Greek Grid Code - rae.gr · 168/A) and the provisions of Presidential Decree 29/96 on the merger of...

HELLENIC REPUBLIC Athens, May 2005 MINISTRY OF DEVELOPMENT A.P. D5-IL/Β/oik. DIRECTORATE OF ENERGY ELECTRICITY GENERATION DIVISION SECTION B Postal Address : 119, Mesogion Ave. Postal Code : 101 92 ATHENS Contact : E. Deligiannis Telephone : 210- 6969415, 431

D E C I S I O N SUBJECT: Approval of the Grid Control and Power Exchange Code For Electricity Having regard to: 1. the provisions of Law 1558/85 “Government and other agencies» (Government Gazette

Issue No 137/A), in conjunction with Presidential Decree 381/89 on the organization of the Ministry of Industry, Energy and Technology (Government Gazette Issue No. 168/A) and the provisions of Presidential Decree 29/96 on the merger of the Ministries of Tourism, Industry, Energy and Technology, and Technology and Commerce into the Ministry of Development” (Government Gazette Issue No. 19/A);

2. the provisions of Presidential Decree 121/2004 on the Appointment of Ministers and State Secretaries (Government Gazette Issue No. 84/Α);

3. the provisions of Law 2773/1999 on the Liberalization of the electricity market – Regulation of energy policy issues and other provisions (Government Gazette Issue No. 288/Α), as has been amended by the provisions of Law 2837/2000 on the regulation of competition issues, the Regulatory Authority for Energy, tourism and other provisions (Government Gazette Issue No. 178/Α), the provisions of Law 2941/2001 on the simplification of procedures for company foundation, Renewable Energy Sources licensing, the regulation of issues pertaining to Hellenic Shipyards SA, and other provisions (Government Gazette Issue No. 201/Α), the provisions of Law 2992/2002 on measures to strengthen the capital market and develop entrepreneurship, and other provisions (Government Gazette Issue No. 94/Α), and the provisions of Law 3175/2003 on the development of the geothermal potential, district heating, and other provisions (Government Gazette Issue No. 207/Α);

4. the provisions of the Grid Control Code for Electricity approved by Decision No. D5/Β/F1oik.8989/14-5-2001 of the Minister of Development (Government Gazette

Issue No. 654/Β/01) as has been supplemented at a later time and is currently in force;

5. the provisions of the Power Exchange Code for Electricity approved by Decision No. D5/Β/F1oik.8988/14-5-2001 of the Minister of Development (Government Gazette Issue No. 623/Β) as has been supplemented at a later time and is currently in force;

6. the provisions of Presidential Decree No. 39/2001 (Government Gazette Issue No. A 28/20-02-2001), transposing Directive 1998/34/EC (OJ L204/37 of 21-07-1998) and Directive 1998/48/EC (OJ L217/1998 of 05-08-1998);

7. the provisions of Directive 2003/54/EC (OJ L176/37 of 15-07-2003); 8. the public consultation held; 9. the opinion of the Regulatory Authority for Energy contained in its document No.

O-10183/06-05-2005; 10. the fact that no cost arises for the state budget from the provisions contained herein,

we hereby decide:

Article one This decision approves the Grid Control and Power Exchange Code For Electricity, prepared in accordance with the provisions of Law 2773/1999, as amended and is currently in force, the text of which is given next:

“Grid Control and Power Exchange Code for Electricity”

SECTION I GENERAL PROVISIONS

CHAPTER 1

ENERGY TRANSACTIONS SYSTEM

Article 1 Energy Transactions Contract

1. Following registration with the Participant Register kept by the Transmission System Operator, the following (Participants) participate The Energy Transactions System which includes the DAS, the Dispatch Procedure, Imbalances Settlement and the Capacity Assurance Mechanism:

Α) Producers, production license holders from Generation Units registered with the Generation Unit Register;

Β) Suppliers, supply license holders;

C) Eligible Customers who choose to be supplied with energy through the Energy Transactions System for own exclusive use (hereinafter referred to as Self-Supplying Customers).

2. By registering with the Participant Register, Participants enter into an Energy Transactions Contract with the Transmission System Operator, governed by the provisions of the Grid Control and Power Exchange Code for Electricity. The Energy Transactions Contract is not subject to any other formality besides registration with the Participant Register.

3. The scope of the Energy Transactions Contract includes transactions carried out in the context of the Energy Transactions System. For that purpose, the Energy Transactions Contract provides Participants the right to take all lawful actions related to their participation in the Energy Transactions System in compliance with the provisions of the Code, and receive the payments corresponding to them, and generates their obligation to pay the corresponding charges in accordance with the provisions of the Code.

4. The Energy Transactions Contract grants to the Transmission System Operator the rights and obligations specified in the provisions of the Code with regard to Energy Transactions System.

Article 2

Registration with the Participant Register 1. In order for applicants to be registered with the Participant Register, their legal

representatives must submit an application to the Transmission System Operator accompanied by the following documents:

Α) a copy of the production or supply license, and in case of Eligible Customers, a certificate issued by RAE certifying that such Customers are entitled to select the supplier;

Β) full information regarding the bank account the applicant is required to keep for the purposes of the Energy Transactions Contract and express authorization to the Transmission System Operator authorizing it to credit and debit such account in accordance with the terms hereof (Participant Account);

C) a declaration by the applicant stating that they expressly and unreservedly accept the regulations of this Code, in particular with regard to the financial obligations arising from their participation in the Energy Transactions System;

D) a draft agreement entered into between the applicant and the Transmission System Operator, signed by the applicant in two copies, to settle disputes resulting from the Energy Transactions Contract, in accordance with CHAPTER 3 of this Code;

E) an express declaration of supply license holders stating that they accept the Transmission System Operator’s right to inform their Customers in case of failure on their part to perform their financial obligations due to participation in the DAS, so that they may exercise the right to change supplier or be supplied by the DAS for their exclusive use, as well as other Suppliers in order for them to undertake the relevant Load Declarations;

F) an express declaration by supply license holders, that they have included in the supply contracts entered into with their customers a clause providing that in case of illegal submission of a Load Declaration due to lack of a certification attesting to the performance of financial obligations or failure to perform financial obligations for the Supplier's Load Declaration in the context of the DAS, the Customer acknowledges the Transmission System Operator’s right to take action directly against the Customer itself with the same rights it has against the Supplier for the part of the consumption corresponding to the Load Declaration, while it may not lodge objections regarding its contractual relation with the Supplier;

G) for Self-Supplying Customers, an express declaration where they shall state that they accept the Transmission System Operator’s competence to interrupt the supply of energy to them on the Dispatch Day in respect of which the

Customer is unable to perform their financial obligations due to participation in the DAS;

H) for supply license holders, proof of payment of the Fixed Charge for Financial Coverage Costs corresponding to them;

I) documentation regarding the applicant’s legal representation by the party signing the application and the above declarations;

J) provision of guarantees in accordance with Article 213 to secure their obligations in the framework of the Imbalances Settlement Procedure and the Uplift Accounts;

K) activation of account and authorization to the Transmission System Operator in accordance with Article 62 paragraph (5).

2. The Transmission System Operator shall register the applicant with the Participant Register within five (5) business days from the day of submission of the respective application if it believes the application to be complete. For the registration, the Transmission System Operator must issue a certificate in writing, accompanied by a copy of the agreement submitted by the applicant in accordance with paragraph (1.D) of this Article, also signed by the Transmission System Operator.

3. Should the application for registration with the Participant Register be rejected, specific justification shall be given for such rejection. Applications shall be rejected in particular where the applicant has not performed in due time its financial obligations arising from its participation in the Energy Transactions System.

4. The application submission and registration with the Participant Register procedure shall be dealt with in detail in the DAS Manual.

Article 3

Expiry of the Energy Transactions Contract 1. The Energy Transactions Contract shall expiry should it be terminated by any one of

the Parties. In case of cessation of payments, compulsory administration, bankruptcy, or an equivalent regime, the Energy Transactions Contract shall expire ipso facto as a result of any of such events.

2. Termination of the contract shall be made in writing and entail all its legal consequences from the time of servicing to the Applicant the deed regarding its removal from the Participant Register. At such time any charges and payments due as a result from participation in the Energy Transactions System shall become overdue and immediately payable.

3. Each Participant is entitled to terminate the Energy Transactions Contract at any time, provided it has paid in full through the Energy Transactions System all outstanding charges and payments that concern it.

4. The Transmission System Operator shall terminate the Energy Transactions Contract in the cases expressly established by the provisions of the Code, as well as in all cases where the conditions for the legal carrying out of energy activities or exercising of the right to select a supplier cease to apply.

Article 4

Generation Unit Register 1. The Transmission System Operator shall keep a Generation Unit Register where

generation units for which a production license is in force, which are installed in continental Greece or on the interconnected islands, a connection with the System or the Distribution Network has been made and activated, the units do not fall within the scope of Article 35 of Law 2773/1999, and for which the Transmission System Operator may issue Dispatch Instructions shall be registered.

2. The Generation Units registered with such register shall be classified as Dispatchable Units if they are not Cold-Reserve Units, as well as only for the part of their capacity and/ or the time period for which an Ancillary Services Contractor or a Supplementary System Energy Contract is not in force or implemented. Any non Dispatchable and non Cold-Reserve Unit in the Generation Unit Register or part thereof in terms of capacity and/ or time, shall be classified as Contracted Unit. Cold-Reserve Units are included in the Generation Unit Register as a separate category. Under the responsibility of the Transmission System Operator, the Generation Unit Register shall be divided into Dispatchable Unit Register, Contracted Unit Register and Cold-Reserve Unit Register.

3. Generation Units shall be registered with the Generation Unit Register following the submission of an application by the holders of the respective production licenses. Generation Units shall be removed from the Generation Unit Register if they definitely cease to operate or are removed.

4. For each Generation Unit, the Transmission System Operator shall enter in particular the following data in the Register:

Α) Generation Unit Code uniquely identifying the Generation Unit;

Β) Production License Protocol Number;

C) Generation Unit Type;

D) Generation Unit Net Capacity in MW as established in Article 217 and declared by the applicant at the time of registration;

E) classification of the Generation Unit as Dispatchable, Contracted or Cold-Reserve Unit. Where the Generation Unit is partially Dispatchable and partially Contracted, the relevant identifying information in terms of capacity and/ or time is registered. The relevant entry may be modified under the responsibility of the Transmission System Operator depending on the classification of the generation unit as Dispatched, Contracted, or Cold-Reserve.

5. The holder of the production license is required to inform the Transmission System Operation and RAE forthwith with regard to any changes in the Generation Unit data entered in the Generation Unit Register.

CHAPTER 2

INFORMATION

Article 5

Monitoring the Energy Transactions System 1. The Transmission System Operator is required to monitor the operation of the Energy

Transactions System on a daily basis and keep relevant records, as well as the Registers provided for by the provisions of this Code.

2. In the context of such obligation, it is required to keep statistics and comparative data concerning the operation of the Energy Transactions System, prepare periodic reports notified to RAE, and publish the such information on its website, in the way approved by RAE decision.

Article 6

Supervising the Energy Transactions System RAE shall supervise the Transmission System Operator in terms of the exercise of its rights and the performance of its obligations in the context of the Energy Transactions System and in view of this it is particularly entitled to:

Α) have access to the Transmission System Operator’s facilities and the technical and financial records kept by it in respect of the operation of the Energy Transactions System, as well as all other relevant information;

Β) conduct ipso facto or following a report by third parties, checks, investigations and hearings relating to compliance with the provisions of this Code and impose the administrative sanctions provided for by the provisions of Law 2773/1999;

C) monitor the performance of the Transmission System Operator in accordance with the provisions of the System exclusive operation license and publish all related performance indicators.

Article 7

Transparency - Confidentiality 1. The Transmission System Operator is required to comply with the principle of

transparency and publish the statistics it collects regarding the transactions performed in the context of the Energy Transactions System.

2. The Transmission System Operator shall provide information to the public and in particular to the Participants upon the relevant request, in accordance with the provisions of this Code.

3. The obligation to inform is subject to compliance with the principle of confidentiality governing commercial transactions. The Transmission System Operator’s personnel is also required to comply with the principle of confidentiality.

4. Any general information regarding the operation of the System and the Participants, as well as information regarding historical data and statistics are not considered confidential.

5. The Transmission System Operator may classify any category or group of data as confidential following RAE’s prior approval.

6. By decision of the Transmission System Operator approved by RAE, a procedure shall be established regarding the disclosing to third parties and publishing data regarding the monitoring of the Energy Transactions System, ensuring uniform and systematic compliance with both the principle of transparency and safe information to the public, and the principle of confidentiality.

CHAPTER 3

RESOLUTION OF DISPUTES

Article 8

Scope Any disputes arising between the parties to the Energy Transactions Contract shall be resolved in accordance with the provisions of this Chapter.

Article 9

Amicable Settlement of Disputes 1. Each party to the Energy Transactions Contract may notify to the other party an

invitation to amicable settlement of disputes. Within three (3) days from receipt of such invitation, the Parties shall appoint and mutually notify their Representatives for the purpose of the settlement of disputes.

2. Such Representatives are required to enter into negotiations in good faith and in accordance with good trade practices in order to settle the dispute.

3. The results of such negotiations shall be reflected in a report signed by the Representatives and binding upon the parties.

4. The dispute settlement procedure shall be completed within thirty (30) days from the dispatch of the invitation to amicable settlement. The procedure for the Amicable Settlement of Disputes shall be carried out in Greek.

Article 10

Arbitral Expertise and Arbitration 1. Should a dispute not be settled using the Amicable Dispute Settlement procedure, the

parties shall take their dispute to RAE for arbitral expertise relating to the technical issues and the real incidents leading to the dispute, as well as for the sum corresponding to the services due and losses to be determined in accordance with the provisions of Article 371 of the Civil Code.

2. The arbitration procedure shall be conducted in Greek and in accordance with the provisions on arbitration of the Internal Operation and Management Regulation of the

Regulatory Authority for Energy (Presidential Decree 139/2001, Government Gazette Issue No. Α 121/2001), which apply accordingly.

3. The conclusion of RAE reached on the arbitration expertise shall be subject to judicial control in accordance with the law.

4. If the dispute is not settled through the procedure for Amicable Dispute Settlement, and if the parties agree, such dispute may be subjected to arbitration by RAE, in accordance with its Internal Operation and Management Regulation. RAE alone shall decide on all issues falling within the scope of its arbitration competency. The arbitration shall be conducted in Greek.

SECTION II

DAILY AHEAD SCHEDULING

CHAPTER 4

GENERAL PROVISIONS

Article 11

Purpose Daily Ahead Scheduling (DAS) aims at minimizing the total cost of serving the energy load for each Dispatch Day under conditions of good and safe System operation and ensuring sufficient reserves, by comparing the overall energy load requested resulting from the Load Declarations to the financial Energy Offers and through the DAS Schedule.

Article 12

DAS Time - Deadlines 1. In order to attain the purpose of the DAS, all procedures and actions provided for by

the provisions of this Section refer to one Dispatch Day, are completed in the day preceding the Dispatch Day and within the deadlines provided for herein.

2. Dispatch Day shall mean the 24-hour period coinciding with a calendar day. Dispatch Period shall mean an hour of the Dispatch Day. Dispatch Periods commence at 00:00 on the Dispatch Day.

3. Gate Closure shall mean 12 noon on the day preceding the Dispatch Day.

4. The calculation of deadlines in this Section shall refer to calendar days.

Article 13

Participation in the DAS Participation in the DAS shall mean in particular:

Α) the submission of Load Declarations by Load Representatives for Customers who consume energy within Greek Territory, production license holders or Suppliers for energy Exports, as well as by production license holders for Pumping Units in pumping operation and for the Auxiliary Loads and the General Auxiliary Loads of their Unit when these are not met by the Unit production. The Load Declarations of production license holders may also be submitted by Suppliers;

Β) the submission of Energy Offers by production license holders for Dispatchable Units, supply license holders and Self-Supplying Customers for energy Imports, and the Transmission System Operator for the Units under Article 35 of Law 2773/1999;

C) the submission of Water Resources Management Declarations by Hydro Unit production license holders, including Hydro Pumping Units;

D) the submission of Reserve Offers by production license holders for Dispatchable Units and the Transmission System Operator for Contracted Units for Ancillary Services;

E) the submission of Total or Partial Non-Availability Declarations by production license holders for Units;

F) the submission of Techno-Economic Declarations by production license holders for Units.

Article 14

Transmission System Operator’s Rights and Obligations In the context of the DAS, the Transmission System Operator shall:

Α) collect the Load Declarations, Energy Offers, Reserve Offers, and Water Resources Management Declarations. It shall submit the Energy Offers for the energy provided for from the Units listed in the provisions of Article 35 of Law 2773/1999, Energy Offers and Reserve Offers for Contracted Units for Ancillary Services and Energy Offers or Load Declarations corresponding to Adjusting Schedules for flow deviations at the Interconnections;

Β) prepare the Transmission System Constraints Study. It shall establish and publish the Load Forecasting, the needs of Primary, Secondary and Tertiary Reserve and the Transmission System Constraints in accordance with the provisions of the foregoing Study, and taking account of the information available for the System, the Generation Units, the System load and the Distribution Network;

C) calculate and publish the Coverage Specification Factors;

D) decide on the acceptance of the Declarations and Offers submitted in the context of participation in the DAS;

E) terminate the Energy Transactions Contract for Load Representatives that are unable to perform their financial obligations due to participation in the DAS, and in that case it may submit Load Declarations corresponding to the load of Customers and their Suppliers;

F) prepare the DAS Schedule and calculate the System Marginal Price;

G) keep and operate the DAS Settlement System, debit and credit Participant Accounts, issue the Instructions necessary to settle the transactions in the framework of the DAS, and may require of Customers to pay all debts and damages in case of non performance of financial obligations by their Supplier;

H) assign to a credit institution to take the bank actions required to perform the obligations resulting from participation in the DAS. The credit institution entering into a contract with the Transmission System Operation for that purpose shall be the DAS Settlement House;

I) assign to a credit institution to cover and transaction deficit in the context of the DAS in combination with the raising of claims against Customers in order to balance the DAS transactions, and for that purpose it shall enter into a Financial Coverage Contract;. The credit institution entering into a contract with the Transmission System Operation for that purpose shall be the Coverage Institution;

J) establish the Financial Coverage Cost, which corresponds to the financial cost of covering any transaction deficit, as well as the Fixed and Extraordinary Charge for Financial Coverage Costs which it may claim from Suppliers;

K) pay to Suppliers any surplus that may be generated in operation in respect of the coverage of any transaction deficits and the financial obligations of Suppliers;

L) operate the Energy Transaction Information Management System;

M) publish the System Marginal Price, as well as the statistics and information relating to the monitoring of the DAS operation;

N) prepare the DAS Manual and the Variable Cost Calculation Manual, which are approved by RAE;

O) take all other actions provided for by the provisions of this Code.

Article 15

Financial Coverage Cost 1. The Financial Coverage Cost in euros is calculated annually and includes:

Α) the Fixed Financial Coverage Cost, which corresponds to the fixed cost of providing the financial coverage service in accordance with the Financial Coverage Contract;

Β) the Extraordinary Coverage Cost, which corresponds to any DAS Transaction Deficit as established during DAS Settlement and the corresponding cost of the financial service for its coverage, as is provided for in the Financial Coverage Contract.

2. The Fixed Financial Coverage Cost shall be established annually and in euros per MWh by the Transmission System Operator and approved by RAE two (2) months. The sum corresponding to the Fixed Charge for Financial Coverage Costs shall be established for each Participant holding a supply license, allocating the annual Fixed Financial Coverage Cost to the energy quantity expressed in MWh, which the supply-license holder has supplied to Customers or for Export during the current calendar year to the date of the calculation. Should there be no activity during the current calendar year, the Fixed Charge for Financial Coverage Costs shall be established as if the supply license holder had supplied during the current calendar year one per cent (1%) of the overall energy quantity absorbed by the System in the previous calendar year.

3. Seven (7) days at the latest before the commencement of each calendar year, each Participant holding a supply license shall pay the annual Fixed Charge for Financial Coverage Costs corresponding to it. Should a Participant fail to pay in due time the Fixed Charge for Financial Coverage Costs, the Transmission System Operator may terminate the Energy Transactions Contract.

4. The sums collected for the Fixed Charge for Financial Coverage Costs shall be credited to the Special Account for DAS Financial Coverage kept by the Transmission System Operator. The sum corresponding to the annual Fixed Financial Coverage Cost shall be debited to the Special Account for DAS Financial Coverage.

CHAPTER 5

LOAD DECLARATIONS

Article 16

Submission of Load Declarations 1. In accordance with Article 13 and this Chapter, Load Declarations are submitted by

Suppliers, Self-Supplying Customers and Producers. These Participants are classified as "Load Representatives" when they submit Load Declarations in this context.

2. The Load Representatives that for a given Dispatch Day represent a Meter, must submit Load Declarations stating thereby per Meter Category for each Dispatch Period of the Dispatch Day the quantity of energy which the Load Representative believes is anticipated to be absorbed by all Meters of the Meter Category it represents, wholly or in part, on such Dispatch Day in accordance with the Meters to Load Representative Table.

3. The Load Representatives that on a given Dispatch Day wish to perform Exports or operate Pumping Units in pumping mode or serve the Auxiliary and General Auxiliary Loads of their Unit when these are not covered by the Unit production, must submit a Load Declaration for that Day.

4. During participation in the DAS, Load Representatives must demonstrate compliance with the Capacity Adequacy Obligation they have in accordance with CHAPTER 42 of this Code. In cases of non-compliance, the consequences under Article 224 shall be incurred and this shall not affect the validity of the Load Declaration.

5. If required, for each Dispatch Day on every Dispatch Day, the Transmission System Operator shall submit Load Declarations corresponding to Adjusting Schedules for flow deviations at the Interconnections.

Article 17

Contents of Load Declarations 1. The Load Declaration concerning a Customer’s absorption within Greek Territory

includes a table where the Load Representative states the energy quantity in MWh for each Dispatch Period on the Dispatch Day and for each Meter Category, if there is a Meter in the Category fully or partially represented on the Dispatch Day by such Load Representative. A decision of the Transmission System Operator subject to approval by RAE, may allow Load Declarations concerning Customer absorption

within Greek Territory to take the form of a stepwise function of price-quantity pairs, each step of which shall comprise a price (€ per MWh) and energy quantity (MWh) pair. In that case this function shall include up to ten steps, where energy prices for successive steps must be strictly non increasing. The energy price shall be expressed in euros with an accuracy of up to three (3) decimal points.

2. Load Declarations for Export shall include for each Dispatch Period of the Dispatch Day and for each Interconnection Corridor for Export a stepwise function of price-quantity pairs, each step of which shall comprise a price (€ per MWh) and energy quantity (MWh) pair. This function shall include up to ten steps, where energy prices for successive steps must be strictly non increasing.

3. Load Declarations for Pumping Units concern the energy consumed to pump water and include for each Dispatch Period of the Dispatch Day and for each Pumping Unit Meter or for all Meters of the Pumping Plant a stepwise function of price-quantity pairs, each step of which shall comprise a price (€ per MWh) and energy quantity (MWh) pair. This function shall include up to ten steps, where energy prices for successive steps must be strictly non increasing.

4. The energy quantity included in the Load Declaration shall refer to the energy absorbed at Meters per Meter Category or at an Interconnection Corridor for Export and shall be expressed with the accuracy of one MWh.

5. Details with regard to the contents of Load Declarations are established in the DAS Manual.

Article 18

Certification attesting to the performance of financial obligations

1. Load Declarations shall be accompanied by a certification issued by the credit institution with which the Load Representative keeps a Participant Account, attesting that there is sufficient balance in the Participant Account to perform its financial obligations from the specific Load Declaration. Such certification must be valid until the completion of the DAS Settlement procedure and for the specific Dispatch Day and may not be revoked for any reason whatsoever.

2. To establish the financial limit of coverage of the financial obligations corresponding to a Load Declaration for a given Dispatch Day, the product of the entire energy quantity in MWh as declared in the Load Declaration, multiplied by the Coverage Specification Factor in €/MWh, which is in force for the specific Dispatch Day and established in accordance with Article 22. In case of a Priced Load Declaration, energy quantity shall mean the total of the energy quantities of all steps in the Declaration.

Article 19

Submission and modification of Load Declarations 1. A Load Declaration concerning a given Dispatch Day shall be submitted at the

earliest within forty eight (48) hours prior to and up to the Gate Closure corresponding to the specific Dispatch Day. Within the same time period the initial Load Declaration may be replaced up to five (5) times.

2. Exceptionally, in accordance with Article 16 paragraph (5), Load Declarations are submitted up to two (2) hours before Gate Closure.

3. The Load Declarations submitted in due time shall be binding upon the Load Representatives having submitted them, until the issue and notification of the DAS Schedule.

4. Load Declarations submitted past the Gate Closure and failure to submit a mandatory Load Declaration shall entail the consequences established in Article 21.

Article 20

Acceptance of Load Declarations 1. The Transmission System Operator shall accept the Load Declarations that have been

submitted lawfully within one hour from their submission and in any case up to thirty (30) minutes from the Gate Closure.

2. In case of non acceptance of a Load Declaration, the Transmission System Operator shall notify to the Load Representative a justified non acceptance decision.

3. In order to establish the DAS Schedule it takes account of all accepted Load Declarations in force at Gate Closure.

4. Where a Load Declaration is not considered acceptable at Gate Closure, the consequences under Article 21 shall be incurred.

Article 21 Consequences of non lawful submission of Load Declarations

and cases of significant Deviations

1. If a Load Declaration is not accompanied by an acceptable certification in accordance with Article18, the Transmission System Operator invites the Load Representative to submit such certificate, setting for that purpose a deadline of up to one (1) hour and in any case of up to thirty (30) minutes from Gate Closure. Should the Load

Representative not submit the certificate after such time has elapsed, the Transmission System Operator:

Α) shall, if the Load Declaration has been submitted by a supply license holder and it corresponds to Customer load within Greek Territory, notify to the Declaration submitter an Energy Transactions Contract termination deed, publish such deed and notify it to the Customers of such Load Representative or the Distribution Network Operator depending on the connection method and remove the Meter Representation entries for the specific Dispatch Day from the Meters to Load Representative Correspondence Table. The submission of Load Declarations those Customers is allowed within one (1) hour by other supply license holders, or by the Customers themselves who act as Self-Supplying Customers, without requiring registration with the Participant Register and without such Customers being required to furnish sufficient capacity guarantees in accordance with CHAPTER 42 for two consecutive days. The provisions of Article 16 up to Article 18 also apply in this case. If more than one acceptable Load Declarations are submitted for the same Customer Meter, the Transmission System Operator shall select based on priority for inclusion in the DAS Schedule the Load Declaration of a Self-Supplying Customer and then the Load Declarations of supply license holders in the time order in which these have been submitted. If no Load Declarations are submitted within such period or if no Load Declaration is acceptable, the consequences of this Article shall be incurred only by the Load Representative to whom the Energy Transactions Contract termination deed has been notified, and the Load Declaration shall be submitted by the Transmission System Operator. In this case, the charge corresponding to such Declaration and which is established in the DAS Settlement shall constitute a Transaction Deficit for the Dispatch Day to which it refers, and the Transmission System Operator may take action against the Customers of such Supplier in order to collect all debts and damages incurred due to failure to lawfully submit the Load Declaration. Charges or credits shall be respectively added to or subtracted from this Deficit, which may result for such Load Declaration from the Imbalances Settlement Procedure and other charges of the Uplift Account.

Β) if the Load Declaration is not submitted by a supply license holder, the Transmission System Operator shall notify to the Participant having submitted it, an Energy Transactions Contract termination deed, disregard such Load Declaration in the preparation of the DAS Schedule, and launch on the same day the procedure of suspending energy supply to such Load Representative. The energy supply suspension procedure shall be carried out by the Transmission System Owner or the Distribution Network Operator by Instruction of the Transmission System Operator;

2. In all other cases of failure on the part of a Load Representative to lawfully submit a Load Declaration for a Dispatch Day to which it is obligated, the Transmission

System Operator shall in accordance with Article 73 charge such Load Representative for such Dispatch Day the sum of NCLD_S in euros, given by the following formula:

NCLD_S = UNCLD_S × MQpd × (1+Α_S) × (N-1)

Where:

UNCLD_S is the unit charge (€ per MWh and Dispatch Day),

A_S charge increase factor,

Ν total number of Dispatch Days having elapsed up until the unlawful submission of Load Declaration in the current calendar year on which the same Load Representative has submitted an unlawful Load Declaration,

MQpd Measured Energy Quantity at the Meters represented by the Load Representative on the Dispatch Day at hand.

3. The numerical values of UNCLD_S unit charge and the Α_S charge increase factor shall be established for each calendar year by decision of the Transmission System Operator which shall be approved by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

4. Where a Load Representative obligated to lawfully submit a Load Declaration for a Dispatch Day does so and a significant deviation is ascertained on such Dispatch Day between the energy quantity measured at the Meters represented by such Load Representative on the Dispatch Day at hand and the energy quantity stated in the Load Declaration of the same Load Representative, the Transmission System Operator shall in accordance with Article 73 charge such Load Representative the sum NCBAL_S in euros calculated using the following formula:

NCBAL_S = BAL_S × Σnt=1(MQpt - (1+BAL_TOL) × DASQpt) ×

(1+Α_Β) × (N-4)

where :

UNCLD_S is the unit charge (€ per MWh and Dispatch Day),

A_Β charge increase factor,

BAL_TOL Factor expressing the tolerance limit,

Ν total number of Dispatch Days up to and including the Dispatch Day at hand in the current month of the calendar year on which the same Load Representative has submitted Load Declarations for which a significant deviation has been ascertained between the lawfully submitted Load Declaration and the load measured,

MQpt Measured Energy Quantity at the Meters represented by the Load Representative on the Dispatch Day at hand,

n number of Dispatch Periods on the Dispatch Day at hand for which (MQpt-(1+BAL_TOL)×DASQpt) >0,

Σnt=1 sum for the Dispatch Periods of the Dispatch Day at hand during which

a significant deviation has been ascertained..

The above charge shall be due only when N-4>0, while in all other cases NCBAL_S = 0.

5. Significant deviation shall mean the case where the energy quantity measured at the Meters represented by the Load Representative for the Dispatch Period at hand of the Dispatch Day is by BAL_TOL% greater than the energy quantity in the Declaration submitted by the same Load Representative.

6. The numerical values of BAL_S unit charge, the Α_B charge increase factor, and the BAL_TOL tolerance limit shall be established for each calendar year by decision of the Transmission System Operator which shall be approved by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

Article 22

Coverage Specification Factors 1. The Coverage Specification Factors are established by the Transmission System

Operator following RAE’s approval for each Dispatch Day in a calendar year and may differ for each Load Representative based on the solvency criteria for each Load Representative. Such criteria include: the Load Representative’s solvency background inside the Energy Transactions System, the time of participation in such system, the annual load quantity represented, the number of customers, any submission of additional bank guarantees or financial solvency certificates, any obligation to supply non Eligible Customers or to last resort supply.

2. The numerical values of the Coverage Specification Factors are established for each Dispatch Day in a calendar year so that they approach as much as possible the anticipated mean value of the System Marginal Price for each Dispatch Day. In order to establish the numerical values, account is taken of the statistics kept by the Transmission System Operator regarding the numerical values of the System Marginal Price for each past Dispatch Day, data and conclusions of the Capacity Adequacy Study, and all other relevant information. The numerical values of the Coverage Specification Factors are established aimed at achieving a safe margin in order to ensure the transactions in the DAS and to avoid transaction deficit, on the one hand, and excessive financial charges for Load Representatives, on the other hand.

3. Coverage Specification Factors are published two (2) months prior to the commencement of the calendar year which they concern.

CHAPTER 6

ENERGY OFFERS

Article 23

Submission Obligation and Right 1. Production license holders are required to submit for each Dispatchable Unit a

separate fully binding Energy Offer for each Dispatch Period of every Dispatch Day, as well as for the entire capacity of the Unit. Production license holders are not entitled to submit Energy Offers for Contracted Units and Cold-Reserve Units. Where a unit is partially Dispatchable and partially Contracted, production license holders shall submit an Energy Offer only for the part corresponding to the Dispatchable Unit as this part or the relevant procedure is established in accordance with terms of the relevant Contract.

2. The obligation under paragraph (1) of this Article shall be suspended in the following cases:

Α) for the time in which the Unit is undergoing Scheduled Maintenance;

Β) during the period of validity of the Total Non-Availability Declaration.

3. During the period of validity of a Partial Non-Availability Declaration, production license holders are required to submit Energy Offers only for the overall capacity of the Unit that is technically available in accordance with such Declaration.

4. If supply license holders and Self-Supplying Customers wish to make Imports, engaging in their activities in accordance with the Law, they must submit a separate Energy Offer for energy Import for each Interconnection Corridor.

5. The Energy Offers for Import submitted by Self-Supplying Customers may not exceed the energy quantity in the Load Declaration they submit for the same Dispatch Period increased by the loss factor corresponding to the Energy Offer.

6. In case of an Auto-Producer Unit not falling within the scope of the provision of Article 35 of Law 2773/1999, the obligation to submit an Energy Offer concerns only the part of the Unit's capacity corresponding to such Unit's Net Capacity NCAP , as this is computed in accordance with Article 217.

7. Especially with regard to hydro Units, RES Units, and combined or open cycle gas turbines, and where there is an operational interdependence for such Units, following an application by the production license holder, the Transmission System Operator may approve the inclusion of Units in the same Hydro Plant or the same RES Unit complex installed in the same location or of the same combined or open cycle gas turbine in the scope of the provisions of SECTION I I to SECTION VI, as well as of SECTION XIV of this Code, per Plant or Unit complex or combined or open production respectively. In that case for the purpose of the provisions of SECTION I to SECTION VI, as well as of SECTION XIV of this Code, the term "Unit" shall be used for all the Units in the Plant or of the same combined or open cycle gas turbine.

Article 24

Energy Offer Contents 1. Energy Offers shall include for each Dispatch Period of a Dispatch Day a stepwise

function of price-quantity pairs, each step of which shall comprise an energy price (€ per MWh) whose numerical value shall be greater than and not equal to zero and energy quantity (MWh) pair. This function shall include up to ten steps, where energy prices for successive steps must be strictly non decreasing. The energy price shall be expressed in euros with an accuracy of up to three (3) decimal points.

2. The energy quantity included in the Energy Offer shall refer to the energy provided to the Connection Point of the Unit with the System or the Interconnection Corridor for Import in the System and shall be expressed with an accuracy of one (1) MWh.

Article 25

Thermal Unit Energy Offer Contents 1. The energy price for each step of the Energy Offer stepwise function must be less

than the Administratively Defined Energy Offer Cap and it may not be less than the Unit Minimum Variable Cost, as such limits apply for the Dispatch Period to which the Energy Offer corresponds.

2. Especially for the first step of the Energy Offer stepwise function, to which, from among all steps of the same function, a lower energy price corresponds, the offered energy price may be under the Unit Minimum Variable Cost. For a Dispatch Period, the energy quantity included in the first step of such stepwise function may not be higher than 30% of the overall energy quantity in the Energy Offer;

3. In any case, the mean energy price that is weighted with the energy quantities of each step for all steps of the Energy Offer stepwise function may not be less than the Unit

Minimum Variable Cost, as this limit applies to the Dispatch Period to which the Energy Offer stepwise function corresponds.

4. Energy Offers submitted for an Auto-Producer Unit not falling within the scope of the provision of Article 35 of Law 2773/1999, shall concern only the part of the Unit's capacity corresponding to such Unit's Net Capacity NCAP , as this is computed in accordance with Article 217. Furthermore, Energy Offers shall include any additional energy quantities injected beyond the Unit Net Capacity NCAP , for each Dispatch Period of the Dispatch Day. The stepwise function of price-quantity pairs for Auto-Producer Units shall concern the overall energy quantity offered.

Article 26

Hydro Unit Energy Offer Contents 1. Energy Offers submitted for Hydro Units, including Hydro Pumping Units in

productive operation, shall include the information established by Article 24. Energy Offers for Hydro Units concern energy quantities beyond those corresponding to the Mandatory Injection in accordance with Article 28.

2. The following restrictions shall apply to Energy Offers submitted for Hydro Units, including Hydro Pumping Units in productive operation:

Α) for each Dispatch Day a stepwise function of price-quantity pairs shall be submitted in accordance with Article 24, applicable to all Dispatch Periods of the Dispatch Day. Exceptionally, for Units with operational interdependence due to water flow, and for purposes of safe water resources management, a stepwise function of price-quantity pairs may be submitted in accordance with Article 24 for each Dispatch Period of the Dispatch Day;

Β) the energy price corresponding to the any step of the Energy Offer stepwise function may not be greater than the Administratively Defined Energy Offer Cap and less than the Unit variable cost established in accordance with Article 44 paragraph (4), as such limits apply to the Dispatch Period to which the Energy Offer refers;

C) especially for the first step of the Energy Offer stepwise function, to which, from among all steps of the same function, a lower energy price corresponds, the offered energy price may be under the Unit variable cost established in accordance with Article 44 paragraph (4). For a Dispatch Period, the energy quantity included in the first step of such stepwise function may not be higher than 30% of the overall energy quantity in the Energy Offer;

D) in any case, the mean energy price that is weighted with the energy quantities of each step for all steps of the Energy Offer stepwise function may not be less than the Unit variable cost established in accordance with Article 44

paragraph (4), as this limit applies to the Dispatch Periods to which the Energy Offer refers.

Article 27

Contents of Energy Offer for Import 1. Energy Offers for Import shall be submitted separately for each Interconnection

Corridor for Import, and shall include the information established by Article 24, along with a declaration regarding the origin of such energy in accordance with the UCTE provisions. The above restriction does not apply to the energy quantity included in the Energy Offer and a lower energy price equal to zero applies.

2. The energy price corresponding to any step must be less than the Administratively Defined Energy Offer Cap in the DAS.

Article 28

Water Resources Management Declarations 1. Hydro Unit production license holders, including Hydro Pumping Units, shall submit

the following Water Resources Management Declarations: a) Weekly Mandatory Hydro Operations Declarations; and b) Twelve-month Forecasted Water Usage Declarations.

2. Weekly Mandatory Hydro Operations Declarations must be submitted until 12:00 each Thursday and refer to seven Dispatch Days starting from the previous Saturday. Weekly Mandatory Hydro Operations Declarations shall establish for each Hydro Unit and each Dispatch Period of the seven Dispatch Days to which they refer, any energy quantity compulsorily injected and which corresponds to the following mandatory operations: a) water supply; b) irrigation; and c) overflow prevention.

3. No energy price is established for the energy injected compulsorily.

4. Weekly Mandatory Hydro Operations Declarations shall be accompanied by relevant documentation and shall be indicative. The authorized representatives of Hydro Unit production license holders may submit an application for modification of Weekly Mandatory Hydro Operations Declarations past the deadline for their submission, and in concert with the respective Region Secretaries General, for purposes related to the technical operation of the Units, emergency conditions and situations regarding the mandatory operations served, or safety issues. The Transmission System Operator may request ex post additional information if it believes the justification to be incomplete.

5. The Transmission System Operator shall publish the Weekly Mandatory Hydro Operations Declarations for each Unit immediately after the deadline for their submission. Furthermore, the Transmission System Operator shall publish immediately after the period to which each Weekly Mandatory Hydro Operations Declaration refers has elapsed, the energy quantity injected from each Unit due to mandatory operations and for each Dispatch Period of the previous seven Dispatch Days.

6. Production license holders must, at regular intervals established by the Transmission System Operator, document the energy quantity declarations concerning mandatory water supply, irrigation, and overflow prevention operations, by furnishing information relating to such obligations, as well as to the inflow-outflow balance at the reservoirs.

7. Twelve-month Forecasted Water Usage Declarations shall be prepared on a rotation basis, refer to the coming up twelve-month period and be submitted up to five (5) days prior to the commencement of the first month to which they refer. Twelve-month Forecasted Water Usage Declarations shall be submitted to the Transmission System Operator accompanied by documentation on maximizing the value of water resources and the total benefit to the energy sector from the use of Hydro Units.

8. Twelve-month Forecasted Water Usage Declarations shall establish the following for each month of the coming up twelve-month period and cumulatively for all Dispatch Periods of the Dispatch Days in each month, as well as cumulatively for all Hydro Plants of each production license holder, and for three hydro scenarios (high, low and intermediate total inflows):

Α) the schedule of forecasted energy injection due to mandatory water supply, irrigation, and overflow prevention operations;

Β) the schedule of forecasted additional energy generation;

C) anticipated water flows into reservoirs;

D) Forecasted water reserves in the reservoirs at the end of the month.

9. Within one (1) month after each Reliability Year, Hydro Unit production license holders must submit to the Transmission System Operator and RAE a balance report regarding water resources management during the previous Reliability Year. Such report shall include: a) the balance information under paragraph (8); b) comparison with the respective Twelve-month Forecasted Water Usage Declarations and justification of any deviations; c) documentation on maximizing the value of water resources and the total benefit to the energy sector from the use of Hydro Units.

Article 29

Energy Offers submitted by the Transmission System Operator

1. The Transmission System Operator shall submit for each Hydro Unit, including Hydro Pumping Units, energy offers corresponding to the mandatory operations of such Units, in accordance with the respective Weekly Mandatory Hydro Operations Declarations.

2. For each Dispatch Period of each Dispatch Day, the Transmission System Operator shall submit an Energy Offer establishing the energy quantity that is forecasted to be injected into the System and the Distribution Network by the Units under Article 35 of Law 2773/1999. The Transmission System Operator shall take all measures in order for such forecast to be as close as possible to the energy quantity to be generated by such Units.

3. If required, for each Dispatch Day on every Dispatch Day, the Transmission System Operator shall submit Energy Offers corresponding to Adjusting Schedules for flow deviations at the Interconnections.

4. For each unit not in commissioning operation, the Transmission System Operator shall submit Energy Offers for each Dispatch Period of each Dispatch Day corresponding to the injection of energy from such unit due to commissioning operation in accordance with CHAPTER 55. Production license holders shall receive payments for the energy corresponding to the above injections which are calculated based on the fuel cost and for which they shall submit Techno-Economic Declarations in accordance with Article 44.

5. No energy price shall be established in the Energy Offers under this Article; such energy price shall be taken to be equal to zero (0) for the DAS Schedule.

Article 30

Submission and Modification of Energy Offers 1. Energy Offers concerning a given Dispatch Day shall be submitted at the earliest

within forty eight (48) hours prior to and up to the Gate Closure corresponding to the specific Dispatch Day. Energy Offers submitted past Gate Closure shall not be accepted. Within the same time period the initial Energy Offer may be replaced up to five (5) times.

2. Exceptionally, Energy Offers submitted by the Transmission System Operator in accordance with Article 29 shall be submitted up to two (2) hours before Gate Closure.

Article 31

Energy Offer Acceptance 1. The Transmission System Operator shall accept Energy Offers if the terms of this

Code are complied with and shall take them into account when preparing the DAS Schedule.

2. In case of non acceptance of an Energy Offer, the Transmission System Operator shall immediately notify a justified decision of non acceptance to the Participant having submitted such Energy Offer.

Article 32

Consequences of unlawful submission of Energy Offers 1. In case of unlawful submission of Energy Offers for a Dispatch Day by a production

license holder obligated to such submission, the Transmission System Operator shall in accordance with Article 73 charge such Producer for such Dispatch Day the sum of NCΙΟ_G in euros, given by the following formula:

NCIO_G = UNCIO_G × NCAP × (1+Α_G) × (N-1)

Where:

UNCIO_G is the unit charge (€ per MW and Dispatch Day),

A_G charge increase factor,

Ν total number of Dispatch Days having elapsed up until the unlawful submission of the Energy Offer in the current calendar year on which the same production license holder has submitted an unlawful Energy Offer,

NCAP the Unit net capacity in accordance with the Dispatchable Unit Register.

2. The numerical values of UNCIO_G unit charge and the Α_G charge increase factor shall be established for each calendar year by decision of the Transmission System Operator which shall be approved by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

CHAPTER 7

RESERVE OFFERS

Article 33

Submission Obligation and Right 1. Production license holders must submit a separate a fully binding Reserve Offer for

each Dispatchable Unit for each Dispatch Period of each Dispatch Day and for the overall capability of each Unit to provide Primary Control Reserve and Secondary Range in accordance with its Declared Characteristics. Production license holders are not entitled to submit Reserve Offers for Contracted Units and Cold-Reserve Units. Where a unit is partially Dispatchable and partially Contracted, production license holders shall submit a Reserve Offer only for the part corresponding to the Dispatched Unit as this part or the relevant procedure is established in accordance with terms of the relevant Contract.

2. The obligation under paragraph (1) of this Article shall be suspended in the following cases:

Α) for the time in which the Unit is undergoing Scheduled Maintenance;

Β) during the period of validity of the Total Non-Availability Declaration.

3. During the period of validity of a Partial Non-Availability Declaration, production license holders are required to submit Reserve Offers only for the overall capability of each Unit to provide Primary Control Reserve and Secondary Range corresponding to the total Unit capacity technically available in accordance with such Declaration and its Declared Characteristics.

4. Reserve Offers submitted for Auto-Producer Units not falling within the scope of the provision of Article 35 of Law 2773/1999, shall concern the part of the capacity of such Units for which the Reserve Offers are submitted.

Article 34

Reserve Offer Contents 1. Reserve Offers shall include for each Dispatch Period of a Dispatch Day two (2)

capacity prices (€ per MW), namely one price for the Primary Control Reserve and one for the Secondary Range, with a numerical value greater than and not equal to zero. Such two capacity prices shall be in euros per MW, with an accuracy of up to three (3) decimal points.

2. The Reserve Offer pair for each one of the Primary Control Reserve and Secondary Range services shall comprise for each Unit the capacity price defined above for each service, and the Primary Control Reserve and the Secondary Range, as such figures are established in the Unit Techno-Economic Declaration.

3. The capacity price for each Reserve Offer for each Ancillary Service must be less than the Administratively Defined Energy Offer Cap for such Service.

Article 35

Reserve Offers submitted by the Transmission System Operator

For each Dispatch Period of each Dispatch Day, the Transmission System Operator shall submit a Reserve Offer for each Ancillary Service Contracted Unit, in accordance with the provisions of this Chapter in terms of the type and contents of Dispatchable Unit Reserve Offers. The capacity price (€/MW) in such Offers shall be determined in accordance with the relevant Ancillary Services Contract.

Article 36

Submission and Modification of Reserve Offers Reserve Offers concerning a given Dispatch Day shall be submitted at the earliest within forty eight (48) hours prior to and up to the Gate Closure corresponding to the specific Dispatch Day. Reserve Offers submitted past the Gate Closure shall not be accepted. Within the same time period the initial Reserve Offer may be replaced up to five (5) times.

Article 37

Reserve Offer Acceptance 1. The Transmission System Operator shall accept Reserve Offers if the terms of this

Code are complied with and shall take them into account when preparing the DAS Schedule.

2. In case of non acceptance of a Reserve Offer, the Transmission System Operator shall immediately notify a justified decision of non acceptance to the Participant having submitted such Reserve Offer.

Article 38

Consequences of unlawful submission of Reserve Offers 1. In case of unlawful submission of Reserve Offers for a Dispatch Day by a production

license holder obligated to such submission, the Transmission System Operator shall in accordance with Article 73 charge such Producer for such Dispatch Day the sum of NCRO_G in euros, given by the following formula:

NCRO_G = UNCRO_G × (RCAP_P + RCAP_S) × (1+ΑR_G) × (N-1)

where :

UNCRO_G is the unit charge (€ per MW and Dispatch Day),

ΑR_G charge increase factor,

Ν total number of Dispatch Days having elapsed up until the unlawful submission of the Reserve Offer in the current calendar year on which the same production license holder has submitted an unlawful Reserve Offer,

RCAP_P, RCAP_S the Unit’s Primary Control Reserve and Secondary Range respectively, in accordance with its Declared Characteristics.

2. The numerical values of UNCRO_G unit charge and the ΑR_G charge increase factor shall be established for each calendar year by decision of the Transmission System Operator which shall be approved by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

CHAPTER 8

GENERATION UNIT NON-AVAILABILITY

Article 39

Non-Availability Declaration 1. In case of an outage exclusively due to technical cause related to the operation or

safety of the Unit installation, and which renders energy generation by the Unit impossible, the production license holder must submit a Total Non-Availability Declaration for the Dispatch Day when such inability appears, establishing the Dispatch Periods in the Dispatch Day during which there is generation inability. The Total Non-Availability Declaration may establish a time period of more Dispatch Days during which it is anticipated that there shall be generation inability.

2. In case of a outage exclusively due to technical causes related to the operation or the safety of the Unit installations, or in case of other technical reasons implying Unit inability to generate energy corresponding to such Unit’s Net Capacity as this is listed in the Generation Unit Register, the production license holder must submit a Partial Non-Availability Declaration for the Unit for the Dispatch Day on which such inability exists, indicating the maximum available Unit capacity in each Dispatch Period of the Dispatch Day on which there is reduced generation capacity. The Partial Non-Availability Declaration may establish a time period of more Dispatch Days during which it is anticipated that there shall be reduced generation capacity. In that case, a single reduced generation capacity shall be established for the entire Dispatch Days period.

3. In particular with regard to Hydro Units, Non-Availability Declarations may be submitted by invoking Plant downstream water flow constraints for safety reasons, which are sufficiently documented and substantiated.

4. Total or Partial Non-Availability Declarations include a description of the technical causes to which the non-availability of the Unit is owed. During a Unit commissioning operation period and until the date of commencement of its commercial operation, the production license holder may submit a Partial Non-Availability Declaration without invoking another special reason.

5. Total or Partial Non-Availability Declarations shall be submitted during Energy Offer submission until the Gate Closure corresponding to the Dispatch Day which it concerns. A production license holder may revoke the Declaration past the Gate Closure for the Dispatch Day for which total or partial non-availability is stated. In that case, it shall not be entitled to participate in the DAS Schedule and the provisions of Article 79 of this Code shall apply.

6. The term of validity of Partial or Total Non-Availability Declarations shall be the total number of Dispatch Periods listed in them. Such declarations shall remain in force until the end of their term of validity, unless revoked earlier by the respective production license holders. A declaration shall cease to be in force before its term of validity has elapsed if the Transmission System Operator cancels such declaration in accordance with the provisions of Article 40.

7. The term of validity of Partial or Total Non-Availability Declarations may not refer to a point in time prior to the submission of such Declarations.

Article 40

Consequences of non lawful submission of Non-Availability Declarations

1. The Transmission System Operator and RAE in the context of its competencies in accordance with Article paragraph 5 (4) of Law 2773/1999, shall verify whether Non-Availability Declarations submitted are true and accurate and meet the requirements of this Code. To that end, following prior notice in written setting a reasonable deadline, production license holders having submitted a Non-Availability Declaration must submit documents and reports to the Transmission System Operator and RAE and allow RAE access to the relevant spaces, as well as all related information. In case of an audit by RAE, the latter shall issue its conclusion notified to the Transmission System Operator and binding upon the latter.

2. The Transmission System Operator may by a justified decision notified to the production license holder cancel a Total or Partial Non-Availability Declaration the term of validity of which has not expired or consider unlawful a Declaration the term of validity of which has expired, if it finds that such declaration is untrue and inaccurate or that it has been submitted in breach of the requirements of this Code. Once the production license holder has received the Transmission System Operator’s decision the suspension of the obligation to submit Energy Offers or the possibility to submit Energy Offers for reduced capacity availability, as the case may be, shall expire. Within five (5) days from which such decision has been received, the production license holder may lodge an objection to the Transmission System Operator. The Transmission System Operator shall issue a final justified decision on such objection within five (5) days; such decision shall be notified in writing to the production license holder. If such period elapses it shall be considered that the objection has been rejected.

3. In case of a decision to cancel a Dispatchable Unit Declaration or finding such a declaration unacceptable, the Transmission System Operator shall in accordance with Article 73 charge the production license holder the sum of NCNAD_G expressed in euros, which is given by the following formula.

NCNAD_G = UNCNAD_G × NCAP × (1+Α_D) × (N-1)

Where:

UNCNAD_G is the unit charge (€ per MW and Dispatch Day),

A_D charge increase factor,

Ν total number of Dispatch Days having elapsed up until such invalid or unacceptable Non-Availability Declaration in the current calendar year on which the same submitter has submitted an invalid or unacceptable Non-Availability Declaration,


4. The numerical values of UNCNAD_G unit charge and the Α_D charge increase factor shall be established for each calendar year by decision of the Transmission System Operator which shall be approved by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

Article 41

Long-term Non-Availability Declarations 1. If a Unit is unable to operate due to technical reasons for a period anticipated to

exceed a period of ten (10) consecutive days between June 15th and August 31st or three (3) consecutive months (Major Outage) for the rest of the year, the production license holder must immediately submit a Major Outage Declaration indicating the technical reasons and the time anticipated to be required to restore the outage.

2. If the Production License or the Operation License is revoked or their validity ceases temporarily or definitely in any other way, as well as in all other cases of operation inability of a Unit not due to unforeseen minor outages for which Partial or Total Non-Availability Declarations are submitted, the production license holder must immediately submit an Operation Inability Declaration indicating the reasons and the time anticipated to be required to restore operation of the Unit.

3. The Transmission System Operator shall evaluate the Declarations submitted in accordance with this Article in terms of the real state of the technical operation of the Unit, as well as in terms of the possibility to remove the reasons leading to operation inability, and issue a relevant conclusion establishing therein the Temporary or Definite nature of such operation inability. In case of a Temporary operation inability, the Transmission System Operator shall fix the date on which the operation of the Unit shall be resumed.

4. The production license holder may within fifteen (15) days from the notification of such Transmission System Operator’s conclusion lodge a justified objection against it. The Transmission System Operator shall issue a justified decision on such objections. Any disputes that may arise between the parties shall be settled following the procedure established in Article 10.

Article 42

Intention to Suspend Normal Operation Declarations If a production license holder intends to suspend the normal operation of a Unit, either because it wishes to remove the Unit or simply because it wishes to suspend its operation for a long time period exceeding the three (3) Reliability Years, then it shall submit to the Transmission System Operator an Intention to Suspend Normal Operation Declaration detailing therein the reasons, the date of suspension of the normal operation of the Unit, and the period during such operation shall be suspended, at least six (6) months prior to the desired date for the suspension of the normal operation of such Unit.

CHAPTER 9

TECHNO-ECONOMIC DECLARATIONS

Article 43

Obligation to submit declarations Production license holders for Units registered with the Generation Unit Register must submit Techno-Economic Declarations separately for each Generation Unit.

Article 44

Contents of Techno-Economic Declarations 1. Techno-Economic Declarations include the information given in the following tables.

Details are given in the DAS Manual. The technical information in the Declaration must agree with the Registered Statistics for the Unit and correspond to the real operation technical information for such Unit. The economic information in the Declaration must be cost-oriented, namely they must reflect the expenses actually incurred by the production license holder as these are allocated in each case and computed in accordance with the definition of each economic figure in the Declaration in accordance with this Code.

A. Technical parameters

A1. Unit operation technical information

Description Numerical value

Measuring unit

Unit Net Capacity (NCAP) as defined in Article 217 MW

Maximum Continuous Generation Capability (Unit Net Capacity after taking into account the internal service and the Unit Auxiliary Loads)

MW

Maximum Continuous Generation Capability under ISO conditions (Unit Net Capacity after taking into account the Unit internal service and auxiliary loads)

MW

Technical Minimum Generation (Unit Net Capacity after taking into account the Unit internal service and auxiliary loads)

MW

Minimum Up time hours

Minimum down time hours

Maximum generation capability (capacity) MW

Price for Maximum generation capability (in case of ancillary service) €/ MWh

Maximum operation time at maximum generation capability time

Time off load before going into longer standby conditions

Hot to warm time

Warm to cold time

Time to synchronize

Hot time

Warm time

Cold time

Minimum time in addition to time to synchronize in case of revocation from total non-availability state time

Operation from synchronization to technical minimum generation

Soak time

Hot time

Warm time

Cold time

Synchronization load MW

Time from minimum generation to de-synchronization time

Operation from technical minimum generation until maximum continuous generation capability (the rates established are also used in the DAS)

Minimum Guaranteed Ramp Up Rate (hereinafter referred to as Ramp Up Rate) from technical minimum generation to maximum continuous generation capability

MW/minute

Minimum Guaranteed Ramp Down Rate (hereinafter referred to as Ramp Down Rate) from maximum continuous generation capability to technical minimum generation

MW/minute

A2 Unit technical information for Ancillary Services

Maximum continuous reactive power capability (under injection point nominal voltage)

MW Mvar

Leading for active power generation equal to technical minimum generation, maximum generation capability and for five (5) intermediate active power levels.

MW Mvar

Lagging for active power generation equal to technical minimum generation, maximum generation capability and for five (5) intermediate active power levels.

Automatic Generation Control (AGC)

AGC Maximum load MW

AGC Minimum load MW

Rate of generation change while operating under AGC MW/minute

Secondary Control Range MW

Other technical information related to ancillary services

Black start capability YES/ NO

Primary Control Reserve MW

Standing reserve MW

A3. Additional technical information for Hydro Units established in accordance with Article 315

Prohibited continuous operation zones due to oscillations

(……, ……) (MW, MW) above and under the zone definition limit

(……, ……) (MW, MW) above and under the zone definition limit

B. Variable Cost Parameters for thermal generation Units

Net Generation Level (MW)

Specific Fuel Consumption (GJ/MWh)

Fuel Specific Consumption Stepwise Function The interval between the load with synchronization up to maximum continuous generation capability is divided into ten (10) steps which are taken so as to better approach the technical input-output curve.

Fuel A

Fuel B

Fuel cost by fuel type

Fuel C

€/quantity measuring unit

Fuel A

Fuel B

Fuel Lower Heating Value (LHV)

Fuel C

GJ/quantity measuring unit


Fuel A (%)

Fuel B (%)

Fuel C (%)

Percentage fuel composition at each capacity interval of the Fuel Specific Consumption Stepwise Function.


Cost (€/MWh)

Special cost for raw materials besides fuel in each capacity interval of the Special Fuel Consumption Stepwise Function.


Cost (€/MWh)

Special cost of additional maintenance expenses due to operation (with the exception of fixed maintenances expenses) at each capacity interval in the Fuel Special Consumption Stepwise Function.


Cost (€/MWh)

Special cost for additional workforce expenses due to operation (besides workforce fixed expenses) at each capacity interval in the Fuel Special Consumption Stepwise Function.

C. Cost Parameters following Dispatch Instructions

Description Numerical value Measuring unit

Additional variable cost (expenses corresponding to additional operation or maintenance cost) to supply reactive power besides the maximum continuous reactive power generation capability established in A2 of this table

€/Mvar-h

From cold standby

From warm standby

Start up cost from cold, warm or hot standby until load with synchronization

From hot standby

€/startup

Fuel cost concerning the maintenance of Unit standby when not generating €/MW-h

Operation and maintenance cost besides fuel cost, concerning the maintenance of Unit standby when not generating

€/MW-h

2. The fuel cost stated in Techno-Economic Declarations corresponds to all expenses incurred by production license holders to supply fuel regardless of the type of individual cost elements. Supply is defined as if the license holder were supplied with fuel from an independent person, which uniformly charges a fuel price for each unit of fuel quantity it supplies. Where there is lack of documentation through purchase invoices or other equivalent documents, fuel cost shall be computed as the ratio of total fuel supply expenses or cost as such expenses or cost have been registered for a sufficient time period to the total fuel quantity a production license holder is supplied

with for the Generation Unit during such time period. All details are established in the Variable Cost Calculation Manual prepared by the Transmission System Operator and approved by RAE. Fuel cost may be checked by RAE.

3. In order for the Transmission System Operator to establish the Thermal Unit Variable Cost, it processes the information in Techno-Economic Declarations as follows:

Α) the Variable Cost curve is taken by Part B of Techno-Economic Declarations as are in force.

Β) the minimum numerical value of the Variable Cost curve is established which as documented corresponds to optimum Generation Unit operation. This value establishes the Minimum Variable Cost for a Generation Unit for a Dispatch Day.

4. For the implementation of the provisions of the present Code, the variable cost of the Hydro Units is determined upon a numerical value expressed in Euro per MWh, constant and unique for each set of cascade Hydro Units. Such value is established annually by RAE based on the water usage value for each set of cascade Hydro Units, as this is readjusted by the water opportunity value reflecting variable cost savings of the thermal generation system. RAE’s decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

5. Techno-Economic Declarations submitted for an Auto-Producer Unit not falling within the scope of the provision of Article 35 of Law 2773/1999, shall concern only the part of the Unit's capacity corresponding to such Unit's Net Capacity NCAP , as this is computed in accordance with Article 217.

6. As Unit Declared Characteristics shall be taken the characteristics established by responsibility of the Transmission System Operator as a combination of the following technical and operational characteristics of a Unit and represent the applicable technical capabilities of such Unit for a specific Dispatch Period and Day:

Α) Registered Unit Characteristics

Β) Techno-Economic Declaration

C) Approved Exceptions in accordance with Article 315 and Article 47 related to the technical characteristics.

D) Non Availability Declaration (Total or Partial)

E) Information submitted to the Transmission System Operator in accordance with Article 79.

Article 45

Techno-Economic Declaration Submission Procedure 1. Techno-Economic Declarations are binding and are submitted until Gate Closure for

the first Dispatch Day to which they refer.

2. Techno-Economic Declarations refer to one or more Dispatch Days and apply if found acceptable. Newer Techno-Economic Declarations if lawfully submitted shall replace all previous ones.

Article 46

Acceptance and Rejection of Techno-Economic Declarations by the Transmission System Operator

1. The Transmission System Operator shall consider lawfully submitted all Techno-Economic Declarations submitted in a timely manner and in accordance with Article 43 to Article 47 of this Code. Where a Techno-Economic Declaration is considered unlawfully submitted, the latest lawfully submitted Declaration shall be in force. Where there is no lawful declaration for a Unit, the Transmission System Operator shall inform RAE to that respect in view of the imposition of the sanctions laid down in Article 33 of Law 2773/1999, and shall admit as Declared Characteristics for such Unit its Registered Characteristics.

2. Lawfully submitted Techno-Economic Declarations shall be accepted by the Transmission System Operator. Techno-Economic Declarations found to be inaccurate and untrue following an audit in accordance with Article 44, shall be considered unacceptable by the Transmission System Operator and shall not be considered to be lawfully submitted, hence the latest lawfully submitted Declaration shall be in force.

3. The Transmission System Operator and RAE in the context of its competencies in accordance with Article paragraph 5 (4) of Law 2773/1999, shall verify whether Techno-Economic Declarations submitted are true and accurate in accordance with Article 44 and meet the requirements of this Code. To that end, following prior notice in written setting a reasonable deadline, production license holders having submitted a Techno-Economic Declaration must submit documents and reports to the Transmission System Operator and RAE and allow RAE access to the relevant spaces, as well as all related information. Where RAE performs an audit, RAE shall issue a conclusion on the acceptance or not of the Declaration, to be notified to the Transmission System Operator and which shall be binding upon the latter. Upon completion of the audit, the Transmission System Operator by its justified decision notified to the production license holder and RAE shall finalize the acceptance or not

of the Techno-Economic Declaration. Once the Transmission System Operator’s decision has been received and provided the Techno-Economic Declaration has not been accepted and refers to current or future Dispatch Days, the production license holder is required to immediately submit a new Techno-Economic Declaration. Within five (5) days from which such decision has been received, the production license holder may lodge an objection to RAE. RAE, following a motion by the Transmission System Operator submitted within five (5) days, shall decide on such objection within seven (7) days, and notify its decision to the production license holder and the Transmission System Operator. If such period elapses it shall be considered that the objection has been rejected.

4. In case of a decision on a unacceptable Techno-Economic Declaration from a Dispatchable Unit, the Transmission System Operator shall in accordance with Article 73 charge the production license holder the sum of NCTED_G expressed in euros, which is given by the following formula:

NCTED_G = UNCTED_G × NCAP × (1+Α_ΤD) × (N-1)

Where:

UNCTED_G is the unit charge (€ per MW and Dispatch Day),

A_ΤD charge increase factor,

Ν total number of Dispatch Days having elapsed up until such unacceptable Techno-Economic Declaration in the current calendar year on which the same submitter has submitted an unacceptable Techno-Economic Declaration,


5. The numerical values of UNCTED_G unit charge and the Α_TD charge increase factor shall be established for each calendar year by decision of the Transmission System Operator which shall be approved by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

Article 47

Technical information for Ancillary Services 1. Especially the information established in parts A2 and A3 of Techno-Economic

Declarations must meet the special planning and performance specifications for thermal and hydro units in accordance with Article 275. The information under parts Α2 and Α3 may not comply with such specifications only if an exemption from such specifications has been approved in advance in accordance with Article 315 and only for the time period to which such exemptions apply.

2. If an application for exemption regarding the information under part A2 of Techno-Economic Declarations entitled Unit technical information for Ancillary Services, regards the reduction of a unit's capability, the respective production license holder must submit along with their application a declaration for the increase of the numerical values for the respective Technical information for Ancillary Services of other Dispatchable Units, in order to offset the reduction applied for throughout the period to which the application for exemption refers. Production license holders accepting the increase of the mandatory provision of Ancillary Services by their Units shall submit another declaration along with this declaration.

Alternatively to the above requirement to offset Ancillary Services, production license holders may submit a request for temporary postponement of performance of such obligation. The Transmission System Operator shall examine the possible consequences the granting of such postponement may have, documenting such consequences on the short- and long-term adequacy of the country’s transmission system in terms of the Ancillary Services to which the production license holder’s request for exemption refers and shall present a motion to RAE, the latter being responsible to grant the relevant approval. The approval of the temporary postponement of the performance of such obligation by a production license holder shall be valid for a year and may be renewed for the following year using the same procedure.

3. Applications for exemption from a unit’s technical information for Ancillary Services shall be submitted to the Transmission System Operator who, taking into account the technical evaluation of the capabilities of the suggested units and ensuring an adequate provision of Ancillary Services for the Transmission System, shall decide on approval of such applications within forty five (45) days. If such period elapses it shall be considered that the application has been rejected. Within five (5) days from which such decision has been received, the production license holder may lodge an objection to RAE. RAE, following a motion by the Transmission System Operator submitted within five (5) days, shall decide on such objection within seven (7) days by issuing a justified decision, which is notified in writing to the production license holder and the Transmission System Operator. If such period elapses it shall be considered that the objection has been rejected.

4. Where an application for exemption from a unit’s Technical information for Ancillary Services is approved and throughout the period of its validity, the information established in part A2 “Unit technical information for Ancillary Services” of the Techno-Economic Declaration and refer to the Units established in the exemption in question, must comply with the increased capability to provide Ancillary Services during the period of such approved exemption.

