Incidents on the Transport Network.

Production of groups included in the Special Generation Regime (b.c.).

8.2 Data to be sent before day 20 of month M + 1. The following monthly data will be sent to the OS before the 20th of the following month with the maximum level of disaggregation possible in physical units:

Gross daily production of thermal groups.

Hydroelectric daily production (CHCHH) (b.a.).

Loss of turban in hydraulic power stations.

We consume your own generation.

Consumption and production of pumping stations.

Accumulated energy available for generation in pumping stations.

Hydroelectric reserves by reservoirs in hm³ and MWh, taking into account the total capacity of the basin.

Fuel entry in power plants/thermal groups (in tonnes and termine (PCI and PCS) broken down by fuel oil classes at the plants of this type.

Fuel consumption in core/thermal groups (in tonnes and termine (PCI and PCS) broken down by fuel oil classes at the plants of this type.

Fuel stocks in power plants/thermal groups (in tonnes and termine (PCI and PCS)) broken down by fuel oil classes at the plants of this type.

Lower calorific power (PCI) and higher (PCS) of each of the fuels used in the generation.

Planned plan for reduced deliveries of guaranteed coal for the next twelve months (expressed in tonnes and in termine (PCI and PCS)) and quantities of the current year actually delivered to date.

8.3 Annual Data. Before the 20th of January, the annual maximum capacity data for each reservoir shall be sent to the OS, taking into account the total capacity of the basin.

9. Statistics and public information regarding the operation of the system

The OS will publish the data that is later indicated on the operation performed, including the behavior of the transport network and the generation media.

9.1 Daily information. The information that the OS will publish daily is the system load curve.

9.2 Information at three days. The OS will publish D + 4 the information of the production power balance, corresponding to day D.

9.3 Monthly information. Monthly the OS will publish the following information:

SEIE Operation Statistics.

Availability of the generation thermal equipment.

Rate of unavailability of lines, transformers, and reactive energy compensation elements (reactances and capacitors) of the transport network.

Incident statistics.

Evolution of short circuit power in the nodes of the transport network.

Service quality for Non-Supplied Energy (ENS) and Medium Interruption Time (TIM).

9.4 Annual information. The OS will publish the following information annually:

● Availability of the generator equipment.

● Availability of the transport network.

● Quality of Service (ENS and TIM).

● Seasonal thermal limits of the transport network.

In addition, the OS will keep updated and available historical strings available from:

● Power installed on each SEIE.

● Technologies generated by technologies.

● Energy generated by the ordinary regime and by the special regime

● Pump consumption.

● Demand for each SEIE.

● Hydroelectric Producible.

● Hydroelectric reserves.

● Generator equipment availability rates.

● Transport network availability rates.

10. Analysis and incident information

10.1 Incidents. Events defining those incidents of electrical systems which are the subject of information, in the field of this procedure, by the subject holder of the facilities concerned or the person responsible for the supply to consumers affected endpoints are as follows:

(a) The loss of one or more transport facilities and/or other elements of the electrical systems (generation and/or transport-distribution transformation) where this results in a violation of the criteria of operation and safety of electrical systems established in the relevant operating procedure or direct loss of supply.

b) Any other circumstances that result in:

a. Major damage to any of the elements of the electrical system.

b. Failure, degradation, or improper performance of the protection system, automatisms or any other system that does not require manual intervention by the operator.

c. Any act that may be suspected of being caused by electronic or physical sabotage, terrorism directed against electrical systems or their components with intent to disrupt the supply, or to reduce the reliability of electrical systems in their set.

d. Loss of supply, regardless of the incident that occurred and the level of tension in which it occurred, significant or requested by the OS.

e. Other anomalous circumstances for the electrical system-for example, significant oscillations-not associated with loss of transport network facilities or loss of supply.

10.2 Communication to the System Operator. In the event of any impact as defined in the previous paragraph, the operator responsible for the supply concerned shall, within a period of 2 hours, provide the best information available to the OS and within 2 hours. on the causes and effects of the event. This information which constitutes the preliminary report of the incidence shall contain at least the aspects (a), (b), (c) and (d) listed in Annex 3 which are applicable.

The OS may, when it deems necessary, carry out additional consultations in order to clarify the content of the preliminary report, leaving the issuer of the same obligation to attend the consultation at that time or as soon as have the required additional information.

When the OS determines that the event constitutes a significant incident for an electrical system, it shall notify the holder or representative of the installation or the person responsible for the supply of the consumers. Affected endpoints.

This subject must submit a written report to the OS within a period of no more than 15 working days from the request. This report shall review and complete the information referred to in the preliminary report (Annex 3) and include any actions identified by the subject to avoid or minimise the effect of similar incidents that may occur in the future.

10.3 System Operator Communication. Where an incident occurs within the meaning of paragraph 10.1, the OS shall include the relevant information in a "Daily Party of Incidents" which shall be made available to the subjects within 12 hours of the day following the occurrence of the occurrence. of the same.

When the OS considers an incident of special relevance, it will produce a written report, once the final information of the report is available. This report shall include the measures to be taken to avoid repetition of the impact or the minimisation of its consequences in the event of a similar situation in the future. This report shall be forwarded to the subjects concerned, to the National Energy Commission and to the Ministry of Industry, Energy and Tourism, within a period not exceeding 60 working days after the occurrence of the incident.

Reports corresponding to the most significant incidents will be presented and analyzed at the meetings of the Incident Analysis Group that will be convened by the System Operator.

10.4 Joint Investigations. For those incidents in which, due to its importance or nature, the OS deems it necessary, it will propose as soon as possible the carrying out of a joint analysis with the other subjects involved or affected. The results of that analysis will be incorporated into the report that the OS produces on the incident.

11. System operator liability clearance information.

11.1 Confidential information. The confidential information corresponding to the settlements made by the os is the one that communicates to the subjects of the market on an individual basis without access to it the rest of the subjects.

All processes associated with this information are defined in the liquidations procedures.

11.2 Public Information. The aggregate settlement information made available to the subjects shall also be made available to the general public on the same day.

ANNEX I

Structural database content

General notes and abbreviations

• As a general rule, data should be expressed in units of the international system unless otherwise expressly stated.

• From impedance data, the voltage to which they are referred or the base values, if any, should be indicated.

• The PSS/E expression refers to the computing application for the stability analysis of power electric systems of Power Technologies Inc.

Annex I structure

This annex is organized according to the following structure:

1. Production system.

1.5 Embalses.

1.6 Central and hydraulic groups.

1.6.1 Installation general and hydraulic data.

1.6.2 Data for each group.

1.6.3 Secondary throttling data.

1.6.4 Data required for service replacement plans.

1.6.5 Group transformer data.

1.6.6 Evacuation line or cable data.

1.6.7 Data from the Protections.

1.6.8 Main data for voltage control equipment.

1.7 Ordinary-speed thermal units.

1.7.1 General installation data.

1.7.2 Data for each generator.

1.7.3 Main turbine data and primary regulatory equipment.

1.7.4 Secondary throttling data.

1.7.5 Data for programming and tertiary regulation.

1.7.6 Main data for voltage control equipment.

1.7.7 Data required for service replenishment plans.

1.7.8 Group transformer data.

1.7.9 Evacuation line or cable data.

1.7.10 Data from the Protections.

1.8 Special Regime Units.

1.8.1 Production facilities based on synchronous generators directly connected to the network larger than 1 MW or connected to the transport network or participating individually or in a pooled manner in the adjustment services system ..

1.8.1.1 Installation and group data.

1.8.1.2 Secondary throttling data.

1.8.1.3 Data for programming and tertiary regulation (in case of participation in technical dispatch).

1.8.1.4 Data required for service replacement plans.

1.8.1.5 Data for group transformers.

1.8.1.6 Data from the evacuation line or cable.

1.8.1.7 Data from the Protections.

1.8.1.8 Main data for voltage control equipment for plants over 5 MW.

1.8.1.9 Tension control for plants over 5 MW.

1.8.2 Wind, photovoltaic and in general installations all production facilities whose technology does not employ a synchronous generator connected directly to the network.

