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 of State Energy the market rules and operating procedures of an instrumental and technical nature 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 organised and regulated, provided, in Article 31, that the system operator may propose for approval by the Ministry of Industry Tourism and Trade the technical and instrumental operating procedures necessary to carry out the proper technical management of the system, who will resolve prior report of the National Energy Commission.

Royal Decree 661/2007, of 25 May, which regulates the activity of electricity production under special arrangements, provides that the holders of special rate arrangements for electricity will have to participate in the market directly or through a representative who may not be the distributor, according to a transitional period that is developed in three phases.

On the other hand, it also establishes new conditions for the participation in the market of the special regime, among them the relative cost settlement of the deviations, exemption from the cost of detours for certain facilities, settlement of the tariff by a method of differences with market settlement, settlement of premiums by a reference method at a market price, participation of the special scheme in system adjustment services, Information exchanges between representatives, Operator of the Iberian market, Polo Español, Operator of the National Energy System and Commission and complete separation of the distributor's liquidation between the energy for consumption at tariff and the energy for special regime in tariff with representative distributor.

The incorporation into the market of a large number of special regime facilities and the new conditions for settlement and participation requires a review of the operating procedures to develop in detail. established in the aforementioned Royal Decree 661/2007, which was collected at the 11th Additional Disposition of Royal Decree 871/2007 of 29 June 2007, for which the electricity charges are adjusted as from 1 July 2007.

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 system operating procedures P.O. 1.6, P.O. 3.1, P.O. 3.2, P.O. 3.3, P.O. 3.7, P.O. 7.2, P.O. 7.3, and P.O. 9,

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

First. -Approve the procedures for the operation of the electrical system P.O. 1.6: "Establishment of the security plans for the operation of the system", P.O. 3.1: "Programming of the generation", P.O. 3.2: " Resolution of technical restrictions ", P.O. 3.3:" Management of generation-consumption deviations ", P.O. 3.7:" Programming of generation of non-manageable renewable sources ", P.O. 7.2:" Secondary Regulation ", P.O. 7.3:" Tertiary Regulation "and P.O. 9:" Information exchanged by the System Operator ", which are inserted below.

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

Third. From the date on which this resolution takes effect, the following procedures for the operation of the electrical system are without effect:

P. O. 1.6: "Establishment of the security plans for the operation of the system", approved by Resolution of the Secretariat of State of Energy and Mineral Resources of 30 July 1998.

P. O. 3.1: "Programming of the Generation", adopted by Resolution of the General Secretariat of Energy of 26 June 2007.

P. O. 3.2: "Resolution of technical restrictions", adopted by Resolution of the General Secretariat of Energy of 26 June 2007.

P. O. 3.3: "Management of Diversion Generation-consumption", adopted by Resolution of the General Secretariat of Energy of 24 May 2006.

P. O. 3.7: "Programming of the generation of non-manageable renewable origin", approved by Resolution of the General Secretariat of Energy of 4 October 2006.

P. O. 7.2: "secondary regulation", adopted by Resolution of the General Secretariat of Energy of 24 May 2006.

P. O. 7.3: "Tertiary Regulation", adopted by Resolution of the General Secretariat of Energy of 24 May 2006.

P. O. 9: "Information exchanged by the System Operator", approved by Resolution of the General Secretariat of Energy of 16 October 2006.

Madrid, May 18, 2009. -Secretary of State for Energy, Pedro Luis Marin Uribe.

INDEX

P. O. 1.6: "Setting up security plans for system operation".

P. Or 3.1: "Generation programming".

P. O. 3.2: "Resolution of technical restrictions".

P. O. 3.3: "Management of consumption-consumption deviations".

P. O. 3.7: "Programming of non-manageable renewable source generation".

P. O. 7.2: "Secondary Regulation".

P. O. 7.3: "Tertiary Regulation".

P. O. 9: "Information exchanged by the system operator".

P. O. 1.6: "Setting up security plans for system operation"

1. Object

The purpose of this procedure is to define the plans to be set to ensure the safe and reliable operation of the system and to perform service replenishment after severe incidents.

2. Scope of application

This procedure applies to:

The system operator (OS).

OS-owned network facilities owned by the OS (RG).

Qualified distributors and consumers connected to the RG.

The companies that own generators connected to the RG and, as regards the plans for the removal of loads for minimum frequency and plans for the disconnection of generation by maximum frequency, to all installations of generation coupled to the Peninsular Electrical System, regardless of their power or connection point.

3. Setting the security plans

The OS will have to establish, with the collaboration of the owners of the affected facilities, the plans of action that will allow to face, in a systematic and coherent way, to the different situations that can be presented on the system operation.

Action plans, based on the objective pursued, are classified into: Safeguard Plans, Emergency Plans, and Service Reposition Plans.

3.1 Safeguard Plans. -The OS will establish Safeguard Plans in all cases where it is necessary to prevent the triggering of incidents that may have a noticeable impact on the supply or on the generating groups.

The need to establish Safeguard Plans will be based on the analysis of the contingencies referred to in the Security Criteria of the operation of the system (P.O. 1.1) and the assessment of the impact they could have. on the system.

In these Safeguards Plans will identify the post-contingency corrective actions that operators should take to return the system to the normal operating condition. They shall also establish the preventive actions to be taken a priori, in cases where the impact may be serious for the system and any post-contingency corrective actions may not be effective at a time. reasonably short (if required, for example, the connection of a new thermal group in the zone).

3.2 Emergency Plans. -The goal of the Emergency Plans is to minimize the scope and extent of the incidents, once these have occurred.

The OS will establish the corresponding Emergency Plans that will be able to include both the performance of automatisms and the adoption of specific measures of operation.

Among the first ones, the following can be highlighted:

Generation facility teleshooting plans:

The OS will establish plans for the telefiring of generation facilities in those areas of surplus power where certain contingencies affecting interconnection axes with other areas may cause significant overloads on the remaining interconnection axes, or the loss of stability of the groups in that area.

The final decision regarding the installation of the telefiring of generation facilities is in the hands of the owners of these facilities. In any event, both the costs arising from the installation of the tele-shot and, where appropriate, the possible implications that the installation of the generation installation would have had its non-installation will be assumed by the owners of These installations.

Minimum frequency load shedding plans:

The OS will set the burden-shedding plans necessary for cases where, for a very severe incidence, the balance between generation and demand of the system cannot be restored by the actions of planned control.

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 load-off plans will set a tiered ballast, first disconnecting the pumping groups, and disengaging, at lower frequency values, sets of non-critical preselected loads.

This disconnect will be done according to the following steps, represented by the frequency value in which it occurs and the percentage of load that is unburdened:

49.5 Hz: 50% of the pumping groups at each site.

49.3 Hz: 50% remaining of the pumping groups at each site.

49 Hz: 15% of the actual total system load.

48.7 Hz: 15% of the actual total system load.

48.4 Hz: 10% of the actual total system load.

48.0 Hz: 10% of the actual total system load.

In no case will the automatic reconnection of the load be admissible. Such reconnection will be done by following the instructions in the OS.

The minimum frequency protection of generation facilities must be coordinated with the load-shedding system, so they can only be decouple from the network if the frequency falls below 48 Hz, timed with at least 3 seconds.

Analogously the OS will establish specific measures of operation with the aim of minimizing the scope and extent of the incidents. These measures include the following:

Generation redispatches.

Interruptibility System application.

Modification or cancellation of international exchange programs.

Generation disconnect plans for maximum frequency:

The OS will set the generation disconnect plans required for cases where, for a very severe incidence, the balance between the generation and the system demand cannot be reset by the actions -planned control.

These plans will be based on the performance of an automatic system of staggered disconnection of generation for maximum frequency, in order to achieve a controlled disconnection of the generation that allows to recover the balance between generation and demand.

In order to recover system controllability and the predictability of your behavior in a situation where it is out of balance, the unmanageable generation of the installations of installed power equal to or greater than 10 MW according to the following steps, without any timing:

50.5 Hz: 5% of non-manageable generation facilities.

50.6 Hz: 10% of non-manageable generation facilities.

50.7 Hz: 15% of non-manageable generation facilities.

50.8 Hz: 20% of non-manageable generation facilities.

50.9 Hz: 25% of non-manageable generation facilities.

51 Hz: 25% of non-manageable generation facilities.

The OS will determine the facilities to be disconnected at each step.

In no case will these generation installations be automatically reconnected. Your reconnection will be done by following the instructions received from the OS through your Control Centers.

All non-manageable power generation installations of less than 10 MW will disconnect with 51 Hz and a timing of 200 ms. Their reconnection shall only be performed when the frequency reaches a value less than or equal to 50 Hz.

Manageable special regime generation facilities shall be disconnected when the frequency exceeds the value of 51 Hz, and the ordinary system production facilities shall not disconnect as long as the frequency does not exceed 51.5 Hz.

3.3 Service replenishment Plans. -Reorder Plans aim to return the electrical system to the normal operating state after severe incidents that have caused market outages.

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.

The OS will develop and keep updated the electrical system's Reposition Plans, which must be known and applied, if any, by the operators of the control centers involved. The OS will also be responsible for the coordination of the service replacement drills taking place.

In the event of a zonal or national incident, the control centers of the different producers, distributors and carriers will proceed to the rapid replacement of the service, according to the indications established in the corresponding Replenishment Plans and under the direction of the OS.

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).

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

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, which incorporates the modifications made to the PDBF for the resolution of the technical restrictions identified in application of the security criteria and for the subsequent generation-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 secondary regulation reserve 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). -It is 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 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 operating procedures by which the resolution of the technical restrictions and the management of the services of adjustment of the system.

4.7 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, thus 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.

4.8 Closing Programme (P48RENER). -It is the programme which is established at the end of the daily programming horizon and which contains the programmes resulting from the daily market and the various sessions of the intraday market, as well as the modifications of the programmes associated with the processes of resolution of technical restrictions and the participation of the different units in, the services of regulation-power of the system and in the process of management of Generation-consumption deviations.

4.9 Nomination of programs corresponding to the execution of bilateral contracts with physical delivery. -Nominations of the energy programs corresponding to the execution of bilateral contracts with physical delivery will be made by the seller and by the buyer, directly or indirectly, to the System Operator:

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 nominated subject is authorised for a bilateral contract with physical delivery, the latter may only be the subject of indirect nomination.

The system of indirect nomination shall, among other cases, apply for the nomination of bilateral contracts with physical delivery arising from the exercise of the options awarded in the Primary Energy Emissions Auctions. (SEP), where it is determined by Ministerial Resolution that the exercise of the options is by physical delivery. In this case, for the purposes of the indirect nomination of energy programmes, it is considered that the Aggregate Entity of the Primary Emission Auctions (EASEP) is part of the bilateral contracts with physical delivery (CBEP) according to the arrangements to be established between this entity and the SM authorised to participate in the Primary Emission Auctions.

In addition, the indirect nomination system may also be used for other bilateral contracts with physical delivery, provided that the SM also complies with all prior authorization communication requirements. established for these purposes.

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.

The nomination of bilateral contracts in the area of the Iberian Market between a UPG located in the Portuguese electrical system and a UPG located in the Spanish electricity system will be realized only through the system of indirect nomination and in use of the physical rights of capacity that the SM performing the nomination is assigned to.

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.

5.2 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 business days before the first day of each month, the entity with aggregator function in the primary energy emission auctions (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, 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.

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 in its information system the corresponding 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 those energy purchase options, for the execution of the process Nomination of post-exercise programs for those 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.

5.3 Nomination of bilateral CBEP contracts associated with the exercise of the energy purchase options of the primary emission auctions. -The OS nomination of the bilateral CBEP contracts associated with the exercise of the Energy purchase options after the primary energy auctions shall be carried out by EASEP, under the principle of indirect nomination, before 8:45 h of day D-1, in accordance with the agreements established between EASEP, the SM vendors and the SM buyers of energy purchase options derived 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.

5.4 Integration of bilateral contracts signed by distributors or dealers of last resort within the framework of the CESUR auctions, for the supply at tariff or supply of last resort in the territory peninsular.

5.5 Nomination of bilateral contracts signed by distributors or dealers of last resort derived from the CESUR auctions (CBCESUR). -After the completion of each auction, once it has been approved by the NEC, and at a notice of no less than six working days in respect of the first day of delivery of the energy allocated at the auction, the distribution or marketing companies of last resort participating in the CESUR auctions, or, where corresponds to the managing body of the auction of bilateral contracts CESUR (EGSED), to OS:

The relationship of the SM to which the sale of energy for the supply by bilateral contracting has been awarded to the distributors or marketers of last resort, being used for this identification of the corresponding Energy Identification Code (EIC) codes

The hourly energy value associated with each partner SM vendor-vendor or SM last-resource marketer in each programming period of the energy delivery period covered by that auction (in case of Only the product of type base load is auctioned, a single value of hourly energy associated to each partner SM will be communicated-distributor or SM sales-marketer of last resort for the entire period of delivery of energy covered by such auction).

The OS will make available to the SM affections to the CBCESUR (and/or the entity that, if necessary, act on behalf of the SM distributor or marketer of last resort as responsible for the management of the billing and the liquidation of the guarantees associated with these contracts), with respect to the criteria of confidentiality established and on a provisional basis, both the structural information of the CBCESUR, and the value of the hourly energy, for each time period programming covered by that auction, (in case only the product of type cargo is auctioned basis, a single hourly energy value is reported associated with each partner SM vendor-distributor or SM vendor-marketer of last resort for each of the energy delivery periods covered by that auction).

In order for the OS to make this information available to the entities that, if any, act on behalf of the SM distributors or marketers of last resort as responsible for the management of the billing and the settlement of the guarantees associated with these contracts, the SM distributors or traders of last resort must have previously communicated to the OS the existence of the corresponding agreements to be established between them and these entities.

CBCESUR shall have a maximum power value equal to the maximum value communicated by the distribution or marketing undertaking of last resort or where appropriate by the managing body of the bilateral contract auction CESUR (EGSED) to the OS for each partner distributed-SM seller or marketer of last resort-SM seller and will have validity during the period communicated by the distributor or marketing company of last resort or when it corresponds to the entity managing the auction of bilateral contracts CESUR (EGSED), with the possibility of these contracts be carried over, or be modified in its maximum capacity by the successive communications of the distribution or marketing undertaking of last resort or where it corresponds to the managing body of the auction of bilateral contracts CESUR (EGSED), keeping the contract execution number unchanged.

These CBCESUR will use Generic Programming Units (UPGCESUR) for the SM vendor, units that will have been previously released, for such purposes, in the system operator information system. The discharge of these UPGCESUR must be requested by the OS by the SM according to the established in this respect in the operating procedures, and will be communicated to the OM by means and deadlines established.

The OS will validate that the information received from the distribution or marketing company of last resort or when it corresponds to the managing body of the auction of bilateral contracts CESUR (EGSED) refers to SM that have the corresponding UPGCESUR for the period of validity to which the communication refers. Otherwise, the communication sent by the distribution or marketing company of last resort or when it corresponds to the managing body of the auction of bilateral contracts CESUR (EGSED) shall be rejected.

In case of an identification of any modification in relation to the information corresponding to the CBCESUR, either derived from the cancellation of CBCESUR, or associated with the execution of bilateral transfers of CBCESUR, in the case of the rules in force provide for their existence, the SM affections to the CBCESUR (or the entity which, where appropriate, acts on behalf of the SM distributor or marketer of last resort as responsible for the management of the invoicing and the liquidation of the guarantees associated with these contracts) must be communicated to the OS at an advance of not less than three working days on the first day of delivery of the energy of the period referred to in that amendment.

Once the deadline for validation of this information has been completed, and if any discrepancies are resolved, the OS will make available to the SM, with respect to the criteria of confidentiality established and definitive, both the structural information of the valid CBCESUR, and the hourly energy value for each programming period of the period covered by the said auction (in case only the product of the base load type is auctioned, communicate a single hourly energy value associated with each SM partner vendor-vendor or SM Last resort-marketer for the entire power delivery period covered by that auction.)

This information will be considered by the OS as the nomination of programs of the bilateral contracts derived from the term auctions for the bilateral contracting of the Distributor Companies or the Marketing of Last Resource (CBCESUR) carried out by the distribution or marketing companies of last resort (or by the entity that, where appropriate, acts on behalf of the SM Distributor or Marketer as responsible for the management of the billing and the liquidation of the guarantees associated with these contracts) and by the SM vendors participating in these contracts auctions for each programming period of the period covered by the corresponding auction.

If, after the completion of the final nomination of CBCESUR, the SM distributor or marketer of last resort (or the entity that, if applicable, act on behalf of the SM distributor or marketer of last resort as responsible for the management of the billing and the liquidation of the guarantees associated with these contracts) inform the OS the cancellation of a CBCESUR contract with an SM, the OS, within a maximum period of 3 working days, will give the corresponding CBCESUR. This cancellation will affect the remaining term of the CBCESUR.

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 OM 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.

5.6 explicit daily auction 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 authorizations for the scheduling and the results of the allocation will be the possible capacity reductions due to the identification of a congestion situation in the pipeline.

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 capacity awarded in the explicit annual and/or monthly auctions carried out jointly by the operators of both electrical systems for the allocation of swap capacity in such interconnection.

The lack of notification of the use of the capacity awarded by a market subject within the time limits shall be construed as a waiver of the physical rights of previously assigned capacity. This process will be parallel to the process of notification of use to the operator of the French electrical system that will be performed in the neighboring electrical system.

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

The communication by the SM that has the physical rights of the execution of one or more bilateral contracts between the Energy Sales Programming Unit for import shall be considered to be a notification of use. (or the Power Purchase Programming Unit for export) and Generic Programming Units or Physical Programming Units.

Once the notifications of use of the assigned capacities in annual and monthly horizons are exchanged, the OS will apply the "used or lost" rule, to the assigned capacities in annual and/or monthly horizon, the use of which has not been correctly reported. 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, communicating below the results of the same to each and every one of the subjects that have been awarded capacity.

The OS will make available to the SM the authorizations for the programming associated with the capacity obtained in that explicit daily auction, indicating the authorized exchange capacity for each subject in each direction flow.

After the daily explicit auction, the OS will make available to the OM the total exchange capacity value assigned in the explicit daily auction for each subject in each flow direction, to the object that this information is for the acceptance of offers to the daily market.

5.7 Transfer of the program from the Generic Programming Units to the PDBF. -The net balance of all transactions associated with the generic programming units (UPG/UPGCESUR) 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 obligation established in the Transitional Provision second of Order ITC 400/2007, 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 programme of the UPG/UPGCESUR through bilateral contracts, the SM will have to be discharged and in force the bilateral contracts that are necessary, both between two units of generic programming, such as between each UPG/UPGCESUR 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.

5.8 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 the Market Subjects (SM) and the Market operator (OM), as indicated in the operating procedure setting out the exchange of information with the OS, the information concerning the forecast demand, the network situation planned for the following day, and for those borders in which there is no coordinated mechanism for capacity management 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.

5.9 Daily Operating Base Program (PDBF). -The OS establishes 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.

5.10 Nominations of bilateral contracts with physical delivery prior to the daily market. -At a time of not less than six working days from the first day of delivery of the allocated energy at each CESUR auction for the supply by bilateral procurement to distributors or marketers of last resort:

The OS will receive from the distribution or marketing company of last resources or when corresponding from the EGSED the corresponding information of the programs of the CBCESUR, bilateral contracts with established physical delivery between the Generic Programming Unit (UPGCESUR) of each vendor SM and the Power Acquisition Programming Unit of each distributor or marketer of last resort. These programs, once validated by the System Operator, and after the deadlines for the submission of possible discrepancies by the corresponding SM established in this same procedure, will stop in a firm nomination of programs.

Not less than 20:30 in advance of day D-2:

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

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 in 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 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 and CBCESUR, 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.

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

International bilateral contracts with physical delivery on 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 awarded 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 in the explicit auctions in the Portugal-Spain interconnection carried out jointly by the operators of both electrical systems, once they are auctions have come into operation.

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.

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

5.11 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 regarding the nomination of bilateral contracts with physical delivery:

Bilateral contracts with physical delivery in the Portugal-Spain interconnection arising from the use of physical capacity rights acquired in the explicit coordinated auctions between the two OS.

Also, before 09:45 hours, the OS will make available to the OM the following information regarding the nomination of bilateral contracts with physical delivery:

The information corresponding to the nominations of bilateral contracts with physical delivery of type CBEP and CBCESUR.

International bilateral contracts with physical delivery on interconnections where there is no coordinated capacity allocation procedure.

Bilateral contracts with physical delivery in the France-Spain interconnection arising from the use of the physical rights of capacity acquired at the annual and/or monthly auctions.

International bilateral contracts with physical delivery in the France-Spain interconnection arising from the use of the physical rights of capacity acquired in the daily auction that have communicated the bilateral contract to the OS with prior to the daily market.

Information regarding the execution of domestic bilateral contracts with physical delivery that have chosen the pre-market firm nomination option.

5.12 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 concerning 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.

5.13 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 hiring 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, two UPGCESURs 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).

5.14 Communication of PU 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 corresponding to 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.

5.15 Elaboration and publication of the PDBF program. -The OS will verify the coherence of the nominations of programs carried out, directly or indirectly, by the market participants and the information concerning the programs of contracted energy in the daily market, received from the OM.

If, as a result of this verification, any disparity has been 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, 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 each day, the OS will make available to all market subjects, and of the OM, the daily operating base program (PDBF) of the programming units of the Spanish electrical system for the next day's programming.

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

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 units, will apply a security analysis on the daily operating base programme (PDBF) to identify potential technical constraints and their possible solutions by selecting those which, by resolving the restriction with an appropriate margin of safety, They involve a 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.

Once the identified technical constraints have been resolved, the OS will proceed to make the necessary additional program modifications to obtain a balanced program in generation and demand, respecting the limitations of program established for security 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.

5.17 explicit intra-day subasts of the exchange capacity in the France-Spain interconnection.

5.18 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 regarding the international exchange programs in the 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 systems electrical.

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.

5.19 Second Intraday Auction of Capacity. -Once the PHF corresponding to the fifth session of the Spanish production market, the operators of the French and Spanish electric systems will exchange, between other information on international exchange programmes in the interconnection between France and Spain, which have been nominated within the time limits set by the market participants using physical capacity rights 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 at the sixth session of the intraday market.

5.20 Secondary Regulatory Reserve Requirements. -Each day, the OS will establish the secondary 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 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.

5.21 Secondary Regulatory Reserve Allowance. -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.

5.22 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.

5.23 Tertiary Regulation Offers. -Before 23:00 hours of D-1 day, the SM will have to present offers of all the reserve of tertiary regulation 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 will make available to the OM the information regarding the authorizations for the programming associated with the total authorized exchange capacity for each subject in each direction the flow, established after the explicit intra-day auction of capacity in the France-Spain interconnection applicable to that session of the IM, in order to ensure that this information is taken into account in the process of accepting tenders for that session of the ME.