CHAPTER 10

LOSS FACTORS

Article 48

Generation Loss Factor Table The Generation Loss Factor Table establishes the numerical value of the generation loss factor corresponding to each Generation Unit Meter injecting into the Transmission System, and to each Interconnection Meter for Import. The generation loss factor corresponds to the part of Transmission System Losses which are allocated to injections from Generation Units and Imports. Such factors may have different numerical values for Dispatch Periods and Days.

Article 49

Load Loss Factor Table The Load Loss Factor Table establishes the numerical value of the energy absorption loss factor corresponding to each Meter Category of the Distribution Network. The Load Loss Factor corresponds to the part of total losses allocated to the electric load absorbed for consumption in the Distribution Network and which is computed taking into account only load loss in the Distribution Network. Such factors may have different numerical values for Dispatch Periods and Days.

Article 50

Loss Factor Specification Study 1. The numerical values in the Generation Loss Factor Table and the Load Loss Factor

Table are established by a special study conducted by the Transmission System Operator, taking into account the Distribution Network’s loss factors established in accordance with Article 157 paragraph (4). Such study is approved by RAE and is valid from the beginning of the following calendar year and for at least two (2) successive years.

2. In order to reduce the number of loss factors, the Transmission System Operator may calculate a single value for the factors in the Generation Loss Factor Table or the Load Loss Factor Table for a predetermined set of Dispatch Periods. The grouping is justified by similar comparative information.

3. The Transmission System Operator may calculate separately the Loss Factor for each Registered Meter or calculated it on a zone basis establishing the same loss factor in geographically neighbouring and connected nodes of the respective zone.

CHAPTER 11

SYSTEM LOAD, SYSTEM INTER-ZONAL CONSTRAINTS, AND RESERVE REQUIREMENTS FORECASTING

Article 51

Transmission System Operator obligations regarding Load, System Inter-Zonal Constraints, and Reserve Requirement

Forecasting In the context of Daily Ahead Scheduling, the Transmission System Operator shall:

Α) generate the Load Forecast for each Dispatch Day;

Β) conduct the System Inter-Zonal Constraint Study and generate the System Inter-Zonal Constraint Forecast establishing the values of System Inter-zonal Constraints per Dispatch Period;

C) generate the Reserve Constraint Forecast for each Dispatch Day;

D) select and put in place suitable Load, System Inter-Zonal Constraint and Reserve Requirement forecast methods using reliable and suitable scientific methodologies;

E) two (2) hours prior to Gate Closure, it shall publish in its website the following information for each Dispatch Period of the Dispatch Day:

(1) total System Load Forecast;

(2) System Reserve Requirement Forecast;

(3) System Inter-Zonal Constraint Forecast;

(4) the energy quantities in the Energy Offers submitted by the Transmission System Operator in accordance with Article 29, cumulatively for each Dispatch Period; and

(5) the Load Declarations in accordance with Article 16 paragraph (5).

F) Until 10:00 am each day, it shall publish in its website balance information for each Dispatch Period of the previous Dispatch Day, regarding the deviations of

the real Transmission System operation and of other installations from the Forecasts, the Energy Offers, and the Load Declarations of paragraph (E) above;

G) Keep records with regard to the data and other parameters used for Load, System Inter-Zonal Constraint, and Reserve Requirement Forecasts, as well as the results of the Load Forecast for each calendar year. The Transmission System Operator shall publish and notify to RAE statistics about the accuracy of the foregoing Forecasts within two (2) months from the end of each calendar year.

Article 52

Load Forecast 1. With regard to the Load Forecast the Transmission System Operator takes account of

the following information concerning the Dispatch Day in question:

Α) historical Load data and statistics resulting from their processing, such as Load evolution per energy usage category;

Β) weather condition forecasts, historical load data under similar weather conditions, as well as comparable statistics, and especially Load co-variation and weather condition parameters;

C) Events which the Transmission System Operator knows in advance they will occur in accordance with CHAPTER 22;

D) Load Shedding and/ or Transmission Network operations that shall affect the average hourly Load at a certain Connection Point in the Transmission System, of which the Transmission System Operator has been informed in accordance with Article 81;

E) other information collected and/ or notified to the Transmission System Operator in accordance with CHAPTER 17.

2. As a result of Load Forecast, the Active Power absorption for each Dispatch Period of the Dispatch Day is estimated with regard to:

Α) the Transmission System’s total Load; and

Β) the Load at certain Transmission System nodes which are selected by the Transmission System Operator.

3. Load Forecasts are indicative and concern only DAS Participants, and under no circumstances do they exempt such Participants from their obligations in the context of the DAS in respect of submitting Offers and Declarations, nor from their obligations arising from the Dispatch Procedure and the Imbalances Settlement Procedure.

Article 53

Transmission System Constraints Study 1. The Transmission System Constraints Study aims at analyzing and forecasting cases

of Transmission System Constraint activation in relation to System load, generation Unit availability, Transmission System equipment availability, and Transmission System development works.

2. Transmission System Constraints refer to Transmission System equipment loading constraints, compliance with voltage limits and voltage stability margin, which, if activated, limit the possibility of energy flow from points of injection to the Transmission System to the points of absorption by the Transmission System.

3. The Transmission System Constraints Study documents:

Α) the definition of System Operational Zones which correspond to parts of the System which are connected with transmission lines energy flow on which is limited in the case of activation of Transmission System Constraints. Where Transmission System Constraints have been activated which are satisfied by limiting the flow of energy on interconnection lines between the System Operational Zones, as a rule the operation of the System inside each Operational Zone must not be affected by other Transmission System Constraints. For illustration purposes it is stated that the unequal generation and consumption dispatch between North and South of the country’s interconnected Transmission System is expected to lead initially to the establishment of respective System Operational Zones due to Transmission Constraints concerning System stability;

Β) the standardization of cases of Transmission System Constraint activation and the preparation of a set of Inter-Zonal Congestion Rules which correlate the operation of Units, System equipment and the System Load with Transmission System Constraints. Inter-Zonal Congestion Rules are practical rules describing the constraints imposed on the operation of Units by geographical area or Operational Zone or to energy flow on interconnection lines among Operational Zones, due to Transmission System Constraints, in various System equipment availability states, System loads, other Unit availability, weather condition, etc.

C) the assessment of the possibility to activate individual Transmission System Constraints in correlation with the total Load of the System;

D) System development works which may prevent the activation of Transmission System Constraints, as well as the techno-economic analysis of the anticipated impact of such works on the total energy generation and transmission cost for end consumers.

4. The Transmission System Constraints Study may integrate load flow analysis methods, voltage stability analysis methods and load flow optimization methods. The

Transmission System Constraints Study shall be prepared by the Transmission System Operator following RAE approved procedures, publication rules and methodology.

5. The Transmission System Constraints Study shall be prepared on an annual rotation basis and the Study time shall be a five-year period inclusive of the current Reliability Year.

Article 54

System Inter-Zonal Constraint Forecasting 1. With regard to the Load Forecast the Transmission System Operator takes account of

the following information concerning the Dispatch Day in question:

Α) the Transmission System Constraints Study and more specifically the Inter-Zonal Congestion Rules;

Β) the Load Forecast;

C) the anticipated operation state of System elements;

D) other data and information which in its opinion affect the possibility of activating the Transmission System Constraints.

2. As a result of the System Inter-Zonal Constraint Forecast the Inter-zonal Congestion Rules are established for each Dispatch Period of the Dispatch Day which correspond to the Transmission System Constraints that are anticipated to be activated, as well as the numerical values of the parameters of such Inter-Zonal Congestion Rules and the conclusions arising from them.

3. The System Inter-Zonal Constraint Forecast is indicative for DAS Participants and is not binding upon the Transmission System Operator.

Article 55

Reserve Requirement Forecasting 1. During Reserve Requirement Forecasting, the Transmission System Operator shall

assess the need to provide Frequency and Active Power Control Ancillary Services per individual Ancillary Service, namely for Primary, Secondary, and Tertiary Control Ancillary Services as these are established in Article 125, in order to ensure adequate System regulation within the limits established in CAHPTER 48 of this Code, taking account of the UCTE regulations and the particularities of the country’s energy system. The need to provide Frequency and Active Power Control Ancillary Services is established per System Operational Zone or per geographical area.

2. The Reserve Requirement Constraint Forecast is indicative for DAS Participants and is not binding upon the Transmission System Operator.

3. Details on Reserve Requirement Forecasting are found in the DAS Manual.

CHAPTER 12

DAS CLEARING

Article 56

DAS Schedule – System Marginal Price and Generation Marginal Price

1. The DAS Schedule includes the scheduling that establishes for each period of the day the DAS refers to the generation of Units having submitted offers and the accepted energy of priced imports. Also, the DAS establishes the provision of Reserve Ancillary Services during the Dispatch Periods of the Dispatch Day. The above quantities are established to optimize the social benefit resulting from the satisfaction of the energy balance and the short-term reserves and ancillary services that may be attained during compliance with the Transmission System constraints. The social benefit is optimized by maximizing the value of the requested load after taking away the generation and reserve cost in the presence of constraints. The constraints regard the energy balance, the reserves and ancillary services necessary to reliably satisfy the energy balance, the available generation and ancillary service and reserve provision capacity, and lastly the capability of the System to transmit any excess generation from one area in the country to another one maintaining System stability. It is noted that certain of the foregoing constraints concern the correlation in time of the energy that may be generated by the same generation unit. Such optimization takes account of Energy and Reserve Offers, Load Declarations, Transmission System Constraints in respect of the transmission of energy to ensure System stability, and the Declared Characteristics of Units, especially with regard to their technical minimum generation.

2. The System Marginal Price takes a numerical value for each Dispatch Period of the Dispatch Day, which corresponds to the marginal increase of optimum DAS cost that would result by a marginal increase of the System load. Such marginal increase includes the cost of injecting additional energy into the System to cover the marginal System load increase which is performed in such a way so as to continue satisfying active constraints concerning the transmission system and technical constraints of units, such as their technical minimum generation, and the Reserve and standby requirements for the provision of Ancillary Services.

3. In solving the DAS problem, if there are no active Transmission System Constraints, the marginal load increase causes optimal cost increase regardless of the geographical location where there is marginal load increase. However, where there is an active Transmission System Constraint, an increase in optimal cost may differ depending on the Operational Zone where such marginal load increase takes place. In this second case, different Marginal Generation Prices are established, one per System Operational Zone, so that each one corresponds for the respective Zone and for each Dispatch Period of the Dispatch Day to the additional total expense resulting from a marginal load increase outside such Zone. In any case, the System Marginal Price is common to all Operational Zones. In case of an active Transmission System Constraint, the System Marginal Price takes a numerical value equal to the weighted average of Generation Marginal Prices for all Operational Zones of the System.

Article 57

DAS Schedule Data The Transmission System Operator shall establish the DAS Schedule based on the following information which refer to each Dispatch Period of the Dispatch Day:

Α) Energy price - quantity pairs in €/ MWh and MWh respectively corresponding to the steps of the Energy Offer stepwise function. Each price-quantity pair is called “Priced Energy Offer Block”;

Β) the energy quantity in MWh for which the Transmission System Operator submits Energy Offers in accordance with Article 29. The sum of such energy quantities is called “Non-Priced Energy Offer”, for which the energy price is taken to be equal zero (0);

C) the energy quantity in MWh for which Load Declarations are submitted with the exception of Load Declarations for Export and Load Declarations for Pumping Units, cumulatively for all Meter Categories represented by each Load Representative which is called “Non-Priced Load Declaration”;

D) Energy price-quantity pairs expressed in €/ MWh and MWh respectively in Load Declarations for Export and Load Declarations for Pumping Units, each one of which is called “Priced Load Declaration Block”;

E) Capacity price-Primary Control Reserve pairs expressed in €/ MW and MW respectively, corresponding to Reserve Offers. Each price-capability pair is called “Priced Primary Reserve Offer Block”;

F) Capacity price-Secondary Control Range pairs expressed in €/ MW and MW respectively, corresponding to Reserve Offers. Each price-range pair is called “Priced Secondary Range Offer Block”;

G) Techno-Economic Declarations, especially with regard to the technical capabilities of Units established therein concerning Technical Minimum Generation, their variable cost, their ramp rate, their standby times in list or the change between lists, and the special startup cost from cold, warm, or hot standby until load with synchronization. Especially for Contracted Units for Ancillary Services, further account is taken of the energy offer price, which is established based on the relevant Ancillary Service Contract;

H) the operational state of Units as scheduled to be loaded during the Dispatch Periods prior to the first Dispatch Period of the Dispatch Day;

I) Total Non-Availability Declarations and Partial Non-Availability Declarations;

J) Transmission System Constraints based on the relevant Forecast concerning the Dispatch Day in accordance with Article 54, and System operation simulation data;

K) Primary, Secondary and Tertiary Reserve needs based on the Reserve Requirement Forecast concerning the Dispatch Day in accordance with Article 55;

L) available capability to transmit Interconnections and the Interconnection Rights Table;

M) the Generation Loss Factor Table and the Load Loss Factor Table;

N) the Meters to Load Representative Correspondence Table.

Article 58

Generation and Load Loss joint assessment methodology Using the DAS Clearing Mechanism, System and Distribution Network losses are taken into consideration in Energy Offers and Load Declarations based on the following methodology:

Α) from the energy quantities in MWh of Priced Energy Offer Blocks and Non-Priced Energy Offers the System losses allocated to them are subtracted linearly applying the corresponding numerical values of the Generation Loss Factor Table;

Β) to the energy quantities in MWh of Priced Declaration Load Blocks and Non-Priced Load Declarations the Distribution Network losses allocated to them are added linearly applying the corresponding numerical values of the Load Loss Factor Table.

Article 59

DAS Clearing Mechanism Methodology - DAS Schedule 1. The DAS Clearing Mechanism methodology is equivalent firstly to an Energy Offer

classification by an ascending order of energy prices including in the first place Non-Priced Energy Offers, such classification establishing the total offer function, secondly to an accepted Load Declaration classification by descending order of energy prices including in the first place the Non-Priced Load Declarations, such classification establishing the total demand function, thirdly to the specification of the System Marginal Price which in general terms corresponds to the energy price of the section point of the total offer function with the total demand function, and fourthly to a Reserve Offer classification by an ascending order of the capacity prices of Reserve Offers in order to meet the Reserve Requirements. Such methodology applies concurrently to all Dispatch Periods of a Dispatch Day taking into account the technical constraints of Units and the Transmission System Constraints.

2. The implementation of the DAS Clearing Mechanism methodology results in the DAS Schedule for each Dispatch Day which comprises the blocks of Priced Energy Offers the energy prices of which in general are less than or equal to the Generation Marginal Price, the blocks of Priced Load Declarations the energy prices of which are greater than or equal to the System Marginal Price, Non-Priced Energy Offers and Priced Reserve Offer Blocks which minimize to the maximum possible extent the cost of meeting the Reserve Requirements.

3. Where in one or more Operational Zones it is impossible to balance System energy balance or to satisfy the DAS problem constraints in respect of Reserve Requirements and Transmission System Requirements, the Generation Marginal Price in each affected Operational Zone shall be established by RAE decision.

4. The DAS Clearing Mechanism methodology is based when establishing and resolving a problem on the following principles:

Α) The problem unknowns are:

(1) synchronization or not of each Unit for each Dispatch Period of the Dispatch Day, in order to supply energy and/or Primary Reserve and/ or Secondary Control Range and/ or Tertiary Reserve;

(2) the energy quantities, expressed in MWh, included in the DAS Schedule from Priced Energy Offer Blocks and Priced Load Declaration Blocks for each Dispatch Period of the Dispatch Day;

(3) the Primary Control Reserve quantities in MW included in the DAS Schedule from Priced Primary Reserve Offer Blocks;

(4) the Secondary Control Range quantities in MW included in the DAS Schedule from Priced Secondary Range Offer Blocks;

(5) the The Tertiary Control Reserve quantities in MW included in the DAS Schedule from synchronized or non-synchronized Units.

Β) The total generation cost taken into account when resolving the problem expresses the sum for all Dispatch Periods of the Dispatch Day as follows:

(1) the cost resulting from Energy Offers included in the DAS Schedule;

(2) the cost resulting from Reserve Offers included in the DAS Schedule;

(3) the possible cost of de-synchronizing Units that have been included in the DAS which is taken to be equal to the synchronization cost;

(4) the possible cost of providing Tertiary Control Reserve from non-synchronized Units.

Dispatchable Units included in the DAS Schedule to meet energy needs or due to the activation of Transmission System Constraints shall be paid based on Generation Marginal Prices and those included to meet Reserve Requirements shall be paid based on the highest price in the Reserve Offers included in the DAS Schedule.

Dispatchable Units included in the DAS Schedule based on their Technical Minimum Generation to meet Reserve Requirements shall be paid exclusively based on their variable cost increased by a fixed and single percentage for all Units, which shall be approved by RAE on annual basis, and receive the highest price in the Energy Offers included in the DAS Schedule.

Contracted Units for Ancillary Services which are included in the DAS Schedule shall be paid exclusively based on the relevant contract. The Transmission System Operator shall include the Energy Offers that correspond to such Units upon resolution of the DAS problem among the problem data based on the relevant contract.

C) The problem aims at minimizing the total generation cost with the following constraints:

(1) Priced Load Declaration Blocks the energy price of which is greater than or equal to the System Marginal Price shall be included in the DAS Schedule for each Dispatch Period of the Dispatch Day. Furthermore, Priced Load Declaration Blocks the energy price of which is less than the System Marginal Price shall not be included in the DAS Schedule for each Dispatch Period of the Dispatch Day;

(2) the sum of the energy quantities for each Dispatch Period of the Dispatch Day that correspond to the Energy Offers, inclusive of the energy quantities of Non-Priced Energy Offer Blocks must be greater

than or equal to the sum of the energy quantities that correspond to the Load Declarations that are included in the DAS Schedule, inclusive of Non-Priced Load Declaration Blocks. Should the energy quantities offered for injection do not suffice to cover the Non-Priced Load Declaration Blocks, this shall be the sole reason for which the problem solved by the DAS Clearing Mechanism may be considered infeasible. In that case, the Transmission System Operator must include among the Energy Offers additional Supplementary System Energy quantities from Contracted Units and Emergency Imports as liable for inclusion in the DAS Schedule. If, despite the above, the problem remains infeasible, the Transmission System Operator must also include additional Supplementary System Energy quantities from Cold-Reserve Units. The blocks of such Offers shall be priced under the responsibility of the Transmission System Operator in accordance with the techno-economic information of the relevant Contracts from which only the part of the payments that are equivalent to the energy quantity provided for in the Contract are taken. If the problem still remains infeasible, the Transmission System Operator must consider that the energy quantities in the Load Declarations are liable to be included in a Load Shedding schedule in accordance with the provisions of this Code;

(3) sum of the Primary Control Reserve, Secondary Control Range, and Tertiary Control Reserve quantities that are included in the DAS Schedule, per Ancillary Service and for each Dispatch Period of the Dispatch Day, must be greater than or equal to the total need for each Ancillary Service. Also, constraints may apply in terms of the need for each Ancillary Service per Operational Zone or geographical area. In case where such constraints entail failure to resolve the problem, the Transmission System Operator must include additional Reserve quantities from Supplementary Energy Contracted Units;

(4) for each Unit and for each Dispatch Period of the Dispatch Day technical constraints must be satisfied in terms of the operation of the Unit, and in particular those constraints concerning the Technical Minimum Generation, their ramp rate, the time they remain in condition or of change between conditions. When establishing certain constraints account may be taken of the scheduled operation of Units during the Dispatch Periods that precede the Dispatch Day to which the DAS Schedule concerns;

(5) the sum of energy quantities for each Dispatch Period of the Dispatch Day that correspond to Energy Offers from Imports included in the DAS Schedule may not exceed the available transmission capability of Interconnections for Import. The sum of energy quantities that correspond to Load Declarations for Export included in the DAS

Schedule may not exceed the available transmission capability of Interconnections for Export. In such constraints account is taken of the Interconnection Rights Table so that in the DAS Schedule those with transmission capability rights of Interconnections are served first in case of equal energy price (€/MWh) as compared to those who submit Offers or Declarations without having the respective right. If Energy Offers for Import and Load Declarations for Export are submitted during the same Dispatch Period and for the same Interconnection Corridor the available transmission capability of the Interconnection in question shall be increased accordingly;

(6) if based on the Capacity Adequacy Study, it is estimated that the constraint provided for with regard to minimum energy generation by the Units under Article paragraph 19 (2) (e) (bb) of Law 2773/1999 is not met, an additional constraint shall be added to the problem. The numerical parameters of such constraint, as well as the method followed in applying it to the Dispatch Days of the calendar year shall be established, subject to RAE approval, based on a special forecast study to be prepared by the Transmission System Operator with regard to the DAS Schedule for the calendar year in question;

(7) the anticipated operation of the System based on simulations where account is taken of the energy quantities in MWh included in the DAS Schedule for injection or absorption from the System for each Dispatch Period of the Dispatch Day must meet all Transmission System Constraints. In case of activation of Transmission System Constraints during resolution of the problem, such solution shall be carried out by implementing the DAS Clearing Mechanism by Operational Zone of the System, taking into consideration additional constraints in terms of energy flow among Operational Zones and/ or of the minimum total energy injection into each Operational Zone, which result from the implementation of Transmission System Constraints in this case;

(8) Contracted Units for Ancillary Services are included in the DAS Schedule only if they are more cost-efficient than Dispatchable Units for meeting Reserve Requirements.

D) In case where the constraints under points (3) to (7) of paragraph (C) above lead to failure to solve the problem, the Transmission System Operator is required to solve the problem anew by removing the most restricting of such constraints and face the problem during operation of the System in real time through Ancillary Services;

E) The System Marginal Price for each Dispatch Period of the Dispatch Day shall where Transmission System Constraints are not activated take a numerical value for each Dispatch Period of the Dispatch Day which corresponds to the

marginal increase of the optimal total generation cost of the DAS that would arise from the marginal increase of the System load. In that case, the Generation Marginal Price shall take a numerical value equal to the System Marginal Price for all Operational Zones.

F) Where Transmission System Constraints have been activated, the Generation Marginal Price shall be established by Operational Zone of the System, and take a numerical value for each Zone and each Dispatch Period of the Dispatch Day which corresponds to the marginal increase of the optimal total generation cost of the DAS that would arise from the marginal increase of the System load within such Zone. The System Marginal Price shall take a numerical value equal to the weighted, in terms of total energy injection in each Zone, average price of the Generation Marginal Prices of all Operational Zones of the System.

G) If for the same Dispatch Period the energy prices of different Energy Offers arithmetically coincide and the respective energy quantities of such Offers are not included in their entirety in the DAS Schedule, the priority of inclusion of such Energy Offers in the DAS shall be established as follows: a) firstly the priority for inclusion in terms of the categories of such Energy Offers shall be selected at random, namely injection shall be selected from among thermal units, hydro units, or Imports; b) if injection from thermal units or imports is selected, then the specific Energy Offers to be partially or wholly included in the DAS Schedule shall be selected at random; c) if injection from hydro units is selected, then the energy quantity required to complete the DAS Schedule shall be dispatched to the respective Energy Offers on a pro rata basis of the energy included in the blocks to be selected from among such offers. A random selection method shall also be used in establishing the priority of inclusion for Load Declarations with Priced Blocks when the energy prices from various Load Declarations for the same Dispatch Period arithmetically coincide. Further details, as well as the selection of the random selection method are established in the DAS Manual. Where the DAS Clearing System performs a random selection in accordance with the provisions of this Code, the Energy Transactions Information Administration System shall register the exact time of such random selection, as well as the rest of the information to which it is related;

H) If the capacity prices of different Reserve Offers for an Ancillary Service and for the same Dispatch Period arithmetically coincide, and the respective energy quantities of the Ancillary Service of such Offers are not in their entirety included in the DAS Schedule, the specific Reserve Offers that are partially or wholly included in the DAS Schedule are selected at random.

5. The DAS Clearing Mechanism Methodology may integrate but not be limited to mixed integer programming problem or linear programming problem solution

methodologies. Details with regard to the DAS Clearing Mechanism Methodology are established in the DAS Manual.

Article 60

Transmission System Constraint activation check 1. Where Transmission System Constraints have been activated in implementing the

DAS Clearing Mechanism in accordance with Article 59, the Transmission System Operator shall implement the DAS Clearing Mechanism taking into account the differential variable cost of Dispatchable Units instead of that of the respective Energy Offers, and shall establish whether the Transmission System Constraints shall be activated during such clearing.

2. Where it is established that while Transmission System Constraints are activated in implementing the DAS Clearing Mechanism based on the Energy Offers, the such constraints are not activated in implementing the DAS Clearing Mechanism based the differential variable cost of Dispatchable Units, there is a case of financial activation of Transmission System Constraints, and the Transmission System Operator shall inform RAE to that respect.

3. RAE checks the cases of financial activation of Transmission System Constraints, in particular with their frequency in view of the possibility to impose sanctions in accordance with Article 33 of Law 2773/1999.

Article 61

DAS Schedule 1. Two (2) hours after Gate Closure, the Transmission System Operator shall prepare

the DAS Schedule, establish the System Marginal Price and the Generation Marginal Prices and publish for each Dispatch Period of the Dispatch Day the System Marginal Price, the Generation Marginal Prices, the total load and total energy for import and export at each Interconnection, which are included in the DAS Schedule.

2. Immediately after that, the Transmission System Operator shall notify to all parties having submitted accepted Energy Offers, Reserve Offers and Priced Load Declarations the part of the DAS Schedule concerning them. Such notification shall not be sent to all parties having submitted Non-Priced Energy Offers or Non-Priced Load Declarations, the energy quantities of which have been taken as given in preparing the DAS. Such notification is not a Dispatch Instruction and it informs its recipient so that the latter takes all necessary actions in order to make to all extent possible the Energy Offer, the Reserve Offer or the Priced Load Declaration on the Dispatch Day.

CHAPTER 13

ACCOUNT SETTLEMENT

Article 62

Account Settlement Procedure 1. Three (3) hours after Gate Closure, the Transmission System Operator shall compute

for each Participant the sums of the debits and credits corresponding to them, in accordance with the accepted Energy Offers and Load Declarations.

2. Load Representatives are required to pay the sum calculated through the DAS Settlement and which corresponds to the Load Declarations they submit as these are included in the DAS Schedule. Submitters of Energy Offers are entitled to collect the sum calculated through the DAS Settlement and which corresponds to the Energy Offers they submit as these are included in the DAS Schedule. Submitters of Reserve Offers are entitled to collect the sum calculated in accordance with CHAPTER 27 and settled in accordance with the provisions of SECTION VI.

3. Payments and collections, with the exception of the relevant deeds regarding Reserves, shall be performed on the same day through bank transactions, namely debits and credits to Participant Accounts, following Instructions issued by the Transmission System Operator at the latest within five (5) hours after Gate Closure.

4. In order for the sums corresponding to debits and credits to be established and the relevant bank transactions to be performed, the Transmission System Operator shall use the DAS Settlement System which is part of the Energy Transactions Information Administration System. The DAS Settlement System is related to the Participant Register kept by the Transmission System Operator with the information and Accounts of Participants.

5. Each Participant must:

Α) keep a bank account in the context of the DAS with a financial institution operating in Greece (Participant Account);

Β) have throughout their participation in the DAS a valid authorization to the Transmission System Operator, which shall also be valid for the DAS Settlement House authorized by the Transmission System Operator to perform bank transactions with regard to their Account, in accordance with the accepted Energy Offers or Load Declarations they submit;

C) inform on the same day the Transmission System Operator with regard to any changes in their Account, by submitting a certificate in writing issued by the relevant financial institution;

D) appoint a contact person for all contact with the Transmission System Operator regarding all Settlement issues in the context of the DAS.

6. The activation of a Participant’s Account which is certified by the financial institution with which such account was opened and the authorization under point (B) of paragraph (5) of this Article are prerequisites for a Participant to be admitted for registration with the Participant Register. For the purposes of Settlement, the Transmission System Operator shall assign a unique code to all Participant Accounts; such code shall be kept by the Transmission System Operator and may not be modified. The Transmission System Operator shall identify a Participant mainly by their code and secondly by the particulars of their Account.

7. A Participant Account shall be deactivated following removal of the relevant Participant from the Participant Register and after all their overdue debts have been paid.

Article 63

Calculation of Payments and Collections 1. The sums corresponding to payments or collections shall be computed daily for each

Participant based on the Energy Offers, Load Declarations and the DAS Schedule referring to the following day which is the Dispatch Day for such Offers and Declarations.

2. Any Participant submitting an Energy Offer which is partially or wholly included in the DAS Schedule shall be entitled to collect for such Offer and for each Dispatch Period the sum in euros resulting from the pricing at the System Marginal Price of the energy quantity in MWh, which is included in the DAS Schedule for injection and corresponds to the Energy Offers submitted by the same Participant. The collection sum to which a Participant is entitled p , for the Energy Offer u , is calculated for the Dispatch Period t , as follows:

tputtup DAIODASMPDAER ,,,, ⋅= where :

, ,p u tDAER the collection sum in euros to which a Participant is entitled p , for the Energy Offer u , is calculated for the Dispatch Period t ;

tDASMP the System Marginal Price for Dispatch Period t of the Dispatch Day in question, expressed in euros per MWh;

, ,u p tDAIO the energy quantity in MWh from Energy Offer u which is included in the DAS Schedule and corresponds to Participant p for Dispatch Period t of Dispatch Day d , after being readjusted in order to take account of the System losses corresponding to Energy Offer u .

3. The total sum to be collected by the Participant for a Dispatch Day is calculated as the sum of collections by the same Participant for all Dispatch Periods of the Dispatch Day in question and all Energy Offers included in the DAS Schedule.

4. Where during resolution of the DAS problem there are Generation Marginal Prices per Operational Zone of the System which differ amongst them and for the Dispatch Periods of the Dispatch Day to which such differentiation applies, the Participants that have submitted Energy Offers that have been included in the DAS Schedule partially or wholly, are entitled to either collect or pay additional sums. The additional sums to be collected by or charged to each Participant p , for the Energy Offer u , shall be calculated for the Dispatch Period t , as follows:

( ) tputtZtup DAIODASMPDAPMPDAARP ,,,,, ⋅−= where :

, ,p u tDAARP the sum in euros corresponding to each additional collection or charge fore each Participant p , for the Energy Offer u , is calculated for the Dispatch Period t ; where the numerical value of , ,p u tDAARP is greater than zero, a Participant is entitled to collect an additional sum equal to , ,p u tDAARP ; where the numerical value of , ,p u tDAARP is less than zero, a Participant is entitled to pay an additional sum equal to , ,p u tDAARP ;

,Z tDAPMP the Generation Marginal Price in euros per MWh for the System Operational Zone Z of installation of the Unit to which Energy Offer u , during Dispatch Period t corresponds;


, ,u p tDAIO the energy quantity in MWh from Energy Offer u which is included in the DAS Schedule and corresponds to Participant p for Dispatch Period t , after being readjusted in order to take account of the System losses corresponding to Energy Offer u .

5. The total sum corresponding to an additional collection by or charge to each Participant for a Dispatch Day is calculated as the sum of the additional sums to be collected or paid by the same Participant for all Dispatch Periods of the Dispatch Day in question and all Energy Offers included in the DAS Schedule.

6. Where the DAS Schedule includes Dispatchable Units which are included in such Schedule based on their Technical Minimum Generations to meet Reserve Requirements and which are paid in accordance with Article 59 paragraph 4 (Β) (7), a participating production license holder is not entitled to collect for injection of energy from such Units the sums calculated in accordance with paragraphs (1) to (5) above, which are credited to the Accounting Account in accordance with SECTION VI. Likewise, where the DAS Schedule includes Contracted Units for Ancillary Services which are paid in accordance with Article 59 paragraph 4 (B) (8), a participating production license holder is not entitled to collect for injection of energy from such Units the sums calculated in accordance with paragraphs (1) to (5) above.

7. Any Participant submitting a Load Declaration which is partially or wholly included in the DAS Schedule shall be required to pay for each Dispatch Period the sum in euros resulting from the pricing at the System Marginal Price of the energy quantity in MWh, which is included in the DAS Schedule for absorption and corresponds to the Load Declarations submitted by the same Participant. The sum the Participant s is required to pay for a Load Declaration u which is included in the DAS Schedule for a Dispatch Period t shall be calculated as follows:

tusttus DAODDASMPDAEP ,,,, ×= where :

, ,s u tDAEP the sum in euros to be paid by a Participant s for a Load Declaration u which is included in the DAS Schedule for a Dispatch Period t ;


, ,s u tDAOD the energy quantity in MWh from Load Declaration u which is included in the DAS Schedule and corresponds to Participant s for Dispatch Period t , after being readjusted in order to take account of the Distribution Network losses corresponding to Load Declaration u .

8. The total sum to be paid to a Participant for a Dispatch Day is calculated as the sum of payments to the same Participant for all Dispatch Periods of the Dispatch Day in question and for all Load Declarations of such Participants included in the DAS Schedule.

9. Especially, the sums collected for Energy Offers from the Units under Article 35 of Law 2773/1999, from Contracted Units for Ancillary Services, from Units under commissioning operation, as well as in cases of Energy Offers corresponding to Supplementary System Energy and Energy Offers corresponding to adjusting schedules for flow deviations at the Interconnections, shall be credited to uplift accounts UA-7, UA-3, UA-8, UA-3 and UA-2, respectively. The sums paid for Load Declarations corresponding to adjusting schedules for flow deviations at the Interconnections shall be charged to uplift account UA-2.

10. DAS Settlement does not include payments or collections regarding the provision of Ancillary Services and for Imbalances Settlement or for other causes except for those provided for in this Section of this Code.

Article 64

DAS Settlement Procedure 1. DAS Settlement is performed on a daily basis and includes the following stages:

Α) once the sums to be paid and collected for each DAS Participant have been calculated, the Transmission System Operator shall record such sums separately for each Participant in the Initial Settlement List which shall be notified to Participants in respect of the part that concerns each one of them;

Β) within four (4) hours from Gate Closure, Participants are entitled to lodge documented objections to the Transmission System Operator;

C) within one (1) hour after Gate Closure, the Transmission System Operator shall decide on any objections, finalize the sums to be paid and collected for each DAS Participant and enter such sums separately for each Participant in the Final Settlement List which shall be notified to Participants in respect of the part concerning each one of them;

D) the Final Settlement List shall be notified to the DAS Settlement House, to which the Transmission System Operator issues an Instruction to perform bank transactions corresponding to debits and credits to Participant Accounts;

E) once the relevant Instruction has been received and definitely on the same day, the Settlement House shall perform the bank transactions corresponding to the debits and credits on the Final Settlement List and inform the Transmission System Operator to that respect.

2. Both the Initial and Final Settlement Lists shall refer to one Dispatch Day and include the following information:

Α) the total sum owed by each Participant (payment) separately for each Load Declaration for each Dispatch Period of the Dispatch Day in question, as well as the total sum of the charge for such Dispatch Day;

Β) the total sum owed to each Participant (collection) separately for each Energy Offer for each Dispatch Period of the Dispatch Day in question, as well as the total sum of the collection for such Dispatch Day;

C) where upon resolution of the DAS problem there are Generation Marginal Prices per Operational Zone of the System that differ amongst them, the additional sum debited or credited to each Participant separately for each Energy Offer and for each Dispatch Period of the Dispatch Day in question, as

well as the total additional collection or payment sum for the Dispatch Day in question;

D) information concerning the activities of each Participant that have been used to calculate the settlement sums.

3. Payments and collections referring to the Settlement Lists and concerning the same Participant may be offset.

4. Notification of the Final Settlement List renders both payments and collections overdue. Payments and collections shall be effected within the deadline provided for in accordance with the terms hereof regardless of objections or subjection to a judicial or out of court settlement of disputes.

5. In order for each Participant to pay off the debts that correspond to them, they must take all necessary actions leading to the performance of the bank transaction debiting their Account within one (1) hour from the notification of the Final Settlement List.

6. If after the above time has elapsed and the Participant’s Account does not have a sufficient balance for the relevant debit transaction corresponding to the Final Settlement List to be performed, it shall be deemed that such Participant has failed to pay the relevant sums. The total sum corresponding to failure on the part of a Participant to Pay and the sums corresponding to a Load Declaration submitted by the Transmission System Operator in accordance with Article 21 paragraph (1) (Α), are Transaction Deficit for the respective Dispatch Day.

7. In case of failure to pay, the Transmission System Operator shall notify to the respective Participant the termination of the Energy Transactions Contract, inform the Customers to that respect by making the relevant announcement on its website, and take all lawful actions against the Load Representative and the Customers corresponding to the Load Representative in order to collect all debts and damages corresponding to the Load Declaration.

8. Any failure to pay shall not suspend nor hinder the course of the DAS Settlement procedure and the performance of the relevant bank transactions. For that purpose, the Transmission System Administrator shall inform the Coverage Institution, for the latter to cover the Transaction Deficit.

9. Upon completion of the bank transactions and within six (6) hours from Gate Closure, the Transmission System Operator shall send separately for each Participant that has lawfully paid their debts, a receipt of full payment including the following information:

Α) the charges and payments concerning them and which have been settled;

Β) any further information established in the DAS Manual.

Article 65

Transaction Deficit 1. When in accordance with the DAS Settlement there is a Transaction Deficit for a

Dispatch Day, the Transmission System Operator shall inform to that respect all Participants that are supply license holders establishing the sum of the deficit, which is a Temporary DAS Deficit for that specific Dispatch Day, and compute the sum of the Temporary Extraordinary Coverage Cost in the context of the contract it has signed with the Coverage Institution. The Temporary Extraordinary Coverage Cost shall be allocated to Participants that are supply license holders accordingly based on the total energy quantities which they supply to Greece and the exports they make during the current calendar year. The Extraordinary Charge for Financial Coverage Costs shall be established for each Participant that is a supply license holder. The relevant payment notice that the Transmission System Operator shall notify to Participants that are supply license holders shall establish the time and terms of payment. The Transmission System Operator shall issue the Instructions relating to the effectuation of such payment. Should a Participant fail to pay in due time the Extraordinary Charge for Financial Coverage Costs, the Transmission System Operator may terminate the Energy Transactions Contract of such Participant.

2. At the end of each six-month period and for each calendar year, the Transmission System Operator shall settle the accounts concerning all cases of Transaction Deficit that has occurred during the current and previous six-month periods. Any sums that the Transmission System Operator has collected for a specific case of Transaction Deficit during such six-month periods shall be taken as credits and shall be subtracted from the respective Extraordinary Coverage Cost. If the remaining sum is a debit or if two years have elapsed from the date on which the Transaction Deficit occurred, the Extraordinary Coverage Cost shall be considered Final and the Transaction Deficit account shall be closed. If during the settlement six-month period the sum of the Extraordinary Charges for Financial Coverage Costs paid is less than the total collections made by the Transmission System Operator to cover such Transaction Deficit, the difference shall be returned by order of the Transmission System Operator to Participants on a pro rata basis of the sums each one of them has paid for the coverage of such deficit.

CHAPTER 14

ENERGY TRANSACTIONS INFORMATION ADMINISTRATION SYSTEM

Article 66

Specifications and Approval of the Energy Transactions Information Administration System

1. The Energy Transactions Information Administration System includes the DAS Offer and Declaration Submission System, the Load Forecasting / Reserve Requirements Forecasting / System Transmission Constraints Forecasting Mechanism, the DAS Clearing System, the DAS Settlement System, the Imbalances Clearing and Settlement System, the Capacity Assurance Mechanism System, the Debit and Credit of the Electricity Market Clearing Accounts System, the Participant Communication System, and the data bases required for the operation of all of the above, also including the Participant Register, the Meters to Load Representative Correspondence Table, the Load and Generation Loss Factors Table, the Available Capacity Table, the CAT Register and the CAC Depository.

2. The Transmission System Operator shall select, install, operate and maintain an Energy Transactions Information Administration System in accordance with the provisions of the DAS Manual. The Energy Transactions Information Administration System selected shall be subject to approval by RAE based on the sole criterion of its compatibility with the operations provided for in this Code and the specifications provided for in the DAS Manual.

3. The Energy Transactions Information Administration System must support the commonly accepted principles of good trade practice, it must be based on modern and suitable information and communications technology and ensure uninterrupted operation and increased reliability.

4. The data bases of the Energy Transactions Information Administration System are protected by means of a special security system not allowing access of unauthorized persons to classified information. The system itself provides protection against deletion of information from the data bases.

5. The Energy Transactions Information Administration System has a backup system operating on an independent electronic system, a suitable security system and is synchronized with the main system in terms of information completeness and integrity. The backup system goes into operation in case of temporary interruption or malfunction of the main system.

6. An updated copy of the software, the codes and the Energy Transactions Information Administration System shall be kept by RAE.

Article 67

Communication between the Transmission System Operator and Participants

1. The communication between the Transmission System Operator and Participants, and in particular all notifications or submissions of documents under the provisions of this Code shall be effected electronically over the Energy Transactions Information Administration System in the form and following the procedure provided for by the DAS Manual.

2. Energy Offers, Reserve Offers, Load Declarations and Techno-Economic Declarations shall be submitted over the Offer and Declaration Submission System which forms part of the Energy Transactions Information Administration System.

3. The Energy Transactions Information Administration System shall automatically issue proof of communication receipt directly sent to Participants over the Participant Communication System.

4. In case of total or partial outage of the Participant Communication System, the Transmission System Operator must immediately inform all Participants, sending them a relevant notice using any suitable means, establishing the procedure to be followed for further communication and the anticipated time required to repair the outage. Immediately once the outage has been repaired, the Transmission System Operator shall inform all Participants electronically.

5. In any case communication over the Participant Communication System shall have precedence, if it does not face an outage.

Article 68

Participant Support The Transmission System Operator shall see to the training of Participants on the Energy Transactions Information Administration System and shall provide them with support and instructions so that they can acquire suitable compatible user system to communicate with the Energy Transactions Information Administration System.

Article 69

Energy Transactions Information Administration System Check

1. All Participants are entitled to have access to the contents of the Energy Transactions Information Administration System data bases, as well as to the codes of the such System’s software if they are available in source code format. No access to confidential trade data and information is allowed. The DAS Manual establishes the access procedure, as well as the principles and methodology relating to the classification of information as confidential. The same Manual establishes the procedure, the form and the contents of statistics relating to the operation of the DAS in the past, as well as the way such statistics are published by the Transmission System Operator.

2. The Energy Transactions Information Administration System software codes shall be certified by an independent renowned firm in terms of their suitability and compatibility with the provisions of this Code. Such certification process shall be conducted each time substantial changes are introduced to the software code. The Transmission System Operator shall see to the publication of such certification.

CHAPTER 15

EMERGENCY SITUATIONS RELATING TO THE OPERATION OF THE DAS

Article 70 Emergency Declaration

1. When there is failure on the part of the Energy Transactions Information Administration System which may not be restored through non-electronic communication, or serious malfunction of the System or the Distribution Network or when the need is forecast to implement the provisions on Load Shedding for any reason and particularly due to inadequate supply of energy to consumers, the Transmission System Operator shall immediately issue an Emergency Declaration which shall have the form established in the DAS Manual where it shall enter the event under one of the categories provided for in the DAS Manual, establish a

tentative time when the event shall occur and issue Instructions to Participants. During the term of validity of the Emergency Declaration, the DAS is in an Emergency Situation.

2. Any reason reduced to financial issues or to the prices of Energy or Reserve Offers or Load Declarations shall not justify the issue of an Emergency Declaration.

3. Immediately after the event has occurred, the Transmission System Operator shall issue a Restoration of DAS Normal Operation Declaration as established in the DAS Manual, where it shall state the time of termination of the Emergency and establish the time schedule of the Transmission System Operator's actions to restore the normal operation of the DAS and establish the time of resumption of normal DAS operation.

4. Emergency Declarations and Restoration of DAS Normal Operation Declarations shall be immediately notified to Participants and RAE electronically. The DAS Manual establishes alternative notification methods in case of inability to use electronic means.

5. Within a reasonable time period from the restoration of normal DAS operation, the Transmission System Operator shall, after having investigated the causes of the event, prepare a report where it shall include information regarding the Emergency and in particular the causes, and justify the suitability of the measures and actions it has decided on in order to restore normal DAS operation. Such report shall be submitted to RAE and published by the Transmission System Operator.

Article 71 Actions of the Transmission System Operator

1. By means of the Emergency Declaration, the Transmission System Operator may extend the Gate Closure or suspend the submission of Offers or Declarations for certain or all of the Participants.

2. In case of suspension of the submission of Load Declarations, the Transmission System Operator shall calculate in its judgment the energy quantities for submitted Load Declarations, taking account of the respective Load Declarations of the respective Dispatch Day, and the Load Forecast.

3. Where the submission of Energy or Reserve Offers has been suspended, the Transmission System Operator shall in its judgment calculate the energy or reserve quantities for non-submitted Energy and Reserve Offers, taking account of the respective Offers on the respective Dispatch Day and the technical capabilities of the Units and the System.

4. Participants receiving Instructions in the context of an Emergency Declaration are required to execute them, regardless of any objections or financial consequences. The

Transmission System Operator may not be held liable for any damage caused to a Participant due to an Emergency Situation not attributed to the former.

5. In order to calculate the payments and collections corresponding to the Load Declarations and the Energy Offers in the context of an Emergency Situation, and if it is not possible to calculate them even in part based on the Energy Transactions Information Administration System, the Administratively Defined System Marginal Price shall be applied and the settlement shall be performed through the Imbalances Settlement System. The DAS Manual establishes all necessary details.

Article 72 Administratively Defined Prices

1. The Administratively Defined Energy Offer Cap which is set as the upper limit to the energy prices of Energy Offers in accordance with the provisions of CHAPTER 6, shall be defined by decision of the Minister of Development following the issue of RAE’s opinion.

2. The Administratively Defined System Marginal Price for each Emergency Situation shall be established by decision of the Minister of Development following the issue of RAE’s opinion, and may be issued following the Restoration of DAS Normal Operation Declaration.

3. Administratively Defined Energy Offer Caps for Primary Control Reserve and Secondary Control Range shall be established by decision of the Minister of Development following the issue of RAE’s decision, in the issue of which account is taken of any extended approval of exemptions in accordance with Article 47 and the risk due to such exemptions of an increase of the calculated Unit Remuneration Rates for such Ancillary Services.

Article 73 Settlement of Charges due to unlawful Offers and

Declarations

1. In case of a charge provided by Article 21, Article 32, Article 38, Article 40, Article 46, Article 92, Article 148, and Article 224, the Transmission System Operator shall calculate the relevant sum and send the relevant payment order to the Participant, also setting the payment deadline, which may not be earlier than ten (10) business days.

2. The DAS Manual establishes further details about the form and contents of the notification for the payment of charges and the relevant documents, such as the contents and method of communication between Participants and the Transmission System Operator in the context of such procedure.

3. Participants are entitled to lodge justified objections to the charge and the relevant sum within four (4) calendar days from the notification of the relevant notice. The objection procedure shall not lead to an extension to the payment deadline.

4. The Transmission System Operator shall issue a justified decision on the objections and notify the decision to the Participant, finalize the charges and send a final payment order to the latter, establishing the payment deadline, which may not be earlier than five (5) business days.

5. Any disputes that may arise between the parties shall be settled following the procedure established in Article 10 During the arbitral expertise or arbitration the obligation to make the payments that have become final and overdue is not suspended.

SECTION III DISPATCH PROCEDURE

CHAPTER 16

DISPATCH PROCEDURE SCOPE

Article 74 Object of the Dispatch Procedure

1. The object of the Dispatch Procedure is to schedule the operation of Dispatchable Units, Contracted Units, Emergency Imports, and Cold Reserve Units, as well as to issue the relevant Dispatch Instructions in real time by the Transmission System Operator, so that, in accordance with the Transmission System Operator’s forecasts and measurements, the total energy absorption by the System is effected under conditions of good and reliable System operation, ease of facing contingencies in the System and the Units, quality Load supply, and total cost minimization.

3. In that context, the Transmission System Operator shall prepare the Dispatch Schedule and issue the Dispatch Instructions to Dispatchable Units for the injection of energy into the System and the provision of Ancillary Services to Contracted Units for Ancillary Services for the provision of Ancillary Services and the injection of energy into the System, and to Contracted Units for Supplementary System Energy and Cold Reserve Units for the provision of Supplementary System Energy and Ancillary Services, also in accordance with the terms of the relevant Contracts.

4. System Users include Suppliers if they are Participants in the Energy Transactions System, production license holders for Units registered with the Unit Register, Customers connected to the System, Self-Supplying Customers, and the Distribution Network Operator.

Article 75 Obligations of the Transmission System Operator in the

context of the Dispatch Procedure

In the Dispatch Procedure context, the Transmission System Operator shall:

A) update the Load Forecast, the Reserve Requirements Forecast, and the System Inter-Zonal Constraints Forecast;

Β) take all necessary measures to ensure sufficient Ancillary Services;

C) prepare the Dispatch Schedule for each Dispatch Day which it may amend if it finds such amendment necessary in accordance with the provisions of this Code;

D) send to production license holders the Dispatch Schedule that concerns their respective Units;

E) issue and send to production license holders the Dispatch Instructions which concern them;

F) manage and use the Dispatch Information Administration System;

G) publish statistics and information with regard to the Dispatch Procedure;

H) suggest the necessary measures to improve the efficiency of the Dispatch Procedure.

I) prepare the Dispatch Manual which shall be approved by RAE.

Article 76 Obligations of production license holders in the context of the

Dispatch Procedure

In the context of the Dispatch Procedure, production license holders are required to:

A) take all necessary measures for their Units to be available for operation in accordance with their Declared Characteristics; and

Β) apply the Dispatch Schedule and comply with the Dispatch Instructions issued by the Transmission System Operator.

Article 77 Dispatch Procedure Rules

1. The Transmission System Operator shall prepare the Dispatch Schedule and issue the relevant Dispatch Instructions based on the following principles:

A) in order to cover the total energy absorption by the System, and more specifically the energy in accordance with the Load Forecast, on the one hand, and the energy for Exports and for Pumping Units, on the other hand, in accordance with the DAS Schedule, as well as to provide Ancillary Services that are necessary in the Transmission System Operator’s judgment in accordance with CHAPTER 25, the operation of Dispatched Units and Contracted Units for Ancillary Services shall be scheduled. To Contracted Units for Ancillary Services applies the additional constraint in accordance

with which they shall be scheduled only if they are more cost efficient than Dispatchable Units in terms of meeting the needs for Ancillary Services;

Β) Contracted Units for Supplementary System Energy and/ or Emergency Imports of Supplementary System Energy and Contracted Units for Ancillary Services which are not scheduled to provide Ancillary Services, shall be scheduled for the provisions of energy if the Units under paragraph (A) above do not suffice to cover the overall absorption of energy by the System. Contracted Units for Supplementary System Energy shall be scheduled to provide Ancillary Services only where their operation is required to cover the overall energy absorption by the System;

C) Cold Reserve Units shall be scheduled under responsibility of the Transmission System Operator to cover the overall energy absorption by the System only in those cases where despite the actions taken under paragraphs (A) and (B) above there is risk of not covering the overall energy absorption need to take measures.

2. When preparing the Dispatch Schedule and issuing the Dispatch Instructions, the Transmission System Operator shall see that:

A) first the reliability and smooth operation of the energy transactions system is ensured; and

Β) secondly, the overall cost of energy injection into the System, providing Ancillary Services and Supplementary System Energy Provision Standby cost is minimized per Dispatch Day.

CHAPTER 17

COLLECTION AND EXCHANGE OF INFORMATION DURING THE DISPATCH

PROCEDURE

Article 78 Object of the collection and exchange of information during

the Dispatch Procedure

1. In the context of Dispatch Procedure, the Transmission System Operator shall collect information about the availability of Units and the state of their operation, the availability of Interconnections, the state of operation of the Distribution

Network since it affects the operation of the System, as well as the state of operation of the System.

2. In the context of the Dispatch Procedure, System Users are required to provide to the Transmission System Operator the information provided for in this Chapter.

3. Users are required to provide such information as soon as they take cognizance of the relevant real events, or when occurrence thereof is reasonably possible.

4. Performance of this obligation on the part of Users to provide information does not release them in any case from their obligations in the context of the DAS in terms of the submission of Offers and Declarations in accordance with SECTION II, nor from their obligations resulting from the Imbalances Settlement.

5. Details with regard to the contents of the information submitted to the Transmission System Operator in the context of the Dispatch Procedure are established in the Dispatch Manual.

Article 79 Obligations of production license holders to provide

information

1. A production license holder which has submitted an Energy Offer and/ or Techno-Economic Declaration to the DAS, is required, regardless of the inclusion of the Energy Offer in the DAS Schedule, to inform immediately and in a justified manner the Transmission System Operator where after Gate Closure:

A) the overall energy quantity of the Unit, as this results from the respective Energy Offer in the DAS, is anticipated to change or has been changed for one or more Dispatch Periods of the Dispatch Day in question by at least five (5) MWh; or

Β) any piece of information which is included in the Techno-Economic Declaration of the Unit has been changed or is anticipated to change for one or more Dispatch Periods of the Dispatch Day.

2. All production license holders are required to notify to the Transmission System Operator the maximum available capacity of their Units for each Dispatch Period of the Dispatch Day in the following cases:

A) where they have not submitted an Energy Offer in the context of the DAS for the Units which however had been available prior to Gate Closure or which became available thereafter; or

Β) where they have submitted in the context of the DAS a (Total or Partial) Non-Availability Declaration the reasons for which have ceased to apply and the maximum available capacity of such Units has been restored or increased.

3. In the above cases, if the Techno-Economic Declaration does not represent the current or forecast state of the Unit, the production license holder is required to submit an additional updated Techno-Economic Declaration.

4. All thermal Unit production license holders must immediately inform the Transmission System Operator about any switching of the thermal state of the Unit between cold, hot, and warm standby.

5. All Dispatched or Contracted Hydro Unit production license holders must inform the Transmission System Operator about the level of the Reservoir as well as about any anticipated changes thereto, be they periodical or extraordinary, as established by the Transmission System Operator.

6. All production license holders for the Units under Article 35 of Law 2773/1999 are required to inform immediately the Transmission System Operator in any case of major Unit outage or extended outage for any reason.

Article 80 Obligations of Importers to provide information

If an Importer has submitted an Energy Offer for Import, which has been included in the DAS Schedule, it is required to inform immediately and in a justified manner the Transmission System Operator when the total imported energy which has been included in the DAS Schedule or part of such energy over five (5) MWh per Dispatch Period, cannot or is considered possible that it cannot be imported in the System for reasons which do not concern the operation of the System.

Article 81 Obligations of Load Representatives and the Distribution

Network Operator to provide information

1. A Load Representative who has submitted a Load Declaration that has been included in the DAS Schedule is required to notify immediately to the Transmission System Operator all information that may affect the energy quantities corresponding to Meters which it represents or which concern Exports.

2. A Load Representative who has not submitted a Load Declaration in the context of the DAS for a specific Meter Category, and (wholly or partially) represents Meters of that category on the Dispatch Day in question in accordance with the Meters to Load Representative Correspondence Table, is required to immediately inform the Transmission System Operator about the total Load it anticipates that shall be absorbed per Dispatch Period of the Dispatch Day by such Meters.

3. Where Load Representatives and/ or the Distribution Network Operator plan to proceed to Load Shedding, which is anticipated to cause a Load decrease over ten (10) MW at a specific Connection Point in the System, they are required to inform immediately and in a justified manner the Transmission System Operator.

4. Where the Distribution Network Operator plans to proceed to Network operations which are anticipated to cause a Load decrease over ten (10) MW at a specific Connection Point of the Distribution Network in the System, it is required to inform immediately and in a justified manner the Transmission System Operator.

CHAPTER 18

DISPATCH SCHEDULE

Article 82 Dispatch Schedule Data

For each Dispatch Day, the Transmission System Operator shall prepare the Dispatch Schedule based on the following data which concern each Dispatch Period of the Dispatch Day:

A) the energy price - quantity pairs in euros per MWh and MWh respectively that correspond to the steps of the stepwise function of the Priced Energy Offers of Dispatchable Units and Contracted Units for Ancillary Services, regardless of whether the respective Energy Offer has been included in the DAS Schedule or not. Especially with regard to imports, account is taken of only the energy quantity in MWh that is included in Energy Offers for Import with regard to the part thereof that has been included in the DAS Schedule;

Β) capacity price and Primary Control Reserve pairs in euros per MW and MW respectively, and the capacity price and Secondary Control Range pairs in euros per MW and MW respectively, that correspond to the Reserve Offers of Dispatchable Units and Contracted Units for Ancillary Services, regardless of whether the respective Reserve Offer has been included in the DAS Schedule or not;

C) the updated forecast of the energy generation quantity in MWh from the Units under Article 35 of Law 2773/99;

D) the energy quantity in MWh for which the Transmission System Operator submits Energy Offers in accordance with Article 29, as this quantity has been included in the DAS Schedule. For the respective energy price - quantity pairs in euros per MWh and MWh respectively of the Priced Energy Offers and

when preparing the Dispatch Schedule an energy price equal to zero (0) shall be used;

E) the energy quantity in MWh included in Load Declarations for Export or for Pumping Units with regard to the part thereof that has been included in the DAS Schedule, as well as the Load Declarations corresponding to adjusting schedules for flow deviations at the interconnections. Where it is possible to submit Priced Load Declarations for Customers, the energy quantity in MWh that is included in the priced part of such Declarations, and with regard to the part thereof that has been included in the DAS Schedule;

F) Techno-Economic Declarations, especially with regard to the technical capabilities of Units established therein concerning Technical Minimum Generation, their ramp rate, their standby times in list or the change between lists, as well as the provision of Ancillary Services per Service, and the special startup cost from cold, warm, or hot standby until load with synchronization;

G) (Total or Partial) Non-Availability Declarations of Units;

H) updated Load, Reserve Requirements, and System Inter-Zonal Constraints Forecasts;

I) the Generation Loss Factor Table and the Load Loss Factor Table for the load of Customers connected to the Distribution Network;

J) the Net Transfer Capacity for each Interconnection;

K) the total of other Ancillary Services per service, which the Transmission System Operator estimates that must be provided in accordance with CHAPTER 25;

L) the cost elements regarding the provision of Ancillary Services;

M) the pricing of blocks of energy quantities liable to be injected by Contracted Units for Supplementary System Energy, Emergency Imports and Cold Reserve Units if they are required in accordance with Article 77, which are priced by responsibility of the Transmission System Operator in accordance with the financial information of the relevant Contracts from which only the part of payments provided for in the Contract which correspond to the energy quantity is taken into account; Such blocks are considered as Energy Offers for the resolution of the Dispatch Schedule problem;

N) the price that is calculated in accordance with Article 83 for the additional energy supplied by Units that have stated an extraordinary increase of their maximum available capacity in accordance with Article 79, as well as the additional energy quantity that may be provided by such Units. The respective price and energy quantity pairs are considered as Energy Offers for the resolution of the Dispatch Schedule problem;

O) Events that are notified to the Transmission System Operator in accordance with CHAPTER 22;

P) other information collected and/ or notified to the Transmission System Operator in accordance with CHAPTER 17, as well as other technical and simulation data regarding the operation of the System.

Article 83 Calculation of the price of energy supplied by extraordinarily

available Units

1. If an extraordinary increase of maximum available capacity is declared for a Unit past the Gate Closure in accordance with Article 79, the Transmission System Operator shall calculate the price of the additional capacity supplied by such Unit for each Dispatch Period of the Dispatch Day in accordance with the provisions of this Article.

2. For the purposes of the previous paragraph, additional supplied energy shall mean the energy that may be generated by such Unit in addition to the total supplied energy included in the Energy Offer that has been submitted to the DAS for the Dispatch Day due to the declaration of an extraordinary increase of the maximum availably capacity of the Unit. Where no Energy Offer has been submitted for such Unit or where a Total Non-Availability Declaration has been submitted, additional supplied energy shall mean the total energy that may be generated as a result of the declaration of extraordinary increase of the maximum availably capacity of the Unit.

3. The price of the additional energy supplied by a Unit shall be established per Priced Energy Offer Block and be taken to be the average of the energy prices included in the Energy Offers that have been submitted for the specific Unit for the respective Dispatch Period of the respective day of the week within the 26-week period preceding the week of the Dispatch Day in question. In such calculation account is taken of the Priced Energy Offer Blocks of the above Energy Offers, the energy of which corresponds to the level of the additional supplied energy. In any case, the energy prices of successive blocks must be non decreasing. Where it is not possible to carry out this calculation due to unavailability of all such information, such price shall be established in the reasonable judgment of the Transmission System Operator.

4. The Dispatch Manual establishes the details of the calculation of the additional supplied energy.

Article 84 Generation and Load Loss joint assessment methodology

Using the Dispatch Schedule Clearing Mechanism, System and Distribution Network losses are taken into consideration in Energy Offers and Load Declarations based on the following methodology:

A) from the energy quantities in MWh of Priced Energy Offer Blocks and Non-Priced Energy Offers the System losses allocated to them are subtracted linearly applying the corresponding numerical values of the Generation Loss Factor Table; equivalent losses are subtracted for Contracted Units, Emergency Imports and Cold Reserve Units;

Β) to the energy quantities in MWh of the Priced Load Declaration Blocks shall be added on a case to case basis the Distribution Network losses that are allocated to them, linearly applying the corresponding numerical values of the Load Loss Factor Table.

Article 85 Dispatch Schedule preparation methodology

1. The methodology of the Dispatch Schedule Clearing Mechanism comprises in establishing and resolving of a problem that is equivalent to the DAS problem, based on the Dispatch Schedule data in accordance with Article 82 and the DAS Clearing Mechanism methodology in accordance with Article 59. In addition, the following are also taken into account:

A) the unknown variables of the problem include the quantities of the other Ancillary Services (namely those in addition to the Frequency and Active Power Control Services) that must be provided per Unit;

Β) the overall generation expense that is taken into account when resolving the problem includes the possible expense for the provision of the above other Ancillary Services;

C) when establishing the problem constraints, the Dispatch Procedure rules in accordance with Article 77;

D) the energy quantities in MWh which correspond to the following Energy Offers or Load Declarations are taken as constant while resolving the Dispatch Schedule problem, and arithmetically equal to the respective quantities that have been included in the DAS Schedule for each activity from the total blocks of the respective Offer or Declaration:

(1) in the Load Declarations for Export and the Energy Offers for Import;

(2) the Energy Offers for Hydro Units with regard to the part thereof that corresponds to mandatory injection, and the Energy Offers that correspond to Units that are in commissioning operation;

(3) the Load Declarations of Pumping Units and the possible Priced Load Declarations for Customers;

(4) the Load Declarations and the Energy Offers that correspond to adjusting schedules for flow deviations at the interconnections.

2. The Transmission System Operator may include in the Dispatch Schedule Clearing Mechanism schedules and methodologies for the analysis of the operation of the System, such as flow analysis, optimum capacity flow, System stability, etc. schedules.

3. The Dispatch Manual establishes details with regard to the preparation and implementation of the Dispatch Schedule Clearing Mechanism Methodology.

Article 86 Dispatch Schedule preparation time schedule

1. The Transmission System Operator shall prepare the Dispatch Schedule within six (6) hours from the Gate Closure. If there are updated data with regard to the operation conditions of the System, which cause significant deviations from the data that have been taken into account, the Transmission System Operator may prepare anew the Dispatch Schedule at the latest two (2) hours prior to the commencement of the Dispatch Day.

2. Where during dispatch in real time there are significant deviations of the energy system operation as compared to the data taken into account in preparing the Dispatch Schedule on the previous day, the Transmission System Operator may prepare the new Dispatch Schedule for the following Dispatch Periods of the Dispatch Day, taking account of the new data.

3. There shall be significant deviations in the energy system operation particularly:

A) in case of outage in one or more Units or Interconnection rendering necessary the review of the adequacy of Ancillary Services and the Supplementary System Energy;

Β) in case of outage of a significant System element;

C) in case of another event which in the reasonable judgment of the Transmission System Operator leads or may lead to a significant change to the System Load provided for, the availability of the energy that is scheduled to be injected in the System and the availability of the scheduled Units to provide Ancillary Services or Supplementary System Energy.

4. After the Dispatch Schedule has been prepared, the Transmission System Operator shall immediately inform the production license holders about the scheduled operation of their Units in accordance with the applicable Dispatch Schedule. In addition, the Transmission System Operator shall publish in accordance with CHAPTER 2 information about the constraints that have been taken into consideration in preparing the Dispatch Schedule, as well as information pertaining to the constraints that have affected the solution of the problem.

CHAPTER 19

DISPATCH INSTRUCTIONS

Article 87 Dispatch Instructions

1. The Transmission System Operator shall issue Dispatch Instructions about the operation of Dispatchable Units, Contracted Units and Cold Reserve Units. Each Dispatch Instruction shall regard exclusively one and only one Unit. In addition, and especially with regard to the Units under Article 35 of Law 2773/99, the Transmission System Operator may issue Dispatch Instructions concerning exclusively the limitation of their generation for safety reasons regarding the operation of the System.

2. Notification of the Dispatch Schedule to production license holders in accordance with Article 86, implies for them the respective obligations that result from the issue of Dispatch Instructions by the Transmission System Operator regarding the operation of the Units in accordance with the Dispatch Schedule. The Transmission System Operator may issue Dispatch Instructions which differ from the Dispatch Schedule depending on the degree of deviation of the operating conditions of the energy system which includes the transmission system and the generation units in real time, from those that have been taken account when implementing the Dispatch Schedule.

3. The Dispatch Instructions may be issued in the period between the issue of the Dispatch Schedule and the commencement of the period to which they refer.

4. Any later Dispatch Instruction shall replace each previous one with regard to the operation characteristic of the Unit which is established in such later Instruction.

5. Dispatch Instructions also include the Instructions through the Automatic Generation Control system.

Article 88 Issue of Dispatch Instructions

1. The Transmission System Operator shall issue Dispatch Instructions in such a way so that it applies to the extent possible the Dispatch Schedule, taking account of the operation conditions of the System in real time, as well as all events so as to ensure the reliable operation of the System, especially with regard to the frequency of the System, the voltage and current at significant nodes or elements of the System.

2. For that end, the Transmission System Operator, besides the Dispatch Schedule shall also take into account particularly the following:

A) the quantity of net energy generation of each Unit, inclusive of the Units under Article 35 of Law 2773/99, during the operation of the System;

Β) the quantity of net energy flow between Interconnections, during the operation of the System;

C) the energy quantity which is absorbed by the System at each Connection Point of Eligible Customers and the Distribution Network with the System, during the operation of the System;

D) the assessment of the current and anticipated System Load;

E) the change of the System operation parameters, especially with regard to System frequency, as well as the voltage and current at significant nodes or System elements, during the operation of the System;

G) the operation characteristics of Units as these are made know in real time;

H) other information collected by the Transmission System Operator or submitted to it in accordance with CHAPTER 17 and CHAPTER 22.

Article 89 Contents of Dispatch Instructions

1. The Transmission System Operator shall issue Dispatch Instructions which shall establish the generation of Active Power of Units, their synchronization and de-synchronization with the System, the provision of Ancillary Services and the way of their operation.