1.8.2.1 Features of each installation.

1.8.2.2 Network connection transformer data.

1.8.2.3 Network connection cable or line data.

1.8.2.4 Data from the Protections.

1.8.2.5 Additional data for installations connected to a transport network.

1.8.2.5.1 Features of each installation.

1.8.2.5.2 Installation evacuation transformer data.

1.8.2.5.3 Data on the evacuation line or cable for each installation.

1.8.2.5.4 Network connection transformer data.

1.8.2.5.5 Evacuation line or cable data.

1.8.2.5.6 Data from the Protections.

2. Transport network.

2.1 Substations.

2.2 Parks.

2.3 Lines and cables.

2.4 Transformers.

2.5 Active or reactive power control elements.

3. Consumer installations connected to the transport network.

4. Observable network.

4.1 Substations.

4.2 Parks.

4.3 Lines and cables.

4.4 Transformers.

4.5 Reactive power control elements.

1. Production System

1.1 Embalses.

• Name of the reservoir.

• Enterprise or business owners or concessionaires:

-Name.

-NIF/CIF.

-Address.

-Percentage of participation.

• Situation: province, municipal term, place or land.

• Date of termination.

• Capacity in electrical energy (MWh).

• Historical series of partial contributions to the reservoir in monthly and weekly terms (m³).

• Maximum volume (hm³).

• Minimum volume (hm³).

• Curva cote of reservoir based on useful volume (minimum 3rd grade).

• Maximum farm (m).

• Minimum farm (m).

• Ecological minimum flow to keep downstream.

• Regulatory Coefficient (days), defined as the ratio between the reservoir volume and the average annual contribution to the reservoir.

• Reservoir emptying time (hours) with turban at full load of the plant itself.

• Usage (Hydroelectric, Mixed).

• Operating constraints (detactions, waterings, etc).

1.2 Central and hydraulic groups.

1.2.1 Installation general and hydraulic data

1.2.1.1 Data in the case of power stations that are not connected to the transport network.

-Name of the Central.

-Home of the Central: municipality, postal code and province.

-Enterprise or proprietary companies:

■ Name.

■ NIF/CIF.

■ Address.

■ Percentage of participation.

-Enterprise or exploitative companies:

■ Name.

■ NIF/CIF.

■ Address.

-Cuenca (river) in which the plant is located.

-The associated reservoir.

-Substation/network connection park (Name, kV).

-Hydraulic Management Unit to which you belong, if any.

-Number of groups.

-Nominal flow (m³/s).

-Nominal net high (m).

-Apparent power in alternator (MVA) terminals.

-Nominal power in turban (MW).

-Nominal pumping power (MW), if any.

-Net technical minimum, that is, in central bars (MW).

-Inertia Constant (s) of the rotating assembly: electric machine, exciter and turbine.

-Availability of primary regulation or speed regulation (SI/NO). If not, please provide documentation supporting the provision of the service by another generating unit.

-Insensitivity of the regulator (mHz). It must be less than 10 mHz.

-Regulator voluntary dead band (mHz): confirm that the adjusted value is zero.

-Minimum frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

1.2.1.2 Data in the case of power stations that are connected to the transport network or to the observable network.

-Name of the Central.

-Home of the Central: municipality, postal code and province.

-Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

-Installation UTM coordinates (give a reference point)

-Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 10 kV with influence over the network transport).

-Enterprise or proprietary companies:

■ Name.

■ NIF/CIF.

■ Address.

■ Percentage of participation.

-Enterprise or exploitative companies:

■ Name.

■ NIF/CIF.

■ Address.

-Cuenca (river) in which the plant is located.

-Hydraulic subsystem schema.

-The associated reservoir.

-Substation/network connection park (name, kV).

-Hydraulic Management Unit to which you belong, if any.

-Estimated unavailability rates for maintenance.

-Estimated unavailability rates for other causes.

-Driving Channel/Pressure Gallery (SI/NO). If yes, length (s) and diameter (s).

-On or off date (forecast if applicable).

-Forced Tuberia (SI/NO). If yes, length (s) and diameter (s).

-Number of groups.

-Nominal power.

-Type of turbine.

-Nominal flow (m³/s).

-Nominal speed (m/s).

-Maximum turbination flow (m³/s).

-Minimum turbination flow (m³/s).

-Maximum gross high (m).

-Minimum gross (m).

-Nominal net high (m).

-Net of equipment (m).

-Maximum net high (m).

-Minimum net high (m).

-Maximum energy efficient (kWh/m³).

-Minimum energy efficient (kWh/m³).

-Losses in flow-based pipelines.

-Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

-For reversible or pumping groups:

■ Nominal power.

■ Nominal effective height (m).

■ Nominal drive height (m).

■ Nominal flow rate (m³/s).

■ Maximum pump flow (m³/s).

■ Minimum pumping flow (m³/s).

■ Pump accumulation index (%), defined as the ratio of the electrical energy that can occur with the water accumulated by pumping and the energy consumed for its elevation.

■ Loss in aspiration and drive based on flow rate.

■ Performance curves based on the pumped flow and the manometric height (alternative: power tables for different manometric heights and different flow rates for each manometric height).

-Additional data in the case of power stations connected to the transport network:

■ Physical diagram (general scheme at site) of the link installation.

■ One-to-one detail diagram of power equipment from the different generation units to the point of connection to the network.

■ Unifilar installation protection scheme.

1.2.2 Data for each group.

-Identification number in the RAIPEE (Administrative Registry of Electrical Power Production Facilities).

-On or off date (forecast if applicable).

-Type of turbine.

-Nominal speed (rpm).

-Nominal power in turban (MW).

-Nominal flow (m³/s).

-Nominal net high (m).

-Net technical minimum, that is, in central bars (MW).

-Maximum turbination flow (m³/s).

-Minimum turbination flow (m³/s).

-Maximum gross high (m).

-Minimum gross (m).

-Maximum net high (m).

-Minimum net high (m).

-Losses in flow-based pipelines.

-Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

-For reversible or pumping groups:

■ Type of pump.

■ Nominal power.

■ Nominal speed (rpm).

■ Nominal effective height (m).

■ Nominal flow rate (m³/s).

■ Maximum pump flow (m³/s).

■ Minimum pumping flow (m³/s).

■ Loss in aspiration and drive based on flow rate.

■ Performance curves based on the pumped flow and the manometric height (alternative: power tables for different manometric heights and different flow rates for each manometric height).

■ Apparent power in alternator borns (MVA).

■ Maximum Full-Load Reactive Generation (MVAr) in b.c.

■ Maximum Technical Minimum Reactive Generation (MVAr) in b.c.

■ Maximum load-reactive (MVAr) absorption in b.c.

■ Maximum technical minimum reactive absorption (MVAr) in b.c.

■ Nominal power factor.

■ Capability as synchronous compensator (SI/NO).

■ Absorbed power in operation as synchronous compensator (MW).

■ Top turbine and primary regulatory equipment data

■ Turbine characteristics: manufacturer and model.

■ Availability of primary regulation or speed regulation (SI/NO).

-If you do not have your own primary regulation, provide documentation that accredits the service delivery to another generating unit, indicating:

■ Unit providing the service.

■ Insensitivity confirmation not exceeding 10 mHz.

■ Null voluntary dead band confirmation.

-In case of own primary regulation, indicate:

■ Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ...

■ Permanent statism:

or tuning range

or adjusted value

or telemetry capability of the adjusted value.

■ Speed of power variation in MW/s, by frequency variation. Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

■ Voluntary regulator dead band (mHz):

or tuning range

or adjusted value: confirm that it is zero

or télédida capability of the adjusted value

■ Regulator characteristics: manufacturer, type of control (PID series compensator, resupply compensation using transient staticism, ...) and technology (hydraulic, electrohydraulic ...)

■ Dynamic compensations: a function of transfer of dynamic compensation (transient statism, series compensator, ...). The range of each parameter and its setting or watchword value must be specified.

■ The turbine-speed regulator block scheme and the corresponding values of the parameters that are represented in the schemas. This information will be provided as follows:

■ Through a model included in the list of dynamic models supported by the OS, and which will be provided by the OS itself,

■ either through a model not included in the above list provided that it meets the characteristics and conditions set out in document to the effect developed by the OS.

■ In both cases, it must be accompanied by a validation report on the suitability of the model to represent the turbine-speed regulator according to the conditions set out in the document to the effect produced by the OS.

■ Nominal generation (kV).

■ Maximum generation voltage (kV).

■ Minimum generation voltage (kV).

■ Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis in machine base (Xd, Xq, X'd, X'q, X'' d, and X'' q. Symbology as standard UNE-EN 60034-4)

■ transient and subtransient time-short constants for both direct and transverse axis (s) (T' d, T' q, T '' d and T '' q. Symbology as standard UNE-EN 60034-4).

■ Transient time and subtransient open circuit constants for both direct and transverse axis (s) (T' d0, T' q0, T '' d0, and T '' q0. Symbology as standard UNE-EN 60034-4).