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).

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 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, 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 repurchases power in the IM:

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

2. While respecting the management of point 1, the energy of the programming units shall be reduced to a value equal to zero or up to the total of the program of the associated supply unit married in the corresponding session of the IM.

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, 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 setting of the adjustment value of the frequency-power regulation system in charge of controlling the exchange of energy between the two electrical systems that share each electrical interconnection, only those energy programmes that have been correctly nominated shall be taken into consideration, 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 demand and/or deliveries of special regime production, with respect to its program or (a) forecast, and/or significant differences between the expected demand and the envisaged demand in the market, may be resolved through the implementation of the diversion management mechanism, provided that the conditions of application of this mechanism set out in the operating procedure for which the solution process for 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). -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 there is 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. -modification of a P48 with respect to 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.

The General Programming Unit for the integration into the market of energy production from the auctions of primary energy emissions (SEP) has also been defined in Annex II of this procedure. bilateral contracts signed by the distribution or marketing companies of last resort within the framework of the CESUR auctions (CESUR) and for the communication of firm international transactions in interconnections with France and Portugal.

The Programming Unit (UP) and, where appropriate, the General Programming Unit (UPG and UPGCESUR) is also the elementary unit for the recording of the payment entitlements and the payment obligations that correspond to the Registry 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.

12.2 Holder of the Programming Unit. -The holder of the Programming Unit (and/or the Generic Programming Unit) will be the Subject of the market responsible for this 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, as defined in Annex II, corresponding to the Subject Representatives, Distributors or Traders, the holder of the same shall be the Representative Subject himself, Distributor 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 Programming Units used for the integration into the production market of the bilateral contracts signed by the distribution or marketing companies of last resort within the framework of the auctions CESUR (CESUR), the holders of the Generic Programming Units will be the SM vendors who have been awarded the auction.

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

by SM to OS of program nominations per programming unit:
-Bilateral contracts:
Domestic bilateral contracts with physical delivery that have not chosen the pre-market firm nomination option.
Modification (increase only) of domestic bilateral contracts with physical delivery that have chosen the pre-market firm nomination option.
Program-UP Program Nominations of UP Programming Units, integrated with other UP in a single offering unit.
Sending the SM to the OS of the program for:
UP breakdowns in UF.
UGH maximum hydraulic power.

Time
each auction for supply to distributors, distribution companies or marketing companies of last resort or where the EGSED corresponds to the OS the information corresponding to the contracts CBCESUR, contracts formalized between the UPGCESUR of the seller and the last resource vendor or marketer.	Di-6 business days
the possible discrepancies reported by CBCESUR officials have been resolved, the OS will facilitate the final nomination of the CBCESUR.	Di-3 business days
Notification of OS to SM of the authorizations for programming relative to the physical rights of allocated capacity in auctions explicit in the France-Spain and Portugal-Spain interconnection (D-2 or previous day).	D-2 < 16:00 hours
Nomination of SM to OS of allocated capacity in the annual and monthly capacity explicit auctions in the pipeline France-Spain.	< 7:45 hours
The OS makes available to the OM and the SM the physical capacity information obtained in annual and monthly horizons for the France-Spain interconnection whose use has been notified in both systems electrical.	< 08:15 hours
The EASEP performs an indirect nomination of the formalized CBEPs between UPG of the Seller and Buyer SM.	< 8:45 hours
The OS makes available to the SM the information corresponding to the nominations of bilateral contracts with physical delivery of type CBEP and CBCESUR.	< 08:50 hours
The OS Publication of the MD.	< 09:00 hours
by the SM to the OS of the Bilateral contract nominations: International bilateral contracts with physical delivery through interconnections where a coordinated capacity allocation procedure is not established. International bilateral contracts with physical delivery in use of the physical rights of daily capacity in the France-Spain interconnection that have communicated the contract prior to the daily market. 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. National bilateral contracts with physical delivery that have chosen the pre-market firm nomination option.	< 9:35 hours
Portuguese OS on behalf of both OS, will make available to the OM: The information concerning the nomination of bilateral contracts with physical delivery in the Portugal-Spain interconnection arising from the use of the physical rights of capacity acquired in the explicit auctions. The maximum capacity values usable in the bidding process in the Daily and Intradiary (ATC) Market.	< 9:45 hours
	< 09:45 hours
11:00 hours
< 11:00 hours (in any case, up to 30 min. after PDBC publication
PDBF Publication	< 12:00 hours
Presentation of offers for the technical constraint resolution process.	≤ 12:30 hours (in any case, up to 30 min. after PDBF publication
Puesta available to the SM and the OM of the results of the auction of capacity for bilateral contracts with physical delivery made, in case of congestion, in interconnections without coordinated capacity allocation procedure.	< 14:00 hours
PDVP Publication.
secondary throttling reserve.	< 14:00 hours
Presentation of secondary regulation offerings.	< 15:30 hours
regulation reserve allocation.	< 16:00 hours
Tertiary Regulation Reserve Requirements.	< 21:00 hours
Presentation of tertiary regulation offerings.	< 23:00 hours

Notes:

Say: First day of energy delivery of the commitments derived from the Distribution Auctions.

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

In the event of delays in any 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. Schedules for the publication of the phf after intra-day market sessions

Logout.

	Session 1.	Session 2.	Session 3.	Session 4.	Session 5.	Session 6.
Session Opening.	16:00	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
UP Nominations Receive 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
Horizon.	28 hours	24 hours	20 hours	17 hours	13 hours	9 hours
21-24)		(1-24)	(5-24)		(12-24)	(16-24)

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

	Daily Auction (d-1)	1. Intra-day Auction (D-1)	2. Intra-day Auction (D)
Limit for nomination to OS of previously acquired capacity.	7:45	15:00	10:25
Exchange of nominations between OS.	7:55-8:05	15:35-15:40	10:35-10:40
Publication of the auction specification.	8:35	16:05	11:05
Open Receive Period Bids.	8:45	16:15	11:15
Close receipt period offers.	9:15	16:45	11:45
Communication results from the Auction to SM.	9:30	17:00	12:00
Communication to the SM and the OM of the authorizations for programming.	9:30	17:15	12:15

ANNEX II

Programming units located in the Spanish peninsular electrical system

1. Programming units for energy acquisition

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

a) Programming unit for the acquisition of energy by distributors or marketers of last resort. -Each Subject Reseller or Marketer of last resort with supply at tariff or last resort shall be holder of a single Programming Unit for the provisioning of its customers at rate or last resort.

b) Programming unit for direct energy acquisition by direct consumers on the market. -Each Direct Consumer 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 Subject in his own name and on behalf of 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.

e) Programming Unit for the acquisition of energy by producers. -Each Producer may be the holder of a Programming Unit for the acquisition of energy for the supply of all those auxiliary services of its facilities which are not fed from its own production units, with auxiliary services being understood as the electrical energy supplies necessary to provide the basic service in any operating system of the plant (load, start, stop and emergency), including supplies to electrical equipment and actuations 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.

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 distributors or traders of last 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, under the terms 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-axis power plants, such as certain combined cycle groups (2 gas turbines plus 1 steam turbine), 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) will be constituted. 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 special arrangements on the market in the production market through the producer subject;-a production planning unit for the production of 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 be the holder of many special regime programming units as production types compose their generation park so that each Programming Unit integrates into the market the production of a single type.

In addition, for each type of programming unit of a special type of management, there will be two Programming Units, one that will group the facilities eligible for participation in the System adjustment services of a potestative nature, and another grouping facilities that are not eligible 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) Programming Unit for the sale of special regime production in the market economy of the market integrated in the production market through the Subject Marketer or Representative in its own name. o Representative acting in his own name and on behalf of others shall be the holder of so many special regime programming units on a market economy as rates, in accordance with the operational classification established by the OS, make up the park of generation with which he has established a marketing contract or a representation on behalf of others, so that each of its aggregating Programming Units integrates into the market the production corresponding to a single type.

For each type of special regime production aggregator programming unit manageable, two Programming Units will exist; one that will group the facilities enabled for the participation in the setting up of the potestative system, and another grouping of facilities not eligible 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, two units of Programming for the sale of special regime production on an economic tariff rate for each of the types, of programming units established and published by the System Operator in the the website of the eSIOS market, which consists of the special regime generation park at the rate it integrates on the market. The first of these will integrate the production of all facilities of the same type that are not exempt from the payment of the cost of diversion and the second will integrate the production of those facilities of the same type that are exempt from the payment of the cost of deviations. In this way, each of its aggregating Programming Units will integrate in the market the production corresponding to the production of the same type and of the same way of liquidation of the deviations.

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 the same or 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.

g) Programming unit for the sale in the daily market of the excess energy acquired in time by the Dealer or Dealers of Last resort. -Each Subject Dealer or Marketer of Last A resource shall be the holder of a sales programming unit that allows it to reduce, where appropriate, in the daily market, the energy programme committed by the procurement in the market in time and in the CESUR auctions.

The OS will settle in the PBF the program of this sales UP with the corresponding unit of purchase of the distributor or marketer of last resort (paragraph 1.a) of Annex II] and associate the resulting balance to this last unit, of such that the PDBF program published by the OS will not contain the UP for the sale of the distributor or marketer of last resort of the excess of the energy acquired in time by the Dealers Dealers or Dealers of Last resource.

h) Energy sales programming unit for the import from external systems to the Iberian electrical system. -Each authorized subject for the import of energy from external systems to the Iberian electrical 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) a programming unit for the sale of energy on the market with the intention of importing it from the French electricity system without the availability of 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.

3. Generic programming units

a) Generic Programming Units associated with primary energy and/or international transactions (UPG) auctions. -Generic programming units used for integration into the production market of the energy corresponding to the nominations of the energy purchase options allocated in the primary energy emission auctions and/or for the notification of the use of capacity in the interconnection with France.

In the case of primary emission auctions, each SM vendor and each SM holder of power purchase options shall have a single generic programming unit, with this UPG being the same as the one used, if any, for the notification of the use of the capacity of the France-Spain interconnection.

(b) Generic Programming Units associated with the auctions of bilateral contracts of the distribution or marketing of last resort (UPGCESUR). -Generic programming units used for integration into the the market for the production of the energy corresponding to the auctions of bilateral contracts CESUR.

Each MS vendor awarded the power supply at these auctions will have a generic programming unit for these purposes (UPGCESUR).

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.

The Generic Programming Units located in the Portuguese electricity system will be communicated to the Spanish OS by the Portuguese OS within the time limits and through the procedures agreed between the two OS for the purposes of their consideration. in the bilateral contracts established in the area of the Iberian Market between a UPG located in the Portuguese continental electricity system and a UPG located in the Spanish peninsular electricity system.

P. O. 3.2: "Resolution of technical restrictions"

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 program resulting from the appeal of the daily market and the nominations of the program. -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 production market, with the energy programmes contracted in the daily market, including energy programmes resulting from the integration into the market of the contracts established in the market in the forward market under the option of physical clearance of energy.

Before 11:00 hours of each day, or before 30 minutes after the publication of the information corresponding to the results of the procurement in the daily market, when it is carried out after At 10:30 a.m., the OS will receive from the subject holders, for the process of analysis and resolution of technical restrictions, the nominations of the schedules of energy corresponding to the execution of bilateral contracts with delivery (a) physical, in accordance with the procedure laid down in the procedure for establishing the programming of the generation.

3.2 Disaggregation of the programs of the sales and energy acquisition programming units and the communication to the OS of other information necessary for the security analysis. -Before 11:00 hours of each day, or within 30 minutes of the publication of the result of the appeal of the daily market, when this publication takes place after 10:30 hours, the subject holders of the programming units shall provide the next information:

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.

3.4 Period for the 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 after 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.

3.5 Presentation of offers.

3.5.1.1 Energy sales units. -The subject 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.

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 power sales units corresponding to energy imports through interconnections with neighboring electrical systems.

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.

3.5.1.2 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.

3.5.1.3 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.

3.6 Characteristics of the tenders.-The offers for the process of resolution of technical restrictions will be, in general, simple offers, and must be submitted by the subject holder of the corresponding unit, and 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 it has only energy programme in the first three periods of time of that horizon, in the form of a downward ramp of load associated with a process of uncoupling the unit.

In the case of multi-axle multi-axle cycles, these complex offers may be taken into account in cases where the programme of the unit corresponds to the operating mode of a gas turbine and a turbine steam and, by system security requirements, this multi-axis combined cycle group is required in the technical restriction solution processes, the start of the second 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 start is programmed and/or performed by the second gas turbine 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.

3.7 Process of solving 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.

3.8 Phase 1: Modification of 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 modifications of the PDBF. the programme which is necessary for the resolution of the technical restrictions identified, and establishing the necessary safety programme limitations in order to avoid the emergence of new technical restrictions in the second stage of the process of resolution of technical restrictions and in subsequent markets.

3.8.1.1 Identification of technical constraints.

3.8.1.1.1 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.

3.8.1.1.2 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:

f) 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.

g) Insufficient secondary and/or tertiary regulation reserve.

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

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

j) 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.

3.8.1.1.3 Security 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.

3.8.1.1.4 Resolution of technical restrictions. -Before proceeding with the solution of the technical restrictions identified in the Spanish electricity system, the OS will resolve, if necessary, the congestions identified in the PDBF that affect interconnections with neighbouring electrical systems, as laid down in the rules and in the operating procedures in force.

3.8.1.1.5 Resolution of technical restrictions in the Spanish electricity system.-Once the non-existence of congestion in the international interconnections has been verified, the OS will analyze the security conditions of the system Spanish peninsular electric. 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.

3.8.1.1.5.1 Means for the resolution of technical restrictions. -In order 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 electrical interconnections with Community countries (UVICs).

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 for energy import programmes through electricity interconnections with Community countries (UVICs).

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

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

d) Acquisition units corresponding to energy export programmes through interconnections with neighbouring electrical systems (KAUs) (interconnections with both Community and third-party electrical systems countries).

3.8.1.1.5.2 Selection and application of the resolution media. -Solution of technical constraints by increasing the programmed energy in the PDBF.

In the event of the necessary increases in the energy programmed in the PDBF, and there is more than one technically valid and equivalent solution, the OS will carry out an economic evaluation 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.

Solution of technical constraints by reducing the programmed energy in the PDBF.

For the implementation of reductions in the energy programmes provided for in the PDBF for the resolution of the technical restrictions identified in the Spanish electricity system, account will be taken of the influence of the energy of each unit has on the technical restrictions identified, using to these effects the contributing factors to the technical constraints obtained in the applied safety 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 upload:

In those cases where, once the redispatches and security limitations on the PDBF program necessary for the resolution of the technical restrictions have been incorporated, the existence of an insufficient Power reserve to be raised in the resulting program, the OS will adopt the following measures:

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 two possible modes of operation of the multi-axis combined cycles, the corresponding one for a gas turbine and a turbine steam and two gas turbines and a steam turbine.

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 security limitations on the PDBF program necessary for the resolution of the technical restrictions have been incorporated, the existence of an insufficient Reserve of power to be reduced in the resulting program, the OS may proceed to apply program limitations on the units of acquisition corresponding to consumption of pumping up to a value equal to that of its program in the PDBF, in order to avoid possible subsequent reductions of this pump consumption program.

3.8.1.1.5.3 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, should always take into account the expected and published maximum exchange capacity values for the relevant interconnection and flow sense, as well as the necessary availability of rights. of capacity on the part of the units of import of energy in the case of interconnections for which there is a coordinated method of capacity management.

Once selected, among the set of technically valid, and equally effective, solutions that represent a lower overall cost, the OS will establish the modifications of the programs corresponding to the resolution adopted, indicating for each unit affected by such modification the type and magnitude of the redispatch that is applicable to it 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, for which a reduction of its programme of energy is required. acquisition with respect to the PDBF.

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.

3.8.1.1.5.4 Setting security limitations. -As part of the technical restrictions resolution process, the OS should set limitations that are necessary for system security reasons. 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, will only allow the application of redispatches that respect the limits of maximum power to be lowered or to climb, respectively, for them set.

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.

3.8.1.1.5.5 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, 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 such a case, the distribution system operator shall be directed in writing-by fax or e-mail-to the OS, informing them of the risk on the distribution network which is the subject of its management, and detailing the days and the programming period concerned, 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 (a) the distribution network operator must inform the OS of the existence of such a technical restriction before 13:00 hours of the day on which the programming is carried out and, in any event, before the end of the day of the publication by the OS of the energy redispatches and the necessary limitations for safety 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 process of re-balancing generation-demand.

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.

3.8.1.1.5.6 Treatment of the 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. Congestion in the case study basis and/or identification of post-contingency transient instability conditions.

Production shall be limited in the area affected by congestion in such a way that at no time on the evacuation lines and transformers are exceeded the maximum load limits set in the operation procedure by the setting 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. Congestion in post-contingency situations.-Once the absence of congestion in the baseline case has been proven, or conditions of transient instability requiring a priori reduction of production in the area, having already been Those who, if any, have been identified, will then analyse the possible existence of post-contingency congestions.

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. In the case of congestion in the production evacuation of an area limited to post-contingency situations, the production units that may be affected by a reduction or even the cancellation of production units In order to ensure the efficiency of the energy programme, the Commission will be able to avoid, or at least reduce, this reduction in its programme, by activating, on the basis of an authorisation by the OS, a generation-firing automatism acting in accordance with the Case of any of the contingencies causing overloads Inadmissible post-contingency. 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 due to increased production in respect of the PDVP. -In the event that there are no congestions in the case base case or in post-contingency situation with the programs of In the case of the sale of energy in the PDBF corresponding to these production units, these congestions could be presented if the production units in the area increased their production in subsequent markets (intra-day market, diversion management and tertiary regulation), above 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.

3.9 Phase 2: Reequilibrium generation-demand.-Once the technical constraints identified in the PDBF have been resolved, the OS will proceed to make the necessary program modifications to obtain a balanced program in generation and demand, while respecting the constraints established, for reasons of system security, in the first phase of the process of resolution of technical restrictions, and the expected and published values of the exchange capacity in the international interconnections.

3.9.1.1 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, in the first place, reduce or Even totally, the energy sales programs of those programming units that are enabled to participate in the process of resolution of technical restrictions, are affected to bilateral contracts with physical delivery whose demand has been reduced in the first phase of the resolution process technical constraints of the PDBF.

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 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.

3.9.1.2 Partial or total reduction of energy acquisition programmes corresponding to pumping or export consumption associated with bilateral contracts with physical delivery the generation of which has been reduced in the PHASE 1. -The OS will reduce, or even cancel, the energy acquisition programs corresponding to pumping consumption or to exports that are associated with bilateral contracts with physical delivery whose corresponding generation has been reduced in the first phase of the PDBF technical restrictions resolution process.

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.

3.9.1.3 Obtaining a balanced program generation-demand.

Means for the balance generation-demand.-To restore the balance generation-demand, the OS may proceed to the allocation of the simple offers presented 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 [UVI (interconnections with Community electrical systems and with third countries)].

(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 program base of operation (PDBF), after the inclusion of the modifications established in the first phase of the technical restrictions resolution process, in order to obtain a balanced programme in generation and demand in each and every programming period, with the view that these changes will have the reduced economic impact, while respecting the limitations of the programme in all cases for security established in the first phase of the process and the capacity for 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.

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.

3.10 Inavailabilities of production units with influence on security, reported after the PDBF was published. -In the case of partial or total unavailability for the programming day of a unit of scheduled or limited production for the PDBF's resolution of restrictions, if the communication of such unavailability is made before 13:00 hours of the day on which the programming is made, the OS will try to readjust the program provided for the resolution of the restrictions of the PDBF, according to the latest information available at relationship to generation inavailabilities.

If the unavailability communication is received after 13:00 hours, or if it is still known before that time, the reported unavailability affects the resolution of the PDBF restrictions in a As such that the consideration of the same could delay the publication of the PDVP beyond 14:30 hours, the OS will proceed to publish the PDVP without considering such inavailability of 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.

3.11 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 resulting from the PDBF technical constraint resolution process.

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.

3.12 Failure and complaint resolution regarding the process of resolution of the PDBF technical restrictions. -The possible identification of anomalies and/or claims submission to the restriction resolution process PDBF techniques, including the PDVP and other associated information media, could lead to the repetition of this process in case the solution of the failure so requires, provided that this is possible, with due respect to the the maximum permissible time limits laid down and published by the OS, to ensure that they do not The subsequent programming processes of the generation are negatively affected.

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, through the Application of Claims Management made available for these purposes by the OS, being able to advance the information regarding the existence of this claim, through telephone communication, fax or e-mail, being necessary, in any case, the existence of an express formal communication through the Claims management information application, or by written means (fax or e-mail), for consideration as a formal complaint.

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 Reception and loading of the outcome of the appeal from the IM. -As a step before the implementation of the security analysis, 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 Process of resolution of technical restrictions of the intraday market. -The OS, in case of identification of any technical restriction that prevents the program resulting from the session of the intra-day market, having also 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. Resolution of technical constraints in real time

5.1 Amendments by security criteria. -The OS will permanently analyze the state of the system's actual and anticipated security throughout the entire programming horizon and detect any restrictions that may exist in the 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 the technical restrictions, the same criteria as referred to in paragraph 3.4.1.1.5.2 of the Annex shall be taken into account. (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 bid blocks submitted for the PDBF technical restriction resolution process, with the result that the allocation of this programme modification between the unit set is to be carried out which resolve the restriction, according to the order of price of the tenders submitted, the pro rata rule in the event of an equal bid price.

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.

5.2 Treatment of the reductions/cancellations of the capacity to evacuate the production of generating groups for over-sold inavailabilities of elements of the Transport Network or of the Distribution Network. -In the case of 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 evacuation capacity does not involve a diversion of the actual production of the unit in relation to the programme envisaged 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.

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.

Reducing/nullifying export capabilities to external systems.

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.

5.5 Reduction of pumping consumption. -For the use of pumping consumption units to solve technical restrictions identified in real time, the order of economic precedence of the offers of tertiary regulation to be submitted to the OS by the holders of such units, provided that there is no technical condition preventing the consideration of such an order.

5.6 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.

5.7 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.

5.8 Reequilibrium generation-demand after the resolution of the technical constraints in real time. -In the process of solving technical restrictions 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 liquidation of this complementary 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.

6.2 Liquidation of energy programs. -Reoffices and prices incorporated in the same applicable to each of the units of sale and acquisition that have modified their program as a result 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.

6.3 Liquidation according to energy measures.-settlement with measures shall be applicable 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.

6.4 Distribution of cost overruns resulting from the process of resolution of technical constraints. -Overruns of the PDBF technical restrictions resolution process and in real time will be calculated and passed on the criteria specified in the operating procedure for 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 emergency situations or for reasons of urgency, or because of the absence of offers due to force majeure or other circumstances 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 subject-holders concerned and the NEC, without prejudice to 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. -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.