2. Where the Dispatch Instructions establish numerical values for a Unit's Active or Reactive Power or the voltage level of such Unit, such values shall refer to the Connection Point of the Unit with the System or the Distribution Network. Exceptionally, the Dispatch Instructions issued by the Automatic Generation Control system may refer to Unit mixed generation inclusive of their auxiliary loads.

3. For each Unit the Active Power generation level established by the Dispatch Instructions may not be less than the technical minimum Generation of such Unit.

4. The following apply with regard to Dispatch Instructions for the synchronization and de-synchronization of Units:

A) prior to the issue of a Unit synchronization Dispatch Instruction or the issue of a Unit de-synchronization Dispatch Instruction, the Transmission System Operator may issue Dispatch Instructions concerning the thermal state of such Unit between cold, hot, and warm standby. Production license holders are required to inform the Transmission System Operator with regard to the thermal state of the Unit in accordance with Article 79;

Β) where a synchronization Dispatch Instruction does not include a specific numerical value for Active Power generation, it is considered that such Instruction Εντολή concerns the increase of generation following synchronization to the technical minimum generation of such Unit, while if the synchronization Dispatch Instruction does not include a specific numerical value for Reactive Power generation it shall be considered that such Instruction regards the generation of zero (0) Mvar Reactive Power after synchronization;

C) where a de-synchronization Dispatch Instruction does not include a specific numerical value for Reactive Power generation, it shall be considered that such Instruction concerns the reduction of Reactive Power generation to zero (0) Mvar at the Synchronization point during De-synchronization.

5. The following apply with regard to Dispatch Instructions concerning voltage control:

A) the Transmission System Operator may issue Dispatch Instructions with regard to the adaptation of Reactive Power generation (leading or lagging) by Units;

Β) a Dispatch Instruction which concerns Reactive Power generation may establish the numerical value for the voltage that needs to be attained at the Unit's Connection Point;

C) the Transmission System Operator is required to take account during the issue of a Active Power Dispatch Instruction the effect of such Instruction on the capability of the Unit to generate Reactive Power, as well as during the issue of a Reactive Power Dispatch Instruction the effect of such Instruction on the capability of the Unit to generate Active Power;

D) the Transmission System Operator may, if so required under the System operation conditions, issue Dispatch Instructions to maximize Reactive Power generation (leading or lagging);

E) the Transmission System Operator may issue Dispatch Instructions concerning the generation of Reactive Power by individual units of a combined cycle Unit.

6. The Dispatch Manual establishes details with regard to the contents of Dispatch Instructions.

Article 90 Sending of Dispatch Instructions

1. Dispatch Instructions shall be sent by the Transmission System Operator to production license holders using the Dispatch Information Administration System in accordance with CHAPTER 21.

2. In case of Dispatch Information Administration System outage which renders impossible the sending of a Dispatch Instruction in accordance with the provisions of the previous paragraph, alternative means of communications shall be used.

Article 91 Obligation of production license holders to comply with

Dispatch Instructions

1. Production license holders ensure the way of operation of their Units as this is established in the Dispatch Instructions and change the operation of their Units only following a Dispatch Instruction, as well as where it is expressly specified by this Code.

2. Where compliance with a Dispatch Instruction is impossible due to constraints to the operation of a Unit, which constraints are included in the Declared Characteristics of such Unit, the respective production license holder shall immediately inform the Transmission System Operator. In that case, the Transmission System Operator may revoke the initial Dispatch Instruction and issue a new one.

3. Where compliance with a Dispatch Instruction has become impossible due to an unforeseen impediment due exclusively to reasons regarding the safety of the personnel or the installations of a Unit, the production license holder is required to immediately inform the Transmission System Operator in accordance with Article 79. In such case the Transmission System Operator may issue a new Dispatch Instruction in accordance with the new Declared Characteristics of the Unit.

4. Production license holders shall comply with the Dispatch Instructions that concern the Synchronization or De-synchronization of their Unit, if they execute them with a ten (10) minute deviation from the time established in such Instructions.

5. Production license holders shall comply with Dispatch Instructions that refer to Active Power generation by their Units, if they execute such Instructions with a maximum non systematic deviation of ±5 MW from the Active Power generation value, and within the period established in such Instructions.

6. The following apply with regard to Voltage Control:

A) production license holders are required to allow the fluctuation of Reactive Power generation by their Units under the control of an automatic voltage regulator;

Β) production license holders shall comply with Dispatch Instructions concerning Reactive Power generation by their Units, if such Instructions are executed within two (2) minutes from reception of such Instructions when the latter concern an immediate change of Reactive Power generation, or within the longest time period established therein, and with a non systematic deviation from the Reactive Power generation value established in the respective Dispatch Instructions not exceeding ±2 Mvar;

C) where Dispatch Instructions are issued concurrently regarding Active and Reactive Power generation by the same Unit, the deadline for achieving Reactive Power may be extended to the time established in such Dispatch Instructions for achieving Active Power generation;

D) the operation of the automatic voltage regulator is the only case where it is allowed to modify Reactive Power generation by a Unit without being preceded by a Dispatch Instruction, and without application of the limits established in case (2) of paragraph (B) above;

E) where the operation of the automatic voltage regulator leads to Reactive Power generation outside the limits established in the Declared Characteristics of the Unit, the respective production license holder is required to immediately inform the Transmission System Operator;

F) a production license holder shall comply with a Dispatch Instruction to carry out a tap change on the Unit Transformer, if it executes such Instruction within one (1) minute from reception of the Instruction, when such Instruction regards immediate tap change, or within a time period longer than the one established therein;

G) a production license holder shall comply with a Dispatch Instruction concerning the attainment of a voltage value at the Connection Point of a Unit, through a tap change on the Unit Transformer, if it executes it with a maximum deviation of ±1 ΚV from the voltage value established in such Instruction; an exception to this rule is the case where in the Declared Characteristics of a Unit there is a different maximum deviation limit in order to attain a voltage value at the Connection Point; the respective production license holder is required to observe such limit;

H) where a Dispatch Instruction is issued to maximize Reactive Power generation (leading or lagging) by a Unit, the respective production license holder shall take all necessary actions to that end taking account of Active Power generation by such Unit;

I) production license holders shall regulate the operation of the excitation system with stable output voltage with the reactive power limiters in operation and the stable Reactive Power or stable Power Factor operation control systems deactivated, unless a different Dispatch Instruction is issued. Where there is a change in the System’s voltage, production license holders shall not take actions to offset the automatic reaction to the Reactive Power loading caused as a result of operation under stable output voltage of the excitation control automatic system, unless a different Dispatch Instruction is issued or unless immediate action on their part is required to comply with stability limits. In this last case, production license holders shall immediately inform the Transmission System Operator;

J) where Dispatch Instructions are issued regarding tap changes:

(1) when these concern more than one Units in the same Generation Plant or one Combined Cycle Unit, the tap change shall be carried out by the respective production license holder progressively and by one tap position each time, or progressively and by more tap positions if this is technically practicable for each Unit or Combined Cycle Unit, successively among Units;

(2) when they concern the change of more than two tap positions of the same Unit, and the execution of the Instruction is not technically practicable within the time established by the Instruction, the respective production license holder shall execute the Instruction with the minimum possible delay. In this case, the production license holder shall immediately inform the Transmission System Operator;

Article 92 Non-compliance with Dispatch Instructions

1. In case of non-compliance on the part of a production license holder with any Dispatch Instruction, the Transmission System Operator shall point out such non-compliance to such production license holder indicating the relevant Unit, the Dispatch Instruction and the time of its issue, with the exception of the cases under paragraphs (2) and (3) in accordance with Article 91. Under no circumstances shall such obligation of the Transmission System Operator release such production license holder from its obligations deriving from the Dispatch Instruction and the

consequences that may be incurred by it due to non-compliance with such Dispatch Instruction.

2. The Transmission System Operator shall compute within five (5) business days from the end of each month, and for each Unit, the weighted average of Active and Reactive Power generation deviations for such Unit from the respective Dispatch Instructions, for all Dispatch Instructions that have been issued to that Unit for that month. Where the weighted average of generation deviations for such Unit exceeds the absolute value of 0.5 MW for Active Power or 0.4 Mvar for Active Power, the Transmission System Operator shall charge the Producer for such month with the sum NCDO_G in euros, which is calculated using the following formula:

NCDO_G = (PDM_G + QDM_G) × Η_G × SMPM × (1+ΑD_G) × N

Where:

PDM_G is the absolute value of the weighted average of Active Power generation deviations by such Unit from the respective Dispatch Instructions, for all Dispatch Instructions issued to that Unit during the month in question. If it is less than 0.5 MW it shall be taken to equal 0 MW, while if its over 5 MW it shall be taken to equal 5 MW.

QDM_G is the absolute value of the weighted average of Reactive Power generation deviations by such Unit from the respective Dispatch Instructions, for all Dispatch Instructions issued to that Unit during the month in question. If it is less than 0.4 Mvar it shall be taken to equal 0 Mvar, while if its over 2 Mvar it shall be taken to equal 2 Mvar.

Η_G the number of Dispatch Periods in the month in question during which the Unit has supplied energy to the System

SMPM the average value of the System Marginal Price during the Dispatch Periods of the month in question when the Unit has supplied energy to the System.

AD_G the charge increase factor.

Ν the total number of months of the current calendar year up to the exceedance in question of the limit of average generation deviations of a Unit, during which the respective production license holder has exceed the limit of average generation deviations of a Unit.

3. The numerical value of the charge increase factor ΑD_G is established for each calendar year by decision of the Transmission System Operator which is subject to approval by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

4. Further, where a given Unit repeatedly fails to comply with any Dispatch Instruction, the procedure established in CHAPTER 55 and the Transmission System Operator shall inform RAE to that respect in view of the imposition of sanctions in accordance with Article 33 of Law 2773/1999.

5. Especially where a production license holder fails to comply for a Dispatchable Unit with a Dispatch Instruction which concerns the provision of Ancillary Services, in terms of non-compliance with the provision of Ancillary Services the provisions established by Article 148 shall apply, while the provisions under paragraphs (2) and (3) of this Article shall not apply.

CHAPTER 20

RECORDS AND REPORTS REGARDING THE DISPATCH PROCEDURE

Article 93 Keeping Dispatch Procedure Records

1. The Transmission System Operator is required to keep a complete data base regarding the Dispatch Procedure, including:

A) a Dispatch Schedule Record;

Β) a Dispatch Instruction Record;

C) a Record of the proof of receipt of Dispatch Instructions which are issued in accordance with CHAPTER 21; and

D) a Record of the information that has been collected in accordance with CHAPTER 17.

2. The information contained in the above records shall be kept by the Transmission System Operator for at least five (5) years from their entry.

3. Production license holders are entitled to access to the information of the previous paragraph in any case for the Unit in their production license, as well as for other Units only in the context of settling disputes in accordance with the procedure established in Article 10.

Article 94 Dispatch Procedure Statistics

The Transmission System Operator is required to publish at the end of each calendar quarter information about the Dispatch Procedure which shall include at least the following:

A) the total energy and the maximum total System Load per Dispatch Day;

Β) the System Inter-Zonal Constraints that have affected its operation;

C) System Events;

D) cumulative information by Dispatch Instruction category regarding breaches of Instructions by production license holders, as well as information concerning the relevant actions of the Transmission System Operator.

CHAPTER 21

DISPATCH INFORMATION ADMINISTRATION SYSTEM

Article 95 Installation and maintenance of a Dispatch Information

Administration System

1. The Dispatch Information Administration System includes particularly: a Load Forecast, Reserve Requirement, and System Inter-Zonal Constraint Forecasting Mechanism, a Dispatch Schedule Clearing Mechanism, the Mechanism for the issue of Dispatch Instructions in real time, a software to analyze the operation state of the System, the supervisory control and data acquisition (SCADA) system, the communications system and all required data bases.

2. The Transmission System Operator shall select, install, and maintain the Dispatch Information Administration System in accordance with the provisions of the Dispatch Manual.

3. The Transmission System Operator shall see that the operation of the Dispatch Information Administration System meets the commonly accepted specifications in this sector. It shall particularly see that the Dispatch Information Administration System employs suitable and reliable technology and complies with strict uninterrupted operation and information integrity specifications.

4. The Dispatch Manual establishes details with regard to the right of other users to acquire a user license and use the Dispatch Information Administration System, as well as the relevant specifications and operation requirements.

Article 96 Communications System

1. The Transmission System Operator shall notify to all System Users that are required to provide information to it, the communications center to which they shall address such information. The above Users are required to setup, staff, and keep operationally perfect own communications centers also in accordance with the provisions of the Connection Contracts.

2. The mutual exchange information between the Transmission System Operator and System Users shall be carried out exclusively among the communications centers of Users and the Transmission System Operator and through the Dispatch Information Administration System. The Transmission System Operator shall send the Dispatch Instructions to Users in the same manner.

3. In case of outage of the Dispatch Information Administration System which renders impossible the sending of Instructions or information in accordance with the provisions of the previous paragraph, alternative means of communications shall be used which have been specified in the Dispatch Manual and/ or have been agreed on between the Transmission System Operator and each production license holder.

4. The Dispatch Information Administration System shall automatically confirm the correct reception of the information sent through it, and issue reception receipts to the senders of information.

5. The telecommunications equipment installed at the control centers and included in the Dispatch Information Administration System must comply with the relevant standards.

6. Terminal equipment compatible with the respective equipment of the Transmission System Operator communications center shall be placed at an appropriate point of the installations of production license holders, the Distribution Network Operator and of Eligible Customers connected to the System. In addition, such equipment must be allow for teleoperation if this is imposed for the purposes of implementing the provisions of this Code.

Article 97 Special arrangements for the Dispatch Information

Administration System

1. In case of automatic accidental selection by the Dispatch Schedule Clearing Mechanism in accordance with Article 85, the Dispatch Schedule Clearing Mechanism shall record the exact time of such automatic accidental selection, as well

as the Dispatch Period it concerns. The results of such accidental selection shall be notified to all directly involved production license holders.

2. The data bases required for the operation of the Dispatch Schedule Clearing Mechanism are in electronic format and are subject to the safety rules which are established in the following paragraph. No possibility for deleting data from the data bases is allowed.

3. A backup system of the main Dispatch Information Administration System shall be kept in a separate electronic safety system, along with a backup copy of the date that have been entered in the Dispatch Information Administration System, and which is updated on a daily basis. An updated copy of the Dispatch Schedule Clearing Mechanism software shall be kept by RAE. The Transmission System Operator shall see to the compatibility of the backup system with the specifications of all the elements of the Dispatch Information Administration System in case of temporary outage of or malfunction in the main system.

4. The System Users have the right to access to the information in the databases that directly concern them. The Dispatch Manual establishes the details for the relevant procedure.

Article 98 Support by the Transmission System Operator

For the better operation of the Dispatch Information Administration System, the Transmission System Operator shall provide to all System Users that have control centers the possibility to be informed about the operation and use of the Dispatch Information Administration System, as well as information so that they are able to be supplied with a suitable compatible user system.

Article 99 Dispatch Information Administration System check and

certification

1. The Dispatch Information Administration System software codes shall be certified by an independent renowned firm in terms of their suitability and compatibility with the provisions of this Code. Such certification process shall be conducted each time substantial changes are introduced to the software code.

2. The Transmission System Operator shall see to the publication of such certification.

CHAPTER 22

EVENT NOTIFICATION

Article 100 Scope of the Event Notification procedure

This Chapter lays down the rights and obligations of the Transmission System Operator on the one hand, and the following users, on the other: (a) production license holders with Units connected to the System; (b) supply license holders; (c) Eligible Customers connected to the System ; (d) the Distribution Network Operator; and (e) the System Owner, in cases where there are System Events, as these are defined below.

Article 101 System Events

1. System Events (hereinafter referred to as Events) shall be operations and events that take place or are anticipated to take place in the System or the user’s installations and may affect the operation of the System. Events shall mean especially the operation of installations and machinery above their normal operation limits, as these are established in this Code, the Transmission Network Management Code, and the Agreements for Connection with the System, unusually adverse weather conditions, outages or temporary changes affecting the capabilities of an installation or machine, or faults in the control, communication or measurement equipment, the increase of risks from an undesirable function of a protection device, and the unscheduled operation of the System or the user’s installations.

2. The Transmission System Operator shall collect the information it considers necessary to analyze Events either through the SCADA systems or other measurement collection systems. The Transmission System Operator shall also use in the analysis of Events all other information available to it from any source.

Article 102 Additional Events

The Transmission System Operator and users may define by means of a joint agreement in writing, notified to RAE, cases of operations and events as Events by analogy of the provisions of Article 101.

Article 103 Event notification procedure

1. The Transmission System Operator on the one hand, and users on the other, have the mutual obligation to notify Events, both existing or reasonably anticipated ones.

2. The Transmission System Operator is required to immediately notify to all users Events of which it has taken cognizance, if in its reasonable judgment such Events may affect the operation of the recipient being informed.

3. Should the Transmission System Operator perform emergency operations that constitute Events without prior communication with the user affected by them, shall be required to inform such user immediately about the event that has caused them, the possible duration of such event, and the way of its restoration, unless it is the case of a temporary event, with a short duration and which in the meantime has been restored.

4. If a certain Event is the result of another Event having occurred at the installations of a user, the Transmission System Operator is entitled upon notifying such event to a third user, to also notify at the same the information it has received from the first user.

5. The Transmission System Operator shall provide to a production license holder who has notified an Event that has occurred at its installations, all relevant information requested by the latter, in order to be able to accurately assess the implications of such event for its installations.

6. The information received by the user in the context of this Article, shall be confidential, unless if there is different written agreement between the Transmission System Operator and the user.

Article 104 Event Notification Contents, Form and Procedure

1. Events shall be notified in writing, unless where this is impossible or where an emergency operation is required due to the nature of an Event, in which case its recipient may require the dispatch of an ex post written notification.

2. Event notifications must clearly describe the event or the operation that has occurred, in order for its recipient to be able to assess the implications and risks caused. Notifications shall necessarily state the name and the capacity of the natural person sending them.

3. Notification recipients may request further clarifications by the sender, which the latter shall be required to supply as soon as practicable.

4. Operation notifications must, to the extent that it is practicable, reach their respective recipient prior to the occurrence of the respective operation and at a time allowing the

study and assessment of the risks that may be caused by it. Events shall be notified immediately from the time they have become known to the Transmission System Operator or the user.

5. To perform the notification obligation, as this is established by the provisions of this Chapter, the Transmission System Operator on the one hand, and users on the other hand, shall be required to have suitable means of communication and comply with the procedures, as these are detailed in the Dispatch Manual.

6. In cases of Emergency, the provisions of this Chapter shall not apply, but rather the relevant provisions of the Code.

CHAPTER 23

EMERGENCY SITUATIONS

Article 105 Scope of Emergency Situations

1. This Chapter lays down the rights and obligations of the Transmission System Operator, as well as of: (a) production license holders with Units connected to the System; (b) supply license holders; (c) Eligible Customers connected to the System ; (d) the Distribution Network Operator; and (e) the System Owner, in Emergency Situations as these are defined below.

2. The above parties are required, in accordance with the provisions of the following Articles, to respond without undue delay to alarms and comply with the Instructions they receive.

Article 106 Emergency Situation

There is an Emergency Situation when there is a problem which, for any reason, places or may place the System or the Distribution Network in serious risk or affect the reliable and adequate supply of consumers or adversely affect the smooth operation of the Dispatch Procedure.

Article 107 Emergency Situation Notification

1. The Transmission System Operator shall be required, without, however, delaying the performance of all necessary operations provided for by this Article, to inform the users affected by such operations, in accordance with the Contract for Connection to the System, and particularly he shall be required to:

A) notify to the Distribution Network Operator all important situations adversely affecting reliable and adequate supply at a certain Connection Point between the Distribution Network and the System, in order for the Distribution Network Operator to be able to seek alternative supply of the Distribution Network or take other actions; and

Β) inform all Customers that are connected to the System about any case affecting reliable and adequate supply at a certain Connection Point with the System, in order for such Customers to be able to seek alternative supply of the Distribution Network or take other actions.

2. In emergency situations, the Transmission System Operator may proceed to operations without previously informing the users the operation of which is affected by them. In that case, it is required to inform them about the operations that have been performed, the possible duration of such Emergency Situation, and its anticipated ending, unless it is the case of a temporary situation that has been fully restored.

3. To perform the notification obligation, as this is established by the provisions of this Chapter, the Transmission System Operator, users and the System Owner shall be required to have suitable means of communication and comply with the procedures, as these are detailed in the Dispatch Manual.

Article 108 Alert Activation

1. In case of an Emergency Situation in the System, the Transmission System Operator is required to activate an alert towards uses and the System Owner.

2. Such alert shall be transmitted through an electronic system, and activate an equivalent sign recognizable by the recipient in the recipient’s area. Should such system not operate, the Transmission System Operator is required to use the alternative means provided for in the Dispatch Manual.

Article 109 Types of Alert

Alerts are orange, red and blue.

1. An orange alert shall be activated by the Transmission System Operator in case where an event has increased the possibility of failure to cover the load of the System, or when the frequency or voltage of the System significantly deviate from their rated value, which is established in CHAPTER 48, or when, due to weather conditions more then one events may concurrently occur in the System.

2. The Transmission System Operator shall activate red alert where the frequency or voltage of the System are or may immediately fall outside the System operation limits during disturbances, which are established in CHAPTER 48, or immediate failure to cover the System load is a possibility.

3. The Transmission System Operator shall activate blue alert in case of partial or general System operation interruption, or in case of a System restoration test in accordance with Article 122.

Article 110 Additional Alerts

The Transmission System Operator on the one hand, and users or the System Owner on the other hand, may by means of a written agreement notified to RAE, establish alert types beyond those provided for in the previous Article.

Article 111 Procedures in Alert Activation Cases

1. The Transmission System Operator shall establish the procedure to be followed in each case of alert. To that end, the Transmission System Operator prior to establishing the procedures, shall take into account the opinions of users and the System Owner. Such procedures shall be included in the Dispatch Manual.

2. Users and the System Owner are required to take the measures required to be ready to perform the procedures.

3. The procedures pertaining to the activation of orange alert may not provide for additional obligations for users, besides those resulting from this Code.

Article 112 Actions taken by the Transmission System Operator in case of

an Emergency Situation

1. In case of an Emergency Situation, the Transmission System Operator shall activate the suitable alert and take all necessary actions by issuing the relevant Instructions to users and the System Owner.

2. During a blue alert, the Transmission System Operator shall, besides the actions and Instructions referred to in the previous paragraph, modify at its discretion the Dispatch Procedure for such period of blue alert.

3. During the recovery procedure, users and the System Owner shall be required to immediately execute the Instructions given by the Transmission System Operator to the extent that the execution of such Instructions does not affect the safety of their personnel, installations, and machinery.

4. The Transmission System Operator, users and the System Owner are required to have adequately trained personnel in respect of System recovery procedures.

5. The Transmission System Operator in cooperation with the Distribution Network Operator, the other users and the System Owner, shall be required to prepare a System recovery plan in case of partial or general System interruption. Such plan shall be included in the Dispatch Manual.

6. The Instructions issued by the Transmission System Operator in accordance with the provisions of paragraph (1) may deviate, if the Distribution Network Operator deems it necessary, from the System recover plan.

Article 113 Actions taken by the Transmission System Operator in case of

No Coverage of Load

1. Should the Transmission System Operator believe that the coverage of the System load provided for is not ensured by Dispatchable Units, Supplementary Energy Contracted Units, and the capabilities of Emergency Imports, the Transmission System Operator shall take the following actions in the order they are given. It shall:

A) ensure additional active power from Cold Reserve Units if they are contracted to supply Supplementary System Energy;

Β) see that additional capacity is ensured through imports using up the possibilities of Available Transfer Capacity of interconnections;

C) decrease exports if such decrease ensures higher energy injection quantity to be absorbed in Greek Territory;

D) instruct a reduction of energy consumption by Hydro Units if the operate in pumping mode and provided that such reduction shall not adversely affect their capability to inject energy at later Dispatch Periods, during which a significant failure to cover System load is anticipated;

E) should the above actions not suffice or should it be estimated that they do not suffice, the Transmission System Operator shall take the actions provided for in Emergency Situations and Load Shedding actions.

2. The actions taken by the Transmission System Operator in accordance with this Article shall not release Load Representatives from the consequences provided for in this Code in case of failure to perform their obligation to supply sufficient guarantees in the context of the Capacity Assurance Mechanism.

3. Where one or more of the measures under paragraph (1) of this Article are adopted, the Transmission System Operator shall be required to publish all information related to such measures, including information related to the validity and duration of load shedding, and the consumer categories to which load shedding may apply.

Article 114 System Disconnection

1. The Transmission System Operator may disconnect the installations or equipment of a given user in accordance with their respective Connection Contract, if such disconnection is considered absolutely necessary to face an Emergency Situation, as well as in case of System recovery test in accordance with Article 122.

2. The interruption of the operation of the installations or equipment of a user is allowed particularly in an Emergency Situation, provided the continued operation of such installations or equipment may undermine the safety of personnel working on the System or at such user's installation, place in risk the safety of such user's installations or equipment, on grounds of safe and reliable System operation or to ensure the supply Customers with priority in accordance with Article 115.

Article 115 Load Shedding

1. Where load shedding is necessary either in accordance with Article 113, or in case of fault or other operation problems that affect System frequency, voltage values or lead to overloading beyond the thermal loading limits of any part of the System, such load shedding shall be performed by:

A) actions taken by the Transmission System Operator, and especially by Instructions issued to the System Owner and the Distribution Network Operator;

Β) an Instruction of the Transmission System Operator to supply license holders, Customers connected to the System and the Distribution Network Operator (hereinafter referred to as Load Shedding);

C) automatic load shedding due to overloading or low voltage.

2. In the context of Load Shedding, the Transmission System Operator and the Distribution Network Operator, as the case may be, shall ensure that users are not discriminated against to the extent possible. With regard to Load Shedding account shall be taken of cases of Customers to whom priority is given in terms of supply and Customers who are not subjected to Load Shedding. The principles and criteria based on which the Customers not subjected to Load Shedding are selected, as well as the priority of implementing Load Shedding by Customer category, shall be established by decision of the Minister of Development made following the issue of RAE’s opinion. The Transmission System Operator, and the Distribution Network Operator, as the case may be, shall be responsible to implement such decision and prepare a detailed Customer or Customer category list for Load Shedding. Such list shall be included in the Dispatch Manual.

Article 116 User obligations with regard to Load Shedding

1. Users and the System Owner shall be informed as early as possible about an imminent Load Shedding, as well as about its anticipated duration.

2. Load Shedding Instruction recipients shall be required to execute them by the time established therein.

Article 117 Recovery following Load Shedding

The supplying of supply license holders, Customers connected to the System, and Customers connected to the Distribution Network by the Distribution Network Operator shall be restored following Instructions issued by the Transmission System Operator and the Distribution Network Operator, as the case may be, in accordance with the specific procedures established in the Dispatch Manual.

Article 118 Additional obligations of the Distribution Network Operator in

respect of Load Shedding

1. The Transmission System Operator’s Instructions for Load Shedding shall be issued to the Distribution Network Operator either following the activation of alert or without it.

2. The Distribution Network Operator shall be required to execute the Transmission System Operator’s Instructions and take all necessary actions to implement Load Shedding as follows:

A) where an alert has been activated concerning Load Shedding, the Distribution Network Operator shall apply cyclical Load Shedding, unless otherwise established in the Load Shedding Instruction;

Β) if no alert has been activated concerning a Load Shedding, the Distribution Network Operator shall be required to be in standby for Load Shedding at the time established in the respective order, and inform the Transmission System Operator with regard to such standby;

C) where an alert has been activated with regard to Load Shedding and during such alert the Transmission System Operator issues a Load Shedding Instruction for a percentage higher than that established by the alert, the Distribution Network Operator shall make all best efforts to be standby for the Load Shedding required and inform the Transmission System Operator to that respect;

D) where no alert has been activated with regard to Load Shedding, the Distribution Network Operator shall immediately take all necessary actions in order to execute the Load Shedding Instructions issued by the Transmission System Operator immediately, if possible, and in accordance with such Instructions;

E) the Transmission System Operator shall shed loads by isolating 150 KV/MV power transformers by transmitting the relevant Instruction to the 400 kV Substation and/ or Transfer Substation supervisors, if necessary for the safe operation of the System. Load shedding shall be performed in accordance with the priority list per area for power transformer cutting off, which shall be issued by the Distribution Network Operator ensuring to the extent possible that the lines supplying the installations of Customers not subject to Load Shedding in accordance with Article 115 paragraph (2) are not cut off, and submits it to the Transmission System Operator. The foregoing Instruction issued by the Transmission System Operator is an Instruction to the Distribution Network Operator for the latter to proceed as soon as possible to

the reallocation of the load shedding among Distribution Network owners, so that the least possible disturbance is caused, without reducing the total load shed, and then to contact the Transmission System Operator for load resetting.

Article 119 Cyclical Load Shedding

1. The Transmission System Operator, particularly when it anticipates the need for an extended period of Load Shedding, shall ensure the cyclical alternation of the Load Shedding it implements to supply license holders, Customers that are connected to the System, and the connection points between the System and the Distribution Network, in order to ensure as much as possible equal Customer treatment in the area.

2. If in a given area Load Shedding is necessary, the Transmission System Operator shall issue an Instruction regardless of the Load Representative to whom the Customers in the area belong.

3. Where the Distribution Network Operator cyclically alternates the Customers the load of which is shed, it shall ensure that:

A) the total load shedding percentage remains fixed, in accordance with the Transmission System Operator’s Instruction; and

Β) the System load changes caused by the Load Shedding alternation are the lowest possible.

4. The Dispatch Manual establishes the contents of the Load Shedding Instruction.

Article 120 Obligation to inform the Transmission System Operator about

Load Shedding actions

The Distribution Network Operator, supply license holders, Customers connected to the System, and the System Owner, shall inform the Transmission System Operator with regard to their compliance with a Load Shedding Instruction within five (5) minutes from the completion of their relevant works, stating the estimated load quantity shed.

Article 121 Automatic Load Shedding

1. The Transmission System Operator may appoint per Connection Point between the Distribution Network and the System the frequency and/ or voltage limits where automatic Load Shedding occurs, the automatic Load Shedding percentage, as well as

the frequency and/ or voltage levels where loads are resupplied, and which it notifies to the Distribution Network Operator.

2. The Distribution Network Operator is required to take all necessary measures to comply with the above limits and percentages during automatic Load Shedding and resupply in the Distribution Network.

3. The Transmission System Operator, once having received the opinion of a Customer connected to the System, it may appoint for the installations of such Customer the frequency and/ or voltage limits where automatic Load Shedding occurs, the percentage of the relevant automatic Load Shedding, as well as the frequency and/ or voltage limits where load is resupplied, which it notifies to it.

4. Such Customer is required to take all necessary measures to comply with the above limits and percentages during automatic Load Shedding and resupply in its installations.

5. In the cases under paragraphs (1) and (3), the Transmission System Operator may issue an Instruction to the Distribution Network Operator or the Customer, to prevent automatic load resupply, by any means, manually or automatically. In this case Distribution Network or Customer load shall be resupplied by a new Instruction of the Transmission System Operator in accordance with Article 117Article .

Article 122 System Recovery Test

1. The Transmission System Operator, in cooperation with the System Users and Owner, shall carry out a System recovery test once every year, following blue alert activation. The test time shall be agreed on by the Transmission System Operator, users and the System Owner.

2. Users and the System Owner are required to cooperate with the Transmission System Operator in the test, in accordance with the mutually accepted specifications in this area.

SECTION IV ANCILLARY SERVICES AND SUPPLEMENTARY

SYSTEM ENERGY

CHAPTER 24

GENERAL PROVISIONS

Article 123 Definition of Ancillary Services and Supplementary System

Energy

1. Ancillary services are the services required to transfer energy through the System from the injection points to the consumption points and ensure the quality of energy supply through the System. The Dispatch Manual contains detailed definitions for each Ancillary Service, the method in which they are measured and the quantitative and qualitative control procedure followed by the Transmission System Operator which are established in accordance with the applicable each time UCTE regulations taking account of the operational particularities of the Greek System.

2. Supplementary System Energy shall be the energy which is supplied or may be supplied to the System under the responsibility of the Transmission System Operator in accordance with Article 15 paragraph (4) and Article 19 paragraph (2) (g) of Law 2773/1999, in accordance with the terms and conditions established in SECTION III, to balance Generation - Demand Deviations in real time during System operation, particularly during System peak loads, if required to cover the total energy absorption by the System.

3. Supplementary System Energy may be supplied under the responsibility of the Transmission System Operator provided it comes from:

A) Contracted Units for Supplementary System Energy;

Β) Emergency Import Contracts for Supplementary System Energy;

C) Cold Reserve Units for which a Cold Reserve Contract has been signed.

Article 124 Individual Ancillary Services

1. There are the following individual Ancillary Services:

A) Primary Control and Reserve;

Β) Secondary Control and Range;

C) Tertiary Control and Spinning Reserve;

D) Tertiary Non-Spinning Reserve;

E) Standing reserve

F) Voltage Control;

G) Black Start.

2. The individual Ancillary Services under paragraphs 1 (Α) to (D) above are briefly referred to as Frequency and Active Power Control Ancillary Services.

Article 125 Frequency and Active Power Control Ancillary Services -

Definitions

1. System Primary Control shall mean the collective automatic corrective response of Generation Units and Loads to deviations of the real System frequency from the reference frequency, by which it is sought to balance the total generation with the total energy absorption and frequency stabilization within thirty (30) seconds from the occurrence of frequency distortion. Such regulation may not restore frequency to reference frequency levels. More specifically, the automatic corrective response is the result of automatic regulation of the output Active Power of Units depending on the droop of the load regulator.

2. Primary Control Reserve is the change of the generated Unit Active Power as automatic response of the frequency regulator, in order for the System Primary Control to take place, for a frequency deviation from the reference frequency equal to ±200 mHz. The change of Unit Active Power must take place within thirty (30) seconds from the occurrence of frequency distortion and the level of Unit Active Power generation must be analogous to the value of the frequency deviation for at least fifteen (15) minutes. Primary System Control shall be the collective contribution of the System Units in Primary Control Reserve, so that assisted by the Loads participating in the Ancillary Service, System Primary Control takes place.

3. System Secondary Control shall be the regulation which is the result of the central operation of the Automatic Generation Control through which active power

generation by Generation Units is tele-controlled, provided that such regulation can take place from ten (10) seconds to fifteen (15) minutes from its activation. This regulation seeks to minimize the Area Control Error, the tolerance limit of which is established by the Transmission System Operator.

4. Secondary Control Reserve is the margin of change of the generated Unit Active Power at a specific rate through tele-control by the central operation of the Automatic Generation Control in order for the Secondary System Control to take place, provided this change margin is fully available within fifteen (15) minutes from the activation of the System Secondary Control. Secondary Control Range shall be the interval between minimum and maximum Unit Active Power that may be established through tele-control. Positive or negative Secondary Control Reserve shall be margins of increase or decrease respectively of the Unit Active Power taking account of the current Active Power level of a Unit. System Secondary Reserve and System Secondary Control Range shall be the collective contribution of the System Units respectively to Reserve and Secondary Control Range, in order for the System Secondary Control to take place.

5. System Tertiary Control shall be the regulation which takes place periodically, within a few minutes which is established by the Transmission System Operator in order to restore the System Secondary Reserve level if this has changed as a result of the operation of the System Secondary Control. This regulation concerns the change of the Active Power of Units which the Transmission System Operator Instructions by means of a relevant Dispatch Instruction, based on the criterion of minimizing the total energy injection expense through Automatic Generation Control or of sending a relevant warning to the Unit using another way.

6. Tertiary Control Reserve shall be the margin of change of the generated Unit Active Power between ninety (90) seconds and fifteen (15) minutes after the relevant Instruction, in order for the System Tertiary Control to take place, which range is established based on the generation increase and decrease rates of each Unit. System Tertiary Reserve shall be the collective contribution of the System Units in Tertiary Control Reserve in order for the System Tertiary Control to take place.

7. Unit Tertiary Spinning Reserve shall be the Unit Tertiary Control Reserve in accordance with the definition under paragraph (6), which is synchronized in the System.

8. Unit Tertiary Non-Spinning Reserve shall be the Unit Tertiary Control Reserve in accordance with the definition under paragraph (6), which is non synchronized with the System.

9. Interruptible Load Ancillary Service shall be the possibility to automatically interrupt load supply for a given Customer aiming at contributing to regulating frequency through the provision of a respective reserve. The provision of Interruptible Load Ancillary Service is only allowed when such load may be automatically interrupted

by the Transmission System Operator through tele-operation under the responsibility of the Transmission System Operator or through under-frequency switches installed by the Customer in accordance with the Transmission System Operators instructions. The provision of this Ancillary Service shall commence following the approval of the Transmission System Operator's relevant study and the relevant modification of this Code.

10. Generation Pick up Ancillary Service shall be the possibility for automatic rapid generation pick up by Units in synchronous condenser or motor operation, or the response of Pumping Units which are activated due to a specific and increased frequency deviation. Such service shall start being provided as an Ancillary Service, and the relevant payments shall be made, following the approval of the Transmission System Operator's relevant study and the relevant modification of this Code.

Article 126 Standing Energy Reserve Ancillary Service - Definition

Unit Standing Reserve shall mean the maximum active power quantity which may be made available to the System by a synchronized Unit, within a period from between twenty (20) minutes to four (4) hours following the issue of a Unit synchronization Dispatch Instruction, as this magnitude is established in the Unit's Declared Characteristics. System Standing Reserve shall mean the sum of the Standing Reserves of Units which have been or may be scheduled to provide such service for each Dispatch Period. Scheduling for the provision of this service is carried out by the Transmission System Operator in order to render possible Active Power and Frequency Control in view of unforeseen disturbances of the System load balance in real time during a Dispatch Day.

Article 127 Voltage Control Ancillary Service - Definitions

1. System Voltage Control aims at maintaining voltage within normal operation limits in accordance with CHAPTER 48. For that purpose it is required that there be sufficient standing and dynamic Active Power reserve.

2. System Voltage Control is achieved under the responsibility of the Transmission System Operator through the following means:

A) use of System devices, notably control of autotransformers’ tap changers, switch of lines and cables, use of electronic compensators or alternative means of reactive power production, switch of reactors and capacitors;

Β) change of Unit Transformer tap positions; and

C) control of the Active Power generation of Units locally or centrally, as well as manually or automatically.

3. Voltage Control Ancillary Service shall be all services provided in the context of indents (B) and (C) under paragraph (2).

4. Increased Demand for Customers Reactive Power Ancillary Service shall be the operation of Customer installations connected to the System, with a mean hourly power factor which for each Dispatch Period or for certain Dispatch Periods established by the Transmission System Operator, shall be significantly higher than the lower limits established in Article 276 paragraph (19). System Voltage Support Ancillary Service shall be the operation of energy generation units which are not Dispatchable nor Contracted Units, with regulated inactive power injection in order to assist the System Voltage Control in the way established by the Transmission System Operator. Such services shall start being provided as Ancillary Services, and the relevant payment shall be made, following the approval of the Transmission System Operator's relevant study and the relevant modification of this Code.

Article 128 Black Start Ancillary Service - Definition

Black Start Ancillary Service following a general or partial System operation interruption shall be the service provided by Units (hereinafter referred to as Black Start Units) and consists in the possibility to black start Units without being supplied externally, and in injecting energy into the System within one (1) hour or fifteen (15) minutes in the case of hydro units.

Article 129 Supplementary System Energy - Definitions

1. Supplementary System Energy from a Contracted Unit shall mean the active power quantity of a Contracted Unit for Supplementary System Energy, which is supplied to the System by responsibility of the Transmission System Operator in order for the System Supplementary Energy needs to be met.

2. Supplementary System Energy from Emergency Imports shall mean the active power quantity from imports which is supplied to the System by responsibility of the Transmission System Operator in order for the System Supplementary Energy needs to be met.

3. Supplementary System Energy from Cold Reserve Units shall be the active power quantity from a Cold Reserve Unit, provided that such Unit is contracted for that purpose, which is supplied to the System by responsibility of the Transmission

System Operator in order for the System Supplementary Energy needs to be met if this is required in order to avoid an Emergency Situation.

4. Total Supplementary System Energy shall be the sum of System Supplementary Energy from Contracted Units, Emergency Imports and Cold Reserve Units.

Article 130 Provision Availability, Provision Standby, Supplementary

System Energy Provision - Definitions

1. Supplementary System Energy Provision Availability from a Contracted Unit or Cold Reserve Unit shall be the technical capability of such Unit in accordance with its Declared Characteristics, and the relevant contract, to remain in Provision Standby and provide Supplementary System Energy following a Dispatch Instruction.

2. Supplementary System Energy Provision Standby of a Contracted Unit or Cold Reserve Unit shall be real time standby of such Unit, in accordance with its Declared Characteristics and the relevant contract, to provide Supplementary System Energy following a Dispatch Instruction. More specifically, Provision Standby corresponds to a non synchronized Contracted or Cold Reserve Unit that is in suitable standby in order to be able to be synchronized and operate at a given capacity level and within the time required in accordance with the relevant contract, while Supplementary System Energy Provision concerns the operation of a Contracted or Cold Reserve Unit in synchronized mode so that it injects energy into the System following a Dispatch Instruction and in accordance with the relevant contract.

3. Supplementary System Energy Provision Availability from Emergency Imports shall be the possibility which the Transmission System Operator ensures through the relevant contracts in order to have energy injected into the System through interconnections, if necessary.

4. There shall be Supplementary System Energy Provision Standby from Emergency Imports when the Transmission System Operator ensures the standby of the other party of the relevant contract to inject energy into the System through interconnections, in accordance with the relevant contract.

5. Supplementary System Energy Provision from Emergency Imports shall be the injection of energy into the System through interconnections based on the relevant contract and if considered necessary.

Article 131 Transmission System Operator’s obligations with regard to

Ancillary Services and Supplementary System Energy

1. The Transmission System Operator is responsible for scheduling and managing Ancillary Services and the Supplementary System Energy. To that end it shall: a) supervise the capability of Dispatched Units to provide Ancillary Services in accordance with their Declared Characteristics; b) implement the provisions of Article 47 regarding the exceptions regarding the technical information of Dispatchable Units in terms of providing Ancillary Services; and c) enter into Ancillary Service Contracts, Supplementary System Energy Contracts and Cold Reserve Contracts.

2. The Transmission System Operator shall ensure that all necessary Ancillary Services are available for the smooth and safe operation of the System. To that end it shall supervise all available and provided Ancillary Services per Dispatch Period and service, in accordance with the provisions of the Code.

3. The Transmission System Operator shall schedule Provision Standby and Supplementary System Energy Provision from Units Contracted to that end, Emergency Imports, and Cold Reserve Units, in accordance with the provisions of the Code.

4. Ancillary Services and the Supplementary System Energy shall be scheduled and managed by the Transmission System Operator so as to minimize total expenses, including all fixed costs and for that end it shall periodically notify to RAE detailed estimates of the Expected Ancillary Service and Supplementary System Energy Cost in accordance with Article 132.

5. The Transmission System Operator shall issue Instructions for the provision of Ancillary Services and Provision Standby or Supplementary System Energy Provision Instructions through the Dispatch Schedule and/ or the issue of Dispatch Instructions.

Article 132 Calculation method for the Expected Ancillary Service and

Supplementary System Energy Cost

1. The Expected Ancillary Service and Supplementary System Energy Cost shall be estimated during optimization of the expense required for Ancillary Services and to meet the energy balance, which is carried out through the Dispatch Schedule Clearing.

2. The Expected Ancillary Service and Supplementary System Energy Cost includes all fixed expenses which may be provided for in relevant contracts entered into by the Transmission System Operator.

3. The Dispatch Manual provides details about the calculation of the Expected Ancillary Service and Supplementary System Energy Cost.

Article 133 Obligations of production license holders with regard to Ancillary Services and Supplementary System Energy

1. Dispatchable Units are required to provide Ancillary Services in accordance with their Declared Characteristics and the Dispatch Instructions.

2. Contracted Units are required to provide Ancillary Services in accordance with the terms and conditions of the relevant Contracts and their Declared Characteristics, as well as in accordance with the Dispatch Instructions.

3. Production license holders are required to take all necessary measures so that their Units provide Ancillary Services, implement the Dispatch Schedule and comply with the Dispatch Instructions issued by the Transmission System Operator.

4. Production license holders for Supplementary System Energy Contracted Units and Cold Reserve Units are required to take all necessary measures so that their Units provide Supplementary System Energy, implement the Dispatch Schedule and comply with the Dispatch Instructions issued by the Transmission System Operator.

CHAPTER 25

DETERMINING ANCILLARY SERVICE AND SUPPLEMENTARY SYSTEM ENERGY NEEDS

Article 134 Frequency and Active Power Control - Need Forecast

The Transmission System Operator shall estimate the need for the provision of Frequency and Active Power Control Ancillary Services per individual Ancillary Service and Dispatch Period of the Dispatch Day in accordance with the provisions of Article 55.

Article 135 Standing Reserve - Determination of needs

The Transmission System Operator shall establish the Standing Reserve quantities required each time per Dispatch Period of the Dispatch Day taking account of all uncertainty factors and in particular the reliability level of each Unit, Load Forecast reliability, the DAS Schedule, the extent of allowed Load Shedding, the time that has elapsed since the last Load Shedding, particular events that have occurred in the energy system, which includes the transfer System and the Units, or in neighboring energy system and which justify the provision of additional Reserve, the total available capacity for the specific Dispatch Period, the expected generation from Renewable Energy Sources, and particularly from those that are directly affected by weather conditions, the weather conditions directly or indirectly affecting the operation of Units and the reliability of the System, the possibility of special high load cases, and the constraints imposed by agreements with operators of other energy transfer systems.

Article 136 Voltage and System Voltage Stability Control – Determination

of needs

1. The Transmission System Operator controls the System voltage and sees that it remains within the limits established in CHAPTER 48, implementing dynamic and standing regulation methods and seeing to System voltage stability. In order to determine the needs for Voltage and System Voltage Stability Control Ancillary Services, account is particularly taken of daily, weekly or seasonal factors, so that the Transmission System Operator can establish the voltage levels sought, the optimum use of available means for Voltage Control, and minimize the cost of the relevant Ancillary Services.

2. The Transmission System Operator shall ensure using the means established by Article 127 all necessary margins for Voltage Control taking account of the following factors:

A) System Load;

Β) System state and the available means for Voltage Control; and

C) the possibility of Units to generate Inactive Power (leading or lagging).

Article 137 Black Start - Determination of needs

The Transmission System Operator shall see during the preparation of the Maintenance Schedule to the availability of sufficient Black Start Units. In an emergency where a problem is found based on the Declared Characteristics of Units, the Transmission System Operator and production license holders are required to cooperate to face such problem by modifying the Maintenance Schedule if necessary.

Article 138 Supplementary System Energy - Determination of needs and

criteria

1. The Transmission System Operator must ensure through contracts with Contracted Units sufficient Supplementary System Energy Availability so that there is Provision Standby or Supplementary System Energy Provision under competitive financial conditions to minimize the risk of not covering the total System load due to contingencies and/ or to mitigate the uncertainty of DAS Participants relating the cost of balancing load in unforeseen situations. Unforeseen situations shall be particularly increases of maximum peak load beyond those provided for in the Capacity Adequacy Study, cases beyond the anticipated extended Unit faults, and the reduction of the possibility of energy flow from neighboring energy systems.

2. In addition, and only in the context of avoiding Emergency Situations, the Transmission System Operator shall also see to the conclusion of suitable contracts with Cold Reserve Units ensuring that the respective cost is competitive and equivalent to the reserve service provided by them.

3. The above scheduling shall extend over a suitable timeframe in order to face all unforeseen situations relating to System load coverage and achieve the lowest possible cost in the context of contracts, especially where a cost reduction is achieved through sufficiently long-term contracts.

4. The Transmission System Operator shall ensure to the extent possible that scheduling of the Supplementary System Energy Provision Standby from Contracted Units or Emergency Imports or Cold Reserve Units takes place before the Dispatch Day on which the Provision of the relevant services is expected to be required.

Article 139 Medium-term scheduling of Ancillary Service and

Supplementary System Energy Availability

1. The Transmission System Operator shall prepare and notify to RAE by the end of each calendar year the schedule of meeting Ancillary Service and Supplementary System Energy needs at least for the following calendar year.

2. In this scheduling, the Transmission System Operator shall take account of the elements in the Capacity Adequacy Study and other similar studies that it may prepare.

3. Details regarding the methodology used to calculate the needs for Ancillary Service and Supplementary System Energy availability per individual service, are given in the Capacity Assurance Mechanism Manual.

Article 140 Keeping Ancillary Service and Supplementary System Energy

Records

1. Within one month from the beginning of each calendar year, the Transmission System Operator shall prepare and notify to RAE a report concerning the previous calendar year and which shall include total expenses for Ancillary Services and Supplementary System Energy, as well as statistics regarding the extent of the Ancillary Services and the Supplementary System Energy provided in the context of the Dispatch Procedure, the Supplementary System Energy services for which it gave a Provision Standby Instruction, and the Supplementary System Energy Provision Instructions issued, incidents where the available Ancillary Services and the Supplementary System Energy did not suffice, and the cases of non-compliance with the Dispatch Instructions in respect of the provision of such services. The report may include proposals regarding the improvement of Ancillary Service and Supplementary System Energy scheduling and management.

2. An extensive summary of such report shall be published in accordance with CHAPTER 2.

CHAPTER 26

OBLIGATION TO PROVIDE ANCILLARY SERVICES AND SUPPLEMENTARY SYSTEM

ENERGY

Article 141 Primary Control and Reserve - Provision Obligations

1. To meet the needs of Primary Control and Reserve, production license holders with Units with maximum generation capability above 2 MW are required to constantly operate their Units that are synchronized in the System under the control of a Unit load regulator. The Units under Article 35 of Law 2773/1999 are excluded. A Unit may be temporarily released of this obligation only if an exemption is granted in accordance with Article 47.

2. In terms of the response of Units, no time delay shall be admitted with the exception of those related to the technical characteristics of the load regulator. During the operation of the load regulator no inactive frequency zone above ±20 mHz may be implemented, inclusive of the measurement error.

3. Exceptionally, the operation of the load regulation may be constrained for a short period not exceeding one Dispatch Day only in the following cases:

A) following the granting of approval by the Transmission System Operator, which is granted upon request of a production license holder, provided that such constraint is required for reasons pertaining to the safety of the personnel or the installations of the Unit; or

Β) if a relevant Dispatch Instruction has been issued.

4. Each time paragraph (3) is implemented, the Transmission System Operator must record the nature of the constraint, the reasons causing it, as well as its duration.

Article 142 Secondary Control and Range - Provision Obligations

1. Units with a registered capacity over 60 MW are required to provide Secondary Control and Range operating under automatic generation control, if they remain inside the control area established in their Declared Characteristics. The Units under Article 35 of Law 2773/1999 are excluded. A Unit may be temporarily released of this obligation only if an exemption is granted in accordance with Article 47.

2. The Transmission System Operator may issue Dispatch Instructions to Units operating under automatic generation control to stop operating under the automatic generation control system.

3. Unit operation under automatic generation control may be interrupted for a short period of time, which may not exceed one Dispatch Day, and the production license holder may undertake the control of Unit's output Active Power manually upon approval of the Distribution Network Operator, following a justified application filed by the production license holder, if this is required for reasons pertaining to the safety of the Unit personnel or installations. A production license holder is required to immediately restore the operation of a Unit under automatic generation control, immediately after the problem has been solved, after having previous informed the Transmission System Operator to that respect.

Article 143 Voltage and System Voltage Stability Control – Provision

Obligations

1. Units with maximum generation capability over 2 MW and if they are synchronized in the System, are required to provide Inactive Power in accordance with the relevant Dispatch Instruction issued by the Transmission System Operator. The Units under Article 35 of Law 2773/1999 are excluded. A Unit may be temporarily released of this obligation only if an exemption is granted in accordance with Article 47.

2. To that end, the Unit excitation system shall operate under the constant control of an automatic voltage regulator, which must be set so as to ensure fixed voltage at the generator terminals. The deactivation of and constraints to the operation of the automatic voltage regulator are not allowed.

3. The deactivation of or constraints to the operation of the automatic voltage regulator are allowed exceptionally upon approval by the Transmission System Operator and for a short period of time not exceeding one Dispatch Day, if this is imperative for reasons pertaining to the safety of the Unit personnel or installations.

4. In the case of the previous paragraph, the Transmission System Operator, taking account of assuring the reliable and safe operation of the System, may impose additional constraints to the operation of the Unit, if the safety of the Unit personnel or installations is not jeopardized. In that case, the Transmission System Operator may also issue a Dispatch Instruction for the de-synchronization of the Unit.

Article 144 System Black Start – Provision Obligations

1. A production license holder is required to keep its Unit in System black start technical capacity if such Unit is included among Black Start Units.

2. Where during black start a Black Start Unit is unable to respond to the load complying with the limits for its safe operation, the Transmission System Operator shall be notified immediately. The Transmission System Operator may either issue Instructions for changing the load or reconfigure the System, so that the problem of the Black Start Unit is tackled, and to that end it shall cooperate with the relevant production license holder taking into consideration the safety of the Unit personnel or installations.

Article 145 Supplementary System Energy - Provision Obligations

1. Production license holders of Contracted Units for Supplementary System Energy or Cold Reserve Units are required to provide, following a Dispatch Instruction, Supplementary System Energy, in accordance wit their Declared Characteristics and the relevant contract.

2. Production license holders of Contracted Units for Supplementary System Energy or Cold Reserve Units are required to place their Units, following a Dispatch Instruction, in Supplementary System Energy Provision Standby, in accordance wit their Declared Characteristics and the relevant contract.

CHAPTER 27

REMUNERATION FOR ANCILLARY SERVICES PROVIDED BY DISPATCHABLE UNITS

Article 146 Unit Remuneration Rates for Ancillary Services

The Unit Remuneration Rates for Ancillary Services provided by Dispatchable Units shall be established for all Dispatch Periods of a Dispatch Day as follows:

A) for the Primary Control Reserve and the Secondary Control Range, the Standby Unit Remuneration Rate shall be different from the rates for each Ancillary Service,

and it shall be equal to maximum rate (in €/MW) among Reserve Offers for each Service, which have been included in the DAS Schedule to provide Service during the Dispatch Period in question;

Β) the Unit Remuneration Rate for Voltage Control is fixed as the highest additional variable cost (expenses corresponding to the additional operation or maintenance cost) for the provision of inactive power beyond the maximum continuous reactive power generation capability by the Units established in accordance with the Dispatch Schedule to provide this Service during the Dispatch Period in question.

Article 147 Rules for the calculation of Remuneration for Ancillary

Services provided by Dispatchable Units

1. The charges and remuneration provided for in this Chapter, with the exception of those provided for in paragraph (3) of this Article, shall be effected in the context of the Ancillary Services and Supplementary Energy Account.

2. No provision is made for remuneration with regard to the availability of Ancillary Service provision by a Dispatchable Unit, namely to cover the possible fixed cost of the relevant installations.

3. In order to settle Energy Deviations, the energy injected by Dispatchable Units when these provide Ancillary Services is not distinct from the energy they inject to cover the System total load, and therefore the calculations for the corresponding charges and remuneration for Energy Deviations refer to the total energy injected by a Dispatchable Unit.

4. By exception of the provisions of paragraph (3), where the DAS Schedule includes Dispatchable Units which are included in such Schedule based on their Technical Minimum Generation to meet Reserve Requirements, such Units shall be remunerated for energy injection based exclusively on their variable cost increased by a fixed and single percentage applicable to all Units, which RAE shall approval annually.

5. Provision is made for remuneration besides remuneration for energy under paragraphs (3) and (4), for the following Ancillary Services provided such services are provided by Dispatchable Units following a Dispatch Instruction: a) Primary Control and Reserve; b) Secondary Control and Range; c) Voltage Control. Such remuneration shall be the product of the quantity corresponding to the Ancillary Service provided for each Dispatch Period by the Standby Unit Remuneration Rate for the respective Ancillary Service for the same Dispatch Period.

6. The quantity corresponding to the Ancillary Service provided for each Dispatch Period shall be calculated as follows per Ancillary Service which is provided by a Unit in real time following a Dispatch Instruction:

A) for Primary Control, it shall be equal to the Units Primary Control Reserve (in MW). The numerical value of the Primary Control Reserve shall be established in accordance with the Unit's Declared Characteristics and the respective Dispatch Instructions. Where Primary Control is provided for a part of a Dispatch Period, the quantity of the Ancillary Service provided shall be reduced accordingly;

Β) for Secondary Control, it shall be equal to the product of the following: a) the Secondary Control Range provided (MW), taking away any Prohibited Zones of constant operation due to oscillations (MW); and b) the ratio of the Ramp Rate under AGC (in MW/minute) to the expected Ramp Rate under AGC (in MW/minute) for the Unit technology.

The numerical value of the Secondary Control Range shall be established in accordance with the Unit's Declared Characteristics and the respective Dispatch Instructions. The numerical values of Prohibited Zones of constant operation and the Ramp Rate under AGC are established in accordance with a Unit’s Declared Characteristics.

The numerical value of the Expected Ramp Rate under AGC per Unit technology shall be established by RAE following a motion presented by the Transmission System Operator annually and prior to the commencement of their term of validity, for each one of the following Unit technologies: a) lignite units; b) steam electric units using Oil or Natural Gas; c) carbon units; d) non combined cycle gas turbines and Internal Combustion Engine units; e) combined cycle gas units; and f) hydro units. The numerical values of the Expected Ramp Rate under AGC per unit technology reflect the optimal rate that generation units of the specific technology may attain when fully fitted with the required equipment, and under good maintenance and operation conditions.

Where Secondary Control is provided for a part of a Dispatch Period, the quantity of the Ancillary Service provided shall be reduced accordingly;

C) with regard to Voltage Control, it shall be equal to the integral during the Dispatch Period in question of the absolute value of the difference between the provided (leading or lagging) reactive power and the maximum continuous reactive power generation capability which is established in part A2 of the Techno-Economic Declaration for the respective level of active power generation. No remuneration shall be paid for the provision of a Voltage Control Ancillary Service where a Unit provides reactive power until its maximum continuous reactive power generation capability established for its operation conditions in accordance with the respective Techo-Economic Declaration.

7. The Dispatch Manual establishes details on the calculation of the energy corresponding to an Ancillary Service rendered for each Dispatch Period and per Ancillary Service.

8. In addition, remuneration shall be paid to Dispatchable Units in the following cases:

A) if imposed by execution of Dispatch Instruction that a Unit remains non synchronized and standby to provide Tertiary Non-Spinning or Standing Reserve, the remuneration paid shall be equal to the sum of: a) the fuel cost for keeping such Unit standby when not generating; and b) the operation and maintenance cost, besides the fuel cost, referring to such Unit being standby when not generating, as such information is established in the respective Techno-Economic Declaration;

Β) if it is required that a Unit be de-synchronized by execution of a Dispatch Instruction. More specifically, for Dispatchable Units included in the DAS and not found in a state of Total Non-Availability and for which the Dispatch Schedule requires that they be de-synchronized, the remuneration paid shall be equal to the de-synchronization cost which is taken to be equal to the cost of synchronization.

9. Where a Dispatchable Unit using natural gas, operates following a Dispatch Instruction beyond its anticipated operation in accordance with the DAS Schedule, resulting in increased natural gas consumption which may generate additional fuel supply cost due to special terms in the respective contract, additional remuneration may be paid. Such remuneration shall be made only after approval by RAE, which shall be granted following an application of production license holder of the Unit, accompanied by the relevant supporting documents regarding the natural gas consumption for the Unit in question, as well as for the other Units of the same production license holder. Such supporting documents must document the payment of additional remuneration for fuel supply by the production license holder due to non scheduled operation of its Units using natural gas.

10. Where a Unit, following a Dispatch Instruction, operates at a capacity greater than its maximum continuous generation capability, remuneration shall be paid for the part of the injected energy that corresponds to the capacity beyond such Unit's maximum continuous generation capability which is calculated based on the applicable Rate for maximum generation capability.

11. Where a Dispatchable Unit provides a Black Start Ancillary Service, remuneration shall be paid for the energy injected into such service, which is calculated based on the Administratively Specified System Marginal Price. No provision is made for other payments regarding the provision of a Black Start Ancillary Service by Dispatchable Units.

12. With regard to Contracted Units, Emergency Imports and Cold Reserve Units, remuneration shall be computed based on the relevant contracts.

Article 148 Non-compliance with Ancillary Service Dispatch Instructions

by Dispatchable Units

1. The Transmission System Operator shall calculate within five (5) business days from the end of each month, and separately for each Ancillary Service included in accordance with Article 147 paragraph (5) and for the Dispatchable Unit the quantity of Ancillary Services which the Unit has been unable to provide despite the relevant Dispatch Instructions and charge the Producer for such month the sum of NANC_G in euros, which is given by the following formula:

NANC_G = Σt(PANCt × QANC_Gt) × (1+ΑNC_G) × N

Where:

PANCt the Unit Remuneration Rate for the Ancillary Service as this rate applies to Dispatch Period t;

QANC_Gt the Ancillary Service quantity that the Unit has been unable to provide despite the relevant Dispatch Instructions during Dispatch Period t, which shall be calculated based on the implementation details established in the Dispatch Manual;

ANC_G charge increase factor;

Ν the total number of Dispatch Days in the current calendar month during which the same production license holder has failed to provide the instructed Ancillary Service from the said Unit.

2. The numerical value of the charge increase factor ΑNC_G is established for each calendar year by decision of the Transmission System Operator which is subject to approval by RAE. Such decision shall be taken at least two months prior to the end of a calendar year, it shall be in force for the next calendar year and it may not be modified within such year.

CHAPTER 28

ANCILLARY SERVICE CONTRACTS

Article 149 Ancillary Service Contracts

1. The Transmission System Operator may, following a call for tenders, enter into Ancillary Service Contracts with production license holders separately per Unit in the

context of its competencies pursuant to Article 15 paragraph (4) of Law 2773/1999 as is in force. The tender procedure, the terms and conditions for participation to them, the selection criteria used to select the most financially advantageous offer, maximum and minimum offers, draft contracts and all other necessary details shall be established by decision of the Minister of Development following a motion presented by the Transmission System Operator and the issue of RAE's opinion.

2. Ancillary Service Contracts shall concern the provision of Ancillary Services. The feasibility of entering into such contracts is founded based on a possible inadequate provision of Ancillary Services by Dispatchable Units in accordance with their relevant obligations, the pursuit of moderating in the long run the expense regarding the provision of Ancillary Services, reliability and quality assurance regarding the provision of energy services, and any special needs for Ancillary Services. This purpose shall be documented in the Transmission System Operator’s motion regarding the relevant calls for tenders and must be in line with the contents of the medium-term Ancillary Service Availability scheduling performed in accordance with Article 139.

3. Contracts concerning Cold Reserve Units, Contracted Units for Supplementary System Energy, and Emergency Imports for Supplementary System Energy shall be entered into by the Transmission System Operator in accordance with CHAPTER 29 and do not fall in the scope of this Chapter.

4. By means of the Ancillary Service Contracts, a production license holder reserves part of or all the generation capability of a Unit for the provision of Ancillary Services in accordance with the provisions of the relevant Contract.

5. Where an Ancillary Service Contract refers to the total generation capability of a Unit, such Unit shall be considered to be a “Contracted Unit for Ancillary Services”. Under the same category falls the case of Ancillary Service Contracts for Reactive Power. When a Contract refers to part of the generation capability of a Unit, such Unit shall be considered a “Contracted Unit for Ancillary Services" with regard to that part, and for the remaining part of its generation capability, such Unit shall be considered a Dispatchable Unit. A production license holder shall be entitled to participate in the DAS for the part of a Unit's generation capability that corresponds to a Dispatchable Unit and for the time period during which such capability is true in accordance with terms and conditions of the Ancillary Service Contract.

Article 150 Remuneration in the context of Ancillary Service Contracts

1. The charges and remuneration provided for in this Chapter shall be effected in the context of the Ancillary Service and Supplementary System Energy Account.

2. Remuneration shall be calculated in accordance with the terms and conditions of an Ancillary Service Contract and shall be:

A) remuneration for Ancillary Service Provision availability by the Contracted Unit that corresponds to the fixed expenses in order for the Unit to be in a technical state suitable to provide the Service and to the extent that such expense is allocated to the part of such Unit's generation capability corresponding to the Contract. Fixed expenses also include fixed expenses for all other special equipment with which the Unit is fitted in addition to that required for its normal operation in order to provide the Service;

Β) remuneration for the provision of Ancillary Services by a Contracted Unit which corresponds to variable expenses for the provision of the Service and to the extent that such expense is allocated to the part of the Unit's generation capability that corresponds to the Contract. The following are taken into account in calculating such remuneration:

(1) for the energy injected by the Contracted Unit when it provides the Services, the remuneration shall correspond to the variable cost for energy generation, as this is calculated based on the information in the Techno-Economic Declaration, and any further terms and conditions of the Contract.

Especially, where the Contracted Unit absorbs energy from the System in order to provide the Services (e.g. synchronous condenser operation), provision is made for additional remuneration which corresponds to the expense for energy absorption, as such expense is calculated in accordance with the Imbalances Mechanism and shall be paid by the production license holder in the context of Imbalances Settlement;

(2) where the Contracted Unit is not synchronized and it is called upon by means of a Dispatch Instruction to synchronize in order to provide the Services, additional remuneration shall be paid corresponding to the special startup cost from cold, warm, or hot standby until synchronization, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

(3) with regard to Primary Control and Reserve no additional remuneration shall be paid;

(4) for Secondary Control and Reserve additional remuneration shall be paid corresponding to the additional variable maintenance cost for operation under automatic generation control, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

(5) with regard to Tertiary Control and Spinning Reserve no additional remuneration shall be paid;

(6) for Tertiary Non-Spinning Reserve and Standing Reserve additional remuneration shall be paid which corresponds to: (a) the cost of fuel used to maintain the Contracted Unit standby when not generating, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract; and (b) the operation and maintenance cost, besides the fuel cost, to maintain the Unit standby when not generating, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

(7) with regard to Voltage Control additional remuneration shall be paid that corresponds to the change in the operation cost of the Contracted Unit as compared to the cost of normal operation, to the extent that such change is due to the provision of the Service, also taking into account the expense for Unit Transformer tap changes;

(8) for Black Start additional remuneration shall be paid corresponding to the additional fuel cost until the load with synchronization for restart without supply by an external capacity source.