■ Inertia Constant (s) of the rotating assembly: electric machine, exciter and turbine.

■ Unsaturated leak reactance (p.u.) (X_l).

■ Saturation of machine to voltage 1.0 p.u., as shown in Figure 1.

■ Saturation of machine to voltage 1.2 p.u., as shown in Figure 1.

■ P-Q capacity curves (generator operating limits).

Figure 1. Saturation factors

1.2.3 Secondary throttling data.

-Regulatory zone to which you belong.

-Ability to receive external throttling signals (secondary loop) (SI/NO).

-Generators with the possibility of active participation in secondary regulation:

-Detailed information of the connection of the system of regulation with the AGC: characteristics of the signal signal, processing of the signal, limits, ...

-Maximum and minimum active power of regulation in b.a. (MW) for different stable operating points, if applicable.

-Limitations on upload and load drop on MW/min: adjustment range and slogan values for continuous ramp and step.

1.2.4 Data required for service replacement plans.

-Stand-alone boot capacity (SI/NO).

-Own media to energize the auxiliary services needed for startup:

■ Battery.

■ Diesel Group.

■ Other.

-Unifillar diagrams.

-Autonomy time (hours).

-Boot type:

■ By remote control.

■ Local operation (will indicate the hourly availability of personnel).

-The minimum guaranteed operating time continued at full load during the replenishment process (minimum water reserves).

-Possibility of performing a certain number of consecutive starts in a given time (in case of possible shots during the replacement process): number of start and stop cycles, and duration of the cycle.

-Minimum number of groups to operate in parallel.

-Cascade-start capability of a set of groups.

-Island operating capacity. Minimum market bag that is capable of feeding the group in island situation.

-Ability to remain stable after a disconnect from the outside network with sudden loss of full load, only feeding its own consumption.

1.2.5 Data for group transformers.

-Nominal power (MVA).

-Primary and secondary nominal voltage (kV).

-Connection group.

-Loss due to load (kW).

-Short circuit voltage (%).

-Homopolar impedance (% on machine base).

-Regulatory characteristics (winding with takes, no takes, maximum and minimum ratio).

1.2.6 Evacuation line or cable data

-View observable network lines and cables.

1.2.7 Data from the Protections

-Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

-Minimum voltage gels: settings.

-Central stability to short circuits in the network: critical disconnect time.

-Minimum frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

-Overfrequency protection. Adjustments.

-Disarrest for over-speed. Firing value.

-In case the critical time in the connection node to the network is less than 1 second, indicate:

or Short-circuit protection scheme in the main network-transformer stretch.

or Compliance with the General Protection Criteria.

or Unifilar installation protection scheme.

1.2.7.1 Additional data for groups connected to the transport network.

1.2.7.1.1 Central Protections.

-Network short-circuit support protection: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with network protections.

-Protection from loss of synchronism: indicate type of protection, number of slides for the shot and if the group is left over auxiliary.

-Overvoltage Relation: Settings.

-Reverse sequence protection: indicate the coordination status of this protection with the single-phase reengagement and the network pole discordance relays.

-Sync conditions for coupling. Existing automatisms and settings.

1.2.7.1.2 Protections associated with the link installation.

-Network short-circuit support protection: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with network protections.

-Short circuit protection scheme in the generation network-transformer stretch. Compliance with the General Protection Criteria.

-Minimum voltage Rele: settings.

1.2.7.1.3 Telefiring against network contingencies.

-Teleshooting capacity (SI/NO).

-The tele-firing time since the signal is received.

-The telephoto logic and switches or selectors that it includes.

1.2.8 Main data for voltage control equipment (in the case of connection to the transport network).

-Brief description of the voltage regulator-excitation, which will include the name and type of the regulator.

-Block schema, and corresponding values of the parameters that are represented in the schemas, of the voltage-excitedess and the power stabilizer system (PSS) regulators if they have this device. This information will be provided using PSS/E compatible model, either from the application's own library or as a user model by supplying the code of your FLECS language source program.

1.3 Thermal Units.

1.3.1 General installation data.

-Central name.

-The name of the installation.

-Geographical location (access requests): planes (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

-Installation UTM coordinates (give a reference point).

-Unifile diagram with all the components of the network link installation (access requests).

-Physical diagram (general scheme at site) of the link installation.

-Unifilar detail diagram of the power equipment from the different generation units to the point of connection to the network.

-Enterprise or proprietary companies:

-Name.

-NIF/CIF.

-Address.

-Percentage of participation.

-Enterprise or exploitative companies:

-Name.

-NIF/CIF.

-Address.

-Identification number in the RAIPEE.

-Headquarters of the plant: municipality, postal code and province.

-On or off date (forecast, if any).

-Main and alternate fuels.

-Substation/network connection park (Name, kV).

-General configuration of the installation, indicating in its case characteristics of coupling between elements (e.g. gas turbines, steam turbines and alternators), as well as modularity and operating flexibility.

-Estimated unavailability rates for maintenance and other causes (annual and seasonal indices if applicable).

-Efficiency of each thermal unit and set for different load regimes (kWh/kcal).

-Maximum primary and alternate fuel storage capacity (T).

-Power reserve (fuel storage park) (MWh) for primary and alternative fuels.

-Maximum number of operating hours at full load without external supply for primary and alternate fuels.

-Planned operating system.

-Uniform protection and measurement schemes for the installation up to the point of connection to the network, including auxiliary and transformer start-up services, where appropriate.

1.3.2 Data for each generator.

• In the case of generators dependent on each other, as the combined cycle members can be, also contribute the active and reactive power data, for the different possible configurations of operation permanent as short duration, for example, with off-duty steam turbine.

-Apparent power installed (MVA).

-Generation nominal voltage (kV).

-Maximum generation voltage (kV).

-Minimum generation voltage (kV).

-Active power installed in b.a. (MW)

-Net active power installed in b.c. (MW).

-Effective net active power of winter in b.c. (MW).

-Active net active power of summer in b.c. (MW).

-Technical minimum in b.a. (MW)

-Technical minimum in b.c. (MW).

-Special technical minimum in b.a. (MW).

-Special technical minimum in b.c. (MW).

-Time that the minimum special technician (h) can be maintained.

-Maximum Full Load Reactive Generation (MVAr) in b.a.

-Maximum Technical Minimum Reactive Generation (MVAr) in b.a.

-Maximum load-reactive (MVAr) absorption in b.a.

-Maximum technical minimum reactive absorption (MVAr) in b.a ..

-Consumption of auxiliary services in b.a. at full load, active power (MW).

-Consumption of auxiliary services in b.a. at full load, reactive power (MVAr).

-Consumption of auxiliary services in at least technical, active power (MW).

-Consumption of auxiliary services in a minimum technical, reactive power (MVAr).

-Nominal power factor.

-Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis (p.u.).

-transient and subtransient time-short constants for both direct and transverse axis (s).

-Open-circuit transient and transient time constants for both direct and transverse axis (s).

-The inertia constant of the rotating turbine-generator set (s).

-Unsaturated leakage reactance (p.u.).

-Saturation of machine to voltage 1.0 p.u. (p.u.), as Figure 1.

-Saturation of machine to voltage 1.2 p.u. (p.u.), as Figure 1.

(The above three data can be collected in the form of an interiron curve and full load).

-P-Q capacity curves (operating limits).

Figure 1. Saturation factors

1.3.3 Main turbine and primary regulatory equipment data

• In the case of multi-axis combined cycles, the information requested here will be sent separately for each gas and steam turbine.

-Gas turbine characteristics (if any): manufacturer and model. A simplified operating model that considers the combustion temperature limiter must be included.

-Steam turbine characteristics (if any): manufacturer and model. A simplified operating model must be included that specifies the time constant of the high pressure stage and the recheartening stage along with the power fractions corresponding to each stage. A simplified model of the boiler should also be included with the steam accumulation time constant, the pressure regulator model and the corresponding adjustments and limits.

-Availability of primary regulation or speed regulation (SI/NO). If not, please provide documentation supporting the provision of the service by another generating unit.

-Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ...

-Permanent statism:

-adjustment range.

-adjusted value.

-the telemetry capability of the adjusted value.

-Speed of power variation in MW/s, by frequency variation.

-Insensitivity of the regulator (mHz). It must be less than 10 mHz.

-Regulator voluntary dead band (mHz):

-adjustment range.

-adjusted value: confirm that it is zero.

-the telemetry capability of the adjusted value.

-Characteristics of the regulator (or regulators, if any): manufacturer, type of control (PID series compensator, compensation for resupply by means of transient staticism, ...) and technology (hydraulic, electrohydraulic ...).