Units programmed 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 it 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 in the program of a power sales unit for the resolution of technical restrictions of the PDBF, by means of a power-supply of the (a) the UPOPVPMER rate, the unit being not affected by an unavailability which prevents the implementation of the security programme, and no tenders submitted for that unit for the process of resolution of technical restrictions; Energy redispatches scheduled in each hour will incorporate a price equal to the one resulting from applying A KMAY capital ratio equal to 1,15 on the corresponding marginal daily market time price.

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 unit and acquisition 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 with programs associated with bilateral contracts with physical delivery whose generation has been reduced in Phase I, and which reduce energy programmed to obtain a balanced program in generation and demand.

ECOCBV energy redispatches scheduled in the PDVP on energy acquisition units (pumping consumption or, where applicable, export via international interconnections) for contracts Bilateral agreements, the generation of which has been reduced in the first phase of the PDBF's technical restrictions resolution process, will not incorporate 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.

1.3.2 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.

1.3.3 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.

1.3.4 Pump consumption acquisition units that increase your energy program for the resolution of technical constraints in real time.

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.

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

1.3.6 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.

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

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.

1.3.8 Pump consumption acquisition units that increase your energy program for the resolution of technical constraints in real time.

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.

1.3.9 Real-time applied redispatches not covered with tertiary regulation offerings nor with offers submitted for the technical constraint resolution process.

In cases where the OS has to schedule power redispatches to go up or down for the resolution of technical restrictions identified in real time, without any offers of tertiary regulation, no offers In the case of the process of resolution of technical restrictions, or existing ones, they are insufficient to fully cover the redispatches applied for security in real time, the redispatches which, if any, can be applied by the MER, the following prices will be associated:

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 implementation of the redispatches scheduled in accordance with 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 planned starts and the specific type of start-up (cold or hot) scheduled, and the fact that they have been effectively produced in accordance with the measures received, as well as the actual energy measured for the unit and the energy for it programmed by security criteria (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. 3.3: "Management of consumption-consumption deviations"

1. Object

The purpose of this procedure is to establish the process of resolving deviations between generation and consumption that may occur after the end of each session of the intraday (MI) market and up to the start time of the programming horizon for the next session.

2. Scope of application

This procedure applies to the System Operator (OS) and the electrical power production (SM) market subjects.

3. Service providers

The suppliers of this system adjustment service are the production facilities of the ordinary regime and special scheme of a manageable character that are enabled for their delivery by the OS and the consumption facilities of the pumping.

3.1 Enabling units for service delivery. -Interested production facilities must meet the following requirements to obtain the enablement:

Enrollment in the corresponding RAIPEE section.

Request for participation in the process of resolving deviations between generation and consumption.

Integrating the production installation into a control center.

Communication to the OS of the additional information required for the providers of this service in the Operation Procedure establishing the exchange of information with the OS and updating it when it is produce any variation.

In the case of production facilities belonging to the special management regime, the corresponding resolution of the General Directorate of Energy Policy and Mines that authorizes the participation in the system adjustment services of a potestative nature.

Verification that the programming unit in which the production facility is integrated provides an offering capacity for the provision of this service not less than 10 MW.

satisfactory outcome of the OS analysis of the information specified in the operating procedure establishing the exchange of information with the OS presented for the purpose by the subject holder of the installation.

For the acceptance of offers and consideration for all the effects of the participation in the process of management of deviations from a production unit, the person responsible for the installation must have the express authorization of the OS.

Production units are required to communicate and keep updated the information required by the OS in the relevant operating procedure to enable the proper functioning of the management process deviations.

The OS may withdraw any of the ratings previously granted when it detects a lack of technical capacity for the provision of the service, the quality of the service provided does not meet the requirements required or does not receive any change or modification information that might affect the delivery of this system tuning service.

4. Resolution procedure

4.1 Process Definition.-The subject holders of programming units shall communicate to the System Operator as soon as possible all partial or total inavailabilities affecting the physical units. the production and physical units of pumping consumption, as set out in the operating procedure for establishing the communication and the treatment of the inavailabilities of the production units.

In addition, the subject holders of the programming units shall also communicate to the System Operator any duly justified modifications to the programme which are submitted in their respective equipment. generation or consumption of pumping, for other reasons (technical infeasibility, certain discharges, etc.), and which entail a variation of the energy programme delivered or taken from the network of more than 30 MWh with respect to the value of the schedule Previously communicated for the programming unit, the holder must also be explicit the intended duration of the diversion.

For its part, the Operator of the System will make forecasts of the demand of the Spanish peninsular electric system, according to the procedure of operation by which the forecast of the coverage of the demand is established, thus as to the deliveries of energy from the special regime production facilities integrated into the market through the Representatives of the Representatives.

The System Operator will also note deviations from the programming units associated with the international exchange programs in cases where, once the last session of the intraday market has been For the programming period in question, the subject of a programming unit associated with an international exchange programme shall maintain an energy programme which does not have the relevant conformity of the programme. operator of the neighbouring electrical system.

Taking as a starting point its best forecasts for the demand of the Spanish peninsular electric system and wind production according to the procedure in which the reserve for the regulation is established frequency-power, as well as information of inavailabilities and justified deviations of the programme communicated by the subject-holders of programming units, and possible deviations from the programming units concerned the international exchange programmes, the System Operator shall estimate the predicted global deviations up to the start time of the programming horizon of the next IM session.

The Operator of the System, based on the planned deviations, will assess the need to convene the market for the management of consumption-consumption deviations, requesting offers, if any, for the resolution of these deviations. Those deviations in which the value of the average deviation provided for each programming period is less than 300 MW shall not be resolved by means of a call for the market for diversion management.

In the event that the average deviation provided for each programming period is equal to or greater than 300 MW, the System Operator shall communicate to the SM the total energy requirement and its meaning (to be raised or lowered) for the resolution of the the deviations in each programming period, as well as the maximum and minimum energy limitations applicable to the offers which, if necessary, the System Operator could establish, in accordance with the National Energy Commission, to ensure adequate provision and proper control of that service.

To address the intended deviations, the System Operator will use the offers to increase and reduce the programming units for generation and/or pumping consumption facilities and to allocate the program modifications that correspond to each programming unit, incorporating these modifications into the following P48 operating schedule.

The temporary scope of application of the generation-consumption diversion management market may reach all the programming periods between the closure of a session of the IM and the start time of the horizon of the programming of the next session of the IM.

4.2 Bid Presentation. -Once communicated by the System Operator the energy requirements to be covered to compensate for the identified deviations and, where applicable, the maximum and minimum energy limitations applicable to the tenders, the holders may submit, within a maximum of 30 minutes, tenders for each of their programming units corresponding to their facilities for generating and/or pumping consumption for the energy available to them for cover the detour.

The participation in the process of resolution of the generation-consumption deviations of the programming units corresponding to production facilities in phase of pre-operational tests of operation is found established in the operation procedure whereby the participation of these facilities is established in the processes managed by the system operator. The tenders submitted shall be valid only for the call made, being cancelled after the corresponding allocation process has been closed.

For each programming unit the following information will be specified:

Type of offer (generation or consumption of pumping).

Power to upload:

For the set of the detour resolution horizon it will be indicated:

Maximum Total Energy (MWh).

Maximum power variation allocated (MWh/h).

In addition for each programming period, it will be indicated:

Block N. (correlative order starting with 1, maximum = 10).

Energy (MWh).

Power price offered (€/MWh).

Indivisibility code.

Full acceptance code extended to all programming periods of the deviation resolution horizon (Apply if n. block order = 1).

Energy to go down:

The same information required under the heading of Energy to be uploaded, taking into account that the energy offered in this case is to be lowered, rather than to go up, and that the price offered corresponds to the repurchase price of the energy.

The value of time energy to be uploaded or lowered from an indivisible offer may not exceed 300 MWh in any case.

4.3 Offer allocation.-The System Operator will analyze the offers received and, in the event of detecting any incompatibility with the programs assigned in previous processes, the offer will be limited. This process shall be carried out by the application of a control over the physical limits of the production and pumping units. If these physical limits are exceeded, or where the allocation of an offer gives rise to a programme limitation established for reasons of system security, the criteria set out in Annex I to this Regulation shall apply. procedure.

The bids must respect the maximum prices that, if any, can be established and published by the competent administration in the field of electrical energy, after report of the National Energy Commission, in addition the acceptance and validation criteria set out in Annex I to this procedure.

The System Operator will assign the offers using the allocation algorithm specified in Annex II of this procedure.

4.4 Communication of the results of the assignment. -The System Operator will communicate the results of the offer allocation process to the subject holders of each assigned programming unit.

The allocation made by the System Operator shall be deemed to be firm immediately after being communicated, acquiring, the subject holder of the programming unit, the obligation to carry out the new energy programme derived from the conjunction of its previous program plus the program modification associated with the allocation of bids for the resolution of the generation-consumption deviations.

Fifteen minutes before the change of time, the System Operator shall transmit to the subject-holders of the programming units concerned, in accordance with the operating procedure establishing the exchange of information with the System Operator, the new program for their respective programming units. This programme shall include the additional production to be incorporated or reduced in the programming of each unit for the resolution of consumption-consumption deviations.

4.5 Failure and Claims Solution for Bid Allocation Process. -Once the result of the Deviation Resolution Offer Allocation Process is published, the subjects holding the The program will be able to present claims to this process, through the Application of Claims Management made available to these effects by the Operator of the System, being able to advance the information regarding the existence of this claim via telephone, fax or email, where necessary, in any case Case, the existence of a formal express communication through the IT application of claims management, or by a written means (fax or email), for its final consideration as a formal complaint.

The System Operator will manage, as soon as possible, these claims or any anomalies that could have been identified in the offer allocation process, proceeding with a new allocation process, where the solution of the anomaly so requires, provided that this is possible, with due regard to the maximum allowable time limits set and published by the System Operator, to ensure that they are not negatively affected the subsequent programming processes of the operation.

4.6 Settlement of the service.-The economic treatment of this service is defined in the operating procedure whereby payment entitlements and payment obligations are established by the system adjustment services.

4.7 Liquidation of service provision. -Pump generation and consumption supply units will be able to modify their energy program for resolution of consumption-consumption deviations.

The planned modifications in the generation and consumption supply units for the resolution of these generation-consumption deviations will be valued at the marginal price of the offers allocated in each of the programming, the marginal price being calculated in accordance with the mechanism specified in Annex II to this procedure.

4.8 Distribution of costs arising from the resolution of consumption-consumption deviations-the settlement of costs arising from the modification of the power generation or pumping energy programme for the resolution of the general consumption-consumption deviations shall be passed on in accordance with the criteria specified in the operating procedure establishing the payment entitlements and the payment obligations for the system adjustment services.

5. Exceptional allocation mechanism

In cases where, for reasons of urgency, the absence of sufficient offers, or the unavailability of management information systems or other justified cause, it is not possible to resolve a diversion through the application of the The mechanism provided for in this procedure, without sufficient reserve of tertiary regulation, the System Operator may adopt the programming decisions it considers more appropriate, in order to resolve the generation-consumption deviations identified, subsequently justifying their actions to the subjects concerned and to the National Energy Commission, without prejudice to the remuneration to which there would have been for the provision of the service.

Energy allocations that, if any, can be applied by the OS by exceptional allocation mechanism will be valued:

For energy allocations to be uploaded: At a price equal to the result of applying a KMAY mayorization coefficient, of equal value to 1.15, for the maximum marginal time price of all sessions of detours to be raised covered by that time or, failing that, by the marginal price of the daily market

For energy allocations to be lowered: At a price equal to the result of applying a KMIN minorization coefficient, of a value equal to 0.85, for the minimum marginal price of all sessions of detours to be lowered covered by that time or, failing that, by the marginal price of the daily market.

ANNEX I

Criteria for the acceptance and validation of deviations resolution offerings

The tenders submitted by the holders for the resolution of the consumption-consumption deviations shall be subject to the validation criteria set out in this Annex.

1. Checks applied in the bid read process

Only one offer per unit of programming for the sale of energy corresponding to generation facilities or per unit of programming for the acquisition of energy for consumption of pumping for each call will be admitted Management of deviations. In this way, if more than once information is sent to the same programming unit for the same call, the last information will replace the previous one.

The offer must be sent by the subject holder of the scheduling unit to which the offer corresponds.

The time period covered by the offer must be included in the open call horizon in force at the time of receipt of the offer.

Each offer shall be composed of consecutive blocks, the number of which shall not exceed the maximum which, if applicable, establishes and publishes the System Operator.

In the case of programming units that integrate energy from installations belonging to the special regime, in each of the time periods for which the offer is presented, the sum of the blocks that make up the component must be equal to or greater than 10 MW.

Only one block of type all or nothing will be allowed per offer and meaning (sub/lower), the block n. 1 is mandatory. If more than one exists, the offer will be rejected.

Each offer must respect the maximum and minimum energy limitations established and published, if any, by the System Operator, after compliance with the National Energy Commission. Energy offers exceeding that range shall be rejected.

The bids must respect the maximum prices that, if any, can be established and published by the competent authority in the field of electrical energy, prior to the report of the National Energy Commission.

2. Checks on the preprocessing of the offerings

These checks are made immediately prior to application of the offer allocation algorithm, requiring consideration of information such as program limitations for security and inavailabilities of physical units of production, which may have been modified from the time the offers were read.

The checks that are performed at this stage on the programming units are as follows:

Non-violation of limits for security.

No violation of limitations due to unavailability (communicated by the responsible holder of the programming unit or, failing that, introduced by the System Operator, after prior communication from the titular subject).

Non-violation of the physical power limits of the group (only in the case of generator groups and pumping units).

Do not offer an energy to lower your generation program, or for the programming units for energy acquisition for pumping, energy supply to go up higher than your pumping program.

The actions to take when a bid block violates any of the above limits will depend on the indivisibility conditions of the offer:

Divisible block: Block will be truncated to the point where it stops violating the limit

Indivisible block: Block will be completely rejected in those programming periods in which the violation occurs

All or Nothing Type Block: The offer block will be completely rejected, that is, for all scheduling periods that span the offer, even if only the violation occurs in some period.

It should be noted that in the first and the last programming period for which the market for the management of deviations is called, all the bidding blocks (except for all or nothing blocks) will be considered as divisible. For this reason, in these extreme programming periods, when a violation occurs, the offer block will always be truncated.

3. Checks made during the allocation process

These checks are performed by the allocation algorithm itself, and affect those offer blocks that, for price, should be allocated. During this process it is proven that the allocation does not violate any of the maximum power and ramp restrictions of the offer. Your application may cause the offer to not be allocated in its entirety or to be rejected.

It should be noted that while rejections affect offer blocks, checks are performed at the program level for the programming unit.

The checks performed at this stage are as follows:

After the assignment, the programming unit must not violate with its offer any ramp up or down. That is, you have to comply that:

E (t + 1) E (t) + Ramp Up (t)

E (t + 1) E (t)-Ramp Down (t)

The E (t) and E (t + 1) energies correspond to the program of the programming unit after the allocation of the deviation management offer.

That is:

E (t) = Initial Program (t) + Devios Assignment (t)

This check is performed, regardless of the sign of the detour, for all the hours in which it is allocated, except for the last one.

Check that the power allocated to the programming unit does not exceed the maximum power limitation of the offering. Once this limit is reached, no more blocks of this offering will be allocated.

Check that all or nothing type blocks have been allocated in all programming periods. When such a block has not been allocated for any programming period, either for price or for any of the above restrictions, it will be unallocated in all those periods in which it would have been allocated.

In cases where some of these limitations are violated, the treatment applied to the offer block is a function of the type of block in question, taking into consideration the same criteria as indicated in the paragraph 2 of this Annex, depending on whether the blocks are divisible, indivisible or all or nothing.

ANNEX II

Offer Allocation Algorithm for Generation-Consumption Deviation Resolution

1. Fundamental characteristics of the allocation algorithm

The main features presented by this offer allocation algorithm are as follows:

Single allocation process in which there are horizontal constraints: ramp and total power allocated.

Iterative allocation process in which different application of the algorithm is performed until a valid solution is reached.

Indivisible and all-or-nothing offer blocks are supported. The latter are blocks that must be fully allocated in all programming periods. However, in the first and last programming period for which the diversion management market is called, all indivisible blocks are considered as divisible.

The offering blocks can incorporate maximum and total power ramp conditions assigned to the market horizon set.

The marginal market in which the settlement for the provision of the service in each programming period is determined by the price of the last offer partially or wholly allocated to cover the requirements in that period.

A margin is allowed in the allocation of bids (± 10% of the requirements) so that the valid allocation is considered when covering the requirements published within the range defined by this margin (90% <-> 110% of the published requirements).

2. Description of the operation of the algorithm

The procedure used in the offer allocation process is as follows:

1. Time-to-time the offer blocks are placed in increasing order of prices (decreasing for requirement to be lowered) to cover the requirement.

2. In each hour, the maximum power that can be assigned to each block is calculated so that the ramp and total power constraints that the bids might present are not violated.

3. For price equality, the blocks are sorted according to the following criteria:

The divisible blocks on the indivisible are preferred.

At type equality (both divisible or indivisible), the block that offers less energy is preferred.

4. In case multiple bidding blocks exist at the same price, at the coverage limit, the allocation is prorated between them if they are divisible.

If one or more of these blocks were indivisible (pumping), preference is given to the coverage with the divisible ones. If assigned, the assignment of an indivisible block is still necessary, as follows: The smaller indivisible blocks are preferred. If placing an indivisible block exceeds the requirement in a value less than the allowed margin, the block will be assigned and the allocation will be ended.

If this value is exceeded, the block will be removed. If once the block is removed, the requirement is not reached, but it is within the allowable variation margin around the published requirement, the assignment is considered complete.

If the above is not true, the next price blocks are continued, until the allocation is complete.

5. Once the requirements have been reached in a programming period, the next one is reached until the end of the horizon.

6. Once the end of the horizon is reached, the process of back assignment is repeated again. When the backward allocation is performed, in blocks that present ramp and/or total power constraints, no more power than assigned in the forward process can be allocated.

7. Once the first programming period is reached, it is analyzed if the solution is valid (no restriction is violated). The process is repeated until the maximum number of iterations is reached or a valid solution is reached after four iterations.

8. When a valid solution has been reached, it is checked that all of the offer blocks of type all or nothing have been fully allocated in all programming periods. If there are multiple blocks in this situation, the one that is most expensive is removed and the entire process is repeated again.

P. O. 3.7: "Programming of non-manageable renewable source generation"

1. Object

This procedure describes the information flows and processes required for non-manageable renewable source generation programming, in order to ensure the secure operation of the System.

All the generation of the Spanish Peninsular Electrical System, including that which is the subject of this procedure, is generally subject to the provisions of the Operation Procedures and in particular in procedures 3.1, 3.2 and 3.3.

Given the unmanageable nature of the primary energy sources of some production units, they must try to transform all the primary energy they receive into electrical energy, avoiding primary energy discharges. The purpose of this procedure must therefore be to lay down the measures for the operation of the system as a whole and of these production units in particular, enabling maximum possible integration of the power and energy compatible with the system. the secure and stable operation of the system.

2. Scope of application

This procedure applies to the following subjects:

a) Electrical Network in its System Operator (OS) condition.

(b) proprietary enterprises of non-manageable renewable source production facilities.

c) Non-manageable renewable source generation facility control centers.

d) The companies that own the transportation network facilities.

e) The companies that own the distribution network facilities and the corresponding distribution managers.

From the point of view of the production facilities, this procedure applies to facilities of generation of non-manageable renewable origin with nominal power recorded in the Administrative Registry of Electrical Power Production Facilities (RAIPEE) greater than 10 MW. In the case of installations with a power lower than the above, but which are part of a set with a common connection point and the sum of powers of which is greater than 10 MW, this procedure shall also apply to them.

It is defined as a generation of non-manageable renewable origin, in accordance with the provisions of RD 661/2007, the primary source of which is neither controllable nor storable and whose associated production plants lack the the possibility of carrying out a production control following instructions from the System Operator without incurring a primary energy spill, or the strength of the future production profile is not sufficient for it to be considered as program, although it could be considered as a forecast.

3. Information to provision to the system operator

In addition to the provisions of P.O. 9, the Control Centers to which this procedure applies, will send to the Operator of the System, within the first ten calendar days of each month, an update of the production units to which they are attached, it being understood that each non-manageable renewable source generation facility constitutes a production unit. The information shall be submitted in accordance with the forms available to the System Operator and shall include at least the following information for each production unit:

a) Identification number in the MITyC record and production unit name

b) Owner.

c) The number and technology of the generating units that make up each production unit as well as, where applicable, associated equipment.

d) Maximum power of generating units.

e) The Transport Network Nudo on which your generation pours.

f) Mechanisms available for power and power control, as well as characteristics of such control systems associated with the production unit.

g) Any information that the Control Center considers relevant for the best programming of these production facilities.

h) Production Unit Protections and Adjustments.

4. Programming of the production modifications

The System Operator, in compliance with the procedure of operation 3.2, and as a result of the analysis and monitoring of System security applied in different time horizons, can detect different conditions that pose a certain risk to the quality and continuity of supply. In the field of technical restrictions described in this proceeding and only in cases where there is no other means to avoid such a risk by acting in real time or in good time, either because the action has already been taken on the manageable generation or because the problem to be solved is only resolvable with the action on the generation of non-manageable renewable origin, the Operator of the System will give the appropriate instructions for modification of production to the units covered by this procedure by means of the respective Control Centres. In that case, the System Operator shall identify the maximum permissible production by knot of the Transport Network and for each production technology in cases where it is relevant.

In cases of restrictions on installations that pour their energy into the distribution network, the system operator shall communicate to the manager of this network the instructions given to the relevant Control Centre.

In the Control Centres, records of the reduction slogans given by the system operator and by the control centre itself, as well as the actual execution of the production cuts and reductions, must be available for the control centres. that can be used in the resolution of possible conflicts.

Production modification.-The System Operator will inform the Control Centers affected of the maximum production that each of the units under its control can discharge so that the maximum production is not exceeded In each of the nodes of the Transport Network, the primary control variable of the generation is the latter. The distribution of such maximum production by knot shall be carried out in proportion to the power programmed or in production, depending on the time area in which the proposed modification takes place, managed by each of the dispatches in each of the the knots. Such production must be achieved within a maximum of 15 minutes after the modification instruction has been received.

Alternatively to the methodology described, each Control Center may perform another internal distribution of the generation, provided that the limitation is respected in each of the nodes of the Transport Network, according to the set out in point 5 of this Operation Procedure. In any case, the System Operator shall supply to each Control Centre the information relating to the production of each unit under its responsibility which has been considered for the production by knot. Such production per unit shall be calculated on the basis of the apportionment proportional to the programmed power or production.

