PANDELIS BISKAS Ι. PERSONAL INFORMATION

Birth Date:

03/03/1977

Place of birth:

Serres, Greece

Position:

Lecturer, School of Electrical & Computer Engineering, Aristotle University of Thessaloniki (SECE – AUTH)

Contact details:

2310-994352, 6973-841753

ΙI. QUALIFICATIONS

TIME-PERIOD 10/1994 - 7/1999

INSTITUTE Aristotle University of Thessaloniki, School of Electrical & Computer Engineering

10/1999 - 11/2003

Aristotle University of Thessaloniki, Department of Electrical & Computer Engineering Post-Doc research in Power Systems Operation, in the Department of Electrical & Computer Engineering, Aristotle University of Thessaloniki (Funding program: «PYTHAGORAS») Supervisor: Professor Anastasios Bakirtzis

03/2004 – 08/2005

III. TEACHING Teaching of courses as a PhD candidate (SECE-AUTH): α) «Power Systems Analysis» Years: 1999-2003 Electrical Energy Department (8th semester) Exercises, laboratory tests and exams β) «Power Systems Operation» Years: 2000-2003 Electrical Energy Department (9th semester) Exercises, laboratory tests and exams Teaching of courses after PhD: 1

TITLE Electrical & Computer Engineer Diploma (GPA: 8.1) Ph.D. (GPA: Honors) Post-Doc Researcher

1) Academic Year 2004-2005: Research associate in the Department of Automization in the Technological Educational Institute of Thessaloniki, for teaching courses «Electricity ΙΙ» and «Electrical Machines» (winter semester). 2) Academic Year 2004-2005: Research associate in the Department of Mechanical Engineering in the Technological Educational Institute of Serres, for teaching course «Fire protection» (winter semester). 3) Academic Year 2005-2006: Research associate in the Department of Energy Technology in the Technological Educational Institute of Athens, for teaching course «Electrical Machines II». Teaching of courses as a Lecturer (2009-today): Winter semester • Power System Economics (9th semester, ECTS: 4), with Professor Anastasios Bakirtzis • Introduction in Energy Technology II (5th semester, ECTS: 4), with Associate Professor Grigoris Papagiannis Summer semester • Power Systems Analysis, (8th semester, ECTS: 4), with Professor Anastasios Bakirtzis • Power Systems Operation, (8th semester, ECTS: 4), with Professor Anastasios Bakirtzis ΙV. Supervision of Diploma Theses As a Lecturer of SECE-AUTH, he has supervised 22 diploma theses in the following topics: 1. 2. 3. 4. 5.

Construction and operation of electric power plants in Greece Economic viability of CCGTs in the Greek interconnected system Wholesale electricity markets analysis Demand management in the Greek wholesale electricity market Computation of the Capacity Credit of RES units

The above-mentioned theses are published in the following link: http://vivliothmmy.ee.auth.gr/ (only in Greek). ΙV. MEMBER OF Ph.D. CANDIDATES COMMITTEES Since 2009 he is a member of the following six (6) Ph.D. candidates (3-member) committees of SECE-AUTH: • • •

• •

PhD of Dimitris Chatzigiannis with subject: «Energy Markets Integration» Supervisor: Professor Anastasios Bakirtzis PhD of Manolis Bakirtzis with subject: «Virtual Power Plants operation» Supervisor: Professor Dimitris Labridis PhD of Grigoris Dourbois with subject: «Integration of wholesale electricity markets with power system security constraints Supervisor: Professor Anastasios Bakirtzis PhD of Stelios Vagropoulos with subject: «Large-Scale penetration of RES in power systems» Supervisor: Professor Anastasios Bakirtzis PhD of Vangelis Kardakos with subject: «Energy markets analysis and simulation» Supervisor: Professor Anastasios Bakirtzis 2

•

PhD of Andreas Domaris with subject: «Power systems operation with large-scale RES penetration» Supervisor: Professor Anastasios Bakirtzis

Since 2009 he is a member of the following two (2) Ph.D. candidates (7-member) committees of SECE-AUTH: •

PhD of Kostas Baslis with subject: «Medium-term hydro scheduling in a competitive electricity market» Supervisor: Professor Anastasios Bakirtzis PhD of Christos Simoglou with subject: «Optimal strategic bids of producers in a day-ahead electricity market» Supervisor: Professor Anastasios Bakirtzis

•

V. PARTICIPATION IN FUNDED RESEARCH PROJECTS V.1. As a Principal Investigator 1. 2. 3. 4. 5.

Mid-Term Energy Scheduling software package, licensed to ELPEDISON POWER, 2010 Mid-Term Energy Scheduling software package, licensed to PPC, 2010. Greek wholesale electricity market study, HELLAS POWER, 2011. Mid-Term Energy Scheduling software package, licensed to PROTERGIA, 2012. Simulation of the Greek wholesale electricity market under different load scenarios, Regulatory Authority for Energy (RAE), 2012. Simulation of the Greek wholesale electricity market under different PV injections, Photovoltaic Companies Association, 2012. Computation of the avoidable production cost through the operation of PV stations, Photovoltaic Production Companies Association, 2012. European electricity markets integration, Research Committee AUTH, 2013.

6. 7. 8.

No

Title

Budget (EUR)

Source of Funding

Role in Research Team

Begin Date

End Date

1

Mid-Term Energy Scheduling software package

125,000

Licensed to: ELPEDISON S.A.

Principal Investigator

05/03/2010 04/03/2015

2

Mid-Term Energy Scheduling software package

90,000

Licensed to: PPC S.A.

Principal Investigator

01/09/2010 04/11/2013

3

Mid-Term Energy Scheduling software package

10,000

Licensed to: PROTERGIA S.A.

Principal Investigator

27/01/2012 27/01/2016

4

Greek wholesale electricity market study

2,000

HELLAS POWER S.A.

Principal Investigator

19/10/2011 31/12/2011

3

Simulation of the Greek wholesale electricity market under different load scenarios Simulation of the Greek wholesale electricity market under different PV injections Computation of the avoidable production cost through the operation of PV stations

5

6

7

European electricity markets integration

8

15,000

Regulatory Authority for Energy

Principal Investigator

04/05/2012 03/09/2012

15,000

Photovoltaic Companies Association

Principal Investigator

25/06/2012 24/11/2012

4,000

Photovoltaic Production Companies Association

Principal Investigator

09/07/2012 08/11/2012

4,000

Research Committee AUTH

Principal Investigator

01/02/2013 31/01/2014

V.2. As a Senior Researcher 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13.

14. 15. 16.

Transmission pricing in the Greek power system. Funded by PPC, 1999. Transmission Use of System Charges derivation in Greece. Funded by PPC, 2001. E-learning environment for the new pan-European information and communication technologies. Funded by EU, 2002. Seminars and training program. Funded by A.U.Th., 2002. Neural Network based Short-Term Electric Load Forecasting Software. Funded by PPC, 2003. Transmission System Management. Funded by the Greek Ministry of Education, 2004. Generation Loss Factors for the Hellenic Transmission System - Study and Software Development. Funded by HTSO (Hellenic Transmission System Operator), 2009. Day-Ahead Energy Scheduling software package, licensed to ENDESA HELLAS (PROTERGIA),2008. Day-Ahead Energy Scheduling software package, licensed to PPC, 2009. Day-Ahead Energy Scheduling software package, licensed to HERON THERMOELECTRIC, 2009. Day-Ahead Energy Scheduling software package, licensed to ELPEDISON POWER, 2010. Day-Ahead Energy Scheduling software package, licensed to ALOUMINION OF GREECE, 2010. Development of Operation Manuals for the Energy Management Department of the Public Power Corporation according to the requirements of the contemporary liberalized Electricity Markets, funded by PPC, 2010. Simulation software for the load forecast of a load representative, funded by PPC, 2012-2013. Smart and sustainable insular systems under large-scale RES penetration, 7th Framework Programme (Cooperation, Energy), 2012-2015. Large-scale RES integration in modern electricity markets, General Secretary for Research and Technology, Ministry of Education and Religious Affairs, Sport and Culture, 2012-2015.

No

Title

Budget (EUR)

Source of Funding

Role in Research Team

Begin Date

End Date

1

Transmission Use of System Charges derivation in Greece

20,000

Public Power Corporation (PPC)

Researcher

30/01/2001

29/1/2002

4

No

Title

Budget (EUR)

Source of Funding

Role in Research Team

Begin Date

End Date

2

E-learning environment for the new pan-European information and communication technologies

11,700*

European Union

System Administrator

2002

2003

3

Seminars and training program

1,300

Aristotle University of Thessaloniki

Trainer

2002

2002

4

Neural Network based Short-Term Electric Load Forecasting Software

43,000

PPC

Researcher

20/5/2003

19/5/2004

5

Simulation of the Greek Day-Ahead Electricity Market

18,000

PPC

Researcher

13/9/2004

12/12/2004

6

Transmission System Management

40,000

Greek Ministry of Education

Post Doc Researcher

1/3/2004

31/8/2005

435,000

Licensed to: ENDESA PPC ELPEDISON PROTERGIA HERON ENERGA

Consultant Researcher

7/5/2008 6/4/2009 11/9/2009 24/12/2010 8/2/2011 4/2/2011

6/5/2012 31/12/2012 10/9/2014 23/12/2011 7/2/2012 3/2/2012

45,000

HTSO

Consultant Researcher

29/01/2009

28/09/2009

175,000

PPC

Consultant Researcher

22/2/2010

30/9/2011

Senior Researcher

01/12/2012

30/11/2015

Senior Researcher

27/09/2012

26/09/2015

7-12

Day-Ahead Energy Scheduling software package

*

13

Generation Loss Factors for the Hellenic Transmission System Study and Software Development