-Dynamic compensations: dynamic compensation transfer function (transient staticism, series compensator, ...). The range of each parameter and its watchword value must be specified.

-A block scheme of the regulator (or the regulators, if any) of the turbine-speed and the corresponding values of the parameters that are represented in the schemas. This information will be provided using PSS/E compatible model, either from the application's own library or as a user model by supplying the code of your FLECS language source program.

-Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

-Or through a model not included in the above list provided it meets the characteristics and conditions set out in document to the effect elaborated by the OS.

-In both cases, it must be accompanied by a validation report on the suitability of the model to represent the speed-turbine regulator, in accordance with the conditions set out in the document to the effect produced by the OS.

1.3.4 Secondary throttling data.

-Regulatory zone to which you belong.

-Ability to receive external throttling signals (secondary loop) (SI/NO).

-Generators with the possibility of active participation in secondary regulation:

-Detailed information of the connection of the system of regulation with the AGC: characteristics of the signal signal, processing of the signal, limits, ...

-Maximum and minimum active power of regulation in b.a. (MW) for different stable operating points, if applicable

-Limitations on upload and load drop on MW/min: adjustment range and slogan values for continuous ramp and step.

1.3.5 Data for programming and tertiary regulation.

• In the case of generators dependent on each other, as the combined cycle members can be, also contribute the requested data, for the different possible configurations of both permanent and of short duration, for example, start of the second gas turbine in case it is operating with a gas turbine and steam turbine.

-Minimum startup time:

or cold (from boot order to ready for synchronization).

or hot (from boot order to ready for synchronization).

-Minimum programming boot time:

or from synchronization to minimum technical (min).

or from synchronization to full load (min).

-Minimum programming stop time (from full load to disconnection) (min).

-Maximum up-ramp of tertiary regulation (MW in 15 min).

-Top down ramp of tertiary regulation (MW in 15 min).

-Minimum time from disconnect to ready for synchronization (MIN OFF) (h).

-Minimum time from synchronization to ready for disconnect (MIN ON) (h).

1.3.6 Main data for voltage control equipment.

• In the case of multi-axis combined cycles, the information requested here shall be sent separately for each gas and steam turbine generator.

-Brief description of the voltage regulator-excitation, which will include the name and type of the regulator.

-Block schema, and corresponding values of the parameters that are represented in the schemas, of the voltage-excitedess and the stabilizer system (PSS) regulators if they have this device. This information will be provided using PSS/E compatible model, either from the application's own library or as a user model by supplying the code of your FLECS language source program.

-Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

-or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect elaborated by the OS.

-In both cases, it must be accompanied by a validation report on the suitability of the model to represent the voltage regulator and the power stabiliser system (PSS), in accordance with the conditions set out in the document to the effect developed by the OS.

-In the case of generating groups and reversible groups that have the capacity to function as synchronous compensators, the technical operating requirements shall be indicated, and the time required for their entry into operation.

-The possibility, if any, of telemandar the groups must be indicated in such a way that the excitation delivery and/or the takes of the group's output transformer can be modified from the generation office of the titular holder or group representative, or from the appropriate control center.

1.3.7 Data required for service replenishment plans

-SSAA power.

-Simplified schema and description of the SSAA power process in the following assumptions:

■ Normal.

■ Boot.

■ Other alternatives (Diesel/Battery/Otras).

-SSAA power supply.

■ Consumption of auxiliary services in b.a. for group stop, active power (MW).

■ Auxiliary services consumption in b.a. for group stop, reactive power (MVAr).

■ Consumption of auxiliary services in b.a. for start-up, active power (MW). Specify different possibilities: Cold start/Hot start.

-Consumption of auxiliary services in b.a. for startup, reactive power (MVAr). Specify different possibilities: Cold start/Hot start.

■ Stand-alone startup capacity.

-Own media to energize the auxiliary services needed for startup:

■ Battery.

■ Diesel Group.

■ Other.

-Unifillar diagrams.

-Autonomy time (hours).

-Boot type:

■ By remote control.

■ Local operation (will indicate the hourly availability of personnel).

-The minimum guaranteed operating time continued at full load during the replacement process (minimum fuel or water reserves).

-Possibility of performing a certain number of consecutive starts in a given time (in case of possible shots during the replacement process): number of start and stop cycles, and duration of the cycle.

-Minimum number of groups to operate in parallel.

-Cascade-start capability of a set of groups.

■ Reconnection of the group to the network.

-P-Q capacity curves (Operating limits).

-Minimum cold start time (from boot order to ready for synchronization).

-Minimum hot start time (from boot order to ready for synchronization).

-Maximum stop time for the boot to be hot.

■ Ability to remain stable after a disconnect from the outside network with sudden loss of full load, only feeding its own consumption. (Yes/No. Description).

■ Island operating capacity. Minimum market bag that is capable of feeding the plant in island situation.

■ Sync conditions for coupling. Existing automatisms and settings.

■ Other data.

-Characteristics of the engines and loads of auxiliary services and data on protections and adjustments, if any.

-Dependence on non-fuel supply infrastructures for the reorder process.

1.3.8 Data for group transformers.

• View transport transformers.

1.3.9 Evacuation line or cable data.

• View transport lines and cables.

1.3.10 Data from the Protections

1.3.10.1 Central Protections

-Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

-Network short-circuit support protection: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with network protections.

-Auxiliary services, minimum voltage and/or minimum frequency relays: indicate adjustments and for the minimum voltage relay phases in which it measures and trigger logic.

-Central stability (group and ancillary services) to short circuits in the network: critical disconnect time.

-Protection from loss of synchronism: indicate type of protection, number of slides for the shot and if the group is left over auxiliary.

-Overvoltage Relation: Settings.

-Reverse sequence protection: indicate coordination status with the monophasic reengagement and the network pole discordance relays.

-Minimum group frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

-Overfrequency protection (yes/no). Adjustments, if any.

1.3.10.2 Protections associated with the link installation.

-Network short-circuit support protection: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with network protections.

-Short circuit protection scheme in the network-group transformer section. Compliance with General Protection Criteria. Critical time contemplated.

-Minimum voltage Rele: settings.

1.3.10.3 Telefiring against network contingencies.

-Tele-Shot Capacity (SI/NO)

-Type of telephoto (generation switch or fast-valve opening)

-Final power and time of descent in cases of rapid load reduction (fast-valving) and in general in non-instantaneous processes, such as in combined cycles, the response of the steam turbine to the telefiring partial gas turbines.

-The tele-firing time since the signal is received.

-The telephoto logic and switches or selectors that it includes.

1.4 Production units on special speed.

1.4.1 Production facilities based on synchronous generators directly connected to the network larger than 1 MW or connected to the transport network or participating individually or in a pooled manner in the adjustment services system.

1.4.1.1 Installation and group data.

1.4.1.1.1 General.

-Central name.

-Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

-Enterprise or proprietary companies:

■ Name.

■ NIF.

■ Address.

■ Percentage of participation.

-Identification number in the RAIPRE.

-The offering unit to which you belong, if any.

-Headquarters of the plant: municipality, postal code and province.

-On or off date (forecast, if any).

-Central type.

-Grant Date on Special Regime.

-The final year of the concession.

-Applicable rules.

-Distributor Company.

-Substation/park connection to the transport network (name, kV).

-Type of installation according to Royal Decree 661/2007 or alternative regulations that are applicable.

-Number of groups.

-Fuel.

-For hydraulic groups:

■ Jump (m).

■ Maximum flow (m³/s).

■ Regulatory regime (flow, daily, weekly).

-Data from energy storage systems and support by complementary fuel in the case of manageable or manageable thermal power plants:

■ Energy storage method (steam, oil, salts ...).

■ Recovery time curves for stored primary energy.

■ Stored primary energy loss curves.

■ Type of support with complementary fuel, power supply with said fuel and autonomy of the same (in hours at rated power).

■ Maximum power that can be delivered by the maximum storage and power system that you can accumulate.

■% of the plant's over-dimension for storage.

-Type of power (eventual/guaranteed).

-Apparent Installed Power (MVA) of the generating units.

-Welcome to Royal Decree 661/2007 or alternative regulations that are applicable (MW).

-Non-host power (MW).

-Net active power and minimum technical (MW) available for the network: statistical distribution by tenths of powers or time energies poured into the network since the plant became operational or estimated.

-For generations: Maximum electrical consumption (MW) of the plant, including industrial consumption.

-Availability of primary regulation or speed regulation (SI/NO). If not, please provide documentation supporting the provision of the service by another generating unit.