In the event that a Control Center performs an internal distribution other than the one sent by the System Operator after receiving a reduction instruction, the System Operator must receive from that Control Center, prior to the following day, the power allocated to each production unit in each time period, in order to be taken into consideration, provided that the allocation complies with the conditions laid down. In another case the System Operator will consider that the distribution performed corresponds to the one sent by the envoy. The format and conditions of that shipment will be determined by the System Operator.

If the operating conditions allow the limitation to be partially lifted, the lifting order of that limitation will be the inverse of the employee to establish the limitation.

Production Reduction Types: Depending on the problem identified by the System Operator, the following cases can be distinguished:

Congestion in the generation evacuation. -congestion is understood to be the occurrence of inadmissible overloads, in accordance with the safety criteria, in elements of the Transport Network, due to an excess of production in a the capacity to evacuate from the site, as well as the total impossibility of evacuation due to the unavailability of the facilities that allow such evacuation. Modification of production for the solution of such congestion will be performed as set out in Operation Procedure 3.2 without any further consideration.

If cases of frequent reduction in the production of a transport network knot are produced, determined by a number greater than 3 times in one month or 10 times in the set of one year, the system operator must present in the maximum period of 6 months, for authorisation by the Secretary of State for Energy, an Investment Plan for the solution of the relevant restriction.

When the distribution network manager of an area detects in the programming process or in real time a problem of network congestion under its responsibility that it is not possible to resolve by a different means to the modification of the production of units covered by this procedure, in accordance with the provisions of P.O. 3.2, it shall inform the Operator of the System, leaving a written record by fax or e-mail of the non-compliance with the conditions of detected safety, and the causes to which it is due, as well as the maximum power of each of the production units affected by the modification. The System Operator will order the reduction to the Control Centers, and may, upon request, distribute the request made by the Distributor to the affected Control Centers.

Stability. -Stability problems will be associated with the maximum loss of instant generation that the system can withstand due to a voltage gap resulting from a lack in a network installation Transportation that is cleared in a time equal to or less than 100 ms. In the circumstances required by the system, in accordance with current regulations, the System Operator may apply 250 ms clearance times.

The System Operator will evaluate in advance sufficient time and in real time, with unbundling by the Transport Network, the maximum power of generation of non-manageable renewable source that can be integrated into the system without compromising their safety, taking into account the instantaneous loss of generation caused by voltage gaps. To this end, it shall take into account the technology of each of the production units, taking into account the technical requirements laid down in the operating procedures, in order to minimise the necessary generation modification, First place the productions of the installations most sensitive to those voltage voids.

Short-circuit power. -When the System Operator detects in knots of the Transport Network short circuit power values that put at risk the security of the system, according to the current regulations, the Operator of System shall identify the maximum allowable production under safety criteria. This will take into account the technology of each of the production units in order to minimize the required generation modification.

Feasibility of power balance sheets. -In the generation programming the System Operator must ensure the viability of the active and reactive power balances, taking into account the unique circumstances of operation and the technical limits of the manageable plants that are essential to meet the demand in times of the period concerned, which may result in technical restrictions on unmanageable plants. In this case, associated with daily programming horizons, the scope of application will generally be that of the system as a whole, not having the technology of the generation units being relevant.

The System Operator will set the precise modifications for each production unit.

Non-integrable generation surpluses in the System. -In certain circumstances where there is a lower demand than the forecast and/or a production of the units which are the subject of this procedure higher than the forecast Previously, the System Operator may specify to reduce the production of the generation covered by this procedure.

5. Power management mechanisms at the disposal of generators in control centres

In general, the internal distribution performed by each Control Center, always respecting the limitation in each of the nodes of the Transport Network communicated by the Operator of the System, will be equally proportional to the power programmed or in production, depending on the time frame in which the proposed modification takes place.

Alternatively to this general criterion of power management, and provided that an equivalent or more favourable effect is ensured in the resolution of the technical restriction in question, on the transport and distribution networks and the system as a whole, the allocation to the different production units may be carried out by the Control Centres on the units attached to them with the requirements set out below.

In this context, on the scope and magnitude of action established by the System Operator, the Control Centres may implement alternative mechanisms in which a performance on a set of units is replaced. of the production concerned, by another action on a subset of those units which, with a consequence equal to or more favourable to the system, may be more efficient for generators and, as a priority, safer for the system.

To this effect, for each of the proposed areas of restriction, the Control Centers must propose to the Operator of the System the alternative mechanisms to apply justifying and documenting their consistency and contribution to the safety and efficiency previously reviewed. In this respect, the units associated with those areas of restriction shall be identified and, within those areas, those units which shall be acted upon in each case and for each foreseeable situation.

The System Operator will value and, if applicable, authorize the application of these management mechanisms by informing the CNE.

Moreover, it falls outside the scope of this procedure and the functions of the System Operator to ensure, monitor or assess the implementation of the management mechanisms of the different units assigned to the Control, provided this is not relevant to system security.

6. Exceptional resolution mechanism

In the event that, in the event of emergencies or for reasons of urgency, caused by force majeure or otherwise unanticipated or controllable, it is not possible to resolve the restrictions by means of the mechanisms provided for in this procedure, the OS may take the programming decisions it considers appropriate, justifying its subsequent actions to the agents concerned and the CNE, without prejudice to the economic remuneration of the same ones that are applicable in each case.

P. O. 7.2: "Secondary Regulation"

1. Object

The purpose of this procedure is to regulate the complementary service of secondary regulation of the Spanish peninsular electrical system. It sets out the criteria for the following aspects:

Provision of the service.

Assignment of the capability.

Control and measure of service delivery.

Service Economic Settlement Criteria.

This procedure also includes the technical criteria for the Peninsular Shared Regulation (CPR) system and secondary regulatory areas, through which this service is provided.

2. Scope of application

This procedure applies to the System Operator (OS) and to the production facilities belonging to the ordinary regime and to the special management system as well as to the persons responsible for the regulation.

3. Definitions

3.1 Complementary Secondary Regulation Service. -The Complementary Secondary Regulation Service is a service of the potestative character system managed by market mechanisms.

The goals of the secondary regulation service are:

Override the detours at every instant with respect to the exchange programs.

Maintenance of the system frequency to its reference value.

The secondary regulation service is provided by the regulatory areas (also known as control zones) in response to the requirements of the OS master regulator. This master regulator is referred to as CPR (Peninsular Shared Regulation).

3.2 Peninsular Shared Regulatory System (R.C.P.). -R.C.P. (Peninsular Shared Regulation) is the control system that functions as the master regulator of secondary system regulation.

For security reasons, the system is duplicated: the master master regulator is located in the Electrical Control Center (CECOEL), with a secondary regulation backup system located in the Center of Support Control (CECORE).

3.3 Regulatory Area. -A Regulatory Area is a grouping of production units that, together, has the capacity to regulate in response to the orders of an Automatic Generation Control (AGC) system complying with the established requirements and enabling their assessment from a real-time energy control system.

Regulatory zones are constituted by units, previously enabled by the OS and responding to control signals sent by the corresponding AGC and by units not enabled for active participation in the complementary service of secondary regulation. Annex III, Regulation of Secondary Regulation, describes the dynamic response required to the regulatory areas.

3.4 Secondary regulation reserve. -The secondary regulation reserve to be raised/lowered is the maximum power variation value in which it is possible to modify the generation of the set of production units in control in the corresponding sense and with the established speed, in response to the requirements of the control system.

3.5 Net effective energy of secondary regulation. -Net effective energy of secondary regulation realized in a programming period, is the diversion in energy with respect to its programs of the set of production units integrated in the control loop of the corresponding AGC due to the monitoring of the requirements of secondary regulation.

Secondary regulatory net effective energy shall not be considered as deviations in units of production of a regulatory area that are not directly linked to the generation changes required by the AGC.

When the sign of such net energy in a programming period is positive, it is called secondary regulation energy to be raised, and in case of negative sign, secondary regulation energy to be lowered.

4. Service providers

The secondary regulation service providers are the regulatory zones.

4.1 Constitution and modification of the regulatory zones. -Both the constitution and any modification affecting the composition of a regulatory area must be previously authorized by the OS.

In particular, the authorization by the OS is required in the following cases:

Constitution of a new Regulatory Area.

Modifying the composition of an existing regulation zone.

Inclusion/Exclusion of a programming unit with no active participation in service delivery.

Modification of the physical units that make up a programming unit included in the regulatory zone.

Enabling a new unit for active participation in regulation within an area.

The following requirements must be met for the authorization to create or modify a regulatory zone:

The size of the regulatory area, measured by its installed power, that must be equal to or greater than the required minimum that will be established and published by the Administration.

Correct information exchange of both real-time signals with the main and backup systems of the RCP, as well as programs and other information associated with this service with the Operator Information System System (SIOS).

Compliance with the technical control requirements set out in Annex I.

Successful test result that, in each case, is required by the OS. The description of the tests is included in Annex I.

For consideration of all the effects of a new regulatory area or changes in existing regulatory areas, the controller must have the express authorization of the OS.

In regulation zones only manageable character programming units can be incorporated.

The condition of enabling a regulatory area shall be without effect in the event that none of the integrated production units in that area has a recognised technical capacity for the active provision of the regulatory area. secondary regulation.

4.2 Enabling units for bid presentation and active participation in regulation. -Within the set of generation programming units integrated into a regulatory area, they can only offer this complementary service and respond to the slogans sent by the AGC those units enabled for this by the OS.

The following requirements must be met for enablement:

Communication to the OS of the additional information required for these units in the Operation Procedure establishing the exchange of information with the OS and updating thereof when any information is produced variation.

In the case of production facilities belonging to the special management regime, the corresponding resolution of the General Directorate of Energy Policy and Mines that authorizes the participation in the system adjustment services of a potestative nature.

Membership of a single regulatory zone.

Correct communication between the production unit, the AGC of the regulatory zone, and the primary and backup systems of the RCP.

Compliance with the technical requirements for active participation in the secondary regulation service (Annex I).

Successful result of the response assessment tests of the defined zone to the effect, as to composition, by the OS.

For the acceptance of offers and consideration for all the effects of participation in the secondary regulation of a production unit, the controller of the regulatory area must have the express authorization of the OS.

Production units are required to communicate and keep updated the information required by the OS in the operating procedure for which the information exchanged by the OS is established, in order to allow the appropriate operation of the secondary regulation service.

The OS may withdraw any of the above authorisations and ratings when it detects a lack of technical capacity for the provision of the service, the quality of the service provided does not comply with the requirements or do not receive the information of changes or modifications that may affect the provision of the supplementary service.

4.3 Information to be provided to the System Operator. -Those units of production that wish to participate in the provision of the secondary regulation service within an area, shall provide the OS with all the information available technique on its frequency-power regulation system. This information should describe in detail and clearly the primary frequency regulator, the secondary loop of frequency-power regulation and its connection with the AGC, those components of the central that intervene in the regulation. (turbines, boilers, etc.) and automatisms and protection which may affect the regulatory system in accordance with the procedure laid down in the procedure for the exchange of information with the OS, in order to exercise the functions it has (i) The information provided should be sufficiently detailed in order to be able to reproduce by simulation, with reasonable accuracy, the actual operation by means of a model of the regulatory system. In the operating procedure for which the information exchanged by the OS is established, the information to be supplied by the units wishing to be enabled is detailed.

Regulatory areas are required to communicate and keep updated the information required by the OS in the operating procedure for which the information exchanged by the OS is established, in order to allow the appropriate operation of secondary system regulation.

The OS will keep up to date a list of the regulatory areas authorised for the provision of the secondary secondary regulation service, indicating for each of them the production units integrated into the same (list of generation programming units and physical units that compose them). This relationship will identify the production units that are enabled for the provision of this service.

This information will be provided to those responsible for each of the regulated zones, and to other subjects of the electrical system with due respect for the conditions of confidentiality of information in force. Any modification affecting the composition of the regulatory areas shall be communicated to the controller of the regulatory area concerned.

4.4 Transfer of control to the backup system. -In situations that make it impossible to implement the program correctly from the main secondary regulation system, the OS will transfer its control to the system support as soon as possible. This will be communicated by the OS to the companies responsible for the regulatory areas.

The step from the master regulator to the backup system, and vice versa, will force the companies responsible for the different regulatory zones to switch the signal-receiving communications channel to the system that in That time manages the supplemental service.

5. System operator functions relating to secondary secondary regulation service

The OS functions associated with the secondary regulatory supplemental service are:

Authorize the constitution and modification of regulatory zones.

Enable production units to actively participate in service delivery.

Determine and communicate daily to market subjects the required global reserve in the system for each programming period of the following day. Establish the reserve ratio to be up and down required for the regulatory areas and the maximum and minimum value of the eligible regulatory band in each bid as provided for in the procedures for establishing the criteria system operation and security.

Manage the secondary regulatory band market.

As responsible for the master control system (RCP):

Evaluate the regulatory requirement in real time and establish the distribution between the regulatory zones.

Track the response of regulatory zones.

Transfer the secondary regulation system to the backup system, and vice versa, when necessary, and report this fact promptly to those responsible for the regulatory zones.

Calculate the terms set for the remuneration and cost allocation for the provision of the regulatory service.

Ensure the proper functioning of the regulatory system and its adequacy to the requirements of the electrical system.

6. Submission of service offerings and allocation

6.1 Bid submission. -Market subjects responsible for regulatory areas may submit, for enabled generation programming units (each consisting of one or more production units) (a) the provision of the service (s) included in its regulatory area, secondary regulatory power band offers, in MW, with its corresponding price, in €/MW, for each of the programming periods of the following day.

In the case of programming units that integrate energy from installations belonging to the special regime, in each of the time periods for which the programming unit is enabled, the sum of the blocks, to be raised or to be lowered, that the component must be equal to or greater than 5 MW.

The bids must respect the maximum prices that, if any, can be established and published by the competent authority in the field of electrical energy, prior to the report of the National Energy Commission.

These offers shall contain the information set out in Annex II to this procedure.

The agent responsible for each regulatory area may thus present for each enabled programming unit included in its zone an offer of secondary regulation power band composed of different blocks, being able to be only one of them indivisible. These blocks can be accepted independently, with the result of the allocation to each programming unit the set of all the blocks accepted for the same.

The relationship between the reservation to be raised and down from an offer may be different from the one set by the OS globally for the system set and for each regulatory zone.

6.2 Assignment Criteria-The OS will assign those offers that, as a whole, represent a lower total cost.

The following criteria will be considered for the offer allocation:

Each throttling zone must meet the established relationship between the reservation to be raised and down for the system set.

For the valuation of an offer the offer price of the power band will be taken into account.

In the case of equal pricing of several bids, a proportional distribution of the allocated reserve shall be made, depending on the band offered in each of them.

If the allocation of a secondary regulation offering with its associated redispatch, if any, creates a technical constraint on the system, it will not be considered in the allocation process

The total sum of the assigned power bands shall be within a range of +/-10% around the total regulatory band required.

The allocation to each regulatory zone will be the sum of the allocations made to the generation programming units integrated into the corresponding zone.

The allocation made by the OS will be considered to be firm, acquiring the regulatory area with the obligation to dispose of the assigned band.

If to obtain the assigned secondary regulation power band a power redispatch is required on the program assigned to that programming unit in the Provisional Viable Program (PVP), the agent responsible for This programming unit must go to the Intradiary Market to obtain the necessary redispatch.

In case you have not been able to obtain it having participated in the Intradiary Market as a price taker, the agent responsible for that programming unit will communicate it to the OS indicating the necessary redispatch. In this case, the OS will modify the program of the corresponding programming unit according to the needs of the redispatch and will solve the carelessness provoked by the convocation of the market for management of deviations, and if the conditions do not exist necessary for this call, it will resolve the real-time neglect by allocating, where appropriate, the reserve of tertiary regulation, incurring the affected agent at the cost of the corresponding deviation.

6.3 Communication of the results of the allocation. -The OS, within the deadlines set in the operating procedure establishing the process of programming of the generation, will communicate the results of the allocation process of secondary regulatory power band offers to the responsible producers of each programming unit and to those responsible for the regulatory areas in which they are included.

The OS will also communicate to those responsible for each regulatory area, for each programming period of the following day, the coefficients of participation of that zone in the reserve requirements of secondary regulation. of the Spanish peninsular electrical system, resulting from the process of allocating secondary regulation power band offers.

6.4 Failure and Claim Solution for Bid Allocation Process. -Once the result of the secondary regulation power band offer allocation process is published, the subjects responsible for the Regulatory areas may submit complaints to this process, through the Application of Claims Management made available to them for these purposes by the OS, and may advance the information regarding the existence of this claim, by telephone, fax or e-mail, where necessary, in any case, the existence of an express formal communication through the IT application of claims management, or by a written means (fax or email), for final consideration as a formal complaint.

The OS will manage, as soon as possible, these claims or any anomalies that could have been identified in the offer allocation process, proceeding with a new allocation process, in case the solution of the anomaly as necessary, provided that this is possible, with due respect to the maximum allowable time limits established and published by the OS, to ensure that the subsequent ones are not negatively affected operation programming processes.

7. Exceptional allocation mechanism

In emergency situations for the system or in the absence of sufficient offers or unavailability of the management system, the OS may take the decisions it considers most appropriate for the use of the reservation of secondary regulation available in the system, subsequently justifying its actions to the market participants concerned and to the National Energy Commission, without prejudice to the remuneration to which it would have been paid for the abovementioned benefit required by the service and by the modifications of the production programmes which would have been required.

8. Backup Reallocation Mechanism in Band Loss Cases by Track of OS Instructions in Real Time

The application of the mechanism for the solution of technical restrictions in real time, contemplated in the procedure of operation by which the solution of the technical restrictions is established, on units of programming generation which had previously acquired firm commitments to reserve secondary regulation, having been assigned offers in the secondary regulatory band market, may result in breaches of such commitments by the corresponding regulatory area, for reasons other than the agent itself.

Also, the allocation of power redispatches by emergency mechanisms after the allocation of secondary regulation reserve [allocation of tertiary regulation reserve or management of deviations by application of the Exceptional Resolution Mechanism (MER)], as set out in the operating procedures, may cause the generation programming units to have a total or partial loss of the committed secondary regulatory power band.

In these situations, and since the service delivery is performed at the regulatory and non-programming zone level, in case of sufficient additional reserve of secondary regulation, the regulatory area will be able to deal with other of its groups enabled with the acquired secondary regulation band commitments.

However, if the regulatory area does not have sufficient additional means, the application of a specific mechanism allowing the owner of the regulatory area to apply for the reduction of the band secondary regulation committed in the secondary market of secondary band on day D-1 in order to avoid non-compliance with the provision of the secondary regulatory service, caused both by the application of the restriction mechanism in real time as per application of emergency mechanisms in real time on units of generation programming included in their zone and that they had acquired high-regulatory power band commitments.

This mechanism is described in more detail in Annex IV in order to avoid non-compliance with regulatory areas due to causes outside the scope.

9. Real-time tracking of service delivery

The control of the secondary regulation response and the measure of the service provided shall be carried out by regulatory areas, in accordance with the Regulation of Secondary Regulation (Annex III).

This document establishes the process of monitoring the response of the regulatory zones as well as the calculation of the reserves made available to the regulation for the zones and the energy of regulation used in each programming period.

10. Liquidation of the service

This section describes in general terms the main aspects of the supplementary secondary regulation service which have a direct impact on the liquidation of this supplementary service.

The provision of the secondary regulation service will be associated with three settlement concepts:

Secondary regulation reserve allocation in the corresponding market.

A variation of the secondary regulation reserve available in real time with respect to the allocated one.

Net effective energy of secondary regulation carried out following regulatory requirements, in the corresponding programming period.

The liquidation of the Complementary Secondary Regulation Service will give rise to the payment entitlements and payment obligations defined in the operating procedure for which the payment entitlements are established and the payment obligations for the system tuning services.

The measures and prices applicable to the provision of the secondary secondary regulation service are detailed below.

10.1 Secondary regulation reserve allocation. -The secondary regulation reserve allocation to be settled will be the result of the allocation process described in paragraph 6.2 of this procedure, and will be valued at marginal price resulting from the allocation process.

The marginal price of the secondary regulation reserve allocation, which will be established for each programming period, will correspond to the price of the last secondary regulation offer that has been required to be allocated Total or partial form in the corresponding programming period, to cover the requirements of the global reserve for secondary regulation of the Spanish peninsular electricity system.

10.2 Variation of secondary regulation reserve by the functioning of secondary regulation in real time. -As a result of the follow-up performed by the RCP of the response of each regulatory area in real time to each programming period, the following measures shall be determined:

Inability to contribute to the regulation by the area according to the number of cycles in which the regulatory area remains in the OFF state (except for those where it is indicated by the OS), being valued such incapacity at the price of the secondary regulation reserve corresponding to that period, affected by a KS coefficient of value equal to 1,5.

Residual reserves placed at the service of secondary regulation: the value of the residual reserve in each sense of the regulatory requirement shall be calculated in each cycle and shall be assessed in overall terms of the reporting period programming if the value of the residual reserve to be raised (or to be lowered) is higher or lower than the band to be raised (or to be lowered) allocated to that regulatory area. The residual reserve values higher or lower than the allocated reserve shall be valued at the price of the secondary regulation reserve for each programming period, affected by a KS coefficient of value equal to 1,5 in both cases.

10.3 Net effective energy carried out by monitoring regulatory requirements. -Net effective secondary regulation energy performed in each programming period as a result of real-time monitoring of the requirements of secondary regulation shall be assessed, in general, at the marginal price of the tertiary regulatory energy which it would have been necessary to allocate in that programming period, either to rise or to fall, to replace the Secondary regulatory net energy realized.

The marginal price of replacement energy to be increased in that programming period will always be established on the tertiary regulatory ladder to be uploaded, irrespective of whether or not regulatory energy has been used. tertiary to be higher in that programming period.

The marginal price of replacement energy to be lowered in that programming period will always be set on the tertiary regulation ladder to be lowered, irrespective of whether or not regulatory energy has been used. It would be lower in this programming period. The marginal time price of the secondary regulation energy to be lowered so calculated shall in any case be limited by the maximum price value (FVC) in force in the Daily Market.

10.4 Liquidation of band assignments and redispatches by application of the exceptional resolution mechanism (MER). -Power band allocations by application of the exceptional resolution mechanism (MER) that has been In each programming period to obtain the required reserve of regulation, they will be valued at a price equal to the one resulting from the application of a coefficient of mayorityKMAY, of equal value to 1,15 for the marginal price of the band in the corresponding time period or, failing that, for the maximum band price of the same hour in the previous seven days.

The power redispatches required to obtain the power band assigned by application of the exceptional resolution mechanism (MER) shall be valued:

For power redispatches to be uploaded: At a price equal to the result of applying a KMAY capital ratio equal to 1.15, for the marginal daily market time price.