14

Development of Operation Manuals for the Energy Management Department of the Public Power Corporation according to the requirements of the contemporary liberalized Electricity Markets

15

Smart and sustainable insular systems under large-scale RES penetration

492,400

16

Large-scale RES integration in modern electricity markets,

250,000

7th Framework Programme (Cooperation, Energy) General Secretary for Research and Technology, Ministry of 5

No

Title

Budget (EUR)

Source of Funding

Role in Research Team

Begin Date

End Date

Education and Religious Affairs, Sport and Culture * denotes only Lecturer Pandelis Biskas participation in the research project VI. PROFESSIONAL ACTIVITY 2005 - 2009 Electricity Market Expert, Day-Ahead Scheduling Department, Hellenic Transmission System Operator; he participated in working groups for the harmonization of HTSO with the provisions of the “Greek Grid and Exchange Code”, in commissions for the “Mathematical Formulation of the Day-Ahead Scheduling problem”, and in task groups for the harmonization of the market rules in the Central-South European (CSE) Region (including Italy, France, Switzerland, Austria, Slovenia and Greece). 2009 - today Department of Electrical and Computer Engineering, Aristotle University of Thessaloniki, Greece; Lecturer As a member of the Power Systems Lab, he participated actively in two software products for the analysis of the electricity markets, “Day-Ahead Scheduling” and “Long-Term Scheduling”, licenses of which have been granted to all leading energy companies in Greece VIII. Professional Society Memberships • • •

Member of IEEE (since January 2001) Member of CIGRE (since September 2009) Member of the Technical Chamber of Greece (since June 2000) IX. Other activities

•

SECE-AUTH committees – administrative activities

He is in charge of the committee for the timetable of the courses. He is also a member of the Seminars Committee and the Library Committee of SECE-AUTH. •

Journal papers reviewer

He is a reviewer in many international scientific journals, such as “ΙΕΕΕ Transactions on Power Systems”, “ΙΕΕΕ Transactions on Smart Grid”, “ΙΕΤ Proceedings-Generation, Transmission and Distribution”, “Electric Power Systems Research”, “European Journal of Operational Research”, etc. XII. International Awards / Distinctions 1) 2001 IEE Swan Premium Award, for paper: • Bakirtzis, P. Biskas, A. Maissis, A. Coronides, J. Kabouris, and M. Efstathiou, "Comparison of Two Methods for Long-Run Marginal Cost Based Transmission Use-of-System Pricing", IEE Proceedings - Generation Transmission and Distribution, Vol. 148, no. 5, pp. 477-481, Sep. 2001

6

2) Fellowship by the National Fellowship Foundation of Greece, for excellent performance in the lessons of the third year of his diploma studies (1996-1997). 3) Fellowship by the National Fellowship Foundation of Greece for the Ph.D. thesis (2000-2003).

XIII. PUBLICATIONS

Publications Statistics • Book Chapters

1

(in English)

C.K. Simoglou, P. N. Biskas, A.G. Bakirtzis, “Hydrothermal Producer Self-Scheduling,” Chapter 8 in Book "Electric Power Systems: Advanced Forecasting Techniques and Optimal Generation Scheduling", CRC Press, Taylor and Francis Group, February 2012. • Journal Papers 21 (all of them in ISI) 10 in IEEE Transactions on Power Systems 6 in IEE/IET Generation, Transmission and Distribution 4 in Electric Power Systems Research 1 in Electrical Power and Energy Systems • Conference Papers 29 (POWERTECH, PSCC, EEM, ISAP, IREP, UPEC, MED POWER, General Meetings of the IEEE PES, DISTRES) • Citations

257

(ISI)

(245, excluding self-citations)

• h-Index

6

(ISI)

8 (SCOPUS)

Α. PhD Thesis «Decentralized power systems operation», SECE-AUTH, April 2003.

Β. Journal papers Β.1 A.G. Bakirtzis, P.N. Biskas, A. Maissis, A. Coronides, J. Kabouris, M. Efstathiou, “Comparison of two methods for long-run marginal cost-based transmission use-of-system pricing”, ΙΕΕ ProceedingsGeneration, Transmission and Distribution, vol. 148, no. 4, July 2001, pp. 477-481. B.2 A.G. Bakirtzis, P.N. Biskas, C.E. Zoumas, V. Petridis, “Optimal Power Flow by Enhanced Genetic Algorithm”, ΙΕΕΕ Transactions on Power Systems, vol. 17, no. 2, May 2002, pp. 229-236. B.3 P.N. Biskas, A.G. Bakirtzis, “Decentralized congestion management of interconnected power systems”, ΙΕΕ Proceedings-Generation, Transmission and Distribution, vol. 149, no. 4, July 2002, pp. 432-438. Β.4 A.G. Bakirtzis, P.N. Biskas, “Decentralized DC Load Flow and applications to transmission management”, ΙΕΕ Proceedings-Generation, Transmission and Distribution, vol. 149, no. 5, September 2002, pp. 600-606. Β.5 A.G. Bakirtzis, P.N. Biskas, “A decentralized solution to the DC-OPF of interconnected power systems”, ΙΕΕΕ Transactions on Power Systems, vol. 18, no. 3, August 2003, pp. 1007-1013. 7

Β.6 P.N. Biskas, A.G. Bakirtzis, “Decentralized Security Constrained DC-OPF of interconnected power systems”, ΙΕΕ Proceedings-Generation, Transmission and Distribution, vol. 151, no. 6, November 2004, pp. 747-754. Β.7 P.N. Biskas, A.G. Bakirtzis, N.I. Macheras, N.K. Pasialis, “A Decentralized Implementation of DC Optimal Power Flow on a network of computers”, ΙΕΕΕ Transactions on Power Systems, vol. 20, no. 1, February 2005, pp. 25-33. Β.8 P.N. Biskas, A.G. Bakirtzis, “Decentralized OPF of large multi-area power systems”, ΙΕΕ ProceedingsGeneration, Transmission and Distribution, vol. 153, no. 1, January 2006, pp. 99-105. B.9

P.N. Biskas, N.P. Ziogos, A. Tellidou, C.E. Zoumas, A.G. Bakirtzis, V. Petridis, “Comparison of two metaheuristics with mathematical programming methods for the solution of OPF”, ΙΕΕ ProceedingsGeneration, Transmission and Distribution, vol. 153, no. 1, January 2006, pp. 16-24.

Β.10 P.N. Biskas, N. P. Ziogos, A.G. Bakirtzis, “Analysis of a monthly auction for financial transmission rights and flow-gate rights”, Electric Power Systems Research, vol. 77, no. 5-6, pp. 594-603. Β.11 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Optimal self-scheduling of a thermal producer in shortterm electricity markets by MILP”, ΙΕΕE Transactions on Power Systems, vol. 25, no. 4, November 2010, pp. 1965-1977. Β.12 P. Andrianesis, P.N. Biskas, G. Liberopoulos, “An overview of Greece's wholesale electricity market with emphasis on ancillary services”, Electric Power Systems Research, vol. 81, no. 8, August 2011, pp. 1631-1642. Β.13 P.N. Biskas, A. Tsakoumis, A.G. Bakirtzis, A. Koronides, J. Kabouris, “Transmission loss allocation through zonal aggregation”, Electric Power Systems Research, vol. 81, no. 10, October 2011, pp. 19731985. Β.14 A.G. Vlachos, P.N. Biskas, “Balancing Supply and Demand Under Mixed Pricing Rules in Multi-Area Electricity Markets”, ΙΕΕE Transactions on Power Systems, vol. 26, no. 3, August 2011, pp. 1444-1453. Β.15 A.G. Vlachos, P.N. Biskas, “Simultaneous Clearing of Energy and Reserves in Multi-Area Markets Under Mixed Pricing Rules”, ΙΕΕE Transactions on Power Systems, vol. 26, no. 4, November 2011, pp. 2460-2471. Β.16 C. K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Optimal Self-Scheduling of Thermal Units During Commissioning”, ΙΕΕE Transactions on Power Systems, vol. 27, no. 1, February 2012, pp. 181-188. Β.17 G. A. Bakirtzis, P. N. Biskas, V. Chatziathanasiou, “Generation Expansion Planning by MIP considering mid-term scheduling decisions”, Electric Power Systems Research, vol. 86, May 2012, pp. 98-112. Β.18 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Optimal self-scheduling of a dominant power company in electricity markets,” International Journal of Electrical Power & Energy Systems, vol. 43, 2012, pp. 640-649. Β.19 P.N. Biskas, D.I. Chatzigiannis, G.A. Dourbois, A.G. Bakirtzis, “European Market Integration With Mixed Network Representation Schemes”, ΙΕΕE Transactions on Power Systems, in press. Β.20 P.N. Biskas, D.I. Chatzigiannis, A.G. Bakirtzis, “European electricity market integration with mixed market designs – Part I: Formulation”, ΙΕΕE Transactions on Power Systems, in press. Β.21 P.N. Biskas, D.I. Chatzigiannis, A.G. Bakirtzis, “European electricity market integration with mixed market designs – Part II: Solution algorithm and case studies”, ΙΕΕE Transactions on Power Systems, in press.

C. Greek journal papers C.1 Α. Dagoumas, D. Labridis, P. Biskas, P. Dokopoulos, «The wholesale electricity market in Greece», “Τεχνικά Χρονικά”, Technical Chamber of Greece, September-October 2004. 8

D. International Conference Papers D.1

P.N. Biskas, A.G. Bakirtzis, “Decentralized congestion management of interconnected power systems”, MED POWER, pp. 152, 4th-6th November 2002, Athens, Greece.

