Energy Technology and Governance Program

ENERGY TECHNOLOGY AND GOVERNANCE PROGRAM

Quarterly Report October – December, 2014

Prepared for:

Prepared by:

1300 Pennsylvania Avenue, NW Suite 550 Washington, DC 20004-3022 www.usea.org

Under USAID Cooperative Agreement Number: AID-OAA-A-12-00036

January 31, 2015

Energy Technology and Governance Program October – December 2014 Quarterly Report

Table of Contents

Executive Summary……………………………………………………………………………………………………………………4 Introduction ...... 3

1. Southeast Europe Cooperation Initiative Transmission Planning Project ...... 5 2. Black Sea Regional Transmission Planning Project (BSTP) ...... 9 2.a. BSTP Sub-Regional Analyses: Azerbaijan-Georgia-Turkey Power Bridge (AGT) ...... 12 2.b. BSTP Sub-Regional Analyses: Armenia-Georgia Integration and Optimization Working Group and Study ...... 14

3. Joint BSTP/Black Sea Regional Regulatory Initiative Workshop & Joint SECI and Black Sea Meeting on Model Integration ...... 15

4. Security of Supply and Mutual Assistance Program for Southeast Europe ...... 16

5. Kosovo ...... 20

6. Ukraine ...... 22

7. Armenia ...... 24

8. Georgia ...... 25

9. Monitoring and Evaluation Plan ...... 28

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AC Alternating Current AGT Azerbaijan-Georgia-Turkey Power Bridge Project B2B Back-to back Station BPA Bonneville Power Administration BSRI Black Sea Regulatory Initiative BSTP Black Sea Regional Transmission System Planning Project CGM Common Grid Model DSO Distribution System Operator BPM Business Process Manual E&E Bureau for Europe and Eurasia EAP Energy Assistance Program for Armenia EIHP Energy Institute Hrvoje Požar EKC Electricity Coordinating Center ENTSO-E European Network of Transmission System Operators – Electricity EPSO Electric Power System Operator of Armenia EPRA Engineering, Procurement, Research and Analysis, Inc. ESCR Effective Short Circuit Ratio ETAG Energy Technology and Governance Program GOGC Georgian Oil and Gas Corporation GSE Georgian State Electrosystem HVDC High Voltage Direct Current IOA Interconnection Operating Agreement ISO Independent System Operator KEDS Kosovo Electricity Distribution System kV Kilovolt M&S Maintenance and Support MW Megawatt NTC Net transfer Capacity MOENR Ministry of Energy and Natural Resources of Armenia MOU Memorandum of Understanding NARUC National Association of Regulatory Commissioners NTC(s) Net Transfer Capacity(ies) OAA Office of Acquisition Assistance OPF Optimal Power Flow PJM Pennsylvania, Jersey, Maryland Interconnect, LLC PSRC Public Service Regulatory Commission of Armenia PSS/E Power System Simulator for Engineers RUM Romania-Ukraine-Moldova Sub-regional Transmission Planning Project RDSM Regional Dynamic Stability Model SRIE Scientific Research Institute for Energy SECI Southeast Europe Cooperation Initiative Transmission Planning Project SEE Southeast Europe

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SOS Security of Supply SPS Special Protection System TEIAS Turkish Electricity Transmission Corporation TOR Terms of Reference TSO(s) Transmission System Operator(s) USAID United States Agency for International Development USEA United States Energy Association

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Energy Technology and Governance Program October - December 2014 Quarterly Report Executive Summary

…The SECI Working Group conducted a meeting in Skopje, Macedonia in November at which the members updated the 2020, 2025 and 2030 planning models; the Sustainability Sub-Committee reported on its progress on developing the Sustainability Business Plan and reviewed progress on the current workplan study evaluating the network and electricity market effects of the undersea cable interconnection under construction to connect Montenegro to Italy…page 8

…The SECI Working Group adopted the terms of reference for its current workplan study, which will evaluate the network and electricity market impacts on Southeast Europe of the undersea cable currently under construction to connect Montenegro to Italy…page 11

…Based on the June 2014 Dynamic Modeling and Analysis training conducted in Tbilisi, the Black Sea Regional Transmission Planning Project Working Group members updated the dynamic models of the five largest power plants in their respective 2020 network models, thereby improving the accuracy of this important planning model used to evaluate network stability…page 16

…A meeting of the Azerbaijan-Georgia-Turkey Power Bridge (AGT) Working Group was conducted in Baku in October 2014, during which the group reviewed the final trial net transfer capacity calculation conducted using the AGT Power Bridge NTC Business Process Manual…17

…The AGT Power Bridge Working Group reviewed and adopted the final report, “Alleviating Congestion in the Transmission Network in Northeast Turkey to Enable Clean Energy Exports from the Caucasus”, which indicated that Turkey is on schedule to reduce network congestion by 2017…page 17

…Under the Armenia-Georgia Integration and Optimization Working Group, the Scientific Research Institute for Energy of Armenia received a 2018 network planning model from the Georgian State Electrosystem and integrated with its 2018 model of Armenia. The models will be used to test the technical feasibility of optimizing the networks combined assets that was identified in a previous phase of the project…page 20

…To leverage resources and synergies, USEA and the Energy Community of Southeast Europe structured a protocol for conducting joint meetings of the USAID/USEA Distribution System Operator Security of Supply Working Group and the Energy Community Distribution System Platform. A first co-located meeting of the projects will be conducted next quarter…page 23

…The City of Brcko, Bosnia Herzegovina completed an analysis on its distribution system’s outages and selected a major electricity circuit upon which to locate a smart grid pilot project in cooperation with Schweitzer Engineering Laboratories (SEL) of Pullman, Washington. The project, which features both in- kind and financial contributions from Brcko, SEL and USAID, will measure the impact the number and duration of distribution system outages as a result of smart grid technology deployment…page 26

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…A USEA consultant from Black and Veatch Engineering provided five weeks of on the ground support to KEK, the national generation company in Kosovo, by providing daily oversight of the repair work being performed on Kosovo Units A4 and A5 by KEK’s contractor, Turbocare…page 29

…USEA contractor, Jonathan Moore, developed an economic model and trained KEK staff on using it to evaluates options for securing electricity in light of the lengthy outage of Units A4 and A5…page 31

…USEA established the Ukraine Power System Support Project in cooperation with Ukrenergo, the national transmission system operator, and completed an analysis of the network’s capacity to remain stable in light of curtailed natural gas imports, curtailed domestic coal production and increased demand for electricity. The analysis recommended a detailed hierarchy of network stability remedial actions that were put into effect by Ukrenergo in December 2014…page 33

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Energy Technology and Governance Program Fiscal Year 2015 Work Plan Quarterly Update

USAID assisted countries in the Southeast Europe Energy Community and the Black Sea region are developing policies, incentives and regulations to support European clean energy mandates and to accelerate integration of their domestic electricity markets with European regional electricity markets. In response, there is heightened interest among private investors and international financial institutions in developing new, clean energy wind, photovoltaic and small hydroelectric generation plants in the Europe and Eurasia (E&E) region. Investment in these technologies has the potential to transform the regional energy economy through, 1) a shift in the electricity generation mix toward clean energy production; 2) the development of regional clean energy electricity markets; and 3) enhanced energy security.

Owing to the intermittent nature imposed by variable wind currents, cloud cover and precipitation, clean energy technologies pose unique technical challenges to their integration in the E&E regional high voltage electricity networks. Best practices in North America and Europe indicate that solutions to clean energy integration lie in a robust and reliable regional electricity transmission network capable of hosting clean energy generators and the transmission of their electrical output. The networks must be sufficiently flexible and reliable to support cross-border markets for clean energy production and the back-up capacity needed to compensate for intermittent generation, while optimizing for the varied weather, geography and the seasonal and temporal production and consumption of electricity in the E&E region.