CHAPTER 29

SUPPLEMENTARY SYSTEM ENERGY CONTRACTS AND COLD RESERVE UNIT

CONTRACTS

Article 151 Supplementary System Energy Contracts

1. The Transmission System Operator may, following a call for tender, enter into Supplementary System Energy Contracts with production license holders separately per Unit, as well as for Emergency Imports into the System in the context of its competencies pursuant to Article 15 paragraph (4) of Law 2773/1999 as is in force. The tender procedure, the terms and conditions for participation to them, the selection criteria used to select the most financially advantageous offer, maximum and minimum offers, draft contracts and all other necessary details shall be established by decision of the Minister of Development following a motion presented by the Transmission System Operator and the issue of RAE's opinion.

2. Supplementary System Energy contracts concern the provision of Active Power and/ or Availability to provide Active Power. The purpose of these contracts is founded based on assuring the coverage of total energy absorption by the System where based on Contracted Unit availability and expected offers for Imports into the DAS the risk of not covering the entire energy absorption is anticipated, the pursuit of moderating in the long run the expense regarding the balancing of Energy Deviations, reliability and quality assurance regarding the provision of energy services, and any emergencies in special cases. This purpose shall be documented in the Transmission System Operator’s motion regarding the relevant calls for tenders and must be in line with the contents of the medium-term Supplementary System Energy scheduling performed in accordance with Article 139.

3. By means of the Supplementary System Energy Contracts, a production license holder reserves part of or all the generation capability of a Unit for the provision of Supplementary System Energy in accordance with the provisions of the relevant Contract.

4. Where a Supplementary System Energy Contract refers to the total generation capability of a Unit, such Unit shall be considered to be a “Contracted Unit for Supplementary System Energy”. When a Contract refers to part of the generation capability of a Unit, such Unit shall be considered a “Contracted Unit for Supplementary System Energy" with regard to that part, and for the remaining part of its generation capability, such Unit shall be considered a Dispatchable Unit. A production license holder shall be entitled to participate in the DAS for the part of a Unit's generation capability that corresponds to a Dispatchable Unit and for the time period during which such capability is true in accordance with terms and conditions of the Supplementary System Energy Contract.

5. The Transmission System Operator may, only if it has issued a Dispatch Instruction to a Dispatchable Unit for Supplementary System Energy Provision, also issue to such Unit a Dispatch Instruction for the provision of an Ancillary Service, based on the specific terms and conditions of the Supplementary System Energy Contract.

Article 152 Remuneration in the context of Supplementary System Energy

Contracts

1. The charges and remuneration provided for in this Chapter shall be paid in the context of the Ancillary Service and Supplementary System Energy Account, with the exception of charges and remuneration corresponding to Supplementary System Energy Provision provided a Unit generates energy, which are paid in the context of Imbalances Settlement.

2. Remuneration shall be calculated in accordance with the terms and conditions of an Supplementary System Energy Contract and shall be:

A) remuneration for Supplementary System Energy Provision availability by the Contracted Unit that corresponds to the fixed expenses in order for the Unit to be in a technical state suitable to provide Supplementary System Energy and to the extent that such expense is allocated to the part of such Unit's generation capability corresponding to the Contract. In case of Emergency Imports, the remuneration for the Availability of such imports may be included, which corresponds to fixed expenses, such remuneration regardless of reception;

Β) remuneration for Supplementary System Energy Provision Standby which corresponds to: (a) the cost of fuel used to maintain the Contracted Unit standby when not generating, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract; and (b) the operation and maintenance cost, besides the fuel cost, to maintain the Unit standby when not generating, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

C) remuneration for Supplementary System Energy Provision by a Contracted Unit which corresponds to variable expenses for the provision of Supplementary System Energy and to the extent that such expense is allocated to the part of the Unit's generation capability that corresponds to the Contract. The following are taken into account in calculating such remuneration:

(1) for the energy injected by the Contracted Unit when it provides Supplementary System Energy, the remuneration shall correspond to the variable cost for energy generation, as this is calculated based on the information in the Techno-Economic Declaration, and any further terms and conditions of the Contract. In case of Emergency Imports, such payment shall correspond to the energy purchase expense that is calculated in accordance with the terms and conditions of the Contract;

(2) where the Contracted Unit is not synchronized and it is called upon by means of a Dispatch Instruction to synchronize in order to provide Supplementary System Energy, additional remuneration shall be paid corresponding to the special startup cost from cold, warm, or hot standby until synchronization, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

D) remuneration for the provision of Ancillary Services by the Contracted Unit when it has synchronized with the System for Supplementary System Energy Provision, which remuneration corresponds to variable expenses for the

provision of Ancillary Services and to the extent that such expense is allocated to the part of the Unit's generation capability corresponding to the Contract. The following are taken into account in calculating such remuneration:

(1) if a Contracted Unit provides Primary Control and Reserve no additional remuneration shall be paid;

(2) if a Contracted Unit provides Secondary Control and Reserve additional remuneration shall be paid corresponding to the additional variable maintenance cost for operation under automatic generation control, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;


(4) if a Contracted Unit provides Voltage Control additional remuneration shall be paid that corresponds to the change in the operation cost of the Contracted Unit as compared to the cost of normal operation, to the extent that such change is due to the provision of the Service, also taking into account the expense for Unit Transformer tap changes;

(5) for Black Start additional remuneration shall be paid corresponding to the additional fuel cost until the load with synchronization for restart without supply by an external capacity source.

Article 153 General terms for Cold Reserve Units

1. A Unit shall be placed in Cold Reserve if the respective production license holder submits a relevant application in accordance with Article 317 of this Code for the Units falling within the scope of this Article or an Intention to Suspend Normal Operation Declaration in accordance with Article 42 for the other Units.

2. In accordance with this Code the provision of Cold Reserve services requires the conclusion of a Cold Reserve Contract between a production license holder and the Transmission System Operator. Such contract shall be entered into separately for each Unit and, in the case of Units for which an Intention to Suspend Normal Operation Declaration is submitted, the contract shall be entered into only if it results from such Intention to Suspend Normal Operation Declaration that absolutely serious technical or age reasons justify such intention. Such Contracts shall be approved by the Minister of Development following the issue of RAE’s opinion.

3. By means of a Cold Reserve Contract, the respective production license holder shall be paid remuneration for Provision Availability, Provision Standby and Supplementary System Energy Provision in accordance with Article 154.

4. Cold Reserve Contracts may not include terms which directly or indirectly allow the participation of a Cold Reserve Unit in the DAS, the Imbalances Mechanism or the Capacity Assurance Mechanism, especially with regard to the issue of Capacity Availability Tickets.

5. The Transmission System Operator may, only if it has issued a Dispatch Instruction to a Cold Reserve Unit for Supplementary System Energy Provision, also issue to such Unit a Dispatch Instruction for the provision of an Ancillary Service, based on the specific terms and conditions of the Cold Reserve Contract.

Article 154 Remuneration in the context of Cold Reserve Contracts

1. The charges and remuneration provided for in this Chapter shall be effected in the context of the Ancillary Service and Supplementary System Energy Account.

2. Remuneration shall be calculated in accordance with the terms and conditions of a Cold Reserve Contract and shall be:

A) remuneration for Cold Reserve Unit Availability which corresponds to fixed expenses, including capital expenses and all fixed operation and maintenance expenses in order for the Unit to be in a suitable state of technical capability to provide Supplementary System Energy especially in emergencies where there is risk that the total energy absorption by the System shall not be covered. Capital expenses shall be calculated based on the undepreciated accounting value of the Unit’s assets at a capital return rate established by RAE. Fixed operation and maintenance expenses for the Unit are calculated based on the resorts of the cost audit carried out by the Transmission System Operator;

Β) remuneration for Supplementary System Energy Provision Standby by a Cold Reserve Unit, which corresponds to: (a) the cost of fuel used to maintain the Unit standby when not generating, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract; and (b) the operation and maintenance cost, besides the fuel cost, to maintain the Unit standby when not generating, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

C) remuneration for Supplementary System Energy Provision by the Cold Reserve Unit, which corresponds to variable expenses for Supplementary System Energy Provision. The following are taken into account in calculating such remuneration:

(1) for the energy injected by the Cold Reserve Unit when it provides Supplementary System Energy, the remuneration shall correspond to the

variable cost for energy generation, as this is calculated based on the information in the Techno-Economic Declaration, and any further terms and conditions of the Contract;

(2) where the Cold Reserve Unit is not synchronized and it is called upon by means of a Dispatch Instruction to synchronize in order to provide Supplementary System Energy, additional remuneration shall be paid corresponding to the special startup cost from cold, warm, or hot standby until synchronization, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;

D) remuneration for the provision of Ancillary Services by the Cold Reserve Unit when this has synchronized with the System for Supplementary System Energy Provision, which remuneration corresponds to the variable expenses for the provision of Ancillary Services. The following are taken into account in calculating such remuneration:

(1) with regard to Primary Control and Reserve no additional remuneration shall be paid;

(2) if a Cold Reserve Unit provides Secondary Control and Reserve additional remuneration shall be paid corresponding to the additional variable maintenance cost for operation under automatic generation control, as this is calculated based on the information in the Techno-Economic Declaration and any further terms and conditions in the Contract;


(4) no additional remuneration shall be paid for Voltage Control.

SECTION V METER AND MEASUREMENT ADMINISTRATION

CHAPTER 30

GENERAL TERMS GOVERNING METER AND MEASUREMENT ADMINISTRATION

Article 155 Scope of the meter and measurement administration

procedure

This section establishes the rights and obligations of the Transmission System Operator, the Distribution Network Operator, other System Users and the System Owner with regard to the procedure and the terms governing the installation and maintenance of Registered Meters, the preparation of Registered Meter Register, and the Meters to Meter Representative Correspondence Table, as well as the establishment of energy Metering Data.

Article 156 Obligations in the context of the meter and measurement

administration procedure

1. In the context of the Meter and measurement administration procedure, the Transmission System Operator shall:

A) keep and update a Meter and measurement data base including:

(1) the Register of meters that are installed in the System or the Distribution Network, the measurements of which are used in implementing this Code (hereinafter referred to as Registered Meters). The Transmission System Operator must collect and check the information of the System's Registered Meters, and enter into and update the Meter Register with the information of Registered Meters;

(2) the Meters to Meter Representative Correspondence Table for Registered Meters, part of which is the Meters to Load Representative Correspondence Table;

(3) measurement and Register Meter Metering Data records;

(4) records of the checks and tests performed on Registered Meters;

(5) other information established in this section of the present Code.

Β) collect the measurements of Registered Meters through an electronic measurement collection system with which it is supplied and which it operates;

C) implement the measurement certification and control procedure, as well as the procedure for their correction or estimation, if necessary, in order to establish the Registered Meter Metering Data;

D) ensure that any installation connected to the System is activated, as well as that energy is allowed to flow through such connection, only if such energy is measured by at least one Registered Meter;

Ε) ensure that access is provided to Users and Meter Representatives to the Registered Meter and Metering data that concern them;

F) elaborate the Meter and Measurement Manual, which shall be approved by RAE;

G) supervise compliance with the Typical Agreement for Meter Allocation among Suppliers and/or Self-Supplying Customers for Registered Meters, the form of which, as well as any exceptions thereto shall be subject to RAE's approval.

2. System Users, in the context of the Meter and measurement administration procedure shall be required to:

Α) provide to the Transmission System Operator all the information established in this section with regard to the Meters of their installations, as well as about the relevant measurements;

Β) see to the safety of Meters and measurements, in accordance with the provisions of this Code.

Article 157 Additional Distribution Network Operator obligations in the

context of the meter and measurement administration procedure

1. The Distribution Network Operator shall calculate and provide to the Transmission System Operator the representation percentages for each Distribution Network Boundaries Registered Meter held by Load Representatives, based on the total energy absorption by each Load Representative for its Customers established by the Distribution Network Operator, so that the timely and accurate updating of the Meter

database is ensured, as well as the timely, accurate, and efficient implementation of the Imbalances Settlement procedure, in accordance with the provisions of this Code.

2. Load Representatives shall be fully responsible in terms of the Energy Transactions System as regards the load of their Customers that are connected to the Distribution Network, and Imbalances Settlement shall be performed taking account of the Load Declarations of such Representatives, and the Metering Data calculated in accordance with this Section of the Code. The Distribution Network Operator shall not be held responsible for such transactions.

3. The Distribution Network Operator must implement periodically the Energy Transactions Settlement procedure for the Distribution Network, among Suppliers and Self-Supplying Customers to the extent that they represent Customers that do not have an hourly measurement meter. Such settlement does not regard credits or charges performed in the context of the Energy Transactions System.

4. The Distribution Network Operator shall establish the Distribution Network loss factors based on a special study, whereby average losses are calculated in accordance with the Distribution Network operation statistics for the previous two years. Distribution Network loss factors shall be subject to approval by RAE and shall enter into force from the beginning of the following calendar year and be valid for at least two (2) consecutive years.

5. Until the issue of the Distribution Network Administration Code the details regarding the implementation of this Article shall be established in accordance with the Measurement Administration and Distribution Network Periodic Settlement Manual which shall be prepared by the Distribution Network Operator and be subject to approval by RAE.

Article 158 Meter Categories

1. Registered Meters shall be distinguished into:

Α) Generation Meters, which measure the energy injected by Units which are connected to the System or the Distribution Network at medium voltage. Each Generation Meter shall measure the energy for one Unit;

Β) Load Meters, which measure the energy absorbed by the installations of Eligible Customers or Pumping Units, which are connected to the System. Each Load Meter shall measure the energy of one independent Eligible Customer or Pumping Unit installation, with the exception of those cases where the energy absorbed by an installation is measured by more than one Load Meters; details for such cases are established in the Measurement and Meter Manual;

C) Distribution Network Boundaries Meters, which measure the quantity of energy transfered by the System to the Distribution Network;

D) Check Meters, which measure the flow of energy within the System, so as to facilitate the checking and correction of Registered Meter measurements;

Ε) Backup Meters, each one of which measures energy quantities also measured by another Registered Meter, which with regard to the former shall be hereinafter referred to as Main Meter;

F) Interconnection Meters, which measure the flow of energy through Interconnections.

2. In order to submit Load Declarations, each Registered Meter shall fall under one and only Meter Category. The following criteria are used in defining Meter Categories:

Α) Registered Meter type in accordance with paragraph (1);

Β) connection voltage;

C) System Geographical zone or Operational Zone;

D) specific Meters which the Transmission System Operator sees fit that they constitute a distinct category.

3. Meter Categories are established by the Transmission System Operator subject to approval by RAE, three (3) months before the beginning of the first calendar year for which such categories are valid. Meter Categories shall be valid for at least three (3) calendar years.

4. The Meter and Measurement Manual establishes details with regard to Registered Meters.

Article 159 Registered Meter Installation

1. Notwithstanding the more specific provisions of this Code, Registered Meters shall be installed as follows:

Α) only one Generation Meter shall correspond to one Unit;

Β) only one Load Meter shall correspond a Eligible Customer installation or Pumping Unit;

C) Distribution Network Boundaries Meters shall be installed at high to medium voltage substations and in case of installation of new Distribution Network Boundaries Meter installation or replacement thereof at the high voltage side of substation T/Fs;

D) Check Meters shall be installed in the Transmission System Operator’s judgment;

Ε) Backup Meters shall be installed as per the Transmission System Operator’s judgment and in accordance with the provisions of CHAPTER 57;

F) Interconnection Meters shall be installed as per accordance with the applicable UCTE rules.

2. The System Owner shall supply and install new measuring devices in the System, as well as maintain and replace existing ones, as established by this Code. In addition, the System Owner shall see to the installation of a telecommunications connection and ensure the possibility of tele-transmission for the System’s Registered Meters. With regard to supervising and monitoring such supplies, an Implementation Agreement shall be entered into by and between the Transmission System Operator and the System Owner, which shall be subject to approval and supervision by RAE.

3. Customers and Producers that are connected to the System shall assume the initial cost pertaining to the supply and installation of their Registered Meter, as well as of all related equipment. The System Owner shall undertake the cost of supplying and installing the remaining Registered Meters of the System, and the relevant equipment. The System Owner shall assume the maintenance, operation, and replacement cost for all measuring devices of the System, including those cases where an existing meter is replaced, which, however, is unable to record and tele-transmit hourly measurements, as well as the cost of the telecommunications connection. The Transmission System Operator shall assume the cost of operation of the telecommunication connection of the System’s Registered Meters and Distribution Network Boundaries Registered Meters.

4. The Distribution Network Operator shall assume the cost regarding the supply and installation of the measuring devices of Registered Meters on the Distribution Network, with the exception of Registered Generation Meters, the cost of which shall be borne by production license holders. The Distribution Network Operator shall assume the maintenance, operation and replacement cost for the measuring devices of the Distribution Network, including those cases where an existing meter is being replaced. The Distribution Network Operator shall see to the supply, installation, and maintenance of the measuring devices installed in the Distribution Network. Moreover, the Distribution Network Operator shall see to the installation of a telecommunications connection ensuring the possibility of tele-transmission to the Registered Meters that are installed in the Distribution Network.

5. The Distribution Network Operator must see to the installation, and maintenance of a measuring device and tele-transmission equipment approved by the Transmission System Operator, at the energy generation installations that are connected to the Distribution Network at Medium Voltage. The Distribution Network Operator is required to provide to the Transmission System Operator all the information regarding the measuring devices of producers connected to the distribution network, as well as assist through its services in the collection of metering data in cases where this is not possible for the Transmission System Operator to do.

6. The Transmission System Operator shall schedule and in general supervise the supply, installation, and maintenance of Registered Meters, as well as of the relative data recording and transmission equipment established in this Code.

CHAPTER 31

METER AND METER REPRESENTATIVE REGISTRATION

Article 160 Registered Meter Register

1. The Transmission System Operator shall prepare and update the Registered Meter Register.

2. The Registered Meter Register shall include at least the following information for each Registered Meter:

Α) the Meter Category under which a given Meter falls;

Β) Meter specifications;

C) Meter serial number;

D) telephone numbers to access the Meter;

Ε) pulse values;

F) information concerning measurement transformers;

G) Meter certificates;

Η) the code of the Connection Point where a Meter is installed and the address of the installation site;

I) date of installation;

J) details about checks performed during installation;

K) details about periodic checks;

L) the codes of a Meter in the telemetering system;

M) the use category for the energy measured;

N) with regard to Generation Meters and Load Meters, the code of the installation the energy of which is measured;

O) for Backup Meters, the Main Meter code;

P) other information which the Transmission System Operator considers necessary.

3. System Users are required to submit to the Transmission System Operator the information related to the Registered Meters of their installations, in order for such information to be included in the Registered Meter Register.

4. Details on the contents and structure of the Registered Meter Register shall be established in the Meter and Measurement Manual.

Article 161 Meters to Meter Representative Correspondence Table

1. The Transmission System Operator shall prepare and update a special table (Meters to Meter Representative Correspondence Table) where at least one DAS Participant shall be entered as Meter Representative for each Registered Meter of the System and each Distribution Network Boundaries Registered Meter, with the exception of Check Meters. The Transmission System Operator shall see that the Meters to Meter Representative Correspondence Table is up to date and complete in accordance with Article 162 up to and including Article 164 for each Dispatch Day.

2. The Meters to Meter Representative Correspondence Table for Registered Meters shall be prepared based on the following principles:

Α) each Generation Meter shall be represented by the production license holder for the respective Unit;

Β) each Load Meter shall be represented by one or more Load Representatives;

C) each Distribution Network Boundaries Meter shall be represented by one or more Load Representatives for Customers connected to the Distribution Network;

D) each Backup Meter shall be represented by the Representative(s) of the Main Meter;

Ε) each Interconnection Meter shall be represented by DAS Participants, who have submitted Load Declarations for export or Energy Offers for Import through the respective Interconnection Corridor, if included in the DAS Schedule and by analogy to the energy included therein based on such Declarations or Offers;

F) the energy percentage or quantity for which each Participant represents a Registered Meter shall be entered in the Meters to Meter Representative Correspondence Table. The sum of the representation percentages of Participants for each Registered Meter and Dispatch Period shall be equal to 100%.

3. The part of the Meters to Meter Representative Correspondence Table which establishes the representation of Registered Load Meters and Distribution Network Boundaries Registered Meters by DAS Participants that submit Load Declarations shall be hereinafter referred to as Meters to Load Representative Correspondence.

4. Details on the contents and the structure of the Meters to Meter Representative Correspondence Table shall be established in the Meter and Measurement Manual.

Article 162 Registered Load Meter Representation Declaration

1. Load Representatives are required to submit to the Transmission System Operator a Meter Representation Declaration, which shall establish the Registered Load Meter they represent and the energy percentage or quantity they represent per Dispatch Period. Such Declarations shall be submitted once the first time a Load Representative submits a Load Declaration, and each time there is a change either in terms of the Registered Load Meter or in terms of the energy percentage or quantity represented. The submission of a Meter Representation Declaration is not required where a Load Representative wishes to represent an Interconnection Meter. Such representation is implied from the DAS Schedule. No Meter Representation Declarations shall be submitted for Registered Distribution Network Boundaries Meters.

2. By submitting a Meter Representation Declaration, a Load Representative solemnly states that it has been authorized by a Customer with regard to the representation and the relevant percentage.

3. Where a Registered Load Meter is not represented or where the total representation percentage is under 100% for one or more Dispatch Periods, the Transmission System Operator must immediately contact the Customer to whom the Meter corresponds. In case of voluntary supply interruption, the Transmission System Operator shall not accept any Load Declaration for such Meter and see to the interruption of such Meter's supply. In all other cases, the Transmission System Operator, depending on the relevant Customer declaration and in the representation method indicated by it, shall either correspond the meter to Suppliers or the Customer itself, who in the latter case shall act as a Self-Supplying Customer.

4. Where the sum of the representation percentages for a Load Meter is over 100% for one or more Dispatch Periods, the Transmission System Operator is required to immediately contact the Load Representatives representing such Meter and ask them to correct the Meter Representation Declarations. Where the problem persists, the Transmission System Operator shall contact directly the Customer and ask the latter to determine the way in which it is represented, so that the total representation percentage for each Dispatch Period is 100%.

5. In case of unlawful submission of a Load Declaration in accordance with Article 20 and Article 21, the Transmission System Operator shall delete the respective Meter Representation entry from the Meter to Load Representative Correspondence Table for the specific Dispatch Day.

6. Where the Transmission System Operator's actions in accordance with paragraphs (4) and (5) do not succeed, the procedure established in accordance with Article 21 paragraph (1) shall apply accordingly to the load corresponding to the Meter. In that case, as well as where there are indications for untrue Meter Representation Declarations by Suppliers, the Transmission System Operator is required to refer such case to RAE, providing all necessary information so that a breach of the Code and the Law may be investigated.

Article 163 Meter Representation Declaration Contents

1. Meter Representation Declarations include:

Α) the code of a Registered Load Meter; .

Β) information pertaining to the Customer corresponding to a Load Meter;

C) the percentage of representation of the Meter load or the energy quantity represented per Dispatch Day. Such information may not receive different numerical values for different Dispatch Periods of a Dispatch Day;

D) the date of the first Dispatch Day when the Declaration enters into force.

2. Details on the contents and the form of Load Representative change applications are established in the Meter and Measurement Manual.

Article 164 Time schedule for the submission of Meter Representation

Declarations

1. Meter Representation Declarations may be submitted at any time, and in any case before the first submission of a Load Declaration also concerning the relevant Meter. A new Declaration must be submitted in cases of change to the information in a Meter Representation Declaration.

2. Meter Representation Declarations may not enter into force earlier than at least five (5) days from the date of its submission.

CHAPTER 32

METERS AND COLLECTION OF MEASUREMENTS

Article 165 General provisions regarding meters and the collection of

measurements

1. Each energy quantity measurement required for the implementation of this Code shall be provided exclusively by Registered Meters in accordance with CHAPTER 33.

2. Registered Meters must be able to measure active and reactive power, at least on an hourly basis and provide all necessary information for the implementation of this Code, in accordance with the technical and operational requirements established in CHAPTER 57. Registered Meter devices also include the necessary equipment to tele-transmit their measurements based on the protocols and other specifications of the central measurement collection system of the Transmission System Operator.

3. More specifically, Interconnection Meters require the capabilities established by UCTE and the relevant agreement between the Transmission System Operator and the operators of other energy transmission systems.

Article 166 Collection of Measurements

1. Measurements from Registered Meters are collected by the Transmission System Operator, who shall, for that purpose, procure and operate an electronic system to collect measurements and automatically transmit them to meter and measurement database files.

2. Measurements from Registered Meters shall be collected with the following frequency:

Α) immediately at the end of each Dispatch Day, for measurements concerning the injection of energy from Units and measurements from Check Meters;

Β) immediately at the end of each Dispatch Day, for measurements from Registered Load Meters and Distribution Network Boundaries Meters;

C) for Interconnection Meters, in accordance with the provisions of UCTE and the relevant agreements with the operators of other energy transmission systems;

D) for Backup Meters, this frequency shall be that for the respective Main Meters.

3. For the needs of implementing this Code, the Transmission System Operator, may establish periods shorter than the above for the collection of Measurements.

4. Exceptionally, where the electronic system for the collection of measurements does not operate, measurements shall be taken using any other suitable method before the end of the following Dispatch Day. In case of a problem concerning the collection of measurements from the System’s Load Meters and Generation Meters, the Transmission System Operator shall inform the Representatives of such Meters about the problem, while in case of a problem regarding the collection of measurements from Registered Distribution Network Boundaries Meters, the Transmission System Operator shall inform the System Owner if a Meter is installed in the System, and the Distribution Network Operator.

5. Where the collection of measurements from a Registered Meter is impossible through the Transmission System Operator's electronic system, the Transmission System Operator shall immediately publish the following information in its website: (a) the code of the Registered Meter and a description of the installations the energy flow of which is measured by such Meter; (b) the Meter Representatives; (c) the cause for which the measurement collection electronic system has failed to work; and (d) all other information that is required for transparency reasons.

6. Details on the collection and recording of measurements are established in the Meter and Measurement Manual.

CHAPTER 33

METERING DATA

Article 167 Metering Data

1. Measurements collected by the Transmission System Operator shall be subjected to automatic certification and verification, to measurement adaptation, as well as to correction or estimation, where required, in accordance with the provisions of this Chapter. The final measurement data (hereinafter referred to as Metering Data) shall result from this procedure.

2. In all procedures established in this Code where measurement data are required, exclusive and sole use shall be made of Metering Data.

3. The Transmission System Operator may request the assistance of Meter Representatives and the Distribution Network Operator in the correction or estimation of measurements.

Article 168 Measurement certification and control

1. All measurements from Registered Meters shall be certified and checked automatically, immediately following their collection by the central measurement administration system.

2. The measurement certification and control procedure includes the verification of errors in measurements which may be due to software or hardware operation conditions and faults, also including telecommunications system errors, as well as measurement deviations from the established accuracy limits and errors as these are established in CHAPTER 57.

3. Measurement certification and control consists in:

Α) checking the compatibility of measurements and the procedure for their collection with the specifications applied;

Β) checking the correspondence between transformer measurements and the measurements taken, if such data are available;

C) verifying the export of the quantities measured from electronically transmitted primary data;

D) checking the synchronization of the Meter clock;

Ε) checking the adequacy of the data storage media of the Meter;

F) monitoring error messages, signs and alerts received by the Meter;

G) comparing the measurements taken from the Main and Backup Meters if the latter is installed, and those from Registered Meters and Check Meters.

4. The Transmission System Operator may implement automated measurement certification and control procedures, besides those established in the previous paragraph.

5. Details about the measurement certification and control methods are established in the Meter and Measurement Manual.

Article 169 Measurement certification and control results

1. If the measurements collected by a Registered Meter are successfully certified following the certification and control procedure in accordance with Article 168, these shall be acknowledged as Metering Data following an adaptation of their numerical values in accordance with Article 171.

2. If the measurements collected by a Registered Meter are not successfully certified following the certification and control procedure in accordance with Article 168 or are not available, the following procedure shall be followed:

Α) the Transmission System Operator shall inform the following about the problem: a) the Representatives of the Meter, in case of a Generation Meter or Load Meter or Backup Meter of the respective Main Meter; b) the System Owner in case of a Registered Meter installed in the System; and c) the Distribution Network Operator, in case of a Distribution Network Boundaries Registered Meter;

Β) the Representatives of Generation Meters, or Load Meters, or Backup Meters of the respective Main Meter, or the Distribution Network Operator in case of Distribution Network Boundaries Registered Meters, once they have taken cognizance of the problem in accordance with the above, must take all necessary action, in cooperation with the Transmission System Operator, to face the problem and then:

(1) provide to the Transmission System Operator all possible information about the causes of the problem and the actions they may take to tackle it; and

(2) provide to the Transmission System Operator a documented appraisal of the energy quantity not correctly measured per Dispatch Period.

C) the System Owner or the Distribution Network Operator, for Registered Meters which are installed in the System or the Distribution Network respectively, and once they have ascertained the causes of the problem shall take the following actions:

(1) if the problem is due to a failure in the measuring device, they shall see to its repair, total or partial replacement;.

(2) if the problem is due to the meter's telecommunications connection, they shall take all actions necessary to tackle the problem;

(3) especially in the case of a Registered Load or Generation Meter, the System Owner shall inform the Eligible Customer or Producer respectively, in the installations of which such Meter is installed.

D) the Transmission System Operator shall correct or estimate such measurements in accordance with Article 170. The measurements resulting shall be acknowledged as Metering Data, once they have had their numerical values adapted in accordance with Article 171.

3. The System Owner and the Distribution Network Operator are required to take all necessary actions so that any problems in Registered Meters installed in the System or the Distribution Network respectively are resolved within seventy two (72) hours from the notification of such problem to them.

Article 170 Measurement correction and estimation

1. Where the measurements from a Main Meter are not available or have not been successfully certified using the certification and control procedure, the Transmission System Operator shall, in order to establish the Metering Data, use the measurements from the Backup Meter, if such measurements have been successfully certified using the above procedure.

2. Where there is no Backup Meter, and the measurements from a Registered Meter are not available or have not been successfully certified using the above certification and control procedure, the Metering Data shall be estimated in accordance with the provisions of paragraphs (3) to (5). The same shall apply where measurements from both the Main and Backup Meter are not available or have not been successfully certified using the certification and control procedure.

3. In the cases of paragraph (2), the following shall be taken into account for the correction or estimation of the energy quantity injected from Units:

Α) the Dispatch Instructions that have been issued to the Unit at the time where there was no adequate measurement;

Β) compliance on the part of the Unit with such Dispatch Instructions which is estimated using the data collected by the dispatch information administration system;

C) measurements from suitable Check Meters;

D) other data which the Transmission System Operator sees suitable to be taken into account, including the estimation in accordance with Article 169 paragraph 2 (B) (2).

4. In the cases of paragraph (2), and in order to correct or estimate the energy quantity corresponding to Registered Load Meters or Distribution Network Boundaries Meters, the following shall be taken into account:

Α) if the period during which measurements are not available or have not been successfully certified in accordance with the certification and control procedure is less than one Dispatch Period, the estimation of data shall be based on the weighted average of Metering Data from the same Meter immediately before and after the time when the problem appeared. Such data are weighted using factors corresponding time distance of the estimated measurement from the time of collection of the foregoing Metering Data;

Β) if the period during which measurements are not available or have not been successfully certified in accordance with the certification and control procedure is more than one Dispatch Period, the estimation of data shall be based on the

average of the Metering Data collected on three recent and, if possible, similar in terms of load, Dispatch Days for the same Dispatch Periods;

C) measurements from suitable Check Meters;

D) other data which the Transmission System Operator sees suitable that they be taken into account, including the estimation in accordance with Article 169 paragraph 2 (Β) (2).

5. In the cases of paragraph (2), and to correct or estimate the energy quantity measured by Interconnection Meters, the UCTE rules applicable each time shall be used, as well as the provisions of the relevant agreements between the Transmission System Operator and other energy transmission system operators.

6. The Transmission System Operator shall correct or estimate measurements within ninety six (96) hours from the Dispatch Day to which they refer.

7. In case of measurement correction or estimation in accordance with the provisions of this Article, the recording of the respective Metering Data in the meter and measurement database shall be accompanied by a relevant marking, while all data and the method used to correct or estimate the measurements shall be recorded in a special file.

8. The Transmission System Operator shall publish each month in its website a list of the measurement correction or estimation cases, which shall include:

Α) the code of the Registered Meter concerned and a description of the installations the energy flow of which is measured by such Meter;

Β) the Meter Representative(s);

C) a description of the reason for which it has become necessary to correct or estimate the measurements; and

D) all other information necessary for transparency reasons.

9. Details about the measurement correction or estimation methods used are given in the Meter and Measurement Manual.

Article 171 Metering Data Adaptation

1. For all Units, with the exception of Auto-Producers, the Transmission System Operator shall substract the Metering Data concerning the auxiliary load of each Unit from the Metering Data concerning energy injection from such Unit, if the auxiliary load installations are supplied by System nodes and are used for the Unit to generate energy or provide Ancillary Services, with the exception of the case where they are used to quarry raw materials or fuel. Systems supplying a Unit with fuel, which are

located in the same location as the Unit, shall be considered auxiliary load installations, if the in the horizontal or vertical accounting unbundling their operating cost is included in the cost of generation activity of such Unit.

2. Where more than one Units are installed in the same location and it is not clearly specified which one supplies energy to the auxiliary load installations, the Transmission System Operator shall allocate the energy quantity that needs to be subtracted in accordance with the previous paragraph, based on the allocation percentages which are established by the production license holders for such Units. The sum of the allocation percentages shall be equal to 100%.

3. The Transmission System Operator must subtract the auxiliary load Metering Data from the respective generation data of a given Auto-Producer Unit, if such Unit is synchronized with the System and generates an energy quantity which suffices to cover the entire auxiliary load. Such subtraction is not allowed if the auxiliary load is served through a line which is not connected to the substation with which the Unit is connected.

4. Metering Data regarding a load that does not correspond to a Unit's auxiliary loads shall not be subtracted from such Unit's generation. Such load, in case where it is connected with the auxiliary system of a Unit and is served by the Unit, shall be added to the energy quantity generated by such Unit.

Article 172 Measurement and Metering Data Record

1. The Transmission System Operator shall keep a full measurement and Metering Data record which shall include:

Α) measurements;

Β) Metering Data, marked where these have been established after correction or estimation in accordance with the provisions of Article 170;

C) a measurement correction or estimation data and method record.

2. The information in such record shall be kept by the Transmission System Operator for at least five (5) years from their entering.

3. System Users shall not have access rights to the information of the following paragraph if they have lawful interest.

SECTION VI IMBALANCES SETTLEMENT

CHAPTER 34

GENERAL PROVISIONS

Article 173 Definitions

1. Energy Deviation shall be defined separately per Energy Offer and Load Declaration and separately per Dispatch Period, and it shall be the difference in MWh between the energy quantity scheduled for injection to the System or absorption by it in accordance with the DAS Schedule and the energy quantity injected to or absorbed by the System in real time operation as is measured for the same Dispatch Period and corresponded to the Participant and the Energy Offer and Load Declaration in question in accordance with SECTION V.

2. In order to achieve promotion of the availability of generation installations and allocation of the cost of deviations as much as possible to those causing deviations, the following shall be established with regard to the settlement of deviations:

Α) Uninstructed Generation Deviation in MWh of a Unit for a Dispatch Period shall be the difference between the quantity energy established by Dispatch Instructions to be injected to the System for the same Dispatch Period and the energy quantity measured for the same Dispatch Period at the Unit Meter;

Β) Instructed Generation Deviation in MWh of a Unit for a Dispatch Period shall be the difference between the quantity energy declared in the Energy Offer for the Unit to the extent that this is included in the DAS Schedule for the same Dispatch Period and the energy quantity established by the Dispatch Instructions for injection to the System for the same Dispatch Period.

Article 174 Scope of the Imbalances Settlement Procedure

Imbalances Settlement includes the settlement of transactions related to Generation Deviations, Ancillary Services and the Uplift Accounts. For that reason the following

shall be calculated during the Imbalances Settlement procedure and for each Dispatch Day:

Α) the energy quantities for Generation Deviation and Instructed and Uninstructed Generation Deviation (in MWh), which are then corresponded to each Participant for each Dispatch Period;

Β) the charge or credit sum corresponding to Generation Deviations and to each Participant for a Dispatch Day, as well as the supplementary charges or credits corresponding to Instructed and Uninstructed Generation Deviations and to each Participant for the same Dispatch Day;

C) the credit sum for each Participant for the provision of Ancillary Services, Supplementary System Energy Provision Availability in the context of Cold Reserve Contracts through the Transmission System Operator's Uplift Account;

D) charges and credits to the Uplift Account.

Article 175 Principles governing the Imbalances Settlement Procedure

1. At the end of each Dispatch Day, the Transmission System Operator shall activate the Imbalances Settlement Procedure which shall be completed within four (4) calendar days (Imbalances Clearing Period). Clearing Day shall be the last day of the Imbalances Clearing Period.

2. Generation Deviations shall be settled at a single price (€/MWh), (Imbalances Marginal Price).

3. With regard to Instructed and Uninstructed Generation Deviations, supplementary charges or remuneration may be calculated and settled in addition to those for Generation Deviations, which shall take different numerical values on a case to case basis separately for each Unit.

4. During the Imbalances Clearing Period the transactions related with Ancillary Services, Supplementary System Energy and Cold Reserve for each Dispatch Period shall also be settled.

Article 176 Imbalances Settlement Procedure Data

The Transmission System Operator may collect, check, manage and store all information it sees necessary for the good operation of the Imbalances Settlement Procedure.

CHAPTER 35

CALCULATION OF ENERGY DEVIATIONS

Article 177 Explanation of Symbols and Magnitudes

1. For the purposes of the Imbalances Settlement Procedure the following symbols shall be used:

Α) d is used for Dispatch Days;

Β) p is used for Load Representatives;

C) g is used for Producers. For the purposes of Imbalances Settlement, this symbol shall also be used for the Transmission System Operator for Units in commissioning operation, Contracted Units for Supplementary System Energy, and Cold Reserve Units, for which the Transmission System Operator submits Energy Offers;

D) u shall be used for Units. These shall include Units in commissioning operation, Contracted Units for Supplementary System Energy, and Cold Reserve Units, for which the Transmission System Operator submits Energy Offers;

Ε) r shall be used for the Units under Article 35 of Law 2773/99;

F) k shall be used for Load Representatives exporting energy from Greece. These exports shall include Exports corresponding to adjusting schedules for flow deviations at the interconnections for which the Transmission System Operator submits Load Declarations;

G) j shall be used for Load Representatives importing energy into Greece. Such imports shall include Imports corresponding to adjusting schedules for flow deviations at the interconnections for which the Transmission System Operator submits Energy Offers;

Η) i shall be used for the Connection Point of a Meter with the System;

I) m shall be used for the Interconnection Corridor for energy imports and exports;

J) t shall be used for Dispatch Periods;

K) c shall be used for Customer Category;

L) s shall be used for the Priced Blocks of an Energy Offer for a Unit u;

M) f shall be used for the steps referring to Table B entitled "Variable Cost Parameters" of Techno-Economic Declarations;

N) isl shall be used for Non-Interconnected Islands.

2. The following variables shall be used for Instructed and Uninstructed Generation Deviations, Energy Deviations, Imbalances Settlement related credits and charges and all related information:

MQpt Measured energy quantity in MWh, concerning energy absorption by a Load Representative p, during Dispatch Period t, as has been measured by the total number of Meters represented by the Load Representative;

MQut Measured energy quantity in MWh, concerning the injection of energy from a Unit u, during Dispatch Period t;

MQrt Measured energy quantity in MWh, concerning the injection of energy from the Units under Article 35 of Law 2773/99, during Dispatch Period t;

MQjmt Measured energy quantity in MWh, at Interconnection Corridor m, for Load Representative j during Dispatch Period t, concerning the injection of energy from import as has been scheduled following an agreement between the Transmission System Operator and the operators of the systems of other countries;

MQkmt Measured energy quantity in MWh, at Interconnection Corridor m, for Load Representative k during Dispatch Period t, concerning load to be exported as has been scheduled following an agreement between the Transmission System Operator and the operators of the systems of other countries;

MQmt Measured energy quantity in MWh, at Interconnection Corridor m, during Dispatch Period t concerning the injection of energy from import and load to export;

MQislt Measured energy quantity in MWh, concerning the absorption of energy in Non-Interconnected Islands isl, during Dispatch Period t, which is the result of dividing the daily absorbed energy in Non-Interconnected Islands by 24;

DASMPt System Marginal Price in € / MWh, during Dispatch Period t;

DASQut Energy quantity in MWh, corresponding to an Energy Offer as this has been included in the DAS Schedule for Unit u, for Dispatch Period t;

DASQrt Energy quantity in MWh, corresponding to an Energy Offer as this has been included in the DAS Schedule for all units under Article 35 of Law 2773/99 for Dispatch Period t;

DASQjmt Energy quantity in MWh, corresponding to an Energy Offer as this has been included in the DAS Schedule for Load Representative j, who imports energy into Greece over the Interconnection Corridor m, for Dispatch Period t;

DASQpt Energy quantity in MWh, corresponding to a Load Declaration as this has been included in the DAS Schedule for Load Representative p, for Dispatch Period t;

DASQkmt Energy quantity in MWh, corresponding to a Load Declaration as this has been included in the DAS Schedule for Load Representative k, who exports energy from Greece over the Interconnection Corridor m, for Dispatch Period t;

INSTQut Difference in MWh between the energy quantity stated in the Energy Offer as this has been included in the DAS Schedule for Unit u and Dispatch Period t and the generation established in the Dispatch Instruction;

UNINSTQut Difference in MWh between the energy quantity established in a Dispatch Instruction and the quantity measured at the Meter of Unit u for Dispatch Period t;

EPSMPt Generation Imbalances Marginal Price in €/MWh, for Dispatch Period t;

EPSMPZt Generation Imbalances Marginal Price for Operational Zone Ζ, in €/MWh, for Dispatch Period t;

IMQt Total Generation Deviations Quantity in MWh for all Participants during Dispatch Period t;

IMQut Generation Deviations Quantity in MWh for Unit u, during Dispatch Period t;

IMQpt Generation Deviations Quantity in MWh for Participating Load Representative p during Dispatch Period t;

IMQrt Generation Deviations Quantity in MWh for all units under Article 35 of Law 2773/1999;

IMQmt Generation Deviations Quantity in MWh for the Interconnection Corridor for import and export m during Dispatch Period t;

IMQjmt Generation Deviations Quantity in MWh for the Interconnection Corridor for import m for Load Representative j during Dispatch Period t;

IMQkmt Generation Deviations Quantity in MWh for the Interconnection Corridor for export m for Load Representative k during Dispatch Period t;

INSTut Energy quantity in MWh, which Unit u must generate during Dispatch Period t, following a Dispatch Instruction issued by the Transmission System Operator;

IMPut Generation Deviation Charge or Credit in € for Unit u and Dispatch Period t;

IMPgt Generation Deviation Charge or Credit in € at Producer g, for Dispatch Period t;

IMPpt Generation Deviation Charge or Credit in € at Load Representative p, for Dispatch Period t;

IMPjmt Generation Deviation Charge or Credit in € at Load Representative j who imports energy over the Interconnection Corridor m, for Dispatch Period t;

IMPjt Generation Deviation Charge or Credit in € at Load Representative j who imports energy for Dispatch Period t;

IMPkmt Generation Deviation Charge or Credit in € at Load Representative k who exports energy over the Interconnection Corridor m, for Dispatch Period t;

IMPkt Generation Deviation Charge or Credit in € at Load Representative k who exports energy for Dispatch Period t;

RECrt Remuneration in € in favor of Units r under Article 35 of Law 2773/99, for Dispatch Period t;

GEN_BALgt Generation remuneration balance in €, for Producer g and Dispatch Period t;

GEN_BALgd Generation remuneration balance in €, for Producer g and Dispatch Day d;

ECgd Energy quantity charge in €, for Producer g and Dispatch Day d;

EPgd Energy quantity payment in €, for Producer g and Dispatch Day d;

SUP_BALpt Supply payment remuneration balance in €, for Load Representative p and Dispatch Period t;

SUP_BALpd Supply payment remuneration balance in €, for Load Representative p and Dispatch Day d;

EPpd Energy quantity payment in €, for Load Representative p and Dispatch Day d;

ECpd Energy quantity charge in €, for Load Representative p and Dispatch Day d;

IMP_BALjt Import remuneration balance in €, for Load Representative j and Dispatch Period t;

IMP_BALjd Import remuneration balance in €, for Load Representative j and Dispatch Day d;

ECjd Energy quantity charge in €, for Load Representative j who imports energy, for Dispatch Day d;

EPjd Energy quantity payment in €, for Load Representative j who imports energy, for Dispatch Day d;

EXP_BALkt Export payment balance in €, for Load Representative k who exports energy for Dispatch Period t;

EXP_BALkd Export payment balance in €, for Load Representative k who exports energy for Dispatch Day d;.

ECkd Energy quantity charge in €, for Load Representative k who exports energy, for Dispatch Day d;

EPkd Energy quantity payment in €, at Participating Load Representative k who exports energy for Dispatch Day d;

RESIDt Charge or credit in €, to the Uplift Account due to deficit or balance from the Imbalances Settlement Procedure for Dispatch Period t;

STEPQsut The energy sum in MWh of Priced Blocks of the Energy Offer of Unit u for Dispatch Period t up to the Priced Block of Energy Offer s (MWh) (where s ≤ 10);

STEPPsut Price in € / MWh of Priced Block s (where s ≤ 10) of the Energy Offer of Unit u for Dispatch Period t;

INSTMut Adjusted energy quantity in MWh per Dispatch Period t, during which Unit u has been called upon to inject energy in the System following a Dispatch Instruction issued by the Transmission System Operator.

UNINSTMut Adjusted energy quantity in MWh per Dispatch Period t, during which Unit u injects energy in the System following a Dispatch Instruction issued by the Transmission System Operator beyond the INSTMut quantity.

INSTPsut Price in € / MWh of the Priced Block s of an Energy Offer of Unit u, which is applied following a Dispatch Instruction to increase the generation of Unit u, during Dispatch Period t.

CONPsut Remuneration in € for an increase of generation, corresponding to the Priced Block s of an Energy Offer of Unit u, for Dispatch Period t.

CONPut Total remuneration in €, for an increase of generation for Generation Unit u and for Dispatch Period t.

TECHSTEPQfut Energy sum in MWh until the step of Variable Cost Curve f (f ≤10) of the Techno-Economic Declaration for Unit u for Dispatch Period t.

TECHSTEPPfut Price in €/MWh, of the step of Variable Cost Curve f (f ≤10) of the Techno-Economic Declaration of Unit u for Dispatch Period t.

INDNPfut Price in €/MWh of the step of Variable Cost Curve f corresponding to a decrease in the generation of Unit u for Dispatch Period t.

COFCut Total charge or credit in €, regarding a decrease in the generation of Unit u for Dispatch Period t.

UPLIFTPt Total charge in € to the Uplift Account through secondary accounts for Dispatch Period t.

TOL Tolerance limit in MWh per dispatch period t in determining Uninstructed Generation Deviations. The same tolerance limit shall be established for imports, exports, and energy absorption accordingly.

RENCOSTt The total sum paid by the Transmission System Operator to production license holders of the Units under Article 35 of Law 2773/99, in accordance with Article 40 of the same law.

TESTCOSTut The total sum paid by the Transmission System Operator to the production license holder of a Unit u for Dispatch Period t, which is in commissioning operation and provided it injects into the System during the same Dispatch Period, and which is calculated for each Dispatch Period as the product of multiplying the energy quantity injected into the System from the Unit, as such energy quantity is measured, by the energy price agreed upon between the Transmission System Operator and the holders of the respective production license, based on the fuel cost for the Unit.

Article 178 Calculation of Energy Deviations for Units

1. Energy Deviations, Instructed and Uninstructed Generation Deviations shall be calculated as follows for each Dispatch Period t, and for Unit u:

A) If TOL < [MQut − INSTut], then the energy quantity corresponding to a Generation Deviation shall be given by the following formula:

IMQut = DASQut – MQut

In addition, an Instructed Generation Deviation in the case of INSTut Dispatch Instructions shall be calculated as follows:

INSTQut = DASQut – (INSTut + TOL)

And :

INSTMut = TOL+ INSTut

And the Uninstructed Generation Deviation in the case of an INSTut Dispatch Instruction shall be calculated as follows:

UNINSTQut = (TOL + INSTut ) – MQut

And:

UNINSTMut = (TOL + INSTut )

Β) If [MQut − INSTut ] < −TOL, then the energy quantity corresponding to a Generation Deviation shall be given by the following formula:


Additionally, the Instructed Generation Deviation in the case of INSTut Dispatch Instructions shall be calculated as follows:

INSTQut = DASQut – (INSTut −TOL)

And:

INSTMut = INSTut −TOL

And the Uninstructed Generation Deviation in the case of INSTut Dispatch Instructions shall be calculated as follows:

UNINSTQut = (INSTut –TOL) – MQut

And:

UNINSTMut = (INSTut –TOL)

C) If TOL ≥ [MQut − INSTut] ≥ −TOL, then the energy quantity corresponding to a Generation Deviation shall be given by the following formula:


Additionally:

INSTQut = DASQut – INSTut

And:

INSTMut = MQut

And:

UNINSTQut = 0

2. Instructed Generation Deviations for a Unit are due to Dispatch Instructions issued by the Transmission System Operator especially regarding a change to Active Power generation for a Unit for reasons of Load monitoring, System Inter-Zonal Constraints and for Ancillary Service and Supplementary System Energy Provision.

3. The numerical value of TOL is established in a single manner by the Transmission System Operator for each calendar year and two (2) months prior to the beginning of a calendar year and shall be subject to approval by RAE. TOL shall receive a single value for all Units, the sole exception being the Units for which the period of 2 years from the commencement of their commercial operation has not yet elapsed, and for which a numerical value for TOL is established increased by 100% for the first year of commercial operation and by 50% for the second year.

4. Details with regard to the method used in calculating the energy quantities corresponding to INSTut Dispatch Instructions, are established in the Dispatch Manual.

Article 179 Establishing Deviations in Energy Imports and Exports at

Interconnections

For each Dispatch Period t, the energy quantity corresponding to Deviations in Imports and Exports at Interconnection m, in MWh shall be calculated as follows:

IMQmt = Σnj=1DASQjmt - Σz

k=1DASQkt – MQmt

Where

n the number of importers; z the number of exporters.

Article 180 Establishing Generation Deviations for Load Representatives

of Customers in Greece

Generation Deviations for each Dispatch Period t, and for Load Representative p, shall be calculated in MWh as follows:

If TOL ≥ [ MQpt − DASQpt] ≥ −TOL,

then IMQpt = 0

else IMQpt = MQpt – DASQpt

Article 181 Establishing Generation Deviations for the Units under Article

35 of Law 2773/1999

For each Dispatch Period t, and for the Units under Article 35 of Law 2773/1999, Generation Deviations in MWh shall be calculated as follows:

If TOL > MQrt – DASQrt > - TOL

then IMQrt =0

else IMQrt = MQrt – DASQrt

Article 182 Methodology for the calculation of Generation Imbalances

Marginal Price

1. Generation Imbalances Marginal Price, EPSMPt, shall be computed by analogy to the DAS Clearing Mechanism methodology. Should System Inter-Zonal Constraints be activated during DAS Clearing, a Generation Imbalances Marginal Price shall be established calculated per System Operational Zone. The problem to be solved shall differ from the DAS problem in terms of the following:

Α) the energy quantities of Energy Offer Priced Blocks for Thermal Units shall be adjusted to correspond to the Adjusted Maximum Capacity of Units, as this is calculated in accordance with paragraph (2) of this Article. Such adjustment shall

be performed by subtracting blocks from the Energy Offer or by reducing the energy quantity of blocks of the Energy Offer in the inverse order of the stepwise function steps. In addition, account shall be taken of the energy quantity-price pairs corresponding to Contracted Units for Ancillary Services and Cold Reserve Units as additional Priced Blocks, to the extent that such energy quantities are included in the Dispatch Schedule for energy injection and only in that case. Any inclusion of such Units in the Dispatch Schedule for Ancillary Service Provision or just Supplementary System Energy Provision Standby, shall not be taken into consideration for the calculations performed in the context of this Article. As energy prices for such blocks shall be taken the cost of Provision Standby and the cost Supplementary System Energy Provision and Emergency Imports which shall be referenced to each energy injecting unit. Adjusted Maximum Capacity shall apply to such units;

Β) account shall be taken of the real load absorbed at Interconnection Connection Points and Corridors during the Dispatch Period of the Dispatch Day;

C) no account shall be taken of Energy Offers submitted by the Transmission System Operator under Article 29. The energy injected to the System at each Dispatch Period of a Dispatch Day and which corresponds to such Offers shall reduce the real load absorbed by the System during the same Dispatch Period. With regard to such decrease, the energy injection quantities shall be adjusted using suitable load loss factors as these are used in the DAS.

2. The Adjusted Maximum Capacity for a Unit shall be calculated for each Dispatch Period and be equal to the Unit’s Maximum Capacity as this has been adjusted following the submission of Non-Availability Declarations and which shall be further adjusted by the Transmission System Operator based on more recent information regarding the real availability of the Unit, which have become known to it during the period from Gate Closure until the real dispatch time. During the calculation of the Unit’s Adjusted Maximum Capacity particular account shall be taken of any cases of non-compliance of such Unit with Dispatch Instructions.

Article 183 Generation Imbalances Marginal Price Recording and

Publishing

1. The Transmission System Operator shall immediately publish the Generation Imbalances Marginal Price in its website.

2. The Transmission System Operator is required to keep a Generation Imbalances Marginal Price record for each Dispatch Period in the past five (5) years readily available to all interested parties.

CHAPTER 36

GENERATION DEVIATIONS SETTLEMENT

Article 184 Charge or Credit Calculation for Generation Deviations

1. The IMPut charge or credit that corresponds to a Generation Deviation for Unit u shall be calculated as follows for each Dispatch Period t:

IMPut = IMQut × EPSMPt + ∆Ζ

where

if the deviation is negative (IMQut < 0) a credit shall be calculated for the Producer of Unit u, while if the deviation is positive (IMQut > 0) a charge shall be calculated for the Producer of Unit u; and

∆Ζ is the additional charge or credit in the case of System Inter-Zonal Constraint activation, which shall be calculated as the product of multiplying the deviation and the Generation Imbalances Marginal Price by the Generation Imbalances Marginal Price of the respective Operational Zone.

2. The charge to Producer g corresponding to a deviation for each Dispatch Period t shall be calculated as follows as the sum of all charges for all of such Producer's units:

IMPgt = Σn u=1IMPut

Article 185 Calculating Charges for Deviations in Imports and Exports at

Interconnections

The IMPm,xt charge or credit corresponding to a Import and Export Deviation at Interconnections shall be calcluated as follows:

IMPm,xt = IMQm,xt × EPSMPt

where a positive value shall correspond to a debit to Uplift Account UA-2 concerning the net cost of interconnections

Article 186 Calculating Charges for Generation Deviations of Load

Representatives

1. The charge or credit corresponding to a Generation Deviation for Load Representative p per Dispatch Period t shall be calculated as follows:

IMPpt = IMQpt x EPSMPt

A positive result shall correspond to a charge and a negative result to a credit for Load Representative p.

2. Exceptionally, if a deviation is due to Load Shedding, in the above formula the Generation Imbalances Marginal Price shall be taken to be the Administratively Defined Imbalances Marginal Price.

Article 187 Calculating Charges for Generation Deviations for the Units

under Article 35 of Law 2773/99

The secondary account of the Uplift Account for the Units under Article 35 of Law 2773/1999 shall be debited or credited with sum RECrt, in €, which shall be calculated as follows for each Dispatch Period t and for all Units under Article 35 of Law 2773/1999:

RECrt = IMQrt × EPSMPt

CHAPTER 37

INSTRUCTED GENERATION DEVIATIONS SETTLEMENT

Article 188 Calculating Additional Remuneration or Charges for Units regarding Uninstructed Generation Deviations in case of a

Generation Increase Instruction

1. The additional CONPut charge for Uninstructed Generation Deviation for Unit u where such Unit has received a Dispatch Instruction to increase its generation (INSTQut < 0), shall be calculated as follows for each Dispatch Period t, provided

that the Dispatch Instruction corresponds to a INSTut generation less than the measured MQut generation quantity:

CONPut = − UNINSTQut × EPSMPt + ∆Ζ

which in this case shall be assigned a plus sign and correspond to a charge for the Producer of Unit u. ∆Ζ is the additional charge or credit in the event of System Inter-Zonal Constraint activation which shall be calculated as the product of multiplying : a) the difference between the energy quantity established in the Dispatch Instruction and the energy quantity measured at the Meter of Unit u for Dispatch Period t; and b) the difference between the Generation Imbalances Marginal Price and the Imbalances Marginal Price of the respective Operational Zone.

2. The additional charge for an Uninstructed Generation Deviation in case of a Generation Increase Instruction for Producer g for each Dispatch Period t shall be takent to be the sum of the respective charges for all the Units of such Producer as follows:

CONPgt = Σnu=1CONPut

Article 189 Calculating Additional Unit Charges or Credits for Instructed

and Uninstructed Generation Deviations in the event of a Generation Decrease Instruction

1. The additional COFCut charge or credit corresponding to Instructed and Uninstructed Generation Deviations for Unit u shall be calculated for each Dispatch Period t, if there is a decrease in the generation (INSTQut > 0) of such Unit.

2. During Dispatch Period t for Instructed Generation Deviations, the charges under paragraph (1) shall be computed as follows:

Α) f' shall be calculated, which shall be take values between 1 and f (1≤ f' ≤ f), in order to meet the following expression:

TECHSTEPQ(f'–1)ut < DASQut ≤ TECHSTEPQf'ut)

Β) the variable cost for step f' shall be taken as this has been stated in the Techno-Economic Declaration, as the value for calculating the temporary charge for the part of the energy quantity that corresponds to step f', which Unit u has been called upon not to generate during Dispatch Period t. The above are shown as follows:

INDNPf'ut = TECHSTEPPf'ut

C) the temporary charge shall be calculated for the part of the energy quantity which has been reduced following the Dispatch Instruction and corresponds to the step f' in accordance with the following formula:

COFCf'ut = min [INDNPf'ut × (DASQut – TECHSTEPQ(f'-1)ut),

INDNPf'ut × (DASQut – INSTMut)]

D) the variable cost is taken for each step between 1 and (f'-1), as these have been stated in the Techno-Economic Declaration, as the value for the calculation of the temporary charge for the part of the energy quantity of the respective step, which Unit u has been called upon not to generate during Dispatch Period t as follows:

For n = 1 to (f'-1)

And TECHSTEPQ0ut= 0

If INDNP((f'–n)+1))ut ≠ 0

and INSTMut < TECHSTEPQ(f'–n)ut

then INDNP(f'–n)ut = TECHSTEPP(f'–n)ut

else INDNP(f'–n)ut = 0

Ε) the temporary remuneration (COFC(f'-n)ut) shall be calculated for each part of the energy quantity that has not been generated by Unit u following a Dispatch Instruction, and which corresponds to step n in accordance with the formula:

COFC(f'-n)ut = min[INDNP(f'–n)ut × (TECHSTEPQ(f'–n)ut –

TECHSTEPQ(f'–n–1)ut), (INDNP(f'–n)ut) ×

(TECHSTEPQ(f'–n)ut – INSTMut)]

∀n ∈(1,(f′-1))

3. Τhe additional charge or credit for Unit u which has received a Dispatch Instruction to reduce its generation during Dispatch Period t, shall be calculated using the following formula:

COFCut = Σf'n=1 COFCnut − (DASQut – max(MQut, INSTMut)) ×

EPSMPt + ∆Ζ

Where ∆Ζ is the additional charge or credit in case of System Inter-Zonal Constraint activation, and calculated as the product of multiplying:

a) the difference between: (aa) the energy quantity which corresponds to an Energy Offer as this has been included in the DAS Schedule for Unit u and Dispatch Period t; and (bb) the maximum value between the measured energy quantity injected by Unit u and the adjusted energy quantity per Dispatch Period t, during which Unit u has been called upon to inject energy into the System following a Dispatch Instruction; and

b) the difference between the Generation Imbalances Marginal Price and the Imbalances Marginal Price of the respective Operational Zone.

4. The formulas under (Α), (Β) and (D) above establish the steps of the Techno-Economic Declaration for Unit u, which correspond to the energy quantity which Unit u was called upon to reduce, following a Dispatch Instruction issued by the Transmission System operator.

5. The additional charge or credit for Uninstructed Generation Deviations in case of a Generation Decrease Instruction for Producer g for each Dispatch Period t shall be taken as the sum of the respective charges for all Units of such Producer as follows:

COFCgt = Σnu=1COFCut

Article 190 Daily Payments and Charges

On each Clearing Day the Transmission System Operator shall calculate the daily energy payment or charge corresponding to each Participant for the respective Dispatch Day, taking account of the energy which the Participant has injected into or absorbed from the System for each Dispatch Period for the specific Dispatch Day. More specifically:

Α) for production license holders of Units they shall be calculated as follows:

GEN_BALgt = IMPgt + CONPgt + COFCgt

GEN_BALgd = Σ24t=1GEN_BALgt

if GEN_BALgd < 0 then EPgd = -GEN_BALgd

else ECgd = GEN_BALgd

Β) for Load Representatives of Customers in Greece they shall be calculated as follows:

SUP_BALpt = IMPpt

SUP_BALpd = Σ24t=1 SUP_BALpt

If SUP_BALpd >0 then ECpd = SUP_BALpd

else EPpd = - SUP_BALpd

CHAPTER 38

CHARGE AND CREDIT SETTLEMENT PROCEDURE

Article 191 Imbalances Settlement Accounts

6. To settle daily charges and credits in the context of Imbalances Settlement, the Transmission System Operator shall use the Imbalances Settlement System.

7. Each Participant shall keep a bank account with a financial institution operating in Greece (Imbalances Settlement Account) to perform the payments or collections corresponding to them through bank transactions, following instructions issued by the Transmission System Operator as a result of Imbalances Settlement.

8. The Transmission System Operator may enter into a contract with the DAS Settlement House in order for the latter to perform the bank transactions and provide accounting monitoring services.

9. The Transmission System Operator shall keep a special Imbalances Settlement accounting account separately for each Participant aiming at the accounting monitoring of the credits and charges corresponding to them in the context of Imbalances Settlement.

Article 192 Daily Payment and Charge Procedure and Provision of

Information to Participants

10. Credit and charge instructions shall be issued on the Clearing Day and recorded in the Initial Imbalances Settlement List which shall be notified to all Participants for the part that concerns them.

11. The Initial Imbalances Settlement List shall include in particular:

Α) details about the charges and credits for each Participant for each Dispatch Period and for each one of their activities;

Β) the total monetary sum that results as a charge or credit for each Participant;

C) the metering data for each Dispatch Period both for each Meter and for each Meter Category represented by each Participant;

D) the Dispatch Instructions related to the calculation of the above charges and credits;

Ε) other information which in the judgment of the Transmission System Operator explain the Initial Imbalances Settlement List, if such information is not confidential.

12. Should a Participant doubt the contents of the Initial Imbalances Settlement List, they shall lodge justified objections addressed to the Transmission System Operator in writing and within four (4) calendar days from the notification of the Initial Imbalances Settlement List.

13. The Transmission System Operator shall issue a justified decision on such objections and issue the Final Imbalances Settlement List. Any disputes that may arise between the parties shall be settled using the procedure established in Article 10.

14. On the fourteenth (14) calendar day from the Dispatch Day, the Transmission System Operator shall notify to all Participants the Final Imbalances Settlement List concerning each one of them, as well as the relevant documents and issue the respective bank orders. Until the issue of the Distribution Network Administration Code, the Final Imbalances Settlement List shall be issued cumulatively for all Dispatch Days in the same month, and it shall be notified to Participants on the 14th calendar day from the end of the month.

15. The Final Imbalances Settlement List, shall be issued following the form and having the contents of the Initial Imbalances Settlement List.

16. In any case, a Participant to whom a Final Imbalances Settlement List is addressed, is required to pay in full the charges and receive the credits listed in this by the Payment Day, namely after two (2) business days from the first business day following the notification of the Final Imbalances Settlement List, and until 10:00 am on such day. The above obligation is independent of any objections lodged by a Participant and failure to perform it shall entail the consequences under Article 194.

17. The Participant cooperating with the Transmission System Operator on the settlement of a dispute that has arisen with regard to a specific Initial Imbalances Settlement List, shall be required to pay any additional expenses incurred by the Transmission System Operator in repeating the settlement calculations. These sums shall be returned to the Participant, unless the repeated calculations result in that the Initial Imbalances Settlement List is erroneous. Such expenses shall be entered in the Final Imbalances Settlement List.

18. The Dispatch Manual lays down details with regard to the form and contents of Initial Imbalances Settlement Lists, Final Imbalances Settlement Lists and the relevant documents and bank transactions, as well as with regard to the method and contents of any communication between the Participants and the Transmission System Operator in the context of Imbalances Settlement.

Article 193 Fund Transfer Procedures

19. In the context of Imbalances Settlement funds shall be transferred between the Imbalances Settlement Accounts of the Transmission System Operator and the Participants respectively.

20. Any Participant that is in debt in accordance with the Final Imbalances Settlement List, shall be required to take all necessary actions in order to complete the transfer of any sums owed to the Transmission System Operator's Imbalances Settlement Account within the deadline established in Article 192.

21. Once such deadline has elapsed, the Transmission System Operator shall check all performed transfers of funds to the Transmission System Operator’s Imbalances Settlement Account, enter the relevant payments made by each Participant in the special Imbalances accounting account for each Participant, and see to the transfer of any relevant sums to the Imbalances Settlement Account of each Participant.

Article 194 Settlement Procedure in case of Participant Default

22. In case of Participant default, the Transmission System Operator shall see to the completion of the settlement of the Imbalances Settlement Account prior to the expiry of the bank transactions for the specific Payment Day and to that end it shall take the following actions. It shall:

Α) take all necessary actions in order to be satisfied by the guarantees provided by the Participant in default and inform such Participant, the remaining Participants and the Settlement House about the default;

Β) if the overdue debt has not been paid in full, it shall cover the deficit from the Reserve Fund Account and take all necessary actions for the collection, including interest, of the overdue debt, as well as all direct damages it has suffered due to such default;

C) the Participant in default must take immediately all actions in order to perform the obligation of providing the guarantees corresponding to it in accordance with Article 213.

23. The Transmission System Operator is entitled to terminate the Energy Transactions Contract for those Load Representatives that become in default in terms of the performance financial obligations during Imbalances Settlement.

Article 195 Operator's Reserve Fund Account

1. In order to meet any deficit in terms of transactions performed in the contexts of the Imbalances Settlement Procedure, the Transmission System Operator shall keep a Reserve Fund Account.

2. The expenses relating to the keeping of the Reserve Fund Account, as well as all financial costs related thereto, shall be debited to a special secondary account of the Uplift Account relating to the Reserve Fund Account.