D.2

P.N. Biskas, C.E. Zoumas, A.G. Bakirtzis, “Optimal Reactive Power Flow by Enhanced Genetic Algorithm”, ISAP 2003, 31st August – 3rd September 2003, Limnos, Greece.

D.3

P.N. Biskas, A.G. Bakirtzis, “Decentralized congestion management of interconnected power systems”, UPEC ’03, pp. 393-396, 1st-3rd September 2003, Thessaloniki, Greece.

D.4

P.N. Biskas, A.G. Bakirtzis, “A decentralized solution to the Security Constrained DC-OPF problem of multi-area power systems”, PowerTech ‘05, 27-30 June 2005, St. Petersburg, Russia.

D.5

P.N. Biskas, N.P. Ziogos, A. Tellidou, C.E. Zoumas, A.G. Bakirtzis, V. Petridis, A. Tsakoumis, “Comparison of two metaheuristics with mathematical programming methods for the solution of OPF”, ISAP ‘05, 6-9 November 2005, Washington, U.S.A.

D.6

P.N. Biskas, A.G. Bakirtzis, “Decentralized OPF of large multi-area power systems”, AIESP ‘06, 6-10 February 2006, Madeira, Portugal.

D.7

P. Biskas, D. Michos, P. Nikolaou, M. Philippou, I. Blanas, “The new HTSO Market Management System”, MED POWER 2008, November 2008.

D.8

P.N. Biskas, C.E. Zoumas, M. Philippou, “Co-optimization of commodities in the Greek energy market”, MED POWER 2008, November 2008.

D.9

P. Andrianesis, G. Liberopoulos, P. Biskas, “Tertiary reserve in Greece’s electricity market: The need for peakers”, Conference on the promotion of Distributed Renewable Energy Sources in the Mediterranean region (DISTRES ’09), 11-12 December 2009, Nicosia, Cyprus, Paper ref No: 134, 7

pages. D.10 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “A MILP Approach to the short term Hydrothermal SelfScheduling Problem”, Bucharest PowerTech Conference, JUN 28-JUL 02, 2009 Bucharest, ROMANIA, Pages: 1696-1703, 2009. D.11 N.A. Iliadis, P.N. Biskas, “Trading opportunities in the SEE”, General Meeting of the IEEE-Powerand- Energy-Society, JUL 26-30, 2009 Calgary, Canada. Book Series: IEEE Power and Energy Society General Meeting-PESGM, Pages: 458-460, 2009. D.12 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Effect of increased RES penetration on the system marginal price of the Greek electricity market”, 7th International Conference on the European Energy Market (EEM), 2010. D.13 P.N. Biskas, C.G. Baslis, C.K. Simoglou, A.G. Bakirtzis, “Coordination of day-ahead scheduling with a stochastic weekly unit commitment for the efficient scheduling of slow-start thermal units”, Bulk Power System Dynamics and Control (iREP) - VIII (iREP), 2010 iREP Symposium. D.14 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Impact of increased RES penetration on the operation of the Greek electricity market”, 7th Mediterranean Conference and Exhibition on Power Generation, Transmission, Distribution and Energy Conversion (MedPower 2010), Agia Napa, Cyprus, 7-10 November 2010. D.15 P. Andrianesis, G. Liberopoulos, P.N. Biskas, “Impact of emissions cost on the mid-term generation scheduling in the Greek Electricity Market”, 7th Mediterranean Conference and Exhibition on Power Generation, Transmission, Distribution and Energy Conversion (MedPower 2010), Agia Napa, Cyprus, 7-10 November 2010. D.16 C. Baslis, P.N. Biskas, A.G. Bakirtzis, “A Profit Maximization Model for a Power Producer in a PoolBased Energy Market with Cost Recovery Mechanism”, 8th International Conference on the European Energy Market (EEM 2011), 25-27 May 2011, Zagreb, Croatia. 9

D.17 P. Andrianesis, G. Liberopoulos, P.N. Biskas, A.G. Bakirtzis, “Medium-Term Unit Commitment in a pool market”, 8th International Conference on the European Energy Market (EEM 2011), 25-27 May 2011, Zagreb, Croatia. D.18 C.K. Simoglou, P.N. Biskas, C.E. Zoumas, A.G. Bakirtzis, “Evaluation of the Impact of RES Integration on the Greek Electricity Market by Mid-term Simulation”, IEEE PES PowerTech 2011, 19 23 June, Trondheim, Norway. D.19 P.N. Biskas, G.H. Naziris, C.K. Simoglou, C.E. Zoumas, A.G. Bakirtzis, “Market design effects on private producers in Greece”, 17th Power Systems Computation Conference (PSCC), 22-26 August 2011, Stockholm, Sweden. D.20 A.G. Vlachos, P.N. Biskas, “Multi-Area Market Clearing with Complex Pricing Rules”, 17th Power Systems Computation Conference (PSCC), 22-26 August 2011, Stockholm, Sweden. th

D.21 A.G. Vlachos, P.N. Biskas, “Supporting services for real time wheeling transactions requests”, 16 International Conference on Intelligent System Applications to Power System (ISAP 2011), 25-28 September 2011, Hersonissos, Crete, Greece. D.22 P.N. Biskas, D.I. Chatzigiannis, A.G. Bakirtzis, “Volume-Coupling Between a Power Pool and a Power Exchange”, 9th International Conference on the European Energy Market (EEM 2012), 10-12 May 2012, Florence, Italy. D.23 C. Baslis, P.N. Biskas, A.G. Bakirtzis, “Price-Based Annual Generation Maintenance Scheduling of a Thermal Producer”, 9th International Conference on the European Energy Market (EEM 2012), 10-12 May 2012, Florence, Italy.

D.24 P.N. Biskas, C.K. Simoglou, C.E. Zoumas, A.G. Bakirtzis “Evaluation of the Impact of IPPs on the Greek wholesale and retail electricity markets”, 11th IASTED European Conference on Power and Energy Systems, June 25 – 27, 2012, Napoli, Italy. D.25 C.K. Simoglou, P.N. Biskas, and A.G. Bakirtzis, “Optimal Offering Strategies in Day-Ahead Electricity Markets under Uncertainty”, MED POWER 2012, 1-3 October 2012, Cagliari, Sardinia. D.26 G.A. Dourbois, D.I. Chatzigiannis, P.N. Biskas, A.G. Bakirtzis, “European market integration with both physical and non-physical markets”, 10th International Conference on the European Energy Market (EEM 2013), Stockholm, Sweden, approved for presentation. D.27 C.K. Simoglou, P.N. Biskas, E.A. Bakirtzis, A.N. Matenli, A.I. Petridis, A.G. Bakirtzis, “Evaluation of the Capacity Credit of RES: The Greek Case”, PowerTech ‘13, 16-20 June 2013, Grenoble, France, approved for presentation. D.28 C. Baslis, P.N. Biskas, A.G. Bakirtzis, “Impact of Natural Gas Supply, Renewable Penetration and Demand Trends on Power System Maintenance”, PowerTech ‘13, 16-20 June 2013, Grenoble, France, approved for presentation. D.29 D.I. Chatzigiannis, P.N. Biskas, A.G. Bakirtzis, “A Market Splitting Approach for the European Electricity Market Integration”, PowerTech ‘13, 16-20 June 2013, Grenoble, France, approved for presentation.

Ε. Greek conferences Ε.1

Α. Μπακιρτζής, Π. Μπίσκας, Α. Μαïσης, Α. Κορονίδης, Ι. Καμπούρης, Σ. Ευσταθίου, «Χρέωση χρήσης του ελληνικού συστήματος μεταφοράς ηλεκτρικής ενέργειας», Παγκόσμιο Συνέδριο «Ενέργεια 2002», σελ. 56-59, 21-23 Μαρτίου 2002, Κοζάνη.

E.2

Π. Μπίσκας, Α. Μπακιρτζής, «Αποκεντρωμένη επίλυση του γραμμικού προβλήματος Βέλτιστης Ροής Φορτίου», Σύνοδος CIGRE «Αθήνα 2003», 27-28 Νοεμβρίου 2003, Αθήνα.

E.3

Π. Μπίσκας, Μ. Φιλίππου, Γ. Ευαγγελίδης, Β Γκουντής, «Επίδραση του προβλήματος ένταξης 10

μονάδων στην Ελληνική Αγορά Ηλεκτρικής Ενέργειας», Σύνοδος CIGRE «Αθήνα 2009», 3-4 Νοεμβρίου 2009, Αθήνα. Ε.4

Β. Νικολόπουλος, Π. Ανδριανέσης, Π. Μπίσκας, Μεθοδολογία μέτρησης και ανάλυσης της Πελατειακής Δέσμευσης (Customer Engagement), στις Υπηρεσίες Ευφυών Δικτύων (Smart Grids) και Διαχείρισης Ενεργειακής Ζήτησης, βάσει Τεχνολογιών Web Smart Metering 2.0, 15ο Εθνικό Συνέδριο Ενέργειας – «Ενέργεια & Ανάπτυξη 2010», ΙΕΝΕ, 22-23 Νοεμβρίου 2010, Αθήνα.

E.5

Ανδριανέσης, Π., Γ. Λυμπερόπουλος, Π. Μπίσκας. 2010. Αποτίμηση της επίπτωσης στην ελληνική αγορά ηλεκτρικής ενέργειας από την εσωτερικοποίηση του κόστους εκπομπής αερίων του θερμοκηπίου στις προσφορές των παραγωγών. 11ο Πανελλήνιο Συνέδριο Ι.ΔΙ.Π.-Π.Υ. Ε.Ε.Δ.Ε. με θέμα «Βιώσιμη Παραγωγή και Πράσινη Επιχειρηματικότητα», Αθήνα, 9-10 Δεκεμβρίου 2010.