Toward this end, the Energy Technology and Governance Program will support the following objectives:

1. Plan for robust, reliable cross border transmission interconnections as the backbone infrastructure for cross border trade and exchange of electricity generated by clean and innovative energy technologies

2. Develop technical rules, guidelines, and network infrastructure assessments to accelerate integration of clean and innovative energy technologies

3. Support utility commercialization, privatization and market transformation to improve overall network efficiency and support clean energy market development

4. Build capacity within regional transmission and distribution system operators to develop climate change adaptation and mitigation emergency response and disaster preparedness programs

The delivery mechanisms to support these objectives are:

I. Southeast Europe Cooperation Initiative (SECI) Transmission Planning Project The USEA has supported the SECI Transmission Planning Project since 2002 with the objective to promote regional cooperation in transmission planning through the development of common transmission planning tools and methodologies. Members of the project working group

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represent the transmission system operators (TSO) of Albania, Bosnia & Herzegovina, Bulgaria, Croatia, Kosovo, Macedonia, Montenegro, Romania and Serbia. Neighboring TSOs from Turkey, Hungary, Slovenia, Greece and Italy participate in the project in a support role.

II. Black Sea Regional Transmission System Planning Project The BSTP was established by the United States Agency for International Development, the United States Energy Association and the TSO of the Black Sea region in 2004 to build institutional capacity to develop and analyze the region’s first common transmission planning model. Members of the project working group represent the TSOs of Armenia, Bulgaria, Georgia, Moldova, Romania, Russia, Turkey and Ukraine.

III. Southeast Europe Security of Supply and Mutual Assistance Working Group Similar to the USAID/USEA Southeast Europe Coordination Initiative Transmission Planning Working Group (SECI), USEA will establish a Security of Supply and Mutual Assistance Working Group populated by Southeast Europe distribution company representatives and regulatory authorities. The Working Group will assist utilities in the region to develop common Disaster Preparedness & Emergency Response programs.

IV. Utility Commercialization, Privatization and Market Transformation Bilateral Partnerships with U.S. utilities for Georgia and Kosovo USEA will provide bilateral assistance through utility partnerships in Georgia and Kosovo that will support utilities in these countries to participate in national and regional clean energy markets. The partnerships will employ volunteers from U.S. electric and gas utilities, which will share the cost of the program by contributing the labor associated with their participation in hosting exchange visits and conducting advisory missions overseas.

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1. Southeast Europe Cooperation Initiative Transmission Planning Project (SECI) The USEA has supported the Southeast Europe Cooperation Initiative (SECI) Transmission Planning Project since 2002 with the objective to promote regional cooperation in transmission planning through the development of common transmission planning tools and methodologies. Members of the project working group represent the TSOs of Albania, Bosnia & Herzegovina, Bulgaria, Croatia, Kosovo, Macedonia, Montenegro, Romania and Serbia. Neighboring TSOs from Turkey, Hungary, Slovenia, Greece and Italy participate in the project in a support role.

The SECI Working Group developed the first detailed national and regional steady state, dynamic and short circuit models of the high voltage network for the planning horizons of 2002 and 2005 winter peak and summer minimum conditions. Subsequently, similar national and regional models were developed for 2010, 2015 and 2020. These models are used to identify bottlenecks to regional trade of electricity, model the impact of the transmission network on energy security initiatives, determine the potential to integrate renewable energy resources, and identify network investment requirements.

The SECI Working Group is the steward of the regional models, updating them on a quarterly basis to ensure accuracy as national networks and energy plans change. In FY ’14 the Working Group will develop a 2025 intermediate term and a 2030 long term forecasting model, while continuing to update the 2020 near term model. As steward of the models, it is developing mechanisms and processes to share the models with interested parties, including International Financial Institutions, bilateral donors, and neighboring TSOs with an interest in funding generation and transmission projects consistent with the objectives of SECI participants.

Objective 1: Plan for robust, reliable cross border transmission interconnections as the backbone infrastructure for cross border trade and exchange of electricity generated by clean and innovative technologies.

1. Task One: Organize and Conduct Meetings of the SECI Working Group/Update 2020 and Develop 2025 SECI Transmission Planning Models

The Working Group will continue to update the following national and regional models of the SECI high voltage transmission system: 2020 Load Flow Model 2020 Dynamic Model

In addition to updating the 2020 models, the Working Group will finalize development of the 2025 regional Load Flow model.

The Working Group will develop a set of 2030 load flow and dynamic models to be consistent with the planning requirement time horizons of ENTSO-E. Updates will be coordinated at regularly scheduled quarterly Working Group meetings, at which revisions to the models will be discussed and agreed to.

SECI Working Group Meeting #1 Dates: November 2014 Location: Skopje, Macedonia Objectives: • Update SECI TSP Regional Transmission System Models for 2020, 2025 and 2030 • Review and adopt revised terms of reference for the study SECI TSP Study, “Network and Market Perspectives to 2030: Assessing the Impact of Regional Connections to Italy”.

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• Review and Comment on the SECI Sustainability Business Plan Draft • Exchange Information on Current ENTSO-E Planning Studies

QUARTERLY UPDATE A SECI Working Group meeting was conducted in Skopje, Macedonia on November 4, 2014. The Macedonia Electric Power System Operator (MEPSO) served as the host for the meeting. Mr. Spasov, MEPSO General Director, provided opening remarks during which he recognized SECI’s valuable contributions to the region and longtime success and pledged MEPSO’s support to assist SECI to transition to a self-sustainable organization by October 2016 when USAID funding is set to expire.

EKC presented the current status of the 2020, 2025 and 2030 regional transmission system models (RTSM).

- Each TSO was requested to send their National models for 2025 and 2030 Winter Peak by November 30. - Models from Greece, Turkey, and Slovenia are still missing. - EKC will send an e-mail following the meeting with instructions for preparation of the snapshots for winter and summer peak 2014. - The next model updates are expected to be finalized by the end of May.

EKC provided a presentation on the possibility of merging the SECI and Black Sea Transmission System Planning (BSTP) models. The two regions offer the significant potential for electricity trade as the Black Sea region has a surplus of power generation while the Southeast Europe region has a deficit. Both models are of similar quality and are technically compatible and offer the potential to be merged. EKC proposed that a good pilot test would be to merge the 2020 winter peak load flow model.

- EKC will provide a more detailed presentation on the requirements to merge the two models at the next SECI meeting in February 2015 - USAID / USEA will investigate the possibility to conduct a joint SECI / BSTP in June 2015.

USEA reported on the status of the SECI Sustainability Plan. USAID plans to gradually reduce financial support to SECI in FY 2016 with the goal of SECI being a self-sustainable organization beginning in FY 2017. USEA/USAID and the SECI technical coordinator have convened a SECI Sustainability Committee to assist in brainstorming the path to sustainability.

The committee meets regularly by Skype and is in the process of developing a business plan that comprises the following elements:

• A value proposition & mission statement • Two-year workplan of studies and capacity building consistent with the mission statement • Two year budget establishing member contributions • Governance plan • Staffing Plan • Recommendation for organizational host • MOU to be signed by each TSO at the conclusion of transition period • Legal & taxation analyses and recommendations RTERLY UPDATE The SECI Sustainability Committee has drafted the first three chapters of the SECI Sustainability Business Plan: a SECI Value Proposition and Mission Statement; a proposed two year Workplan of studies and capacity building activities for FY 2015 and FY 2016; and an accompanying budget detailing USAID’s gradual reduction in funding and establishing member contributions.

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USAID / USEA also received formal agreement from MEPSO, the Macedonian transmission system operator, to serve as the institutional host for SECI beginning in FY 2017.

ATTACHMENT ONE: SECI Working Group Meeting Agenda

ATTACHMENT TWO: SECI Working Group Meeting Minutes

ATTACHMENT THREE: Draft Two of the SECI Sustainability Business Plan

SECI Working Group Meeting #2 Dates: February 2015 Location: Sarajevo, Bosnia Herzegovina Participants: Two Representatives from each SECI TSP TSO Objectives: • Update SECI TSP Regional Transmission System Models for 2020, 2025 and 2030 • Review First Draft of Network Component Assessment of the SECI TSP Study, “Network and Market Perspectives to 2030: Assessing the Impact of Regional Connections to Italy” • Review and Approve SECI Sustainability Business Plan for Submission to Senior TSO Management • Introduce TOR for the FY15 SECI TSP Study • Exchange Information on Current ENTSO-E Planning Studies

SECI Working Group Meeting #3 Dates: June 2015 Location: Vienna, Austria Participants: Two Representatives from each SECI TSP TSO Objectives: • Update SECI TSP Regional Transmission System Models for 2020, 2025 and 2030 • Review and Approve Final Draft of Network Component Assessment of the SECI TSP Study, “Network and Market Perspectives to 2030: Assessing the Impact of Regional Connections to Italy” • Provide Brief on SECI TSP Capabilities and Study Findings for Energy Community Secretariat • Review and Approve SECI Sustainability Business Plans Amendments Proposed by TSO Senior Management Comments • Approve FY15 SECI TSP Study TOR • Exchange Information on Current ENTSO-E Planning Studies

2. SECI Training and Capacity Building

The SECI TSP will conduct the following training and capacity building relevant to the daily operations of the member TSOs and in support of SECI studies and assessments in this workplan.