3. If the overdue debt that has been covered from the Reserve Fund Account is collected, the Transmission System Operator shall credit the sum collected to the Reserve Fund Account.

Article 196 Settlement in Emergency Situations

1. If it is impossible to implement the Imbalances Settlement procedure, particularly due to a System Emergency Situation, a fault in the Dispatch Information Administration System or in the Communications Systems or other Transmission System Operator electronic systems, the latter shall be able to postpone the Settlement for three (3) days, if such failure is considered temporary and is not anticipated to last beyond such period. In all other cases, settlement shall be performed using all suitable means.

2. If at the end of the Clearing Period the Metering Data or other information that are necessary in order to calculate payments and charges in the context of Imbalances Settlement are not available, the Transmission System Operator shall proceed to the reasonable evaluation of unavailable data, taking account of their history as well as all necessary information for that purpose, and issues based on them the Initial and Final Imbalances Settlement List extending the relevant deadlines for the Settlement of Imbalances, if necessary. The details pertaining to the extension of such deadlines and the method used to substantiate the estimated data shall be published in the Operator’s website.

3. Within a reasonable time period from the occurrence of an emergency situation, the Transmission System Operator shall prepare a justified report on such situation as well as on the measures taken to tackle them. Such report shall be submitted to RAE and published in the Transmission System Operator’s website.

4. The Transmission System Operator shall verify the estimated data it has used and based on such verification it shall review the Initial and Final Imbalances Settlement Lists. Should such verification not be possible, the Transmission System Operator

shall review such Lists in its reasonable judgment, taking account of the data provided by Participants.

Article 197 Establishing the Imbalances Marginal Price in case of

Emergency

1. Where the calculation of the Imbalances Marginal Price is impossible particularly due to an Emergency Situation or fault in the DAS Information Administration System or the Dispatch Information Administration System, or other Transmission System Operator electronic systems, the latter shall be able to postpone the calculation of the Imbalances Marginal Price for three (3) days if the failure is considered temporary and is not anticipated to last beyond such period, and inform RAE making available to the latter all the information this may request to establish the Administratively Defined Imbalances Marginal Price.

2. In that case, the Transmission System Operator shall investigate the reasons for which it has not been possible to establish the Imbalances Marginal Price and publish a relevant report.

Article 198 Aggregate Imbalances Settlement

1. Each calendar year shall be divided into four quarters, each one of which shall be defined as an Aggregate Imbalances Settlement Period.

2. Once the Aggregate Imbalances Settlement Period has elapsed, the Transmission System Operator shall proceed to the Aggregate Settlement of Imbalances in the context of which it shall:

Α) identify any errors in the initial charge and credit calculations in the Final Imbalances Settlement Lists;

Β) verify based on more recent data any estimates made in the case of Settlement in Emergency Situations;

C) take account of the result of the Imbalances Settlement procedure.

3. Six weeks after the Aggregate Imbalances Settlement Period, the Transmission System Operator shall send to each Participant a Temporary Aggregate Imbalances Settlement List concerning such Period. Such Temporary Aggregate Imbalances Settlement List shall include the charges and credits that have resulted from the Aggregate Imbalances Settlement.

4. Should a Participant doubt the contents of the Temporary Aggregate Imbalances Settlement List, they shall lodge justified objections addressed to the Transmission System Operator in writing and within four (4) calendar days from the notification of such List.

5. The Transmission System Operator shall issue a justified decision on such objections and issue the Final Aggregate Imbalances Settlement List, which it shall announce to all Participants to the extent it concerns them. Any disputes that may arise shall be settled using the procedure established in Article 10.

6. On the fourteenth (14) calendar day from the notification of the Final Aggregate Imbalances Settlement List, the Transmission System Operator shall send the relevant documents and issue the respective bank orders.

7. The Temporary and Final Aggregate Imbalances Settlement Lists shall be issued following the form and having the contents of the Initial Imbalances Settlement List and refer to the aggregate information of the Aggregate Imbalances Settlement Period.

8. In any case, a Participant to whom a Final Aggregate Imbalances Settlement List is addressed, is required to pay in full the charges and receive the credits listed in this by the Payment Day, namely after two (2) business days from the first business day following the notification of the Final Aggregate Imbalances Settlement List, and until 10:00 am on such day. The above obligation is independent of any objections lodged by a Participant and failure to perform it shall entail the consequences under Article 194.

9. The Participant cooperating with the Transmission System Operator on the settlement of a dispute that has arisen with regard to a specific Aggregate Imbalances Settlement List, shall be required to pay any expenses incurred by the Transmission System Operator in repeating the settlement calculations. These sums shall be returned to the Participant, unless the repeated calculations result in that the Temporary Aggregate Imbalances Settlement List is erroneous. Such expenses shall be entered in the Final Aggregate Imbalances Settlement List.

CHAPTER 39

UPLIFT ACCOUNT SETTLEMENT

Article 199 Transmission System Operator Accounts

1. Using its accounting system, the Transmission System Operator shall keep the following distinct accounting accounts:

(A-A) DAS Settlement Account, which shall also include individual DAS Settlement Accounts separately for each Participant;

(A-Β) Special Account for DAS Financial Coverage regarding the coverage of any deficits in the context of Energy Transactions;

(A-C) Generation Deviations, Instructed and Uninstructed Generation Deviations Settlement Account, which shall also include individual Generation Deviations, Instructed and Uninstructed Generation Deviations Settlement accounts separately for each Participant;

(A-D) Account for the provision of Ancillary Services, Ancillary Service provision availability from Contracted Units for Ancillary Services, Supplementary System Energy Availability, Standby and Provision from Contracted Units for Supplementary System Energy, Emergency Imports and Cold Reserve Units, which shall also include individual accounts per category and separately for each Participant;

(A-Ε) Reserve Fund Account regarding the coverage of any deficits in the context of Imbalances Settlement transactions;

(A-F) Capacity Assurance Mechanism Account, which shall also include individual Capacity Assurance Mechanism Accounts separately for each Participant;

(A-G) Non-Compliance Charges Account, which shall be further divided into other accounts for each category of non-compliances, provided for in Article21, Article 32, Article 38, Article 40, Article 46, Article 92, Article 148 and Article 224, and which shall also include individual Non-Compliance Charges Accounts separately for each Participant;

(A-Η) Use of System Charge Account;

(A-I) Account for the cost of obligations for the Units under Articles 35 and 36 of Law 2773/1999;

(A-J) Account for the cost of obligations for Units operating under commissioning conditions, prior to the commencement of their commercial operation;

(A-K) Public Service Obligations cost account;

(A-L) Transmission System Operator Administrative Expenses account;

(A-M) Allocation of Interconnection Transfer Capacity account;

(A-N) Uplift Account, which comprises the following secondary accounting accounts:

UA-1: uplift for the Account for DAS Financial Coverage;

UA-2: uplift for the Generation Deviations, Instructed and Uninstructed Generation Deviations Settlement Account;

UA-3: uplift for the Account for the provision of Ancillary Services, Ancillary Service provision availability from Contracted Units for Ancillary Services, Supplementary System Energy Availability, Standby and Provision from Contracted Units for Supplementary System Energy, Emergency Imports and Cold Reserve Units;

UA-4: uplift for the Fund Reserve Account;

UA-5: uplift for the Capacity Assurance Mechanism Account;

UA-6: uplift for the Use of System Charge Account;

UA-7: uplift for the Account for the cost of obligations for the Units under Articles 35 and 36 of Law 2773/1999;

UA-8: uplift for the Account for the cost of obligations for Units operating under commissioning conditions, prior to the commencement of their commercial operation;

UA-9: uplift for the Public Service Obligations cost account;

UA-10: uplift for the Transmission System Operator Administrative Expenses account.

2. Among others, the necessary sums for the payment of compensation, may be disbursed from the A-L account, which are used to pay compensations that may be imposed to the Transmission System Operator, as is the case for instance in the context of its participation in the Multilateral Agreement for the implementation of the UCTE Operation Handbook. The expenses imputed to the payment of compensations shall be recovered through a special charge to Load Representatives through secondary accounting account UA-10, of the Uplift Account. Such expenses shall be recovered within six months from their imputation.

3. The accounting system for the above accounts shall be audited and certified on an annual basis by certified auditors.

Article 200 Uplift Account Accounting Transactions

1. Accounting accounts A-A to A-M shall include all accounting transactions and especial the debits and credits to Participants as these are provided for in the provisions of this Code. They shall also include on a case to case basis debits to Accounts corresponding to payments made to beneficiaries, in accordance with the provisions of this Code, as is particularly the System Owner, for the use of System charge and the Distribution Network Operator for its administrative expenses.

2. The accounting transactions for the Uplift Account shall concern exclusively charges to or the return of previous payments made by Participants which are necessary to balance the respective accounts.

3. This Code establishes separately for each secondary account of the Uplift Account the method used to calculate charges to or return payments made by Participants, as well as the method of allocating the deficit or surplus of the respective account.

Article 201 Accounting Transactions for UA-1

1. Charges to Participants in the context of Uplift for the Account for DAS Financial Coverage shall compensate the Fixed and Extraordinary Coverage Cost.

2. The way of allocation of the relevant cost to Participants and in particular to Suppliers shall be established in Article 15.

3. The method for the periodic balancing of the Account for DAS Financial Coverage is established in Article 65, which establishes the calculation method for additional charges or return of charges to Participants in order for the respective account to be balanced.


1. Charges to Participants in the context of Uplift for the Generation Deviations, Instructed and Uninstructed Generation Deviations Settlement Account shall compensate the cost of such deviations and deviations which may not be allocated to Participants using the special allocation method established in CHAPTER 36 and CHAPTER 37.

2. Such total cost to which Uplift Account UA-2 refers, shall be calculated as follows for each Dispatch Period t:

RESIDt = Σng=1GEN_BALgt + Σn

p=1SUP_BALpt - ΙΜPmt

∀g,p,j,k,r

for which a positive result implies charges to Participants in the context of UA-2,while a negative result implies the return of charges to Participants. Subscripts gd and m, t, indicate the Transmission System Operator who acts as a Producer, Importer, and Exporter respectively for a) Units in commissioning operation, Contracted Units for Supplementary System Energy and Cold Reserve Units; and b) Emergency Imports, and the Imports and Exports corresponding to adjusting schedules for flow deviations at the interconnections.

3. Cost RESIDt shall be allocated to each Load Representative p depending on the energy quantity it absorbs from the System during Dispatch Period t, as such energy quantity is measured during the Measurement Collection Procedure. Such allocation shall be performed as follows:

UPLIFT2p,mt = RESIDt × [(MQpt+DASQkmt) /

(Σnp=1MQpt + Σn

x=1Σnk=1DASQkmt)]

4. The sum UPLIFT2pt is included in the Imbalances Settlement List and the Imbalances Settlement Procedure is followed with regard to charges, bank transactions, and payments.

5. If as a result of such procedure the Generation Deviations, Instructed and Uninstructed Generation Deviations Settlement Account is not balanced at the end of the calendar year, any deficit shall be covered through the imposition of additional charges as established in paragraph (3), where in terms of the allocation account is taken of the total energy corresponding to the Load Representative for such calendar year. The allocation method shall be used to calculate the sums to be returned to Load Representatives if the annual result of the Generation Deviations, Instructed and Uninstructed Generation Deviations Settlement Account is a surplus for a given calendar year.


1. Charges to Participants in the context of Uplift for the Account for the provision of Ancillary Services, Ancillary Service provision availability from Contracted Units for Ancillary Services, Supplementary System Energy Availability, Standby and Provision from Contracted Units for Supplementary System Energy, Emergency Imports and Cold Reserve Units compensate the payments made for such services subtracting the credits which result from the DAS and correspond to the Priced Blocks of the respective Energy Offers submitted to the DAS by the Transmission System Operator in accordance with Article 59. They also include charges and credits

corresponding to deviations for Contracted Units for Supplementary System Energy, Emergency Imports and Cold Reserve Units. This Account includes the net price (expenses less sums collected) paid by the Transmission System Operator to the Operators of Neighboring Systems or in the context of the Cross-Border Trade System of the European Union and Southeast Europe and the charges or credits for deviations corresponding to emergency energy imports by the Transmission System Operator in case of Emergency, as well as for the energy, the deviations, the credits or charges in the context of the DAS corresponding to energy flows for adjusting schedules for flow deviations at the interconnections.

2. Such total payment shall be calculated in accordance with the provisions of the Code and the relevant contracts. With regard to the fixed part of payments the sum corresponding to the total calendar year shall be allocated for each Dispatch Period t by dividing such sum into the number of annual hours (namely 8,760). To this the sums of payments calculated for each Dispatch Period in accordance with the provisions of this Code and the relevant contracts shall be added. The symbol used for the resulting payment sum for each Dispatch Period shall be ANSCC t and the sum shall be in €.

3. Sum ANSCCt shall be allocated to each Load Representative p depending on the energy quantity they absorb from the System for Dispatch Period t as such energy is measured during the Measurement Collection Procedure. Such allocation shall be performed as follows:

UPLIFT3p,mt = [(MQpt+DASQkmt) /

(Σnp=1MQpt + Σn

x=1Σnk=1DASQkmt) ] × ANSCCt


5. If as a result of such procedure the Account for Ancillary Services, Supplementary System Energy Availability, and Cold Reserve Units is not balanced at the end of the calendar year, any deficit shall be covered through the imposition of additional charges as established in paragraph (3), where in terms of the allocation account is taken of the total energy corresponding to the Load Representative for such calendar year. The allocation method shall be used to calculate the sums to be returned to Load Representatives if the annual result of the Account for Ancillary Services, Supplementary System Energy Availability, and Cold Reserve Units is a surplus for a given calendar year.


1. Charges to Participants in the context of Uplift for the Reserve Fund Account compensate the financial cost related to the keeping by the Transmission System Operator of the Reserve Fund Account, as well as extraordinary expenses that arise due to failure to restore deficits in the Reserve Fund Account due to failure on the part of Participants to pay their debts.

2. Such total sum LOANCµ shall be calculated on a monthly basis, it shall be expressed in € and allocated to each Participant p depending on the total monthly IMP charges for Imbalances with which a Participant has been charged in accordance with the Imbalances Settlement Procedure. Such allocation shall be performed as follows:

UPLIFT4pµ= [Σµt=1IMPpt / [Σn

p=1 Σµt=1IMPpt]] × LOANCµ

Where

Σµt=1 the sum for all Dispatch Periods in month m.

3. The sum UPLIFT4pt is included monthly in the Aggregate Imbalances Settlement List and the Imbalances Settlement Procedure is followed with regard to charges, bank transactions, and payments.

4. If as a result of such procedure the Reserve Fund Account is not balanced at the end of the calendar year, any deficit shall be covered through the imposition of additional charges as established in paragraph (2), where in terms of the allocation account is taken of the total energy corresponding to the Load Representative for such calendar year. The allocation method shall be used to calculate the sums to be returned to Participants if the annual result of the Reserve Fund Account is a surplus for a given calendar year.


1. Charges to Participants in the context of Uplift for the Capacity Assurance Mechanism Account compensate the expenses incurred from Financial Agreement for Guaranteed Revenues entered into by the Transmission System Operator for new Unit CACs.

2. The relevant cost shall be allocated to Participants and more specifically to Load Representatives in accordance with Article 246.

3. The method for the balancing of the Capacity Assurance Mechanism Account per calendar year is established in the pervious Article, so is also the method for the

calculation of charges to Participants in order for the relevant account to be balanced annually.


1. Charges to Participants in the context of Uplift for the Use of System Charge Account shall compensate the price paid to the System Owner fro the use of the System by users.

2. The Transmission System Operator shall budget such price for each calendar year in accordance with the lawful approval of the sums corresponding to the relevant parts.

3. CHAPTER 60 establishes the method of allocation and the balancing of the Use of System Charge Account to users, as well as other details. The method and procedure for the settlement of the relevant payments are established in CHAPTER 38.


1. Charges to Participants in the context of Uplift for the Account for the cost of obligations for the Units under Articles 35 and 36 of Law 2773/1999 compensate the sum corresponding to the net payment made by the Transmission System Operator to production license holders for Units under Articles 35 and 36 of Law 2773/1999 in the context of the Account for the cost of obligations for the Units under Articles 35 and 36 of Law 2773/1999. The net payment sum shall be the difference in the context of the respective Account of the obligations to make payments to production license holders for Units under Article 35 and 36 of Law 2773/1999 and the credits of such Account which are effected in the context of the DAS and the Imbalances Settlement Procedure.

2. The net payment sum shall be calculated as follows for each Dispatch Period t:

RENPAYt = RENCOSTt + Σnr=1RECrt + NETPAYt + DASQrt × SMPt +

TSRESt + RENFEE × (Σnp=1MQpt + Σn

x=1Σnk=1DASQkmt + MQislt)

Where

NETPAYt are the sums paid by PPC as the Single Supplier in Non-Interconnected Islands for such Units in addition to the cost avoided which is calculated based on the average variable generation cost of PPC in such islands, in accordance with the provisions of Article 40 paragraph (2) (b) of Law 2773/1999, which is budgeted for each calendar year and is allocated to each Dispatch Period dividing the budgeted sum into 8,760;

TSRESt is the sum that corresponds to the use of system charges from generation units under Article 35 of Law Ν.2773/1999, in accordance with Articl 309;

RENFEE are the special fees under Article 40 paragraph (3) (c) of Law 2773/1999.

3. The sum RENPAYt shall be allocated to each Load Representative p depending on the energy quantity it absorbs from the System during Dispatch Period t as such energy quantity is measured during the Measurement Collection Procedure. Allocation shall be performed as follows:

UPLIFT7p,m,islt = [(MQpt+DASQkmt+MQislt) / (Σnp=1MQpt +

Σnx=1Σn

k=1DASQkmt + MQislt) ] × RENPAYt × CTp

Where CTp are cost allocation factors established per Load Representative category in accordance with Article 23 paragraph (20) of Law 3175/2003.


5. If as a result of such procedure the Account for the cost of obligations for the Units under Articles 35 and 36 of Law 2773/1999 is not balanced at the end of the calendar year, any deficit shall be covered through the imposition of additional charges as established in paragraph (3), where in terms of the allocation account is taken of the total energy corresponding to the Load Representative for such calendar year. The allocation method shall be used to calculate the sums to be returned to Load Representatives if the annual result of the Account for the cost of obligations for the Units under Articles 35 and 36 of Law 2773/1999 is a surplus for a given calendar year.


1. Charges to Participants in the context of Uplift for the Account for the cost of obligations for Units u operating under commissioning conditions, prior to the commencement of their commercial operation compensate the sum corresponding to the net payment made by the Transmission System Operator to production license holders for Units in commissioning operation. The net payment sum shall be the difference in the context of the respective Account of the obligations to make payments to production license holders for Units in commissioning operation and the credits of such Account which are effected in the context of the DAS.

2. The net payment sum shall be calculated as follows for each Dispatch Period t:

TESTPAYt = Σn u=1 (TESTCOSTut + DASQut × DASMPt)

+ Σngd=1GEN_BALgdt

Where DASQut is the energy quantity of the energy offer submitted by the Transmission System Operator to the DAS on the part of Unit u in commissioning operation . Subscript gd indicates exclusively the Transmission System Operator who acts as Producer for Units in commissioning operation.

3. The sum TESTPAYt shall be allocated to each Load Representative p depending on the energy quantity it absorbs from the System during Dispatch Period t as such energy quantity is measured during the Measurement Collection Procedure. Allocation shall be performed as follows:

UPLIFT8p,mt = [(MQpt + DASQkmt) /

[Σnp=1 MQpt + Σn

x=1 Σnk=1 DASQkmt]] × TESTPAYt



1. Charges to Participants in the context of Uplift for the Public Service Obligations cost account compensate the net expenses for compliance with the requirements for the provision of Public Service Obligations in accordance with Article 28 paragraph (3) of Law 2773/1999. Net expenses shall be the expenses for Public Service Obligations for which the Ministerial Decision provided for in Article 28 paragraph (3) of Law 2773/1999 establishes that they be recovered through Uplift Account UA-9.

2. The sum corresponding to such PUPLC expenses shall be budgeted by the Transmission System Operator for each calendar year and allocated for each Dispatch Period t as follows: PUPLCt = PUPLC/8,760 and shall be expressed in €.

3. The sum PUPLCt shall be allocated to each Load Representative p depending on the energy quantity it absorbs from the System during Dispatch Period t as such energy quantity is measured during the Measurement Collection Procedure. Allocation shall be performed as follows:

UPLIFT9p,m,islt= [(MQpt + DASQkmt + MQislt) /

[Σnp=1 MQpt + Σn

x=1 DASQkmt + MQislt]] × PUPLC t × CTp

Where CTp are cost allocation factors established per Load Representative category in accordance with Article 23 paragraph (19) of Law 3175/2003.


5. If as a result of such procedure the Public Service Obligations cost account is not balanced at the end of the calendar year, any deficit shall be covered through the imposition of additional charges as established in paragraph (8), where in terms of the allocation account is taken of the total energy corresponding to the Load Representative for such calendar year. The allocation method shall be used to calculate the sums to be returned to Load Representatives if the annual result of the Public Service Obligations cost account is a surplus for a given calendar year.


1. Charges to Participants in the context of Uplift for the Transmission System Operator’s Administrative Expenses Account shall compensate the Transmission System Operator’s total Administrative Expenses which it may recover from Participants in accordance wit the terms of its License. The Transmission System Operator is required to keep the necessary records in order for such expenses to be documented.

2. The Transmission System Operator shall budget the expenses sum HTSOC for each calendar year in accordance with the terms of its License, and such sum shall be allocated for each Dispatch Period t as follows: HTSOCt = HTSOC/8,760 and be expressed in €.

3. The sum HTSOCt shall be allocated to each Participant p depending on the energy quantity that corresponds to it as it is included in the DAS Schedule either as injection or as absorption. The allocation shall be effected as follows:

UPLIFT10p,islt = [[DASQpt + MQislt] /

[Σnp=1 DASQpt + MQislt)]] × HTSOCt


5. If as a result of such procedure the Transmission System Operator’s Administrative Expenses Account is not balanced at the end of the calendar year, any deficit shall be covered through the imposition of additional charges as established in paragraph (3), where in terms of the allocation account is taken of the total energy corresponding to the Participant as is included in the DAS Schedule as injection or absorption for such calendar year. The allocation method shall be used to calculate the sums to be

returned to Participants if the annual result of the Transmission System Operator’s Administrative Expenses Account is a surplus for a given calendar year.

Article 211 Payment Settlement for A-H

The Transmission System Operator shall calculate the sums for the charges corresponding to each Participant as these result in accordance with the contracts regarding connection to the System and the contracts for use of the System for the Participants or the Customers, the Meters of which are represented by Participants. Such charges shall correspond to entries in the A-H Account for the Cost of the System. In order to pay such sums in full, the Transmission System Operator shall issue the relevant orders for the performance of accounting transactions through the Participant’s Accounts. The provisions of the Code on Imbalances Settlement Procedure shall apply accordingly and in particular with regard to the preparation and notification to Participants of charge settlement lists, periodically and cumulatively, the lodging of objections by Participants and the examination of the same by the Transmission System Operator, the submittal and the dispute settlement procedure, the case of Participant default and the Transmission System Operator’s right to terminate the Energy Transactions Contract for a Participant in default.

Article 212 Management of surplus in A-G and A-M accounts

1. During the calendar year, the Transmission System Operator may transfer the total sum that has been collected in Non-Compliance Charges Account A-G and/or Allocation of Interconnection Transfer Capacity account A-M for such calendar year, or part thereof and enter it temporarily as revenue in Transmission System Operator Administrative Expenses Account A-L which shall be used for the direct payment of compensations which may be imposed upon the Transmission System Operator, as for instance in the context of its participation in the Multilateral Agreement for the implementation of the UCTE Operation Handbook. The progressive recovery of the sums in Accounts A-G and A-M which have been transferred temporarily to Account A-L shall be effected through a special charge to Load Representatives in accordance with Article 199 paragraph (2).

2. The price paid by Participants for reserving interconnection transfer capacity shall be entered as revenue in the Allocation of Interconnection Transfer Capacity account.

3. At the end of each calendar year, the Transmission System Operator shall transfer the total sum that has been accumulated in Non-Compliance Charges Account A-G

during the calendar year in question and enter it as revenue into Special Account for DAS Financial Coverage A-B.

4. At the end of each calendar year, the Transmission System Operator shall transfer the total sum accumulated in Allocation of Interconnection Transfer Capacity account A-M during the calendar year in question and enter it as revenue in the Extraordinary Reserve Fund Account which shall be used to increase interconnection transfer capacity. Furthermore, the expenses allowed through the Extraordinary Reserve Fund Account shall be established by decision of the Minister of Development issued following the issue of RAE’s opinion.

Article 213 Guarantees

1. Each Participant must during the term of the Energy Transactions Contract furnish guarantees for the performance of their obligations arising from the Imbalances Settlement Procedure and the Uplift Accounts.

2. The obligation to provide guarantees shall be performed either by the submission of a letter of guarantee either through the deposit of a sum into a special account kept by the Transmission System Operator either in any other lawful way to which the Transmission System Operator consents.

3. Prior to the commencement of the implementation of this Code, a decision issued by RAE shall establish the Guarantee Sums Table per Participant category where for each category the sum shall be established taking account of the extent of the activity that is anticipated to correspond to such category and the financial risk factor which is established inversely to the extent of the Participant’s activity during the exercise of such activity. The information included in the Guarantee Sums Table may be readjusted before the calendar year to which they shall apply. Such information may not be reproduced unless two years have elapsed. The Guarantee Sums Table shall be published using all suitable means.

4. The sum corresponding to the guarantee owed shall be established prior to the entry of a Participant with the Participant Register by decision of RAE, which shall be based on the Guarantee Sums Table and on a reasonable estimate regarding the anticipated activity of the Participant based on the information in its relevant license. Before each calendar year, RAE may readjust the sum corresponding to the guarantee owed by a Participant based on the Guarantee Sums Table and on a reasonable estimate regarding the anticipated activity of the Participant for the new calendar year.

5. The letter of guarantee submitted by each Participant in performing the guarantee provision obligation in accordance with this Article must be irrevocable, it must have been issued by a renowned bank legally operating in a European Union Member State, it must have the form and contents established by the Transmission System

Operator in the Dispatch Manual and allow partial withdrawals on the part of the Transmission System Operator to pay the Participant's monetary debts arising from the Imbalances Settlement Procedure and the Uplift Account.

6. The above guarantee shall cover at least the period from the registration with the Participant Register until after the first three months of the first calendar year during which the Participant exercises its activity.

7. Such guarantee shall have a term of at least six months and expire on March 31st or September 30th respectively of each year, and shall be renewed for fifteen days prior to its expiry.

8. Should a Participant fail to provide the guarantee, the Transmission System Operator is entitled to terminate such Participant’s Energy Transactions Contract.

9. The Participant may replace the guarantee it has provided to the Transmission System Operator with a guarantee for the same amount and with a different form after having informed it to that respect at least fifteen days in advance and before it has received its approval. The new form guarantee shall be submitted at least fifteen days before the following March 31st, or September 30th respectively, and such guarantee must not enter into force earlier than April 1st, or October 1st respectively. Should a new form guarantee be submitted, all previous guarantees shall be unblocked at the time of entry into force of such new guarantee.

10. Further details with regard to the provision of guarantees are established in the DAS Manual.

SECTION VII CAPACITY ASSURANCE MECHANISM

CHAPTER 40

GENERAL PROVISIONS

Article 214 Purpose

The Capacity Assurance Mechanism aims at ensuring long-term adequate generation capacity availability.

Article 215 Reliability Year

The procedures laid down in the provisions of this Section refer to a Reliability Year which is defined as the period between October 1st of a calendar year and September 30th of the following calendar year.

Article 216 Transmission System Operator Rights and Obligations

In the context of the Capacity Assurance Mechanism, the Transmission System Operator shall:

Α) check the issue of Capacity Availability Tickets (CATs) by production license holders and the observance of the rest of their obligations in the context of the Capacity Assurance Mechanism;

Β) check the compliance of the Load Representatives with their Capacity Adequacy Obligation;

Γ) keep the CAT Register and the Capacity Availability Contract (CAC) Depository;

D) prepare the Capacity Adequacy Study in accordance with the provisions of Article 15 paragraph (4) of Law 2773/1999;

Ε) prepare reports with regard to the implementation of the Capacity Assurance Mechanism and its results;

F) ensure transparency within the Capacity Assurance Mechanism and provide relevant information to all interested parties;

G) hold calls for tenders for the conclusion of CACs for new Generation Units;

Η) hold auctions to facilitate the conclusion of CACs between production license holders and Load Representatives;

I) be entitled to recover through the secondary Capacity Assurance Mechanism Account of the Uplift Account the expenses it incurs due to entering into financial contracts in the context of calls for tenders for the conclusion of CACs for new Units;

J) issue the Capacity Assurance Mechanism Manual which is subject to approval by RAE;

K) take all other actions provided for in the provisions of this Code.

CHAPTER 41

UNFORCED CAPACITY


1. Unit Net Capacity NCAP shall be the capacity in MW which a Unit is capable of maintaining for any period, provided that such Unit operates under ISO conditions, there are no equipment related or technical constraints or constraints resulting from the institutional or financial framework governing the operation of the Unit and that the internal service, as well as any auxiliary load concerning the Unit have been taken into account.

2. Generation Unit Unforced Capacity UCAP shall be the capacity in MW which the Unit is capable of providing at the Connection Point with the System at any time throughout one (1) Reliability Year, having taken account of the forced outages of the Unit and provided that such Unit operates under ISO conditions, there are no equipment related or technical constraints or constraints resulting from the institutional or financial framework governing the operation of the Unit and that the internal service, as well as any auxiliary load concerning the Unit have been taken into account.

3. Forced outage shall mean inability to generate energy by a Generation Unit due to outage which is due exclusively to technical causes related to the operation or security

of the Unit installations. In that case a Total Non-Availability Declaration shall be submitted in the context of the DAS.

4. Forced partial outage shall mean inability by a Generation Unit to generate the energy corresponding to the Unit Net Capacity due to outage which is due exclusively to technical causes related to the operation or security of the Unit installations. In that case a Partial Non-Availability Declaration shall be submitted in the context of the DAS.

5. Especially in the case of an Auto-Producer Unit not falling in the scope of the provisions of Article 35 of Law 2773/1999, Generation Unit Net Capacity NCAP shall mean the capacity of the Unit (in MW) in accordance with the provisions of paragraph (1), which, in accordance with the declaration of the respective production license holder, the Unit may provide to the System in the following three (3) consecutive Reliability Years. In the case of an Auto-Producer who can guarantee an additional capacity part for the Unit for two (2) consecutive Reliability Years, Generation Unit Net Capacity NCAP shall be increased by an energy quantity equal to a maximum of 80% of this additional capacity part. In the case of an Auto-Producer who can guarantee an additional capacity part for the Unit for one (1) Reliability Year, Generation Unit Net Capacity NCAP shall be increased by an energy quantity equal to a maximum of 60% of this additional capacity part. The aforementioned declarations of Auto-Producers shall be submitted prior to the commencement of their reference period. RAE, by issuing a decision shall establish the additional capacity percentage of a Unit that will be taken into account in the calculation of Generation Unit Net Capacity NCAP during the Reliability Year, in the cases above where an Auto-Producer is able to guarantee a part of the capacity of its Unit for less than three Reliability Years.

Article 218 Unforced Capacity Table

1. The Transmission System Operator shall calculate and enter in the Unforced Capacity Table the numerical value of the Unforced Capacity of each Dispatchable Generation Unit and of each Generation Unit for which Capacity Availability Ticket Issuance Certification has been issued. The Unforced Capacity Table shall be published in the Transmission System Operator’s website. The Transmission System Operator shall keep a database where it shall enter the numerical values of all parameters and all relevant information used to calculate the numerical values of the Unforced Capacity Table as well as the relevant historical data. Production license holders shall be entitled to have access to the information in the database only with regard to the Generation Unit which corresponds to their respective license.

2. At least six (6) months prior to the beginning of each Reliability Year, the Transmission System Operator shall update the numerical values in the Unforced

Capacity Table. The numerical value of Unforced Capacity shall be calculated based on the information in the database which concern the operation of each Generation Unit, as such data have been recorded in prior Reliability Years.

3. If during the period between the updating of the Unforced Capacity Table and the commencement of a Reliability Year, the Unforced Capacity of a Generation Unit has changed due to an unplanned event, the Transmission System Operator shall amend the Unforced Capacity Table accordingly.

4. Within fifteen (15) days from the date of publicization of the Unforced Capacity Table, each production license holder may lodge objections with regard to its Units vis-à-vis the Transmission System Operator. The latter shall decide on such objections within fifteen (15) days. If the dispute remains, it shall be settled following the procedure established in CHAPTER 3.

Article 219 Unforced Capacity Calculation

1. All magnitudes involved in the calculation of Unforced Capacity shall concern one Generation Unit and one Reliability Year during which the Transmission System Operator shall record the relevant numerical values which derive from the real operation of the Unit.

2. The Unforced Capacity UCAP of each Generation Unit shall be calculated as follows for each Reliability Year:

NCAP)EFOR(1UCAP D ⋅−=

Where:

DEFOR the Demand Equivalent Forced Outage Rate for the Unit, which is expressed in percent. Its numerical value shall be calculated in accordance with one of the following three methods based on the information pertaining to the operation of the Unit, as such information is recorded by the Transmission System Operator;

NCAP Unit Net Capacity.

3. First calculation method for factor DEFOR :

Α) The numerical value of magnitudes used in implementing this method derive from the information recorded by the Transmission System Operator during the three (3) Reliability Years preceding the current Reliability Year. It is hereby clarified that forced outage or forced partial outage shall be defined in the sense of the Total or Partial Non-Availability Declarations submitted in the context of the DAS and these shall not include cases such as a Unit Major Outage or Scheduled Maintenance. The magnitudes used are defined as follows:

FOH the total number of Dispatch Periods for which the Unit has been in a state of forced outage;

EFOH the total number of Dispatch Periods during which the Unit has been in a state of forced outage or forced partial outage. Forced partial outage Dispatch Periods shall be reduced to forced outage Dispatch Periods based on the ratio of Unit maximum continuous capacity in each one of such Dispatch Periods to the Unit Net Capacity;

SH the total number of Dispatch Periods during which some level of energy generation by the Unit has been measured, regardless of the maximum continuous capacity of the Unit during the Dispatch Periods in question;

RSH the total number of Dispatch Periods during which the Unit has not been in a state of forced outage and during which no Dispatch Instruction of any form and for any reason whatsoever has been issued for the Unit;

AH the total number of Dispatch Periods during which the Unit has not been in a state of forced outage, including any Dispatch Periods during which the Unit has been operating as synchronous condenser, as well as any Dispatch Periods of pumping operation of the Unit;

ff Total factor f defined as:

D1+

T1+

r1

T1+

r1

f f =

where:

r mean time period of forced outage calculated using the following formula:

nr

FOHr =

Where nr the number of different Total Non-Availability Declarations that have been submitted for the Unit in the context of the DAS provided they have been accepted;

T mean time period between different calls to the Unit for operation, as such calls are recorded as Dispatch Instructions for Synchronization and which is calculated as follows:

nT

RSHT =

where nT is the number of Dispatch Instructions for Synchronization that have been issued for the Unit;

D mean operation time for the Unit defined as:

nDSHD =

where nD is the number of Dispatch Instructions for Synchronization that have been issued for the Unit and with which the Generation Unit has complied;

pf Partial factor f defined as:

AH SH f p =

Β) In the following cases conventional values shall be assigned to certain magnitudes that are involved in the calculations of paragraph (Α):

1f0RSH f == is

1f0SH f == is

0r10FOH == is

1f0AH p == is

C) The Demand Equivalent Forced Outage Rate for each Reliability Year shall be calculated using the following formula:

( ) FOH fSH EFOH-FOH f FOH f

EFORf

pf

D ⋅++⋅

=⋅

4. Second calculation method for factor DEFOR :

Α) the numerical value of magnitudes used in the implementation of this method, are established from the information recorded by the Transmission System Operator during the three (3) Reliability Years preceding the current Reliability Year. The magnitudes used are defined as follows:

yhMQ , total measured energy generated by the Unit in MWh/h during Dispatch Period h of Reliability Year y ;

yhL , total load demand for the System in MW during Dispatch Period h of Reliability Year y ;

yLmax, maximum annual peak load in MW during Reliability Year y as has been recorded in on Dispatch Period;

a parameter with a numerical value greater than or equal to the unit approved by RAE following a justified motion presented by the Transmission System

Operator and which shall be valid for three (3) Reliability Years following the Reliability Year in which such approval has been granted;

yHCAP the maximum capacity contributed by the Unit to cover the System peak loads, which is calculated for each Reliability Year y using the following formula:

⎟⎟

⎠

⎞

⎜⎜

⎝

⎛

⎟⎟⎠

⎞⎜⎜⎝

⎛×=

a

y

yhyhhy L

LMQmaxHCAP

max,

,,

Β) The Demand Equivalent Forced Outage Rate shall be calculated using the following formula:

)NCAPHCAP(1EFORD −=

where

HCAP the numerical average of the maximum capacity contributed by the Unit to cover the System peak loads as calculated in accordance with paragraph (Α) above for the three Reliability Years prior to the current Reliability Year.

5. Third calculation method for factor DEFOR :

Α) The numerical value of the following magnitudes used in the implementation of this method, are established from the information recorded by the Transmission System Operator during the three (3) Reliability Years preceding the current Reliability Year. Exceptionally, this method may also be applied using the information referring to one Reliability Year.

tDC the maximum continuous capacity of the Unit under ISO conditions expressed in MW during Dispatch Period t . In case of forced outage of the Unit for the said Dispatch Period, 0DCt = ;

tINST energy quantity expressed in MWh/h which the Unit is required to provide during Dispatch Period t and which corresponds to the total number of Dispatch Instructions that have been issued for the Unit during Dispatch Period t in question;

tMQ the total measured energy generated by the Unit during Dispatch Period t in MWh/h;

Β) For each Dispatch Period t during which a Dispatch Instruction to generate energy has been issued to the Unit, the differences tC∆ , tM∆ and tCAP∆ shall be calculated using the following formulas:

⎩⎨⎧

<−≥

=∆NCAPDCDCNCAP

NCAPDCC

tt

tt if ,

if ,0

⎩⎨⎧

<−≥

=∆tttt

ttt INSTMQMQINST

INSTMQM

if , if ,0

ttt MCCAP ∆+∆=∆

C) Demand Equivalent Forced Outage Rate shall be calculated using the following formula:

NCAPnt

CAP

EFOR

nt

tt

D

∑=

∆

=1

where

nt the number of Dispatch Periods t during which a Dispatch Instruction has been issued for the generation of energy by the Unit.

D) Where:

0 is == DEFOR0nt

6. The technical details regarding the calculation of the Demand Equivalent Forced Outage Rate shall be established in the Capacity Assurance Mechanism Manual.

7. Every three (3) years, and during the first implementation within two (2) years, RAE shall prepare a report evaluating the methods of calculation for the Demand Equivalent Forced Outage Rate based on the relevant technical data that have been collected during the previous Reliability Years. RAE may include in such report proposals for the modification of the Demand Equivalent Forced Outage Rate, and in that case the report shall be subjected to public consultation for RAE to express its opinion on a possible amendment to the Code.

Article 220 Rules regarding the implementation of calculation methods

1. During the first time implementation of this Code and until three (3) full Reliability Years have elapsed, the following rules shall be used when calculating the Unforced Capacity of Generation Units:

Α) The Demand Equivalent Forced Outage Rate of Dispatchable Thermal Units shall be calculated using the following formula:

( ) DcalcDD CEFORFNAEFORFNAEFOR ⋅−+⋅= 1,

where

calcDEFOR , the Demand Equivalent Forced Outage Rate as is calculated using the first method in Article 219 and based on the information collected by the Transmission System Operator since the beginning of the implementation of this Code. If for any reason whatsoever, the information required to calculate factor calcDEFOR , using the first method in Article 219 is not available, the third method advocated in the same Article shall be used.

FNA the time period calculated as a percentage of the three (3) Reliability Years preceding the Reliability Year for which DEFOR is calculated, during which period a Generation Unit has been registered with the Dispatchable Unit Register and the Transmission System Operator had available adequately recorded information on the calculation of the various magnitudes using the first or the third method in Article 219.

DCEFOR the Demand Equivalent Forced Outage Rate for the Generation Unit category where the Unit in question belongs. Factor DCEFOR shall be estimated based on the information in the data base kept by the Transmission System Operator or the respective production license holder. Where there are no historical data about the Generation Unit category in which the Unit in question belongs, the Transmission System Operator shall estimate the numerical value of DCEFOR taking account of the historical data and the statistics relating to the specific Generation Unit category from any reliable source.

Β) With regard to Hydro and Pumping Units, the second method in Article 219 shall be used. If three Reliability Years have not elapsed the statistics for the last three calendar years shall be used for Hydro and Pumping Units.

2. The provisions of paragraph (1) above shall also apply to Generation Units for which three (3) Reliability Years have not yet elapsed since their registration with the Dispatchable Unit Register.

3. Once three (3) Reliability Years have elapsed since the entry into force of this Code, the following rules shall be used to calculate the Demand Equivalent Forced Outage Rate :

Α) for Dispatchable Thermal Units, the first method advocated in Article 219 shall be used to calculate factor DEFOR ;

Β) for Hydro Units, including Pumping Units, the second method advocated in Article 219 shall be used to calculate factor DEFOR ;.

C) in special cases, in particular Supplementary System Energy Contracts, and subject to approval by RAE, just the third method in Article 219 may be used.

Article 221 Correspondence between Effective Unforced Capacity and

CATs

1. For each Reliability Year and throughout it, Effective Unforced Capacity shall be the Unforced Capacity calculated in accordance with the provisions of the Code (Article 219 and Article 220) based on the information available to the Transmission System Operator and have been recorded in or refer to previous Reliability Years.

2. Effective Unforced Capacity for t, as this applies for one Reliability Year and is recorded by the Transmission System Operator in the Unforced Capacity Table, shall be allocated pro rata and equally to all Capacity Availability Tickets (CATs) the Reference Period of which is the Reliability Year in question or part thereof where a CAT refers to the current Reliability Year.

3. If a Unit shall be interrupted for a certain period due to Major Outage or production or operation license revocation or due to any other similar reason, such period shall not be considered when calculating Effective Unforced Capacity for the Unit. In that case, the respective CAT shall be suspended in accordance with the provisions of the Code.

CHAPTER 42

OBLIGATION TO FURNISH ADEQUATE CAPACITY AVAILABILITY GUARANTEES

Article 222 Obligation to furnish adequate capacity availability guarantees

1. The provisions of this Code establish the way in which Load Representatives shall in carrying out their activities furnish sufficient long-term guarantees for ensuring adequate generation capacity availability for the System.

2. Load Representatives shall be required to furnish adequate capacity availability guarantees for each Dispatch Day for which they totally or partially represent a Meter in accordance with the Meters to Load Representative Correspondence Table in force on that Dispatch Day. Exceptionally, Load Representatives representing the load of Hydro Units in pumping operation, shall not be required to furnish adequate capacity availability guarantees for such load, if pumping is performed outside Hours with Increased Loss of Load Probability; this shall be checked by the Transmission System Operator.

3. Adequate capacity availability guarantees shall be lawfully furnished by a Load Representative exclusively through the deposit with the CAC Depository, during the Dispatch Day to which the Load Declarations it submits refer, of Capacity Availability Contracts (CACs), which in total correspond to Effective Unforced Capacity equal to the Load Representative's Capacity Adequacy Obligation for that Dispatch Day.

4. CACs shall be considered accepted adequate capacity availability guarantees, only when they are in the form and has the contents provided for in the terms of this Section.

Section 223 Capacity Adequacy Obligation

1. Hours with Increased Loss of Load Probability shall be the Dispatch Periods in one Reliability Year established in accordance with the Capacity Assurance Mechanism Manual and are reference hours for the calculation of the Capacity Adequacy Obligation of Load Representatives. Hours with Increased Loss of Load Probability shall be selected in such a way so that, taking account of historical load demand seasonality data, they also include to the extent possible cases with increased loss of load probability due to:

Α) very high load demand;

Β) high load demand as compared to System available capacity and in particular in cases of reduced installed capacity adequacy due to scheduled Unit maintenance, Transmission System congestion, or a combination of the above.

2. For each Dispatch Day of a Reliability Year, a Load Representative's Peak Load shall be measured in MW per hour and calculated as the maximum load demand measured during Hours with Increased Loss of Load Probability in the previous Reliability Year for all Meters totally or partially represented by a Load Representative on the Dispatch Day in question, in accordance with the Meters to Load Representative Correspondence Table in force on the Dispatch Day in question. The sum of the loads corresponding to the Meters represented by a Load Representative are taken on an hourly basis. If a Load Representative partially represents a Meter, in calculating the Peak Load account shall be taken of the part of the load of the Meter pro rata the representation share.

3. The Capacity Adequacy Obligation of each Load Representative for each Dispatch Day of a Reliability Year shall be calculated in MW per hour and be established for each Dispatch Day of a Reliability Year as the magnitude that results from multiplying the following factors: a) maximum demand of the System's total load in MW per hour that has been measured in the previous Reliability Year, increased by the percentage of the Installed Capacity Adequacy Factor that applies to the said

Reliability Year and the estimated capacity figure regarding load shedding that may have been performed during the same period; and b) the ratio resulting by dividing the Peak Load that is corresponded to the Load Representative for the specific Dispatch Day, based on the Meters represented by it on that day, into the sum of the respective Peak Loads of all Load Representatives.

4. Real Load for a Load Representative for a given Dispatch Day shall be the load served in MW per hour cumulatively for all Meters totally or partially represented by the Load Representative during the Dispatch Day in accordance with the Meters to Load Representative Correspondence Table.

5. The Installed Capacity Adequacy Factor shall be established by decision of the Minister of Development following a motion presented by the Transmission System Operator and the issue of RAE’s opinion.

Article 224 Performance of the Capacity Adequacy Obligation

1. Until 12:00 hours on each Dispatch Day, the Transmission System Operator shall check if Load Representatives provide the guarantees corresponding to their Capacity Adequacy Obligation for the Dispatch Day in question. Such check shall be performed based on the total Effective Unforced Capacity of the Units which in the sense of Capacity Availability Tickets (CATs) correspond to Capacity Availability Contracts (CACs) with a Reference Period including the Dispatch Day and which have been submitted with the CAC Depository in the name of the Load Representative provided that such Load Representative has submitted all such Capacity Availability Contracts at the latest by the deadline for the submission of Load Declarations to the DAS for the Dispatch Day in question.

2. If on a Dispatch Day a Load Representative fails to supply sufficient guarantees regarding the Capacity Adequacy Obligation it has for such Dispatch Day, the Transmission System Operator shall enter in the database the capacity figure for which no sufficient guarantees have been furnished and notify the relevant document to such Load Representative.

3. At the end of each month, the Transmission System Operator shall calculate for each Load Representative the maximum hourly load figure for which no sufficient guarantees have been submitted during the Dispatch Days of such month. Such capacity shall be called Load Representative Non-Compliance Capacity (NCC-LR) in MW. The Transmission System Operator shall in accordance with Article 73 charge such Load Representative with the Non-Compliance Charge (NCCh-LR) in €, which shall be calculated as follows:

NCCh_LR= NCUC × [Number of Days in the month ] × NCC)_LR×

(1+Α_ NCCh) × N

where

NCUC non-compliance unit charge in € per MW and Dispatch Day;

A_NCCh charge increase factor;

Ν the number of days up until the month in question in the current Reliability Years during which the same Load Representative has failed to furnish sufficient guarantees regarding its Capacity Adequacy Obligation.

4. The numerical values of unit charge NCUC and charge increase factor Α_NCCh shall be established for each Reliability Year by decision of the Transmission System Operator subject to RAE’s approval. Such decision shall be issued at least two months before the end of a Reliability Year, apply for the following Reliability Year and may not be amended during such Reliability Year.

CHAPTER 43

CAPACITY AVAILABILITY TICKETS

Article 225 Issue

1. Production license holders and for Units that are registered with the Dispatchable Unit Register must issue and deposit with the CAT Register Capacity Availability Tickets for the overall Net Capacity of each Generation Unit and for the current Reliability Year and the following four Reliability Years at least, or until the expiry of the production license for the Unit, if this occurs within the above-mentioned 5-year period. The overall capacity of CATs with the same Reference Period concerning the same Generation Unit, cannot exceed the Unit Net Capacity.

2. No CATs may be issued for Cold Reserve Units, Contracted Units, Generation Units under Article 35 of Law 2773/99 (Government Gazette Issue No. Α 286), as is in force, and Generation Units connected to the Distribution Network.

3. Production license holders for new Generation Units to be connected to the System may issue CATs if they hold a CAT Issuance Certificate, which is granted by RAE if a production license holder sufficiently commits to the time of commencement of the commercial operation of the new Generation Unit. In order for a CAT Issuance Certificate to be issued, a production license holder shall submit an application accompanied by the following supporting documents:

Α) declaration with regard to the date of commencement of the commercial operation of the new Unit;

Β) technical characteristics of the new Unit based on which the Unforced Capacity of the Unit is calculated;

C) installation license for the new Unit;

D) signed Engineering-Procurement-Construction (EPC) contract or preliminary agreement;

Ε) signed funding contract or preliminary agreement, if applicable;

F) Approved Terms or Offer for Connection with the System;

G) Approved Terms or Offer for Connection with the fuel transfer network where fuel is supplied through a network.

4. Auto-Producers may issue CATs for the Net Capacity of their Units if they hold an Auto-Producer CAT Issuance Certificate, which is granted by RAE upon request of any interested party. The Auto-Producer CAT Issuance Certificate certifies the energy self-consumption percentage of the Auto-Producer. The maximum number of CATs that an Auto-Producer may issue cannot correspond to a capacity over 50% of the total capacity of such Auto-Producer's Unit.

5. CAT Issuance Certificates shall be revoked by decision of RAE when in accordance with the production license monitoring system kept by RAE, the new Unit cannot be completed, or the conditions for the granting of such certificate no longer apply.

Article 226 Form and Contents

1. CATs implies the promise to maintain a certain level of technical availability of the Generation Unit at a future time.

2. CATs have a written form, refer to part of the CAT Unit Net Capacity and specifically to one (1) MW capacity.

3. CATs include:

Α) the Generation Unit they refer to (CAT Unit). CATs also list the Generation Unit Code Number in accordance with the Dispatchable Unit Register or the CAT Issuance Certificate Number, as the case may be;

Β) the Reference Period as established in a Reliability Year, unless they concern the current Reliability Year at the time of their issue, whereupon they shall cover the time period remaining until the end of such Year. The Reference Period shall establish the specific Reliability Year for which a production license holder promises to maintain the specific level of Unit technical availability;

C) the terms and conditions of the suggested CAC, as these are established in accordance with the provisions of this Code (Article 229), which include the numerical value of Referenced Unforced Capacity (RUCAP) for the CAT-Unit.

4. By submitting a CAT with the Register, a production license holder expressly and unreservedly accepts its terms, including the terms and conditions of the offered CAC. Such production license holder further acknowledges his obligation to keep in an equitable manner the promises included in all CATs, which refer to the same Generation Unit and have the same Reference Period.

Article 227 Amendments - removal - suspension

1. The Transmission System Operator shall see to the removal from the Register of all CATs whose Reference Period has elapsed.

2. In all cases of amendment regarding the Production License holder, CATs shall continue in force and their issuer shall be replaced by the new production license holder.

3. In case of a CAT that corresponds to a new Unit, should there be a delay in the commencement of the commercial operation of such Unit, the CAT shall be amended in terms of the commencement of the Reference Period.

4. Where a CAT Issuance Certificate has been revoked, the respective CATs shall be removed from the Register.

5. Where there has been a change to the Unit Net Capacity quantity as a result of amendment to a Production License, the number of CATs that correspond to the Unit and have the same Reference Period shall be adjusted accordingly. Where the Unit Net Capacity has decreased, priority shall be given for removal from the Register to those CATs for which no CAC has been entered into, and should that not suffice, the removal of the suitable number of CATs from the Register shall be allocated on a pro rata basis to Load Representatives that have entered into the respective CACs.

6. Where Long-term Non-Availability Declarations have been submitted with regard to which a finding is issued establishing the definite nature of inability of a Unit to operate, the CATs that have been issued for such Unit shall be removed.

7. Where Long-term Non-Availability Declarations have been submitted with regard to which a finding is issued establishing the Temporary nature of inability of a Unit to operate, the CATs that have been issued for such Unit shall be suspended until restoration of the Unit operation.

8. Where an Intention to Suspend Normal Operation Declaration has been submitted, the CATs for the Unit that have a Reference Period after the Reliability Year including

the desired date for the suspension of the normal operation of the Unit shall be removed from the Register.

CHAPTER 44

CAPACITY AVAILABILITY CONTRACT

Article 228 Form

1. The CATs that have been submitted to the Register constitute a proposal for the conclusion of a Capacity Availability Contract (CAC) with Load Representatives. CACs shall be entered into by the Load Representative filling in the data in the respective CATs, unreservedly signing the CAT and the making of the relevant entry in the CAC Depository. This form shall constitute full proof with regard to the conclusion of a CAC.

2. In order to facilitate the conclusion of CACs, the Transmission System Operator may hold auctions in accordance with the provisions of the Code (Article 236 to Article 243)

3. The Transmission System Operator may enter into CACs with production license holders following a tender procedure in accordance with the provisions of CHAPTER 47 of this Code, aiming at further transferring them to Load Representatives. Being a party to such CACs, the Transmission System Operator shall act as a quasi Load Representative.

Article 229 Content

1. CACs shall have the content and include the terms and conditions established in the provisions of this Article. The parties may not derogate from the terms and conditions or add any other financial or other agreement to the CAC text. Any additional terms and conditions shall not affect the validity, construal, or implementation of the CAC and shall be deemed as non-registered.

2. CAC terms and conditions are as follows:

“Made in …. ……….. (location), this ……….. day ………….…, by and between the holder of production license No.. ………. for Generation Unit with Net Capacity ……. MW, with Dispatchable Unit Register Code …….. for which CAT Issuance Certificate No. ……………… has been issued, with the corporate name

……………….. and its seat in ………………….., legally represented in accordance with ………………… ………………, hereinafter referred to as “Producer”, and Load Representative with the corporate name …………………….., and its seat in ………………….., legally represented in accordance with ……………………………, hereinafter referred to as “LOAD REPRESENTATIVE”, who is the holder of energy supply license No. …………. or is an Eligible Customer in accordance with applicable provisions

WITNESSETH

1. Definitions. The terms used herein shall have the meaning assigned to them in accordance with the provisions of Law 2773/1999 as is in force, and Grid Control and Power Exchange Code For Electricity (hereinafter referred to as Code).

2. Object of the Contract

2.1 Generation Unit. This Contract concerns Generation Unit (hereinafter referred to as Generation Unit) with Dispatchable Unit Register Code …….. for which CAT Issuance Certificate No. ………………….. has been issued, and which has a Total Net Capacity of ………… ΜW (hereinafter referred to as Net Capacity). This Contract concerns a Net Capacity of 1 ΜW.

2.2 Reference CAT. This contract corresponds to CAT No. ………………, which is in force, as is demonstrated from the relevant entry made in the Transmission System Operator’s Register.

2.3 Referenced Unforced Capacity. During the Reference Period hereof, the Producer undertakes vis-à-vis the Load Representative to maintain the Unit technically available for an Unforced Capacity of ……… MW, hereinafter referred to as Referenced Unforced Capacity (RUCAP). Effective Unforced Capacity shall be established by the Transmission System Operator in accordance with the Code.

2.4 Compliance with Codes. The Producer is required to comply with the provisions of the Code by a) submitting particularly Energy Offers for the entire available capacity of the Unit, Total or Partial Non-Availability Declarations, Major Outage Declarations, production or supply license Suspension Declarations, Intention to Suspend Normal Operation Declarations, or removal or cold reserve declarations, as the case may be; and b) cooperating with the Transmission System Operator with regard to scheduling the Unit's regular maintenance. The Producer shall further acknowledge that it is required to keep in an equitable manner the promises included in all CATs, which refer to the same Generation Unit and have the same Reference Period, particularly with regard to capacity availability and the transactions that concern the relevant real and contractual magnitudes.

3. Entry into force and Expiry - Reference Period

3.1 Entry into force and expiry. This Contract shall enter into force as of the date of its making by the Load Representative and the making of the

relevant entry in the CAC Depository kept by the Transmission System Operator. This Contract shall normally expire after the Reference Period has elapsed.

3.2 Reference Period. The Reference Period for this Contract shall be established for Reliability Year ……………… and shall coincide with the Reference Period of the respective CAT.

4. Transfer. The Load Representative may unreservedly transfer by virtue of a written agreement to third-party Load Representatives that unreservedly sign the CAC all the rights and obligations arising from the CAC (hereinafter referred to as Transfer). The Transfer shall be completed with the making of the relevant entry in the CAC Depository kept by the Transmission System Operator. Such Transfer shall be accompanied by a written declaration by virtue of which the two parties have agreed on the provision of a mutually acceptable fee in consideration of the transfer of the rights and obligations arising from the CAC and that such agreement shall not affect in any way whatsoever the validity of the CAC, as well as the performance of the obligations and the exercise of the rights arising from the CAC. The transfer does not require the Producer’s consent and no announcement is made to the Producer. The Producer may not lodge any objections before the new Load Representative nor to terminate the contract for any reason not substantiated in the CAC and in particular for any reason arising from any financial or other agreements that it has signed with the original Load Representative.

5. Unforced Capacity Modification

5.1 Inability of the Unit to operate. In case of a Major Outage of the Unit in accordance with the Code or in case of revocation of the production or operating license or definite interruption of the operation of the Unit for any reason or of dismantlement of the Unit or placement in cold reserve, as well as in any other case where the Unit is unable to operate which is not a small scale unforeseen outage for which Partial or Total Non-Availability Declarations are submitted to the DAS, the Producer must notify to the Load Representative all documents it submits to that respect to the Transmission System Operator in accordance with the Code. Where as a result of such situations, and in accordance with the relevant finding of the Transmission System Operator, which is issued in accordance with the provisions of the Code, the respective CAT is suspended, the performance of the obligations or exercise of the rights arising from this contract shall be suspended for the period of CAT suspension. Where as a result of the finding of the Transmission System Operator a CAT is removed from the Register, namely if the finding classifies the inability of the Unit to operate as definite, this contract shall expire early.

5.2 Referenced Unforced Capacity reduction by Producer initiative. At any time prior to the end of the Reference Period hereof, the Producer may send to the Load Representative an irrevocable, written, and justified proposal for

the reduction of the Referenced Unforced Capacity in MW (hereinafter referred to as Capacity Reduction Proposal) which shall apply for the Reference Period or the remaining period thereof. The sending of a Capacity Reduction Proposal shall be mandatory where the Producer expects that technical problems will lead to substantial and systematic deviation of the Effective Unforced Capacity from the Referenced Unforced Capacity. The Load Representative is entitled within fifteen (15) days from the day it has received the Capacity Reduction Proposal to lodge an objection against such Capacity Reduction Proposal and to send an Investigation Notice which it shall notify to the Transmission System Operator. In such case the provisions of paragraph 5.3 hereof shall apply. Should the Transmission System Operator accept the Capacity Reduction Proposal, or should the Load Representative fail to lodge an objection against such proposal in a timely manner, the Transmission System Operator shall modify accordingly the Referenced Unforced Capacity and enter it in the CAC Depository in accordance with this Code.

5.3 Referenced Unforced Capacity reduction by Load Representative initiative. When the Load Representative finds a systematic large deviation between the Referenced Unforced Capacity and the Effective Unforced Capacity as it results from the Transmission System Operator's information, it may send to the Producer an investigation notice (hereinafter referred to as “Investigation Notice”) about the real situation of technical operation of the Unit and the possibility of recovery from an eventual outage or other technical reasons, aiming at the evaluation of the possibility to attain Referenced Unforced Capacity which reasonably approaches Effective Unforced Capacity. The investigation shall be carried out by the Transmission System Operator as is provided for in the provisions of the Code on the check of Non-Availability Declarations and shall be completed with the issue of the relevant finding. The Producer must allow on site checks and provide all necessary information for the unobstructed performance of the investigation. The cost of such investigation shall be borne by the Producer if the existence of a significant deviation is verified or the Load Representative who has requested such investigation in all other cases. When the investigation results that it is possible to attain a Referenced Unforced Capacity which approaches the Effective Unforced Capacity, the Producer is required within a reasonable time to take all lawful actions to that end. Once it has carried out all necessary technical works, it shall send an Outage Recovery Notice to the Transmission System Operator which it shall notify to the Load Representative. Should the Transmission System Operator accept such notice, the Referenced Unforced Capacity shall remain as stands. Should the deadline for the submission of an Outage Recovery Notice elapse without any action taken or should the Transmission System Operator not accept it or if the Transmission System Operator’s finding states technical inability to increase the Unit's unforced capacity, the Transmission System Operator shall make a Capacity Reduction Proposal which shall be notified to both parties. Within fifteen

(15) days from the receipt of such proposal by the Producer, the latter may lodge objections against it. In case of definite approval of the Capacity Reduction Proposal by the Transmission System Operator, or where the Producer has failed to lodge an objection against such proposal in a timely manner, the Transmission System Operator shall modify accordingly the Referenced Unforced Capacity and enter it in the CAC Depository in accordance with this Code.

5.4 Referenced Unforced Capacity Restoration. At any time prior to the end of the Reference Period hereof, and provided that the Referenced Unforced Capacity has decreased in accordance with paragraphs 5.2 or 5.3, the Producer may, provided it has performed all necessary technical works, send an Outage Recovery Notice to the Transmission System Operator which shall be notified to the Load Representative and by which it proposes the restored quantity of the Referenced Unforced Capacity. Within fifteen (15) days, the Load Representative shall be entitled to send an Investigation Notice, in which case the provisions of paragraph 5.3 shall apply. Should the finding of the investigation confirm the proposed capacity quantity or should the Load Representative accept such proposed capacity quantity, the Transmission System Operator shall modify accordingly the Referenced Unforced Capacity and enter it in the CAC Depository in accordance with this Code.

6. Common Declarations.

6.1 Both parties agree that any agreement not included in this CAC on amendments to the terms and conditions of the CAC or the limitation of the obligations and rights arising from the CAC shall not generate any lawful results in the context of the CAC.

6.2 The parties hereto may enter into a financial agreement referring to the performance of the obligations arising from this CAC which under no circumstances shall affect the validity, construal, or implementation of the CAC. The two parties hereto agree that a non paid consideration objection substantiated based on the financial agreement entered into by and between the parties may not be lodged lawfully regarding failure to perform obligations arising from the CAC and that failure to perform obligations arising from the financial agreement or the expiry of the financial agreement shall not substantiate a right for any one of the parties to terminate the CAC.

6.3 The two parties hereto expressly and unreservedly state that they have agreed to provide a commonly accepted consideration for the keeping the availability promise and all promises deriving from this CAC and hereby agree that this agreement does not affect in any manner the validity of the CAC, nor the performance of the obligations or the exercise of the rights arising from this CAC.

7. Producer Replacement. The two parties hereto agree that the Producer may be replaced by another Producer in this CAC, only if such replacement

has been performed lawfully for the Reference CAT and the relevant entry has been made to the Register.

8. Provision of Information.

The Producer guarantees that it shall provide to the Load Representative upon a relevant written request, information about Total or Partial Non-Availability Declarations and Major Outage Declarations, as well as all other information about the performance of its obligations arising from this contract, unless such information is protected as confidential by a legal provision or agreement.

9. Legislation.

During the Reference Period hereof, the Parties are required to act in accordance with Greek Laws and in particular with the provisions of Law 2773/1999 as is in force and the Code.

10. Force Majeure.

10.1 “Force Majeure Event” shall be any event or situation that is out of the control or influence of the Parties hereto and which could have not been foreseen or prevented even had the Parties hereto exercised extreme diligence. In particular, Force Majeure Events, shall be strikes or any other employee mobilization or dispute which in any case occurs at a national level and has a duration of over five (5) consecutive days and substantially adversely affects the performance of the obligations of any one of the Parties hereto, acts of war (declared or not), invasion, armed conflict or act of foreign enemies, which in any case directly concern or affect Greece, revolutions, popular riots, munity, social turmoil, sabotage or terrorist acts which in any case occur in Greece and directly affect the performance of the obligations of any one of the Parties hereto, nuclear explosion, radioactive or chemical pollution, which directly affect the performance of the obligations of any one of the Parties hereto, earthquake or other form of seismic activity the consequences of which are more serious than those which in accordance with the Unit's specifications do not affect its operation.

10.2 Should a Force Majeure Event occur, the Party that is unable to perform its obligations, shall immediately and in writing inform the other party hereto with regard to such Force Majeure Event and its anticipated duration, indicating the obligations it is unable to perform due to such cause. Due to a Force Majeure Event, the Party affected shall regularly inform the other Party about any developments and inform it in writing when the Force Majeure Event has ceased to exist or when its consequences have ceased to affect it. The Parties hereto shall make all reasonable efforts to minimize the adverse consequences (including delays in the performance of the obligations hereunder) of the Force Majeure Event.

11. Early Expiry. This Contract shall expire early ipso facto if the Reference CAT has been removed from the Register. In any case, the Load

Representative may voluntarily waive its rights arising from this Contract, in which case such contract shall expire early. In case of early expiry of this Contract without being preceded by removal of the Reference CAT, the CAC shall be removed from the Depository, which the Reference CAT shall continue in force. The Load Representative may terminate the contract should the Producer fail to perform its obligations, and in particular those under paragraph 5 hereof.

12. Settlement of Disputes. Any disputes arising between the Parties hereto relating to the validity, binding nature, construal or implementation hereof, shall be definitely settled in accordance with the provisions of this Article.

12.1 Amicable Settlement. In case of dispute, either Party may notify to the other Party an invitation for amicable settlement. Within three (3) days from the reception of the invitation, the Parties hereto are required to appoint and mutually notify their Representatives for the settlement. Such Representatives are required to negotiate in good faith and in accordance with good trade practices the settlement of the dispute. The results of such negotiation shall be included in a report, which shall be signed by the representatives and be binding upon the Parties hereto. The amicable settlement procedure shall be completed within thirty (30) days from the dispatch of the amicable settlement invitation.

12.2 Expert report and arbitration. It is hereby expressly agreed that should a dispute not be settled during the amicable settlement procedure, such dispute shall be settled in accordance with Article 10 of the Grid Control and Power Exchange Code For Electricity.

12.3 Performance of Obligations. During Amicable Settlement, Expert Report and Arbitration, performed under this Contract, the Parties hereto shall continue performing their obligations under this Contract.