Ε.6

Π. Μπίσκας, A. Μπακιρτζής, “Υπολογισμός του μοναδιαίου τιμήματος πληρωμής ισχύος στην Ελληνική αγορά ηλεκτρικής ενέργειας», Σύνοδος Ελληνικής Επιτροπής CIGRE, 15-16 Δεκεμβρίου 2011, Αθήνα.

Ε.7

Σ.Ευαγγελοπούλου, Π.Μπίσκας, Δ.Κουγιουμτζής, “Έλεγχος της αιτιότητας κατά Granger σε πολυμεταβλητές χρονοσειρές με εποχικότητα και εφαρμογή στην αγορά ηλεκτρικής ενέργειας της Ιταλίας”, Ελληνικό Στατιστικό Ινστιτούτο, Πρακτικά 25ου Πανελληνίου Συνεδρίου Στατιστικής (2012).

F. Book Chapters F.1

C.K. Simoglou, P. N. Biskas, A.G. Bakirtzis, “Hydrothermal Producer Self-Scheduling,” Κεφάλαιο 8 στο βιβλίο "Electric Power Systems: Advanced Forecasting Techniques and Optimal Generation Scheduling", CRC Press, Taylor and Francis Group, δημοσίευση 02/2012.

ΙX. ANALYSIS OF PAPERS

Β. Journal papers Β.1 A.G. Bakirtzis, P.N. Biskas, A. Maissis, A. Coronides, J. Kabouris, M. Efstathiou, “Comparison of two methods for long-run marginal cost-based transmission use-of-system pricing”, ΙΕΕ ProceedingsGeneration, Transmission and Distribution, vol. 148, no. 4, July 2001, pp. 477-481. Two methods that provide geographically differentiated transmission usage tariffs, based on the longrun marginal cost of transmission, are presented and compared: investment cost-related pricing and the DC load flow pricing. The basic assumptions and approximations behind their design are analyzed. Very efficient implementations of both methods, based on sensitivity analysis, are presented. Both methods are applied to the computation of transmission usage tariffs in the Greek power system, and the resulting tariffs are compared. B.2 A.G. Bakirtzis, P.N. Biskas, C.E. Zoumas, V. Petridis, “Optimal Power Flow by Enhanced Genetic Algorithm”, ΙΕΕΕ Transactions on Power Systems, vol. 17, no. 2, May 2002, pp. 229-236. This paper presents an enhanced genetic algorithm (EGA) for the solution of the optimal power flow (OPF) with both continuous and discrete control variables. The continuous control variables modeled are unit active power outputs and generator-bus voltage magnitudes, while the discrete ones are transformer-tap settings and switchable shunt devices. A number of functional operating constraints, such as branch flow limits, load bus voltage magnitude limits, and generator reactive capabilities, are included as penalties in the GA fitness function (FF). Advanced and problem-specific operators are introduced in order to enhance the algorithm’s efficiency and accuracy. Numerical results on two test systems are presented and compared with results of other approaches.

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B.3 P.N. Biskas, A.G. Bakirtzis, “Decentralized congestion management of interconnected power systems”, ΙΕΕ Proceedings-Generation, Transmission and Distribution, vol. 149, no. 4, July 2002, pp. 432-438. A method for the decentralized solution of the congestion management problem in large interconnected power systems is presented in this paper. The multi-area congestion management is achieved through crossborder coordinated redispatching by regional transmission system operators. The coordination is performed through a pricing mechanism inspired by Lagrangian relaxation. The prices used for the co-ordination of the regional sub-problem solutions are the prices of electricity exchanges between adjacent areas. Test results from the application of the method to the three-area RTS96 are reported. Β.4 A.G. Bakirtzis, P.N. Biskas, “Decentralized DC Load Flow and applications to transmission management”, ΙΕΕ Proceedings-Generation, Transmission and Distribution, vol. 149, no. 5, September 2002, pp. 600-606. A method for the decentralized solution of the DC load flow (DC-LF) problem of large, multi-area power systems is presented in this paper. The method transforms the original large set of the linear. Sparse DC-LF equations into a number of smaller sparse quadratic programming (QP) problems, one for each area, which are iteratively solved using the auxiliary problem principle (APP) until they converge to the original problem solution. The applications of the decentralized DC-LF solution to the decentralized management of large, interconnected power systems by coordinated transmission system operator (TSO) actions are discussed. Test results on the IEEE-RTS 96 (up to five areas) are presented. Β.5 A.G. Bakirtzis, P.N. Biskas, “A decentralized solution to the DC-OPF of interconnected power systems”, ΙΕΕΕ Transactions on Power Systems, vol. 18, no. 3, August 2003, pp. 1007-1013. This paper presents a new method for the decentralized solution of the dc optimal power flow (OPF) problem in large interconnected power systems. The method decomposes the overall OPF problem of a multiarea system into independent OPF sub-problems, one for each area. The solutions of the OPF sub-problems of the different areas are coordinated through a pricing mechanism until they converge to the global OPF solution. The prices used for the coordination of the sub-problem solutions are the prices of electricity exchanges between adjacent areas. Test results from the application of the method to the three-area RTS-96 and the Balkan power system are reported. Β.6 P.N. Biskas, A.G. Bakirtzis, “Decentralized Security Constrained DC-OPF of interconnected power systems”, ΙΕΕ Proceedings-Generation, Transmission and Distribution, vol. 151, no. 6, November 2004, pp. 747-754. A method for the decentralized solution of the security constrained optimal power flow (SCOPF) problem in large interconnected power systems is presented. The method decomposes the overall SCOPF problem of a multi-area system into independent SCOPF sub-problems, one for each area. The solutions of the SCOPF sub-problems of the different areas are co-ordinated through a pricing mechanism until they converge to a reduced scope central SCOPF solution. The prices used for the co-ordination of the sub-problem solutions are the prices of electricity exchanges between adjacent areas. The reduced scope SCOPF of a multi-area power system is a SCOPF with a reduced set of security constraints, in which the effects of contingencies outside an area on monitored elements within the area are ignored. Test results from the application of the method to the IEEE three-area RTS-96 and to the Balkan power system are presented. Β.7 P.N. Biskas, A.G. Bakirtzis, N.I. Macheras, N.K. Pasialis, “A Decentralized Implementation of DC Optimal Power Flow on a network of computers”, ΙΕΕΕ Transactions on Power Systems, vol. 20, no. 1, February 2005, pp. 25-33. This paper presents a decentralized implementation of the DC Optimal Power Flow (OPF) problem on a network of workstations. Each workstation is assigned to a regional Transmission System Operator (TSO), who manages the operation of the transmission system of his own region, as well as cross-border exchanges with neighboring regions. The workstations take part in an iterative process, exchanging information with each 12

other and solving regional OPF sub-problems, until the global OPF solution is reached. Tie-line related information is exchanged between workstations assigned to neighboring regions. A master workstation, assigned to a “Super-TSO”, checks for the convergence of the algorithm. The parallel processing system is tested on various test systems, including a large real-world system, the Balkan power system. Β.8

P.N. Biskas, A.G. Bakirtzis, “Decentralized OPF of large multi-area power systems”, ΙΕΕ ProceedingsGeneration, Transmission and Distribution, vol. 153, no. 1, January 2006, pp. 99-105.

The paper presents a method for the decentralized solution of the optimal power flow (OPF) problem of large, interconnected power systems. The method decomposes the central OPF problem of a multi-area system into independent OPF sub-problems, one for each area. The mathematical decomposition method is based on the decoupling of the first-order (KKT) conditions of the original system-wide OPF problem. The solutions of the OPF sub-problems of the different areas are co-ordinated through a pricing mechanism until they converge to the system-wide OPF solution. The method requires no parameter tuning for reaching convergence of faster convergence. Results from the application of the method to several IEEE test systems are presented. B.9

P.N. Biskas, N.P. Ziogos, A. Tellidou, C.E. Zoumas, A.G. Bakirtzis, V. Petridis, “Comparison of two metaheuristics with mathematical programming methods for the solution of OPF”, ΙΕΕ ProceedingsGeneration, Transmission and Distribution, vol. 153, no. 1, January 2006, pp. 16-24.

Different optimization methods developed for the solution of the nonlinear OPF problem with both continuous and discrete variables are compared in this paper. Two mathematical programming methods are compared with two metaheuristics, and enhanced genetic algorithm and a particle swarm optimization implementation. Test results from the application of the methods to several IEEE systems are presented and compared. Useful conclusions are drawn, concerning the execution times and the “optimum” costs provided by all four tested methods. Β.10 P.N. Biskas, N. P. Ziogos, A.G. Bakirtzis, “A monthly auction for Financial Transmission Rights and Flow-Gate Rights”, Electric Power Systems Research, vol. 77, no. 5-6, pp. 594-603. A monthly transmission rights (TR) auction issuing both point-to-point financial transmission rights (FTRs) and flow-gate rights (FGRs) is studied in this paper. Initially, a locational marginal pricing (LMP) based energy market is presented, in which the linear security constrained optimal power flow (SCOPF) problem is solved for each hour of system operation, determining the nodal prices, the transmission link capacity prices and the transmission congestion charges (TCCs) that should be collected by the ISO in case of congestion. A monthly auction is conducted in the TR market issuing FTR obligations, FTR options and FGRs to market players, building a link between all types of transmission rights under the same market structure. Combining the advantages of financial and physical rights, the market efficiency can be enhanced by offering a variety of choices for risk management to market players. The monthly TR auction is tested on several case studies using the IEEE three-area RTS96 and useful conclusions are drawn concerning the utility of the various types of transmission rights as compared to one another, in terms of the reimbursement they provide to their holders. Β.11 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Optimal self-scheduling of a thermal producer in shortterm electricity markets by MILP”, ΙΕΕE Transactions on Power Systems, vol. 25, no. 4, November 2010, pp. 1965-1977. This paper addresses the problem of the self-scheduling of a thermal electricity producer who acts as a price-taker in day-ahead energy and reserves markets. A 0/1 mixed integer linear formulation of the producer self-scheduling problem is provided, which allows a realistic and accurate modeling of the unit’s operating phases. A novel unit start-up modeling is presented, in which three different start-up types are modeled, hot, warm and cold, each with distinct start-up cost, synchronization time, soak time and predefined start-up power output trajectories, all dependent on the unit’s prior reservation time. Test results address the effect of the energy and reserves market clearing prices on the producer units’ day-ahead commitment status and profits.