Developing and Applying Generation Cost Curves for Market and Network Analyses Date: May 2015 (coincidental to SECI TSP Working Group Meeting) Duration: Two Days Participants: Two Representatives from each TSO

Course Description: With the gradual introduction of wholesale electricity market trade, development of the network is no longer centrally planned, but is increasingly driven by market forces determining

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the location of generation facilities, load flows and the extent to which distributed generation penetrates the network. To better understand market behavior, TSO must improve their capacity to forecast new and unanticipated load flows resulting from the optimization of arbritage between wholesale markets with varying prices of electricity.

This training course will introduce TSO to sources of data used to develop generation cost curves, including both fixed and variable costs; the process of constructing such curves, including development of ramping costs; Excel and software applications used to develop cost curves; and the use and application of optimization software used to conduct network analyses.

Responsible Parties: USEA Milestones:

Date Action Jan – Mar 2015 Draft Terms of Reference for Trainer& Identify Trainer April 2015 Develop Training Materials May 2015 Conduct Training

QUARTERLY UPDATE There was no activity on this workplan during this quarter.

3. Network and Market Perspectives to 2030: Assessing the Impact of Regional Connections to Italy

As a region, Southeast Europe is characterized by an overall deficit of generation capacity and electricity supply. With its predominance of hydroelectric and lignite generation capacity, it is largely dependent on weather and hydrology for stable supplies and prices of electricity. Nascent electricity markets support limited electricity trade resulting from variations in available generation capacity and hydrology within the region, but lack the depth and liquidity necessary to attract investment in new generation capacity. Furthermore, congestion and bottlenecks in the internal high voltage transmission networks of Southeast Europe are technical limitations to electricity trade.

These challenges will be compounded when the high voltage undersea direct current (DC) cable connecting the networks of Montenegro and Italy is constructed and energized, as soon as 2016, resulting in unforeseen changes in electricity flows and economics of regional electricity trade. The SECI TSP will address these challenges by planning for transmission infrastructure investments necessary to ensure system stability and incentivize the investment in clean energy resources required to address the region’s capacity deficit in a low carbon manner. Working with system operators, policy makers, regulators and donors in Southeast Europe, the SECI TSP will ensure network stakeholders fully understand the scope of impending changes associated with the Montenegro-Italy interconnection and further ensure they are prepared with a set of system stability plans and recommendations to reinforce the network in light of the potentially radically different patterns of electricity trade and power flows it will bring.

Using SECI network planning models developed and updated by the SECI Working Group in 2014, the SECI TSP will conduct an analysis to assess the network stability and electricity market impact of the new undersea cable under construction to connect Montenegro with Italy. The assessment will measure the technical and economic impact of projected electricity exports from the region to Italy, with an emphasis on the incentives it will provide for new clean energy investments in, and exports from, Southeast Europe.

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Preparation of the assessment will be conducted in two phases: 1) development of the common regional market model; 2) preparation of the network and market analyses.

Phase one will be completed in FY 2015 and Phase two will be completed in FY 2016.

Responsible Parties: USEA, Energy Institute Hrvoje Požar (EIHP), EKC Milestones:

Date Action Nov 2014 Adopt Terms of Reference and Distribute Data Survey March 2015 Phase1 – Task 1: Creation of database for market analyses June 2015 Phase1 – Task 2: Methodology for market studies June 2015 Phase1 – Task 3: Development of network models for target years (2025/2030)

QUARTERLY UPDATE

A Terms of Reference was developed for the study Market and Technical Impact Assessment of the Integration of the Electricity Markets in Southeast Europe and Italy.

The study will provide a market and technical based analysis resulting from the construction of the HVDC undersea cable connecting Italy and Montenegro. The study will focus on the integration of Italian and SEE electricity market and give answer to the following questions: • Are there sufficient surpluses in SEE to feed the HVDC cables? • What would be the price increase in SEE resulting from exports to Italy? • Where will network congestion be located in the event of HVDC outages? • What will be the impact of electricity exports on national balances?

The expected results from this Study are: • Cross-border power exchange (MWh/h) for each border in the region on hourly basis • Projected electricity prices (€/MWh) for each country in the region on hourly basis • Projected HVDC line loadings (MWh/h) for each HVDC submarine cable on hourly basis • Country electricity balance (MWh) for each country with and w/o new HVDC links.

The study will be divided into the following two phases to be conducted over the next two years: 1) Preparation of a common market model and relevant network model for 2025/2030 2) SEE market perspectives study.

The first phase will be conducted during FY 2015 and will consist of the following tasks: 1) Definition of relevant input data needed for the market analyses on the regional level, as well as to be detailed enough for internal TSO analyses, 2) Collection of existing input data from existing PSS/E models, TSOs and PEMDB 3) Clarification of missing input data, 4) Verification of common market model, and 5) Decisions on the market study methodology, future versions, format of common market models, as well as the eventual common market software platform.

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The second phase will take place in FY 2016 and will be to assess perspective electricity market behavior in the Southeast Europe region considering the:

1) Influence of generation development involving renewable energy sources, 2) Market integration and 3) Subsequent needs for transmission investments.

ATTACHMENT FOUR: Terms of Reference for Market and Technical Impact Assessment of the Integration of the Electricity Markets in Southeast Europe and Italy

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2. Black Sea Regional Transmission System Planning Project

The Black Sea Transmission Planning Project (BSTP) was established in 2004 by the United States Agency for International Development, the United States Energy Association and the TSOs of the Black Sea region into build institutional capacity to develop and analyze the region’s first common transmission planning model. Members of the project working group represent the TSOs of Armenia, Bulgaria, Georgia, Moldova, Romania, Russia, Turkey and Ukraine.

The BSTP Working Group developed the first detailed national and regional load flow and dynamic models of the high voltage network for the 2010, 2015 and 2020 planning horizons. These models are used to identify bottlenecks to regional trade of electricity, model the impact of the transmission network on energy security initiatives, determine the potential to integrate renewable energy resources, and identify network investment requirements.

The models were updated to reflect more accurate estimates of new renewable capacity projected to be added to the network in 2015 and 2020. Using the Optimal Power Flow feature of PSS/E, the Working Group produced transmission constrained optimized dispatch models of the national and regional power systems. The optimized models tested the security and reliability of the regional network using economically based scenarios for cross border trade. The results suggest where network reinforcement and new interconnections are required to optimize regional trade of new, clean and renewable resources.

The BSTP Working Group is the steward of the regional models, updating them on a quarterly basis to ensure accuracy as national networks and energy plans change. In FY ’15 the Working Group will complete development of a 2025 intermediate term forecasting model, while continuing to update the 2020 near term model. In addition, it will continue to develop mechanisms and processes to ensure model sharing with interested parties, including: International Financial Institutions, bilateral donors, and neighboring TSOs with an interest in funding generation and transmission projects consistent with the objectives of the BSTP.