■ Insensitivity of the regulator (mHz). It must be less than 10 mHz.

■ Regulator voluntary dead band (mHz): confirm that the adjusted value is zero.

-If you do not have your own primary regulation, provide documentation that accredits the service delivery to another generating unit, indicating:

■ Unit providing the service.

■ Insensitivity confirmation not exceeding 10 mHz.

■ Null voluntary dead band confirmation.

-Minimum frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

1.4.1.1.2 Additional data in the case of generators or pool of generators of more than 1 MW of total power or connected to the transport network.

1.4.1.1.2.1 General.

-Installation UTM coordinates (give a reference point).

-Unifile diagram with all the components of the network link installation

-Planned operating system (daily, weekly, seasonal cycles, if applicable).

-Estimated unavailability rates for maintenance.

-Estimated unavailability rates for other causes.

-Maximum full load reactive (MVAr) generation at the point of connection to the network.

-Maximum technical minimum reactive (MVAr) generation at the point of network connection.

-Maximum load-reactive (MVAr) absorption at the point of connection to the network.

-Maximum technical minimum reactive (MVAr) absorption at the network connection point.

1.4.1.1.2.2 Additional general for hydraulic power stations of more than 1 MW.

-Hydraulic subsystem schema.

-The associated reservoir.

-Hydraulic Management Unit to which you belong, if any.

-Driving Channel/Pressure Gallery (SI/NO). If yes, length (s) and diameter (s).

-Deposit or charging chamber (SI/NO). If yes, volume.

-Forced Tuberia (SI/NO). If yes, length (s) and diameter (s).

-Number of groups.

-Nominal flow (m³/s).

-Nominal net high (m).

-Maximum turbination flow (m³/s).

-Minimum turbination flow (m³/s).

-Maximum gross high (m).

-Minimum gross (m).

-Maximum net high (m).

-Minimum net high (m).

-Losses in flow-based pipelines: Perdconduccio = f (Q2).

-Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

-For reversible or pumping groups:

-Nominal power.

-Nominal effective height (m).

-Nominal flow rate (m³/s).

-Maximum pump flow (m³/s).

-Minimum pumping flow (m³/s).

-Loss in aspiration and drive based on flow rate: Perdconduccio = f (Q2)

-Performance curves according to the pumped flow rate and the manometric height (alternative: power tables for different manometric heights and different flow rates for each manometric height).

-Output accumulation index (%), defined as the ratio of the electrical energy that can occur with the water accumulated by pumping and the energy consumed for its elevation.

1.4.1.1.2.3 Data for each generator.

-Nominal voltage (kV).

-Maximum generation voltage (kV).

-Minimum generation voltage (kV).

-Nominal speed.

-Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis in machine base (Xd, Xq, X'd, X'q, X'' d, and X'' q. Symbology as standard UNE-EN 60034-4).

-transient and subtransient time-short constants for both direct and transverse axis (s). (T' d, T' q, T '' d and T '' q. Symbology as standard UNE-EN 60034-4).

-Transient time and subtransient open circuit constants for both direct and transverse axis (s). (T' d0, T' q0, T '' d0, and T '' q0. Symbology as standard UNE-EN 60034-4).

-Inertia Constant (s) of the rotating assembly: electric machine, exciter and turbine.

-Unsaturated leakage reactance (p.u.) (Xl).

-Saturation of machine to voltage 1.0 p.u. (p.u.), as Figure 1.

-Saturation of machine to voltage 1.2 p.u. (p.u.), as Figure 1.

-P-Q capacity curves (operating limits).

-Main turbine data and primary regulatory equipment.

-Turbine characteristics: manufacturer and model.

-In case of self-regulation, indicate:

■ Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ...

■ Permanent statism:

or range of tuning.

or adjusted value.

or telemetry capability of the adjusted value.

■ Speed of power variation in MW/s, by frequency variation.

■ Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

■ Voluntary regulator dead band (mHz):

or range of tuning.

or adjusted value: confirm that it is zero.

or telemetry capability of the adjusted value.

■ Regulator characteristics: manufacturer, type of control (PID series compensator, resupply compensation using transient staticism, ...) and technology (hydraulic, electrohydraulic ...).

■ Dynamic compensations: a function of transfer of dynamic compensation (transient statism, series compensator, ...). The range of each parameter and its current value must be specified.

■ The turbine-speed regulator block scheme and the corresponding values of the parameters that are represented in the schemas. This information will be provided as follows:

or Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect developed by the OS.

In both cases, it must be accompanied by a validation report on the suitability of the model to represent the speed-turbine regulator, in accordance with the conditions set out in the document to the effect produced by the OS.

1.4.1.1.2.4 Data for each additional generator for hydraulic power stations over 1 MW.

-Type of turbine.

-Nominal power in turban (MW).

-Nominal flow (m³/s).

-Nominal net high (m).

-Net technical minimum, that is, in central bars (MW).

-Maximum turbination flow (m³/s).

-Minimum turbination flow (m³/s).

-Maximum gross high (m).

-Minimum gross (m).

-Maximum net high (m).

-Minimum net high (m).

-Losses in flow-based pipelines.

-Performance curves based on flow rate and net jump (alternative: power tables for different net jumps and different flow rates for each net jump).

-For reversible or pumping groups:

■ Type of pump.

■ Nominal power.

■ Nominal speed (rpm).

■ Nominal effective height (m).

■ Nominal flow rate (m³/s).

■ Maximum pump flow (m³/s).

■ Minimum pumping flow (m³/s).

■ Loss in aspiration and drive based on flow rate

■ Performance curves based on the pumped flow and the manometric height (alternative: power tables for different manometric heights and different flow rates for each manometric height).

1.4.1.1.3 Additional data in the case of connection to the transport network.

-Installation data at the network connection point.

-Physical diagram (general scheme at site) of the link installation.

-One-to-one detail diagram with all the component elements of the link installation from the different generation units to the point of connection to the network.

-General configuration of the installation, indicating in its case characteristics of coupling between elements (e.g. gas turbines, steam turbines and alternators), as well as modularity and operating flexibility.

-For generations: See consumer installations connected to the transport network.

-Report with maximum guaranteed harmonic distortion content, only in case there are wave control processes in the installation:

or through a forecast, as indicated in IEC 61000-3-6, of the voltage and intensity harmonics (magnitude and order of 2 to 50) and the harmonic distortion rate

or perform measurements at the point of connection, of the voltage and intensity harmonics (magnitude and order of 2 to 50) and of the harmonic distortion rate, at minimum periods of one week as indicated in IEC 61000-4-30.

• Unifilar installation protection scheme.

1.4.1.2 Secondary throttling data.

-Regulatory zone to which you belong.

-Detailed information of the connection of the system of regulation with the AGC: characteristics of the signal signal, processing of the signal, limits, ...

-Maximum and minimum active power of regulation in b.a. (MW) for different stable operating points, if applicable

-Limitations on upload and load drop on MW/min: adjustment range and slogan values for continuous ramp and step.

1.4.1.3 Data for programming, and tertiary regulation (in case of participation in technical dispatch).

-Minimum programming boot time

■ from synchronization to technical minimum (min)

■ from synchronization to full load (min)

-Minimum programming stop time (from full load to disconnection) (min).

-Maximum up-ramp of tertiary regulation (MW in 15 min).

-Top down ramp of tertiary regulation (MW in 15 min).

1.4.1.4 Data required for service replacement plans.

-SSAA power (except CCHH).

-Simplified schema and description of the SSAA power process in the following assumptions:

■ Normal.

■ Boot.

■ Other alternatives (Diesel/Battery/Otras).

-SSAA power supply.

-Auxiliary services consumption in b.a. for group stop, active power (MW)

-Auxiliary services consumption in b.a. for group stop, reactive power (MVAr)

-Consumption of auxiliary services in b.a. for boot, active power (MW) Specify different possibilities: Cold start/Hot start.

-Auxiliary services consumption in b.a. for startup, reactive power (MVAr) Specify different possibilities: Cold start/Hot start.

-Stand-alone startup capacity.

-Own media to energize the auxiliary services needed for startup:

■ Battery.

■ Diesel Group.

■ Other.

-Unifillar diagrams.

-Autonomy time (hours).

-Boot type:

■ By remote control.

■ Local operation (will indicate the hourly availability of personnel).

-The minimum guaranteed operating time continued at full load during the replacement process (minimum fuel reserves).

-Possibility of performing a certain number of consecutive starts in a given time (in case of possible shots during the replacement process): number of start and stop cycles, and duration of the cycle.