13

Β.12 P. Andrianesis, P.N. Biskas, G. Liberopoulos, “An overview of Greece's wholesale electricity market with emphasis on ancillary services”, Electric Power Systems Research, vol. 81, no. 8, August 2011, pp. 1631-1642. Greece’s wholesale electricity market is a mandatory pool in which the commodities of energy and ancillary services are simultaneously traded and dispatched on the generation units. In this paper, we provide an overview of the Greek wholesale electricity market with emphasis on ancillary services. Considering the wide range of ancillary services, our goal is to contribute to the growing literature on individual case studies and comparisons of different ancillary services markets worldwide, pointing out similarities and differences with other market models. In addition, we discuss several aspects, and report on some of the strengths and weaknesses of the Greek wholesale electricity market model. Β.13 P.N. Biskas, A. Tsakoumis, A.G. Bakirtzis, A. Koronides, J. Kabouris, “Transmission loss allocation through zonal aggregation”, Electric Power Systems Research, vol. 81, no. 10, October 2011, pp. 19731985. This paper presents a methodology for the aggregation of nodal generation loss factors into zonal loss factors, taking into account the geographic as well as the “electrical” proximity of the nodes to the zone centers. The annual net economic consequence (gain or loss) of each generator from the aggregation is estimated and used as an index for the evaluation of the methodology. Additionally, an algorithm for the automated zonal configuration with pre-defined economic consequences is presented. Starting from one zone comprising the whole power system, the algorithm finds the number of zones that keep the economic consequences of zonalization below a pre-defined threshold, and the resulting zonal configuration. By performing an exhaustive search using this algorithm for the “best” initial root node, an optimal zonal configuration can be identified that achieves the pre-defined level of economic consequences with the minimum number of zones. Numerical results from a real power system, the Greek power system, are presented and discussed. Β.14 A.G. Vlachos, P.N. Biskas, “Balancing Supply and Demand Under Mixed Pricing Rules in Multi-Area Electricity Markets”, ΙΕΕE Transactions on Power Systems, vol. 26, no. 3, August 2011, pp. 1444-1453. Market clearing has always been an issue of great interest and research as liberalized electricity markets evolved over time in many countries. As trading in electricity evolves rapidly, multi-area power exchanges appear to substitute the local markets. The tie-lines constitute a significant parameter in multi-area power exchanges, since congestion leads to price differentiation. Prices are affected by physical (e.g., network) constraints, yet they should sometimes follow regulatory policy rules, which do not necessarily reflect or depend on physical characteristics. Until now, all approaches in clearing a multi-area power dispatch (or a multi-area market) are based on a zonal or nodal pricing model, which is applied uniformly to both production and demand within the same zone (or at each node). These approaches are not able to deal with complex pricing rules, which impose price discrimination for supply or demand entities within the same area. This paper presents a mathematical approach for the solution of a multi-area dispatch, in which production and demand of the same area may be cleared in different prices. The main principle is the formulation of a mixed complementarity problem for the system equilibrium conditions, in which supply and demand are associated to explicitly or implicitly defined prices. Illustrative implementations and test results for a simple five-zone system and the 73-bus IEEE RTS-96 are presented. Β.15 A.G. Vlachos, P.N. Biskas, “Simultaneous Clearing of Energy and Reserves in Multi-Area Markets Under Mixed Pricing Rules”, ΙΕΕE Transactions on Power Systems, vol. 26, no. 4, November 2011, pp. 2460-2471. The integration of the spot electricity markets in Europe shall lead to multi-area power exchanges that will substitute the local markets. In such scheme, market prices are affected by physical (e.g., network) constraints, yet they should sometimes follow regulatory policy rules, which do not necessarily reflect or depend on physical characteristics. In some cases, complex pricing rules should be implemented, which impose price discrimination for supply and demand entities within the same area. The methodology presented 14

in this paper enables the balancing of supply and demand in a multi-area market considering energy and reserve bids, under complex pricing rules, which mix energy and reserve prices. A demand bid corresponds to the whole cost a demand entity is willing to pay for its participation in the energy market, including the cost for the procurement of the necessary reserves. The approach attains price integration of energy and reserves markets, simultaneous settlement of energy and reserves, and significant decrease of the payments through the uplift accounts. The main principle is the formulation of a mixed complementarity problem for the system equilibrium conditions, in which supply and demand are associated to explicitly or implicitly defined prices, which may be different even in the same zone. Β.16 C. K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Optimal Self-Scheduling of Thermal Units During Commissioning”, ΙΕΕE Transactions on Power Systems, vol. 27, no. 1, February 2012, pp. 181-188. This paper addresses the self-scheduling problem of an electricity producer who owns thermal generating units during commissioning. A 0/1 mixed-integer linear formulation is presented, which allows an accurate and realistic modeling for the scheduling of the commissioning tests that should be performed once the construction of the thermal unit has been completed and prior to entering its commercial operation. The solution of the Producer self-scheduling problem aims at determining the desired timing of the start-up of the commissioning tests for the next week. A flexible contract between the producer and the contractor regarding the performing period of the commissioning tests is proposed. Under this contract, flexibility is provided in both the number of commissioning tests that should be completed in a given time period and the timing of the start-up of the commissioning tests. The model presented can be used by a producer with thermal units in commissioning, who acts either as a price-taker or a price-maker in the day-ahead energy market. Test results on a medium-scale real test system address the effect that the implementation of the proposed model has on the producer profits as well as on the day-ahead market clearing prices. Β.17 G. A. Bakirtzis, P. N. Biskas, V. Chatziathanasiou, “Generation Expansion Planning by MIP considering mid-term scheduling decisions”, Electric Power Systems Research, vol. 86, May 2012, pp. 98-112. This paper presents a mixed-integer linear programming model for the solution of the centralized Generation Expansion Planning (GEP) problem. The GEP objective is the minimization of the total present value of investment, operating and unserved energy costs net the remaining value of the new units at the end of the planning horizon. Environmental considerations are modeled through the incorporation of the cost of purchasing emission allowances in the units’ operating costs and the inclusion of annual renewable quota constraints and penalties. A monthly time-step is employed, allowing mid-term scheduling decisions, such as unit maintenance scheduling and reservoir management, to be taken along with investment decisions within the framework of a single long-term optimization problem. The proposed model is evaluated using a real (Greek) power system. Sensitivity analysis is performed for the illustration of the effect of demand, fuel prices and CO2 prices uncertainties on the planning decisions. Β.18 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Optimal self-scheduling of a dominant power company in electricity markets,” International Journal of Electrical Power & Energy Systems, vol. 43, 2012, pp. 640-649. This paper addresses the problem of the self-scheduling of a power company with a dominant role in both the production and retail sectors of an electricity market. The dominant power company acts as a pricemaker producer in all day-ahead markets (energy and reserves) as well as an energy retailer through its forward bilateral contracts with final consumers. An integrated 0/1 mixed integer linear programming (MILP) formulation is provided, which combines both thermal and hydro subsystems in a single portfolio for the dominant power company through a detailed modeling of the operating constraints of thermal units and hydroplants. Residual demand curves for energy and reserves are used to model the effect of the power company’s interactions with its competitors. Test results on a medium-scale real test system address the effect that the power company’s forward commitments and the market rules have on its daily self-scheduling and profits as well as on the resulting energy and reserve market clearing prices. 15

Β.19 P.N. Biskas, D.I. Chatzigiannis, G.A. Dourbois, A.G. Bakirtzis, “European Market Integration With Mixed Network Representation Schemes”, ΙΕΕE Transactions on Power Systems, in press. This paper addresses the problem of the self-scheduling of a power company with a dominant role in both the production and retail sectors of an electricity market. An integrated 0/1 mixed integer linear programming (MILP) formulation is provided, which combines both thermal and hydro subsystems in a single portfolio for a dominant power company through a detailed modeling of the operating constraints of thermal units and hydroplants. Residual demand curves for energy and reserves are used to model the effect of the power company’s interactions with its competitors. Test results on a medium-scale real test system address the effect that the power company’s forward commitments and the market rules have on its daily selfscheduling and profits as well as on the resulting energy and reserve market clearing prices. Β.20 P.N. Biskas, D.I. Chatzigiannis, A.G. Bakirtzis, “European electricity market integration with mixed market designs – Part I: Formulation”, ΙΕΕE Transactions on Power Systems, in press. The integration of the day-ahead electricity markets in Europe shall lead to one multi-area market that will substitute the local/national ones. In view of the “target model” that will be enforced in all European markets in conjunction with their forthcoming coupling/integration, a centralized market splitting algorithm is implemented in this paper, respecting the standard market regulatory framework of power exchanges (PXs) and power pools, including 1) block offers/bids, linked block offers/bids, flexible hourly offers/bids and convertible block offers in power exchanges and 2) unit technical/commitment constraints and system operating constraints in power pools. The problem is formulated as a mixed integer linear programming (MILP) model, which can be solved using commercial MILP solvers. The performance and computational requirements of an implementation in pan-European level is presented in the companion paper; the model is tested in terms of problem solvability to its limits, considering a day-ahead market clearing time threshold equal to one hour. Β.21 P.N. Biskas, D.I. Chatzigiannis, A.G. Bakirtzis, “European electricity market integration with mixed market designs – Part II: Solution algorithm and case studies”, ΙΕΕE Transactions on Power Systems, in press. This paper presents the solution algorithm and test results of the market-splitting approach, proposed in the first part of this two-paper series, for the clearing of the forthcoming Internal Electricity Market. The market-splitting approach is implemented in a Europe-wide level, indicatively defining three power pools and 22 power exchanges, comprising 42 bidding areas in total, with each local/national market respecting the standard market regulatory framework of power pools and power exchanges (PXs). The performance and computational requirements of this implementation is presented; the model is tested in terms of problem solvability to its limits, considering a day-ahead market clearing time threshold equal to one hour. The results demonstrate that a viable solution to the clearing of the Internal Electricity Market can be attained with the current state-of-the-art of computers’ processing power. Further discussion is made concerning the viability of the proposed approach and other harmonization issues that should be considered for successful market integration.