For power redispatches to be lowered: At a price equal to the result of applying a KMIN minoring coefficient, of equal value to 0.85, for the marginal daily market time price.

10.5 Distribution of the costs arising from the provision of the secondary regulation service. The settlement of the costs arising from the provision of the supplementary secondary regulation service will be passed on with the criteria specified in the operating procedure establishing the payment entitlements and the payment obligations for the system adjustment services.

ANNEX I

Technical requirements for secondary regulation service

In all cases, it is a precondition for the OS to have the installation information set out in the current regulations (Operation Procedure 9)

1. Requirements for the establishment of a new secondary regulatory area. -For the establishment of a new secondary regulatory area, the production units which make up the secondary regulatory area, depending on whether they are active or not in the provision of the service, should comply with the applicable information requirements in each case. Additionally the zone as a whole should verify:

Compliance with the technical and functional requirements of the Control Center in the current regulations.

Existence of units enabled for active participation in the service within the regulatory zone.

Successful test result that, in each case, is required by the OS. The description of the tests is included in paragraph 4.

2. Requirements for the inclusion of generating units without active participation in the secondary regulation service. -For the inclusion of a generation unit in a regulatory area without active participation in the regulatory service, it must verify all the technical and communication requirements for information established by the current regulations. In particular you must credit:

The express compliance of the holder of the regulatory area for inclusion in the case of units whose ownership does not match that of the holding company in the regulatory area.

Reception at the real-time OS control centers of the net power poured into the network by the generation unit (s) that are included in the zone by the links between the OS and the generation dispatch of the regulation. The collection of signals from the generating units and their dispatch to the control centre of the area shall be carried out by means of their own.

Availability in the SIOS of the net power schedules of those generation units.

Net annual energy generated in the previous two years. In the case of new units, estimated values shall be reported from the planned operating system.

Manageable character of the units to be included in the case of special regime membership

3. Requirements for active participation in the secondary regulation service. -For the enabling of a production unit for active participation in secondary regulation, it must verify all technical and communication requirements the information established by the current regulations and to overcome the testing of the response assessment in the unit itself and/or the regulatory area (new or existing) in which it is included. These tests are described in paragraph 4.

In addition, in the case of installations belonging to the special scheme, it must be verified that the programming unit provides an offer capacity for the provision of this service not less than 5 MW.

4. Tests for the assessment of the response to the provision of secondary regulation service. The purpose of the test is to verify that a regulatory area is capable of exchanging the signals required both with the master of the regulation as with the backup, in addition to responding satisfactorily to the regulatory requirements sent from the System Operator control system.

The test will directly affect the regulatory area involved and its composition of the test zone will be established by the OS which will communicate to the area responsible the units that must be under control of the AGC during the test. same.

The test will be performed on the agreed date between the OS and the Regulatory Area and both its start and its development will be conditioned at all times to maintain the necessary safety conditions for the correct operation of the electrical system.

During the test, the correct exchange of all the signals of regulation between the AGC of the zone and both the host and the backup of the regulation (RCP) will be checked.

Regulatory requirements will then be sent to the test area and your response will be recorded. With the data recorded during the test, the response quality of the units subject to the test shall be analysed.

The OS will issue a report on the development of the test where the following parameters will be collected at least:

the response rate of the groups in control of the zone to both go up and down generation.

retards in the response in case of existing as the regulatory zone.

upper and lower limits of net power between which, in case of successful outcome, the group is enabled to serve in each possible configuration.

The controller of the regulatory area under the test shall transmit to the OS the records collected at its control centre during the test in order to be included in the report described above.

ANNEX II

Allocating secondary regulatory supplemental service

1. Input data to the allocation process

1.1 Secondary regulation requirements of the system. -The OS will determine and communicate daily to market subjects the global reserve of secondary regulation required in the Spanish peninsular electricity system for each the next day's programming period. In addition, it shall establish the reserve ratio to be up and down required for the regulatory areas, and the maximum and minimum allowable power band value in each offer. To this end, the OS shall follow the criteria laid down in the procedures laying down the performance and safety criteria for the operation of the electrical system.

The information communicated to market subjects will be composed of the following data:

Backup requirement to be uploaded on the RSSUBh (MW) system.

Reserve requirement to be dropped on the RSBLOW (MW) system.

Maximum and minimum value of the secondary regulation power band per offer (sum of the reserve to be raised and dropped for each individual offer), respectively referred to as RSBANmax (MW) and RSBANmin (MW),

where h = The corresponding programming period index.

1.2 Provisional Viable Program (PVP). -In the allocation process, to establish the operating point of each production unit, the energy values of the Provisional Viable Program (PVP) are taken into consideration. each generation programming unit (j), and for each programming period (h):

PVPhj

1.3 Integration in Regulatory Areas. -For the submission of secondary regulation reserve offers, the programming unit must be enabled in advance by the OS, with 100% of the unit of the unit being integrated. programming in a single regulatory area which must have also been previously enabled as such by the OS.

1.4 Offers submitted by the producers. -The secondary regulation offers will be presented by the controller of the regulatory area in which the programming unit is included and will contain the following information:

Number of the offer.

Backup offer to upload RNSsubirh (MW).

Backup offer to download RNSbajarh (MW).

The price of the PSbandah (€/MW) regulation band offer. Tenders shall comply with the maximum prices which, where appropriate, may be established and published by the competent authority in the field of electrical energy.

Energy variation required for the PVP program, VEPh (+ /- MWh).

Offer indivisibility code.

The sum of the reservation to be raised and dropped from an offer (RNSsubirh + RNSbajarh) must comply with the maximum and minimum limits reported by the OS (RSBANmax and RSBANmin).

2. Allocation of secondary regulation reserve offerings: Operation of the allocation algorithm

2.1 General criteria.-For the allocation of the secondary regulation reserve the following criteria will be taken into account:

Each regulatory zone must meet in each programming period the ratio between the reserve to be raised and to the lower set RSBh (RSBh = RSSUBh/RSBLOW (p.u.)).

The resulting offer allocation will be the lowest cost that meets the requirement of the secondary secondary regulation backup service.

The cost of a secondary regulation reservation offer will be the product of the total band offered for the bid price.

2.2 Process Development-The assignment process covers the following steps sequentially:

Those offering blocks that do not meet the minimum and maximum values of the bid band set by the OS are removed from the process.

If RSBANmax < RNSsubirhni + RNSbajarhni, the n block of the i offering is removed.

If RSBANmin > RNSsubirhni + RNSbajarhni, the n block of the i offering is removed.

A cost-ordered list of the received offer blocks is set for each programming period (h), the cost being calculated as:

Costehr = PSbandahr * 1000

where r = Index that takes a variable value from 1 to the total number of valid blocks accepted.

The requirement set according to the priority defined by the ordered list is assigned. In each allocation of the block of an offer, the relationship between the reserve to be raised and the reserve to be lowered for the zone of regulation to which the offer belongs, truncating the values to the contrary and remaining, must be guaranteed. the truncated value to be allocated in subsequent iterations. Therefore, for each offer block you will be satisfied:

Rsubirnh = Minimum [RNSsubirnh + RNSsubirmh, (RNSbajarnh + RNSbajarmh) * RSBh]-Rsubirmh

Rbajarnh = Minimum [(RNSsubirnh + RNSsubirmh) /RSBh, RNSbajarnh + RNSbajarmh]-Rbajarmh

Where:

n = Offer block index based on cost ordered list.

m = The index of the order offering blocks less than n, in the same regulatory zone to which the programming unit in which the order offering block is included belongs.

Rsubirnh = Band to be uploaded to the order offering block n.

Rbajarnh = Band to be dropped assigned to order offering block n.

In case the offer block to assign includes the status of indivisibility, and the assignment of the same assumes the default of the raise/lower ratio set for the zone of regulation to which the offer, its assignment will be postponed, given its status as indivisible, pending its possible assignment in subsequent iterations.

The reserve allocation process to be raised and down ends when the value of Rsubirn and Rbajarn allocated is in the range of ± 10% around the value of the secondary regulation reserve set as requirement (RSSUBh and RSBLOW):

1.1 *RSSUBh > Rsubirnh > 0.9 * RSSUBh

1.1 *RSLOW > Rbajarnh > 0.9 * RSLOW

In the event of a cost equality between multiple offers at the closing of the allocation, the closing value will be apportioned in proportion to the bands offered.

The total secondary regulation reserve allocation for each regulatory zone, will correspond to the sum of all allocations made to generation programming units belonging to that zone.

The secondary regulation reserve allocation coefficients by regulation zone will be calculated according to the following formula:

KZR = Rsubirt/RSSUB * 100

where:

ZR = Regulatory Zone Code.

t = Index of allocated offers belonging to the ZR regulatory zone.

3. Validation of secondary regulation offerings

Prior to the offer reading process, it will be checked that the programming unit and the regulatory zone to which it belongs are enabled for the provision of the secondary throttling service.

Both during the reading process of the secondary regulation reserve offerings and in the allocation of those offers, a series of checks are applied. The violation of any of them will cause the offer to be rejected in whole or in part.

The failure to comply with the checks carried out in the automatic process of reading the offer implies its rejection, without it being able to contribute, due to the characteristics of the process itself, precise information about the cause of the rejection. Conversely, rejected or truncated offers in the process immediately prior to the application of the allocation algorithm, or in the allocation process itself, are associated with a rejection code, visible in the last column on the screen of assignments.

Checks are performed in four different stages.

During the process of reading the offers.

In preprocessing of offers prior to application of the allocation algorithm.

In the allocation process itself.

At the end of the allocation process.

The applied checks are described below, as well as the reject codes associated with each one.

3.1 Checks applied in the process of reading the offers. -In this market a single offer per unit of programming of generation is supported, composed of an unlimited number of blocks that can offer band to increase and/or download for one or more programming periods.

The following restrictions are contemplated for offers, which are violated by the rejection of the affected offer block:

The offer price of each block must not exceed the maximum price of the secondary regulation band established and published, if any, by the competent authority in the field of electrical energy prior to the report of the National Energy Commission.

The sum of the band to be raised and lowered from each block must be between the maximum and minimum bands reported by the OS together with the reserve requirements.

The generation programming unit for which a secondary regulation reserve offer is submitted must be integrated into a single regulatory area, with the offer to be submitted by the person responsible for that area of regulation.

The programming periods for which the secondary regulation reserve offer is made must be included in the current open market horizon.

In the case of programming units that integrate energy from installations belonging to the special regime, in each of the time periods for which the offer is submitted, the sum of the blocks, to be raised or to be lowered, that the make up 10 MW or more.

No generation programming unit offers will be accepted for regular.

3.2 Checks on preprocessing of offers. -These checks are made immediately prior to application of the offer allocation algorithm, requiring consideration of information such as limitations of the program for security and inavailabilities of generation, which may have been modified since the time the offers were read.

The checks performed at this stage are as follows:

That the generation programming unit does not violate any security limitations.

That the generation programming unit does not violate any unavailability limitation (communicated by the agent responsible for the programming unit or, failing that, entered by the OS, after prior communication from the agent).

When an offer block fails to comply with any of these checks, the block will be completely rejected, regardless of whether it is divisible or indivisible.

The blocks corresponding to the secondary regulation reserve offerings may have an energy redispatch associated with the value of this redispatch when performing the validation process. The redispatch is associated with the block and is treated independently for each of them.

3.3 Checks made during the allocation process. -These checks are performed by the allocation algorithm itself, and affect those offer blocks that, for price, should be allocated.

The associated checks are as follows:

Offer not allocated in full for not being able to compensate with offers from its same regulatory zone to maintain the set up/down ratio.

Rejection by indivisibility on closing offer. This rejection takes place in the final pro rata versus other offers at the same cost. The divisible offers are sufficient to meet the requirements, so the indivisible ones are not assigned.

Divisible offer not assigned by being displaced by an indivisible. In the final prorate, if there are divisible and indivisible offers of a regulatory area at the same price, the divisible ones are assigned in the first place and, if the requirements are not met, then the indivisible ones are assigned. If they exceed the maximum of 10% on the requirement published for this programming period, it will be possible to withdraw divisible offers until the set of offers allocated is within the margin of +/-10% compared to the published requirement.

3.4 Checks made at the end of the allocation process. -After the allocation process is complete, the following rounding and assignment checks are performed that can slightly alter the result of the allocation derived from the direct application of the algorithm:

Indivisible allocation: To those indivisible blocks assigned to which they are left to assign band, in a single sense (to go up or down, but not in both), below a certain value (currently 2 MW) they are assigned this pending band.

Rejection by minimum allocation: To those offers that have been assigned a single-purpose band (to be moved up or down but not in both), below a certain minimum value (currently 1 MW), they are eliminated from the assignment.

Assignment Rounding: Assigned bands are rounded up to get whole numbers. Rounding is done to the nearest integer value. Thus, for example, 22.4 would be rounded to 22 and 22.5 or 22.6 to 23. In no case the resulting value of the rounding can be higher than the initial offering.

ANNEX III

Secondary regulation regulation

1. Introduction

The proper functioning of interconnected electrical systems, from the point of view of the safety and reliability of the operation, requires proper coordination of its frequency-power regulation.

Secondary regulation is part of the automatic frequency-power control systems.

The Spanish electricity system is part of the interconnected European synchronous network and is therefore obliged to comply with the requirements laid down by the UCTE, a body responsible for coordinating this network.

The objective of secondary regulation is, after an incident, to return frequency and exchanges with other systems to the slogan values by restoring the primary reservation used. To do this, the throttling system generates the appropriate control signals to modify the load status of the groups connected to it so that:

The value of power exchanges with other systems is maintained at the scheduled value.

The system frequency value is maintained at its common and unique slogan value in the UCTE synchronous network.

Compliance with the above objectives is equivalent to maintaining the overall demand-demand balance of the interconnected system.

The secondary regulation system in Spain is a hierarchical system where there is a master regulator that sends its control signals to systems that, in turn, control the production units connected to each of them. The system of the Peninsular Shared Regulation, coordinated and controlled by the OS, plays the role of master regulator. Each regulator connected to it, AGC (Automatic Generation Control System), coordinates and controls the set of production units that constitute a regulatory area. In order to perform this function, the OS shall have adequate means and information to assess the total system regulatory requirement and to transmit to the area regulators the power values to be provided.

The OS establishes for each programming period the secondary regulation reserve required by the system to both go up and down. This reserve requirement is provided by the allocation of bids in the corresponding secondary regulation band market. The nominal allocation of the total system requirement shall be equal to that obtained in the bid allocation process for the relevant secondary regulatory band market for the programming period considered.

In situations where, for security reasons, the secondary regulation reserve allocation cannot be made with economic criteria, the emergency mechanisms that are regulated shall apply.

The installation and maintenance of the zone regulatory equipment and the communication channels with the "Master Regulator" will be the responsibility of the company responsible for each regulatory area, up to its border with the OS.

The RCP master regulation system will have a main system in the CECOEL of the OS and a system of support in CECORE, located in Tres Cantos (Madrid) that will assume the role of "Master Regulator" in case of unavailability of the principal.

2. Secondary regulation band allocation

2.1 Concept and needs.-The secondary regulation reserve available in the system to be raised/lowered is the maximum increase/power reduction value in which it is possible to automatically modify the generation of the system under the control of the secondary regulation system, in accordance with the speed requirements set out in the following paragraph.

At every moment, the secondary regulation reserve available in the system will be the sum of the reserves in each of the zones that verify a proper follow-up of the requests of the regulatory system.

2.1.1 Regulatory Area Response Model. The response rate required for the set of regulatory units-production units involved in the regulation is uniformly established for all areas that participate in the regulation.

Zone regulators must be of the integral or proportional-integral type, fixing the response tracking time constant in 100 seconds. That is, it is established as a model of behavior in the regulation to monitor the requests issued by each zone regulator with an equivalent response to that of a linear system with a time constant of 100 seconds.

The regulatory system will compare the real-time response of each regulatory zone to the previous model to establish whether its response is adequate or not and determine its regulatory status accordingly.

2.2 Regulatory Required Reserve. -Depending on the expected situation in each programming period, the OS will set the RNTS positive (up) and negative RNTB (down) power reserve required on the system set Spanish peninsular electricity, as set out in the operating procedures for establishing the operating and safety criteria for the operation of the electrical system.

2.3 Reserve allocation. -As part of the Diaria Programming process, allocations of secondary regulation reserves will be established for programming periods, both for the Spanish peninsular system as a whole as for each generation programming unit, depending on the offers of the units enabled for the provision of this service that the OS receives from those responsible for the regulatory zones in which each of these units is integrated generation programming units.

Once these offers are assigned, the reserves assigned to each regulatory zone will be determined.

If the circumstances of the real-time operation require new secondary regulation reserve allocations, the OS will allocate more secondary regulation reserve among the generation programming units. enabled for the provision of the service, in accordance with established regulatory procedures.

2.4 Rebirth of reserves between regulatory zones.-The secondary regulation reserve obligation of each zone in each programming period shall be the arithmetic sum of the individually assigned values in the band market of secondary regulation, to the different generation programming units integrated into that regulatory area.

In each programming period, the Peninsular Shared Regulation system shall have the following values for each of the regulatory zones:

RASi: Reserve assigned to move up to zone i.

RABi: Reserve assigned to go down to zone i.

KAi: Coefficient of nominal participation of zone i in the regulation of the Spanish peninsular system.

3. Operation of the master regulator (RCP)

3.1 Evaluation of the system regulation requirement. -The CPR system, in each cycle, evaluates the electrical system area control error:

ACE = FNIDR-Bgrout f

where

FNIDR: Filtering value of the detour in the system interconnections with respect to its scheduled value.

B (MW/Hz): The "bias" constant of the system allocated by the UCTE.

tif f: Dismissed frequency with respect to its watchword value.

Depending on the calculated ACE value and the status of each throttling zone, the PRR regulation requirement is calculated to be distributed.

3.2 Determination of the state of the regulatory zones. -Possible states for a regulatory zone are:

OFF STATUS: Incapacity to contribute to the regulation by the zone. One of the possible causes is the unavailability of the area AGC.

OFF BY ORDER OF THE OS: The system considers, at the request of the OS or as a consequence of the condition of the operation or unavailability of equipment under the responsibility of the OS, inability to participate in the regulation by the area. This status will be equivalent to OFF mode for all purposes, except that it will not be computed as time in OFF.

INACTIVE STATE: Transitional absence of participation in the Peninsular Shared Regulation due to technical failures, mainly in communication channels. If this situation is maintained for a certain number of cycles (see Technical Instruction published by the OS), the regulatory area will be switched to OFF, if the problem is to be solved, or to OFF by order of the OS, in case you are responsible for this failure.

EMER STATE: Lack of adequate follow-up to the requests of the Shared Regulation due to the depletion of the reserve of the regulatory area or an insufficient response rate of the regulation.

ACTIV STATUS: Correct tracking of High Regulation requests.

3.3 Calculation of the regulation requirement to the zones. -Once the requirement for total system regulation is calculated and taking into account that the error signal of the regulator of each zone is calculated:

ACEi =	1	NIDi-Bi grout f + CRRi
	G

where:

ACEi: Zone area control error i.

NIDi: Unsaw from zone i generation regarding your program.

Bi: A constant of "bias" assigned to zone i of regulation.

CRRi: Required contribution to regulation for zone i,

the RCP system will calculate the value of the RCP to be sent to each regulatory area in a way that ensures that the set of regulatory zones contribute sufficiently to the total system requirement. This shall be used as nominal distribution coefficients calculated on the basis of the allocations of the corresponding regulatory band market. These nominal coefficients will be modified according to the zones ' regulatory states and their capacity to respond adequately to the requirement.

The algorithm of the RCP regulation system is described in detail in the corresponding Technical Instruction published by the OS.

3.4 Supplementary margin allocation. -In each algorithm cycle, the master regulator will evaluate the total reserve available in the system and, if insufficient, reallocate reserve among the areas that credit availability of the same. On the basis of such reallocation, this reserve shall be considered in the same way as the reserve allocated in the relevant regulatory band market.

ANNEX IV

Reallocation of Band by Application of the Exceptional Resolution Mechanism (MER)

The owner of a regulatory zone in which one or more affected programming units are integrated either by the application of security constraints in real time or by the allocation of backup redispatches Tertiary regulation or diversion management by application of MER, may request the OS to implement the secondary regulation band reduction mechanism to avoid non-compliance with the band commitment acquired in the PVD by its area of regulation.

After the affected band reduction request by the affected regulatory zone owner, the OS will analyze, both individually for each production unit, and globally for the set of the corresponding regulatory area, the reduction of the band requested by the owner of the regulatory area, in contrast to the theoretically lost power band due to the application of security constraints for the solution of restrictions in real time or by allocation of energy redispatches (tertiary or diversions) by application of the MER.

The maximum secondary regulation reserve band to be reduced will be calculated in each programming period as the minimum of the two previous values for each production unit.

The band reduction mechanism will only be applied when the security limitation or in its case the energy redispatch by MER covers a full programming period, and the agent's request is received by the OS at least 15 minutes before the start of the first programming period in which it would be applicable.

Once the secondary regulation band reduction is validated by the OS in the different integrated production units in the corresponding regulatory area, the following actions will be performed:

The corresponding secondary regulatory band disallocations will be generated, further establishing, based on the order of merit of the offer allocation made on D-1 day (current for day D), the reductions Additional band that may be required to be applied in the same regulatory area to maintain the set up/down ratio. All of these band deallocation annotations shall be associated with a price equal to the marginal of the current secondary regulatory band market for the corresponding D-day programming period.

The new nominal participation ratios of the regulatory zones will be calculated and sent to the SPC in line with the reduction of the regulatory band applied in each full programming period. The new nominal participation ratios of the zones shall be calculated taking into account the previous band misallocations, thus being referred to as these new coefficients to the resulting new regulatory reserve global value, after the total of D-1 day assignments are counted, the de-assignments described in the immediate point above.

In case the causes that caused the application of the band reduction mechanism disappear (reducing or disappearing the safety limitation or the allocation of the tertiary allocation energy redispatch) or deviations per MER that caused a non-compliance of the allocated power reserve band in D-1), and there has been no additional allocation of secondary regulation band in real time per MER, the OS may decide on the possible total refund or (a) partial of the band engaged in the PVD from the moment of acceptance of this action by the the responsible agent of the regulatory area, the nominal participation coefficients of the regulatory areas being calculated again, and the band deallocation annotations that may have been previously made on those areas being modified periods.

P. O. 7.3: "Tertiary Regulation"

1. Object

The purpose of this procedure is to regulate the complementary service of tertiary regulation of the Spanish peninsular electrical system. It sets out the criteria for the following aspects:

Provision of the service.

Assignment of the capability.

Control and measure of the capability.