-In the case of CCHH: Minimum number of groups to operate in parallel

-Cascade-start capability of a set of groups.

-Reconnection of the group to the network (except CCHH).

-Minimum cold start time (since power is received in the SSAA until ready for synchronization).

-Minimum hot start time (since power is received in the SSAA until ready for synchronization).

-Maximum stop time for the boot to be hot.

■ Ability to remain stable after a disconnect from the outside network with sudden loss of full load, only feeding its own consumption. (Yes/No. Description).

■ Island operating capacity. Minimum market bag that is capable of feeding the plant in island situation.

-Sync conditions for coupling. Existing automatisms and adjustments (except CCHH).

-Other data (except CCHH).

■ Characteristics of the engines and loads of ancillary services and data on protections and adjustments, if any.

■ Dependence on non-fuel supply infrastructures for the replacement process.

1.4.1.5 Group transformer data

-Nominal power (MVA).

-Primary and secondary nominal voltage (kV).

-Connection group.

-Loss due to load (kW).

-Short circuit voltage (%).

-Homopolar impedance (% on machine base).

-Regulatory characteristics (winding with takes, no takes, maximum and minimum ratio).

1.4.1.6 Evacuation line data (if any).

• View observable network lines and cables.

1.4.1.7 Data from the Protections.

-Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) in the face of internal disturbances to the plant (yes/no). Indicate particularities, if any.

-Minimum frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

-Minimum voltage gels: settings.

-Short circuit protection scheme in the network-main transformer stretch.

-Central stability to short circuits in the network: critical disconnect time.

-Overfrequency protection. Adjustments.

-Disarrest for over-speed. Firing Value

1.4.1.7.1 Central Protections.

-Network short-circuit support protection: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with network protections.

-Overvoltage Relation: Settings.

-Sync conditions for coupling. Automatisms and adjustments.

1.4.1.7.2 Protections associated with the link installation.

-Unifilar installation protection scheme Telefiring against contingencies on the network.

-Teleshooting capacity (SI/NO).

-The tele-firing time since the signal is received (also indicate switch opening times).

-The telephoto logic and switches or selectors that it includes.

1.4.1.8 Main data for voltage control equipment for plants over 5 MW.

-For each group:

■ A brief description of the voltage regulator, which will include the name and type of the regulator.

■ Block scheme, and the corresponding values of the parameters that are represented in the schemes, of the voltage regulators-excitation and of the power stabiliser system (PSS), if they have this device. This information will be provided as follows:

or Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect developed by the OS.

In both cases, it must be accompanied by a validation report on the suitability of the model to represent the voltage regulator and the power stabiliser system (PSS), in accordance with the conditions set out in the document to the effect developed by the OS.

• In the case of generating groups and reversible groups that have the capacity to function as synchronous compensators, the technical operating requirements shall be indicated, and the time required for their entry into operation.

• The possibility, if any, of telemandar the groups should be indicated so that the excitation slogan and/or the takes of the output transformer of the group can be modified from the office of generation of the subject holder or installation representative, or from the appropriate control center.

1.4.2 Wind, photovoltaic and in general installations all production facilities whose technology does not employ a synchronous generator connected directly to the network.

1.4.2.1 Features of each installation.

-Name of the installation.

-Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

-Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 10 kV with influence over the network transport).

-Owner Enterprise:

■ Name.

■ NIF.

■ Address.

-Identification number in the RAIPRE.

-Special Regime Grant Date.

-On or off date (forecast, if any).

-Installation address: municipality, postal code, and province.

-Park polygonal UTM, orchard, etc.

-Distributor Company.

-Installed power: apparent gross (MVA) and net active (MW). The apparent power must include all of the installation's reactive compensation.

-Substation/park connection to the transport network (name, kV).

-Availability of primary regulation or speed regulation (SI/NO). If yes, please indicate:

■ Insensitivity of the regulator (mHz). It must not be greater than 10 mHz.

■ Regulator voluntary dead band (mHz): confirm that the adjusted value is zero.

-If you do not have your own primary regulation, provide documentation that accredits the service delivery to another generating unit, indicating:

■ Unit providing the service.

■ Insensitivity confirmation not exceeding 10 mHz.

■ Null voluntary dead band confirmation.

-Installation intended operation regime:

■ Hours of use (at full power) for annual and seasonal periods.

■ Active power curve depending on wind speed, including indication of maximum wind speeds for which wind turbines fail to provide power.

-Compliance with voltage recesses (yes/no) requirements.

-Data for each model of each generating unit (wind turbine, inverter, etc.):

■ Number of generating units of the same model.

■ Manufacturer and model.

■ Technology: Squirrel cage induction or asynchronous machine, variable-slip induction or asynchronous machine, doubly-fed induction or asynchronous machine, wind turbines with total power conversion (full converter), investors, etc. In case of other technologies not indicated, provide brief description.

■ Active power installed on each generating unit (kW).

■ The apparent installed power of each generating unit (kVA) including, if applicable, its internal reactive compensation.

■ reactive power curve depending on the active power considering, where appropriate, the internal reactive compensation of each generating unit.

■ A model will be provided for the installation which should describe its dynamic behaviour from the point of view of the electrical system to which it is connected, in the face of any disturbance in it. This information will be provided as follows:

or Through a model included in the list of dynamic models supported by the OS, and that will be provided by the OS itself,

or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect developed by the OS.

In both cases, a validation report of the suitability of the model shall be accompanied by the conditions set out in the document to the effect developed by the OS.

-Reactive compensation in bornas of each generating unit excluding, if applicable, internal compensation:

■ Static compensation and reactive power dynamics (nominal values in MVAr).

■ Possibility of regulation.

-Reactive compensation in bornas of the installation excluded, if any, the one associated with each generating unit:

■ Static compensation and/or total reactive power dynamics (nominal value in MVAr).

■ Possibility of regulation.

■ Condenser Batteries (yes/no).

or Total Power (MVAr).

or Number of steps.

or Type of control of the steps.

■ Continuous compensation or regulation systems based on power electronics (FACTS) (yes/no).

or Total Power Installed (MVAr).

1.4.2.2 Network connection transformer data.

-Enterprise or proprietary companies:

■ Name.

■ NIF.

■ Address.

-Nominal power (MVA).

-Primary and secondary nominal voltage (kV).

-Connection group.

-Loss due to load (kW).

-Short circuit voltage (%).

-Homopolar impedance (% on machine base).

-Regulatory characteristics (winding with takes, no takes, maximum and minimum ratio).

1.4.2.3 Network connection cable or line data.

• View observable network lines and cables.

1.4.2.4 Data from the Protections.

1.4.2.4.1 Production Installation Protections.

-Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) against internal disturbances to the installation (yes/no). Indicate particularities, if any.

-Minimum voltage Rele: indicate phases in which measures and adjustments.

-Overvoltage Relation: Settings.

-Park stability in the face of short circuits in the network: critical disconnect time.

-Minimum frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

-Overfrequency protection. Adjustments.

-Auto-replace automatic devices: Confirm that they do not exist or that they are disabled.

1.4.2.4.2 Protections associated with each generating unit

-Minimum voltage Rele: indicate phases in which measures and adjustments.

-Overvoltage Relation: Settings.

-Minimum frequency protection: settings and compliance with the procedure that the Safety Plans are set for.

-Overfrequency protection. Adjustments.

-Disarrest for over-speed, if any. Firing value.

1.4.2.4.3 Protections associated with the link installation

-Minimum voltage Rele: settings.

-Short circuit protection scheme in the network-main transformer stretch.

-Compliance with the General Protection Criteria.

1.4.2.5 Additional data for installations connected to the transport network

1.4.2.5.1 Features of each installation.

-Physical diagram (general scheme at site) of the link installation.

-Unifilar detail diagram of the power equipment from the different generation units to the point of connection to the network.

-Short circuit intensity contributed by the installation to a short circuit at the point of connection to the network.

-Report with maximum guaranteed harmonic distortion content:

■ well through an installation-level forecast, as indicated in IEC 61000-3-6, of the voltage and intensity harmonics (magnitude and order of 2 to 50) and the harmonic distortion rate

■ or perform measures at the level of installation of the voltage and intensity harmonics (magnitude and order of 2 to 50) and the harmonic distortion rate, in minimum periods of one week as indicated in IEC 61000-4-30.

-The voltage level (kV) of the internal connection network of the generating units.

-Unifilar protection and measurement scheme for the production installation and the binding installation.

1.4.2.5.2 Installation transformer data (if this is the network connection transformer, see paragraph 1.4.2.5.5).

-Nominal power (MVA).