D. International Conference Papers D.1 P.N. Biskas, A.G. Bakirtzis, “Decentralized congestion management of interconnected power systems”, MED POWER, pp. 152, 4th-6th November 2002, Athens, Greece. This paper presents a method for the decentralized solution of the congestion management problem in large interconnected power systems. The multi-area congestion management is achieved through cross-border coordinated redispatching by regional transmission system operators. The coordination is performed through a pricing mechanism inspired by Lagrangian Relaxation. The prices used for the coordination of the regional sub-problem solutions are the prices of electricity exchanges between adjacent areas. The results from the 16

application of the method to the three-area RTS-96 are reported. This paper is related with the methodology described in paper B.3. D.2 P.N. Biskas, C.E. Zoumas, A.G. Bakirtzis, “Optimal Reactive Power Flow by Enhanced Genetic Algorithm”, ISAP 2003, 31st August – 3rd September 2003, Limnos, Greece. This paper presents an Enhanced Genetic Algorithm for the solution of the Optimal Reactive Power Flow (ORPF) problem. Both continuous and discrete control variables are incorporated in the proposed algorithm. The continuous control variables modeled are unit active power outputs and generator-bus voltage magnitudes, while the discrete ones are transformer-tap settings and switchable shunt devices. Operating constraints, such as branch flow limits, load bus voltage magnitude limits and generator reactive capabilities are included as penalties in the genetic algorithm fitness function. Advanced and problem-specific operators are introduced in order to enhance the algorithm’s efficiency and accuracy. Numerical results on test systems derived by the replication of the IEEE RTS-96 are presented. D.3 P.N. Biskas, A.G. Bakirtzis, “Decentralized congestion management of interconnected power systems”, UPEC ’03, pp. 393-396, 1st-3rd September 2003, Thessaloniki, Greece. This paper presents a method for the decentralized solution of the congestion management problem in large interconnected power systems. The multi-area congestion management is achieved through cross-border coordinated redispatching by regional Transmission System Operators (TSOs). The method decomposes the overall problem into independent subproblems, one for each area. The solutions of the sub-problems of the different areas are coordinated through a pricing mechanism until they converge to the overall system solution. The prices used for the coordination are the prices of electricity exchanges between adjacent areas. Test results from the application of the method to the IEEE 3-area RTS-96 are presented. This paper is related with the methodology described in paper B.5. D.4 P.N. Biskas, A.G. Bakirtzis, “A decentralized solution to the Security Constrained DC-OPF problem of multi-area power systems”, PowerTech ‘05, 27-30 June 2005, St. Petersburg, Russia. This paper presents a new method for the decentralized solution of the Security Constrained Optimal Power Flow (SCOPF) problem in large interconnected power systems. The method decomposes the overall SCOPF problem of a multiarea system into independent SCOPF sub-problems, one for each area. The solutions of the SCOPF sub-problems of the different areas are coordinated through a pricing mechanism until they converge to a reduced scope central SCOPF solution. The prices used for the coordination of the subproblem solutions are the prices of electricity exchanges between adjacent areas. The reduced scope SCOPF of a multi-area power system is a SCOPF with a reduced set of security constraints, in which the effects of contingencies outside an area on monitored elements within the area are ignored. Test results from the application of the method to the IEEE 3-area RTS-96 and to the Balkan power system are presented. This

paper is related with the methodology described in paper B.6. D.5 P.N. Biskas, N.P. Ziogos, A. Tellidou, C.E. Zoumas, A.G. Bakirtzis, V. Petridis, A. Tsakoumis, “Comparison of two metaheuristics with mathematical programming methods for the solution of OPF”, ISAP ‘05, 6-9 November 2005, Washington, U.S.A. This paper presents a comparison of different optimization methods developed for the solution of the nonlinear OPF problem with both continuous and discrete variables. Two mathematical programming methods are compared with two metaheuristics, a Particle Swarm Optimization implementation and an Enhanced Genetic Algorithm. Test results from the application of the methods to several IEEE systems are presented and compared. Useful conclusions are drawn concerning the execution times and the “optimum” costs provided by all four tested methods. This paper is related with the methodology described in paper B.9. D.6 P.N. Biskas, A.G. Bakirtzis, “Decentralized OPF of large multi-area power systems”, AIESP ‘06, 6-10 February 2006, Madeira, Portugal. This paper presents a method for the decentralized solution of the Optimal Power Flow (OPF) problem 17

of interconnected power systems, with both continuous and discrete variables. The method decomposes the central OPF problem of a multi-area system into independent OPF sub-problems, one for each area. The mathematical decomposition method is based on the decoupling of the first-order (KKT) conditions of the original system-wide OPF problem. The solutions of the OPF sub-problems of the different areas are coordinated through a pricing mechanism until they converge to the system-wide OPF solution. A discretization logic is applied to the solution of the OPF problem with continuous variables, for the handling of the discrete variables. The method requires no parameter tuning for reaching convergence or faster convergence. Results from the application of the method to several IEEE test systems are presented. D.7

P. Biskas, D. Michos, P. Nikolaou, M. Philippou, I. Blanas, “The new HTSO Market Management System”, MED POWER 2008, November 2008.

This paper presents the new Market Management System (MMS) that Hellenic Transmission System Operator (HTSO) acquired by AREVA T&D for the market operations that has to be implemented according to the rules described in the Greek Grid and Exchange Code and its Amendment. The market operations of the MMS are the Day-Ahead Scheduling (DAS), the Dispatch Scheduling (day-ahead DS and Intra-day DS), the Real-Time Dispatch (RTD), the Ex-Post Imbalance Pricing (ExPIP) and the Settlement (day-ahead and imbalance settlement). Each of the above market operations, except from the Settlement, is described in detail in this paper. Also, a brief description of the MMS IT architecture is included. D.8

P.N. Biskas, C.E. Zoumas, M. Philippou, “Co-optimization of commodities in the Greek energy market”, MED POWER 2008, November 2008.

This paper presents the implications of co-optimization of energy and reserves in the day-ahead market that is used in many emerging competitive markets and will be also used in the Greek energy market after the Fourth Reference Day (01/01/2009), as described in the Greek Grid and Exchange Code [1] and its Amendment [2]. The Day-Ahead Scheduling problem formulation is presented, and the relevant energy and reserves prices are computed as a function of the Lagrange multipliers of the problem constraints. A real case is presented to show the interdependence of the prices of energy and reserves provisions. D.9

P. Andrianesis, G. Liberopoulos, P. Biskas, “Tertiary reserve in Greece’s electricity market: The need for peakers”, Conference on the promotion of Distributed Renewable Energy Sources in the Mediterranean region (DISTRES ’09), 11-12 December 2009, Nicosia, Cyprus, Paper ref No: 134, 7

pages. Many recent power system engineering studies have brought into attention the need to incorporate peaker units (or “peakers”) in power systems. Peakers are electricity generation units that can cover the peak load and provide tertiary spinning and non-spinning reserve. In Greece’s electricity market, the increasing interest in Renewable Energy Sources (RES), mostly wind plants, makes the need for peakers even more pressing, because more tertiary reserve is required to preserve system security in cases of sudden changes in RES injection. In this paper, we address in detail the establishment of a tertiary reserve market, by introducing the commodity of tertiary reserve (both spinning and non-spinning) in the Day-Ahead Scheduling (DAS) problem. To provide an estimate of the revenues of peakers from participating in such a market, we simulate the Greek electricity market with a tertiary reserve market add-on, using historical data of generation units, system load and system reserve requirements. Our preliminary results show that the estimated profits are significant indicating that the prospect of a tertiary reserve market can provide the right incentives for investing in peakers. Finally, we discuss potential extensions of our analysis and directions for further research. D.10 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “A MILP Approach to the short term Hydrothermal SelfScheduling Problem”, Bucharest PowerTech Conference, JUN 28-JUL 02, 2009 Bucharest, ROMANIA, Pages: 1696-1703, 2009. This paper provides a simplified modeling of that presented in paper B.11, since the proposed methodology is implemented considering a unique startup type for the generating units. In parallel, the model 18