1. Organize and Conduct Meetings of the BSTP Working Group/Update 2020 and Develop 2025 BSTP Transmission Planning Models The Working Group will continue to update the following national and regional models of the Black Sea high voltage transmission system:

• 2020 Load Flow Model • 2020 Dynamic Model • 2020 Optimal Power Flow Model

A set of new 2025 models will be developed during this phase of the BSTP. Model developments, updates, and subsequent revisions will be discussed and coordinated at regularly scheduled Working Group meetings

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a) BSTP Working Group Meeting #1 Dates: January 2015 Location: Bucharest, Romania Objectives: • Update BSTP Regional Transmission System Models for 2020 • Continue Development of 2025 Load Flow Network Planning Model • Commence the Analysis of the Market and Social Welfare Cost Benefit Components of the ENTSO-E Cost Benefit Analysis Methodology of New Network Reinforcement Projects of Regional Significance • Exchange Information on Electricity Sector Developments in Each Country

QUARTERLY UPDATE This activity was postponed to March 2015 in coordination with USAID to accommodate a joint meeting of the BSTP and the Black Sea Regulatory Initiative to be jointly hosted by USEA and NARUC. The joint meeting will be conducted immediately following the two day BSTP Working Group meeting.

b) BSTP Working Group Meeting #2 Dates: May 2015 Location: Lviv, Ukraine Objectives: • Update BSTP Regional Transmission System Models for 2020 • Continue Development of 2025 Load Flow Network Planning Model Development • Review Data Surveys and Preliminary Results of the Market and Social Welfare Components of the ENTSO-E Cost Benefit Analyses of New Network Reinforcement Projects of Regional Significance • Exchange Information on Electricity Sector Developments in Each Country

c) BSTP Working Group Meeting #3 Dates: September 2015 Location: Sofia, Bulgaria Objectives: • Update BSTP Regional Transmission System Models for 2020 • Finalize Development of 2025 Load Flow Network Planning Model Development • Review Final Draft Report on the Market and Social Welfare Components of the ENTSO- E Cost Benefit Analyses of New Network Reinforcement Projects of Regional Significance • Exchange Information on Electricity Sector Developments in Each Country

2. Conduct ENTSO-E Market and Social Welfare Cost Benefit Analyses of New Network Reinforcement Projects of Regional Significance Having completed the network analysis portion of the ENTSO-E cost benefit analysis of network reinforcement project of regional significance, The Working Group will adapt and analyze the Social Welfare components. When completed, the TSOs will have been trained in, and will have conducted, technical, social welfare, and environmental analyses of proposed network reinforcement projects of regional significance. These projects will form the basis of new interconnections and internal reinforcements needed to accelerate trade and exchange of clean energy in the region. Completion of the adaptation of the ENTSO-E Cost Benefit Analysis methodology to the Black Sea region provides the TSOs with another tool in their planning toolboxes that is consistent with best practices in Europe and provides them with new dimensions

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for analyzing projects, including a project’s capacity to integrate renewable energy, reduce carbon emissions and lower the price of electricity to end-use consumers.

A critical component of completing the market and social welfare components of the Cost Benefit Analysis is the completion of the 2025 load flow, OPF and Dynamic network models upon which the analysis will be conducted.

a) Market and Social Welfare Based Assessment of Network Reinforcements Projects of Regional Significance

TASK ONE: Market Based Assessment The TSOs will employ the adapted ENTSO-E methodology (Black Sea CBA Methodology) and according to the available data it will calculate the reduction in total generation costs (including the cost of CO2 emissions on an explicit basis) associated with the candidate Project.

Responsible Party: EKC

Action Date Socio-economic Welfare Benefit Calculation April 2015

QUARTERLY UPDATE There was no activity on this workplan element during this quarter in accord with the workplan project schedule.

TASK TWO: Indicative (non-numerical) benefit categories According to the adapted ENTSO-E methodology (Black Sea CBA methodology) the consultant will assess each selected transmission project for the following indicators: • Renewable Energy Sources (RES) integration – measured via installed MW of RES connected and with the equivalent CO2 reduction level. • Technical resilience/system safety – rare contingencies, special network states, strategic influences • Flexibility – ability to comply with different electricity market scenarios and potential uncertainties in the Black Sea region. • Social and environmental sensibility – evaluation of this indicator will be supported by performed environmental studies, where available and relevant.

Action Date Indicative (Non-Numerical) Benefit Categories May 2015

QUARTERLY UPDATE There was no activity on this workplan element during this quarter in accord with the workplan project schedule.

TASK THREE: Final Report on Market and Social Welfare Components of Cost-benefit Analyses (Phase 2) On the basis of Black Sea CBA Methodology the consultant will perform a multi-criteria assessment for each candidate transmission line identified by the TSOs. The consultant will score the above mentioned indicators on the following scale: Negative, Neutral, Minor Positive, Medium positive or

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High Positive impact. The overall technical assessment of all of the analyzed projects will be given in appropriate form as a multi-criteria matrix.

Action Date First Draft of Cost-Benefit Analyses (Phase 2) July 2015 Final Draft of Cost-Benefit Analyses (Phase 2) September 2015

QUARTERLY UPDATE There was no activity on this workplan element during this quarter in accord with the workplan project schedule.

TASK FOUR: Regular updates of regional models for load flow, OPF and dynamic analyses – Phase The following data exchange protocol has been agreed to by the BSTP Working Group:

• TSOs send updates to EKC by February 28, 2015 as well as new OPF and dynamic models for 2025 • EKC distributes updated regional model by March 31, 2015 • TSOs send updates to EKC by July 15, 2015 • EKC distributes updated regional model by September 20, 2015

The consultant will collect all model updates from the TSOs and integrate them into the regional model. Thereafter, the consultant will check the accuracy of the models and update and correct them, as needed. The models will be updated based on the model guidelines adopted by the BSTP Working Group.

Action Date TSO Regional Model Updates with new OPF and Dynamic February 2015 models sent to EKC EKC Distribution of Updated Regional Model March 2015 TSO Regional Model Updates sent to EKC July 2015 EKC Distribution of Updated Regional Model September 2015

QUARTERLY UPDATE At the September 2014 BSTP Working Group meeting conducted in Yerevan, Working Group members reviewed the most important lessons learned during the Dynamic Modeling Analysis and Training conducted in Tbilisi in June. In support of further capacity building and in support of updating the BSTP regional dynamic model, Working Group members accepted a “homework” assignment to update the dynamic models of the five largest power plants in their current network model using the information received during the Tbilisi training course.

During this quarter, USEA received updated dynamic models of the five largest power plants in their respective systems from all members with the exception of Turkey and Romania. USEA expects to receive the Romanian models prior to the next BSTP Working Group meeting to be conducted in Bucharest in March 2015.

EKC is currently reviewing the models and will provide feedback to the Working Group members in anticipation of integrating the updates into the regional models prior to the March 2015 Working Group meeting. ETAG Quarterly Report October – December 2014 Page 17

2.a BSTP Sub-Regional Analyses: Azerbaijan-Georgia-Turkey Power Bridge (AGT)

Objective 2: Develop technical rules, guidelines, and network infrastructure assessments to accelerate integration of clean and innovative energy technologies

1. Organize and Conduct Meetings of the AGT Power Bridge Working Group The Working Group will continue to perform monthly NTC calculations and prepare an analysis of the maximum intermittent renewable energy capacity that may be integrated in the synchronously connected networks of Azerbaijan and Georgia.

QUARTERLY UPDATE A meeting of the Working Group was conducted in Baku, Azerbaijan in October. This meeting of the Working Group was originally scheduled to be conducted in September, but was postponed to October to coincide with the Annual Investment Conference of the Energy Regulators Regional Association conducted from October 26-28. This constituted a deviation to the FY14 workplan.

During the meeting, the Working Group reviewed the Net Transfer Capacity calculations for the months of September and October that provide an indication to transmission system operators, regulators and electricity traders of the capacity on interconnection lines in the sub-region to transmit electricity from Azerbaijan and Georgia to Turkey.

The performance of the TSOs in preparing the monthly calculations indicate they have internalized the procedures prescribed in the BPM and have developed a capacity to perform the calculations largely independent of the technical support provided through the Energy Technology and Governance Program.

TEIAS and EPRA reported on the Working Group’s study on Alleviating Congestion in the Transmission Network of Northeast Turkey to Enable Clean Energy Exports from the Caucasus. The report indicates that reinforcements to the 400 kV network in Northeast Turkey and deployment of an automated Special Protection System by TEIAS will have alleviated the most significant sources of congestion by 2017.

This meeting marked the conclusion of the third phase of the AGT Power Bridge Project, which was established in 2009 with the signing of a Memorandum of Understanding between Azerenerji, Georgian State Electrosystem, Turkish Electricity Transmission Corporation and the United States Energy Association. The Working Group members noted that the project has largely accomplished the objectives it established for itself.