-Primary and secondary nominal voltage (kV).

-Connection group.

-Loss due to load (kW).

-Short circuit voltage (%).

-Homopolar impedance (% on machine base).

-Regulation features (winding with sockets, number of takes, maximum and minimum ratio).

1.4.2.5.3 Data from the evacuation line of each park (if any) (if this is the line of connection to the transport network, see paragraph 1.4.2.5.6).

View observable network lines and cables.

1.4.2.5.4 Network connection transformer data.

View transport transformers.

1.4.2.5.6 Evacuation line data (if any).

View transport lines and cables.

1.4.2.5.7 Data from the Protections.

1.4.2.5.7.1 Park Protections.

-Sync conditions for coupling. Automatisms and adjustments.

1.4.2.5.7.2 Protections associated with the link installation.

-Short circuit protection scheme in the network-main transformer section. Compliance with General Protection Criteria.

-Network short-circuit support protection: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with network protections.

1.4.2.5.7.3 Telefiring against network contingencies.

-Teleshooting capacity (SI/NO).

-The tele-firing time since the signal is received (also indicate switch opening times).

-The telephoto logic and switches or selectors that it includes.

2. Transport Network

2.1 Substations.

-The name of the substation.

-Address: municipality, postal code, and province.

-On or off date (forecast, if any).

2.2 Parks.

-The name of the substation.

-Tension (kV).

-Park UTM coordinates (give a reference point).

-Configuration.

-Owner of each position.

-Owner of each bar.

-Maximum allowable short-circuit intensity of the various elements of the park.

-Face-to-face cutting power of switches.

-Uniform and measure protection schemes.

-On or off date (forecast, if any).

-Protections:

■ Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

■ Short circuit protection scheme. Critical time contemplated.

■ Protection of support against external circuits: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with the protection of other elements.

■ Unifilar protection and measurement scheme.

■ Minimum voltage gels: trigger logic and switches on which they operate.

2.3 Lines and cables.

-Line name.

-Line ends of the line.

-Circuit number and length in km.

-Owner or set of owners and participation in their case.

-On or off date (forecast, if any).

-Nominal operation and maximum service voltage of each circuit (and projected in case of variation) for each of the circuits or sections thereof with homogeneous characteristics.

-Direct sequence resistance (Ω).

-Direct sequence reactance (Ω).

-Direct sequence (μS) susceptance.

-Homopolar sequence resistance (Ω).

-Homopolar sequence reactance (Ω).

-Homopolar Sequence Susceptance (μS).

-Additional data for transport network lines and cables only, as such:

■ Seasonal values of:

or Nominal line transport capacity (MVA).

or limiting element.

or Driver's Permanent Thermal Limit (MVA).

■ Maximum driver operating temperature (0C).

■ Length in shared supports, if any (in a same ditch or gallery, if isolated cables are treated).

■ Setting up the line.

■ Conductor: Name/material/total section (mm²).

■ Land tables: Denomination/material/total section (mm²).

■ Setting up grounding (for isolated cables only): Type/length of sections.

■ Number of drivers per phase.

■ Protections:

or Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

or Short-Circuit Protection Scheme. Critical time contemplated.

o Protection of support for short-circuit external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

or Unifilar protection and measurement scheme.

or Network or telecoupling devices: existence and adjustments.

or Synchronism Gels: existence and settings. Break down, if necessary, between monitoring of reengagement and voluntary closure.

or Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

or Automatic Reorder Devices: Indicate if they exist and describe their behavior, if any.

or Rehook:

• Relatch position under normal operating conditions (not active/mono/mono + tri/tri).

• Extreme that throws tension in the three-phase reengagement.

• Synchronism monitoring in triphasic reengagement (SI/NO).

or Teleshot:

• Telefiring at voluntary opening (SI/NO).

• Switch opening (SI/NO).

2.4 Transformers.

Transformers that feed loads and those connected to non-observable networks are treated under the heading "Consumer installations".

-The name of the substation and park at the highest voltage level.

-Order number.

-Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

-Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 10 kV with influence over the network transport).

-Physical diagram (general scheme at site) of the link installation.

-Unifilar detail diagram of the power equipment of the network link installation.

-Owner or set of owners and participation in their case.

-On or off date (forecast, if any).

-Type of transformer: configuration (triphasic or bank), autotransformer/transformer, magnetic circuit (n. number of columns).

-Nominal power of each winding (MVA).

-Cooling type.

-Nominal voltage of each winding (kV).

-Maximum service voltage of each winding (kV).

-Connection group.

-Type of regulation in each winding (load or vacuum). Possibility of automatic regulation and its blocking to collapse.

-Number of takes in each winding and extension of takes (%). Number of the main shot (corresponding to the nominal voltage of the transformer), the usual intake (vacuum regulation) and the maximum intake. For generation transformers, in addition, numbers of the usual take (vacuum changer) or of the most frequent (shift-in-load-changer).

-Transform relationship between primary and secondary for each of the possible transformer or autotransformer takes.

-Losses on the transformer:

■ Losses due to load between each winding pair (kW).

■ Empty losses (kW).

■ Losses in auxiliary equipment (kW).

-Short circuit tension between each pair of windings in the main, maximum and minimum takes in their case (%). Main takeaway in generation transformers.

-Homopolare impedances between each winding and its neutral borne in the main, maximum and minimum takes in its case (% on a machine basis). Main takeaway in generation transformers.

-Additional data for transformers of the transport network and of the observable network, as such:

■ Protections:

or Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

or Short-Circuit Protection Scheme. Critical time contemplated.

o Protection of support for short-circuit external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

or Unifilar protection and measurement scheme.

■ Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

2.5 Active or reactive power control elements.

-The name of the substation and park in which it is located.

-Type (Reactance or Capacitor or Static; information will be replicated in case of elements with inductive and capacitive compensation possibilities).

-Order number.

-Nominal voltage (kV).

-Nominal power (MVAr).

-Connection Tension (kV).

-Situation (transformer bars or tertiary).

-Owner.

-Iron losses (kW).

-Copper losses (kW).

-Additional total included losses (kW)

-Connection type.

-Number of steps.

-For each step:

■ Block No.

■ Nominal power of each block (MVAr).

-On or off date (forecast, if any).

-In the case of static compensation: the characteristics of the transformer of connection to the grid, nominal voltage of the compensating equipment, characteristic V/I of the compensation system, and the block scheme of the voltage regulator with the corresponding values of the parameters that are represented in the schema. This information will be provided as follows:

■ Through a model included in the list of dynamic models supported by the OS, and which will be provided by the OS itself,

■ or through a model not included in the above list provided that it complies with the characteristics and conditions set out in document to the effect developed by the OS.

In both cases, it must be accompanied by a validation report on the suitability of the model to represent the FACTS device, in accordance with the conditions set out in the document to the effect developed by the OS.

-In the case of active power control elements, the associated data will be provided based on the corresponding configuration.

-Protections:

■ Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

■ Short circuit protection scheme. Critical time contemplated.

■ Protection of support against external circuits: indicate relay type (s), adjustment criteria and values, and coordination status (SI/NO) with the protection of other elements.

■ Unifilar protection and measurement scheme.

■ Minimum voltage gels: trigger logic and switches on which they operate.

■ Overvoltage protection: existence and settings.

■ Automatic replacement devices: Indicate if they exist and describe their behavior, if any.

3. Consumer installations connected to the transport network

As far as processors are concerned, the present epigraph is applicable to those who feed loads and those connected to unobservable networks. The observable network transformers are dealt with in the Network Observable chapter.

-The name of the installation.

-Order number.

-Geographical location (requests for access to the transport network or distribution network with influence on the transport network): plans (minimum detail of particular situation E 1:50,000 and general situation E 1:200,000) and significant distances (to lines and knots of connection to the network).

-Unifilar diagram with all the components of the network link installation (requests for access to the transport network or for voltage distribution networks exceeding 10 kV with influence over the network transport).

-Unifilar detail diagram of the power equipment of the network link installation.

-Owner.

-Home of the installation. Municipality, postal code and province.

-On or off date (forecast, if any).

-Load type (distribution network, auxiliary services, consumer).

-Substation and network connection park (name, kV).

-General configuration of the installation, modularity, and operating flexibility.

-Estimated unavailability rates for maintenance and other causes (annual and seasonal indices if applicable).

-Planned operating system. Consumption forecast (MW, MVAr) at the point of network connection in significant time and seasonal situations, as well as annual estimated energy.

-A network connection transformer.