13. Notices. Proxy.

(a) Dispatch. All notices regarding or related to this Contract shall be made

(1) For the Producer:

- by registered mail at ……………………… or

- by fax at ……………………… or

- e-mail at ……… ………………

in any case to the care of ………………………

(2) For the Load Representative:

- by registered mail at ……………………… or

- by fax at ……………………… or

- e-mail at ……… ………………

in any case to the care of ………………………

(b) Receipt. Time. The recipient of any such notice shall be considered to have received the document notified to them on the date on which the registered mail has been served, or at the time indicated on the fax transmission receipt, or the time in the e-mail delivery receipt.

(c) Proxy. Mr. ………………… ……………………………. shall be appointed proxy for the Producer, and Mr. ………… ………………………………… for the Load Representative.

14. Partial Nullity. Any provision of this Contract that is or shall become illegal, null, or non enforceable shall be considered that shall be deleted to the extent of such illegality, nullity or non enforceability, and the remaining provisions (and such provision to the extent that it remains in force) shall remain in full force.

15. Applicable Law. This Contract shall be governed by and construed in accordance with Greek Law.

16. Omission of or delay in exercising a right. It is hereby acknowledged by the Parties hereto that omission of or delay in exercising any right shall not be construed as waiver of such right and shall not weaken such right if it has not been exercised.

17. Complete agreement. This Contract shall be the complete agreement between the Parties hereto and shall have precedence over all other written or oral agreements.

IN WITNESS THEREOF, the Parties hereto have signed this Contract in two (2) original copies.”

Article 230 Related agreements

1. Any agreement not included in the CAC on the amendment to the terms and conditions of the CAC or the limitation of the obligations and rights arising from it, shall generate no legal results in the context of this CAC.

2. The parties hereto may enter into a contract for differences or any other financial agreement regarding the performance of the obligations arising from this CAC, which under no circumstances can affect the validity, construal, or implementation of the CAC. A non paid consideration objection substantiated based on the financial agreement entered into by and between the parties may not be lodged lawfully regarding failure to perform obligations arising from the CAC. Failure to perform obligations arising from the financial agreement or the expiry of the financial agreement shall not substantiate a right for any one of the parties to terminate the CAC.

3. Through the CAC the two parties hereto expressly and unreservedly state that they have agreed to provide a commonly accepted fee in consideration of keeping the availability promise and all promises deriving from this CAC and hereby agree that this agreement does not affect in any manner the validity of the CAC, nor the performance of the obligations or the exercise of the rights arising from this CAC.

4. The rights and obligations arising from financial agreements entered into in accordance with the provisions of this Article, shall not be affected by any CAT transfer in accordance with Article 231.

Article 231 Transfer

1. The Load Representative may transfer to another Load Representative all the rights and obligations arising from a CAC while observing the provisions of the Code. The Transfer shall be effected through the unreserved signing of the CAC by the new Load Representative, and the latter shall also see to the making of the relevant entry in the CAC Depository without it being required to notify the Producer. The Transmission System Operator shall make the relevant entry provided that the new Load Representative has submitted a written agreement stating that the old Load Representative unreservedly transfers to it all the rights and obligations arising from the CAC, that both Parties expressly and unreservedly state that they have agreed on the provision of a mutually acceptable fee in consideration of the transfer of the rights and obligations arising from the CAC and that such agreement shall not affect in any way whatsoever the validity of the CAC, as well as the fulfilment of the obligations and the exercise of the rights arising from the CAC.

2. The transfer does not require the Producer’s consent. The Producer may not lodge any objections before the new Load Representative for any reason not substantiated in the CAC and in particular for any reason arising from any financial or other agreements that it has signed with the old Load Representative. The Producer may not terminate the CAC on the sole grounds of the transfer or because the old Load Representative has failed to pay to the Producer any debts substantiated with a reference to financial agreements.

CHAPTER 45

REGISTER AND DEPOSITORY

Article 232 Register and Depository Keeping

1. The Transmission System Operator shall keep a record, where, in accordance with the provisions of the Capacity Assurance Mechanism Manual, and following a check, it shall enter the CAT information, and a Depository where, in accordance with the provisions of the Capacity Assurance Mechanism Manual, it shall enter the CAC information.

2. Entries to the Register and the Depository shall be made upon submission of an application by DAS Participants as follows:

Α) application for CAT registration with the Register submitted by a production license holder corresponding to a CAT Unit;

Β) CAT suspension application, submitted by a production license holder corresponding to a CAT Unit;

C) CAT modification application, submitted by a production license holder corresponding to a CAT Unit

D) application for CAT removal from the Register, submitted by a production license holder corresponding to a CAT Unit;

Ε) application for CAC registration with the Depository, submitted by each Load Representative which is a party to the CAC;

F) application for CAC removal from the Depository, submitted by each Load Representative which is a party to the CAC.

3. The Transmission System Operator may remove or suspend a CAT without a previous request, if conditions for the submission of Long-term Non-Availability Declaration or Intention to Suspend Normal Operation Declaration apply for the Unit, and such declarations have not been lawfully submitted by the production license holder.

4. The Register and Depository shall be published in the Transmission System Operator's website.

Article 233 Registration Data

1. The following information shall be registered with the Register for each CAT:

Α) CAT code uniquely identifying each CAT;

Β) Code of the Unit corresponding to the CAT;

C) Production License Protocol Number for the Unit;

D) Unit Net Capacity in MW, in accordance with the Dispatchable Unit Register;

Ε) Referenced Unforced Capacity (RUCAP), which must be equal to or less than 1 ΜW;

F) CAT Reference Period for the specific Reliability Year;

G) CAT State and in particular CAT suspension or removal;

Η) CAT modification history;

I) historical data with regard to Unit availability, including the reduction of Producer Availability due to force majeure reasons, or Major Outage, which reduces such Unit’s technical availability.

2. The following information shall be registered with the Depository for each CAC:

Α) CAC Code uniquely identifying each CAC;

Β) CAC-Reference Code to which it corresponds;

C) Code of the Load Representative, in accordance with the Participant Register;

D) CAC transfer history.

Article 234 CAT Register Registration Procedure

1. The application for the registration of a CAT with the Register shall be approved by the Transmission System Operator if the following conditions apply:

Α) the production license holder shall be entitled to issue a CAT for the specific Unit;

Β) the total number of CATs concerning the same Unit for the same Reference Period shall not exceed in capacity the Unit's Net Capacity in accordance with the Dispatchable Unit Register;

C) The CAT has been issued in accordance with the form and contents established in Article 226.

2. CAT suspension applications shall be approved by the Transmission System Operator if the conditions provided for in Article 227 are met. By the approval decision, the Transmission System Operator shall approve and publish the anticipated date for CAT suspension removal.

3. CAT modification applications shall be approved by the Transmission System Operator if the conditions provided for in Article 227 are met.

4. CAT removal applications shall be approved by the Transmission System Operator if the conditions provided for in Article 227 are met.

5. Within three (3) days from the submission of an application to register the CAT with the Register, the Transmission System Operator shall decide on such application.

6. Where an application has been rejected, or in case of an ipso facto CAT suspension or removal from the Register, the Transmission System Operator shall inform the CAT issuer in writing. DAS Participants may within five (5) days lodge objections against the Transmission System Operator's decisions.

7. The Transmission System Operator shall decide on such objections within five (5) days from their submission. Where such period has elapsed and no action has been taken, it shall be considered that the objections in question have been rejected. Any disputes that may arise between the parties shall be settled following the procedure established in Article 10.

Article 235 Obligation to inform the Transmission System Operator

Production license holders are required to inform the Transmission System Operator about all events that lead to modification of or changes to the CAT information at the latest within two (2) days from the occurrence of such events.

CHAPTER 46

CAPACITY AVAILABILITY TICKET AUCTIONS

Article 236 Scope

The Transmission System Operator may perform Capacity Availability Ticket auctions aiming at facilitating the conclusion of CACs between CAT issuing production license holders and Load Representatives.

Article 237 Object

1. Capacity Availability Tickets registered with the Register shall be subjected to auction following a relevant request filed by their issuers and provided that:

Α) such auctions shall be held at an earlier time with regard to CAT Reference Periods;

Β) no CACs have been entered into with regard to such CATs.

2. All CATs corresponding to CACs entered into by and between the Transmission System Operator and production license holders in accordance with CHAPTER 47 shall be subject to auctions.

3. Load Representatives are entitled to participate in auctions, if they have previously declared their wish to participate.

4. During auctions, Load Representatives are called upon to make bids for the auctioned CAT, aiming at the conclusion of a CAC, and if found to be the highest bidder they undertake to pay to the issuer of such CAT the price that has resulted from the auction, and accept the terms of the financial contract that may accompany a CAT, and which are notified to them prior to the commencement of the auction. Provided that the price has been paid and the terms of the financial contract accompanying the CAT have been accepted, the CAT issuer is not entitled to refuse to enter into a CAC with the Load Representative.

Article 238 Auction Preparation

1. The Transmission System Operator may hold an auction once during a Reliability Year and within the first four months of such year. Auctions may be held once more during the same Reliability Year, subject to approval by RAE.

2. At least two (2) months prior to the desirable date for the auction, the Transmission System Operator shall publish in its website the intention to hold an auction. The same announcement shall call upon CAT issuers to submit applications with regard to the CATs they wish to be subjected to the auction, within the exclusive deadline of twenty (20) days.

3. In their applications, CAT issuers shall submit the following information for each CAT:

Α) the CAT code number and Reference Period;

Β) the CAT's Referenced Unforced Capacity (RUCAP) which the production license holder suggests for inclusion in the CAC;

C) financial terms and conditions which alternatively may have the following characteristics:

(1) Minimum Price in €, which shall be the minimum sum the CAT issuer wishes to receive in order to enter into a CAC for the CAT. In that case the CAT being auctioned shall be called “CAT with Price”;

(2) a draft financial contract in the form of a Contract for Differences or in any other form, the terms of which the production license holder accepts that they be divulged to candidate Load Representatives, and Minimum Price in €, which shall be the minimum sum the CAT issuer wishes to receive in order to enter into a CAC for the CAT, provided that the respective Load Representative has accepted the terms of the draft financial contract. In that case the CAT being auctioned shall be called “CAT with Financial Contract”.

4. Within ten (10) days from the deadline for the submission of applications, the Transmission System Operator shall verify how many of the CATs submitted for auctioning meet the conditions in Article 237 and Article 238 above, and it shall decide whether it shall hold the auction, based on whether the number of CATs suitable for auction is sufficient so as to justify the holding of an auction. The Transmission System Operator’s decision with regard to the holding of an auction, shall be notified in writing to CAT issuers that have submitted applications for participation in the auction.

5. The Transmission System Operator's decision with regard to the holding or not of the auction shall be subject to approval by RAE.

6. The Transmission System Operator shall announce in its website the date, the object, the terms and the time schedule of the auction at least (20) days in advance of the holding of such auction.

7. At the latest five (5) days prior to the holding of the auction, those Load Representatives that which to participate shall submit to the Transmission System Operator an application for participation accompanied by the following supporting documents:

Α) in case of Suppliers, a copy of the Supply License;

Β) in case of Self-Supplying Customers, a certificate issued by RAE certifying that the Customer to which such certificate is issued has the right to supplier selection.

8. Where none of the above supporting documents have been submitted or where these have been submitted but found to be insufficient, the Transmission System Operator shall reject the application of the relevant Load Representative. The Transmission System Operator shall inform applicants in writing only where their applications have been rejected.

Article 239 Auction Procedure

1. On the day of the auction, the Transmission System Operator shall hold separate auctions for CATs with Price and CATs with Financial Contract. In the case of CATs with Price the procedure laid down in Article 240 shall be followed.

2. In the case of CATs with Financial Contract, the procedure laid down in Article 241 is followed.

3. Auctions for each CAT or CAT group shall be held successively and at random order.

Article 240 Auctions for CATs with Price

1. Auctions in accordance with the provisions of this Article shall be held only for CATs with Price.

2. Each separate auction shall include at the same time all auctioned CATs with Price which have the same Reference Period, and for which the same value for the Referenced Unforced Capacity is suggested. In case of CATs with different Reference Periods or different Referenced Unforced Capacity values, separate auctions shall be held successively for groups of CATs with the same Reference Period and the same Referenced Unforced Capacity quantity. A CAT group shall be considered to have the same Referenced Unforced Capacity quantity when there are not two CATs in such group for which the numerical values for Referenced Unforced Capacity differ by more than 3%.

3. Auctions shall be held by a Committee appointed by the Transmission System Operator.

4. Load Representatives that wish to participate in the auction shall appear at the place and time established by the Transmission System Operator and submit their bids separately for each auction.

5. The bids of Load Representatives shall be submitted in a sealed envelope in accordance with the form established by the Transmission System Operator. Bids shall be in the form of stepwise offered price – capacity pairs expressed in €/MW and MW respectively. Such stepwise functions must be non-increasing with regard to the offered price. The capacity figure at each step of such stepwise functions must be an integer with a capacity figure per step equal to one (1) MW. Load Representatives may not establish in their bids a specific CAT for which they whish to enter into a CAC. Bids shall be binding.

6. Along with the submission of bids, Load Representatives shall submit to the Committee a Participation Letter of Guarantee for a sum equal to that of their bid.

7. Each separate auction shall be completed as follows:

Α) once the bids submitted by Load Representatives have been opened, the Committee shall assign each step of each bid which shall correspond to one (1) ΜW, to an offered price in €/ΜW and record the capacity – price pair (hereinafter referred to as "Demand Pairs”). Such Demand Pairs shall be sorted in descending order in terms of the price offered. Where there are two or more Demand Pairs with the same price, the Committee shall classify such Demand Pairs at random;

Β) likewise, the Committee shall assign the CATs to be auctioned, each one of which corresponds to 1 ΜW, to their respective Minimum Price in €/ΜW and record the capacity - price pair (hereinafter referred to as “Supply Pairs”). Such Supply Pairs shall be sorted in ascending order in terms of the Minimum Price. Where there are two or more Supply Pairs with the same Minimum Price, the Committee shall classify such Supply Pairs at random;

C) those Demand Pairs with a price lower than the Minimum Price of the Supply Offer having been classified in ascending order shall be disqualified from further auction stages. If this results in the disqualification of all Demand Pairs, the Committee shall declare the auction barren. The Transmission System Operator may repeat the auction in accordance with Article 238;

D) the remaining Demand Pairs shall be assigned one by one to the Supply Pairs. The procedure shall start by assigning the first Demand Pair in descending order classification to the first Supply Pair in ascending order classification, followed by the next Demand Pair which shall be assigned to the next Supply Pair and so on and so forth. This procedure continues until it is no more possible to assign pairs either due to lack in Supply Pairs or Demand Pairs, or until the Minimum Price of the Supply Pair to be assigned is higher than the price of the Demand Pair to be assigned;

Ε) the Auction Marginal Price (AMP) shall be established to be equal to the price of the last Demand Pair in descending order classification which has been successfully assigned to a Supply Pair in accordance with the above procedure. All Demand Pairs with an offered price equal to or greater than the AMP shall be entitled to enter into a CAC, provided that the CAT issuers have been paid a sum equal to the AMP for each CAT.

8. Upon completion of the auction, the Transmission System Operator shall prepare and publish separately for each auction, an Auction Results Table listing the correspondence between Demand Pairs and Supply Pairs and the AMP. The Auction Results Table shall be notified in writing to all Load Representatives to which a CAT has been awarded, and to production license holders that are the issuers of such CATs.

Article 241 Auction for CATs with Financial Contract

1. CATs with Financial Contract shall be auctioned at separate auctions to be held in accordance with this Article. Upon request of a CAT issuer, CATs to be auctioned may be auctioned in groups if they concern the same Unit, if they have the same Reference Period, and are accompanied by the same Financial Contract. Auctions shall be held by a Committee appointed by the Transmission System Operator.

2. Auctions for each CAT shall be held as follows:

Α) Load Representatives that wish to participate in an auction, shall appear at the place and at the time established by the Transmission System Operator. The Committee shall see that participating Load Representatives are informed about the Minimum Price of each CAT to be auctioned, the Referenced Unforced Capacity suggested by the CAT issuer for inclusion in the respective CAC, and all the terms of the financial contract corresponding to each CAT;

Β) the submission of bids by Load Representatives is optional. Bids shall be submitted to the Committee in a sealed envelope and in accordance with the form established by the Transmission System Operator. Bids shall include Load Representative information and the bid price that must be higher than the Starting Price each time. Where bids are submitted stating a price lower than the Starting Price, such bids shall not be considered at subsequent procedure stages. Bids are binding. Along with their bids, Load Representatives submit to the Transmission System Operator a letter of guarantee for a sum equal to that of their bid. Letters of guarantee may be delivered once in order to cover the value of all bids of the respective participating Load Representatives;

C) the Committee shall announce the auction Start Up Price for a CAT, which shall be equal to the Minimum Price for the auctioned CAT, and call upon Load Representatives to submit bids within fifteen (15) minutes. If no bids are submitted, the Committee shall declare the auction barren;

D) once the above deadline has elapsed, the Committee shall open the envelopes containing the bids of Load Representatives and decide on the acceptance of bids based on the minimum criteria in accordance with paragraph (Β) above and announce the highest price corresponding to an acceptable bid. If no bids are accepted, the Committee shall declare the auction barren;

Ε) this price shall be the new Start Up Price of the auction. The Committee shall call upon Load Representatives to submit bids within fifteen (15) minutes. If no acceptable bids have been submitted within the foregoing deadline, the Committee shall declare the closing of the auction and the Load Representative that has submitted a bid with the highest price during the immediately previous round, shall enter into a CAC for the auctioned CAT. Otherwise, the procedure

shall be repeated and the Committee shall announce the highest price corresponding to an acceptable bid, which shall then become the new Start Up Price in order for the new bidding round to commence;

F) if at any stage of the auction two or more acceptable bids are submitted with the same price, which is the highest price for that specific stage, the Committee shall hold a draw and the bid to be drawn shall establish the new Start Up Price and shall be a candidate for the conclusion of a CAC;

G) the highest price of an acceptable bid that has been submitted at any stage of the auction shall establish the AMP for the specific auction.

3. The foregoing procedure shall be repeated for each CAT auctioned. Upon completion of all auctions, the Transmission System shall prepare and publish the Auction Results Table where the auctioned CATs are corresponded to the Load Representatives to which they have been awarded, as well as the AMP of each individual auction. The Auction Results Table shall be notified in writing to the Load Representatives to which each CAT has been awarded as well as to the production license holders that are the issuers of such CATs.

Article 242 Payment of Auction Price

1. The Transmission System Operator shall return the letters of Guarantee to the Load Representatives not included in the Auction Results Table.

2. Within seven (7) days from the notification of such Auction Results Table, each Load Representative included therein shall be required to pay the price that has resulted from the auction to the Producer that has issued each CAT awarded to each Load Representative as a result of the Auction, in order for them to enter into the respective CACs and the respective financial contracts, if any.

3. Should a Load Representative refuse to enter into a CAC or the respective financial contract, pay or pay in due time the respective price, the Transmission System Operator shall see that the respective Letter of Guarantee for participation in the Auction shall be forfeited. In that case, the Transmission System Operator shall allocate the sum corresponding to the Participation Letter of Guarantee to the Producers that are the issuers of the respective CAT on a pro rata basis. No CAC shall be concluded for such CATs and they may be auctioned at a later time.

4. Load Representatives that have been awarded CATs, as well as the respective production license holders that are their issuers, shall be required to inform the Transmission System Operator with regard to the payment of the respective price and the conclusion of the CACs, as well as about the conclusion of the required financial contract, if any. Where the information collected by the Transmission System

Operator regarding the payment of the price are contradictory, the Transmission System Operator shall embark on an investigation. Should such investigation not lead to the removal of the contradictions, the disputes between the parties involved shall be settled following the procedure established in Article 10.

5. Once the price has been paid and the contracts have been signed, the Transmission System Operator shall return the Participation Letters of Guarantee to the respective Load Representatives.

Article 243 Auction Cost Recovery

The CAT auction cost shall be included in the Transmission System Operator’s operating cost. Besides the recovery of the cost involved in holding auctions, the Transmission System Operator shall not be required to gain any financial benefit from the auctions.

CHAPTER 47

CAC TENDER FOR NEW GENERATION UNITS

Article 244 Tender scope and purpose

1. In order to ensure the long-term capacity adequacy for energy generation, the Transmission System Operator shall hold tender procedures aiming at the conclusion of CACs for new Generation Units (hereinafter referred to as CAC Tenders) for a maximum overall capacity to be established on a case by case basis taking account of the Capacity Adequacy Study and only when a future risk of capacity inadequacy is ascertained, which is not anticipated to be covered through independent business initiatives of production license holders.

2. The tender procedure, the terms and conditions for participation in them, the criteria used in the selection of the most advantageous bid, bid maximum and minimum values and all other necessary details shall be established by decision of the Minister of Development following the submission of a motion by the Transmission System Operator and the issue of RAE’s opinion.

3. The purpose of the Transmission System Operator entering into CACs from new Units is to provide investors with the minimum required revenues security for the new Units in order to facilitate their funding. This provision shall be offered provided that an investor fully assumes the business risk corresponding at least to the investment

capital and is bound to timely construct the Unit and keep it in perfect technical operation and capacity availability, while undertaking the responsibilities of commercial transactions and initiatives related to the exploitation of the energy generated by such Unit, as well as of other Unit related services. CAC Tenders do not provide any form, directly or indirectly, of contract for the purchase of the energy to be generated by new units, nor does it provide any form of priority with regard to the inclusion of such new Units in the DAS Schedule or with regard to the provision ancillary or backup services. The provision of security with regard to the revenues from the new Units corresponds to the partial coverage of a producer license holder´s ability to recover part of the investment cost corresponding to a Unit through revenues gained in the context of the DAS. The total capacity generated from each Unit for which the Transmission System Operator may enter into a CAC and all other necessary terms and conditions shall be established in the tender call.

4. CACs entered into as a result of a tender in accordance with the provisions of this Chapter, shall have the form and the contents of CACs as established in CHAPTER 44. As a party to the CACs, the Transmission System Operator shall act in accordance with Article 228 and must seek to transfer CACs to Load Representatives in accordance with CHAPTER 46.

5. Where a CAC Tender has been successfully completed, the Transmission System Operator shall enter the following contracts with the production license holder:

Α) Capacity Availability Contracts (CACs), the terms and conditions of which are established by Article 229 and correspond to the CATs issued by the production license holder for the new Unit and have been registered with the Register by the Transmission System Operator;

Β) Implementation Agreement for the new Unit which corresponds to the CATs for the conclusion of which a production license holder must furnish a Good Performance Letter of Guarantee. The terms and conditions of such Agreement shall ensure that real capacity adequacy for energy generation shall be provided during the Reference Period in accordance with the CAT information. For that purpose, the Implementation Agreement shall establish a binding date for the commencement of the commercial operation which shall coincide with the date of commencement of the CAT Reference Period and may also establish the deviation tolerance period from such date;

C) Financial Agreement for Guaranteed DAS Revenues which shall apply to the part of the CAT Reference Period during which the Transmission System Operator is a party to the respective CAC. Such agreement shall be the consideration provided as a result of the CAC Tender for the provision of capacity availability by the new Unit;

D) CAC Transfer Agreement regarding the transfer of CACs by the Transmission System Operator to a Load Representative, including the Contract for Differences,

and the unreserved acceptance on the part of the production license holder of all terms and conditions of the Contract for Differences, as well as the conclusion of a Contract for Differences at a later time with the Load Representative who wishes to become party to the respective CACs, and who shall be indicated by the Transmission System Operator following the CAC auction procedure in accordance with CHAPTER 46.

Article 245 Transfer of CACs to Load Representatives

1. The CACs entered into by the Transmission System Operator in accordance with the provisions of this Chapter shall be transferred to Load Representatives following an auction in accordance with CHAPTER 46.

2. Load Representatives receiving a CAC from the Transmission System Operator must enter a Contract for Differences with the respective production license holders under the terms and conditions established in the results of the CAC Tender, without right to negotiation of the terms and conditions of such contracts by any one of the parties thereto, and pay to the respective production license holders the price established in the context of the auction.

3. Upon signature of the Contracts for Differences, a copy thereof shall be notified to the Transmission System Operator and RAE, and the part of the Financial Agreement for Guaranteed DAS Revenues entered into between the Transmission System Operator and the production license holder corresponding to the CACs that have been transferred to Load Representatives shall expire.

Article 246 Expense Recovery

1. The Transmission System Operator shall recover all expenses resulting from Financial Agreements for Guaranteed DAS Revenues entered into for new Unit CACs.

2. At the end of each Reliability Year and until the end of the respective calendar year, the Transmission System Operator shall calculate all debts to the Producer in accordance with the Financial Agreements for Guaranteed DAS Revenues for the previous Reliability Year (annual debt) and charge the secondary account (UA-5) of the Uplift Account for the following calendar year. The annual debt shall be divided into twelve (12) installments for the same sum each which shall be paid on a monthly basis to the Producer during the calendar year following the Reliability Year when the debt was generated. The Financial Agreement for Guaranteed DAS Revenues

establishes any further details relating to the full payment of the debt as well as the consequences of default.

3. The sums collected by the Transmission System Operator in order to recover the expenses resulting from Financial Agreements for Guaranteed DAS Revenues, correspond to charges to and payments from Load Representatives in the context of the Energy Transactions Contract entered into for participation in the Energy Transactions System. Charges shall be allocated to Load Representatives on a monthly basis pro rata the energy quantities in MWh which they absorb from the System during the following calendar year, in accordance with the absorbed energy measurements taken.

4. The Transmission System Operator shall terminate the Energy Transactions Contract for those Load Representatives that fail to pay their financial obligations under the provisions of this Article.

SECTION VIII SYSTEM OPERATION AND MAINTENANCE

CHAPTER 48

SYSTEM STANDARDS

Article 247 System Operation Standards

1. The Transmission System Operator shall operate the System and plan its development so as to meet operating requirements at the connection points as set out in this Chapter.

2. Normal System frequency (reference frequency) is set at 50Hz and the operating range is set as follows:

Α) Normal operating range: 49.85 Hz to 50.15 Hz;

Β) During disturbances on the System or on transmission systems connected to it: 49.75 Ηz to 50.20 Hz;

C) During exceptional disturbances on the System or on transmission systems connected to it: 49.50 Ηz to 50.50 Hz.

3. Nominal System voltages are set at 400kV and 150 kV and the normal operating range is set as follows:

Α) 380 kV to 420 kV on the 400kV System;.

Β) 142.5kV to 162kV on the 150 kV System;

4. During System disturbances, abnormal conditions or faults, the allowed voltage operating range is as follows:

Α) 350kV to 420kV on the 400kV System;

Β) 135kV to 170kV on the 150kV System.

5. Some System disturbances, such as short circuits to earth or lightning strikes, may result in short-term voltage deviations outside the above ranges. Also in abnormal conditions and in particular when, following an opening of synchronous interconnecting lines, the System is islanded, the frequency may take values outside the ranges under paragraph (2) of this Article, however, such values shall be inside

the ranges established in Article 275 paragraph (2), until the load generation balance has been restored.

6. Due to the electrical characteristics of the System, the voltage for installations operating under common nominal voltage may not be the same at all points of the System.

7. The negative phase-sequence component of the System phase voltage may not exceed 2% under normal operating conditions.

8. The System must be effectively earthed on the neutral system with a fault factor to earth of less than 1.4.

9. The System is designed and operated to maintain short circuit levels below the following:

Α) 40kA on the 400kV System;

Β) 31kA on the 150kV System.

10. During System design, maximum subtransient short circuit fault levels shall not be greater than 90% of the limits under the previous paragraph, and in particular for three-phase or single-phase to earth faults, the design maximum subtransient short circuit fault levels shall not be greater than 36 kA for 400kV and 28 kA for 150kV.

11. The 400kV, 150kV and 66kV Systems must be effectively earthed. The line to earth voltage during single line to earth faults should not rise above 80% of the rated line to line voltage.

12. A safe margin should be provided between the System loading in an area and the voltage collapse point determined by parametric studies, as the System loading increases.

13. Thermal limits on equipment shall be as determined by the assumed seasonal ambient conditions. Normal and overload ratings must take account of the ratings of auxiliary and ancillary equipment such as switchgear, bushings, instrument transformers. No overloading on equipment shall be acceptable during equipment selection and design phase, under neither normal nor emergency operation, except in the immediate aftermath of a Disturbance, while corrective action, either automatic or manual, is being taken.

14. For base case operation with all lines and transmission self-transformers in service, the voltage step resulting from capacitor switching shall not exceed 3.0%. For single Contingencies (N-1), the maximum step change between pre- and post-contingency steady-state voltages shall be no more than 10%.

Article 248 System Operations

1. The Transmission System Operator may proceed to operations or order the System Owner to proceed to such operations particularly imposed by the following:

Α) installation and devices isolation for the purposes of maintenance, construction of new projects, emergency repairs, system tests, protection tests, isolation of a diagnosed or suspected fault and user works;

Β) voltage regulation needs;

C) limitation of energy flows in the System at levels compatible with the capacities of installations and the System safety.

2. If an operation, and in particular an operation altering the System topology, has an operational impact on a User, the Transmission System Operator shall inform the User prior to such future operation, if such notification is necessary and possible given the time frame, in accordance with the terms and conditions of the connection agreement or other agreement between the Transmission System Operator and the User.

3. The installations and devices of a given User may be deactivated at any time and extent that the Transmission System Operator considers necessary for the safe and reliable operation of the System within the specifications provided for. The deactivation of installations and devices of a User is imposed particularly in cases in which the following may arise:

Α) risk for the personnel safety;

Β) risk for the System stability;

Γ) risk for the System or a specific User installation or device;

D) overloading of System components beyond the emergency limits;

Ε) voltage deviations in the System beyond the limits established under Article 247;

F) behavior causing the continuous operation of the System beyond normal frequency limits;

G) substantial breach of the connection terms;

Η) any User action or omission hindering the Transmission System Operator from fulfilling its legal obligations or the obligations arising from its license.

Article 249 Protection of the System

1. The stability of the System shall be maintained following a three-phase zero impedance line-end fault. The fault must be correctly cleared by primary protection and automatic line reclosing shall be in operation where appropriate. This requirement may be met in special cases at the Transmission System Operator discretion and shall apply to single line fault stages.

2. A contingency shall not result in the islanding of major portions or in the shutdown of the system due to the cascade tripping of transmission circuits and generators. Existing protection equipment and capabilities thereof shall be taken into account for System design purposes.

3. There may be automatic changes in the circuit breakers status in the System without a warning due to the activation of protection configurations for the isolation or clearing of faults in System installations or in the installations of a given User connected to the System. The limitation of energy flows or voltage or frequency deviations in case of faults may be automatic.

4. When the performance of urgent operations is necessary as a result of the conditions or a fault in the System, the Transmission System Operator must inform the Users that may be affected.

5. When there is a fault in the System or the protection or other automatic procedure is activated, and the implementation of the procedure set out in the previous paragraph is not possible, or when the Transmission System Operator must perform urgent operations, it shall inform the users that may have been affected after the performance of such operations, unless there is no more reason for it, because the emergency conditions were temporary and have been fully restored in the meantime. The Transmission System Operator shall inform users about the estimated duration of emergency conditions and update such estimate when needed. In addition, the Transmission System Operator shall inform users with regard to the ending of such emergency conditions.

Article 250 Safety rules

The Transmission System Operator shall coordinate compliance with the applicable safety rules and shall issue the necessary working permits and authorizations for the issue and execution of orders for operations, isolations and for all works to be carried out on the System. The working permit shall be granted to persons entitled to such a permit, indicated by the Transmission System Operator. Such persons shall be responsible for compliance with the safety rules when performing the works mentioned in the permit

granted. The recipient of the permit shall be responsible for the performance of works and for taking appropriate measures for the safety of the staff at work. As regards any works on or beyond the System boundaries, the Transmission System Operator shall take all safety measures related to the System and shall notify these to the Users that might be affected.

CHAPTER 49

MONITORING, TESTING AND INVESTIGATION OF SYSTEM AND USER INSTALLATION OPERATION

Article 251 Tests performed by the Transmission System Operator

1. The Transmission System Operator shall perform all necessary operating tests aiming at controlling and developing operating procedures, the training of staff, and the collection of information pertaining to the System behavior under abnormal conditions.

2. The operating tests performed by the Transmission System Operator in accordance with the provisions of the present Chapter are particularly the following:

Α) tests including the controlled imposition of frequency and/or voltage changes for the purpose of information collection regarding the behavior of the System;

Β) System restoration controls;

C) tests concerning the procedures applying to System emergencies and alarm situations;

D) energy quality control and monitoring procedures at various System states.

3. The Transmission System Operator ought to notify the User about the time schedule and the impact of operating tests, as well as about any change in such time schedule or in the nature of operating controls, pursuant to the provisions of CHAPTER 22. Users may request a time period for studying the impact of operating tests on their installations. The Transmission System Operator ought to collaborate with the user in assessing the risks implied by the tests. No operating tests shall be performed without the user’s consent, unless the Transmission System Operator reasonably believes that the user's refusal to give its consent is unjustified.

Article 252 User required tests

1. All users are obliged to perform the minimum required number of operating tests in order to check and develop operating procedures, improve and measure the performance of their installations, fulfill the obligations arising from licenses, comply with generation requirements or other obligations and staff training requirements, ensuring that the impact of such checks on the Transmission System are kept to a minimum.

2. With regard to the performance of operating tests, users must submit relevant proposals within a reasonable time limit pursuant to the provisions of CHAPTER 22, or complying with any possible alternative procedures jointly established with the Transmission System Operator. By means of such proposals, users provide sufficient information to the Transmission System Operator in order for the latter to be able to assess with accuracy any operating impact of tests and particularly:

Α) the cause mandating the performance of the suggested tests, which might be a law requirement, the need for compliance with the user license terms and conditions, regulations or safety codes;

Β) the suggested hour or hours for the performance of operating tests;

C) the milestone time points for each specific stage of operating tests that may be completed separately or for which there is no need for repetition once performed;

D) estimates with regard to any adverse impact that a delay or interruption in the operating test might have on the user, for which delay or interruption the user is informed on a short notice;

Ε) if the operating tests are to be performed on a Generation Unit, along with the proposal for the performance of the test, the dispatch load or loads required by the production license holder for the completion of tests, as well as the duration of tests shall be submitted to the Transmission System Operator. If the production license holder is unable to determine the required unit loads until the completion of tests, then they are obliged to perform tests in appropriate stages, to indicate and discuss with the Transmission System Operator which test stages may be implemented partially and which should not, and to indicate possible changes in the tests for those stages that may be completed partially. The proposals also establish the factors that affect the completion of individual stages, and whether the procedure used for certain stages depends on the result of the previous ones.

3. The proposal of a production license holder for the performance of an operating test, including the execution of a dispatch instruction from a given Generation Unit for a given MW figure or under specific operating conditions is not considered as a

repeated Declaration of Availability or of the capacity to provide Ancillary Services, or operating characteristics.

Article 253 Evaluation of proposals for the performance of operating tests

1. Following the submission by a given User of a request for the performance of operating tests , the Transmission System Operator ought to assess the impact of the suggested tests on the operation of the System. The Transmission System Operator may, in addition, request from the User information which they deem necessary for the assessment of the impact of tests.

2. The Transmission System Operator shall assess the impact of the proposed operating tests on the continuity and reliability of supply to the Users. The Users affected by operating tests are entitled to raise objections which the Transmission System Operator is required to take into account. The Transmission System Operator ought to observe the commercial confidentiality of the information concerning a User, which is disclosed to them in relation to a request for the performance of operating tests.

3. Should the operating test suggested by a certain production licence-holder requires the issue of a Dispatch Instruction, which exceeds the limits of declared values for availability, capacity to provide ancillary services, or operating characteristics of the respective generation unit, the Transmission System Operator may issue a Dispatch Instruction for the Generation Unit, for the time period required for the performance of the operating test, pursuant to the special requirements of the present Code.

Article 254 Approval of proposals for operating tests

1. Following the submission of a request for the performance of operating tests, the assessment of the possible impact thereof and consultations with the User requiring the tests and the Users whose operation is affected by them, the Transmission System Operator shall decide on the approval of the operating tests.

2. The criteria for the approval of operating tests include particularly the impact of operating tests on the safety and cost effective operation of the System, the impact of operating tests on other Users, as well as their impact on the continuity and reliability of power supply.

3. Following the approval of operating tests for a specific production license holder, the Transmission System Operator shall send to the User a proposal related to the dispatch procedure and planning. Such proposal is not a Dispatch Instruction. The User may either accept such proposal or reject it and submit a request for alternative

planning or for a postponement of the operating tests. Should the Transmission System Operator accept the proposal, all Users that are considered to be significantly affected by the tests to be performed shall be informed about the time planning and the type of tests. Such Users are entitled to raise objections to the Transmission System Operator, in case they do not agree with the approved tests. Tests shall be cancelled by the Transmission System Operator, should they consider that the objections raised are justified. Any disputes between the parties shall be settled in accordance with the procedure under Article 10.

4. Should the Transmission System Operator reject the operating tests suggested by a given User, such User shall be entitled to propose an alternative planning or other operating tests or the performance of suggested tests at a different time. With regard to the approval and performance of checks, the provisions of the previous paragraph shall apply accordingly. Any disputes between the parties shall be settled in accordance with the procedure under Article 10.

Article 255 Operating test planning

1. Operating tests shall be planned by the Transmission System Operator in the context of the Dispatch Procedure.

2. The Transmission System Operator must give priority to the operating tests proposed by a specific User, when such User argues that the performance of the said tests is required pursuant to the terms and conditions of their license, safety rules or when the delayed performance of such tests may have important material consequences for the User.

3. Should the Transmission System Operator foresee a need for or the possibility of interruption, postponement, or any other significant change to a given agreed procedure, they must immediately inform the User having proposed the test.

4. Where the Transmission System Operator estimates that the impact of a given operating test on the safety of the System and the reliable supply to the User is more serious than the initially assessed, they shall investigate jointly with the User the possibility to review the procedure or the planning.

5. Should the User that has proposed the tests wishes the interruption or no performance of a given operating test, they shall inform the Transmission System Operator in accordance with Article 252.

6. The Dispatch Instructions required for the performance of operating tests are issued by the Transmission System Operator in accordance with the provisions of SECTION III.

Article 256 Notification of operating test results

1. After the planned time period for the performance of a given operating test has elapsed, the User that has proposed the test must inform the Transmission System Operator about whether all tests have been completed, or in case the tests have been broken down into stages, about the part of the tests that has been completed.

2. Following the completion of operating tests, the User that had proposed the tests is responsible for compiling a written report with regard to the checks performed (Final Report), which shall remain at the disposal of the Transmission System Operator, of the Users whose operation was affected, and of RAE, for three months following the completion of operating tests.

3. The contents of the Final Report shall be notified to third parties only following the granting of approval by the Transmission System Operator and RAE.

4. The Final Report includes the description of the installation and machinery tested, a description of System tests performed, as well as the results, any conclusions, and proposals relating to the Transmission System Operator and the Users operationally affected.

CHAPTER 50

MAINTENANCE OF THE SYSTEM

Article 257 Scope

In order to ensure the secure operation of the System, the Transmission System Operator shall see to, plan and assure the maintenance of the System through the isolation of System installations to that end. For that purpose the System Owner is required to maintain the System and keep it in operational and technical top condition in accordance with the Transmission System Operator's planning and instructions.

Article 258 System outage scheduling

1. In implementing the provisions of this Article, the current Reliability Year shall be symbolized as RY and subsequent Reliability Years as RY+1, RY+2 etc.

2. System Outage Scheduling includes:

Α) Indicative Maintenance Schedule, covering reliability year RY+3. The Indicative Maintenance Schedule shall aim at the timely assessment of the impact of the main outages on supply sufficiency or the secure and economic operation of the system, it shall be indicative and not binding upon the System Owner and the Transmission System Operator during the preparation of the provisional or committed maintenance program;

Β) provisional maintenance program, covering Reliability Year RY+2;

C) committed maintenance program, covering Reliability Year RY+1.

3. System Outage Scheduling shall be prepared by the end of May of the current Reliability Year. Such scheduling shall be absolutely binding for Reliability Year RY+1, binding subject to the appearance of unforeseen conditions for Reliability Year RY+2, and indicative for the following Reliability Year. The procedures used for the scheduling of outages for new installations of the System shall start at least three (3) before the date for which their operation is scheduled.

4. In October each Year, the System Owner shall submit to the Transmission System Operator proposed maintenance schedules for Reliability Years RY+1 to RY+3, which include a list of suggested outages, estimates of forced outage probability for each System element, the date, time and duration of each outage. In particular, the System Owner shall submit the following proposed maintenance schedules:

Α) proposed maintenance schedule for Reliability Year RY+1. This schedule will be based on the provisional maintenance schedule for the same year, with the exception of the first Reliability Year from the entry into force of the Code. Any changes may only reflect changed circumstances;

Β) suggested provisional maintenance program for Reliability Year RY+2;

C) suggested indicative maintenance program for Reliability Year RY+3.

5. The System Owner shall take all efforts so that scheduling is sufficient and extraordinary maintenance is avoided.

6. As regards the proposed outages included in the commited, in the provisional and in the indicative maintenance schedule, the System Owner shall also submit the following:

Α) alternative preferred periods within each year for each outage;

Β) estimate of the minimum required duration for each outage, if less than the suggested outage duration;

C) situations where the parallel outage of two or more Transmission System elements may be required, desirable, undesirable or not possible;

D) a priority order associated with the various suggested outages;

Ε) any outages where it is particularly desirable that they should take place within the time they have been scheduled for.

7. The information of the preceding paragraph shall not be submitted in case of outages for which it is reasonably substantiated that cannot be postponed.

8. The Transmission System Operator shall carry out a secure and economic System operation analysis for the period between Reliability Year RY+1 to RY+3, taking account of the outages suggested by the System Owner, and other related factors, which include the Maintenance Schedule of generation Units, interconnection outages, and the anticipated load growth. Should the outages suggested by the System Owner are detrimental to the secure or economic operation of the System, the Transmission System Operator may modify the outage schedule suggested by the System Owner, informing the latter to that respect.

9. The Transmission System Operator shall notify to the Distribution Network Operator and the other Users that are connected to the System of the various outage scheduling issues that may affect the operation of their installations.

10. The Transmission System Operator shall examine the proposals and/ or objections of the System Owner, the Distribution Network Operator, and the other Users that are connected to the System, and prepare a System Outage Schedule Proposal which they shall notify to the above. The System Owner, the Distribution Network Owner, and other Users that are connected to the System shall notify to the Transmission System Operator any remarks and objections within three (3) weeks at the latest.

11. Subsequently, the Transmission System Operator shall issue the System Outage Schedule which they shall notify to the System Owner, the Distribution Network Owner, and other Users that are connected to the System.

Article 259 Changes to the System Outage Schedule

1. Where the System Owner, the Distribution Network Operator, or another User that is connected to the System believe that there are emergency reasons requiring the alteration of Commited Maintenance Schedule for Reliability Year RY+1 or the maintenance schedule for the current Reliability Year RY, they may at any time submit a substantiated request to the Transmission System Operator.

2. Within three (3) weeks from the submission of the above request, the Transmission System Operator shall examine whether the changes requested are to have an undesirable effect on the secure and economic System operation. To that end they shall request the opinion of the System Owner and Users the operation of the installations of which may be affected by the changes requested. The Transmission System Operator, in their justified decision, may reject the request or accept it in

whole or in part and amend accordingly the Commited Maintenance Schedule or the maintenance schedule for the current Reliability Year, which it shall notify to the System Owner, the Distribution Network Operator, and other Users connected to the System.

3. The Transmission System Operator taking into account the secure and economic operation of the System, may suggest a change to the Commited Maintenance Schedule or the maintenance schedule for the current Reliability Year, which it shall notify to the System Owner, the Distribution Network Operator, and other Users connected to the System, with the exception of those for whom it is demonstrated that the suggested change does not affect the operation of their installations. The System Owner, the Distribution Network Operator, and other Users connected to the System shall notify any remarks and objections to the Transmission System Operator within three (3) weeks at the latest. Next, the Transmission System Operator shall approve the amended Commited Maintenance Schedule or the amended maintenance schedule for the current Reliability Year which it shall notify to the System Owner, the Distribution Network Operator, and other Users connected to the System.

4. Where the Transmission System Operator believes that there are urgent reasons related to the secure operation of the System, they may postpone the maintenance of the System installations. A relevant amendment to the System Maintenance Schedule shall be made as a result of cooperation between the Transmission System Operator and the System Owner.

Article 260 Urgent changes

1. The Transmission System Operator may, where the secure and economic operation of the System would be at risk, decide on alterations to the maintenance schedule following the procedure under Article 259. The Transmission System Operator shall make reasonable endeavors to give as much notice as possible for such alterations. The System Owner must comply with such alterations.

2. The Distribution Network Operator and Users connected to the System must cooperate with the Transmission System Operator in all phases of outage planning to promote and ensure secure and economic System operation.

SECTION IX PLANNING OF SYSTEM DEVELOPMENT

CHAPTER 51

PROCEDURE

Article 261 Definitions and scope

1. Development of the System, which includes both its reinforcement and its extension, may be due to the following reasons:

Α) growth in demand for electricity;

Β) need for interconnection capacity increase;

C) removal of System inter-zonal constraints and/ or improvement of System quality and security;

D) development of User sites already connected to the System;

Ε) introduction of new connection sites or modification of existing connection sites between User systems and the System;

F) changing requirements for electricity transmission facilities due to factors such as demand changes, generation changes, technology changes, reliability requirements, or environmental requirements;

G) the cumulative effect of a number of such factors referred to in this paragraph.

2. The reinforcement or extension of the System may involve work:

Α) at a new or existing connection site where a given User’s plant and apparatus is connected to the System;

Β) on new or existing transmission lines or other facilities which join a specific User to the System;

C) on new or existing transmission lines or other facilities at or between points remote from the connection site of a given User.

3. The time required for the planning and development of the System will depend on the type and extent of the necessary reinforcement or extension work, the time required for obtaining planning permission and wayleaves, including any associated hearings,

and the degree of complexity in undertaking the new work while maintaining satisfactory security and quality of supply on the existing System.

4. The provisions of this Chapter set out the requirements and procedures necessary during planning of the System in order to ensure cooperation between the Transmission System Operator and a particular User in relation to any proposed development on User facilities that may affect the System operation or concerning the User’s direct connection to the System. Moreover, provision is made for the supply of information required by the Transmission System Operator from users in order for the Transmission System Operator to undertake the planning of the System in accordance with the transmission planning criteria and relevant standards, and the preparation of the annual forecast statement for the development of the System.

Article 262 Planning Operations

1. The Transmission System Operator shall plan development of the Transmission System to ensure secure, reliable and economic supply of electricity and meet the operating requirements under CHAPTER 48.

2. System reserve shall be sized by the Transmission System Operator in accordance with N-1 Criterion and the effect of multiple disturbances arising on the System shall be limited by large-scale failure and restoration strategies.

3. System planning by the Transmission System Operator shall consider the current load and generation situation and projected load and generation growth, RAE’s estimates on generation growth and geographical distribution, as well as the anticipated requirements of Users.

Article 263 Transmission System Development Study (TSDS)

1. By October 1st each year the Transmission System Operator shall prepare and publish a draft Transmission System Development Study (SDS) which shall be submitted to RAE. RAE, taking account of the Transmission System Operator’s obligation to ensure uninterrupted access to the System in the most cost-effective, transparent and direct way and without discriminations among Users or User categories, shall proposed to the Transmission System Operator in a documented manner the alterations and supplements to the draft TSDS it considers necessary. The Transmission System Operator shall prepare the final draft TSDS taking account of RAE's remarks. The final draft TSDS shall be submitted to the Minister of Development for approval which shall be granted following the issue of RAE's opinion, and it shall be accompanied by documentation prepared by the Transmission

System Operator regarding the reasons for any differences in the final draft as compared to RAE's remarks on the original draft.

2. The TSDS shall be prepared taking account of the following objectives:

Α) improvement of the supply security level and increase of the transmission capability and the System stability limit, as well as technological improvements;

Β) removal of technical constraints imposed by the operating limits of the System elements, and in particular the systematic Transmission System Constraints;

C) the provision of direct, if possible, priority to new Users regarding access to the System, in the context of the obligations to provide uninterrupted System access to third parties in accordance with Community Law;

D) the increase of the transmission capability of existing interconnections and the development of new interconnections;

Ε) reduction of transmission losses in the System.

3. The term for the TSDS is set to five (5) years and includes time scheduling for all extension or reinforcement projects, including all projects to be completed within the term of the TSDS, as well as projects the construction of which must start within the TSDS term regardless of the time for their completion.

4. For each new project, the TSDS shall include a technical description setting out the main planning elements such as:

Α) for transmission lines, the type and their estimated length;

Β) for Substations and Extra-high Voltage Centers, the general electrical configuration, namely the number of busbars, the type and number of bays, and the nominal capability of power transformers and self-transformers;

C) for reactive power leading or lagging compensation apparatus, their nominal capability, and the Substation or Extra-high Voltage Centers where they shall be installed;

D) for other projects and in particular those involving the application of new technologies, basic technical specifications in accordance with the provisions of this Code.

For each project the feasibility of its construction shall be documented against the criteria under paragraph (2) of this Article.

5. The TSDS shall include a time schedule for the implementation of each project establishing the estimated time for the completion of each stage of the project such as technical studies, submission of dossier for the issue of environmental terms, any appropriations, commencement of construction, completion of construction and tests, and commissioning. Projects shall be grouped by geographical area and efforts shall

be made for the joint time scheduling of such projects, in order to attain coordination and the timely achievement of the TSDS objectives.

6. The Transmission System Operator shall ensure the implementation of the schedule and compliance with the relevant time schedules. To that end, the Transmission System Operator shall monitor progress in the implementation of TSDS projects and shall prepare and publice relevant half-yearly reports.

Article 264 Data about the TSDS

1. For the purposes of System planning and development, Users are required to regularly provide data and information to the Transmission System Operator following a relevant request by the latter. Such data and information shall constitute data for System planning.

2. The data submitted by Users regarding the planning of a System project shall be considered confidential, with the exception of the data submitted by the System Owner or the Distribution Network Operator.

3. By May 1st, each year, RAE shall prepare and notify to the Transmission System Operator a report with regard to generation growth and distribution in space, for the following five-year period. The Transmission System Operator shall take into account the contents of the RAE report in order to fulfill its competencies under Article 15 paragraph (3) of Law 2773/1999.

4. The project planning data, along with other data that the Transmission System Operator disposes and which regard the System shall constitute the basis for the analysis and assessment of the new requests of Users. Such data shall be confidential, unless used by the Transmission System Operator to prepare the annual forecast report, to provide information in relation to such report, assess the requests of other Users or candidate Users or for the purposes of System planning, or if provided for in the connection contract.

Article 265 Data verification and validation

1. Should the Transmission System Operator consider that the data submitted by a given User are erroneous or inaccurate, they may require from such User to submit additional information, which in their opinion is necessary to verify the accuracy of data.

2. If following the assessment of the information submitted in accordance with the previous paragraph, the Transmission System Operator estimates in a justified manner

that it does not have sufficient information to verify the initial data, it may ask the User to perform data verification tests. Tests shall be carried out in accordance with CHAPTER 55.

3. If the data submitted by the User are verified by the tests, the cost of such tests shall be borne by the Transmission System Operator.

4. If the data submitted are not verified, the cost of tests shall be borne by the User. The figures resulting from the tests shall be used as data. Where, in the reasonable judgment of the Transmission System Operato,r data changes which result from a given test render necessary the conduct of further System studies, the User shall bear the cost of such studies.

CHAPTER 52

REINFORCEMENT AND EXTENSION PROJECTS

Article 266 Design criteria and standards

1. For the purpose of System design, the Transmission System Operator shall apply the design criteria laid down in this Chapter, as well as the established rules and standards.

2. In determining the technical requirements of a User connection, the Transmission System Operator ought to refrain from discriminations among Users of the same category, location and size, and if it is technically and economically possible to attain uniform connection ways each time.

3. The System voltage level to which a Unit is connected and the busbar configuration accepted shall depend on the size and number of generation units comprising the User’s installations, compatibility with future System development, and the geographical distance from the existing System.

4. Customers connected to the System shall, as a rule, connect to the 150kV transmission voltage level. The Transmission System Operator may connect any such System customer to a different transmission voltage level for reasons mainly relating to demand in MW at the connection point, compatibility with future System development, proximity with the existing System, and the cost of the proposed connection.

5. As a rule, the Distribution Network is connected to a 150kV transmission voltage level. The Transmission System Operator may connect the Distribution Network to a different transmission voltage level for reasons mainly relating to demand in MW at

the connection point, compatibility with future System development, compatibility with the combined System and Distribution Network design, the geographical distance from the existing System and the cost of the proposed connection.

6. The User shall bear the full cost of extension projects for the connection of its installations with the System, which are among the financially most advantageous and technically acceptable way of connection with the System, in accordance with the N-1 reliability criterion and the requirements of this Code.

7. Upon request of a User and if the Transmission System Operator agrees, in establishing the technical requirements for the connection, specifications stricter than the established ones may apply. In that case, the additional cost generated shall be borne by the User.

Article 267 Ν-1 design criterion

1. The N-1 criterion means that under all operating conditions the loss of any given element, in particular line, transformer, Generation Unit, will not jeopardize the operation of the System or lead to further loss of System elements or supply interruptions. As a result of loss of one element, the configuration of the Transmission System will need to be reorganized in order to comply again with the N-1 Criterion within the shortest possible time so that the loss of a further element will not jeopardize security of operation.

2. The N-1 criterion shall be used for System development and the design of schemes for connection of User installations to the System in accordance with CHAPTER 59.

3. The Transmission System Operator shall carry out System operation analyses and simulations, and in particular regarding its stability and reliability, which shall check the consequences of various load, generation unit, cross-border energy trade, and System topology scenarios.

Article 268 System stability

1. The Transmission System Operator shall install and size Transmission System control facilities to ensure stable operation for all relevant conditions and to face oscillatory phenomena whether transient or steady-state either by limiting amplitude or damping to a sufficient extent so that they will not impair System operation. The Transmission System Operator shall specify measures to be taken to maintain System stability in the event of a change to technical or operational parameters of Users or the connection of a new installation to the System.

2. Steady state stability is the situation in which minor changes to operating conditions do not lead to self induced oscillations which may result in large-scale collapse of the System and result in damage to Users’ plant or facilities. Steady-state stability must be ensured at all times and at all points of the System. The Transmission System Operator shall ensure maintenance of the short circuit levels and Transmission System voltages in accordance with the provisions of CHAPTER 48 and shall examine whether purchases or injections by System Users are possible without risk to steady state stability or whether a constraint must be imposed. The Transmission System Operator shall endeavor to ensure that changes in load and injection situations, such as low-load operation with under-excited Generation Unit, and changes to System configuration shall not endanger steady state stability of the System pursuant to the provisions of CHAPTER 48.

3. Transient stability is the situation in which following clearance of a short circuit on the System, no Generation Units loses synchronism with respect to the System and generator pole slipping does not occur. During System design, the Transmission System Operator shall be able to ensure that the short circuit levels at the System / Generation Units interface do not violate those specified in CHAPTER 48, following fault clearance by the System protection in accordance with its design.

4. Where a generation unit cannot be prevented from pole slipping following System short circuits, the generation unit must be disconnected from the System by means of generator protection to prevent risk to the Transmission System and to generator operation. The System shall withstand the effects upon it, which arise during these dynamic processes.

Article 269 Simulation assumptions

1. System operating analyses shall be based on current energy demand, maximum and minimum load forecasts. The performance of the planned System must meet the transmission design criteria under various load conditions, including but not limited to maximum load.

2. System operating analyses shall be based on the best information on generation development, including RES units. Due to the random nature of RES unit generation, their effect on the System shall be analyzed for two extreme scenarios regarding generation by such units:

Α) they generate their maximum capacity;

Β) they do not operate.

3. System planning shall take account of alternative scenarios regarding the distribution of generation and load on the System. The strength of the System should be such that:

Α) no limitation shall be put on the output of any Unit under normal and N-1 conditions;

Β) a pre-arranged complete shutdown of a generating unit or part of it, during a suitably chosen load period may be tolerated. The duration of such period must be suitably minimized in the context of System planning.

4. The System must be capable of transmitting the net flows resulting from imports or exports through interconnections with other foreign transmission system.

Article 270 Special planning criteria

1. With regard to the supply of energy to transmission substations, the System Owner’s regulations in force each time shall apply.

2. The generation units arrangement shall be such that the loss of generation capacity arising from a busbar fault shall have no serious impact on the System. The loss of generation capacity arising from a fault involving any System element shall not, to the extent possible, exceed twice the rating of the largest single generation unit on the System.

Article 271 Implementation of System Reinforcement Projects

1. The System reinforcement projects shall be assigned to the System Owner in accordance with the Transmission System Control Concession Contract. The System Owner shall be responsible for the perfect completion of such projects in accordance with the specifications in the TSDS, as well as for compliance with the implementation time schedules included in the TSDS. The System Owner shall implement the TSDS projects assigned to it assuming all relevant expenses, in accordance with the terms of its license. The cost of such projects shall be recovered by the Transmission System Operator through charges for the use of the System and shall be paid to the System Owner.

2. When the System Owner demonstrably invokes reasons of inability to comply with the project implementation time schedule in accordance with the TSDS or its funding, the Transmission System Operator may, subject to RAE’s approval, undertake itself or assign to third parties the construction of System projects, the expenses being borne either by the Transmission System Operator or third parties through self-funding, or through any other suitable method to be decided by the Transmission System Operator, subject to RAE's approval. The cost of such projects shall be

recovered by the Transmission System Operator or the latter shall ensure such recovery through charges for the use of the System.

3. In any case ownership of such assets past their final delivery shall pass to the System Owner, who shall next undertake the maintenance of the project in accordance with the provisions of the Code and the construction financing method for such works shall be taken into account in the calculation of the remuneration to be paid to the System Owner.

Article 272 Implementation of System Extension Projects for User

Connection

System extension projects for User Connection may be implemented either by each User or by the System Owner. In any case, a trilateral implementation Contract shall be entered into among the System Owner, the Transmission System Operator and the respective User in accordance with the Transmission System Control Concession Contract, in which express provision is made for the project parts which each party shall undertake, the respective implementation time schedules as well as testing and acceptance procedures, and the procedures for any remuneration. Upon performance of all the obligations arising from the Implementation Contract, the System Owner shall take all legal actions in order to gain ownership of the project part which is part of the System, and shall next undertake the maintenance of the project in accordance with the provisions of the Code.

SECTION X USER INSTALLATION OPERATION AND

MAINTENANCE

CHAPTER 53

REGISTERED CHARACTERISTICS AND OPERATION SPECIFICATIONS FOR USER

INSTALLATIONS

Article 273 User Registered Characteristics Table

1. The Transmission System Operator shall keep in its records a Registered Characteristics Table for the installations of each User that is connected to the System. The information in the Registered Characteristics Table shall be notified to all interested parties following a relevant request, provided such request documents a lawful interest of the requesting party.

2. The Registered Characteristics Table includes data and information pertaining to the technical and operating characteristics of a User’s installations and it includes at least the information basically established in the Connection Contract in accordance with CHAPTER 56.

3. The information in the Registered Characteristics Table shall be established by the Connection Contract in accordance with Article 300.

4. The information in the Registered Characteristics Table shall be further established by the testing and acceptance of equipment in accordance with Article 288.

5. At a later time the User may submit a documented application to the Transmission System Operator for the modification of the information in its Registered Characteristics Table if imposed by technical reasons and if the suggested information is compatible with the specifications set out in CHAPTER 53. The Transmission System Operator shall decide on the application after having applied the testing and investigation procedures in accordance with CHAPTER 55.

6. The information in the Registered Characteristics Table must be compatible with the specifications established in CHAPTER 53. Where a deviation is ascertained from such specifications, the Transmission System Operator shall carry out tests and

investigations in accordance with CHAPTER 55, activate the procedures provided for with regard non compliance with the terms of the Connection Contract or the Registered Characteristics and shall inform RAE to that respect.

7. Where there are serious technical reasons for which the User is unable to comply with certain specifications, it shall submit to that end a relevant exemption application to the Transmission System Operator where it shall indicate in detail the technical reasons documenting the exemption request, as well as the measures that it intends to adopt in order to comply with the specifications within reasonable time which it shall establish in its application. The submission of an exemption application does not release a User from its obligation to comply with the specifications regarding the Registered Characteristics of its installations.

8. The Transmission System Operator with a view to the technical evaluation of the capabilities of the User’s installations and to ensure reliable and efficient System operation, shall decide on the acceptance of the application within fifteen (15) days. Should such time elapse it shall be considered that the application has been rejected. Within five (5) days from receipt of the decision, the User may lodge an objection before RAE, also notifying it to the Transmission System Operator. RAE, following a motion by the Transmission System Operator presented within ten (10) days, shall decide on such objection within twenty (20) days, and notify its decision to the User and the Transmission System Operator. Should such time elapse, it shall be considered that the objection has been rejected.

9. Once an exemption has been approved in accordance with Article 315, the Transmission System Operator shall modify the information in the Registered Characteristics Table for that User. Once the time for which the exemption has been granted has elapsed, the Transmission System Operator shall proceed to the necessary controls and investigations in accordance with CHAPTER 55 and update the information in the Registered Characteristics Table for the User.

10. Where the Transmission System Operator has ascertained a systematic deviation of the information in the Techno-Economic Declaration from the respective information in the Registered Characteristics Table for the User, as well as in all other cases where data and information are collected regarding the real operation of the User’s installation beyond its Registered Characteristics, the Transmission System Operator shall launch procedures for testing, investigation and non-compliance with the terms of the Connection Contract or the Registered Characteristics in accordance with CHAPTER 55.

Article 274 General design and operation specifications

1. For the safe and reliable operation of the System to the benefit of Users, their plants and apparatus will be designed to meet the operating requirements of the System in various conditions.

2. The earthing of all User plants and apparatus and the installation of the earthing system must by made at least in accordance with the relevant standards. The following rules apply for the earthing systems:

Α) the Transmission System Operator must contact each user for the exact specifications of the earthing network to be installed;

Β) each user’s earthing devices must be earthed by direct earthing with the central substation earthing network;

C) each user must ensure that any fault in their plants is limited to the confines of the substation and that any dangerous voltage rise shall not be transmitted outside the earthing zone;

D) each user guarantees that the staff working at the earthing system is properly trained for the performance of the relevant works in a safe manner.

3. The design of each user's plant and apparatus must meet the following minimum specifications for each level of voltage:

Parameter (minimum) 150kV 400kV

Insulation level, impulse voltage (1.2/50 msec)

750 kV

1550 kV

with the following exceptions for autotransformers:

• 1550 kV for bushings,

• 1425 kV for windings.

Insulation level for power frequency (50Hz for 1 min)

325 KV

680 kV with the following exceptions:

Switches:

• 620 kV between phase-earth and among phases

• 800 kV along open contacts

Disconnectors:

• 620 kV between phase-earth and among phases

• 800 kV along the insulation distance

Autotransformers:

• 680 kV for bushings

• 630 kV for windings

Clearance in air between conductors and metal parts in the area of outdoor Substations and Extra-High Voltage Centers

1550 mm

• 3100 mm between conductor and metal part.

• 4100 mm between Rod and metal part

Height of live parts above over pedestrian passageways in the area of outdoor Substations and the Extra-High Voltage Centers

5000 mm 7000 mm

Height of bottom of unscreened live bushings above ground in the area of outdoor Substations and Extra-

2300 mm 2300 mm

High Voltage Centers

Height of live conductors above roadways 9000 mm 11000 mm

4. All control and protection cables must be equipped with a suitable metallic screen. Facilities for earthing these screens at the base of cabinets shall be provided. LV supply cable and auxiliary wiring shall be routed from the transmission substation to each User’s control building through a mutually agreed cable corridor. The cables will be laid in concrete troughs with reinforced concrete covers, or as mutually agreed, to the User’s marshalling rack, which will be situated near the Transmission Station, or in any other way established by joint agreement between the User and the Transmission System Operator.

5. The facility to lock in the open/closed position and interlocking facilities shall be provided by each User on appropriate disconnectors and/or circuit breakers (with withdraw facilities) in order to ensure that the incoming feeder(s) to the facility can be safely isolated when required by the Transmission System Operator. The specific details of this requirement will be outlined at the design phase. Existing generation stations operating in accordance with the safety rules provided for in the provisions of CHAPTER 48 must also comply with this paragraph.

6. Generation units, with installed Registered Capacity greater than 100MW shall provide onload tap-changing (OLTC) facilities for all generator transformers. Customers connected to the System are advised to provide on-load tap-changing (OLTC) facilities for all transformers connected to the System. The design specifications applied by a user for the operation of the OLTC system for transformers connected to the system are approved by the Transmission System Operator.

7. The following specifications apply to transformers installed at connection points:

Α) generator transformer windings shall be connected in star (with the neutral brought out) on the System side (high voltage side) and in delta on the generator side (low voltage).

Β) Other transformers connected to the System are connected in:

(1) delta on the high voltage and in star on the low voltage side, with the neutral node brought out to terminals for resistance or direct earthing; or

(2) star on both high and low voltage sides with the neutral node brought out to a terminal either for direct or resistance earthing and a tertiary winding connected in delta.

C) generating units general ancillary transformers are connected in star on the high voltage side with the neutral node brought out to a terminal for direct earthing and in delta on the medium/ low voltage side;

D) provision should be made for the earthing of the neutral of each transformer connected to the 66kV system by bringing out the neutral to a terminal for direct earthing and ensuring that the insulation is such that the transformer can be operated unearthed;

Ε) provision should be made for the earthing of the neutral of each transformer connected to the 150kV system by bringing out the neutral. The Transmission System Operator will consider on a case by case basis if the transformer is required to be operated with the 150kV neutral unearthed, and will notify the user accordingly;

F) extra-high voltage neutral nodes of all generator transformers connected to 400kV systems must be solidly earthed. The capability of being operated unearthed is unnecessary;

G) the common high and extra-high voltage neutral node of 400/150/30 kV autotransformers is earthed through a circuit breaker also enabling operation without earthing of the neutral node.

8. The User shall be responsible to supply and install the circuit breaker tripping mechanism of the transformer that is connected to the System from the user transformer protection system and other apparatus. The Transmission System Operator shall provide the required settings of the tripping mechanisms for such circuit breaker due to failure concerning the User’s Connection Substation that fall within the Transmission System Operator’s scope of responsibility.

Article 275 Special design and performance specifications for thermal and

hydro generation units

1. The specifications laid down in this Article apply to thermal and hydro generation units that are connected to the System. In any case a Contract shall be entered into for the Connection of Units with the System between the Transmission System Operator and a production license holder. For thermal or hydro generation units that have been connected to the System or for which Connection Contracts were signed prior to the entry into force of this Code, and which are not in compliance with the specifications of this Article and their modification is not possible, an application for exemption shall be submitted in accordance with Article 315.