of the paper B.11 is extended to analyze the self-scheduling problem of an electricity producer, who owns both thermal and hydro generating units. Additional constraints regarding the modeling of the restricted operating zones of hydro units as well as simple energy constraints are considered. Finally, the effect that the clearing prices of the reserves markets has on the commitment and dispatch schedule of the producer generating units as well as on the producer profits is examined. D.11 N.A. Iliadis, P.N. Biskas, “Trading opportunities in the SEE”, General Meeting of the IEEE-Powerand- Energy-Society, JUL 26-30, 2009 Calgary, Canada. Book Series: IEEE Power and Energy Society General Meeting-PESGM, Pages: 458-460, 2009. The SEE electricity market is characterized by its rapid development and growth during the last years. Important companies present in Europe and globally have shown interest for this market and expressed the latter through strategic actions such as project development and joint ventures with local companies. Cross border and internal trading witness an increasing liquidity as the environment becomes more stable, the rules are homogenized and there is activity in infrastructure development. Although the SEE grid has been synchronous with UCTE since 2004 and a common regulation is in process, the region faces actually generation and transmission capacity constraints. The latter have a direct impact on the trading activities, the liquidity and the type of trading in the SEE electricity market performed by the players. D.12 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Effect of increased RES penetration on the system marginal price of the Greek electricity market”, 7th International Conference on the European Energy Market (EEM), 2010. This paper is a precursor of the work described in papers Δ.14. The main difference of this paper from work Δ.14 is that the simulation model was formulated and solved for four indicative days of 2009 (one day per season). The detailed market clearing algorithm of the Greek wholesale day-ahead energy and reserves market was used. The results from the application of the proposed methodology follow, in general, those of work D.14. D.13 P.N. Biskas, C.G. Baslis, C.K. Simoglou, A.G. Bakirtzis, “Coordination of day-ahead scheduling with a stochastic weekly unit commitment for the efficient scheduling of slow-start thermal units”, Bulk Power System Dynamics and Control (iREP) - VIII (iREP), 2010 iREP Symposium. This paper addresses the problem of the coordination of the day-ahead scheduling with a stochastic weekly unit commitment for the efficient scheduling of slow-start thermal units. The solution of the 24-hour unit commitment may lead to cases, in which slow-start thermal units that are initially off-line cannot be scheduled efficiently, due to their long start-up and minimum-up times as well as their large start-up costs. Thus, a new method is proposed, in which the day-ahead scheduling is coordinated with the solution of a weekly unit commitment. The latter is formulated and solved as a two-stage stochastic mixed-integer linear program, under various system and unit operating constraints, according to the provisions of the Greek Grid and Exchange Code. The stochastic parameter of the weekly unit commitment is the unit availability; thus, possible unit outages during the optimization period are taken into account. Test results from the implementation of the proposed method on the medium-scale Greek electricity market are presented. D.14 C.K. Simoglou, P.N. Biskas, A.G. Bakirtzis, “Impact of increased RES penetration on the operation of the Greek electricity market”, 7th Mediterranean Conference and Exhibition on Power Generation, Transmission, Distribution and Energy Conversion (MedPower 2010), Agia Napa, Cyprus, 7-10 November 2010. This paper analyzes the impact that the increased RES penetration in the energy production mix of Greece has on the operation of the Greek electricity market, in terms of the electricity market prices, the total CO2 emissions, the total payment of the consumers for the energy withdrawal and the RES uplift charge, imposed by the government for the payment of the feed-in tariff to the RES producers. The market clearing algorithm of the Greek day-ahead electricity market is used for the simulation of the Greek energy market 19

under ten different scenarios regarding the RES installed capacity. The units’ emissions cost is appropriately incorporated in their total production cost function. Test results from the application of the scenarios on four typical weeks of year 2009 are also discussed. The main difference of this paper from work Δ.14 is that the simulation model was formulated and solved for four indicative weeks of 2009 (one week per season). In addition, it was considered that the total installed capacity of renewable energy accounts only for one technology (wind plants). D.15 P. Andrianesis, G. Liberopoulos, P.N. Biskas, “Impact of emissions cost on the mid-term generation scheduling in the Greek Electricity Market”, 7th Mediterranean Conference and Exhibition on Power Generation, Transmission, Distribution and Energy Conversion (MedPower 2010), Agia Napa, Cyprus, 7-10 November 2010. The EU Emissions Trading Scheme, Europe’s main mechanism for implementing EU climate policy, is driving thermal electricity generation units to incorporate their emissions cost into their variable costs. In this paper, we investigate the impact of this incorporation on the mid-term (yearly) performance of the Greek Electricity Market. To carry out our investigation, we iteratively solve the day-ahead market problem for 365 days, assuming that the generation units internalize the emissions cost in their bids. In order to provide a realistic estimate for the market performance, we use a set of input data that is based on a projection of the current data onto the year 2013. We examine three different scenarios for the prices of gas and oil, which are used to fuel some of the thermal generation units, and seven scenarios for the CO2 prices. To enhance the confidence in our results, we perform a sensitivity analysis of the market performance with respect to outages. We conclude by discussing the major insights and potential extensions of this work. D.16 C. Baslis, P.N. Biskas, A.G. Bakirtzis, “A Profit Maximization Model for a Power Producer in a PoolBased Energy Market with Cost Recovery Mechanism”, 8th International Conference on the European Energy Market (EEM 2011), 25-27 May 2011, Zagreb, Croatia. The objective of this paper is to address the self-scheduling of a power producer in a pool-based energy market where a cost recovery mechanism is applicable. Under the cost recovery framework, generating units are guaranteed to receive payment at least equal to their actual operating cost, if committed. In the proposed model, the effect of cost recovery on the plant’s revenues is included in the objective of the profit maximization problem of the producer, who is assumed to be a price-taker. The proposed method is developed as a mixed-integer linear program using GAMS/CPLEX and tested for the simple case of a small thermal producer owning a single unit, under the general cost recovery provisions of the Greek electricity market. The model constitutes the first step towards a stochastic programming approach for a price-maker producer. D.17 P. Andrianesis, G. Liberopoulos, P.N. Biskas, A.G. Bakirtzis, “Medium-Term Unit Commitment in a pool market”, 8th International Conference on the European Energy Market (EEM 2011), 25-27 May 2011, Zagreb, Croatia. We consider a mandatory pool, based to the one established in the Greek electricity market, in which the unit commitment and the scheduling of energy and reserves are the solution of Day-Ahead Scheduling (DAS), an optimization problem that is solved daily and aims to minimize the system cost for the next day. The single-day horizon of DAS may be rather short for capturing the effects of the long start-up times and large commitment costs of slow-start lignite units; hence, the DAS solution may be myopic, resulting in higher total costs in the long-run. To tackle this problem, the Greek market uses a heuristic approach, in which the units’ shut-down costs are replaced by their start-up costs and the start-up costs are suppressed; this facilitates the start-up and discourages the shutdown of slow-start units. To address and evaluate the “myopic solution” issue of DAS more rigorously, we extend the unit commitment problem to a longer horizon of several days, and keep only the solution for the next day as binding (rolling horizon). We call the resulting approach Medium-Term Unit Commitment (MTUC). We compare the long-run average performance of the MTUC output for different horizon lengths (2, 4 and 7 days) to that of the heuristic DAS approach used in the Greek market. The results show that MTUC brings in a small reduction in the total system cost. 20

D.18 C.K. Simoglou, P.N. Biskas, C.E. Zoumas, A.G. Bakirtzis, “Evaluation of the Impact of RES Integration on the Greek Electricity Market by Mid-term Simulation”, IEEE PES PowerTech 2011, 19 23 June, Trondheim, Norway. This paper presents a yearly simulation model for the analysis of the impact of the large RES penetration in the energy production mix of Greece on the operation of the Greek electricity market. This impact is analyzed in terms of the electricity market clearing prices, the total CO2 emissions, the total payment of the consumers for the energy withdrawal and the RES uplift charge, imposed by the government for the payment of the feed-in tariff to the RES producers. A mid-term scheduling model based on the dayahead market clearing algorithm of the Greek wholesale electricity market is used for the yearly simulation under ten different scenarios regarding the RES installed capacity (multiple RES technologies are considered). Valuable conclusions are drawn from the application of the proposed model for the year 2011. D.19 P.N. Biskas, G.H. Naziris, C.K. Simoglou, C.E. Zoumas, A.G. Bakirtzis, “Market design effects on private producers in Greece”, 17th Power Systems Computation Conference (PSCC), 22-26 August 2011, Stockholm, Sweden. This paper investigates the financial and operational behavior of privately-owned combined cycle gasfired units (CCGTs) in the Greek deregulated electricity market. The mid-term scheduling model used in paper Δ.18 was also used for the simulations. The economic viability of the units is examined through the computation of their total profits under different producer strategies and market regulatory frameworks. Simulations of the Greek electricity market during the years 2011-2012 determine the height of the capacity payment for full recovery of the operating and investment costs of the private CCGT investors. D.20 A.G. Vlachos, P.N. Biskas, “Multi-Area Market Clearing with Complex Pricing Rules”, 17th Power Systems Computation Conference (PSCC), 22-26 August 2011, Stockholm, Sweden. The trend of the European energy markets is towards multi-area markets with coupling mechanisms for the maximization of the economic efficiency though maximization of the utility of the interconnections. Congestion stemming from physical (network) constraints in the interconnections leads to price differentiation. Yet, prices should sometimes follow regulatory policy rules, which do not necessarily reflect or depend on physical characteristics. Until now, all approaches in clearing a multi-area power dispatch (or a multi-area market) are based on a zonal or nodal pricing model, which is applied uniformly to both production and demand within the same zone (or at each node). These approaches are not able to deal with complex pricing rules, which impose price discrimination for supply or demand entities within the same area. This paper presents a mathematical approach for the solution of a multi-area dispatch, in which production and demand of the same area may be cleared in different prices. The main principle is the formulation of a mixed complementarity problem for the system equilibrium conditions, in which supply and demand are associated to explicitly or implicitly defined prices. Illustrative implementations and test results for a simple five-zone system are presented. th