Service Economic Settlement Criteria.

2. Scope of application

This procedure applies to the System Operator (OS), to the production facilities belonging to the ordinary regime and to the special management system and to the pumping consumption facilities.

3. Definitions

3.1 Tertiary regulation. -Tertiary regulation is a complementary service of a potential nature and offer, managed and remunerated by market mechanisms. It is intended to restore the reserve of secondary regulation which has been used, by adapting the operational programmes of the programming units concerned to production facilities and to installations of pumping consumption.

3.2 Tertiary regulation reserve. -A the effects of service delivery, the tertiary regulation reserve is defined as the maximum power variation to be raised or lowered which can be performed by a production unit or by a pump consumption unit within a maximum of 15 minutes, and which can be maintained for at least two consecutive hours.

At the global level of the Spanish peninsular electricity system, the total reserve of tertiary regulation is the set of tertiary regulatory reserves available in each and every programming unit corresponding to production facilities and pumping consumption facilities available in the Spanish peninsular electricity system.

4. Service providers

All those programming units that obtain the corresponding enablement of the System Operator, who will grant it to those programming units whose installation or installation will be able to participate in this complementary service, will be able to participate in this complementary service. set of physical facilities credit their corresponding technical and operational capacity for the provision of the service.

4.1 Enabling units for service delivery. -Interested production facilities must meet the following requirements to obtain the enablement:

Enrollment in the corresponding RAIPEE section.

Request to participate in the Tertiary Regulatory System Adjustment Service.

Integrating the production installation into a control center.

Communication to the OS of the additional information required for the providers of this service in the Operation Procedure establishing the exchange of information with the OS and updating it when it is produce any variation.

In the case of production facilities belonging to the special management regime, the corresponding resolution of the General Directorate of Energy Policy and Mines that authorizes the participation in the system adjustment services of a potestative nature.

Verification that the programming unit in which the production facility is integrated provides an offering capacity for the provision of this service not less than 10 MW.

satisfactory outcome of the OS analysis of the information specified in the operating procedure establishing the exchange of information with the OS presented for the purpose by the subject holder of the installation.

For the acceptance of tenders and consideration of all the effects of participation in the complementary service of tertiary regulation of a production unit, the person responsible for the installation must have the express authorization of the OS.

Production units are required to communicate and keep updated the information required by the OS in the relevant operating procedure to enable the proper functioning of the adjustment service. Tertiary regulation system.

The OS may withdraw any of the ratings previously granted when it detects a lack of technical capacity for the provision of the service, the quality of the service provided does not meet the requirements required or does not receive any change or modification information that might affect the delivery of this system tuning service.

5. Determination and publication of tertiary regulatory reserve requirements

The System Operator shall establish and publish the value of the required minimum tertiary regulatory reserve in the system for each programming period of the following day, in accordance with the operating procedure for which it is sets the reserve for frequency-power regulation.

6. Presentation of the tertiary regulatory offerings

The holders shall make available to the System Operator the information relating to the tertiary regulation reserve corresponding to their programming units entitled to the provision of this service, both to rise and to fall, in the form of offers of reserve of tertiary regulation to be raised and/or to be lowered, within the time limits fixed in the procedure of operation by which the programming of the generation is established.

Thus, all programming units corresponding to production facilities or pump consumption facilities available to meet the requirement for the reserve of tertiary regulation will be required to submit each day, within the scheduling process of the next day's operation, an offer of all its available tertiary regulation reserve, both to be raised and to be lowered, for each of the next day's programming periods.

This information on tertiary regulation reserves provided by the subject holders of the programming units providing this service shall be consistent with the structural information reported by the relevant subject to the Operator of the System, in accordance with the operating procedure establishing the exchange of information with the System Operator, as well as with the particular real-time situation of each physical unit of production and of pumping consumption that integrate the respective programming units.

The programming units for production facilities or for pumping consumption facilities should offer, for each programming period, all of their available reserve of tertiary regulation, both to increase To be lowered, in MW, and the corresponding energy price, in €/MWh.

Should the System Operator detect that the reserve of tertiary regulation available in the planned programme does not permit the necessary requirements to be met, it shall, in application of the procedure by which it is establishes the solution of the technical restrictions, the coupling of additional thermal groups, in order to allow the required reserve of tertiary regulation in the Spanish peninsular electrical system.

The bid price for the tertiary regulation reserve allocation to be lowered has a repurchase price character of the equivalent unproduced energy.

The bids shall respect the maximum prices which, if any, may be established and published by the authority of the competent authority in the field of electrical energy, after the National Energy Commission has submitted its report.

Tertiary regulation reserve offers may be limited in energy, so that their allocation over a given period may involve the cancellation or modification of the offer for subsequent periods. The limitation shall cover at least one programming period with the offer being cancelled in the following programming periods if it is allocated.

In Annex I to this procedure, the main criteria for validation of offers that are applied in the different phases of the allocation process are summarized.

7. Upgrading the tertiary regulation offerings

The holders of the production units of the service will have to update their offers of tertiary regulation, within the day of the operation, provided that their reservation has been modified by one of the Following causes:

Use of such capacity by allocations in the Intradiary Market (MI) or in the diversion management market.

Unavailability of the production unit or pump consumption.

Secondary regulation band contribution.

Other justified causes.

The period for updating the tertiary regulation offerings for each programming period will end in the 35th minute of the previous immediate programming period.

8. Allocation of tertiary regulation offerings

Annex II to this procedure summarizes the main characteristics of the algorithm used for the allocation of tertiary regulation offerings.

As general criteria, the following should be noted:

The System Operator will assign the service delivery with minimum cost criteria, taking into account existing offers at the time of assignment.

In case the allocation of a tertiary regulation offering originates a technical constraint on the system, it will not be allocated.

When assigned to a programming unit corresponding to production facilities or to production facilities, an offer of tertiary regulation in a sense, in the event that subsequently, within the same time, the need to allocate reserve of tertiary regulation to the opposite is present, the latter will be allocated by the reduction, first, of the allocations that had been made previously to the contrary, without affecting the the marginal price of the tertiary regulation reserve in this new sense, provided that partial or total deallocation is sufficient. The economic valuation of tertiary regulatory allocations to be raised and lowered shall be solely for the energy actually requested in the time interval at which the allocation has been maintained.

The allocation of a tertiary regulation reserve offer in a given instant, maintained over a certain period of time, is equivalent to the application of a power redispatch on the prior energy programme of the said reserve. programming unit. This redispatch is calculated on the basis of the product of the power variation associated with the supply of tertiary regulation allocated by the time in which the allocation is maintained. This will determine the scheduled tertiary regulation energy as the result of considering a 15-minute power variation ramp from the time of the offer allocation, remaining after these 15 minutes, the final value of power without variation up to the final point of allocation or, where appropriate, until the moment of the allocation of the previously allocated tertiary regulation offer, in the event that this deallocation takes place before the end of the instant allocation end time initially set.

9. Solution of failures and claims relating to the offer allocation process

Once the outcome of the tertiary regulation offer allocation process is published, the subject holders of the programming units will be able to submit claims to this process, using the Claims made available for these purposes by the Operator of the System, being able to advance the information regarding the existence of this claim through telephone communication, fax or e-mail, being necessary, in any case, the existence of an express formal communication through the application Claims management computing, or by a written means (fax or email), for final consideration as a formal complaint.

The System Operator will manage, as soon as possible, these claims or any anomalies that could have been identified in the offer allocation process, proceeding with a new allocation process, where the solution of the anomaly so requires, provided that this is possible, with due regard to the maximum allowable time limits set and published by the System Operator, to ensure that they are not negatively affected the subsequent programming processes of the operation.

10. Liquidation of the service

The economic treatment of the complementary service of tertiary regulation is defined in the operating procedure whereby payment entitlements and payment obligations are established by the adjustment services of the system.

10.1 Liquidation of service provision. -Programming units corresponding to production facilities or pump consumption facilities enabled for the provision of the supplementary regulatory service tertiary, they may modify their energy programme for the allocation of tertiary regulation offers.

The tertiary regulation energy used will be valued at the marginal price of the tertiary regulation offers allocated in each programming period, distinguishing the reserve to be raised from the reserve to be lowered, and being calculated that marginal price in accordance with the mechanism specified in Annex II to this procedure.

In the event of a technical restriction in real time, programming for the resolution offers of tertiary regulation, these offers will not intervene in the formation of the marginal price of the energy use Tertiary regulation in the corresponding programming period.

The same settlement criterion shall apply to that tertiary regulation reserve which, notwithstanding the obligation of the submission of such an offer, has not been offered and for which the System Operator has required the use of the relevant tertiary regulatory reserve. The System Operator will inform the National Energy Commission of these defaults in the offer of all tertiary regulation, both to upload and to lower, available in the unit.

10.2 Distribution of costs arising from the provision of the tertiary regulatory service.-The settlement of costs arising from the modification of the programme of programming units by the allocation of tenders Tertiary regulation shall be passed on in accordance with the criteria specified in the operating procedure establishing the payment entitlements and payment obligations for the system adjustment services.

11. Controlling the fulfillment of the assigned service

The System Operator will check compliance with the requested tertiary regulation requirement using the active power telemetry registered in its real-time power control system, verifying the suitability of the system. the responses of the programming unit for the production or pumping consumption facilities, both in terms of variation of the power (power step), and of the maximum time (15 minutes) in which the output is to be met. that power modification must take place.

12. Exceptional allocation mechanism

In cases where, for reasons of urgency, the absence of offers by force majeure, or otherwise unanticipated or controllable, the allocation of tertiary regulation offers is not possible, the System Operator may adopt the programming decisions it considers most appropriate, for the use of the tertiary regulatory reserve available in the system, subsequently justifying its actions to the subjects concerned and to the National Energy Commission, without prejudice to the remuneration to which the provision of the service would have been provided; and for the modifications of the programmes of the programming units corresponding to the production or pumping consumption facilities that are necessary.

Tertiary regulatory energy allocations that, if any, can be applied by the OS by exceptional allocation mechanism will be valued:

For tertiary regulatory energy allocations to be uploaded: At a price equal to the result of applying a KMAY shift coefficient, of equal value to 1.15 on the marginal time price resulting from the allocations Tertiary regulation to be raised in that time or, failing that, on the marginal price of the day-to-day market.

For tertiary regulatory energy allocations to be lowered: At a price equal to that resulting from applying a KMIN minoring coefficient, of equal value to 0.85 on the marginal time price resulting from the allocations of Tertiary regulation to be lowered that have been carried out in that hour or, failing that, on the marginal price of the daily market.

ANNEX I

Tertiary Regulation Reserve Bid Validation Criteria

The tenders submitted by the subject holders of the programming units for the provision of the complementary tertiary regulation service shall be subject to the validation criteria set out in this Annex.

The participation in this process will be carried out through the sending of blocks of offers for different programming periods, constituting the offers as the groupings of the blocks offered for the same period of programming.

1. Validation of the offering blocks

Only one offer per unit of programming for the sale of energy corresponding to generation units or per unit of programming for the purchase of energy for consumption of pumping for each date of convocation. In this way, if for the same call date more than once information is sent for the same programming unit, the last information will replace the previous one.

The offer must be sent by the subject holder of the scheduling unit to which the offer corresponds.

The time period covered by the offer must be included in the open call horizon in force at the time of receipt of the offer.

Only offers with a schedule date and period equal to or greater than the next programming period in progress, and covering all of the next day's programming periods, will be supported.

Each offer must respect the limitations of the maximum and minimum value of offer established and published in its case by the Operator of the System, after compliance of the National Energy Commission. Power band offers outside this range will be rejected.

Each of the blocks of an offer of tertiary regulation to be raised, must respect the maximum prices which, if any, can be established and published by the organ of the competent administration in the field of energy The report of the National Energy Commission.

In the case of programming units that integrate energy from installations belonging to the special regime, in each of the time periods for which the offer is submitted, the sum of the blocks, to be raised or to be lowered, that the compose must be equal to or greater than 5 MW.

If one or more blocks of a tertiary regulation offer have been allocated well in the tertiary regulation market, or for security to resolve a technical restriction identified in real time, only then will it be admitted after the receipt of new blocks that complement the offer, but not modifications of the already existing blocks at the time of the assignment.

In case of non-compliance with any of the validation criteria above, the offer will be rejected.

2. Pre-allocation checks for the offerings

These checks are carried out by the establishment of the Tertiary Regulatory Reserve Offering Stairs to be uploaded and lowered, and always prior to the allocation of tenders, by requiring the consideration of such information as program limitations for security and inavailability of production units, which may have been modified from the time the offers were read.

The checks that are performed prior to the allocation of the offers are as follows:

Non-violation of limits for security.

No violation of unavailability limitations (communicated by the subject holder of the service provider programming unit or, failing that, entered by the System Operator, after prior communication from the subject holder of that programming unit).

No violation of the physical power limits of the group (only in the case of thermal groups and pumping units).

Do not offer a power to lower your generation program, or for the programming units for power acquisition for pumping, power supply to go up higher than your pumping program.

When an offer block violates any of these limits, the block will be truncated to the point where it stops violating the limit.

In this market, when the duration assignments are less than a programming period, when the validation is applied, the power profile of the programming unit is taken into account.

ANNEX II

Tertiary Regulation Reserve Offer Allocation Algorithm

1. Fundamental characteristics of the allocation algorithm

The main features of this offer allocation algorithm are as follows:

The algorithm assigns power offerings (MW), not power.

The allocation process covers a particular programming period.

Supports duration assignments that are less than a programming period. In this case, the allocation horizon covers the period between the start and end minutes of the allocation set by the operator, or, until the end of the programming period in question, in the event that the operator does not explicitly set an allocation end-time other than the final instant of that programming period.

The marginalist market in which the price of the allocation of offers in each programming period is determined by the price of the highest price offer (or lower price, if it is a reserve of tertiary regulation). to be lowered) which has been allocated in a partial or total manner in that programming period.

A purely economic allocation process. The algorithm does not impose any constraints.

Indivisible offering blocks are not supported.

2. Description of the operation of the algorithm

The procedure used in the offer allocation process is as follows:

Build a list with all valid blocks that are offered in the programming period in question (Tertiary ladder to go up and down).

Ladder sorting by offer price:

The sort criteria depends on the type of offer. Thus, the blocks that offer the reserve of tertiary regulation to be increased are ordered from lower to higher price and those that offer reserve of tertiary regulation to lower are ordered from greater to lower price of offer.

When a pre-assignment was previously made, a tertiary regulation reserve allocation would have been performed in the opposite direction, preferably the previously allocated blocks. That is, to go in the opposite direction, you always deallocate what you previously assigned before you assign new offers in the opposite direction.

When multiple offer blocks exist at the same price, these are sorted by order of arrival of the offer files.

After the assignment is complete, the assigned power is converted into the corresponding power redispatch and the corresponding tertiary regulation power allocation is thus generated.

The price of the offer allocation depends on the offer type. Thus the allocations of the blocks that offer tertiary regulation to increase are associated to the marginal price of the reserve of tertiary regulation to increase, while those of the blocks that offer tertiary regulation to lower are associated to the price marginal of the tertiary regulation reserve to be lowered.

Although several sessions of the allocation of tertiary regulation reserve offerings are held within the same programming period, only a single marginal price of tertiary regulation will exist in that programming period. (if there have been offers of tertiary regulation offers to be raised in the programming period) and another of tertiary regulation to be lowered (if there has been an allocation in the programming period for which offers of tertiary regulation are to be lowered). These prices will be the extremes of the offer allocations made during the programming period (higher price offer, in the case of tertiary regulation to be increased, and offer of lower price, in the case of tertiary regulation to lower). It may be that there is no marginal price in some sense (going up or down), in the event that there has not been a need to allocate offers of such a ladder (tertiary ladder to rise or to go down), with only allocations and disallowances of offers on the opposite tertiary regulation ladder.

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, in the detail that comes in each case, the way in which the exchange of information between the System Operator (OS) and the different subjects of the Spanish electrical system will be carried out, the access to information, how to structure and organise it (databases), its character (public or confidential) and its subsequent processing (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.

Carriers.

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 considered 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 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, 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 System Operator 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 System Operator.

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 exercise its functions facilitating the analysis of safety and the electrical system performance studies.

4.1 Responsibilities. -The System Operator 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 subject holders or representatives of programming units for the sale of energy in the production market, consumers connected to the transport network, the carriers, the distributors, the managers of the distribution networks, they shall be obliged to supply 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 discharged into the electrical system managed by the System Operator. 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:

Common system and hydraulic groups.

Reservoirs.

Ordinary-speed thermal units.

Special regime units.

Non-Wind Groups.

Wind parks.

Transport Network:

Substations.

Parks.

Lines and cables.

Transformers.

Active or reactive power control elements.

Consumer installations.

Protections.

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 System Operator will define the computer support used and enable the templates of the data entry tabs with the required formats.

The System Operator 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 they are refers to 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 may 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 System Operator shall periodically make available to each subject the data of the elements of his or her property or those to whom it represents collected in the database in order to enable the subjects to check their appropriate 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 that 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 that will be able to have the data from the facilities located in the distribution network under their management scope.

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.

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 the System Operator Information Systems 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 information exchanges indicated in the preceding paragraph, 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 has a backup system in a different location of the main system. The System Operator 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 The power system will have the media with this backup center using the access modes defined by the System Operator.

5.1 Databases of information systems of the system operator. -The System Operator will maintain in its databases all the information necessary for the correct management of the operation programming, the system adjustment services and the management of international exchanges that are under their responsibility.

The SIOS databases will meet the following requirements:

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

b) All economic measures are referred to in EURO cent units (c€).

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

d) The referential integrity of the recorded data.

e) 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 Media exchange of information. -Communication between the OS, OM and 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 System Operator will publish the available electronic means of exchange of information and its characteristics, those new ones to be implemented and those that will be suspended, as well as the expected deadlines. 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 System Operator 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 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 authorization granted by the OS will be necessary according to the regulations in force. No authorization type will be required for the use of the public access service.

5.5.1.1 Private access service security. -At present, the private access service security system is based on the use of the following elements:

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. Also, in case of theft or loss, they must communicate this fact to the OS as soon as possible, so that they can 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 or market entity 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 Management.-The System Operator will be able to establish with the outside information exchanges in both directions:

Information communicated by the OS.

Information communicated to the OS.

The information exchanged by the OS may have different characters:

Public.

Confidential in terms of paragraph 5.3.4.

5.7 Information exchanges. -All exchanges of information will be carried out by electronic documents of certain content and format, which will be published by the OS in the SIOS or communicated to the SIOS by the SM, OM and other participants or entities participating in the Spanish production market, by the means to be established, in the schedules 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 time limits for publication or receipt by the OS are described in a single document "Information Exchange 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 System Operator 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 System Operator on the processes related to the Electrical Production Market are those established in the Real Estate. Decree-Law 6/2000 of 23 June, in the 1/2001 report of the CNE on the proposals to amend the Rules of operation of the market in order to adapt them to the Royal Decree-Law 6/2000, in the Rules of Operation of the approved market by Resolution of the Secretariat of State for Economic, Energy and Small and Medium-sized Enterprises Company, dated April 5, 2001, published in the B.O.E. dated April 20, 2001 and in the General Direction of Energy Policy and Mines dated November 19, 2004.

These criteria are as follows:

The System Operator will make public the result of the electrical system's operating processes, as they are the object of their responsibility.

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

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

In any case, the OM and the OS shall ensure the confidentiality of the confidential information made available to them 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 System Operator makes public about the electrical system operation processes.

This information depends on the period to which the information is affected and the time it is made public.

5.9.1.1 In real time.-The information that the System Operator will publish 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 ability to exchange updated international interconnections in real time.

Real-time, real-time international exchange aggregates and programs.

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.

Unbundled Operational Schedules (P48) programs that result after all allocations made to real time are incorporated into the program.

5.9.1.2 Daily. The following information will be published daily:

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 congestion 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 Spanish peninsular system demand.

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

After the corresponding market or technical management process:

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

Added result of the solution of technical constraints 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 for day D:

Aggregate result and marginal price of secondary regulation energy.

5.9.1.3 At three days. -After three days from day D of programming, the information broken down by type of technology, or if applicable, by type of subject, will be published.

The information to be published on day D + 4 corresponding to the result of the time schedule of day D operation markets will be broken down by the following types:

Nuclear.

Carbon.

Fuel-Gas.

Combined cycle.

Conventional hydraulics.

Pumping turbination.

Consumption pumped.

Imports and Exports of Energy, made by:

External agents.

Marketers that use international interconnections.

Power exchange contracts prior to Law 54/1997, of the Electrical Sector.

Special regime participating in the production market through producers, marketers, or representatives.

Special rate-to-rate production.

Distribution.

Marketing destined for domestic consumption.

Qualified customers.

Auxiliary services of production units.

Generic Programming Units.

5.9.1.4 Weekly. -The System Operator will publish on its website the power of electric generation available in ordinary system aggregated by technologies of generation (nuclear, coal, hydraulic, fuel oil, cycles combined).

Before 18.00h every Thursday, the exchange capacity with each of the neighbouring electrical systems interconnected for each programming period of the following two electric weeks, starting at 00.00h Next immediate Saturday.

5.9.1.5 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 System Operator will publish the aggregated specifications and results of the monthly explicit coordinated auction capacity of the interconnections with France and Portugal, in the form and deadlines set out in the operating procedures relating to the resolution of congestion on the France-Spain and Portugal-Spain interconnections, respectively.

The System Operator 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).

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 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.

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

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.

5.9.1.7 At three months. -After three months from the day it relates, the confidential information contained in paragraph 5.3.4 that is communicated to each market subject (SM), including the offers, will be published. submitted by the SM to the system tuning services.

5.9.1.8 Annually. -The following information will be published:

Before 30 November of each year, the expected capacity levels for the following year for each of the interconnections and flow senses.

The aggregated specifications and results of the annual explicit coordinated auction capacity of the interconnections with France and Portugal, in the form and deadlines set out in the related operating procedures to the resolution of congestions in 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 communicates to the subjects of the system individually without access to it by the other subjects, up to once after three months from 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 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 operating markets are as follows.

5.10.1.1 To Market Operator (OM). -You will be notified of all necessary information for the liquidation of the production market and that other additional in compliance with the provisions of the current legal regulations.

5.10.1.2 To market subjects. -They will be notified of the detailed information corresponding to the units of their property, or to which they represent.

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 of the tenders 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.

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 available to market participants the PSS/E cases used for the analysis of the technical constraints of the Operational Base Program (PBF) before three working days from the date of the date. of the programming day.

5.10.1.3 Other subjects or entities participating in the operation programming process.

5.10.1.3.1 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 Units of Generic Programming Necessary 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.

5.10.1.3.2 Management Entity of the Last Resource Distribution or Marketers Auction (EGSED). -The OS will communicate to the EGSED the updated information pertaining to Market Subjects in the market production.