-Transfter type: configuration (triphasic or bank), autotransformer /transformer, magnetic circuit (n. number of columns)

-Nominal power of each winding (MVA).

-Nominal and maximum service voltage of each winding (kV).

-Connection group.

-Type of regulation in each winding (load or vacuum). Possibility of automatic regulation and its blocking to collapse.

-Loss due to load (kW).

-Short circuit voltage (%).

-Homopolar impedance (% on machine base).

-Main characteristics of the load composition (if applicable):

■ Proportion of induction motors (% on total load).

■ Of the rest of the load that does not correspond to induction engines:

or Equivalent to constant power load (%).

or Equivalent to constant impedance load (% on).

or Equivalent to constant intensity load (%).

-Tension control:

■ Additional information for arc furnaces in alternating current:

■ High voltage (kV).

■ Medium Tension (kV).

■ Low voltage (kV).

■ oven power (MVA).

■ Reactive compensation: type, rated power (MVAr) and connection drilling.

■ Short circuit and power impedance of MT-BT transformers.

■ Series reactance impedance, if any.

■ The impedance of the low voltage cables, the electrode and any other additional that can exist from the point of connection to the network to the electrode.

■ Cos φ of the previous impedances.

-Additional information for arc furnaces in continuous stream:

■ High voltage (kV).

■ Medium Tension (kV).

■ Low voltage (kV).

■ rectification power (MW).

■ Number of pulses.

■ Reactive compensation: type, rated power (MVAr) and connection drilling.

■ Short circuit and power impedance of MT-BT transformers.

■ The impedance of the low voltage cables, the electrode and any other additional that can exist from the point of connection to the network to the electrode.

■ Cos φ of the impedance of low voltage cables.

■ Harmonic filters: order of harmonics to which each filter and unit power (MVAr) is tuned.

• Line or cable connection to the RdT (if applicable):

■ Number of circuits and length in km.

■ Owner or set of owners and participation in their case.

■ Date of entry into service or low (forecast, if any).

■ Nominal performance and maximum service voltage of each circuit (and projected in case of variation) for each of the circuits or sections thereof with homogeneous characteristics.

■ Direct sequence resistance (Ω).

■ Direct sequence reactance (Ω).

■ Direct Sequence Susceptance (μS).

■ Homopolar sequence resistance (Ω).

■ Homopolar sequence reactance (Ω).

■ Homopolar sequence susceptance (μS).

■ Protections:

or Compliance with the General Protection Criteria (in accordance with the procedure for establishing the General Protection Criteria). Indicate particularities, if any.

or Short-Circuit Protection Scheme. Critical time contemplated.

o Protection of support for short-circuit external circuits: indicate relay type (s), criteria and adjustment values and coordination status (SI/NO) with the protections of other elements.

or Unifilar protection and measurement scheme.

or Minimum voltage gels: trigger logic and switches on which they operate.

or Overvoltage protection: existence and settings.

or Frequency Relay Features and Tuning:

or Frequency: adjustment range, stagger, and adjustment value (Hz).

or Timing: Adjustment Range and Adjustment Value (s).

or Reorder mechanism (SI/NO). If yes, confirm your non-enablement.

or Minimum and maximum loads disconnected by the relay (MW).

o Identification of the switch on which the relay acts.

or Automatic reorder devices not associated with the frequency relay: Indicate if they exist and describe their behavior, if any.

4. Observable Network

4.1 Substations.

-The name of the substation.

-Address: municipality, postal code, and province.

-On or off date (forecast, if any).

4.2 Parks.

-The name of the substation.

-Tension (kV).

-Configuration.

-Owner of each position.

-Owner of each bar.

-On or off date (forecast, if any).

4.3 Lines and cables.

-Line name.

-Line ends of the line.

-Circuit number and length in km.

-Owner or set of owners and participation in their case.

-On or off date (forecast, if any).

-Direct sequence resistance (Ω).

-Direct sequence reactance (Ω).

-Direct sequence (μS) susceptance.

-Homopolar sequence resistance (Ω).

-Homopolar sequence reactance (Ω).

-Homopolar Sequence Susceptance (μS).

4.4 Transformers.

-Transforms connected to the transport network are dealt with in the "Transport Network" chapter.

-Block scheme, and the corresponding values of the parameters that are represented in the schemes, of the voltage-excitedess regulators and the power stabilizer system (PSS), if they have this device. This information will be provided as follows:

-Or through a model not included in the above list provided it meets the characteristics and conditions set out in document to the effect elaborated by the OS.

-In both cases it must be accompanied by a validation report on the suitability of the model to represent the voltage regulator and the power stabiliser system (PSS), in accordance with the conditions set out in the document to the effect developed by the OS.

4.5 Reactive power control elements.

-This item is applicable to the elements directly connected to knots of the observable network.

-The name of the substation and park in which it is located.

-Type (Reactance or Capacitor or Static).

-Order number.

-Owner.

-On or off date (forecast if applicable).

-Nominal voltage (kV).

-Nominal power (MVAr).

ANNEX II

Information to be sent to the OS in real time

1. Transport network and observable network

1.1 Switches.

Senalizations

Switch position.

1.2 Sectors.

Senalizations

Position of the dryers.

1.3 Lines and cables.

Measures

Active Power (MW).

reactive power (MVAr).

Line Voltage.

1.4 Transformers (includes transport, generation and consumption), reactances and capacitors.

Senalizations

Switch position.

Position of the dryers.

Automatic voltage control (transformers only).

Measures

The primary active power of transformer (MW).

Transformer primary reactive power (MVAr).

Transformer secondary active power (MW).

Transformer Secondary Reactive Power (MVAr).

Transformer tertiary active power (MW).

Transformer tertiary reactive power (MVAr).

Take the regulator into load (transformers only).

Empty regulator position (if it exists and only transformers).

Reactive Power in Reactances (MVAr).

1.5 Bar Coupling.

Senalizations

Switch position.

Position of the dryers.

Measures

Active Power (MW).

reactive power (MVAr).

1.6 Barras.

Measures

Tension per bar section (kV).

Frequency metric on selected selected bars (Hz).

1.7 Thermal groups and hydraulic groups with regulatory capacity.

• Senalizations

• Local/remote group regulation status.

• Type of regulation, control/non-control.

1.8 Thermal groups in ordinary regime.

• Senalizations

• Position of the group switches.

• Measures

Active power on the machine transformer (MW).

High-reactive power of the machine transformer (MVAr).

Low active power of the machine transformer (MW).

Low reactive power of the machine transformer (MVAr).

Generation Voltage.

1.9 Hydraulic groups in ordinary regime.

Senalizations

Position of the group switches.

Measures

Active power on the machine transformer (MW).

High-reactive power of the machine transformer (MVAr).

Central Bar Voltage Measurements (kV).

1.10 Pure pumping groups.

• Senalizations

• Position of the group switches.

• Measures

• Active power on the machine transformer (MW) high.

• High-reactive power of the machine transformer (MVAr).

• Central bar tension (kV) measures.

• Cacks of reservoirs.

1.11 Generation facilities under special regime to which section 7.1 applies.

Senalizations

Connection status of the installation with the distribution or transport network of each of the power generation units greater than 1 MW.

Measures

Active power produced (MW) for each of the power generation units exceeding 1 MW and the pooled active power of the power generation units equal to or less than 1 MW.

Reactive power produced/absorbed (MVAr) for each of the power generation units exceeding 1 MW and the reactivated power generation units of power generation units equal to or less than 1 MW.

Central bar voltage measurement (kV) for power generation units greater than 1 MW.

In the case of wind farms: wind speed (intensity and direction) (m/s and sexagesimal degrees) and temperature (° C).

1.12 Synchronous compensators.

Senalizations

Connection status.

Measures

reactive power (MVAr).

Voltage (kV).

ANNEX III

Incident reports

The contents to be included in the report on an incident are those that are applicable to the following:

a. The date and time of the incident.

b. Transportation facilities and/or electrical system elements directly involved in the incident (and not only affected by the incident), duration of loss of service (with indication of whether it is data or forecast).

c. Direct market impact: location, type and number of customers affected, demand (in MW) interrupted, energy not supplied (in MWh) and duration of the interruption (with indication of whether it is data or forecast). Information shall also be given as detailed as possible of the replacement of the service, indicating the powers and the interruption times for each stage of the replacement. If there is a border point, the above information will be specified for each of the border points.

d. Generation: group or groups affected, generation interrupted (MW) and duration of the interruption (with indication of whether it is data or forecast). Damage reported.

e. Description of the incidence (chronology of events, action of protection systems and automatisms, ...).