Having met its objectives, the Working Group considered the benefits of continued cooperation in a new project phase. Members suggested two topics for consideration should USAID and USEA elect to continue its support in a fourth phase:

• Continued support for the NTC calculations on a monthly basis • Joint analysis of the maximum potential to integrate wind and solar power in the networks of Azerbaijan and Georgia and solar power in Turkey, with an emphasis on the impact of renewable energy development in these countries on clean energy exports to Turkey

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USAID and USEA advised the Working Group members they would consider this request in the context of available resources and inform the Working Group as to whether current funding will permit the extension of the Working Group in another phase of cooperation.

ATTACHMENT FIVE: OCTOBER 2014 AGT POWER BRIDGE WORKING GROUP MEETING AGENDA

ATTACHMENT SIX: OCTOBER 2014 AGT POWER BRIDGE WORKING GROUP MEETING PARTICIPANT LIST

ATTACHMENT SEVEN: OCTOBER 2014 AGT POWER BRIDGE WORKING GROUP MEETING PRESENTATIONS

ATTACHMENT EIGHT: OCTOBER 2014 AGT POWER BRIDGE WORKING GROUP MEETING REPORT

a) AGT Power Bridge Working Group Meeting #1 Dates: January 2015 Location: Bucharest, Romania Objectives: • Review NTC Calculations Performed for November and December 2014 and January 2015 • Review Final Data Collected for Renewable Energy Integration Study • Review Initial Renewable Energy Capacity Assignments to Specific Substations • Exchange Information on System Developments in each Country

QUARTERLY UPDATE The meeting of the AGT Power Bridge Working Group scheduled to be conducted in January 2015 has been rescheduled to coincide with the meeting of the BSTP Working Group to be conducted in March 2015. The decision to postpone the meeting was taken jointly with USAID to enable the BSTP suite of meetings to coincide with a joint meeting of the BSTP and Black Sea Regulatory Initiative to be co-hosted with NARUC in March 2015. This is a deviation to the ETAG Workplan.

b) AGT Power Bridge Working Group Meeting #2 Dates: May 2015 Location: Lviv, Ukraine • Objectives: • Review NTC Calculations Performed for January – April 2015 • Review and Comment on First Draft of Renewable Energy Integration Study • Discuss Potential Terms of Reference on Project to Develop a methodology for Calculating Wheeling Charges Associated with Electricity Exports from Azerbaijan through Georgia to Turkey • Exchange Information on System Developments in each Country

c) AGT Power Bridge Working Group Meeting #3 Dates: September 2015 Location: Sofia, Bulgaria Objectives:

ETAG Quarterly Report October – December 2014 Page 19

• Review NTC Calculations Performed for May – September 2015 • Accept Final Report on Renewable Energy Integration Study and Present to Working Group Members and Regulators • Agree to Final Terms of Reference on Project to Develop a methodology for Calculating Wheeling Charges Associated with Electricity Exports from Azerbaijan through Georgia to Turkey • Exchange Information on System Developments in each Country

2. Renewable Energy Integration Study for Azerbaijan and Georgia The Working Group conduct a study to determine the maximum intermittent renewable energy capacity that may be integrated in the synchronous interconnection between Azerbaijan and Georgia. The study will consist of the following two components:

i. A contingency based Renewable Energy Source (RES) capacity allocation by substation in Azerbaijan, Georgia (wind and solar) and Turkey (solar). ii. Verification of the capacity allocation through a study to determine compliance with N-1 security and reliability standards and planning criteria.

With support from EPRA, the Working Group will evaluate the potential to integrate RES in the national power networks of each country based on the following studies: 1. Priority allocation of RES to substations in each country, as follows: . Allocation of wind and solar capacity by substation for Azerbaijan and Georgia . Allocation of solar capacity by substation for Turkey 2. N-1 static contingency criteria agreed to by the transmission system operators of each country

The Working Group will allocate RES capacity by individual substation based on existing wind and solar maps of each country. After prioritizing and allocating RES capacity by substations, EPRA will assist the Working Group to evaluate the maximum permissible levels RES capacity that may be integrated based on the planning criteria of each national power system. The consultant will employ the N-1 contingency criteria to determine the maximum RES integration for each TSO. After the defining the permissible RES integration capacity based on the N-1 contingency analysis, EPEA will conduct a transient stability study to verify the permissible RES integration capacity. The transient stability analysis will be based on the use of a commonly agreed-to grid code. Recognizing that grid code studies are currently in progress in Azerbaijan and Georgia and that TEIAS developed and has utilized a wind power grid code for five years, EPRA will employ the Turkish power grid code as guide for conducting the transient stability analysis. Responsible Party: EPRA

Action Date Allocation of Wind and Solar Capacity to Substations January 2015 N-1 Contingency Analysis May 2015 Commence Transient Stability Analysis June 2015 Review Initial Transient Stability Analysis Results September 2015

ETAG Quarterly Report October – December 2014 Page 20

QUARTERLY UPDATE Implementation of this workplan element is in suspense as a project of the AGT Power Bridge Working Group, pending a decision on the disposition of the Working Group. USAID and USEA are considering implementation of this renewable energy integration study as separate bilateral projects in Georgia and Azerbaijan, as Turkey has completed a similar study and because Turkey is not eligible to receive USAID assistance. Accordingly, USEA is in discussions with the USAID Mission in Baku about commencing a bilateral program with Azerenerji and in Georgia about adding the Renewable Energy Integration study to the bilateral workplan.

2.b BSTP Sub-Regional Analyses: Armenia-Georgia Integration and Optimization Working Group and Study

a) Finalize Integration and Optimization Study The Armenia-Georgia Integration and Optimization Working Group will finalize the Analysis of the benefits of integrating the networks through the proposed HVDC B2B substation to be constructed in 2018. The remaning task it to conduct a load flow study to verify the results of the GT Max optimization study perpared by SRIE in FY14.

Responsible Party: SRIE

Action Date Complete N-1 Load Flow Study to Validate GT Max January 2015 Optimization Findings & Present Final Report

b) Armenia-Georgia Integration and Optimization Working Group Meeting #1 Dates: January 2015 Location: Bucharest, Romania Objectives: • Present and Accept Final Results of Integration and Optimization Study

QUARTERLY UPDATE During this quarter, GSE provided PSS/E models for one week in each of the seasonal regimes to be analyzed for the 2018 forecast model year. The models were forwarded to the Scientific Research Institute for Energy (SRIE) of Armenia. SRIE integrated the Georgian 2018 seasonal models with those of Armenia and commenced the network technical analysis of the least cost dispatch suggested by the analysis of the integrated GT Max production cost models of Armenia and Georgia integrated by SRIE in the previous quarter.

The final analysis of the network’s capacity to deliver the economic benefits suggested by the GT Max optimization of the coupled networks will be delivered at a final meeting of the Working Group in February 2015 in Tbilisi, Georgia. This constitutes a deviation to the ETAG Workplan to accelerate presentation of the analysis instead of delaying its presentation until the March 2015 BSTP meeting to be conduced in Bucharest.

ETAG Quarterly Report October – December 2014 Page 21

3. Joint BSTP/Black Sea Regional Regulatory Initiative Workshop & Joint SECI and Black Sea Meeting on Model Integration

1. Conduct a Joint Meeting with the Black Sea Regional Regulatory Initiative A meeting of the BSTP and the Black Sea Regional Regulatory Initiative will be conducted to exchange information on current topics of analysis and industry trends to accelerate harmonization of a common industry/regulatory knowledge base. Topics for discussion will include: the development of scenarios jointly proposed by regulators and TSOs for network analysis employing the PSS/E OPF model, a review of the NTC calculation and allocation procedures being adopted in the region and market monitoring for cross border transmission capacity. This activity will require agenda and logistical coordination with the National Association of Utility Regulatory Commissions (NARUC).

a) Dates: January 2015 Location: Bucharest, Romania Ojectives:

• Conduct Workshop for BSRI on BSTP Models • Present Findings of ENTSO-E Cost Benefit Analysis Methodology for Network Reinforcement Projects of Regional Significance

QUARTERLY UPDATE This meeting will be conducted in March 2015 in conjunction with the meetings of the BSTP and BSRI. This constitutes a deviation to the ETAG Workplan.

b) Dates: September 2015 Location: L’viv, Ukraine Objectives:

• Obtain input from Regulators on Future BSTP Scenarios and Analyses • Present Findings of ENTSO-E Cost Benefit Analysis Methodology for Network Reinforcement Projects of Regional Significance

2. Conduct a Joint Meeting of the BSTP and SECI Working Groups A meeting of the SECI and BSTP working groups will be conducted to exchange information on how the excess generation capacity of the Black Sea Region can be efficiently transmitted to Southeast Europe which does not have enough capacity to meet demand.