After the completion of each valid auction the EGSED will communicate to the OS the relationship of the SM to which the sale of energy for the supply by bilateral contracting to the distributors has been awarded in said auction last-resource marketer and the hourly energy value associated with each partner SM vendor-distributor or SM last resort-marketer at each programming period of the energy delivery period covered by the said auction.

5.10.1.4 To the distribution system operators. -They will be notified of the information of the registered net power generation facilities of more than 50 MW and of the network facilities corresponding to the network under their 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 System Operator, 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 its network proposal observable for this manager, including the exposure of reasons why the inclusion of this additional information is considered necessary.

The System Operator, on a monthly basis, will provide distribution network managers not included in the transitional provision of law 54/97, the information concerning the attachment to control centres of the facilities registered in such centres.

5.11 Exchange of measurement data. -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 System Operator it is necessary to know and maintain information regarding the Market Subjects (SM), Programming (UP), Offer Units (UO) and Physical (UF), Bilateral Contracts, 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 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 System Operator.

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 modification of structural information.-The modification of the structural information will be requested by sending to the OS of the corresponding form available on the web page of SM duly 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 Hub for Electrical Measures

The Main Hub of Electrical Measures is the system with which the System Operator manages the information of measures of the Spanish electrical system in accordance with the requirements laid down in the legal regulations in effect.

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 System Operator is in charge of the 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 System Operator is in charge of the 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 System Operator 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) Measures information resident in the Main Hub for borders of which the System Operator is not in charge of 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 Concentrator of Measures. -The System Operator manages access to the resident measures information on the Main Hub according to the following:

6.3 Free Access Information-The System Operator publishes a variety of general reports based on the energy and inventory data available from the Main Hub.

This information is available from the Internet address of the OS (http://www.ree.es).

6.4 Information for the participants of the measurement system. The information contained in the Main Concentrator of Electrical Measures 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.

The System Operator has developed a secure access system, whereby each participant in the measurement system will be able to consult at least the following information residing in the Main Hub of Measures Electrical:

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.

Additional and regardless of the secure access described above, the System Operator will publish and exchange measure information with the secondary concentrators according to the protocol defined in the Procedure of Operation 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 System Operator 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 electrical 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 Measures Information" and "Information for holders of special regime installations" published on the System Operator's website.

6.7 Main Concentrator Measures Reception.-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 Hub for a minimum period of six calendar years, counted from the following year 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 System Operator will need to receive all information from the transportation and production facilities, including the generation under special regime and the system, in its real-time Operation Control System. An observable network-as defined by the latter in the procedure of operation P.O. 8.1 defining the networks operated and observed by the system operator-that is required to operate in the electrical system. To do this, the System Operator will have the corresponding Operation Control System Database (BDCO).

7.1 Production facility control center. -Real time information regarding production facilities of net power equal to or greater than 10 MW (or in aggregate form of those power plants which are part of a set whose connection is made to the same knot of the voltage grid equal to or greater than 10 kV and add up to more than 10 MW) shall be captured by means of its own and provided to the System Operator via connection between its control centers.

Those units of production of power greater than 1 MW that do not meet the conditions set out in the previous paragraph, have no obligation to be integrated into a control centre, but must send the telemetry of their real-time net production to the OS through the area's distributor control center.

In the event that the production facility is integrated into a regulatory area, its control center will be the generation dispatch of the owner of that regulatory zone.

7.2 Content and structure of the SCO Database (BDCO).-The SCO Database will receive the following information and the technical specifications that are also reflected:

7.3 Technical Requirements. Information to be exchanged with the System Operator will be performed according to a standard communication protocol to be determined by the OS. The frequency 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 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 System Operator 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.

7.4 Required Information. -Information will be required for the facilities listed below:

Transport Network.

Observable network.

Level of filling of reservoirs in pumping stations.

7.4.1.1 Definition and general criteria for standardized collection of signals and measurements. -In this procedure, the set of elements associated with line, transformer, reactance, bars or coupling is understood by position of bars that are precise 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:

1. Signs. -Includes states (open/closed) or indications of devices that do not constitute anomalies or states of malfunction. 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).

The detailed information for the signals to be captured is given in Annex 2.

8. Other information subjects should send to the system operator

The System Operator will be responsible for collecting all other information regarding the system operation described in this section.

It is the responsibility of the producers, carriers and managers of the distribution networks to provide the System Operator with the information that it requires and which is derived from the operation of the facilities of its property or under the scope of its management.

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 you are unable to dispose of some of this data, you will be able to get the System Operator your best estimate.

The following data will be sent to the System Operator with two different levels of temporary aggregation (daily and monthly), which are necessary to maintain the statistical series relating to the energy balance sheets and the operation of the system, as well as to perform security coverage and analysis forecasting.

8.1 Daily data. -System subjects shall provide the System Operator with all the data necessary for the production of official statistics, using the established information exchange channels. All values of the magnitudes listed below shall be given with the greatest disaggregation possible in physical units. The maximum time limit for the submission of such data shall be the following four working days:

Daily production forecasts with hourly breakdown and by technologies of all facilities of special regime at tariff that choose to cede the electricity to the distribution company and are connected to the transport network, in accordance with the provisions of the Transitional Provision Sixth of RD 661/2007.

Production of thermal groups on alternator bars.

Production of hydraulic power plants with installed power equal to or greater than 10 MW, in central bars.

Hydropower production by hydraulic subsystems.

Maximum hydroelectric power that can be maintained by each hydraulic supply unit for four consecutive hours.

Production of wind farms with installed power equal to or greater than 10 MW.

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:

Precipitation.

Means of rivers in aphorous stations.

Hydroelectric reserves by reservoirs (in Hm3 and MWh).

Spills.

Incidents on the Transport Network.

8.2 Monthly data. -The following monthly data will be sent to the System Operator before the 20th of the following month with the maximum possible breakdown in physical units:

Production of thermal, gross and net groups.

Hydroelectric production (gross and net) by hydraulic subsystems.

Production of hydraulic power plants with installed power equal to or greater than 5 MW, in alternator borns and reserves in the associated reservoirs.

turbable losses in hydraulic power stations with installed power equal to or greater than 5 MW.

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.

Energy produced at the rate of the Special Regime.

Energy produced by each producer with the Special Regime.

Consumers of each producer's own consumption and consumption under the special scheme.

Fuel input in power plants/thermal groups (in tonnes and termine (PCI)) broken down by coal or fuel oil classes at the power plants of this type.

Fuel consumption in central/thermal groups (in tonnes and termine (PCI)) 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)) broken down by coal or fuel oil classes at the plants of this type.

Lower heat power 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 quantities of the year in progress 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.

9. Statistics and public information regarding the operation of the system

The System Operator will publish the data below for the operation performed, including the behavior of the transport network and the generation media.

9.1 Daily information. The information that the System Operator will publish daily is as follows:

System load curve.

State of hydroelectric reserves and contributions in the most important rivers.

9.2 Information at three days.-The information corresponding to day D that the System Operator will publish on day D + 4 is as follows:

Production power balance.

9.3 Monthly Information. -Monthly the System Operator 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.

ENS and TIM service quality.

9.4 Annual information. The System Operator will publish the following information annually:

Availability of the generator equipment.

Availability of the transport network.

Annual evolution of the shorting power at the knots of the transport network.

ENS and TIM service quality.

Seasonal thermal limits of the transport network.

In addition, the System Operator will maintain up-to-date and available historical series of:

Power installed on the system.

Energy generated by both the ordinary regime and the special regime.

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. -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 facilities affected or the person responsible for 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 Operator of the System. -In the event that there is an incident of those defined in the previous paragraph, the subject holder of the facilities or responsible for the supply concerned shall provide the 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 System Operator 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 you have the necessary 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 System Operator will include the corresponding information in a "Daily Incident Party" that will be the provision of market subjects before the 12 hours of the day following the occurrence of the day.

When the System Operator considers an incident of special relevance, it will draw up a written report, once it has the definitive information about it. 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 MINECO, 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 Research. -For those incidents in which the Operator of the System considers it necessary for its importance or nature, it will propose as soon as possible the realization of a joint analysis with the remaining subjects involved or affected. The results of that analysis will be incorporated into the report that the System Operator prepares for the incident.

11. System operator liability clearance information

11.1 Confidential information.-The confidential information relating to the liquidations made by the system operator is the one that communicates to the market subjects individually without access to the market. to her the other 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.

The PSS/E expression refers to the computing application for power electrical systems analysis of Power Technologies Inc.

Production System

Reservoirs:

Name of the reservoir.

Company or proprietary or concessionary companies:

Name.

NIF/CIF.

Address.

Percentage of participation.

Basin (river).

Situation: Province, municipal term, place or land.

Date of termination.

Power in electrical power (MWh).

Historical series of partial contributions to the reservoir in monthly and weekly terms (m3).

Maximum volume (hm3).

Minimum volume (hm3).

Reservoir cote curve 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 center itself.

Usage (Hydroelectric, Mixed).

Operating constraints (detettions, watering, etc).

Ordinary regime hydraulic groups and groups

1. General and hydraulic installation data.

1.1 power stations with less than 10 MW of power and not connected to the transport network:

Name of the Central.

Address of the Central: Municipality, postal code and province.

Company or proprietary companies:

Name.

NIF/CIF.

Address.

Percentage of participation.

Enterprise or exploitative companies:

Name.

NIF/CIF.

Address.

Basin (river) in which the power plant is located.

The associated reservoir.

Substation/network connection park (Name, kV).

Hydraulic Management Unit to which you belong, if any.

Number of groups.

Rated power

nominal flow (m3/s).

Net nominal jump (m).

1.2 Central to more than 10 MW or connected to the transport network.

General:

Name of the Central.

Address 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).

UTM Coordinates 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 on the transport network).

Company or proprietary companies:

Name.

NIF/CIF.

Address.

Percentage of participation.

Enterprise or exploitative companies:

Name.

NIF/CIF.

Address.

Basin (river) in which the power 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).

Deposit or charging chamber (SI/NO). If yes, volume.

Forced Pipeline (SI/NO). If yes, length (s) and diameter (s).

Number of groups.

Rated power.

nominal flow (m3/s).

Net nominal jump (m).

Maximum turbination Flow (m3/s).

Minimum Turbination Flow (m3/s).

Maximum gross jump (m).

Minimum gross jump (m).

Maximum net jump (m).

Minimum net jump (m).

Losses in flow-based pipelines: Perdconduccio = f (Q2).

Throughput 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:

Rated power.

Nominal effective height (m).

Nominal Pump Flow (m3/s).

Maximum Pump Flow (m3/s).

Minimum Pump Flow (m3/s).

Loss in aspiration and drive based on flow rate: Perdconduccio = f (Q2).

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).

Pumping 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.

2. Data for each group:

2.1 Central over 1 MW and less than 10 MW of power 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 (MVA) terminals.

Rated power in turbination (MW).

nominal flow (m3/s).

Nominal jump (m).

Net technical minimum, that is, in central bars (MW).

For reversible or pumping groups:

Rated power.

Nominal effective height (m).

Nominal Pump Flow (m3/s).

Rotating set inertia constant: electric machine, exciter, and turbine.

Availability of primary regulation or speed regulation (SI/NO). If yes, indicate:

Regulator sensitivity (mHz). It must not be greater than 10 mHz.

Regulator voluntary dead band (mHz): Confirm that the adjusted value is zero.

In case of no primary regulation of your own, provide documentation that accredits the service delivery by another generating unit, indicating:

Unit that provides the service.

Insensitivity confirmation not greater than 10 mHz.

Null voluntary dead-band commit.

Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) against internal disturbances to the plant (yes/no). Indicate particularities, if any.

Central to short-circuit stability in the network: Critical disconnect time.

Minimum frequency protection: Adjustments and compliance with the procedure that the Safety Plans are set for.

Overfrequency protection. Adjustments.

In case the critical time in the connection node to the network is less than 1 s, indicate:

Short-circuit protection scheme in the network-main transformer stretch.

Compliance with General Protection Criteria.

2.2 Central over 10 MW of power or connected to the transport network.

General:

Identification number in the RAIPEE (Administrative Registry of Electrical Power Production Facilities).

On-or-off date (forecast if applicable).

Turbine type.

Nominal speed (rpm).

Rated power in turbination (MW).

nominal flow (m3/s).

Net nominal jump (m).

Net technical minimum, that is, in central bars (MW).

Maximum turbination Flow (m3/s).

Minimum Turbination Flow (m3/s).

Maximum gross jump (m).

Minimum gross jump (m).

Maximum net jump (m).

Minimum net jump (m).

Losses in flow-based pipelines: Perdconduccio = f (Q2).

Throughput 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.

Rated power.

Nominal speed (rpm).

Nominal effective height (m).

Nominal Pump Flow (m3/s).

Maximum Pump Flow (m3/s).

Minimum Pump Flow (m3/s).

Loss in aspiration and drive based on flow rate: Perdconduccio = f (Q2).

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 (MVA) terminals.

Maximum Full Load Reactive Generation (MVAr) in b.c.

Maximum Technical Minimum Reactive Generation (MVAr) in b.c.

Maximum full-load reactive absorption (MVAr) in b.c.

Maximum Technical Minimum Reactive Absorption (MVAr) in b.c.

Rated power factor.

Rotating set inertia (s): Electrical machine, exciter, and turbine.

Capability as synchronous compensator (SI/NO).

Power absorbed in operation as synchronous compensator (MW).

Top turbine and primary regulatory equipment data:

Turbine features: Manufacturer and model. A simplified turbine operation model must be provided including the water time constant Tw.

Availability of primary regulation or speed regulation (SI/NO).

In case of no primary regulation of your own, provide documentation that accredits the service delivery by another generating unit, indicating:

Unit that provides the service.

Insensitivity confirmation not greater than 10 mHz.

Null voluntary dead-band commit.

In case of your own primary regulation, please indicate:

Features of the local mechanism that supplies the watchword to the regulator: Motorized power, digital slogan, ...

Permanent status:

tuning range.

adjusted value.

telemetry capability of the adjusted value.

Speed of power variation in MW/s, by frequency variation.

Regulator sensitivity (mHz). It must not be greater than 10 mHz.

Regulator voluntary dead band (mHz):

tuning range

adjusted value: Confirm that 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 offsets: 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 shall be provided, in the case of plants of more than 50 MW, using PSS/E compatible model, either from the application's own library or as a user model by supplying the code of its FLECS language source program.

Additional data in the case of power stations connected to the transport network:

Generation Nominal Voltage (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.

Short-circuit transient and subtransient time constants for both direct and transverse axis (s).

Open-circuit transient and subtransient time constants for both direct and transverse axis (s).

Unsaturated leakage reactance (p.u.).

Saturation of the machine at voltage 1.0 p.u. (p.u.).

Saturation of the machine at voltage 1.2 p.u. (p.u.).

(The above three data can be collected in the form of an interiron curve and at full load, see Figure 1).

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 of the connection of the regulatory system with the AGC: Features 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 slogan values for continuous ramp and step.

4. Data necessary for the replacement plans of the service in the case of power stations of more than 50 mw or connected to the transport network:

Stand-alone startup capacity.

Own media to energize the auxiliary services needed for startup:

Battery.

Diesel Group.

Other.

Single-circle 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 cycle duration.

Minimum number of groups to operate in parallel.

Cascade startup capability for a set of groups.

P-Q Capacity Curves (Operating Limits).

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.

5. Data for the group transformers.

5.1 Central over 50 MW not connected to the transport network:

rated power (MVA).

Nominal voltage (kV) of primary and secondary.

Connection group.

Loss due to load (kW).

Short Circuit Voltage (%).

Homopolar impedance (% on machine base).

5.2 Central attached to the transport network:

See transport transformers.

6. Data from the evacuation line or cable (if any).

6.1 over 50 MW non-connected to the transport network:

See observable network lines and cables.

6.2 Central attached to the transport network:

See transport lines and cables.

7. Data from the protection in the case of plants of more than 50 mw or connected to the transport network.

7.1 General:

Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) against internal disturbances to the plant (yes/no). Indicate particularities, if any.

Minimum Voltage Relays: Adjustments.

Central to short-circuit stability in the network: Critical disconnect time.

Minimum frequency protection: Adjustments and compliance with the procedure that the Safety Plans are set for.

Overfrequency protection. Adjustments.

Shot by Overspeed. Firing value.

7.2 Additional data in the case of power stations connected to the transport network:

Protections from the Central:

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 syncism: Indicate protection type, number of slides for the shot, and if the group is left over auxiliary.

Surge Relay: Adjustments.

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.

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-transformer stretch of generation. Compliance with General Protection Criteria. Critical time contemplated.

Minimum voltage relay: Adjustments.

Teleshooting at network contingencies:

Teleshooting capacity (SI/NO).

The tele-firing time since the signal is received.

Teleshooting logic and switches or selectors that includes.

8. Main data of the 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 scheme, and the corresponding values of the parameters that are represented in the schemas, of the voltage regulators-excitepess and of the power stabilizer system (PSS) if they have this device. This information shall be provided, in the case of plants of more than 50 MW, using PSS/E compatible model, either from the application's own library or as a user model by supplying the code of its FLECS language source program.

9. Supplementary voltage control service in the case of connection to the transport network:

explicit declaration of compliance with mandatory voltage control requirements established in the operating 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 telematic the groups must be indicated so that the excitation slogan and/or the takes of the group's output transformer can be modified from the generation office of the titular subject or group representative, or from the appropriate control center.

Ordinary-regime thermal units

1. General installation data.

Denomination of the central.

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).

UTM Coordinates of the installation (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.

One-to-one detail diagram of power equipment from the different generation units to the point of connection to the network.

Company or proprietary companies:

Name.

NIF/CIF.

Address.

Percentage of participation.

Enterprise or exploitative companies:

Name.

NIF/CIF.

Address.

Identification number in the RAIPEE.

Head address: Municipality, postal code and province.

On or off date (forecast, if any).

Primary 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).

Fuel consumption structure on startup: percentage in terms of consumption of each of the fuels used.

Startup 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).

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.

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).

Effective 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).

The 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 full-load reactive absorption (MVAr) in b.a.

Maximum Technical Minimum Reactive Absorption (MVAr) in b.a.

Auxiliary services consumption in b.a. at full load, active power (MW).

Auxiliary services consumption in b.a. at full load, reactive power (MVAr).

Auxiliary services consumption in at least technical, active power (MW).

Auxiliary services consumption in at least technical, reactive power (MVAr).

Rated power factor.

Non-saturated synchronous, transient, and subtransient reactances for direct axis and transverse axis (p.u.).

Short-circuit transient and subtransient time constants for both direct and transverse axis (s).

Open-circuit transient and subtransient time constants for both direct and transverse axis (s).

Rotating turbine-generator assembly (s) constant.

Unsaturated leakage reactance (p.u.).

Saturation of the machine at voltage 1.0 p.u. (p.u.), as Figure 1.

Saturation of the machine at 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).

Here are several images in the original. See the official and authentic PDF document.

3. Main turbine data and primary regulatory equipment. -In the case of multi-axle combined cycles, the information requested here shall 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 (yes/no).

In case of no primary regulation of your own, provide documentation that accredits the service delivery by another generating unit, indicating:

Unit that provides the service.

Insensitivity confirmation not greater than 10 mHz.

Null voluntary dead-band commit.

In case of your own primary regulation, please indicate:

Characteristics of the local mechanism that supplies the watchword to the regulator: motorized potentiometer, digital slogan, ...

Permanent status:

Adjustment range.

Adjusted value.

Adjusted value telemedidability.

Speed of power variation in MW/s, by frequency variation.

Regulator sensitivity (mHz). It must not be greater than 10 mHz.

Regulator voluntary dead band (mHz):

Adjustment range.

Adjusted value: Confirm that it is zero.

Adjusted value telemedidability.

Characteristics of the regulator (or regulators, if any): Manufacturer, type of control (PID series compensator, compensation for refeeding by transient staticism, ...) and technology (hydraulic, electrohydraulic ...).

Dynamic offsets: Dynamic compensation transfer function (transient staticism, series compensator, ...). The range of each parameter and its watchword value must be specified.

Regulator block scheme (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.

4. Secondary regulation data.

Regulatory zone to which you belong.

Detailed information of the connection of the regulatory system with the AGC: characteristics of the signal signal, signal processing, 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.

5. Data for programming and tertiary regulation. -In the case of generators dependent on each other, how can the members of the combined cycles, also contribute the data requested, for the different possible configurations of operation both permanent and short-lived, for example, start of the second gas turbine in case of operation 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).

6 Main data for voltage control equipment. -In the case of multi-axle 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 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.

7. Supplementary voltage control service.

Explicit declaration of compliance with the mandatory voltage control requirements set out in the procedure described in the Complementary Tension Control Service of the transport network or 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 telematic the groups must be indicated so that the excitation slogan and/or the takes of the group's output transformer can be modified from the generation office of the titular subject or group representative, or from the appropriate control center.

8. 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/Bater/Otras) Groups.

SSAA Power Voltage.

Auxiliary services consumption in b.a. for group stop, active power (MW).

Auxiliary services consumption in b.a. for group stop, reactive power (MVAr).

Auxiliary services consumption in b.a. for startup, 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.

Single-circle 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 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 cycle duration.

Cascade startup capability for a set of groups.

P-Q Capacity Curves (Operating Limits).

Reconnect the group to the network:

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 settings.

Other data:

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 reorder process.

9. Data of the group transformers. -See transport transformers.

10. Data from the evacuation line or cable (if any). -See transport lines and cables.

11. Data from the protections.

11.1 Protections of the Central.

Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) against 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 (yes/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.

Central stability (group and ancillary services) in the face of short circuits in the network: Critical disconnect time.

Protection from loss of syncism: Indicate protection type, number of slides for the shot, and if the group is left over auxiliary.

Surge Relay: Adjustments.

Reverse Sequence Protection: Indicate coordination status with the single-phase reengagement and the network's pole discordance relays.

Minimum group frequency protection: Adjustments and compliance with the procedure that the Safety Plans are set for.

Overfrequency protection (yes/no). Adjustments, if any.

11.2 Protections associated with the link installation.

Network short-circuit support protection: Indicate relay type (s), adjustment criteria and values, and coordination status (yes/no) with network protections.

Short-circuit protection scheme in the network-group transformer stretch. Compliance with General Protection Criteria. Critical time contemplated.

Minimum voltage relay: Adjustments.

11.3 Teleshooting at network contingencies.

Teleshooting capacity (yes/no).

Type of telephoto (generation switch opening or "fast-valving") .

End Power and Downtime in Cases of Fast Load Reduction ("fast-valving") and in general in non-instant processes, such as, for example, in combined cycles, the response of the steam turbine to the partial telefiring of gas turbines.

The tele-firing time since the signal is received.

Teleshooting logic and switches or selectors that includes.