2. The generation units must meet at least the following requirements:

Α) operate continuously at normal rated output at System frequencies in the range 49.5Hz to 50.5Hz;

Β) remain synchronized to the System at System frequencies within the ranges 47.5Hz to 49.5 and 50.5 to 52.5Hz for a duration of 60 minutes;

C) remain synchronized to the System at System frequencies within the range 47.0Hz to 47.5Hz for a duration of 20 seconds, whenever this is required in case the Frequency is below 47.5Hz;

D) remain synchronized to the System at System frequencies within the range 52.5Hz to 53Hz for a duration of 5 seconds, whenever this is required in case the Frequency is above 52.5Hz;

E) remain synchronized to the System during rate of change of System frequency of values up to and including 0.5 Hz per second;

F) sustained operation at the specified minimum generation within the range 49.8 to 51.0 Hz;

G) remain synchronized to the System at normal rated output at System voltages within the ranges specified in Article 247 for step changes in System voltage of up to 10%;

Η) sustained operation in accordance with the reactive power capability as required by paragraph (17) hereof at System voltages within the ranges specified in Article 247, unless otherwise agreed;

I) remain synchronized following a short circuit close to the generator during voltage dips on the HV side of the generator transformer of 95% of nominal Voltage (5% retained) for a duration of 0.2 seconds and voltage dips of 50% of nominal Voltage (50% retained) for duration of 0.7 seconds. The characteristic for nominal voltage retained versus duration synchronized in the range between 100% retained voltage and 50% retained voltage shall be a straight line between 1.5 seconds duration and 0.7 seconds duration;

J) remain synchronized to the System during a negative phase sequence load unbalance in accordance with IEC 60034-1;

K) the short circuit ratio of each Generation Unit shall be in accordance with IEC 60034-1.

3. Lignite Plants shall have the following characteristics:

Technical Minimum Generation

not greater than 50% of registered capacity

Ramp-up capability not less than 1.5% of registered capacity per minute when the unit is in normal operation

Ramp-down capability not less than 1.5% of registered capacity per minute when the unit is in normal dispatch operation

Minimum Up-Time not greater than 4 hours

Minimum Down- Time not greater than 4 hours

Forbidden Zones not permitted for thermal units

Block Loading not greater than 10% of registered capacity

Time off-load before going into longer cold operating reserve conditions

Remain in a hot condition for at least 12 hours Remain in a warm condition for at least 60 hours

Time to Synchronize (from instruction)

Hot: not greater than 3 hours

Warm: not greater than 8 hours

Cold: not greater than 12 hours

Time from Synchronizing to Minimum Generation

Hot: not greater than 40 minutes

Warm: not greater than 90 minutes

Cold: not greater than 180 minutes

4. Oil or Gas steam electric Plants shall have the following characteristics:


not greater than 35% of registered capacity

Ramp-up capability not less than 1.5% of registered capacity per minute when the unit is in the normal dispatch condition

Ramp-down capability not less than 1.5% of registered capacity per minute when the unit is in the normal dispatch condition



Forbidden Zones not permitted


Time off-load before going into longer standby conditions










5. Coal plants shall have the following characteristics:


Minimum generation not greater than 40% of registered capacity

















6. Non-CCGT plants and internal combustion engine plants shall have the following characteristics:


not greater than 10% of registered net capacity

Ramp-up capability it must be such so that within 20 minutes from unit synchronization it is possible to provide full unit capacity

Ramp-down capability it must be such so that within 10 minutes unit capacity can drop from maximum generation to technical minimum generation.

Minimum Up-Time not greater than 1 hour





15 minutes


5 minutes

7. CCGT plants shall have the following characteristics:


not greater than 60% of registered net capacity for 1 GT+1 ST units and 35% in all other cases

















8. Thermal and hydro plants with a registered capacity of at least 100MW must meet the following operating reserve requirements::

Α) Each generation unit must have primary frequency control capability. The controller droop shall be adjustable according to the specifications of the Transmission System Operator. They must provide primary operating reserve expressed in MW output not less than 3% of the registered capacity in the range of 50% to 97% of the registered capacity, with such provision that in the range of 97% to 100% registered capacity, primary operating reserve shall not be less than that indicated by a straight line with fixed slope from 3% of registered capacity at 97% output to 0% at 100% output. The production license holder must be capable of activating, within 30 seconds, the total primary operating reserve requested at a

quasi-steady frequency deviation of ±200mHz and of maintaining supply for at least 15 minutes. The primary operating reserve must be available again 15 minutes after activation assuming that the reference frequency has been attained again;

Β) they must provide for a secondary operating reserve expressed in MW output not less than XX% of the registered capacity in the range of 50% to (100-XX)% of the registered capacity, with such provision that in the range of (100-XX)% to 100% registered capacity, secondary operating reserve shall not be less than that indicated by a straight line with fixed slope from XX% of registered capacity at (100-XX)% output to 0% at 100% output. XX% shall be set to 40% for Hydro Units, 15% for CCGT units, and to 3% for other thermal units;

C) they must provide for a tertiary operating reserve expressed in MW output not less than 10% of the registered capacity in the range of 50% to 90% of the registered capacity, with provision that in the range of 90% to 100% registered capacity tertiary operating reserve shall not be less than that indicated by a straight line with fixed-slope from 10% of registered capacity at 90% output to 0% at 100% output;

D) they must provide for non-spinning reserve expressed in MW output not less than the technical minimum generation increased by 25% of registered capacity.

9. The Transmission System Operator may request generation units greater than or equal to 60MW to have the capability to operate under AGC at all loads between AGC Minimum Load and AGC Maximum Load.

10. Users shall not change unit load-frequency or governor control settings without agreement with the Transmission System Operator.

11. The generation units operating characteristics shall be registered in the Transmission System Operator records. These units shall operate in consistency with their type and model, ensuring maximum operating flexibility, in accordance with good industry practice. Where appropriate, operating characteristics and in particular start times, should be registered separately for normal and planned starts, and for starts required under system emergencies, such as following the loss of a generation unit. Production license holders shall maintain operational procedures and practices, which ensure immediate response dispatch instructions in accordance with the technical capabilities of the generation plant.

12. Production license holders shall upon a relevant request cooperate with the Transmission System Operator in the development of procedures and facilities to improve the response of each generation unit during system emergencies. These particularly include automatic start up of fast-start generation units following a loss of generation unit(s) or in advance of an anticipated loss of generation unit(s). Production license holders are required to inform the Transmission System Operator

providing full documentation where the above procedures are not consistent with secure operation of their units.

13. Where start-up time of a generation unit exceeds thirty (30) minutes, it shall be designed to have the capability, where supply from the System is lost, to reduce output to match auxiliary load.

14. Synchronizing operations shall be performed by production license holders at circuit breakers identified by the Transmission System Operator. These circuit breakers, depending on the unit, shall include the generation unit circuit breaker and the HV and LV transformer circuit breakers. The Transmission System Operator will provide signals to the production license holder regarding plant and apparatus in operation, to facilitate synchronizing on the generator transformer HV circuit breaker, in accordance with the relevant provisions of the connection contract.

15. The synchronizing facilities set out in this Article shall facilitate synchronizing under the following conditions:

Α) System frequency within the limits 48.0 to 52.0 Hz; and

Β) System voltage within the limits specified in Article 247, and paragraph (17) hereof.

16. Each generation unit shall be designed to mitigate the risk of common mode failure with other generation units. In particular each generation unit shall be designed so that it can operate with its essential auxiliaries supplied through a unit transformer which shall be connected between the generation unit circuit breaker and the generator transformer LV busbar terminals, or from another backup source as agreed between the Transmission System Operator and the production license holder. Auxiliary supplies may be taken from an alternative source during plant commissioning, testing, start-up or emergencies, always in accordance with good industry practice. In the case of a CCGT module this applies to the combustion turbine units only.

17. The following shall apply to the reactive power generation capability:

Α) Each Generation Unit shall have the following Reactive Power capability as measured at the generator terminal busbars:

Voltage Range Network At Maximum

Continuous Rating At 35% of Maximum

Continuous Rating

140kV to 163kV

0.93 power factor leading to 0.85 power factor lagging


125kV to 140kV

150kV power factor 1.00 to 0.85 lagging


360kV to 420kV

power factor 0.93 leading to 0.85 lagging


350kV to 360kV

400kV power factor 1.00 to 0.85 lagging


Β) for load levels of a particular generation unit between maximum continuous rating and 35% of maximum continuous rating, MVAr reactive power capability may not be less than indicated by a straight line drawn between the two points derived from the values above, on a plot of MVAr capability against MW output;

C) for load levels of a particular generation unit below 35% of maximum continuous rating, MVAr reactive power capability may not be less than that at 35% of maximum continuous rating ;

D) the generation unit transformer shall have nominal rating to allow reactive power supply and/ or absorption over the full range of System voltages, as specified in indent (A) of this paragraph;

Ε) the Transmission System Operator and the production license holder shall cooperate at the design stage to resolve any issues that might arise in the application of this paragraph .

18. Each generation unit shall be equipped with a fast analogue speed governor and a unit load controller or equivalent control device to provide frequency response under normal operating conditions. The speed governor design and operation at normal regulation shall be between 3% and 5% and shall be made in accordance with the relevant European Standards or, otherwise, in accordance with the relevant standards generally applied in the European Union, as in force at the time of the design of the plant of which it forms part .

19. All generation units shall be capable of contributing to the control of System voltage by continuous modulation of the unit voltage by means of a suitable continuously

acting Automatic Voltage Regulator (AVR), in accordance with the relevant standards as determined by the Transmission System Operator and the characteristics accepted by the latter prior to the connection date. The Transmission System Operator may not accept some characteristics recommended by a particular user following a reasonably justified decision.

20. Unit transformers shall have on-load tap changing facilities. The tap step may not alter the voltage ratio at the terminals by more than 2.5% on the 150kV System and 1.6% on the 400kV System, unless otherwise agreed with the Transmission System Operator.

21. Generation units with a registered capacity greater than 100MW shall have a generator protection function with a fault clearing time of greater than 200ms, or the duration to be determined by the Transmission System Operator based on local conditions. During this time and after the fault is cleared, the generation unit maintains synchronized and pole-slipping does not occur. Production license holders must prevent instability or disconnection of the unit from the System throughout the operating range due to short circuit close to the unit, when the system short circuit power following fault clearing at the System and System connection plant exceeds six times the nominal active power of the unit. The auxiliary supply may not be automatically redirected to reserve supply connections under these circumstances.

Article 276 User installation protection and power quality

1. Every user shall be responsible for ensuring that faults on plant and apparatus cause minimal disturbance to the System. Faults on plant and/or apparatus connected to the system should be cleared as soon as possible. The maximum period for fault clearance is set as follows:

Α) 120 msec for the 150 kV System; and

Β) 80 msec for the 400 kV System.

2. These clearance times concern primary protection systems only. At the latest until connection to the System, Users shall install and maintain, in accordance with good industry practice, the protection equipment specified in this Article.

3. Subject to the prior approval of the Transmission System Operator, the User must install the protection equipment at plants and apparatus against System disturbances, as deemed appropriate. The Transmission System Operator shall set the requirements deemed appropriate for the protection of System installations, also taking into account users plant protection.

4. Minimum protection requirements for each User’s plant connected to the System may vary depending on the type, size, earthing and connection method. The Transmission

System Operator must operate the User protection installations throughout the operation of the connected plant.

5. High speed automatic reclosing (HSAR) characterized by the sudden re-activation of the power supply after a dead time of approximately 600 milliseconds on the 400kV system and 500 milliseconds on the 150kV system is a feature of the System operation. All tripping and high speed reclosing on the 150kV and 66kV Systems is threepole.

6. It is recommended that Users take precautions against disturbances on the System including without limitation protection against:

Α) load unbalance (negative sequence) protection;

Β) over or undervoltage;

C) under or over-frequency;

D) a combination of the previous two cases that may result in overexcitation; and

Ε) high-speed automatic reclosing (HSAR), where applicable.

7. Settings for a User's protection systems that may have an operational effect, shall be notified to the Transmission System Operator. The Transmission System Operator may prohibit the settings of some user protection systems within certain ranges, based on such criteria as assuring secure System operation, the perfect cooperation between protection systems and the identification of faults per area, namely System, Distribution Network and User faults, and especially of the following protection systems:

Α) generation unit under-frequency, overcurrent, or distance protection;

Β) transformer overexcitation, over-current, or distance protection; and

C) Loss-of-Mains protection.

8. A mechanism for the notification, approval and determination, of such settings will be set out in the user's connection contract or other agreements.

9. The Transmission System Operator shall provide to the user the information and signals necessary for the interface coordination and operation of the user’s protection equipment, in accordance with the relevant provisions of the connection contract or other agreements, and the provisions of this Article. .

10. Where possible, the Transmission System Operator shall provide circuit breaker failure protection on System Connection Point circuit breakers installed in new transmission substations.

11. Production license holders must provide:

Α) differential protection on the generator transformer. The connections between the connection point circuit breaker and the HV terminals of the unit transformer shall be included in the protected zone of above differential protection ;

Β) backup protection to the System on generation units. The Transmission System Operator shall reasonably require the installation of generator overcurrent protection, voltage controlled generator overcurrent protection or unit distance protection, or a combination of the above from production license holders;

C) under-frequency protection;

D) generation Unit loss of excitation protection.

12. The Transmission System Operator may require production license holders, to install additional protection schemes, where reasonably considered appropriate. Such schemes include the following:

Α) generation unit overvoltage/ undervoltage protection;

Β) generation unit overfrequency protection;

C) generation unit transformer neutral displacement voltage detection;

D) loss-of-mains protection (rate of change of frequency or vector shift); and

Ε) generation unit pole slip protection.

13. Regulation of protection regarding faults within the Transmission System Operator’s scope of responsibility, acting on the connection point circuit breaker of generator transformers shall be provided by the Transmission System Operator

14. The Distribution Network Operator shall provide differential-protection on System connected transformers. The Transmission System Operator may require the Distribution Network Operator to install additional protection schemes, where reasonably considered necessary. Such schemes include the following:

Α) directional overcurrent protection or distance protection on User’s transformer;

Β) direct intertripping between the grid connection point circuit breaker and the User connection point circuit breaker;

C) neutral voltage displacement protection on HV side of User’s transformer;

D) Loss-of-Mains protection;

Ε) over or undervoltage protection;

F) under or over-frequency protection;

G) differential protection on distribution lines or cables;

Η) distance protection on the user connection point circuit breaker on distribution lines or cables;

I) bus zone protection on 150 kV distribution busbars; and

J) teleprotection channels for use with distance protection between the System connection point circuit breaker and User connection point circuit breaker .

15. Regulation of distance protection or over-current protection shall be provided by the Transmission System Operator on System connection point circuit breakers.

16. System connected Customers shall provide differential-protection on System connected transformers. Additional protection schemes may be installed by System connected customers, following a documented request by the Transmission System Operator. Such schemes include the following:

Α) directional overcurrent protection or distance protection on System connected transformers when the user system contains embedded generation;

Β) neutral voltage displacement protection on HV side of System connected transformers when the user system contains embedded generation;

Γ) loss-of-mains protection when the user system contains embedded generation;

∆) under/over voltage protection when the user system contains embedded generation;

Ε) under/over frequency protection when the user system contains embedded generation.

17. Users shall ensure that their connection to the System does not result in distortion or fluctuation of the supply voltage at the connection point, exceeding the relevant limits. Distortion and fluctuation limits are outlined in IEC/TR3 61000-3-6 (Harmonics) and IEC/TR3 61000-3-7 (Voltage fluctuation). The Transmission System Operator may allocate different distortion and fluctuation limits at connection points by a documented report. Users shall also operate their plant in a manner which will not cause the requirements contained in CENELEC Standard EN 50160 to be breached.

18. The hourly average power factor (APF) for a System Connected Customer is calculated in accordance with the following formula:

( ) ( )2 2

En

En QnΜΣΙ =

+

where:

En is the active power supplied to the System connected customer for the specific hourly period;

Qn is the reactive power supplied to the System connected customer for the same hourly period

19. Each System connected user shall ensure that, at any load above 50% of maximum import capacity, the hourly average power factor as determined at the Connection

Point in any hourly period shall be within the range 0.95 lagging to unity. In case of leading load, namely reactive power injection to the System, the hourly average power factor must not exceed 0.98.

System 277 Power supplies

Each user shall provide:

Α) 400 V ac / 230 V ac power supplies as required by the Transmission System Operator for transmission substation facilities. The capacity and other details shall be specified by the Transmission System Operator and provided for in the connection contract;

Β) a standby supply for all AC power supplies for transmission substation facilities by a diesel generator, unless otherwise agreed with the Transmission System Operator. The Transmission System Operator must provide reasonable grounds for its refusal to agree to a different manner of ensuring standby supply. In the event of loss of mains, standby supplies shall be capable of being sustained for a minimum of 10 hours.

Article 278 User provided signals

1. Each User must provide signals and indications about their installations and machinery as the Transmission System Operator may reasonably require in accordance with the Connection Contract.

2. The signals and indications that Users must provide include but are not limited to the following:

Α) MV circuit breaker positions for each transformer connected to the System, through two auxiliary contacts off voltage (one open and one closed under normal conditions when the circuit breaker is open) for each circuit breaker;

Β) voltage at the transformer's MV terminals; and

C) at least four auxiliary contacts off voltage, that under normal conditions shall be closed on the MV side of each transformer to indicate faults.

3. More specifically, production license holders are required to provide the following signals:

Α) MW and ±Mvar at the generator terminals of each generation unit;

Β) voltage at the MV terminals of each unit transformer;

C) unit transformer tap position.

4. If the signals or indications that Users must provide in accordance with this Article are not available or in line with the applicable specifications due to failure or insufficiency of the User’s equipment, the User must in accordance with good professional practice immediately restore or correct such signals and indications.

5. The signals provided by a user shall be transmitted in the form established in the connection contract.

6. Where the Transmission System Operator has decided that due to a modification in the System in order to meet a System requirement there is need for supplementary signals or indications relating to the User's plant and machinery, they must inform the User, who shall immediately and in accordance with good professional practice ensure the availability of such supplementary signals or indications.

7. At transmission substations and at the installations of HV or MV Customers, cabinets shall be placed in a suitable area to for connection and adaptation with the Transmission System Operator's equipment.

8. The supply and maintenance of wiring and signaling, as well as of the device in the interconnection room of the unit, of the Distribution Network Operator and of Customers connected to HV or MV shall be their responsibility. The Transmission System Operator shall provide the cables for connection to the connection and adaptation cabinets.

Article 279 Additional equipment

1. Production license holders, the Distribution Network Operator, and System connected Customers must make available the necessary equipment and be electronically interconnected with the Transmission System Operator having at the same time made provision for the uninterrupted supply of energy at their own expenses. Such equipment shall be used only for communication with the Transmission System Operator.

2. The users under the previous paragraph must make available the necessary telephone and telefax equipment, having at the same time made provision for the uninterrupted supply of energy at their own expenses. They must also have at least two telephone connections with the PSTN and at least on telefax connection through such network.

3. The Transmission System Operator may provide to such Users connection to the telephone system it owns, which shall be only used for operating purposes by an authorized person, as provided under this Code.

Article 280 Access to equipment

No access is allowed to unauthorized persons to the metering equipment, the SCADA, the computers and the telecommunications equipment connected with the Transmission System Operator. The Transmission System Operator may have access to such equipment for maintenance, testing or signal reception purposes. Details regarding access to such equipment are established in the instructions issued by the Transmission System Operator.

Article 281 Clock setting

Time shall be set using the devices established by the Transmission System Operator and shall be the reference for all System or User apparatus, which must operate in a synchronized manner. Such time shall be transferred to the respective System or User apparatus in order to achieve their synchronized operation.

Article 282 Special rules regarding the operation of User installations

1. Each user shall prepare a site operation regulation.

2. The Transmission System Operator shall issue operation instructions for each user site, including, but not limited to:

Α) detailed switching sequences, in accordance with the requirements of the safety rules for faults or emergencies;

Β) control and operation procedures;

C) identification of operational boundaries;

D) identity of the Transmission System Operator and user representatives to be provided with access to the transmission substation or facility for operation and during emergencies.

3. The terminology and nomenclature used with regard to a User's installations and apparatus that connect to the System must use the standardized terminology of the Transmission System Operator. The Transmission System Operator may approve deviations from this rule following a documented User request.

4. Each User must procure, install and maintain clear and legible signs indicating the terminology and nomenclature of the installations and apparatus at its site.

Article 283 Security responsibility

1. Users must cooperate with the Transmission System Operator to develop detailed procedures and achieve agreement on each issue relating to the security in all their installations and in particular their connection equipment.

2. The installation operation regulation details the responsibility of persons carrying out works in or tests on the User's connection installations and on circuits that cross with such installations at any point, in accordance with the provisions of this Code.

CHAPTER 54

GENERATION UNIT AND INTERCONNECTION MAINTENANCE SCHEDULE

Article 284 Unit and Interconnection Maintenance Scheduling

1. In order to assure adequate supply to and the secure operation of the System, the Transmission System Operator shall compile, in cooperation with production license holders, a Unit Maintenance Program on a rotation basis. Such program shall concern Units in the Unit Register.

2. During preparation of the Maintenance Program, the Transmission System Operator shall take account of the following: a) the maintenance program suggested by production license holders regarding their Units, b) all other relevant factor, especially the shut down of interconnections or installations or other System elements, System supply security and anticipated load growth.

3. The Unit Maintenance Program shall be prepared by the end of May of the current Reliability Year and shall include the following three (3) Reliability Years. Such program shall be binding for the first Reliability Year and indicative for the other following Reliability Years. The Transmission System Operator shall establish the periods in each Reliability Year during which units may not be maintained in the interest of System security of supply.

4. Production license holders shall submit by the end of February the suggested maintenance program for their units establishing:

Α) suggested alternative periods for each outage within all Reliability Years;

Β) the minimum outage duration which would be acceptable for maintenance;

C) any outages where it is particularly desirable that they should take place within the year scheduled;

D) any outage where its timing is dependent on generation unit operating hours, equivalent operating hours or starts.

Ε) the technical reasons which document any proposal regarding a maintenance time in excess of the reasonable Unit maintenance time as this is estimated based on common practice regarding the technology of such Unit;

F) the technical reasons which document any suggestion regarding Unit outage outside the time during which the Transmission System Operator has prohibited maintenance for supply adequacy and secure System operation purposes;

G) situations where the paralleling of outages of two or more of its generation units may be required, desirable, undesirable or not possible;

Η) priority order associated with the various proposed outages.

5. The Transmission System Operator shall examine the proposals of production license holders and prepare a Unit Maintenance Program Proposal which it shall send to production license holders and notify to RAE. Production license holders shall notify any remarks and objections to the Transmission System Operator within three (3) weeks at the latest.

6. Next, the Transmission System Operator shall issue the Unit Maintenance Program which it shall send to production license holders and notify to RAE.

7. The outage scheduling procedure for new units shall start at the latest six (6) months from the anticipated commencement of the commercial operation of the Unit.

8. The Transmission System Operator shall prepare the interconnection Outage Schedule in cooperation with the operators of neighboring systems. The Transmission System Operator shall post the interconnection Outage Schedule so that it is known at a reasonable time prior to the long-term interconnection transmission capacity allocation procedure. All amendments to the interconnection Outage Schedule as well as the impact of such amendments to imports and exports shall be made public.

Article 285 Changes to a committed maintenance program

1. Where a production license holder believes that there are emergency technical reasons which impose a change to the Unit maintenance period in the current Reliability Year, they may submit at any time a documented request to the Transmission System Operator. The Transmission System Operator shall process such request within three (3) weeks from its submission and by a justified decision it shall reject it or accept it

in whole or in part and amend the Unit Maintenance Program which it shall notify to production license holders and RAE.

2. The Transmission System Operator may, with a view to supply adequacy and secure System operation, propose an amendment to the applicable Unit Maintenance Program which it shall notify to production license holders and RAE. Production license holders shall notify any remarks and objections to the Transmission System Operator within three (3) weeks at the latest.. Next, the Transmission System Operator shall approve the amended Unit Maintenance Program.

3. Should a production license holder be unable to meet the Unit Maintenance Program, they must declare non-availability for its Unit for the respective time period and inform the Transmission System Operator in accordance with applicable provisions on the submission of Non-Availability Declarations.

Article 286 Obligation to inform about maintenance works

1. Production license holders must inform the Transmission System Operator with regard to any maintenance works that do not constitute scheduled outage and which they intend to undertake, if they affect or may affect the generation unit capability or the capability to provide Ancillary Services.

2. The Transmission System Operator may for adequate supply purposes or for reasons relating to ensuring secure System operation require of production license holders to make changes to scheduled maintenance works.

CHAPTER 55

MONITORING, TESTING AND INVESTIGATION

Article 287 Scope

1. To ensure economic and secure System operation, the Transmission System Operator must monitor, perform control tests on and investigate the performance of User installations in order to be able to verify if their operation meets the design, operation and connection requirements as these are established in the Registered Characteristics Table, connection contracts, Ancillary Service Contracts, Supplementary System Energy Contracts, Cold Reserve Contracts, and in all other specific agreements between Users and the Transmission System Operator.

2. Monitoring, testing and control shall mean in particular:

Α) evaluation of the operation of generation units in accordance with Dispatch Instructions;

Β) assessment of compliance on the part of production license holders with Availability Declarations, CATs, the Ancillary Service and Supplementary System Energy provision capability, Registered Characteristics, Declared Characteristics, and all other information registered pursuant to this Code;

C) assessment of compliance with the IEC standards on energy quality, and in particular IEC/61000-3-6 and IEC/61000-3-7 standards;

D) assessment of compliance on the part of Users with the protection requirements and the respective arrangements provided for in this Code, connection contracts and in all other specific agreements between Users and the Transmission System Operator.

3. The provisions of this Chapter shall apply to Units in the Unit Register, as well as to all other generation units with a registered net capacity over 10 MW in a position and to System connected Customers.

Article 288 Equipment test and commissioning

1. The connection contract sets out the equipment test and commissioning procedures, including commissioning test and operating code tests. .

2. Users shall carry out the necessary tests in order to confirm that the plant and apparatus meet all requirements, effect on the operational date. In order to ensure design and operational compliance, the Transmission System Operator may carry out or cause the user to carry out particular tests. It is the responsibility of users to ensure successful tests and operation, in accordance with the provisions of this Code.

3. Where test and commissioning is likely to involve a requirement for dispatch instruction for test purposes, the user shall immediately notify the Transmission System Operator of this requirement, including reasonable details as to the duration and type of testing required. This information shall be indicative. Users shall give the Transmission System Operator reasonable notice at least fifteen (15) Business Days prior to the date of carrying out of the commissioning tests. The date of such commissioning shall be confirmed at least three (3) business days before the time of carrying out such tests. In the event that, having given such confirmation the user reasonably determines that such tests must be carried out prior to the date agreed, the User shall give the Transmission System Operator reasonable notice. The user must promptly notify the Transmission System Operator in relation to any material change to the requirements and details of the tests.

4. Commissioning tests requiring the issue of a dispatch instruction shall only be carried out following the issue of the dispatch instruction and subject to it.

5. In order to carry out commissioning tests requiring the issue of a Dispatch Instruction, the user shall submit a written request to the Transmission System Operator, which shall include the following information:

Α) details of the proposed commissioning test;

Β) proposal in relation to the dispatch instruction considered necessary by the user for the carrying out of the test, including the duration of the dispatch instruction;

C) where the user may not know the number of operating tests required for completion of the commissioning test, then the User, when proposing the test, shall:

(1) divide the commissioning tests into sections;

(2) indicate and discuss which sections of the tests can be completed in stages and which cannot; and

(3) indicate possible variations of the tests for the sections which can be completed in stages.

Factors which might influence the completion of the stages and especially procedures to be followed if a certain stage depends on the outcome of the previous one, shall be notified to the Transmission System Operator.

D) proposal in relation to the time or times for the tests

Ε) The milestones for individual sections of the tests which can be completed separately, and need not be repeated if the test is interrupted by the Transmission System Operator after completion of a section.

6. Following the connection date but not later than the operational date Users shall verify the technical data provided under the provisions of CHAPTER 56 and other technical data which the Transmission System Operator reasonably requires to be verified to assess compliance with the provisions of this Code or the connection contract. In order to verify such data, the users shall provide the Transmission System Operator with the evidence reasonably required, including the results of the commissioning tests or such other tests provided for in this Code.

7. Based on the values verified under this Article, the user’s Registered οperating Characteristics shall be modified.

Article 289 Monitoring

1. The monitoring process is continuous and is carried out by data recording, checks and analysis, in accordance with the methods as the Transmission System Operator shall reasonably determine are appropriate in the circumstances or mutually agreed with users.

2. Monitoring is performed without advance notification from the Transmission System Operator to Users. Where a data recording and analysis system is used for monitoring, the Transmission System Operator shall inform the User that such data recording and analysis system is being used and shall make available all necessary information.

3. Monitoring may be carried out at any time. The Transmission System Operator may, based on the monitoring results and without the application of further testing, determine noncompliance of a certain user. Where the user disputes a finding of non-compliance, the Transmission System Operator shall provide the user with any data collected during monitoring, which document noncompliance.

4. Performance parameters monitored include:

Α) compliance with dispatch instructions;

Β) compliance with declarations in respect of primary, secondary and non-spinning operating reserve, and frequency control provided by each generation unit, in order to confirm consistency with the declared governor droop;

C) compliance with IEC Power Quality standards;

D) provision of static and dynamic reactive power; .

Ε) monitoring systems and procedures.

Article 290 Testing

1. Testing involves attendance by the Transmission System Operator at user sites in order to carry out tests in accordance with the Transmission System Operator dispatch instructions or other procedures specified. The results of a test may be derived from the monitoring of performance during the test.

2. Tests may be carried out in order to determine that a user is complying with its connection contract conditions, registered operating characteristics and declarations. .

3. When carrying out tests, the Transmission System Operator may:

Α) for the purposes of testing, issue dispatch instructions;

Β) induce controlled power system frequency or voltage conditions or variations for the purpose of determining that the generation unit’s response is in accordance with its declared availability, ancillary service capabilities and operating characteristics;

C) carry out on-site tests in accordance with the provisions of this Chapter, having given the User at least three business days advance notice .

4. The Transmission System Operator may assign on-site tests to a third person, following agreement of the user subject to testing.

5. Three (3) business days prior to a certain test, the Transmission System Operator shall notify the User of the testing procedure to be followed. In case of the first application of a test procedure, an advance notice of seven (7) business days shall be given. Five (5) business days prior to the execution of a test, the user, in accordance with good industry practice, may raise documented objections, on the grounds that there will be a material risk to the safety of the user's plant or personnel, or that the proposed procedure is technically infeasible or inappropriate to the purpose, The Transmission System Operator shall, as it considers necessary, modify the procedure, taking the user’s objections into account.

6. Users must cooperate with the Transmission System Operator to perform control tests and provide all relevant information and additional assistance the Transmission System Operator may request to that end.

7. The Transmission System Operator shall treat information collected during monitoring and testing as confidential, in accordance with the provisions of this Article.

8. Where the user calls for a test, the user will pay for the costs of the test. Where the Transmission System Operator calls for a test, the user will provide to the Transmission System Operator an estimate of the costs. Transmission System Operator shall pay the direct costs of that test if in agreement with the estimate, otherwise costs shall be established by an independent firm. Costs established by an independent firm shall be charged to both parties on a pro rata of the deviation of their estimate of the test costs from the costs established by such independent firm. The User shall cover the costs of tests entirely if these are required due to problems that have been demonstrated to be caused to the operation of the System due to the operation of such User' s plant.

Article 291 Black Start Test

1. The Transmission System Operator may require for black start test either while the unit remains connected to an external electrical supply or while it is disconnected from it.

2. Black Start test may be carried out on more than one units and may not, in the absence of exceptional circumstances, affect any other unit.

3. Black start tests may not be carried out more than once each year in respect of any particular unit unless the necessity for further tests or re-test can be reasonably justified.

4. The Transmission System Operator shall notify the users at least seven (7) business days prior to the time of the black start test with details of the proposed black start test.

5. All black start tests shall be carried out in the presence of representatives of the Transmission System Operator, who shall be given access to all information relevant to the black start test.

6. Should synchronization of a certain generation unit in the System not be achieved within the required time for the start of the auxiliary gas turbines or the auxiliary diesel engine in accordance with Article 128, it is considered that the unit black start test has failed.

7. In the event of a start-up test failure, the user is required within five (5) business days to submit to the Transmission System Operator a written report detailing the reasons for failure detected. Should the Transmission System Operator and the user disagree on the reasons behind such failure, the user may request the repetition of the start-up test, following a notification 48 hours prior to the test. The test shall be repeated in accordance with the procedure agreed upon for the initial test.

8. Should it be ascertained that such failure was due to the fact that the station does not have a real start capability with the System being off voltage, the user is required to submit to the Transmission System Operator within 15 days a proposal for restoring the station to a black start capable status with the System being off voltage on a specific date and at a specific time. The Transmission System Operator may approve such proposal or ask the user to proceed to the modifications considered necessary.

Article 292 Investigation

In order to ascertain User installation or apparatus compliance with the design, operation or connection requirements, established in this Code, the Registered Characteristics Table, connection contracts, Ancillary Service Contracts, Supplementary System Energy Contracts, Cold Reserve Contracts and in all other specific agreements between the Transmission System Operator and Users, the Transmission System Operator is entitled to carry out investigations to collect information not normally collected using the monitoring or control tests method.

Article 293 Non-compliance with the terms of the Connection Contract or

the Registered Characteristics

Should the Transmission System Operator estimate that a certain generation unit does not operate in compliance with the terms and conditions of the connection contract, or the registered operating characteristics, he ought to notify the user to that respect. The user is required to take all necessary actions to restore the unit operation in accordance with the terms and conditions of the connection contract and the registered operating characteristics. The Transmission System Operator is, in this case, entitled to place the user’s installation and devices off voltage.

CHAPTER 56

PROVISION OF USER INFORMATION

Article 294 Data submission by Users or prospective Users

1. This Chapter specifies data to be submitted to the Transmission System Operator by Users or prospective Users of the System as is provided for in the procedure for connection to the System under SECTION XII, as well as in all cases of changes to such data.

2. The data that all users must submit are:

Α) full name of the user;

Β) address of the user;

C) contact person;

D) telephone number;

Ε) telefax number;

F) e-mail address.

3. The data that all users must submit for new connections are:

Α) Projected Operational Date;

Β) Projected Connection Date;

C) reliability of connection requested subject to system security and reliability standards;

D) 1:50.000 map, with the location of the facility and the coordinates of connection substation clearly marked;

Ε) Geographical Army Service map indicating the geographical coordinates of the connection substation lot;

F) a plan of the site, 1:200 or 1:500, of the proposed facility, in hard copy or digitized format, indicating the proposed location for the transmission substation, location of the connection point, transformers, site control buildings and all other necessary information;

G) an electrical single line-diagram of the proposed facility detailing all significant items of plant in hard copy or possibly digitized format;

Η) Users submitting applications only for generation, are required to provided data concerning any possible production licenses granted to them or relevant applications they have submitted, as well as data concerning the license or license applications for the construction or reconstruction of a generation station with which connection is pursued .

Article 295 Production license holder data

1. Each production license holder shall submit to the Transmission System Operator detailed information as required to design, construct and operate the System.

2. The general data that must be submitted by production license holders are:

Α) station name;

Β) number of generation units;

C) Primary Fuel Type / Prime Mover;

D) secondary fuel type;

Ε) Generation Export Connection Capacity Required in MW.

3. Minimum requirements for generator operating conditions are specified in CHAPTER 53.

4. For thermal units, a functional block diagram of the main plant components, showing boilers, heat exchangers, any heat or steam supplies to other processes etc. indicating single shaft or multiple shaft configuration.

5. For each individual generation unit the following data shall be provided:

• Unit number

• Registered capacity in MW

• Nominal Maximum Continuous Generation Capacity in MW

• Nominal Maximum Net Capacity in MW

• Unit auxiliary load in MW;

• Unit auxiliary load in MVAr;

• Overload capacity (gross) in MW

• Overload capacity (net) in MW

• Nominal Minimum Continuous Generating Capacity (gross) in MW

• Nominal Minimum Continuous Generating Capacity (net) in MW

• Generator rating (MVA base) in MVA

• Nominal Maximum Lagging Power Factor in Cosφ or MVAr

• Nominal Maximum Leading Power Factor in Cosφ or MVAr

• Governor Droop (R)

• Forbidden zones in MW

• Terminal Voltage adjustment range in kV

• Short Circuit Ratio

• Rated Stator Current in Amps

• Capability Chart showing full range of operating capability of the generator including thermal and excitation limits

• Open Circuit Magnetization Curves

• Short Circuit characteristic

• Zero power factor curve

• V curves

• Time to synchronize from hot condition in hours

• Time to synchronize from cold condition in hours

• Time to synchronize from warm condition in hours

• Block loading in MW

• Soak Time in hours

• Time from Synchronizing to Minimum Generation (hot condition) in hours

• Time from Synchronizing to Minimum Generation (warm condition) in hours

• Time from Synchronizing to Minimum Generation (cold condition) in hours

• Minimum up-time in hours

• Minimum down-time in hours

• Ramp-up capability in MW / min

• Ramp-down capability in MW / min

• Loading rate in MW / min

• Deloading rate in MW/ min

• End Point of Start-up Period in MW

• Generator capability to start on either fuel

• Ability to change fuel on-load

• Available modes (lean burn, etc.)

• Time to change modes on-load

• Control range for AGC operation in MW

• Other relevant operating characteristics not otherwise provided

• Primary Spinning Reserve

• Secondary Spinning Reserve

• Tertiary non-spinning reserve

• Details of reserve capability of the generator in different operating modes, such as unit coordination, turbine follow, recirculation, base load

• Possible available reserve with the unit off load.

6. The following data may be required for generators::

• Direct axis Synchronous reactance as % on rating

• Direct axis Transient reactance saturated as % on rating

• Direct axis Transient reactance unsaturated as % on rating

• Sub-transient reactance unsaturated as % on rating

• Quad axis Synchronous reactance as % on rating

• Quad axis Transient reactance unsaturated as % on rating

• Negative Phase Sequence Synchronous reactance as % on rating

• Zero phase sequence reactance as % on rating

• Turbine generator Inertia constant for entire rotating mass in MW s/MVA

• Stator resistance (Ra) as % of rating

• Stator Leakage reactance as % on rating

• Poiter reactance as % on rating

• Direct axis open Circuit Transient (Tdo’) in Sec

• Direct axis open Circuit sub-Transient (Tdo’’) in Sec

• Quad axis open Circuit Transient (Tqo’) in Sec

• Quad axis open Circuit sub-Transient (Tqo’’) in Sec

• Direct axis short Circuit Transient (Td’) in sec

• Direct axis short Circuit sub-Transient (Td’’) in sec

• Quad axis short Circuit Transient (Tq’) in sec

• Quad axis short Circuit sub-Transient (Tq’’) in sec.

7. The following parameters or a Laplace-domain control block diagram in accordance with IEEE standard excitation models, or as otherwise agreed with Transmission System Operator, completely specifying all time constants and gains to fully explain the transfer function from the compensator or generator terminal voltage and field current to generator field voltage must be supplied as follows: :

• Excitation system type (AC or DC)

• Excitation feeding arrangement (solid or shunt)

• Excitation system Filter time constant (Tr) in sec

• Excitation system Lead time constant (Tc) in sec

• Excitation system Lag time constant (Tb) in sec

• Excitation system Controller gain (Ka)

• Excitation system controller lag time constant (Ta) in sec

• Excitation system Maximum controller output (Vmax)

• Excitation system minimum controller output (Vmin)

• Excitation system regulation factor (Kc)

• Excitation system rate feedback gain (Kf)

• Excitation system rate feedback time constant (Tf) in sec.

8. A Laplace-domain control block diagram must be supplied in accordance with IEEE standard prime mover models for thermal and hydro units, or as otherwise agreed with Transmission System Operator, completely specifying all time constants and gains to fully explain the transfer function for the governor in relation to frequency deviations and setpoint operation.

9. An additional Laplace domain control diagrams for any outstanding control devices or special protection relays in the generating unit, must be supplied, for discrete control apparatuses or special generation unit protection relays, which automatically impinge on its operating characteristics within 30 seconds following a system disturbance and which have a minimum time constant of at least 0.02 seconds.

10. The following data are required for hydro units:

Α) Reservoir Capacity in volume (m3) and energy (MWh)

Β) Special consumption in MWh/m3

C) upper and lower level management limit

D) diagram showing level change per MWh generated for different levels

11. The following data are required for pumping units:

Α) Downstream Reservoir Capacity (MWh pumping)

Β) Max Pumping Capacity in MW

C) Min Pumping Capacity in MW

D) Efficiency (generating / pumping ratio) as a %

12. With regard to Wind Turbine Generators and asynchronous generator excitation devices the following data must be supplied:

Α) A statement whether turbines are Fixed Speed or Variable Speed

Β) Manufacturer details on electrical characteristics and operating performance with particular reference to Flicker and Harmonic performance

C) Details of the anticipated operating regime of generation, i.e. continuous, seasonal or other

D) The anticipated maximum net capacity level in MW for each calendar month, and indicate how generation would vary over a typical 24 hour period during the month of maximum net capacity

Ε) Details of expected rapid or frequent variations in output, including magnitude, max rate of change expected, frequency and duration.

13. Particularly for asynchronous generator excitation devices the following data shall also be supplied:

Α) the way in which the generator is run up to synchronous speed

Β) magnitude of inrush / starting current in Amps

C) duration of inrush / starting current in Ms;

D) starting / paralleling frequency in Hz;

Ε) power factor on starting;

F) reactive power demand at zero output ('no load') in KVar;

G) details of reactive power compensation to be installed

14. The following data are required for Generator Transformers:

Α) Number of windings

Β) Vector group

C) Rated current of each winding in Amps

D) Transformer Rating in MVATrans

Ε) Transformer nominal LV voltage in kV

F) Transformer nominal HV voltage in kV

G) Tapped winding

Η) Transformer Ratio at all transformer taps

I) Transformer Impedance at all taps as % on rating MVATrans

J) Transformer zero sequence impedance at nominal tap (Z0) in Ohm

K) Earthing Arrangement including neutral earthing resistance & reactance

L) Core construction (number of limbs, shell or core type)

M) Open circuit characteristic graph

15. The production license holder forecast data are submitted as follows:

Α) Expected Maintenance Requirements weeks / year

Β) Forecast availability during the time when units are not being maintained broken down in time and full availability, partial availability, and with an analysis of the causes for reduced availability such as poor fuel, loss of mill, loss of burners, hydro flow restrictions

C) Energy limitations, daily, weekly, monthly, annual in GWh

D) Expected Monthly Hydro Generation in GWh.

Article 296 Demand information

1. All System connected Customers and the Distribution Network Operator shall submit to the Transmission System Operator information required for the design, construction and operation of their connection. In addition, by May 31st each year they shall submit to the Transmission System Operator a demand forecast regarding their connection points for the following five (5) years by completing the relevant table created by the Transmission System Operator.

2. Customers connected to the System shall submit the following:

Α) the capacity that shall be the registered connection capacity in MW;

Β) single-line diagram of User plant to a level of detail to be agreed with the Transmission System Operator;

C) electrical characteristics of all 150kV and 400kV circuits and equipment (R, X, B, R0, X0, B0), continuous and overload ratings;

D) contribution from User plant to a three phase short circuit at connection point on the System side;

Ε) connection details of all transformers, shunt capacitors, shunt reactors etc. and other important equipment;

F) electrical characteristics of all 150kV circuits and equipment at a voltage lower than 50 kV that may form a closed tie between two connection points on the System;

G) information on the source of alternative standby supply and standby capacity required in MW.

3. For each load that can fluctuate by more than 5 MVA at the point of connection to the System, the following information is required:

Α) rate of change of Active Power and Reactive Power, both increasing and decreasing (kW/s. kVAr/s respectively);

Β) the shortest repetitive time interval between fluctuations in active power and reactive power demand (in seconds);

C) the magnitude of the largest step change in active power and reactive power demand (kWand KVAr respectively).

4. Description of any Load causing harmonics or any other significant disturbance to the operation of the System.

5. Data about System connected transformers:

Α) Number of windings

Β) Vector Group

C) Rated current of each winding in A

D) Transformer Rating in MVATrans

Ε) Transformer nominal MV voltage in KV

F) Transformer nominal HV voltage in KV

G) Tapped winding

Η) Transformer Ratio at all transformer taps

I) Transformer Impedance (resistance R and reactance X) at all taps (R+jX) as a % on rating MVATrans

J) For 3 winding transformers, where there are external connections to all 3 windings, the impedance (resistance R and reactance X) between each pair of windings is required, measured with the third set of terminals open-circuit (ZHV:LV1, ZHV:LV2, ZHV:LV3) as a % on rating MVATrans

K) Transformer zero sequence impedances at nominal tap:

(1) zero phase sequence impedance (ZHΤ0) measured between the HV terminals (shorted) and the neutral terminal, with the LV terminals open-circuit in Ohm;

(2) zero phase sequence impedance (ZHL0) measured between the HV terminals (shorted) and the neutral terminal, with the LV terminals short-circuited to the neutral in Ohm;

(3) zero phase sequence impedance (ZLT0) measured between the LV terminals (shorted) and the neutral terminal, with the HV terminals open-circuit in Ohm;

(4) zero phase sequence impedance (ZLH0) measured between the HV terminals (shorted) and the neutral terminal, with the HV terminals short-circuited to the neutral in Ohm;

(5) zero phase sequence leakage impedance (ZL0) measured between the HV terminals (shorted) and the neutral terminals (shorted), with the Delta winding closed in Ohm;

L) Earthing Arrangement plan including LV neutral earthing resistance & reactance, core construction and open circuit characteristics

M) Core construction (number of limbs, shell or core type

N) Open circuit characteristic graph

6. For each shunt capacitor or reactor with a rating in excess of 1 MVAr connected to or capable of being connected to a user plant, the following information must be provided:

Α) Rating in MVAr

Β) Resistance / Reactance / Susceptance of all components of the capacitor or reactor bank

C) Whether single or multiple step

D) In case of multiple step devices, control details (manual or not, required time for operation, load, voltage)

Ε) If automatic control is used, details of settings.

SECTION XI METERING EQUIPMENT

CHAPTER 57

METERING EQUIPMENT SPECIFICATIONS

Article 297 Metering equipment general specifications

1. Registered Meter metering equipment shall mean the equipment that includes a meter, recording and data transmission equipment and instrument transformers and concerns main meters and verification meters.

2. The Transmission System Operator shall prepare and keep a list with approved meter types which shall be made available to Users upon a relevant request.

3. The technical specifications and requirements for metering equipment are established by decision of the Minister of Development following the notification to European Commission of a relevant draft document in compliance with the requirements and procedures under Presidential Decree 39/2001 (Government Gazette Issue Α 28/20.02.2001), transposing Directive 1998/34/EC (OJL204/37 of 21.07.1998) and Directive 1998/48/EC (OJ L217/1998 of 05.08.1998). The specifications established in that decision shall apply to Registered MV Distribution Customer Meters until the Fifth Reference Day.

Article 298 Metering Point

1. The defined metering point shall be on the side of the point at which the User connects to either the Distribution Network or the System, as the case may be, as established in the respective connection contract.

2. Following the granting of approval by the Transmission System Operator, the real metering point may differ from the defined metering point.

3. When the real and defined metering points are different, any capacity transformer and line losses shall be adjusted in order to comply with the total required accuracy at the defined metering point. Such adjustment may be effected locally inside the metering equipment or remotely.

Article 299 User General Obligations

1. Each User must provide access to the Transmission System Operator and in particular to its employees, representatives and subcontractors to all parts of its installations if required to fulfill the obligations provided for in this Chapter. In particular, access right shall mean entry into, passage through and stay in the User’s site, as well as the installation and use of vehicles, machinery or other equipment at the User’s site required to fulfill the obligations provided for in this Chapter.

2. Each User shall see to the conclusion of and compliance with such agreements and forecasts that enable the exercise of the access right, as well as to the revision of such agreements and forecasts.

3. The Transmission System Operator may have access to all information concerning metering equipment which it deems necessary in order to ensure the good operation of the settlement system and the implementation of this Chapter.

4. Any changes to a given meter or the User in the name of which such meter has been registered shall be immediately notified to the Transmission System Operator.

SECTION XII CONNECTION TO AND USE OF THE SYSTEM

CHAPTER 58

PROCEDURE FOR CONNECTION TO THE SYSTEM

Article 300 Connection Contract

1. Minimum technical and operational specifications to be met for the reliable and safe operation of the System to the benefit of Users, as well as plants and apparatus connected to the System, as determined by the terms of the contract for connection to the System, as provided for in the provisions of CHAPTER 53 of this Code.

2. The terms of the contract on connection set out the minimum specifications in relation to:

Α) the method for connection to the System and ensuring smooth System operation and the point of connection;

Β) the type of signs and labeling which must be provided to the System Operator by each user; and

C) the terminology and nomenclature requirements used for all plants and apparatus connected to the System.

D) in case of thermal or hydro generation units, the special design and performance characteristics of the Unit in accordance with Article 275.

3. Connection contracts made between the Transmission System Operator and a specific user also include all special details in relation to connection to the System, in accordance with the provisions of this Code.

Article 301 User connection procedure

1. The Transmission System Operator shall adopt all necessary measures to ensure the immediate and uninterrupted new connection to the System and use thereof by the User in accordance with Community Law. To that end, it must propose a connection

offer to the User aiming at the conclusion of or amendment to a connection contract. During the study for the connection of a User the financially most advantageous and technically suitable way of connection to the existing System shall be selected each time in accordance with the N-1 reliability criterion and the requirements of this Code.

2. Users proposing a new connection site or modification of an existing connection site will need to submit to the Transmission System Operator a completed connection offer application form, including:

Α) description of the desired connection or modification of the user equipment already connected to the System (user development);

Β) the data listed in CHAPTER 56;

C) the desired connection date and operational date of the proposed user development.

3. Data supplied in the application form or data submitted along with the application form which has been submitted in support of it will be treated as preliminary project planning data until such time as the Transmission System Operator’s connection offer has been accepted by the User.

4. The Transmission System Operator shall process the user’s application within sixty (60) business days. If the Transmission System Operator considers the connection to be a complex one, the provisions of paragraph (8) hereof shall apply and the time required for processing the application may be extended, in exceptional circumstances. The user may appeal to RAE if it considers that the length of time for processing its application is unreasonable. In this case, RAE shall propose a new deadline for the submission of the application following assessment of data provided by the user and the Transmission System Operator.

5. The connection offer of the Transmission System Operator shall necessarily include the following::

Α) details of how the connection is to be made, including details of the equipment to be used at the connection;

Β) description of any modifications that the applicant user is required to pay for;

C) indication of the connection and operational date;

D) estimate of the charges for connection. The general terms that apply to the charges regarding the connection of User installations with the System, the calculation method for such charges and, where applicable, the budgeted unit cost for each type of expense shall be established in accordance with the provisions of the System Administration and Operation License Code.

Ε) the effect of the connection offer.

6. The applicant must accept or reject the connection offer within the period stated therein. Upon lapse of this period, the offer connection shall automatically cease to be in effect. Acceptance of the connection offer shall be effected by execution of the connection contract, which shall be binding upon the parties for the System development works agreed. The User is entitled to appeal to RAE if it disagrees with the connection offer. In that case, RAE shall decide taking account of the information provided by the User and the Transmission System Operator.

7. In accordance with the accepted connection offer, a connection contract shall be signed by virtue of which the parties thereto commit to performing the System development works agreed upon. Within 60 business days from signing of the connection contract, the user shall supply the data pertaining to the user development as listed in CHAPTER 56 and which concern the project to be executed. . This data shall be the committed project planning data.

8. Considering the magnitude and complexity of any System extension or reinforcement, which depends by the nature, location and timing of the proposed user connection works, the Transmission System Operator may carry out additional more extensive system studies, on a case basis, in order to evaluate more fully the impact of the proposed user development on the System. Where the Transmission System Operator judges that such additional more detailed studies are necessary, the Connection Offer may indicate the areas that require more detailed analysis. Before such additional studies are carried out, the user shall indicate whether it wishes Transmission System Operator to undertake the work necessary to proceed to make a revised connection offer. The Transmission System Operator may carry out these additional studies itself or employ a competent consultant to perform the studies and in either case it may recover the reasonable cost of these studies from the user. .

9. To enable Transmission System Operator to carry out any of the studies provided for in the preceding paragraph, the User may, at the request of Transmission System Operator, be required to supply the data items reasonably necessary, which are listed in CHAPTER 56, prior to lapse of the deadline laid down in paragraph (7) of this Article. This data shall be treated as preliminary project planning data.

10. When planning the System, the Transmission System Operator may reasonably request one or more users to modify their plants or install new equipment. Where the user deems that such requirement is not feasible for technical reasons or disagrees with the cost involved, it may appeal to RAE. In this case, following approval by RAE, the Transmission System Operator and the user shall enter into an agreement to cover the cost incurred by the user due to such modification or installation.

Article 302 Technical Specifications

1. For the construction of a Transmission Substation and the installation of all other necessary equipment for the connection of user plant to the System, the user must avail of a fenced area, as provided for in the connection contract, adjacent to its plant or at any other location accepted by the Transmission System Operator.

2. Connection to the System must meet the minimum requirements laid down in this Section and in SECTION VIII. The connection method applied may meet stricter specifications than the above, where agreed between the user and the Transmission System Operator.

3. The limit between the System and user installations shall be the interrupter (circuit breaker or disconnector) at the high-voltage side of the power transformer of the user. Each individual issue on the limits and the more specific determination and allocation of liability between the two parties is defined in the connection contract.

4. Each user's plant and apparatus related to its connection to the System must meet the relevant European specifications adopted by ELOT or apply as national standards, if any, or the specifications normally applied in the European Union, in force at the commencement of the connection contract.

5. Where the Transmission System Operator reasonably considers that the safe and coordinated operation of the user’s plant and apparatus with the System requires the application of complementary terms or specifications, the Transmission System Operator shall notify the user. The user must comply with the Operator’s complementary requirements and is entitled to request that the Transmission System Operator procure information proving the need to apply such complementary terms and specification.

6. The user may propose to the Transmission System Operator that such complementary terms or specifications be amended. The Transmission System Operator shall decide thereon following the approval of RAE.

CHAPTER 59

USER CONNECTION WORKS

Article 303 Special connection terms

1. The confines between the System and the installation of a System User are set by a switching apparatus (circuit breaker or disconnector) located at the high voltage side of the User power transformer. Such apparatus shall belong to the user. Detailed provisions in this regard and other issues shall be the competence and responsibility of both parties and shall be stipulated by the respective connection contract.

2. The works required for the connection of new users to the System are divided into extension works for connection and reinforcement works due to connection. Extension works for the connection include the equipment and plant required for the connection from the user’s plant limit to the System. Reinforcement works due to the connection include those required in addition to the existing System due to connection and which are not extension works for Connection.

3. A full transmission line bay shall be the bay containing a transmission line disconnector and circuit breaker and busbar(s) disconnector(s). A simple transmission line bay shall be a bay containing only one disconnector.

4. The Transmission System Operator shall, upon request by the User, examine whether the system conditions prevalent at the existing or planned System connection Node (power available at the supply terminals, short-circuit power, reliability, etc.) are sufficient for operation of the latter’s installation without risk to the operation of the remaining Transmission System Users’ installations and without unacceptable disturbances (stability, flicker, harmonics, step-type voltage changes, violation of short-circuit limit values) to the System, and for electrical power/ energy transfer from the System to User connection points.

5. The User, shall supply the Transmission System Operator with all technical and operating data required for evaluation of the supply connection (e.g. power gradients, harmonics etc.) and shall cooperate in the search for technical solutions.

Article 304 Customer and Distribution Network Connection

1. Extension works for the connection of a User’s installation shall be dependent upon the System being dimensioned at least in accordance with the N-1 criterion. This

minimum requirement may be waived at the request of the User on condition that unacceptable effects under N-1 conditions are avoided. This provision shall require separate agreement governing priority outages of the supply connection in order to avoid risks to the System. Should the system conditions at the system point of connection suffice for operation of the User’s System under the conditions stated above, the Transmission System Operator shall specify the system connection.

2. The detailed system connection shall be specialized in the relevant study carried out under responsibility of the Transmission System Operator on the basis of the requirements set out in the present Code, the data submitted by applicants and the user's special requirements. During the design the following are particularly complied with:

Α) if the connection is made to an existing System substation, this shall include at least one full transmission line bay in the substation from which connection is effected, the transmission line works, the respective simple or full transmission line bay at the user's HV busbars, as well as any other works required in accordance with the Code concerning the connection;

Β) if connection is effected at an intermediate point of an existing System transmission line, it shall be normally effected with an input-output of double circuit transmission line, at least of the same type as the transmission line on which connection is effected and full or simple transmission line bays on the user’s HV busbars.

Article 305 Generation Unit connection

1. In order for a generation unit to be connected to the System, the most cost efficient and technically acceptable connection mode shall be selected in accordance with the reliability N-1 criterion and the requirements of the present Code. Particularly with regard to generation by wind generators, due to the probabilistic nature of such generation, the criterion N-1 may not apply if, at the Transmission System Operator discretion, System reliability is not jeopardized. .

2. With regard to the connection to the System of a generation unit the following shall be particularly complied with:

Α) if the connection is effected at a node or nodes of the existing System it shall include full transmission line bays at the substation from where connection is effected, the transmission line works and the respective full transmission line bays at the generation unit HV busbars. The transmission line bays at the generation unit HV busbars shall, by exception, be of the simple type in the case of generation by wind generators, provided that System reliability is not jeopardized;

Β) if connection is effected at an intermediate point of an existing transmission line of the System, this shall be effected with an input-output of a transmission line double circuit, at least of the same type as the transmission line on which connection is effected, full transmission line bays at the generation unit HV busbars, as well as any works required in accordance with the present Code for the effectuation of the connection. The transmission line bays at the generation unit HV busbars shall, by exception, be of the simple type in the case of generation by wind generators, provided that System reliability is not jeopardized.

Article 306 Execution of extension works for connection

1. The technical specifications of extension works for the connection of new Users are laid down in this Chapter. The extension works for the connection of new Users for which connection contracts have been concluded are included in the TSDS. Moreover, the TSDS also provides a brief description of the works for which connection terms have been issued and the relevant contracts have not been signed.

2. In any case, the cost for the implementation and commissioning of the connection extension works, including the costs for land expropriation and any other expenses shall be exclusively borne by the applicant. Ownership of such works shall pass to the System Owner and shall be a connection fixed cost.

3. Should more than one users be connected or should a new user be connected in the future at a point included in the extension works for connection, then the new user shall assume part of the connection cost, following allocation on the basis of the installed capacity, from the date of its connection, also taking into account the respective financial expenses. The allocation method details and the method the previous users are refunded shall be determined by the Transmission System Operator and are subject to approval by RAE.

CHAPTER 60

TRANSMISSION USE OF SYSTEM CHARGES


1. Summer peak in a year shall be the hour during which the average hourly demand on the System reaches its maximum value in June, July, August.

2. Winter peak in a year shall be the hour during which the average hourly demand on the System reaches its maximum value in the rest of the months of the year in question.

3. Power torque shall mean the product of multiplying the active power transferred by a circuit by the distance over which it is transferred and is expressed in MW.km.

4. Distribution Network Dispersed Generation Factor for each hour shall be the following:

(ΖS/S) / (ΖS/S + GP)

where

ΖS/S is the sum of the measurements of injected power at all substations connecting the Distribution Network to the System during that hour and

GP the total generated output of the units that are connected to the Distribution Network during that hour.

5. Generation unit chargeable capacity shall mean: :

Α) for thermal units, the maximum net capacity registered on the production license;

Β) for hydro plants, 50% of the maximum net capacity registered on the production license;

C) for the units under Article 35 of Law 2773/99:

(1) 50% of the maximum net capacity registered on the production license, provided they are connected either directly to the System or through a MV/HV step-up transformer from which no MV lines depart supplying consumers;

(2) Zero (0) for those units under Article 35 of Law 2773/99 that do not fall under the scope of paragraph (1) above.

D) for Auto-Producer units not falling within the scope of Article 35 of Law 2773/1999, Unit Net Capacity NCAP , as is calculated in accordance with Article 217.

6. The customer chargeable capacity shall be determined annually and calculated as follows:

Α) for each customer connected to the System, the chargeable capacity shall be calculated as the average of the following three values:

(1) of the average hourly demand of such customer at summer peak ;

(2) of the average hourly demand of such customer at winter peak; and

(3) the average hourly demand of such customer at the hour of his own maximum demand during the year in question.

Β) for each customer connected to the Distribution Network, the average hourly demand shall be the measured value of the average hourly demand increased by the Distribution Network losses corresponding to such customer and the chargeable capacity shall be calculated as the average of the following three values:

(1) the product of multiplying the average hourly demand of such customer at summer peak by the respective Distribution Network Dispersed Generation Factor at summer peak;

(2) the product of multiplying the average hourly demand of such customer at winter peak by the respective Distribution Network Dispersed Generation Factor at winter peak; and

(3) the product of multiplying the average hourly demand of such customer at the hour of his own maximum demand in the year in question by the respective Distribution Network Dispersed Generation Factor for that hour .

C) more specifically, chargeable capacity of customers connected to the System at low voltage shall be calculated in aggregate as the average of the following three values:

(1) the product of multiplying the average hourly demand of the total of such customers at summer peak by the respective Distribution Network Dispersed Generation Factor at summer peak;

(2) the product of multiplying the average hourly demand of the total of such customers at winter peak by the respective Distribution Network Dispersed Generation Factor at winter peak; and

(3) the product of multiplying the maximum hourly demand of the total of such customers during the year in question by the respective Distribution Network Dispersed Generation Factor during that hour.

The value of the average hourly power consumed in total by customers connected to low voltage shall be calculated as the sum of the power consumption measurements of all substations connecting the Distribution Network to the System during the hour in question and the total power generation that is connected to the Distribution Network during that same hour, reduced by the total demand of eligible customers that are connected to average voltage, as is measured during that hour increased by the Distribution Network losses corresponding to the latter customers.

D) those Eligible Customers that are connected to medium voltage and have not yet been equipped with a metering equipment for hourly measurements shall be treated as customers connected to low voltage in terms of their chargeable capacity.

Article 308 Annual System Cost

1. The Transmission System Operator shall calculate the annual System cost using the following equation:

A = A1 + A2 ± C1± C2

Where

A is the annual System cost

A1 the annual remunation owed by the Transmission System Operator to the System Owner, in accordance with the provisions of Article 18 paragraph (4) of Law 2773/1999 and is calculated in accordance with the provisions of this Article

A2 is the annual cost of System works borne by the Transmission System Operator

C1 is the non recovered cost (+) or surplus (-) during the current fiscal year from generation units, as calculated in accordance with Article 310 paragraph (1) (C); and

C2 is the non recovered cost (+) or surplus (-) from customers as calculated pursuant to Article 310 paragraph (1) (C).

2. The remuneration owed to the System Owner by the Transmission System Operator on a yearly basis and which corresponds to variable A1, shall be calculated as follows:

A1 = Ο + Α + (V – D) × r

where

Ο is the annual operation and maintenance expenses, as well as indirect expenses, borne by the System Owner, as are budgeted using the accounting unbundling rules. Such expenses include maintenance expenses for the User connection assets.

Α is the annual depreciation of transmission assets, as are budgeted using the accounting unbundling rules

V-D is the average of the total invested transmission capital, including equity and debt, in the beginning and at the end of the year, as they result from the accounting unbundling rules where:

V is the budgeted average initial value of fixed assets based on accepted valuation methods and the working transmission capital

D is the budgeted average value of cumulative depreciation of transmission fixed assets

r is the nominal yield percentage of the invested transmission capital pre-tax, which is accepted by RAE in accordance with the applicable regulatory policy and international practice and experience.

Article 309 System use charge method

1. The Transmission System Operator shall allocate the annual System cost to all System users and shall calculate a charge for each one of them. Generation units under Article 35 of Law 2773/1999 shall not be charged with that sum, which shall be entered as expense in Uplift Account UA-7 held by the Transmission System Operator. Such sum shall be entered as collection for the Use of System Charge Account A-H and the Transmission System Operator shall see to the transfer of the relevant funds following the procedure established for such accounts.

2. The charge corresponding to each user shall be budgeted on an annual basis and shall be the product of multiplying the user’s chargeable capacity by the unit charge corresponding to such user. The unit charge shall be in Euro/MW. The charge for generation units for using the System does not change due to scheduled shut down of such units due to maintenance or fault, unless it is the case of final shut down of the Unit.

3. Within one month from the end of each year, the Transmission System Operator shall settle the system use charges corresponding to each User based on the Metering Data concerning the User's chargeable capacity of the User in the previous year.

4. The annual System cost shall be allocated to all generation units and customers as follows:

Α) generation units shall be allocated 2% of the sum of A1 and A2 increased or decreased by C1 corresponding to non recovered cost (+) or surplus (-) during the previous fiscal year from the generation units;

Β) 13% of the sum of A1 and A2 increased or decreased by C1 corresponding to non recovered cost (+) or surplus (-) from generation units during the previous fiscal year, shall be allocated to all generation units installed in the Prefectures of Evros, Rodopi, Xanthi, Drama, Kavala, Thessaloniki, Halkidiki, Kilkis, Serres, Pieria, Grevena, Florina, Pella, Imathia, Kastoria, Kozani, Larissa, Trikala, Karditsa, Magnisis, Fthiotida, Thesprotia, Preveza, Ioannina, Arta, Kefallinia, Lefkada, Zakinthos, and Corfu;

C) all customers shall be allocated 85% of the sum of A1 and A2 increased or decreased by C2 corresponding to non recovered cost (+) or surplus (-) during the previous fiscal year from customers.

5. RAE shall evaluate the allocation percentages for the annual System cost under paragraph (4), taking account of the maintenance cost for the Generation Unit connection assets, the cost of System Inter-Zonal Constraints, as well as the forecast or possible cost of new System development works and issue a relevant opinion to the Minister of Development. By January 1st, 2008 at the latest, RAE must issue an opinion on the maintenance or readjustment of the allocation percentages for the annual System cost in accordance with paragraph (4) taking into consideration the results of the application of the DAS Clearing method with System Inter-Zonal Constraints in accordance with Article 321. The Minister of Development shall decide on the maintenance or readjustment of such allocation percentages every three years.

6. The unit charge for each customer shall be the same throughout the territory and shall be the product of dividing the annual transmission cost allocated to customers by the sum of customers’ chargeable capacities.

7. The unit charge for generation units varies among the Units under cases (Α) and (Β) of paragraph (4) and shall be the result of dividing the annual System cost allocated to production license holders under cases (Α) and (Β) of paragraph (4) divided by the sum of the chargeable capacities of such Users respectively.