Dates: May 2015 Location: L’viv, Ukraine Objectives: • To review the Black Sea and the Southeast Europe transmission system networks • To discuss possibilities for transmitting power between the two regions via Turkey

ETAG Quarterly Report October – December 2014 Page 22

4. Security of Supply and Mutual Assistance Program for Southeast Europe

Objective 4: Build capacity within regional transmission and distribution system operators to develop climate change adaptation and mitigation emergency response and disaster preparedness programs

Climate change induced and manmade outages occurring in the distribution system networks in Southeast Europe threaten the security of electricity supply for end-user consumers and disrupt economic activity. To assist distribution system operators in Southeast Europe and reduce the breadth and scope of outages in their networks, USAID, together with the United States Energy Association, has established a Southeast Europe Distribution System Operator (DSO) Security of Supply Working Group. Working Group members currently include representatives from the DSOs of:

Albania Bosnia and Herzegovina Croatia Kosovo Macedonia Serbia

Representatives from the regulatory agencies (RAs) in these countries serve as observers to the Working Group. Modelled after the Southeast Europe Cooperation Initiative (SECI) Transmission System Planning Project, the activities of the DSO Security of Supply Working Group will be demand driven to respond to the needs of the distribution companies in the region, with an emphasis on the following deliverables:

• Business continuity plans to help electric companies plan for all scenarios, such as severe weather events that may impact their ability to provide reliable electric power to consumers; • Mutual assistance plans to encourage distribution companies to share staff and materials considered necessary for fast restoration of service after a significant outage; • Maintaining and sharing critical inventory to ensure adequate supply of spare parts necessary to respond to outage events; • Emergency procurement systems to allow for rapid procurement of essential equipment in emergency situations; • Asset management programs to optimize the life of distribution network infrastructure; and • Benchmarking of best practices.

These deliverables will assist the SEE DSOs to harden their distribution systems, thereby mitigating potential system outages induced by weather and climate related events. It will also assist them to adapt to climate induced outages by improving their ability to restore service in an efficient and timely manner as a result of weather related system disturbances.

Though it is widely accepted that distribution system outages continue to plague Southeastern European electric power systems, the exact number, frequency, duration and the scope of outages in terms of the number of customers effected is not quantified.

ETAG Quarterly Report October – December 2014 Page 23

QUARTERLY UPDATE Energy Community of Southeast Europe Electricity Distribution System Operator Coordination Platform (ECDSO-E) Working Group Meeting – December 11, 2014 – Vienna, Austria

USEA, at the request of USAID participated in the Energy Community of Southeast Europe Electricity Distribution System Operator Coordination Platform (ECDSO-E) Working Group Meeting on December 11 in Vienna, Austria.

The USAID / USEA Southeast Europe Distribution System Operator Security of Supply Working Group and the ECDSO-E Coordination Platform share complementary goals and common members and we have agreed to leverage resources and expertise whenever possible.

Participation in the meeting enabled USEA to improve its understanding of the ECDSO-E working group and to introduce the work of the USAID / USEA DSO Working group to the members of the ECDSO-E and to the Energy Community Secretariat. During the meeting it was decided that the next working group meetings would be co-located and take place the week of February 2 in Sarajevo. The agendas and other logistical details would be coordinated following the holidays.

1. Conduct Meetings of the Southeast Europe Distribution System Operator Security of Supply Working Group

a) Southeast Europe Distribution System Operator Security of Supply Working Group Meeting #1 Dates: February 2015 Location: Sarajevo, Bosnia Herzegovina Objectives: • Present Final Benchmarking Report • Discuss Recommendations for Improving Outage Management Resulting from Benchmarking • Presentation of new Committee on Network Losses • Present preliminary findings from Lessons Learned from 2014 Flooding and Ice Storm Disasters in Southeast Europe • Adopt Terms of Reference for Connection of Distributed Generation to Distribution Networks: Recommendations for Technical Requirements, Procedures and Agreements Study

QUARTERLY UPDATE During this quarter, USEA developed the draft agenda for the February 2015 DSO Working Group meeting and coordinated the contents of it’s Working Group meeting agenda with the Energy Community’s DSO platform agenda.

b) Southeast Europe Distribution System Operator Security of Supply Working Group Meeting #2 Dates: May 2015 Location: Vienna, Austria Objectives: • Review and Adopt Final Lessons Learned from 2014 Flooding and Ice Storm Disasters in Southeast Europe • Present preliminary findings from Connection of Distributed Generation to Distribution Networks: Recommendations for Technical Requirements, Procedures and Agreements Study • Presentation on ADMS Pilot Project

ETAG Quarterly Report October – December 2014 Page 24

2. Connection of Distributed Generation to Distribution Networks: Recommendations for Technical Requirements, Procedures and Agreements

The Working Group will initiate a region-wide study to identify obstacles to accelerated deployment of distributed generation resources and recommend solutions to overcoming them on a country-by- country basis. The study will:

a. Identify international best practices for safely connecting distributed generation facilities to medium and low voltage networks while maintaining system security and reliability;

b. Recommend solutions to overcoming legal and regulatory changes to customer owned distributed generation and net metering;

c. Discuss decoupling of utility revenue from volumetric based tariff methodologies to incentivize distribution system operators to connect customer owned and utility owned distributed generation to the network;

d. Recommend terms for provision of emergency back-up power from distribution system operators to facilities at which customer owned generation is deployed;

e. Examine distribution grid codes and recommend revisions to support net metering in Southeast Europe DSOs;

f. Identify solutions to other technical, legal and regulatory impediments.

Responsible Parties: USEA, Energy Institute Hrvoje Požar (EIHP) Milestones:

Action Date Adopt Terms of Reference February 2015 Develop questionnaire and distribute to DSOs March 2015 Collect responses, analyze data and prepare draft report March - May 2015 Draft report presented at working group May 2015 Final Report July 2015

QUARTERLY UPDATE During this quarter, USEA developed a terms of reference for this study. The terms of reference will be presented and is expected to be adopted at the next meeting of the DSO Working Group to be conducted in Sarajevo in February 2015.

ATTACHMENT NINE: Draft Terms of Reference for Distributed Generation Study

3. Lessons Learned Report from 2014 Flooding and Ice Storm Disasters in Southeast Europe Croatia experienced significant icing in February 2014 and Bosnia, Croatia and Serbia experiences severe flooding in spring 2014. Both of these disasters resulted in substantial electric system outages and extensive equipment damage. Preliminary estimates are that reconstruction costs could reach more that $100 million. The value of lost electricity sales resulting from the inability to deliver electricity to customers could be substantially higher.

ETAG Quarterly Report October – December 2014 Page 25

This report will survey how the affected DSOs responded to these extreme situations and provide a lessons learned of what worked and recommendations on what could have been done better. The goal is to provide guidelines on how to better respond to these types of emergencies in the future.

The report will cover the following: . extensive flooding in Serbia, Bosnia and Herzegovina and Croatia . ice storm in Croatia . emergency procedures in all regional DSOs . Observations/Recommendations . Drawbacks observed . Short description of special technical solutions used . Recommendations derived from the experience gained (lessons learned) . Plans for improving performance under emergency events

Responsible Parties: USEA, Energy Institute Hrvoje Požar (EIHP) Milestones:

Action Date Develop questionnaire and distribute to December 2014 DSOs Collect responses, analyze data January-February 2015 Meeting and interview with relevant DSOs March - May 2015 Draft Report presented at Working Group May 2015 meeting Final Report September 2015

QUARTERLY UPDATE During this quarter, EIHP developed a data questionnaire to be used to collect information on the response mechanisms employed by SEE DSOs during the ice storm of 2014. The questionnaire will be reviewed at the DSO Working Group meeting to be conducted in Sarajevo in February 2015, at which time the study will commence.