D.21 A.G. Vlachos, P.N. Biskas, “Supporting services for real time wheeling transactions requests”, 16 International Conference on Intelligent System Applications to Power System (ISAP 2011), 25-28 September 2011, Hersonissos, Crete, Greece. As electricity markets emerge, power exchanges and wheeling transactions become a common operating practice in most power systems. This paper considers an interim system which transfers power between two neighboring systems and presents a methodology to estimate the maximum secure wheeling transaction that the interim system is capable to support. By reactive or active power rescheduling actions, the interim system can significantly increase the size of transfer capability, thus offer support services to accommodate the wheeling transaction. The method utilizes an Optimal Power Flow algorithm, in order to calculate the maximum active power that can be transferred, subject to security constraints, as well as the support services provided by the host system. An AC-OPF model is used and a variety of formulations are 21

examined to model the host system actions. The method is intended for application in real time procedures, utilizing the intra-day electricity market processes. An illustrative study case of the methodology is presented for a 26-bus power system supporting wheeling transaction between two neighboring systems. D.22 P.N. Biskas, D.I. Chatzigiannis, A.G. Bakirtzis, “Volume-Coupling Between a Power Pool and a Power Exchange”, 9th International Conference on the European Energy Market (EEM 2012), 10-12 May 2012, Florence, Italy. Recent developments in European Union’s legal and regulatory frameworks are leading to the creation of the Internal Electricity Market, which will substitute the local spot electricity markets. In this direction, a volume-based market coupling approach between a Power Exchange (PX) and a power pool is implemented in this paper, in order to examine the feasibility of the aforementioned integration between markets with significant diversity in their design. The results of the volume-based approach are compared to those of a single market splitting approach, in terms of pricing, overall social welfare and computational time. D.23 C. Baslis, P.N. Biskas, A.G. Bakirtzis, “Price-Based Annual Generation Maintenance Scheduling of a Thermal Producer”, 9th International Conference on the European Energy Market (EEM 2012), 10-12 May 2012, Florence, Italy. The generation maintenance scheduling problem faced by a power producer aims at defining the optimal time intervals for the maintenance of each generating unit. The planning horizon is typically mid-term (yearahead). In this paper, the annual maintenance scheduling problem of a thermal producer is solved with respect to economic and technical security criteria. The aim is to maximize yearly profit, while simultaneously satisfying the operating constraints of the producer's generating units. Specific constraints regarding unit maintenance are also taken into consideration, such as avoiding the simultaneous planned outage of generating units that belong to the same power station, and maintenance intervals that must be scheduled whenever a specific number of operating hours is completed. The generation maintenance scheduling problem is formulated and solved as a mixed-integer linear programming problem using commercial software (GAMS/CPLEX). D.24 P.N. Biskas, C.K. Simoglou, C.E. Zoumas, A.G. Bakirtzis “Evaluation of the Impact of IPPs on the Greek wholesale and retail electricity markets”, 11th IASTED European Conference on Power and Energy Systems, June 25 – 27, 2012, Napoli, Italy. This paper investigates the impact of the installation and participation of conventional generating units owned by Independent Power Producers (IPPs) on the operation of the Greek competitive wholesale and retail electricity markets. The day-ahead market clearing algorithm of the Greek wholesale electricity market is solved sequentially for the 365 days of the year 2012. Two yearly simulations (scenarios) on a daily basis were performed, namely with and without the existence of the IPP generating units. The effect of the participation of IPPs is examined in terms of various market indicators, such as the resulting system marginal prices, the commitment and profitability of the remaining generating units, the system total operating cost, etc. D.25 C.K. Simoglou, P.N. Biskas, and A.G. Bakirtzis, “Optimal Offering Strategies in Day-Ahead Electricity Markets under Uncertainty”, MED POWER 2012, 1-3 October 2012, Cagliari, Sardinia. This paper addresses the self-scheduling problem of a hydrothermal producer, which is formulated and solved as a two-stage stochastic programming problem with recourse in order to account for market uncertainty. The producer is considered to own thermal and hydro generating units and participate as a pricemaker in the day-ahead energy market. Forward bilateral contracts with end-consumers are considered and their effect on the producer self-schedule and profits is examined. The CVaR metric accounting for risk management is also incorporated. Post-processing techniques are applied for the construction of the generating units optimal offer curves to be submitted to the day-ahead energy market.

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D.26 G.A. Dourbois, D.I. Chatzigiannis, P.N. Biskas, A.G. Bakirtzis, “European market integration with both physical and non-physical markets”, 10th International Conference on the European Energy Market (EEM 2013), Stockholm, Sweden, approved for presentation. In view of the forthcoming large-scale RES penetration, physical markets should check the feasibility of the electricity market clearing against their internal (intra-zonal) transmission network constraints, considering full network topology. Three methods for the solution of a market-splitting problem in a Europewide level are implemented in this paper. Two iterative processes are employed, iterating between the overall optimization algorithm and intra-zonal power flows of the countries/regions that identify possible internal congestions; the iterative processes terminate when all internal transmission constraints are satisfied. The results of the iterative processes are compared with the results of a one-stage solution of the overall problem, which incorporates the full set of transmission constraints of all European electricity markets. The proposed algorithms are also compared in terms of computational efficiency using the full UCTE network. D.27 C.K. Simoglou, P.N. Biskas, E.A. Bakirtzis, A.N. Matenli, A.I. Petridis, A.G. Bakirtzis, “Evaluation of the Capacity Credit of RES: The Greek Case”, PowerTech ‘13, 16-20 June 2013, Grenoble, France, approved for presentation. This paper addresses the evaluation of the capacity credit of RES plants in the Greek power system. Five different RES technologies are considered, namely wind, PV, small hydro, biomass, and cogeneration. The methodology adopted uses widely accepted power system reliability indices, such as the loss of load probability (LOLP) and the loss of load expectation (LOLE), computed using the capacity outage probability table (COPT). A three-step procedure for the calculation of the capacity credit for all RES technologies using the effective load carrying capability (ELCC) metric is implemented. Using real historic operational data of the Greek power system, the capacity credit of all RES technologies for the year 2011 are derived. Sensitivity results regarding the effect of the initial installed capacity and the new entrant capacity on the capacity credit are also presented. D.28 C. Baslis, P.N. Biskas, A.G. Bakirtzis, “Impact of Natural Gas Supply, Renewable Penetration and Demand Trends on Power System Maintenance”, PowerTech ‘13, 16-20 June 2013, Grenoble, France, approved for presentation. This paper analyzes the impact of natural gas supply, increased penetration of renewable energy sources and shifting demand trends due to tight financial conditions on generating unit maintenance scheduling. The main focus is on the increased importance of enhancing unit availability in periods of concurrent peak electricity and natural gas demand and limited RES contribution, through proper adjustment of power system maintenance rules, In power systems with peak demand in summer and high PV penetration, this translates into enforcing unit availability during winter. A detailed mixed-integer linear programming model for the yearly maintenance scheduling of a System Operator is developed with GAMS/CPLEX in order to evaluate modifications in maintenance rules. The same model is used to assess the consequences of a shortterm natural gas shortage contingency scenario, given the maintenance decisions of the yearly scheduling process. The method is applied to the Greek Power System. D.29 D.I. Chatzigiannis, P.N. Biskas, A.G. Bakirtzis, “A Market Splitting Approach for the European Electricity Market Integration”, PowerTech ‘13, 16-20 June 2013, Grenoble, France, approved for presentation. The “Target Model” for the European electricity markets integration has received the attention of regulators, economists and market designers in the last years, namely the substitution of local electricity markets with a harmonized multi-area market, with same market segments in all European countries. In view of this market integration, a Europe-wide market-splitting model is presented in this paper, in which each national market retains its regulatory framework/design, namely remains a power pool or a Power Exchange. The developed model is tested in a Europe-wide test case, comprising three power pools and twenty two existing and prospective Power Exchanges. The model solution and the computational efficiency of the proposed implementation are presented in this paper. 23

F. Book Chapters F.1

C.K. Simoglou, P. N. Biskas, A.G. Bakirtzis, “Hydrothermal Producer Self-Scheduling,” Κεφάλαιο 8 στο βιβλίο "Electric Power Systems: Advanced Forecasting Techniques and Optimal Generation Scheduling", CRC Press, Taylor and Francis Group, δημοσίευση 02/2012.

This chapter presents the short-term hydrothermal producer self-scheduling problem. The problem objective is the maximization of the producer profits from his participation in the day-ahead energy and reserves markets. An integrated 0/1 mixed-integer linear programming (MILP) formulation is provided, which combines both thermal and hydro subsystems in a single portfolio for a hydrothermal producer who acts either as a price-taker or a price-maker in the day-ahead market. A detailed modeling of the operating constraints of thermal and hydro generating units is presented. Thermal unit constraints, such as unit operating limits, minimum up and down times, ramp rate limits, start-up and shut down sequences, fuel limitations e.t.c., are discussed. Hydro constraints ranging from simple energy limit constraints to complex hydraulically coupled reservoir constraints with time lags, head dependent conversion efficiencies, hydro unit prohibited operating zones and discrete pumping are presented. Residual demand curves for energy and reserves are used to model the effect of the price maker producer’s interactions with its competitors. Uncertainty of market conditions is also modeled within a two-stage stochastic programming framework, while a specific risk measure is also incorporated. Post-processing techniques are applied for the construction of the generating units optimal offer curves. Numerical results from the application of the MILP-based solution to the short-term self-scheduling problem of a hydrothermal producer participating in the day-ahead market of a medium-scale real power system (the Greek interconnected power system) are presented and discussed. This Chapter has been based on the work described in papers Β.11 and Β.18.

X. CITATIONS He has 245 citations (excluding self-citations, source: ISI). In the following figure, the annual distribution of these citations is shown, as well as the statistics related with these citations (source: ISI). The corresponding statistics in “Scopus” are shown in the second figure (H-index = 8).

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