Special regime units connected to the transport network or net power installed above 10 MW whatever their connection point or which sell the electricity in the electricity production market

Non-Wind Groups

1. Installation and group data.

1.1 General.

Name of the central.

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).

Company or proprietary companies:

Name.

NIF/CIF.

Address.

Percentage of participation.

Identification number in the RAIPEE.

The offering unit to which you belong, if any.

Head address: Municipality, postal code and province.

On or off date (forecast, if any).

Type of Central.

Grant Date on Special Regime.

The final year of the concession.

Applicable regulations.

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).

Throttling regime (fluid, daily, weekly).

Basin (river).

Rotating set inertia (s): Electrical machine, exciter, and turbine.

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 ...).

Stored primary energy recovery time curves.

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 supplied 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.

Host power to 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.

Availability of primary regulation or speed regulation (yes/no). If yes, please indicate:

Regulator sensitivity (mHz). It must not be greater than 10 mHz.

Regulator voluntary dead band (mHz): Confirm that the adjusted value is zero.

In case of no primary regulation of your own, provide documentation that accredits the service delivery by another generating unit, indicating:

Unit that provides the service.

Insensitivity confirmation not greater than 10 mHz.

Null voluntary dead-band commit.

Compliance with the General Protection Criteria (which are included in the procedure for establishing the General Protection Criteria) against internal disturbances to the plant (yes/no). Indicate particularities, if any.

Central to short-circuit stability in the network: Critical disconnect time.

Minimum frequency protection: Adjustments and compliance with the procedure that the Safety Plans are set for.

Overfrequency protection. Adjustments.

In case the critical time in the connection node to the network is less than 1 s, indicate:

Short-circuit protection scheme in the network-main transformer stretch.

Compliance with General Protection Criteria.

1.2 Additional data in the case of generators or pool of generators of more than 50 MW of total power-reception not received-or connected to the transport network.

1.2.1 General.

UTM Coordinates 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 unavailability rates for other causes.

Maximum full load-reactive (Mvar) generation at the point of connection to the network.

Maximum Technical Minimum Reactive Generation (Mvar) 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.

Top turbine and primary regulatory equipment data:

Turbine features: Manufacturer and model. A simplified model of turbine operation must be provided. For a hydraulic turbine it must include the water time constant Tw. For a gas turbine the model must consider the combustion temperature limiter. For a steam turbine the time constant of the stage of high pressure and the recencouragre must be specified together with the power fractions corresponding to each stage. In the latter case, a simplified model of the boiler should also be provided with the steam accumulation time constant, the pressure regulator model and the corresponding adjustments and limits.

In case of self-regulation, indicate:

Features of the local mechanism that supplies the watchword to the regulator: Motorized power, digital slogan, ...

Permanent status:

Adjustment range.

Adjusted value.

Adjusted value telemedidability.

Speed of power variation in MW/s, by frequency variation.

Regulator sensitivity (mHz). It must not be greater than 10 mHz.

Regulator voluntary dead band (mHz):

Adjustment range.

Adjusted value: Confirm that it is zero.

Adjusted value telemedidability.

Regulator characteristics: Manufacturer, type of control (PID series compensator, resupply compensation using transient staticism, ...) and technology (hydraulic, electrohydraulic ...).

Dynamic offsets: 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, in the case of generators or generators of more than 50 MW, using PSS/E compatible model, either from the application's own library or as a user model, supplying the code of its program FLECS language source.

1.2.2 Additional data in the case of connection to the transport network.

1.2.2.1 Installation data at the network connection point.

Physical diagram (general scheme at site) of the link installation.

Single-line chart 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.

Report with maximum guaranteed harmonic distortion content, only in case there are wave control processes in the installation:

Well through a forecast, as indicated in IEC 61000-3-6, of the harmonics of tension and intensity (magnitude and order of 2 to 50) and the rate of harmonic distortion.

Or to make measurements at the point of connection, of the harmonics of tension and intensity (magnitude and order of 2 to 50) and of the rate of harmonic distortion, in minimum periods of one week as indicated in IEC 61000-4-30.

Unifilar installation protection scheme.

1.2.2.2 Data for each generator.

Nominal voltage (kV).

Maximum generation voltage (kV).

Minimum generation voltage (kV).

Nominal speed.

Synchronous, transient, and sub-transient non-saturated reactances for direct and transverse axes.

Short-circuit transient and subtransient time constants for both direct and transverse axis (s).

Open-circuit transient and subtransient time constants for both direct and transverse axis (s).

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, signal processing, 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.

3. Data for tertiary programming and regulation (in case of participation in the electricity production market).

Minimum programming start time:

From synchronization to minimum technical (min).

From synchronization to full load (min).

Minimum programming stop time (from full load to disconnect) (min):

Maximum up-ramp of tertiary regulation (MW in 15 min).

Top down ramp of tertiary regulation (MW in 15 min).

4. Data for the replacement plans of the service in the case of generators or pool of generators of more than 50 mw of total power-reception not received-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/Bater/Otras) Groups.

SSAA Power Voltage.

Auxiliary services consumption in b.a. for group stop, active power (MW).

Auxiliary services consumption in b.a. for group stop, reactive power (MVAr).

Auxiliary services consumption in b.a. for startup, 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.

Single-circle 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 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 cycle duration.

Cascade startup capability for a set of groups.

P-Q Capacity Curves (Operating Limits).

Reconnect the group to the network:

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 settings.

Other data:

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 reorder process.

5. Data for the group transformers.

5.1 Central or pool of more than 50 MW of total power-host most unwelcomed-not connected to the transport network.

rated power (MVA).

Nominal voltage (kV) of primary and secondary.

Connection group.

Loss due to load (kW).

Short Circuit Voltage (%).

Homopolar impedance (% on machine base).

5.2 Central connected to the transport network. -See transport transformers.

6. Data from the evacuation line or cable (if any).

6.1 Central or pool of more than 50 MW of total power-host most unwelcomed-not connected to the transport network. -See observable network lines and cables.

6.2 Central attached to the transport network. -See transport lines and cables.

7. Data from the protection in the case of plants of more than 50 mw or connected to the transport network.

7.1 General.

Minimum Voltage Relays: Adjustments.

Shot by Overspeed. Firing value.

7.2 Additional data in the case of power stations connected to the transport network.

7.2.1 Central Protections.

Surge Relay: Adjustments.

Sync conditions for coupling. Automatisms and adjustments.

7.2.2 Protections associated with the link installation.

Short-circuit protection scheme in the main network-transformer section. Compliance with General Protection Criteria.

Network short-circuit support protection: Indicate relay type (s), adjustment criteria and values, and coordination status (yes/no) with network protections.

7.2.3 Telefiring against network contingencies.

Teleshooting capacity (yes/no).

The tele-firing time since the signal is received (also indicate switch opening times).

Teleshooting logic and switches or selectors that includes.

8. Main data of the 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 scheme, and the corresponding values of the parameters that are represented in the schemas, of the voltage regulators-excitepess and of the power stabilizer system (PSS) if they have this device. This information shall be provided, in the case of plants of more than 50 MW, using PSS/E compatible model, either from the application's own library or as a user model by supplying the code of its FLECS language source program.

9. Supplementary voltage control service in the case of connection to the transport network.

Indicate option to which you are hosting: operation procedure 7.4 describing the Tension Control Complementary Service (yes/no), Royal Decree 661/2007 (yes/no), others (specify).

If yes:

explicit declaration of compliance with the mandatory stress control requirements laid down in the procedure or in the Royal Decree or non-compliance, where applicable, and its 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 telematic the groups must be indicated so that the excitation slogan and/or the takes of the group's output transformer can be modified from the generation office of the titular subject or group representative, or from the appropriate control center.

Wind Parks

1. Characteristics of each park.

Name of the park.

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).

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 on the transport network).

Owner Company:

Name.

NIF/CIF.

Address.

Identification number in the RAIPEE.

Special Regime Grant Date.

On or off date (forecast, if any).

Park address: Municipality, postal code and province.

UTM Coordinates of the Park Polygonal.

Distributor Company.

Installed Power: Gross (MVA) and Net Active (MW). The apparent power must include all of the park's reactive compensation.

Substation/network connection park (Name, kV).

Availability of primary regulation or speed regulation (yes/no). If yes, please indicate:

Regulator sensitivity (mHz). It must not be greater than 10 mHz.

Regulator voluntary dead band (mHz): Confirm that the adjusted value is zero.

In case of no primary regulation of your own, provide documentation that accredits the service delivery by another generating unit, indicating:

Unit that provides the service.

Insensitivity confirmation not greater than 10 mHz.

Null voluntary dead-band commit.

Planned operation of the park:

Hours of use (at full power) referred to 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 gaps (yes/no) response requirements.

Data for each wind turbine model:

Number of wind turbines 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 in stator (full converter), others.

Brief description of the technology.

Active power installed of each wind turbine (kW).

Apparent installed power of each wind turbine (kVA) including, if applicable, its internal reactive compensation.

A reactive power curve depending on the active power, considering, where appropriate, the internal reactive compensation of the wind turbine.

Wind Turbine Inertia Constant referred to the electrical side (s).

Multiplication relationship, if any.

The elasticity constant of the mechanical-electrical coupling, if any, referred to the electrical side (in absolute units or in p.u. indicating the bases).

Dampening Coefficient, if any, referred to the electrical side (in absolute units or in p.u. indicating the bases).

Nominal speed (on the axis of the alternator).

A model shall be provided for each type of generator that describes the dynamic behaviour from the point of view of the electrical grid to disturbances in the electrical grid (constant wind speed). In addition, the dynamic behaviour of the mechanical part should be considered if, during disturbances on the network, such behaviour modifies the electrical response or justify its disconnection. The block scheme, and the corresponding values of the parameters that are represented in the schemas, will be provided. 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.

Reactive compensation in wind turbine bornas excluding, if applicable, internal compensation:

Static compensation and reactive power dynamics (nominal values in Mvar).

Possibility of regulation.

Reactive compensation in park borns excluding, where appropriate, the one associated with each wind turbine:

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.

Power electronics-based continuous compensation or regulation systems (FACTS) (yes/no).

Total Power Installed (Mvar).

2. Data from the connection transformer to the network.

Company or proprietary companies:

Name.

NIF/CIF.

Address.

rated power (MVA).

Nominal voltage (kV) of primary and secondary.

Connection group.

Loss due to load (kW).

Short Circuit Voltage (%).

Homopolar impedance (% on machine base).

3. Data from the line or cable connection to the network. -See observable network lines and cables.

4. Data from the protections.

4.1 Park 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 relay: Indicate phases in which measures and adjustments.

Surge Relay: Adjustments.

Park stability before network shorts: Critical disconnect time.

Minimum frequency protection: Adjustments and compliance with the procedure that the Safety Plans are set for.

Overfrequency protection. Adjustments.

4.2 Protections associated with wind turbines.

Minimum voltage relay: Indicate phases in which measures and adjustments.

Surge Relay: Adjustments.

Minimum frequency protection: Adjustments and compliance with the procedure that the Safety Plans are set for.

Overfrequency protection. Adjustments.

Shot by Overspeed. Firing value.

4.3 Protections associated with the link installation.

Minimum voltage relay: settings.

In case the critical time in the connection node to the network is less than 1 s, indicate:

Short-circuit protection scheme in the network-main transformer stretch.

Compliance with General Protection Criteria.

Additional data in the case of parks connected to the transport network:

1. Characteristics of each park.

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 park to a short circuit at the point of connection to the network.

Report with the maximum guaranteed harmonic distortion content:

Well through a park-level forecast, as indicated in IEC 61000-3-6, of the harmonics of tension and intensity (magnitude and order of 2 to 50) and the rate of harmonic distortion,

Or perform park-level measurements of the voltage and intensity harmonics (magnitude and order of 2 to 50) and the harmonic distortion rate, at minimum periods of one week as indicated in IEC 61000-4-30.

Voltage level (kV) of the internal network of connection of the generators.

Unifilar park protection scheme and link installation.

2. Supplementary voltage control service.

Indicate option to which you are hosting: Operation procedure 7.4 describing the Tension Control Complementary Service (yes/no), Royal Decree 661/2007 (yes/no), others (specify).

If yes:

explicit declaration of compliance with the mandatory stress control requirements laid down in the procedure or in the Royal Decree or non-compliance, where applicable, and its justification.

The possibility, if any, of telemandar groups should be indicated so that the output of the group's output transformer can be modified from the generation office of the holder or representative of the group, or from the corresponding control center.

3. Data of the park transformer (if the transformer is connected to the network, see paragraph 5).

rated power (MVA).

Nominal voltage (kV) of primary and secondary.

Connection group.

Loss due to load (kW).

Short Circuit Voltage (%).

Homopolar impedance (% on machine base).

4. Data from the line or cable for the evacuation of each park (if any) (if this is the line or cable connection to the transport network, see paragraph 6). -See observable lines and network cables.

5. Data from the network connection transformer. -See transport transformers.

6. Data from the evacuation line or cable (if any). -See transport lines and cables.

7. Data from the protections.

7.1 Park Protections.

Sync conditions for coupling. Automatisms and adjustments.

7.2 Protections associated with the link installation.

Short-circuit protection scheme in the main network-transformer section. Compliance with General Protection Criteria.

Network short-circuit support protection: Indicate relay type (s), adjustment criteria and values, and coordination status (yes/no) with network protections.

7.3 Telefiring at network contingencies.

Teleshooting capacity (yes/no).

The tele-firing time since the signal is received (also indicate switch opening times).

Teleshooting logic and switches or selectors that includes.

Transport Network

Substations

The name of the substation.

Address: Municipality, postal code, and province.

On or off date (forecast, if any).

Parks

The name of the substation.

Voltage (kV).

UTM Park 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.

Short circuit breaker power of switches.

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.

Protection from external short-circuits: Indicate relay type (s), criteria, and adjustment values and coordination status (yes/no) with the protections of other elements.

Unifilar protection and measurement scheme.

Minimum Voltage Relays: Shooting logic and switches on which they operate.

Lines and cables

Denomination of the line.

Line ends 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 operating voltage and maximum service of each circuit (and projected in case of variation) for each circuit or tranches thereof with homogeneous characteristics.

Direct Sequence Resistance (P&C).

Direct Sequence Reactance (P&C).

Direct Sequence Sensitivity (μS).

Homopolar Sequence Resistance (P&C).

Homopolar Sequence Reactance (P&C).

Homopolar Sequence (μS) Sensitivity.

Additional data for transport network lines and cables only, as such:

Seasonal values (summer, fall, winter, spring) of:

Nominal line transport capacity (MVA).

limiting element.

Permanent Thermal Conductor Boundary (MVA).

Maximum driver operating temperature (0C).

Length in shared supports, if any (in a same ditch or gallery, if isolated cables are treated).

Configuration of the line.

Driver: Name/material/total section (mm2).

Earth Cables: Denomination/Material/Total Section (mm2).

Set-to-ground configuration (for isolated cables only): Type/length of sections.

Number of drivers per phase.

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 from external short-circuits: Indicate relay type (s), criteria, and adjustment values and coordination status (yes/no) with the protections of other elements.

Unifilar protection and measurement scheme.

Network couplers or telecouplers: Existence and adjustments.

Synchronism Relays: Existence and adjustments. Break down, if necessary, between monitoring of reengagement and voluntary closure.

Minimum Voltage Relays: Shooting logic and switches on which they operate.

Overvoltage protection: Existence and adjustments.

Automatic Replacement Devices: Indicate if they exist and describe their behavior, if any.

Reengagement:

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 (yes/no).

Teleshooting:

Telefiring at voluntary open (yes/no).

Telefiring at switch opening (yes/no).

Transformers

Transformers that feed loads and those connected to non-observable networks are treated under the heading "Consumer installations":

Substation and park name 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 components of the network-link installation (requests for access to the transport network or for voltage distribution networks greater than 100kV with influence on the transport network).

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 your case.

On or off date (forecast, if any).

Type of transformer: Configuration (triphasic or bank), autotransformer/transformer, magnetic circuit (n. of columns).

Nominal power of each winding (MVA).

Cooling type.

Nominal voltage of each winding (kV).

Maximum Service Voltage (kV).

Connection group.

Type of regulation in each winding: Load or vacuum, automatic regulation (yes/no) and collapse 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.

Transformer losses:

Losses due to load between each winding pair (kW).

Empty (kW) losses.

Losses in auxiliary equipment (kW).

Short circuit voltage 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:

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 from external shorthand support: indicate relay type (s), adjustment criteria and values, and coordination status (yes/no) with the protections of other elements.

Unifilar protection and measurement scheme.

Minimum Voltage Relays: Shooting logic and switches on which they operate.

Overvoltage protection: Existence and adjustments.

For observable network transformers:

Explicit declaration of compliance with the mandatory voltage control requirements set out in the operation procedure 7.4 describing the Complementary Tension Control Service or non-compliances, in their case, and their justification.

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).

rated power (MVAr).

Connection Voltage (kV).

Situation (transformer bars or tertiary).

Owner.

Loss in iron (kW).

Copper losses (kW).

Additional total included losses (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 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 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.

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 from external short-circuits: Indicate relay type (s), criteria, and adjustment values and coordination status (yes/no) with the protections of other elements.

Unifilar protection and measurement scheme.

Minimum Voltage Relays: Shooting logic and switches on which they operate.

Overvoltage protection: Existence and adjustments.

Automatic Replacement Devices: Indicate if they exist and describe their behavior, if any.

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.

Naming 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 on the transport network).

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 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:

Transform type: Configuration (three-phase or bank), autotransformer/transformer, magnetic circuit (n. 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 load composition characteristics (if applicable):

Comparable ratio to constant power load.

Equivalent to constant impedance load ratio.

Comparable ratio at constant intensity load.

Tension control:

explicit declaration of compliance with the mandatory stress control requirements laid down in the procedure for describing the Supplementary Tension Control Service or non-compliances, if any, and justification.

Additional information for arc furnaces in alternating current:

High Voltage (kV).

Media Voltage (kV).

Low Voltage (kV).

furnace power (MVA).

Reactive compensation: Type, rated power (MVAr), and connection sweep.

Short circuit and power impedance of MT-BT transformers.

The impedance of the serial reactance, if any.

The 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.

Cos φ of the previous impedances.

Additional information for arc furnaces in continuous stream:

High Voltage (kV).

Media Voltage (kV).

Low Voltage (kV).

rectification power (MW).

Number of pulses.

Reactive compensation: Type, rated power (MVAr), and connection sweep.

Short circuit and power impedance of MT-BT transformers.

The 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.

Cos φ of the impedance of low voltage cables.

Harmonic Filters: Order of harmonics to which each filter and unit power (MVAr) is tuned.

Additional information for TAV and unbalanced loads:

Nominal voltage (kV).

Nominal power (MVA) and phases between which it loads.

Characteristics of the imbalance compensation team, if any.

Line or cable connection to the RdT (if applicable):

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 operating voltage and maximum service of each circuit (and projected in case of variation) for each circuit or tranches thereof with homogeneous characteristics.

Direct Sequence Resistance (Ω).

Direct Sequence Reactance (Ω).

Direct Sequence Sensitivity (μS).

Homopolar Sequence Resistance (Ω).

Homopolar Sequence Reactance (Ω).

Homopolar Sequence (μS) Sensitivity.

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 from external short-circuits: Indicate relay type (s), criteria, and adjustment values and coordination status (yes/no) with the protections of other elements.

Unifilar protection and measurement scheme.

Minimum Voltage Relays: Shooting logic and switches on which they operate.

Overvoltage protection: Existence and adjustments.

Frequency relay features and tuning:

Frequency: Adjustment range, scaling, and tuning value (Hz).

Timing: Adjustment Range and Adjustment Value (s).

Existence of reorder mechanism (yes/no). If yes, confirm your non-enablement.

Minimum and maximum loads disconnected by the relay (MW).

Identification of the switch on which the relay is acting.

Automatic reorder devices not associated with the frequency relay: Indicate if they exist and describe their behavior, if any.

Network observable

Substations

The name of the substation.

Address: Municipality, postal code, and province.

On or off date (forecast, if any).

Parks

The name of the substation.

Voltage (kV).

Configuration. Single-line detail.

Owner of each position.

Owner of each bar.

On or off date (forecast, if any).

Lines and cables

Line name.

Line ends of the line.

Number of circuit 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 Sensitivity (μS).

Homopolar Sequence Resistance (Ω).

Homopolar Sequence Reactance (Ω).

Homopolar Sequence (μS) Sensitivity.

Additional data in case of lines and cables of the observable network, as such:

Nominal line transport capacity (MVA), seasonal values (summer, autumn, winter, spring).

Transformers

Transformers connected to the transport network are dealt with in the "Transport Network" chapter.

reactive power control elements

This item is applicable to 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

Transport network and observable network

Switches.

Senalizations.

Switch position.

Sectors.

Senalizations.

Position of the dryers.

Lines.

Measures.

Active power.

reactive power.

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.

Transformer primary reactive power.

The secondary active power of transformer.

Transformer secondary reactive power.

Transformer tertiary active power.

Transformer tertiary reactive power.

Take the regulator into load (transformers only).

Empty regulator position (if it exists and only transformers).

Reactive power in reactances.

Coupling of bars.

Senalizations.

Switch position.

Position of the dryers.

Measures.

Active power.

reactive power.

Bars.

Measures.

Tension per bar section.

Frequency measure on selected bars.

Thermal groups and hydraulic groups with regulatory capacity.

Senalizations.

Group throttling local/remote state.

Type of regulation, control/unchecked.

Thermal groups.

Senalizations.

Position of the group switches.

Measures.

Active power on the machine transformer high.

High-reactive power of the machine transformer.

Low active power of the machine transformer.

Low reactive power of the machine transformer.

Generation Voltage.

Hydraulic groups.

Measures.

Active power on the machine transformer high.

High-reactive power of the machine transformer.

Pure pumping groups.

Measures.

Active power on the machine transformer high.

High-reactive power of the machine transformer.

Reservoirs of reservoirs.

Wind groups.

Measures.

High-powered active power by wind farm.

High reactive power grouped by wind farm.

Voltage measurement.

Park connection status with the distribution or transport network.

Temperature.

Wind speed (intensity and direction).

Non-Wind Special Regime.

Measures.

Active power produced by each of the generation units if within the installation there are different consumption to the auxiliary services of the generation units or some of the units has a power equal to or greater than 10 MW and net value of the active power exchanged with the network.

Reactive power produced/absorbed by each of the generation units if within the facility there are different consumptions to the auxiliary services of the generation units or some of the units a power equal to or greater than 10 MW and a net value of the reactive power exchanged with the network.

Measure of tension at the point of connection to the network.

Synchronous compensators.

Senalizations.

2. Connection status.

3.

4. Analog measures.

5. Reactive power.

Voltage.

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, ...).