Article 310 Procedure for the approval of annual System cost and unit

charges

1. By September 30th each year, the Transmission System Operator shall draft the budget for the following year, which shall include:

Α) annual System cost as calculated in accordance with Article 308;

Β) budgeted revenues earned by the Transmission System Operator from the Use of System charge for the following fiscal year based on the unit charges calculated under Article 309 and the anticipated total energy demand of the System;

C) any difference between the sum collected by the Transmission System Operator from generation units and customers due to use of the System and the real transmission cost during the current fiscal year, which shall be credited or debited to the transmission cost budget for the following year.

The Transmission System Operator’s operating expenses are not included.

2. The budget of the annual System cost, including but not limited to the annual remuneration owed to the System Owner, the annual System cost and the unit charges for System use shall be subject to approval by RAE.

3. Following approval of the budget, the Transmission System Operator shall, by October 31st each year, calculate anew, if necessary, the unit charge corresponding to customers and generation units for each charge zone for the following fiscal year.

4. Unit charges for System use shall be approved by the Minister of Development following the issue of RAE’s opinion.

CHAPTER 61

INTERCONNECTION ADMINISTRATION

Article 311 Interconnection transmission capacity

1. For each interconnection or group of interconnections, the Transmission System Operator shall determine:

Α) total transmission capacity;

Β) transmission reliability margin for the proper operation of the interconnection;

C) net transmission capacity expressed as the difference between total transmission capacity and transmission reliability margin;

D) long-term committed transmission capacity; and

Ε) available transmission capacity separately for energy Imports and Exports.

2. Total transmission capacity, transmission reliability margin and net transmission capacity shall be determined in consultation with the operators of the respective transmission systems outside of Greece for each Dispatch Period of each Dispatch Day, three days prior to the respective dispatch day, and shall be posted to the Transmission System Operator website by 14:00 hours on that day.

3. Available transmission capacity of each Dispatch Period of each Dispatch Day shall be determined by the Transmission System Operator, and shall be posted to the Transmission System Operator website two (2) days prior to the respective dispatch day and until 14:00 hours on that day.

4. Subject to RAE approval, it shall be possible to place restrictions to energy Transits through interconnections in order to ensure priority to the uninterrupted and secure operation of the Greek energy market.

Article 312 Interconnection access right

1. The following categories of users shall have the right to access interconnections, in accordance with the terms of their licenses:

Α) supply license holders to exercise the right to Import, Export, Transit energy through interconnections;

Β) production license holders to exercise the right to exPort energy through interconnections;

C) Eligible Customers to exercise the right to Import energy, exclusively for their own use.

2. Energy Transit shall mean the concurrent, namely during the same Dispatch Period, Import and Export of energy by the same participant, regardless of the capacity in which such Participant carries out such concurrent Import and Export. The energy quantity transited by a Participant during a Dispatch Period shall be calculated as the minimum between the absolute value of all Imports and the absolute value of all Exports performed by such Participant in the same Dispatch Period. Imports and Exports, including those involved during energy Transits, shall be effected after having been included in the DAS Schedule based on Energy Offers from Imports and Load Declarations for Exports respectively.

Article 313 Long-term allocation

1. The Transmission System Operator shall assign transmission capacity at interconnections to interested parties on a long-term basis of up to one (1) year.

2. In order to use interconnections, a beneficiary may reserve the respective transmission capacity at the interconnections it intends to use in the long run, for a fee which may also be set to zero. The Transmission System Operator shall manage the revenues earned from the above fees in accordance with the provisions on Account A-M. The Transmission System Operator shall manage the expenses pertaining to emergency imports carried out by themselves in case of Emergency in accordance with the provisions on Uplift Account UA-3.

3. Assignment of power on a long-term basis shall be made as follows:

Α) the Transmission System Operator, subject to the approval of RAE, shall regularly announce the capacity band that is made available on a long-term basis in each direction for each interconnecting line or line-group, and the minimum commitment fee in Euros/ MW per allocation period, and shall proclaim a tender

for capacity assignment, at the same time specifying the procedure for the submission of tenders, the terms of the tender procedure and particularly the starting price, as well as the maximum permitted percentage of total capacity commitment by each interested party. More specifically, such tenders may concern the concurrent allocation of interconnection capability for one or more interconnections;

Β) interested parties shall be registered in a list, sorted from highest to lowest bidder;

C) starting from the highest bidder, those whose request can be satisfied with the proclaimed available capacity band shall be selected from the list. Those selected shall each sign a relevant contract, for the power requested for the period and for the same fee, equal to that offered for the first MW not selected. If the requests of all applicants are satisfied, no fee shall be paid.

4. In cases of emergency and in order to ensure secure energy supply to the Country or protect fair competition, the Transmission System Operator may, subject to approval by RAE, establish the interconnection capacity reservation fee at a fixed amount in € per MW.

5. Beneficiaries who have committed a certain transmission capacity band on a long-term basis must pay the fee for commitment in all cases, even where this zone remains unused either due to non-inclusion in the DAS Schedule or otherwise.

Article 314 Other charges for use of interconnections

1. No fees will be charged for System use during import, where this applies to the country of origin, under the reciprocity rule.

2. To the extent that System use is charged for the transmission of energy through interconnections, suppliers must also pay for the charge for use of the Greek System. The charge applies to the quantity of imported energy in proportion to the System charge for generation units and shall be charged on imported KWh with 1/6 of a millionth of the annual use charge per MW.

3. Imports will be charged with System losses based on the method and loss factor applicable for generation in the zone of import.

4. In respect of power transits, the Transmission System Operator may recover any additional incurred costs, subject to approval from RAE. For this purpose, the Transmission System Operator may impose charges on interested parties for System use and additional losses which might be caused to the System.

5. The Transmission System Operator shall establish the nodes through which energy imported to Greece (Import Nodes) is delivered to the System, as well as the nodes through which energy is delivered from the System in order to be exported (Export

Nodes). For the needs of Day Ahead Scheduling, Imbalances Settlement and the allocation of interconnection transmission capability, the Transmission System Operator may establish virtual or physical Export and Import Interconnection Corridors.

SECTION XIII FINAL PROVISIONS

CHAPTER 62

FINAL PROVISIONS

Article 315 Exemptions from the obligation to comply with the provisions

of this Code

1. Exemption from compliance with the provisions of this Code shall be granted by decision of the Minister of Development, issued following a motion presented by the Transmission System Operator and the issue of RAE's opinion. Such exemption shall be in force for a set and reasonable period and may concern only technical inability of a User's installations to comply with the provisions of this Code. For an exemption to be granted, the interested party shall submit a request to the Transmission System Operator. The conditions under which such exemption shall be granted are:

Α) the exemption must not lead to direct or indirect breach of a term of such person's license;

Β) final settlement with regard to the most recent Dispatch Day must have been completed;

C) all ammounts due in accordance with this Code must have been paid in full;

D) no breach which can be remedied by such person is pending.

2. The request of an interested party for the granting of the exemption shall also include a declaration by such person as to the date on which the requirements under the previous paragraph are met.

3. The decision of the Minister of Development granting the exemption shall establish the date of entry into force of the exemption. Such exemption may not enter in force prior to 15:00 hours on the fifth business day following the day on which it is ascertained that the above requirements are met.

4. In any case, the person to whom such exemption has been granted shall continue to be liable in accordance with the provisions of this Code:

Α) for ammounts owed under this Code that concern the period prior to the entry into force of the exemption; and

Β) for breaches of this Code that have been committed prior to the entry into force of such exemption and which have not been remedied.

5. The Transmission System Operator shall keep a special protocol where it shall enter the details and the terms for the exemptions granted. All Users may have access to such protocol upon request.

Article 316 Units under Article 35 of Law 2773/1999

The Transmission System Operator shall enter into a purchase contract with all production license holders for Units under Article 35 of Law 2773/1999 and which are installed in mainland Greece and on islands the distribution network of which is connected to the mainland System or Distribution Network for the energy generated by such units.

Article 317 Placing PPC SA units in Cold Reserve

1. Within two (2) months from the commencement of the commercial operation of PPC units that receive a production license in accordance with the provisions of Article 19 paragraph (2) (g) of Law 2773/1999, as has been amended by Article 23 paragraph (12) of Law 3175/2003 and more specifically in the context of the section on the 1600 MW capacity, as well as of units to which a production license has been issued prior to the issue of this Code, which includes a term for placing old units in cold reserve, and of units the production license of which includes an equivalent term, PPC must place in cold reserve Dispatchable Units that are covered by the single production license, for a total capacity equal to the capacity of each unit which is placed in commercial operation. The units to be placed in cold reserve shall be established following the submission of a relevant techno-economic study by PPC two (2) months prior to the anticipated commencement of the commercial operation of the new units, and shall be approved by decision of the Minister of Development following the issue of RAE's opinion.

2. Once the units to be placed in cold reserve have been established, PPC shall, within the period set out in the previous paragraph, enter into the relevant contract with the Transmission System Operator under which the latter shall undertake to manage each unit placed in cold reserve in accordance with this Code. Such contracts shall be subject to approval by the Minister of Development following the issue of RAE's opinion. The contents of such contracts shall be established in accordance with this Code.

Article 318 Long-term capacity availability guarantees regarding the issue

of supply licenses

In the context of the procedure for the granting of supply licenses under the Energy Supply and Production License Code it shall be verified whether the conditions of Article 24 paragraph (2) (b) of Law 2773/1999 are met in terms of the long-term capacity availability guarantees from adequate generation capacity installed in a European Union Member State. To that end, the applicants shall submit declarations stating compliance with the provisions of this Code, including the provisions on the Capacity Assurance Mechanism, as well as those on the submission of Energy Offers from Import.

Article 319 Validity of Standards

1. All references in this Code to Standards (national or European or international) shall be for illustration purposes. Equivalent standards may be used in the following order of priority:

Α) European Standards (CEN, CENELEC or ETSI) adopted by ELOT as national;

Β) European Standards (CEN, CENELEC or ETSI);

C) International Standards (ISO, IEC or ITU) adopted by ELOT as national;

D) International Standards (ISO, IEC or ITU);

Ε) National Standards of other European Union and European Free Trade Area Member States;

F) National Standards of other countries.

2. In any case, besides the standards under (Α), (Β) and (C) above, the equivalence of each Standard used must be demonstrated by the party employing such standards.

SECTION XIV TRANSITIONAL PROVISIONS

CHAPTER 63

TRANSITIONAL PROVISIONS

Article 320 Entry into Force

1. The following reference days and periods are established:

Α) January 1st, 2008 as the Fifth Reference Day;

Β) July 1st, 2007 as the Fourth Reference Day;

C) July 1st, 2006 as the Third Reference Day;

D) January 1st, 2006 as the Second Reference Day;

Ε) October 1st, 2005 as the First Reference Day;

F) the period between the First and Fifth Reference Days as the Transitional Period;

G) the period of the year starting on October 1st, 200t as the first Reliability Year.

2. The implementation of all of the provisions in this Code shall start on the Fifth Reference Day.

3. The First Reference Day the following provisions of this Code shall enter into force:

Α) the provisions of SECTION I, notwithstanding the provisions of Article 334 paragraph (4);

Β) the provisions of Article 16, Article 23, Article 28, and CHAPTER 8 with the exception of the provisions of Article 40 paragraphs (3) and (4);

C) the provisions of CHAPTER 9 with the exception of the provisions of Article 46 paragraphs (4) and (5), the provisions of CHAPTER 10, CHAPTER 11, and Article 72;

D) the provisions of SECTION III, with the exception of the provisions of Article 82, Article 84, Article 85, Article 86, Article 92 paragraphs (2) and (3), and Article 95, Article 97, Article 98 and Article 99;

Ε) the provisions of SECTION IV, with the exception of the provisions of CHAPTER 27;

F) the provisions of SECTION V;

G) the provisions of SECTION VIII to SECTION XIII, with the exception of the provisions of CHAPTER 60.

4. The provisions of SECTION XIV shall apply during the Transitional Period, unless otherwise specified under specific provisions of such Section.

5. The provisions of Article 330 to Article 333 as well as those of SECTION VII, with the exception of the provisions of Article 222 paragraph (3), shall enter into force on the Second Reference Day, unless otherwise specified by more specific provisions of SECTION XIV of the Code.

6. The Manuals under this Code shall be approved until the Fifth Reference Day following a relevant public consultation. Specifically the Meter Administration and Distribution Network Suppliers Periodical Settlement Manual shall be approved by the First Reference Day.

7. Until the Fifth Reference Day the provisions of the Powerf Exchange Code (Government Gazette Issue No. Β 623/2001) shall continue to be in force to the extent that they do not oppose to the applicable provisions of this Code. More specifically, on the First Reference Day the provisions of Chapter K of the Power Exchange Code (Government Gazette Issue No. Β 623/2001) shall cease to be in force.

8. On the First Reference Day the provisions of the Grid Control Code (Government Gazette Issue No. Β 654/2001), as has been supplemented and is in force, shall cease to be in force. Exceptionally: a) the validity of the provisions of Article 177 of the Grid Control Code (Government Gazette Issues No. Β 1440/2001 and B 1560/2004) shall not be affected until expiry of such validity; and b) with regard to Chapter X on Use of System charges the provisions of Article 329 shall apply, and the validity of the provisions of such Chapter of the Grid Control Code shall expire upon cessation of their implementation.

9. The validity of the contracts that have been entered into under the provision of Article 178 of the Grid Control Code (Government Gazette Issue No. Β 1644/2003) shall not be affected, and such contracts shall remain in force until their expiry in accordance with their terms and conditions. Details regarding the inclusion of such Units in the scope of the provisions of this Code shall be established by RAE decision.

10. By the Fifth Reference Day, the Transmission System Operator shall take all necessary actions to complete the transactions and settle the accounts it keeps in accordance with the Power Exchange Code (Government Gazette Issue No. Β 623/2001) and SECTION XIV of this Code. Details with regard to the settlement of accounts and in particular the transfer of balances to new accounts provided for in this

Code, shall be established by decision of the Transmission System Operator, subject to approval by RAE, and published in the Government Gazette.

Article 321 Transitional provisions regarding Day Ahead Scheduling

1. With regard to Day Ahead Scheduling, the provisions of Article 322 on the procedures with regard to the Day Ahead Schedule (DAS) and of Article 323 on DAS Clearing without System Inter-Zonal Constraints shall enter into force on the First Reference Day.

2. The procedure for DAS Clearing with System Inter-Zonal Constraints in accordance with Article 324 shall enter into force on the Fourth Reference Day, and the validity of the provisions of Article 323 of this Code, as well as of those of Article 43 of the Power Exchange Code (Government Gazette Issue No.Β 623/2001) shall expire on that same day.

3. The Transmission System Operator must, from the Third Reference Day at the latest, systematically implement an indicative DAS Clearing with System Inter-Zonal Constraints in accordance with Article 324, and calculate indicatively the relevant transaction settlement. Such clearing, as well as the relevant transaction settlement, shall be indicative until the Fourth Reference Day, and shall be performed in parallel with DAS Clearing without System Inter-Zonal Constraints in accordance with Article 323.

4. The results of the indicative DAS Clearing with System Inter-Zonal Constraints and the indicative relevant settlement, shall be compared to the equivalent results of DAS Clearing without System Inter-Zonal Constraints and the relevant settlement. Such comparison aims at verifying the validity and reliability of the methods implemented for DAS clearing and settlement with System Inter-Zonal Constraints. The Transmission System Operator shall prepare and notify to RAE on a monthly basis reports with regard to the results of the comparison of the two DAS clearing methods, which reports shall include results with regard to the validity and reliability of the methods used for DAS Clearing with System Inter-Zonal Constraints, as well as motion on the time schedule for the development of the methodology which in each case must be completed at the latest within six (6) months form the Fourth Reference Day.

5. Taking account of the above reports and motions of the Transmission System Operator, RAE shall approve the method for DAS Clearing with System Inter-Zonal Constraints in accordance with Article 324.

6. Following such approval by RAE of the method for DAS Clearing with System Inter-Zonal Constraints and until the Fourth Reference Day, the Transmission System Operator shall make public cumulative information about DAS Schedule Clearing

with System Inter-Zonal Constraints subject to compliance with the confidentiality principle governing commercial transactions, and notify to Participants the information about the indicative DAS Clearing and transaction settlement with System Inter-Zonal Constraints concerning them. Furthermore, following approval of the method for DAS Clearing with System Inter-Zonal Constraints, the Transmission System Operator shall also apply such method to the Dispatch Days between the Third Reference Day and the day of approval of the method, and make public and notify to Participants the indicative information established in this paragraph pertaining to such period.

Article 322 Procedures regarding Day Ahead Scheduling

1. The scheduling of the operation of generation units and Interconnections (Day Ahead Scheduling) shall be carried out by the Transmission System Operator. With regard to Day Ahead Scheduling, the Transmission System Operator shall collect information about the availability of centrally dispatchable generation units, the availability of ancillary services, Daily Energy Offers, the System load, and the operational characteristics of centrally dispatchable units and the System.

2. Production license holders shall submit for each Unit a Techno-Economic Declaration which shall include the information under Article 44. It shall be the responsibility of the production license holder to update such Techno-Economic Declaration. When preparing the DAS Schedule, account shall be taken of the Techno-Economic Declaration for each Unit that is in force as at 12:00 hours on the day prior to the reference Dispatch Day.

3. By 12:00 hours each day, an Energy Offer shall be submitted for each Unit and for energy imports for each Dispatch Period of the following Dispatch Day. If the Transmission System Operator has not received the Energy Offer for a Unit in due time and in accordance with the provisions of this Article, it shall calculate the price for the energy offered by such unit, to the extent that this is technically available, for each Dispatch Period of the Dispatch Day in accordance with Article 83.

4. With regard to Energy Offers pertaining to Dispatch Days up until the Third Reference Day, the following shall apply:

Α) the Energy Offer shall establish stepwise functions for all Dispatch Periods of the Dispatch Day, each step of which shall comprise one price energy pair in €/MWh and MWh respectively;

Β) each Energy Offer corresponding to a Unit shall include a stepwise function which shall apply for all Dispatch Periods of the Dispatch Day;

C) the stepwise function shall comprise at the most three (3) successive steps of monotonically increasing prices which in total correspond to such Unit's maximum continuous generation capability on the Dispatch Day;

D) the energy price at each step of the stepwise function of the Energy Offer must be less than the Administratively Defined Energy Offer Cap, which is established by justified decision of RAE, and may not be less than the Minimum Variable Cost of the Unit as such limits apply during the Dispatch Period to which the Energy Offer corresponds. Specifically for Hydro Units, in terms of the implementation of the provisions of this paragraph, Minimum Variable Cost shall mean the variable cost for the Unit established in Article 44 paragraph (4);

Ε) the Transmission System Operator shall submit for each Hydro Unit, including Hydro Pumping Units, energy offers corresponding to the Unit’s mandatory operations, in accordance with the respective Weekly Mandatory Hydro Operations Declaration. No energy price shall be established for such energy quantity and during DAS clearing such price shall be taken equal to zero (0);

F) Energy Offers for energy import through interconnections shall be submitted by supply license holders and Self-Supplying Customers, and besides the information established under paragraphs (Α) to (C) above shall also include:

(1) establishment of the neighboring transmission system through which energy is to be supplied to the Greek System;

(2) a declaration that the transfer through transmission system outside Greece of the energy offered for the specific Dispatch Day has been ensured;

(3) the type of the Energy Offer, any additional information, such as the way of communication shall be established in accordance with the instructions of UCTE.

G) Energy Offers not meeting the conditions of this Article shall, by a justified decision of the Transmission System Operator, be considered invalid. In that case, the Transmission System Operator shall inform the party submitting the Energy Offer as soon as possible after receipt of the Offer;

Η) in case of invalidity of the Energy Offer, the party submitting it is entitled to submit anew an Energy Offer by 12:00 hours on the day prior to the Dispatch Day.

5. The following shall apply with regard to Load Declarations concerning Dispatch Days up until and including the Dispatch Day before the Third Reference Day:

Α) Load Representatives shall submit Load Declarations in accordance with Article 16;

Β) more specifically, Load Declarations for energy exports shall be submitted by the beneficiaries of production or supply license holders until 10:00 hours on the second day before the Dispatch Day, and they shall specify the following:

(1) the capacity that is desirable to be exported to each neighboring transmission system for each Dispatch Period of the Dispatch Day in MW;

(2) the type of the Load Declaration, any additional information, such as the way of communication shall be established in accordance with the instructions of UCTE..

6. The following of provisions of this Code shall apply with regard to the Energy Offers and Load Declarations submitted top the DAS for Dispatch Days between the Third Reference Day and on:

Α) the provisions of Article 17, Article 19, Article 20, Article 21 paragraph (1), and Article 22;

Β) the provisions of Article 24 to Article 27, and Article 29 to Article 31.

7. Under no circumstances may the information in Energy Offers be modified past the deadline for their submission.

8. Production license holders are required to keep the Units for which it has submitted an Energy Offer available in accordance with the terms of the Offer and the Techno-Economic Declaration for the period from the submission of the Offer until the Dispatch Period it concerns.

9. By 16:00 hours each day, the Transmission System Operator shall prepare the DAS Schedule that concerns the operation of the Units and the load of interconnections based on the Energy Offers and the Load Forecast for the Dispatch Day. The DAS Schedule may also be prepared at the end of the above deadline in case of serious reasons.

10. By 16:30 hours each day, the Transmission System Operator shall notify to the parties submitting Energy Offers or Load Declarations the part of the DAS Schedule that concerns them.

11. By 16:30 each day, the Transmission System Operator shall post in its website the Forecasted System Marginal Price for each Dispatch Period of the Dispatch Day.

12. The DAS Schedule is not a dispatch instruction and is indicative in terms of the scheduling of the generation unit operation.

Article 323 Day Ahead Scheduling Clearing without System Inter-Zonal

Constraints

1. The following apply with regard to Day Ahead Scheduling Clearing without System Inter-Zonal Constraints for Dispatch Days up until the day before the Third Reference Day:

Α) the DAS Schedule without System Inter-Zonal Constraints aims at minimizing the total expense incurred on the Dispatch Day to meet the total load, and is prepared in the same way as the Unconstrained on the Transmission System Schedule under Article 43 paragraph (5) of the Power Exchange Code (Government Gazette Issue No. Β 623/2001);

Β) the Forecasted System Marginal Price shall receive a numerical value for each Dispatch Period of the Dispatch Day which shall be established based on the above DAS Schedule and the provisions of Article 43 paragraph (1) of the Power Exchange Code (Government Gazette Issue No. Β 623/2001).

2. With regard to Day Ahead Scheduling Clearing without System Inter-Zonal Constraints for Dispatch Days from the Third Reference Day and on the provisions of Article 56 to Article 59, as well as those of Article 61 of this Code shall apply, for the implementation of which System Inter-Zonal Constraints are not taken into account.

3. RAE shall check ex post whether the reserve requirements are at reasonable levels for DAS Schedule preparation.

Article 324 Day Ahead Scheduling Clearing with System Inter-Zonal

Constraints

1. Day Ahead Scheduling Clearing with System Inter-Zonal Constraints shall be effected in accordance with CHAPTER 12 of this Code.

2. RAE shall check ex post whether the System Inter-Zonal Constraints and the Reserve Requirements are at reasonable levels for DAS Schedule preparation.

Article 325 Transitional provisions with regard to the Dispatch Schedule

1. By 18:00 hours the Transmission System Operator shall prepare the Dispatch Schedule for the following Dispatch Day, aim at minimizing the total expense

incurred to meet the total load on the Dispatch Day taking account of the following updated information:

Α) Load Forecast and Load Declarations for energy export, Pumping Unit operation in pumping mode, serving Auxiliary and General Auxiliary Units when not covered by the generation of each Unit, and for the adjusting schedules for flow deviations at the interconnections, as have been included in the DAS Schedule;

Β) Energy Offers;

C) Unit Registered Characteristics;

D) System Inter-Zonal Constraints;

Ε) Ancillary Service requirements;

F) anticipated generation from non centrally dispatchable units and units under Article 35 of Law 2773/1999;

G) the pumping schedule of pumping units;

Η) declared extraordinary risks for Units;

I) System testing requirements;

J) User testing requirements;

K) transmission losses;

L) available transmission capability at interconnections;

M) agreements with regard to interconnections and the rights to their use;

N) other factors reasonably considered by the Transmission System Operator to be related to the DAS Schedule.

2. The Transmission System Operator may prepare anew the Dispatch Schedule at the latest up to two (2) hours prior to the commencement of the Dispatch Day. In case of events in terms of the operation of the System or of Units, the Transmission System Operator may prepare anew the Dispatch Schedule also during the Dispatch Day. Once the Dispatch Schedule has been prepared, the Transmission System Operator shall immediately inform production license holders about the scheduled operation of their Units in accordance with the applicable Dispatch Schedule.

3. Immediately after the preparation of the Dispatch Schedule it shall notify to production license holders the Schedule information concerning them. The information notified to production license holders shall include at least information for each one of their Units in accordance with the Dispatch Schedule:

Α) possible start up or shut down time for each Unit;

Β) active power generation forecast for each Dispatch Period for each Unit;

C) forecast of the supply from each Unit for Ancillary Services for each Dispatch Period.

4. RAE shall verify ex post whether the System Inter-Zonal Constraints and the Ancillary Service requirements are at reasonable levels for Dispatch Schedule preparation.

Article 326 Transitional provisions regarding DAS account settlement

1. The User Charges and Payments established in accordance with the provisions of the Power Exchange Code (Government Gazette Issue No. Β 623/2001), shall be calculated based on the ex post System Marginal Price. Past the Fourth Reference Day energy payments shall be calculated based on the Generation Marginal Prices calculated ex post.

2. In order to calculate the ex post System Marginal Price and the ex post Generation Marginal Prices after the Fourth Reference Day, the Transmission System Operator shall prepare the ex post DAS Schedule once the Dispatch Day has passed, implementing the provisions of Article 323 by the Fourth Reference Day or of Article 324 after such Day, taking account of the real information that have resulted during the Dispatch Day for the System operation and its load, as well as for Unit availability and other technical characteristics.

3. The ex post System Marginal Price, as well as the Generation Marginal Prices calculated ex post after the Fourth Reference Day, shall be calculated using a calculation method equivalent to that used for the calculation of the respective forecasted figures in accordance with Article 323 and Article 324.

4. By 14:00 hours of the fifth day after the Dispatch Day, the Transmission System Operator shall post in its website the ex post System Marginal Price for each Dispatch Period of the Dispatch Day, as well as the Generation Marginal Prices calculated ex post after the Fourth Reference Day.

5. The Dispatchable Units that are included in the DAS Schedule based on their Technical Minimum Generation to meet reserve requirements, shall be remunerated exclusively based on their variable cost increased by a fixed percentage which is the same for all Units subject to approval by RAE.

6. Load Representatives, the Load Declarations of which are totally or partially included in the DAS Schedule shall be required to pay, for each Dispatch Period, the sum in € resulting from pricing the energy quantity in MWh they absorb from the System at System Marginal Price.

Article 327 Transitional provisions regarding Meter and Measurement

Administration

1. During the Transitional Period, energy consumption by the installations of Eligible Customers installed on the Distribution Network at Medium Voltage shall be measured by meters capable of taking hourly measurements and tele-transmitting measurements, which are included among Registered Meters in the sense of the provisions of SECTION V of the Code as MV Distribution Network Customer Meters.

2. Registered MV Distribution Network Customer Meters must be able to measure active and reactive power, at least on an hourly basis and provide all information necessary for the implementation of this Code. Registered MV Distribution Network Customer Meter equipment includes the equipment necessary for the tele-transmission of their measurements based on the protocols and other specifications of the Transmission System Operator’s central measurement collection system.

3. Registered MV Distribution Network Customer Meters and the relevant metering and telecommunications equipment shall be installed under the responsibility and care of the Distribution Network Operator who shall also assume the relevant expenses, by strict priority to Distribution Network Customers who state a Supplier change intent. The Distribution Network Operator must maintain and repair all faults in the Registered MV Distribution Network Customer Meters and the relevant equipment at own expenses. In order to fulfill such obligations, the Distribution Network Operator must take all necessary actions in order to ensure prompt availability of all equipment, and systematically inform RAE about the relevant procedures and any problems that may arise. In any case, the Distribution Network Operator must immediately take all actions in order to enable the exercise in practice of the right of Distribution Network Eligible Customers to Supplier selection.

4. As an exception to the provisions of the previous paragraph, Suppliers may undertake the installation of Registered MV Distribution Network Customer Meters if they so wish and provided they furnish a relevant written authorization by Eligible Customers. The Distribution Network Operator must by the First Reference Day prepare a list of certified meter types, which meet the specifications pertaining to Registered MV Distribution Network Customer Meters. Furthermore, the Distribution Network Operator must by the First Reference Day publicize the other specifications pertaining to the metering and telecommunications equipment and the way of installation of Registered MV Distribution Network Customer Meters. Such list of certified meter types and all other specifications shall be updated and made public under the responsibility of the Distribution Network Operator. Suppliers may install meters only if their type is included in such certified meter list, and in accordance with the other specifications pertaining to meters and the relevant metering and

telecommunications equipment. In that case, Suppliers shall assume the cost for the initial procurement and installation of meters and other relevant equipment, the ownership of which shall be transferred to the Distribution Network Operator, while the latter must, assuming the relevant expenses, maintain and immediately repair all faults in Registered MV Distribution Network Customer Meters and the relevant equipment. In any case, the Distribution Network Operator must immediately take all necessary actions and proceed to all necessary checks with regard to the Registered MV Distribution Network Customer Meters installed by Suppliers in order to enable the exercise in practice of the right of Distribution Network Eligible Customers to Supplier selection.

5. The Transmission System Operator shall have the following obligations with regard to Registered MV Distribution Network Customer Meters. It shall be required to:

Α) collect the measurements from Registered MV Distribution Network Customer Meters through the electronic measurement collection system;

Β) apply the procedure for the certification and check of measurements, adjustment or estimation thereof, and establish the Metering Data for Registered MV Distribution Network Customer Meters taking account Distribution Network losses in accordance with the loss percentages established by RAE's decision;

C) keep and update the Meters to Load Representative Correspondence Table for Registered MV Distribution Network Customer Meters in accordance with the representation percentages or the method used to allocate the energy quantities measured established by the Distribution Network Operator;

D) provide, during the Transitional Period, to the Distribution Network Operator all information, technical data and specifications it has collected or applied while performing its competencies under this Article, to facilitate the Distribution Network Operator to fulfill its relevant competencies after the Transitional Period.

6. The Distribution Network Operator shall have the following obligations with regard to Registered MV Distribution Network Customer Meters. It shall be required to:

Α) receive the Representation Declarations for Registered MV Distribution Network Customer Meters and check them in terms of the limitations to the total representation, assuming the obligations of the Transmission System Operator in accordance with Article 162 paragraphs (1) to (4) for such Meters;

Β) supervise compliance with the Typical Agreement for Meter Allocation between Suppliers and/ or Self-Supplying Customers for Registered MV Distribution Network Customer Meters, the form of which, as well as any exceptions thereto shall be subject to RAE’s approval;

C) inform the Transmission System Operator on any changes to the representation percentages for the Registered MV Distribution Customer Meters;

D) take all necessary actions and facilitate the Transmission System Operator in fulfilling its competencies assigned to it under this Article, and in particular to assist the latter in the measurement certification and checks, adjustment or estimation procedure and the establishment of the Metering Data for Registered MV Distribution Network Customer Meters;

Ε) submit to RAE for approval a documented study on the numerical values of Distribution Network loss factors within one (1) month from the publication of this Code in the Government Gazette.

7. In order to represent Registered MV Distribution Network Customer Meters, Load Representatives, Suppliers or Self-Supplying Customers, are required to submit to the Distribution Network Operator a Meter Representation Declaration in accordance with the provisions of Article 162 to Article 164.

8. With regard to Eligible Customers that are installed in the LV Distribution Network, the Distribution Network Operator shall initially establish the total load for such Customers per Dispatch Period as the difference between the total load the Distribution Network absorbs during the Dispatch Period and the total energy quantity absorbed during the same Dispatch Period by Customers with a Registered MV Distribution Network Customer Meter. The percentage of Representation by each Supplier of the load of Eligible Customers that are installed to the Distribution Network at LV per Dispatch Period shall be established by the Distribution Network Operator taking account of the energy which was supplied by each Supplier to LV Customers during the previous metering period as a percentage on the total consumption of LV Customers of the Distribution Network that is connected to the System for that same period. The Distribution Network Operator shall calculate the energy absorbed by each Supplier for its LV Customers per Dispatch Period as the product of multiplying the total load for LV Customers of the Distribution Network that is connected to the System during the Dispatch Period and the respective Percentage of Representation of such Customers by said Supplier. The Distribution Network Operator shall notify to the Transmission System Operator the calculated energy that each Supplier has absorbed for its LV Customers per Dispatch Period, within the time and using the procedure established by the Transmission System Operator, in order for the latter to fulfill its obligations with regard to Imbalances Settlement. Furthermore, the Distribution Network Operator shall implement the Distribution Network periodic Energy Transaction Settlement in accordance with Article 157.

Article 328 Transitional provisions regarding the provision and

remuneration of Ancillary Services

1. On the First Reference Day and every month since the First Reference Day, the Transmission System Operator shall debit the secondary Uplift Account for Ancillary Services with the Monthly Charge for Ancillary Services which is established by Decision of the Minister of Development following the issue of RAE's opinion.

2. Suppliers and Self-Supplying Customers shall be charged for Ancillary Services ex post and on a monthly basis in accordance with the provisions of Article 66 of the Power Exchange Code (Government Gazette Issue No. Β 623/2001).

3. The Transmission System Operator shall issue Dispatch Instructions to Units for the provision of Ancillary Services so as to meet the needs for good and secure System operation, aiming at minimizing the increase of the expense for energy provision to the System.

4. The energy injected from Dispatchable Units when they provide Ancillary Services is not differentiated from the energy they inject to meet the total load of the System, hence the calculations of the respective charges and payments refer to the total energy injected from Dispatchable Units. Exceptionally, where the DAS Schedule includes Dispatchable Units that are included in such Schedule based on their Technical Minimum Generation to meet Reserve Requirements, such Units shall be remunerated for energy injection based on their variable cost increased by a fixed and single for all Units percentage to be approved by RAE on an annual basis.

5. Provision is made for payments beyond payments for energy in accordance with paragraph (4) for the following services provided they are provided by Dispatchable Units following a Dispatch Instruction: a) Primary Control and Reserve; b) Secondary Control and Range; and c) Voltage Control.

6. Payments to production license holders for the provision of Ancillary Services shall be calculated and paid ex post on a monthly basis. Monthly payments shall be calculated for each Dispatchable Unit as a result of the product of multiplying the Ancillary Serviced provided during any given month and the Unit Remuneration Rate for the respective Ancillary Service for such month. Payments to Contracted Units for Ancillary Services shall be calculated based on the relevant contracts.

7. The quantity of the Ancillary Service rendered monthly by each Unit shall be calculated as the sum of the quantities of such Ancillary Service rendered by the Unit for all Dispatch Periods of the month. The quantity of the Ancillary Service rendered per Dispatch Period shall be calculated per Ancillary Service provided by a Unit in real time following a Dispatch Instruction as follows:

Α) for Primary Control it shall be equal to the Primary Control Reserve of the Unit in MW. The numerical value of the Primary Control Reserve shall be established in accordance with the Registered Characteristics of the Unit and the Dispatch Instructions for its provision. Where the Primary Control is provided for a part of a Dispatch Period, the quantity of the Service rendered shall be reduced accordingly;

Β) for Secondary Control it shall be equal to the product of multiplying the following: a) the Secondary Control Range provided in MW, taking away any continuous operation Prohibited Zones due to oscillations (MW); and b) the ratio of the Ramp Rate under AGC (in MW/min) to the Anticipated Ramp Rate under AGC (in MW/min) for the technology of the Unit.

The numerical value of the Secondary Control Range shall be established in accordance with the Declared Characteristics of the Unit and the Dispatch Instructions for its provision. The numerical values of continuous operation Prohibited Zones and the Ramp Rate under AGC shall be established in accordance with the Declared Characteristics of the Unit.

The numerical value of the Anticipated Ramp Rate under AGC per Unit technology shall be established by RAE following a motion presented by the Transmission System Operator on an annual basis and before their entry into force, for each of the following Unit technologies: a) lignite units; b) oil or gas steam electric units; c) coal units; d) Non-CCGT plants and internal combustion engine units; e) CCGT units; and f) hydro units. The numerical values of the Anticipated Ramp Rate under AGC per unit technology reflect the optimum rate that generation units of the respective unit may achieve, which are fully fitted with the required equipment, and under good maintenance and operating conditions. The conditions for measuring the Ramp Rate under AGC (MW/min), which is stated in the Techno-Economic Declaration shall be established in the Dispatch Manual.

Where Secondary Control shall be provided for a part of the Dispatch Period, the quantity of the Service provided shall be reduced accordingly.

C) for Voltage Control it shall be equal to the integral during such Dispatch Period of the absolute value of the difference between the reactive power (leading or lagging) provided and the maximum continuous reactive power generation which is established in part A2 of the Techno-Economic Declaration for the respective active power generation level. No payments shall be made for the provision of the Voltage Control Ancillary Service where a Unit provides reactive power up to the maximum continuous reactive power generation capability established for the operating conditions in accordance with the respective Techno-Economic Declaration.

8. RAE shall by justified decision published in the Government Gazette, following a motion presented by the Transmission System Operator, establish a scale among the remunerated Ancillary Services and the Monthly Charge for Ancillary Services. Such scale shall be valid for one month and be published at least five (5) days prior to its entry in force. The Transmission System Operator shall provide RAE in a timely manner an estimate of the anticipated total quantity required in the future for each remunerated Ancillary Service which it shall also make public.

9. The Unit Remuneration Rate for each Ancillary Service shall be calculated ex post for each month, and shall be equal to the ratio of the total monthly remuneration resulting for such Service from the application of the scale on the Monthly Charge for Ancillary Services to the total quantity for that Service rendered during the month in question from all Contracted Units for Ancillary Services.

10. In addition, payments shall be made to Dispatchable Units in the following cases:

Α) if as a result of a Dispatch Instruction it is imperative that each Unit remain non-synchronized in Tertiary Non-Spinning or Standing Reserve provision standby, a payment shall be made equal to the sum of: a) the cost of the fuel involved in maintaining Unit standby when not generating; and b) the operation and maintenance cost, with the exception of the fuel cost, involved in keeping the Unit in standby when it generates, as such data are established in the Techno-Economic Declaration;

Β) if it is imperative that a Unit be de-synchronized as a result of a Dispatch Instruction. More specifically, for Dispatchable Units that have been included in the DAS and not in Total Non-Availability and for which the Dispatch Schedule demands that they be de-synchronized, a payment shall be made equal to the de-synchronization cost which shall be taken to be equal to the cost of synchronization.

11. Payments for Tertiary Non-Spinning or Standing Reserve and for Unit de-synchronization shall not be included in the basis used in the calculation and allocation of the Monthly Charge for Ancillary Services.

12. Where a Dispatchable Unit using natural gas operates as a result of a Dispatch Instruction beyond the anticipated operation under the DAS Schedule, resulting in increased gas consumption which may imply an additional fuel cost due to the special terms in the respective contract, an additional payment may be made. Such payment shall be made only subject to RAE’s approval granted upon request of the production license holder of the Unit and such request shall be accompanied by all relevant supporting documents pertaining to the gas consumption by the specific Unit, as well of the other Units of such production license holder. Such supporting documents must substantiate such additional payment for fuel procurement by the production license holder due to the unscheduled operation of the Units with gas.

13. The Transmission System Operator may carry out sampling checks relating to the provision of Ancillary Services in accordance with CHAPTER 55, in order to verify their provision. Where during a month at least three sampling checks substantiate a reduced provision of Ancillary Services by a Unit, the Transmission System Operator shall inform RAE in view of the imposition of the sanctions under Article 33 of Law 2773/1999. In any case, the results of such sampling checks shall be notified to the respective production license holder and RAE.

Article 329 Transitional provisions regarding Use of System Charges

1. In order to establish the annual cost of the System, the provisions of Article 172 of the Grid Control Code (Government Gazette Issue No. Β 654/2001) shall apply. In order to establish the annual cost of the System for 2006 and subsequent years, the provisions of Article 308 of this Code shall apply.

2. Regarding the calculation of use of System charges:

Α) for the year 2005 the provisions of Article 171, and Articles 173 to 175 of the Grid Control Code (Government Gazette Issue No. Β 654/2001) shall apply;

Β) for the year 2006 the provisions of Article 171, and Articles 173 to 175 of the Grid Control Code (Government Gazette Issue No. Β 654/2001), with the exception of the provisions of Article 173 paragraph (3), which shall be replaced by the provisions of Article 309 paragraph (4) of this Code, shall apply;

C) for the year 2007 and subsequent years the provisions of this Code shall apply.

Article 330 Transitional provisions regarding capacity assurance

1. Until the First Reference Day, the Transmission System Operator shall create and keep a CAT Register and CAC Depository and establish the Referenced Unforced Capacity for each Dispatchable Unit in accordance with the provisions of this Code and create the Unforced Capacity Table. The decision of the Transmission System Operator to create the CAT Register and CAC Depository shall be made public using all suitable means and such decision shall call upon production license holders with Units registered with the Dispatchable Unit Register to take all legal action and a deadline is fixed for that purpose.

2. Production license holders with Units that are registered with the Dispatchable Unit Register must, within the deadline fixed by the Transmission System Operator under paragraph (1) hereof, issue and submit to the Register Capacity Availability Tickets

(CATs) for the total Net Capacity of each Generation Unit in accordance with the provisions of SECTION VII of this Code.

3. The Transmission System Operator shall make entries to the CAT Register public using all suitable means.

Article 331 Proof of capacity adequacy

1. As of the Second Reference Day, Load Representatives shall be required to submit energy generation capacity availability guarantees.

2. Load Representatives shall be required to furnish generation capacity availability guarantees for each Dispatch Day during which they totally or partially represent a Meter during the current Reliability Year, which correspond to Capacity Adequacy Obligation for all the Meters they represent.

3. By the Fifth Reference Day, the obligation to furnish capacity availability guarantees of Load Representatives may be performed either by depositing to the CAC depository Capacity Availability Contracts or by entering into a Transitional Capacity Assurance Mechanism Participation Contract with the Transmission System Operator.

4. Capacity Availability Contracts entered into between a production license holder and a Load Representative shall be deposited to the CAC depository at least one (1) month before the beginning of each Reliability Year and for the first implementation of this Code at least one (1) month before the Second Reference Day.

5. Transitional Capacity Assurance Mechanism Participation Contracts shall be entered into between the Transmission System Operator and Load Representatives, shall be governed by the provisions of this Code and shall not be subject to any other formalities besides the declaration of Load Representatives that they shall perform their obligation to supply adequate capacity availability guarantees under such contracts.

6. Under Transitional Capacity Assurance Mechanism Participation Contracts Load Representatives undertake to pay the price to the Transmission System Operator in accordance with the provisions of this Article.

7. The price that Load Representatives must pay under Transitional Capacity Assurance Mechanism Participation Contracts shall be established depending on the Capacity Adequacy Obligation of Load Representatives in accordance with the provisions of Article 222, multiplied by the Capacity Payment Unit Price and the Normalization Factor, which are established in accordance with the provisions of Article 333.

8. Where a Capacity Availability Contract has been entered into between a production license holder and a Load Representative, a relevant financial agreement may also be made in accordance with the provisions of SECTION VII of this Code.

9. Within a month from the First Reference Day, the Transmission System Operator shall announce the hourly demand measured in the period between October 1st, 2004 and September 30th, 2005 for all Meters during Hours with Increased Loss of Load Probability in accordance with the provisions of the Code. Such information shall be used to calculate the Capacity Adequacy Obligation of Load Representatives during the first Reliability Year after the Second Reference Day.

Article 332 Capacity Adequacy Tickets

1. The Transmission System Operator shall establish a special section of the CAT Register where CATs for which CACs have not been entered into shall be submitted as it shall result from the CAC Depository. The CATs submitted to such special section of the CAT Register shall, under responsibility of the Transmission System Operator, include the Referenced Unforced Capacity which is established in accordance with the provisions of SECTION VII of this Code.

2. CATs shall be submitted to the special section of the CAT register following a reasonable declaration which production license holders are required to submit at least one (1) month before the beginning of each Reliability Year and for the first implementation of this Code at least one (1) month before the Second Reference Day. The submission of CATs to the special section of the CAT Register shall constitute the conclusion of a contract between a production license holder and the Transmission System Operator which shall generate the right of production license holders to receive the payments corresponding to them and their obligation to pay the charges corresponding to them under this Code.

3. A production license holder that submits a CAT to the special section of the CAT Register shall be entitled to receive a payment established by the figure of the Referenced Unforced Capacity in accordance with the provisions of SECTION VII of this Code multiplied by the Capacity Payment Unit Price which is established in accordance with the provisions of Article 333.

Article 333 Capacity Assurance Mechanism Participation Contract Price

1. The Capacity Payment Unit Price shall be approved by the Minister of Development following a motion presented by RAE and shall be valid during the Transitional Period.

2. In order to establish the Capacity Payment Unit Price account shall be taken in particular of the installation expenses of Units and of the maintenance of maximum availability and reliability of such Units, so as to ensure installed capacity adequacy

and the secure operation of the energy system which includes the Transmission System and the Generation Units.

3. The Normalization Factor shall be established by the Transmission System Operator subject to approval by RAE at least one (1) month prior to the beginning of each Reliability Year and for the first implementation of this Code, at least one (1) month before the Second Reference Day, and it shall apply for the following Reliability Year and for the first implementation of this Code from the Second Reference Day until the end of the first Reliability Year. The Normalization Factor shall be calculated as the ratio of the total Referenced Unforced Capacity established by the Transmission System Operator for all CATs that have been submitted by production license holders to the special section of the CAT Register under Article 332, to the sum of the Capacity Adequacy Obligations of all Load Representatives as established in accordance with Article 222, and which are not fulfilled through the submission of Capacity Availability Contracts to the CAC Depository. The maximum value that the Normalization Factor may receive is 1.0.

4. Within five (5) days from the end of each Reliability Year, the Transmission System Operator shall calculate the price that Load Representatives are required to pay depending on their Capacity Adequacy Obligation, it shall notify to each Load Representative a list with the charges for the Transitional Capacity Assurance Mechanism, which shall include in particular charges for each Meter and each Meter Category represented by a Load Representative during the Dispatch Days of the previous calendar month and total charges.

5. Should a Load Representative question the contents of such list of charges for the Transitional Capacity Assurance Mechanism shall address in writing and within three (3) calendar days from the notification of such list of charges for the Transitional Capacity Assurance Mechanism justified objections to the Transmission System Operator. The Transmission System Operator shall issue a justified decision on such objections and a final list of charges for the Transitional Capacity Assurance Mechanism and send to such Load Representative the relevant documents and it shall also issue the relevant bank orders. Any disputes between the parties shall be settled following the procedure stipulated in Article 10.

6. In any case, a Load Representative to which the final list of charges for the Transitional Capacity Assurance Mechanism is notified, must pay in full the charges in such list within five (5) days from such notification. In case of default on the part of such Load Representative, the provisions of the Code under Article 194 and Article 224 shall apply.

7. The Transmission System Operator shall credit the Capacity Assurance Mechanism Account under Article 199 with the sums paid by Load Representatives. To the same account it shall debit the payments it makes to production license holders who have submitted CATs to the special section of the CAT Register.

8. The Transmission System Operator shall make to production license holders and on a quarterly basis the payments which correspond to the Referenced Unforced Capacity of the CATs that have been submitted to the special section of the CAT Register. Should the Transmission System Operator ascertain following an ex post check of the Unforced Capacity of each Unit that during the previous Reliability Year the Unforced Capacity measured ex post is less than the Unforced Capacity, as this had been calculated in accordance with the provisions of CHAPTER 41CHAPTER 41 by a percentage greater than XX%, at the end of a Reliability Year and during the settlement of the last quarter, the payment to the production license holder of such Unit for the second quarter shall be reduced by a sum equal to the product of the Capacity Payment Unit Price and the difference between (100-ΧΧ%) Unforced Capacity and the Unforced Capacity measured ex post. ΧΧ% shall be fixed to 5%. Especially for new Units, and exclusively for the first year of their commercial operation, ΧΧ% may be fixed specifically for each Unit up to 15% subject to approval of the request of the relevant interested party by RAE.

Article 334 Other transitional provisions

1. With regard to the Units which are in commercial operation at the time of publication of this Code in the Government Gazette, and where such Units do not comply with the provisions of this Code, the respective production license holders must submit exemption requests in accordance with Article 315 and Article 47, up to six (6) months after the publication of this Code in the Government Gazette.

2. Until approval of the foregoing exemption requests, RAE shall confirm that the general characteristics of such Units and more specifically their technical minimum generation capability, dead zones and their capability to control their frequency and active power are at reasonable levels. Production license holders must immediately provide all relevant information and documentation requested by RAE.

3. During the Transitional Period, and exceptionally to the provisions of Article 276 paragraph (19), the Transmission System Operator must ensure that for each point where the Distribution Network connects to the System and for loads over 50% of maximum Distribution Network supply capacity at the connection point, the mean hourly power factor calculated at the connection point for each hour shall be within the range of 0.91 lagging to 1.0.

4. During the Transitional Period, the provisions of Article 2 paragraph (1) (F) on supply contracts to Customers that have been entered into prior to the publication of this Code in the Government Gazette, as well as the provisions of Article 2 paragraph (1) (Η) shall not apply. Supplies must see that such provisions are complied with by the Fifth Reference Day.

Article Two Draft technical specifications and requirements regarding the metering equipment of the Registered Meters of the Grid Control and Power Exchange Code For Electricity to be submitted to the European Commission in accordance with the provisions of Presidential Decree 39/2001 (Government Gazette Issue No. Α 28/20-02-2001), transposing Directive 1998/34/EC (OJ L204/37 of 21-07-1998) Directive 1998/48/EC (OJ L217/1998 of 05-08-1998), is included in the Annex hereto.

ANNEX Α

DRAFT TECHNICAL SPECIFICATIONS AND REQUIREMENTS FOR REGISTERED METERS

CHAPTER A.1

METERING EQUIPMENT SPECIFICATIONS

Article A.1 General specifications for metering equipment

1. Registered Meter metering equipment shall mean the equipment that includes a meter, recording and data transmission equipment and instrument transformers.

2. Metering equipment must apply the DLMS-IEC 62056 communication protocol established by the Transmission System Operator.

3. The specifications and requirements laid down in this Chapter shall apply to both main meters and verification meters.

4. The meters used must be of an approved type. The Transmission System Operator shall prepare and keep a list with the approved meter types which shall be made available to Users upon a relevant request.

Article A.2 Meter and transformer standards

The following international standards shall apply to meters and transformers:

A) IEC 61036, AC static meters Wh for active energy (Class1 & 2),

Β) IEC 62053-22, AC static meters Wh for active energy (Class 0.2S & 0.5S),

C) IEC 62053-23, AC static meters Varh for reactive energy (Class 2 & 3),

D) IEC 60044-1, current transformers,

Ε) IEC 60044-2, voltage transformers,

F) IEC 60044-3, instrument transformers - combined transformers,

G) IEC 62056-42/46/53/61/62, DLMS communication protocol for the exchange of data, meter readings and the control of tariffs and loads.

Article A.3 Metering equipment standards

1. All metering equipment shall meet the specifications provided for in this Chapter. Such specifications shall be modified taking account of technological developments by motion of the Transmission System Operator which shall be approved by RAE complying with the obligations and procedures laid down in Presidential Decree 39/2001 (Government Gazette Issue No. Α 28/20-02-2001), transposing Directive 1998/34/EC (OJ L204/37 of 21-07-1998) Directive 1998/48/EC (OJ L217/1998 of 05-08-1998) .

2. Each meter shall be placed in a suitably designed cabinet in accordance with the environmental requirements for installation established by their manufacturer, and which shall ensure at least protection against humidity or entry of dust, as well as against physical damage and shocks and shall ensure suitable temperature levels. It must be possible for such cabinets to be locked in order to prevent unauthorized access. In order to take measurements, a current transformer shall be installed in accordance with IEC 60044-1 or with an equivalent European standard, as well as a voltage transformer in accordance with IEC 60044-2 or with an equivalent European standard.

3. When single voltage and current transformer units are installed a precision check shall be carried out covering their interaction, as established under Article 8 of IEC 60044-3.

4. Meters shall be connected to voltage and current transformers and placed in a securely sealed metering cabinet located near the data recording and telecommunications equipment, in accordance with IEC 62053-22 or IEC 62053-21 that apply to such transformers or other equivalent European standards.

5. Data shall be stored either internally or externally through a data recorder.

6. When an external data recorder is used, one output for each measured quantity must be provided.

7. New meters and meters installed to replace older ones must provide at least eight consumed energy recordings and four capacity demand recordings. In addition, new

meters as well as meters installed to replace old ones must be able to tele-measure demand values and maximum energy demand recordings.

8. Meters must have a cumulative energy recorder which keeps the recorded energy quantity in any case. All data communication equipment must comply with the relevant standards concerning the transfer of data over telecommunications systems.

9. Any special insulation requirements shall apply in accordance with the rules of good professional practice and meeting the specific requirements of the telecommunications services provider.

10. Computer systems and communication protocols for the measurement collection procedure must be compatible with the specifications of the Transmission System Operator and comply with applicable standards.

Article A.4 Equipment accuracy and error limits

1. The accuracy of the various parts of the metering equipment must comply with the relevant IEC standards or equivalent European standards.

2. For the purpose of the provisions of this Chapter, rated circuit power in MVA shall be the lowest rated power of the main components of an installation, and in particular the capability of transformers or circuit lines. The provisions on the accuracy of the metering equipment must take account of any future capacity growth in the existing main installation. To make such estimate, account shall be taken of the maximum continuous capability in MVA of the main components of installations.

3. The accuracy class or other equivalent magnitude shall be established in accordance with the transmission capability of the connection in MVA and it must correspond at least to the forecasts in the following table:

Equipment accuracy class

Connection capacity

Equipment type > 50 MVA 10 - 50 MVA

1 - 10 MVA < 1 MVA

Current transformer 0.2S 0.2S 0.5S 0.5S

Voltage transformer 0.2S 0.5S 0.5S 0.5S

Meters 0.2S 0.5S 1 2

Article A.5 Measured magnitudes and parameters

1. For each independent circuit the metering equipment of each User must be able to measure the incoming energy quantity expressed in kWh and the incoming energy quantity expressed in kVArh. In addition, for each independent circuit the metering equipment of each production license holder installation and in each auto-generation installation it must be possible to measure the outgoing energy expressed in kWh and the outgoing energy expressed in kVArh. Measurements shall be taken every fifteen (15) minutes.

2. Integration metering equipment must be able to calculate the flow of active and reactive power during each metering period for each defined metering point.

3. The quantity of net energy directly delivered to the System or the Distribution Network from each generation unit installed in Greece, shall be measured independently from that delivered by any other unit.

4. The energy quantities delivered by an auto-producer to the System, those supplied to it by the System, and the total energy it generates shall be measured independently.

Article A.6 Storage of information

The media used to store meter information must meet at least the following requirements:

Α) they must have a storage capacity of 96 periods a day at least for 60 days and for all demand values;

Β) stored demand values must correspond to integral kW or kVΑr or pulse number values and have a resolution better than ~0.1% in full load;

C) the accuracy of energy values calculated in accordance with demand values must remain in the ±0.1% range at full load of the energy measured by the respective meter;

D) the value of each measured energy quantity for the demand period that has not been stored for the specific demand period must be carried over to the next period;

Ε) in case of fault in the power supply of the metering equipment, such equipment must protect all information stored up to the time of the fault and maintain time accuracy in accordance with Article A.15;

F) in case of disturbance in the metering voltage or the meter power supply the values measured, the clock, the parameters and all data must be stored in an EEPROM memory for protection without the use of battery;

G) the reading operations may not delete or modify the data measured and stored;

Η) following a request by the electronic measurement result receipt and automatic transmission system, each metering equipment must be able to provide any part of data that has been stored in it.

Article A.7 Main and Backup Meters

1. Main and verification (backup) meters shall be installed at connections with a capacity over 10 MVA which shall operate using independent voltage and current transformer windings.

2. Voltage and current transformer windings and the cables used to connect such windings to the main meters serve exclusively the connections under the previous paragraph. Cables and connections shall be sealed securely.

3. Voltage and current transformer windings and the cables used to connect such windings to the backup meters may also be used for other purposes, provided the total accuracy requirements are met and the value of additional loads may be controlled by the Transmission System Operator.

4. The main meter, the verification meter and additional connected loads must have independent fuses for their supply from voltage transformers.

5. In addition to the main +Α, +Ri, +Rc measurements, meters must be able to measure copper losses (depending on the Ι2) of power transformers - transmission lines and iron losses (depending on the U2) of power transformers. In that case, the meter must have at least four (4) recorders to record losses. To calculate such losses the copper resistance of lines and the iron resistance of the transformer must be programmed in the meter aiming at recording the following metering quantities:

Α) active energy of the copper losses of lines and transformer windings;

Β) active energy of iron losses of the current transformer;

C) total losses to the positive direction;

D) total losses to the negative direction.

6. Furthermore, each meter must comply with the following specifications:

Α) they must have additional recordings at all three phases regarding capacity quality and diagnostics:

• number of voltage dips with the relevant time duration;

• number of harmonic distortions (THD) per active energy phase;

• voltage and current per phase;

• phase angles between voltages;

• phase angles between voltage and current;

• phase tripping;

• number of overvoltage and undervoltage fluctuations (with the ability of programmed limits and time delays).

With regard to the above capabilities additional available recorders shall be required.

Β) a support software shall be available in a widely used operating environment installed in a laptop to configure the meter using optical connection in accordance with IEC 62056-21 and the DLMS communications protocol in accordance with IEC 62056-42/46/53/61/62;

C) it must provide the possibility to enter a special code at multiple security levels to program the meter and provide protection for parameters and measurements;

D) it must provide the possibility to configure the meter for the following magnitudes:

• primary and secondary circuit measurement values;

• ratio of the transformer voltage and current relationship;

• pulse values (e.g. kWh/imp., kVArh/imp.);

• signals and operation indications;

• analysis of registers;

• number and type of the values measured;

• measuring units and decimal points separately for incoming (+Α) and outgoing (-Α) values.

Article A.8 New and existing instrument transformers

If the installed instrument transformers do not meet all the conditions herein, they shall be accepted if they meet the following requirements:

Α) in case of a significant change to the electrical installation, installed transformers shall be replaced by new instrument transformers meeting the requirements herein;

Β) if the installed meters do not exclusively perform the measurements needed for settlement, provision must be made so that additional loads are quantified and

taken into account in calibration and testing. Additional loads may not be changed without the Transmission System Operator having been previously informed;

C) main meters, verification meters and additional loads must be supplied by voltage transformers through independent fuses.

CHAPTER A.2

METERING EQUIPMENT OPERATION AND CONTROL

Article A.9 Metering Equipment approval and testing

1. The Transmission System Operator shall be responsible for approving the type of each meter, its calibration and testing to certify its compatibility with the requirements of this Chapter, in accordance with the terms of each User's license.

2. The following shall apply with regard to meter certification:

Α) each new metering equipment shall be subjected to the certification tests provided for. Tests shall be carried out in accordance with the IEC standards under Article A.2;

Β) after the certification tests, meter certificates shall be issued which shall be valid for a given period. The term of validity of such certificates may vary depending on the type of each meter and be modified when necessary;

C) after certification each meter shall be sealed. Its sealing must remain intact in order for the meter to remain in the certified state;

D) meters that have been turned off shall be certified anew prior to their connection for use in accordance with the provisions of this chapter.

3. Voltage and current transformer and meter testing certificates must be made available to the Transmission System Operator for inspection.

4. In order to measure active and reactive power, each metering equipment shall be tested and set so that it operates within the total error limits given in the following tables, after having taken into consideration any voltage and current transformer errors and the resistance of wiring or protection circuits. The regulation arrangement shall comply with national or accredited international standards.

Error limits at the declared power factor ACTIVE POWER

Connection capacity Current as a % of the measured

current Power Factor > 50

MVA 10 - 50 MVA

1 - 10 MVA

< 1 MVA

120% -10% 1 ±0.5% ± 1.0% ±2.0% ±3.0%

10% -5% 1 ±0.7% ± 1.5% ±2.5% ± 3.5%

5%-1% 1 ± 1.5% ±2.5% ±3.5% ±4.0%

120% -10% 0.5 lagging ± 1.0% ±2.0% ±3.0% ±3.5%

120% -10% 0.8 leading ± 1.0% ±2.0% ±3.0% ±3.5%

Error limits at the declared power factor REACTIVE POWER

Connection capacity Current as a % of the measured

current Power Factor > 50

MVA 10 - 50 MVA

1 - 10 MVA

< 1 MVA

120% -10% 0 ±4% ±4% ±4% ±4%

120% -20% 0.866 lagging ±5% ±5% ±5% ± 5%

120% -20% 0.866 leading ±5% ±5% ±5% ±5%

Article A.10 Periodic check

1. Meters, current and voltage transformers shall be subjected to initial verification tests at the time of their procurement. To confirm their operation within the predefined error limits under Article A.9, it is possible to carry out additional tests at regular intervals, as follows:

Agreed capacity > 50MVA 10MVA - 50MVA

1MVA - 10MVA

< 1MVA

Check frequency 1 year 3 years 5 years 5 years

2. The Transmission System Operator may, depending on the behavior of a meter, extend or shorten the testing period and perform additional special checks.

3. Both main and verification meters must be fitted with suitable testing boxes, located at a small distance, in order to facilitate on site tests.

Article A.11 Checks in special cases or upon a User’s request

1. The Transmission System Operator shall carry out the checks it deems necessary to verify whether the recorded energy measurement at each metering point reflects the real consumption of a Customer or Unit injection.

2. Extraordinary checks shall be performed on meters where there is a difference between the reading of the main meter and that of the verification meter over 1.5 times the predefined limits under Article A.9.

3. Each user may require that their meter be tested. If a meter operates within the predefined error limits, the User shall be charged with the cost of tests. Users shall be informed about the tests that are to be carried out and their results, and are entitled to be present during such tests.

4. During the performance of tests, it shall be ensured that measurement interruptions are prevented and the duration of such interruptions, if any, are minimized, calibrated testing equipment shall be used with traceability in accredited primary standards, and national or accredited international reference standards must be complied with. Tests may be assigned to a certified independent laboratory the standards of which are traceable in accredited primary standards.

5. Metering equipment shall be turned on and checked for operation within the predefined accuracy limits as soon as possible.

Article A.12 Result recording and operation monitoring

1. When a test results in the existence of an error exceeding the limits set out in Article A.9, such error shall be recorded prior to immediate adjustment, repair or replacement of the metering equipment or of any defective accessory thereof.

2. The recordings of the relevant data required to classify a test or calibration as successful shall be recorded and updated in the meter and measurement database.

3. To verify remotely collected results, the Transmission System Operator may request at times the collection of local meter readings.

4. Any deviations over 0.1% resulting from the comparison of remotely collected values and the local meter readings for the same period, shall be noted and reported for check. If the checks confirm the above exceedance of the foregoing limit, the Transmission System Operator shall inform the party responsible for the maintenance and operation of the meter and the Users the energy flow of which is measured by such meters, and the procedures provided for in the Grid Control and Power Exchange Code For Electricity shall be used.

Article A.13 Protection of meters and relevant equipment

1. The Transmission System Operator shall see to the sealing of meters, data collection equipment and connected modems, as well as of telephone connections.

2. Meters shall be installed in a way so that the readings included in them are protected against local or remote electronic access using suitable passwords and security checks established by the Transmission System Operator.

3. All metering equipment along with the respective telecommunications connection equipment shall be placed in a secure metering cabinet installed in an accessible area free from obstacles and well lit using artificial lighting. Such metering cabinet shall be placed at a visible point and locked by the Transmission System Operator. The sealing check shall be carried out in accordance with the procedures established in each case by the Transmission System Operator. Unsealing is allowed only after the Transmission System Operator has granted its consent. In cases of emergency, unsealing is allowed even without the Transmission System Operator’s consent, in which case the latter shall be informed immediately.

4. Access to the metering equipment and the information contained in it, as well as to the respective telecommunications connection equipment shall follow the procedures established by the Transmission System Operator.

5. Meter local readings must be always legible.

6. The Transmission System Operator shall check the position of seals and the sealing tools and record the sealing tools, as well as the authorized Users to which such tools are provided. The Transmission System Operator shall inspect such sealing tools on an annual basis.

7. All persons that have access to metering equipment are required to handle it safely and carefully and take all necessary measures to avoid damage to it. Users shall

immediately report in writing all damage to the metering equipment to its supplier regardless of the cause of such damage.

Article A.14 Metering equipment replacement

If a given metering equipment or part thereof is destroyed or damaged or cease to operate or is outside the predefined accuracy limits, it must be adjusted, replaced, or repaired immediately in order to be able to operate within the predefined accuracy limits as soon as possible and in any case within 72 hours.

Article A.15 Metering equipment synchronization

1. All metering equipment shall be set annual to summer time in accordance with the UTC (Universal Time Clock).

2. Time settings may even be performed following communication with the central data processing system provided for in the Grid Control and Power Exchange Code For Electricity.

3. Each demand period must start within ± 10 seconds from real time. The duration of each demand period must be precisely within the ± 0.1% limits, unless time synchronization has taken place in that period.

Article A.16 Validity of Standards

1. All references in this Code to Standards (national or European or international) shall be for illustration purposes. Equivalent standards may be used in the following order of priority:

Α) European Standards (CEN, CENELEC or ETSI) adopted by ELOT as national;

Β) European Standards (CEN, CENELEC or ETSI);

C) International Standards (ISO, IEC or ITU) adopted by ELOT as national;

D) International Standards (ISO, IEC or ITU);

Ε) National Standards of other European Union and European Free Trade Area Member States;

F) National Standards of other countries.

2. In any case, besides the standards under (Α), (Β) and (C) above, the equivalence of each Standard used must be demonstrated by the party employing such standards.

Article Three 1. This decision shall enter in force as from its publication in the Government Gazette.

2. This decision be published in the Government Gazette.

The Minister

Dim. Sioufas

INTERNAL DISTRIBUTION

1. Minster Cabinet

2. Deputy Minister Cabinet

3. Secretary General Cabinet

4. Energy Director General

5. Division D4

6. Division D5

7. Division D6

8. Division D13

9. Division D15

NOTIFIED TO

1) RAE

69, Panepistimiou and Eolou streets;

105 64 ATHENS

2) PPC SA

30, Chalkokondyli street

104 32 ATHENS

3) HTSO SA

11, Amfitheas Ave.,

171 22 NEA SMYRNI

Greek Grid Code - rae.gr · 168/A) and the provisions of Presidential Decree 29/96 on the merger of...

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Transcript of Greek Grid Code - rae.gr · 168/A) and the provisions of Presidential Decree 29/96 on the merger of...