ATTACHMENT TEN: Data Questionnaire on Responses to Ice Storm Flooding

ETAG Quarterly Report October – December 2014 Page 26

4. Smart Grid Automation Pilot Project The application of smart grid automated distribution management systems (ADMS) is often prescribed as the solution to intermittency associated with distributed renewable energy generation resources. ADMS provides wide area awareness of the network through remote sensing capability and rapid, automated dispatch of the network. Conversion from “blind” operation of distribution networks in today’s operating environment to smart grid enabled networks will smooth and balance intermittent resources by more effectively directing electricity from surplus to deficit areas of the network.

USAID and USEA will partner with Schweitzer Engineering , a U.S. manufacturer of Automated Distribution Management Systems, for a pilot project in the Brcko Distribution utility in Bosnia & Herzegovina. The project will provide ADMS on a single feeder line in the selected distribution system operator’s network. In doing so, ETAG will:

a. Develop criteria to identify a distribution system operator service districts in which customers have identified a desire to deploy distributed generation and which suffer from frequent network outages of significant duration; b. Collect baseline data on unplanned system outages; c. Build capacity of distribution system operator counterparts in designing, deploying and operating an ADMS; d. Deploy ADMS in tandem with existing System Control and Data Acquisition systems (SCADA); e. Measure improvements in power quality, reduction in the frequency and duration of outages and increase the amount of distributed generation resources connected to the pilot network; f. Disseminate a case study to Southeast Europe policy and regulatory authorities and stakeholders, of best practices and lessons learned to replicate and scale up throughout the SOS Working Group.

Responsible Parties: USEA, Schweitzer Engineering Milestones: Action Date Identify appropriate feeder to install ADMS equipment October - December 2014 Collect baseline data prior to installation of equipment October – December 2014 Install equipment January- February 2015 Collect periodic data from ADMS and measure February - August 2015 performance against baseline data Prepare final report and present at next working group September 2015 meeting

QUARTERLY UPDATE

Schweitzer Engineering (SEL) initiated talks with the Brcko DSO in Bosnia and Herzegovina and both organizations agreed to move forward with the pilot project. Brcko performed a detailed analysis to determine the most appropriate feeder to install the Schweitzer ADMS equipment and is now in the process of procuring the re-closer equipment from the Serbian company “Saturn Electric”. The expected delivery date for the equipment is early January 2015. Once the re-closers are installed, SEL will install their equipment which is expected to take approximately 4-6 weeks.

ETAG Quarterly Report October – December 2014 Page 27

ATTACHMENT ELEVEN: Brcko DSO Analysis of Potential Feeder locations for Schweitzer Equipment

ETAG Quarterly Report October – December 2014 Page 28

Kosovo Objective 2: Develop technical rules, guidelines, and network infrastructure assessments to accelerate integration of clean and innovative energy technologies Korporata Energjetike e Kosovës (KEK), the generation utility in Kosovo, recently experienced a series of explosions due to a failure in a nearby electrolytic facility producing hydrogen for cooling for the Kosovo A power plant. Kosovo A is one of two large lignite power plants in Kosovo consisting of five units (three operable – units 3-5) and supplying 449 MW or approximately 30% of the electricity consumption of the country. The explosion completely destroyed the electrolytic facility and the resulting shockwave caused significant structural damage to Units A4 and A5.

Black & Veatch performed a damage assessment in August 2014 and provided a detailed report on the repairs needed to get the units back online. KEK has contracted with TurboCare to make the repairs outlined in the report. The contract with TurboCare calls for the repairs to be completed and the units brought back online by December 19, 2014. If the repairs are not completed in time, Kosovo will be forced to import power from the region at significantly high prices.

1. Project Management Support to KEK to Repair Damage to Kosovo A Black & Veatch performed will follow-up to its earlier damage assessment by providing assistance to KEK in managing the repair work to bring the Kosovo A units back online as scheduled. Mr. Carl Schaeffer, Project Manager, Black & Veatch, will travel to Pristina, Kosovo two times for a total of five weeks to assist KEK in managing the repair work being performed by TurboCare to the Kosovo A units. Mr. Schaeffer will maintain daily contact with USAID Kosovo, KEK management and TurboCare representatives while not in country through email, regularly scheduled Skype calls, and weekly progress reports.

Mr. Schaeffer will perform the following tasks: 1. Review critical documents pertaining to the return of Kosovo A units A4 and A5 into operation including the contract with TurboCare. 2. Provide initial assessment of work plan established by TurboCare to monitor their progress on the work. 3. Collaborate with TurboCare to establish a Baseline Schedule Plan to measure the progress during the monitoring stage in order to identify potential delays. 4. Monitor TurboCare's progress of the work against the Baseline Schedule Plan. 5. Identify issues which may delay return to operation, and collaborate with TurboCare to identify and implement mitigating actions and recovery plans that may be required to bring the units online by December 19, 2014. 6. Identify and facilitate resolution of issues that under KEK's contract with TurboCare to ensure project goals were achieved 7. Provide weekly progress reports.

This activity constitutes a change to the FY'15 Workplan adopted in cooperation with USAID.

Responsible Parties: USEA, Black & Veatch Milestones:

Action Date Initial Trip to Pristina, Kosovo for two weeks November 1 – 15, 2014

ETAG Quarterly Report October – December 2014 Page 29

Establish a Baseline Schedule Plan for TurboCare’s work to November 15, 2014 measure their progress in order to identify potential delays Maintain communication with USAID Kosovo, KEK and November 15-29, 2014 TurboCare to monitor the progress while not in country through email and regularly scheduled Skype calls. Travel to Pristina, Kosovo for three weeks November 29 – December 19, 2014 Weekly progress reports November 1 – December 19, 2014

QUARTERLY UPDATE Mr. Carl Schaeffer, Project Manager, Black & Veatch traveled to Pristina, Kosovo two times for a total of five weeks during the quarter. Mr. Schaefer provided assistance to KEK in the role of an owner’s engineer to provide daily oversight of the repair work being performed by TurboCare to bring Kosovo A TPP Units A4 and A5 back online.

While in Pristina, Mr. Schaefer conducted daily meetings with TurboCare and KEK management and noted several inadequacies impeding the repair work including.

1. TurboCare did not have internationally acceptable project management schedules in place and KEK was unable to accurately monitor their progress. 2. TurboCare did not have a senior person on site with approval authority. All approvals needed to be made from Poland which significantly slowed down their progress. 3. TurboCare was not focusing their attention on both units A4 & A5 to meet their contract commitments. Most of their focus was only on unit A4. 4. The contract between KEK and TurboCare did not follow internationally recognized NEC format and requirements which would have improved KEK’s position on receipt of deliverables 5. Most of the damaged equipment was sent to Poland for repairs. KEK has no representation in Poland to monitor the schedule and quality of the work.

Mr. Schaefer implemented the following actions while in country:

1. Conducted daily planning meetings with TurboCare, KEK management and USAID to review progress, highlight issues that would impede progress and develop recovery plans if the scheduled work was not accomplished. 2. Conducted several planning workshops with TurboCare, USAID and KEK management to improve their ability to develop accurate daily work plans. 3. Provided the following recommendations to the senior management of KEK: a. KEK should require TurboCare to provide a breakdown by cost element such as salary, materials, transportation, shipping, overhead, etc. b. KEK should send a team to Poland to meet with TurboCare senior management to confirm the delivery dates of all materials and equipment and explain why all site work is being focused on unit 4 c. KEK should require TurboCare to provide a work plan schedule for Kosovo A5 to determine if the completion of both units will meet the contracted date of December 19, 2014 d. KEK should request TurboCare to provide a senior manager onsite who can make decisions e. KEK and TurboCare should investigate repair shops closer to Kosovo than Poland who could assist in repairing the damaged equipment.

ETAG Quarterly Report October – December 2014 Page 30

i. A shop in Serbia was located and made a difference in receiving equipment for earlier installation. f. KEK DShould TurboCare should start to work double shifts. i. This was agreed to by both KEK and TurboCare. 4. TurboCare should provide a holiday Staffing Plan. Depending on the number of resources that remain in Kosovo will determine if the unit A4 December 19 return to service date would be met.

ATTACHMENT TWELEVE: Final Report and Weekly Status Reports of Carl Schaefer

2. Preparation of Power Supply Strategy for KEK for Winter 2014/2015 Moore Ventures, LLC will provide the services of Jonathan Moore to provide assistance to KEK to help them analyze the possible power supply scenarios for winter 2014/2015 and to prepare a power supply strategy in case Kosovo A is not repaired as scheduled.

Mr. Jonathan Moore will travel Pristina, Kosovo two times and spend a total of nine (9) days in-country and an additional fifteen (15) days in the U.S. to perform the following tasks:

1. Review key documents including the Black & Veatch Damage Assessment report; the TurboCare scope of work to repair the damage; current winter load forecasts; and Kosovo’s energy market rules. 2. Meet with the Kosovo energy market stakeholders to gain a clear understanding of the impact if the units were not brought back online as scheduled 3. Work closely with key KEK staff to develop and refine economic models to analyze the possible power supply scenarios for winter 2014/2015 4. Assist KEK to utilize the economic models and to interpret the results 5. Provide daily progress reports while in country 6. Conduct up to three (3) Skype calls per week with KEK and USAID Kosovo to review progress while in the U.S. 7. Provide the final economic models and final analysis report

This activity constitutes a change to the FY'15 Workplan adopted in cooperation with USAID.

Responsible Parties: USEA, Moore Ventures Milestones

Action Date Travel to Pristina, Kosovo for 4 full business days in country to November 2 – 7, 2014 meet with USAID Kosovo, KEK, TurboCare, KEDS to assess the situation and begin to prepare economic model for analysis Prepare daily progress reports while in country November 3-6, 2014 Complete trip report for first trip November 14, 2014 Travel to Pristina, Kosovo for one week (5 full business days) to November 29 – December 6, complete the economic model and assist KEK to perform the 2014 economic analysis and interpret the results Prepare daily progress reports while in country November 29 – December 6, 2014

ETAG Quarterly Report October – December 2014 Page 31

Complete economic model and provide to KEK for future use February 2015 Complete Final Analysis Report and present results via Power February 2015 Point Presentation at Close-out briefing with USAID

QUARTERLY UPDATE Jonathan Moore traveled to Pristina, Kosovo two times for a total of nine days during the quarter to work with KEK, KEDs and KOSTT to develop an economic model for KEK to provide them with a tool to analyze the economic impact of having the damaged Kosovo A units A4 and A5 offline during winter 2014/2015.

Mr. Moore spent his time in country reviewing KEK’s load forecasts, collecting data from KEDS and KOSTT, and monitoring the projected repair status of Units A4 and A5. This information was used to develop a detailed economic model for KEK which was then utilized to analyze the possible power supply scenarios for Winter 2014/2015 given the uncertainty of the availability of the Kosovo A units. The updated model and analysis was then presented to USAID and the U.S. Embassy.

The major finding is that the economic impact to KEK of having the Kosovo Units A4 and A5 out of service will be minimal based upon the quality of the forecasts KEK provides to KEDS.

It is suggested that training be provided to key energy stakeholders on how to utilize the model and to effectively interpret the results.

ATTACHMENT THIRTEEN: Power Supply Strategy Report for Winter 2014-15 ATTACHMENT FOURTEEN: Power Supply Economic Model

ETAG Quarterly Report October – December 2014 Page 32

5. Ukraine

Objective 2: Develop technical rules, guidelines, and network infrastructure assessments to accelerate integration of clean and innovative energy technologies

1. Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Analysis

The Ukraine Power System Support Project will assesses the high voltage transmission network’s stability in response to curtailed gas and coal fueled electric power generation and expected increased demand for electricity resulting from consumers switching to electric heat. The project grows out of the Black Sea Regional Transmission Planning Project (BSTP) and supports USAID goals of strengthening the interconnections of Ukraine power system to enhance energy security and optimize the generation fleet.

In coordination with representatives of Ukrainian transmission system operator (Ukrenergo), the Consultant (EKC) will develop a set of indicative scenarios taking into account the possible regional support (Romania, Poland, etc.) as well as critical production and consumption levels of the transmission network. The current BSTP planning model will be revised to reflect the current network topology. Assumptions regarding the availability of natural gas and coal for fuels for power generation will be developed in consultation with Ukrenergo. Likewise, assumptions regarding electricity demand resulting from a curtailement of municipally supplied heat and hot water will be developed and incorporated into the mode.

Network analysis will be conducted with the goal of providing recommendations on remedial actions necessary to preserve the stability of the high voltage transmission network during the upcoming winter season.

USEA will continue to provide technical support for model updates and contingency analysis throughout the winter of 2014/2015.

Responsible Parties: USEA; EKC; Allah Brekht; Aleksei Nekrasov

Action Party Date Develop and Submit Model Data EKC September 26 Questionnaire Develop Coal Assumptions Nekrasov October 15 Revise Model for 2014/2015 Brekht October 15 Develop Demand Scenarios Brekht October 22 Interim Report EKC October 29 Draft Final Report EKC November 28 Final Report EKC December 22

Potential follow-up actions include:

1) With selected local distribution companies, develop an optimized load shedding hierarchy prioritizing disconnection of loads with the greatest potential to restore system balance while preserving public services and sparing the disconnection of as many residential consumers as possible

ETAG Quarterly Report October – December 2014 Page 33

2) With Ukrenergo, analyze the impact of disconnecting Ukraine’s network with Russia and provide recommendations for balancing the Ukrainian system in its absence 3) Conduct a transient stability analysis (dynamic analysis) to determine the impact of network disturbances on the operation of nuclear power units and other large generators and develop remedial action plans in response to potential contingencies 4) Provide training and software support to the Ukrenergo headquarters dispatch department and regional offices to enable them to use PSS/E for real time modeling and system dispatch

QUARTERLY UPDATE In December 2014 USEA and EKC completed an analysis of the Ukrainian high voltage network’s capacity to remain stable and secure in light of rising electricity demand, curtailments in Russian gas deliveries and curtailed domestic coal supply. To perform the required load flow analysis, USEA reduced the 2015 Black Sea Regional Transmission Planning Project (BSTP) load flow model developed by Ukrenergo in the PSS/E planning software environment so as to create an operational model reflecting the network topology in autumn 2014. The model was loaded with assumptions from the peak demand day of December 2013 (the most recent peak load day) and tested to determine its security under various scenarios of generation capacity availability, network topology variations for connection to Crimea and Donbas and varying levels of consumption corresponding to increased electricity demand owing to a reduction in municipal heat supply. The resulting analysis identified conditions when the network would become unstable and provided a hierarchy of remedial actions to be taken by Ukrenergo to maintain system security through load shedding as few residential consumers as possible.

The load flow analysis found that the dynamic nature of the network topology, load swings and production capacities require a more in-depth analysis of the network security to be performed though a transient stability study.

ATTACHMENT FIFTEEN: Ukraine Power System Support Project Phase One Report

ETAG Quarterly Report October – December 2014 Page 34

6. ARMENIA

Objective 2: Develop technical rules, guidelines, and network infrastructure assessments to accelerate integration of clean and innovative energy technologies

1. Develop A Draft Transmission Network Technical Code (Grid Code) Based On ENTSO-E Requirements And Adapted To The Unique Network Topology And Market Model Of Armenia

In FY 2014, USEA produced a second draft Grid Code in coordination with the Stakeholder Working Group established by the Ministry of Energy. The Grid code provides a draft set of rules, procedures and standards consistent with the approved requirements of the ENTSO-E network codes.

At the conclusion of FY14 USEA submitted the draft Grid Code to the Ministry of Energy together with an explanatory note of remaining outstanding issues to be addressed by the Stakeholder Working Group and USEA’s consultant, Mr. Doug Bowman. To date, USEA has not received comment from the Ministry on the draft and explanatory note.

Recognizing the need for further revision to the draft Grid code to bring it into compliance with current Armenian energy law and regulation, USEA has proposed a hybrid approach to its completion. USEA will continue to employ the resources of Mr. Bowman as the subject matter expert on ENTSO-E grid code requirements. USEA will also continue to employ the services of the Scientific Research Institute for Energy (SRIE) of Armenia as the subject matter expert for Armenian technical standards, planning procedures and market operations. And, USEA will engage a lawyer with energy legal/regulatory expertise to: 1) ensure the draft grid code complies with current Armenian legislation and regulation; and 2) bring the drafted language into compliance with the format, structure and syntax of Armenian legal documents.

USEA will work through an iterative process of revising the draft Grid Code together with the consultants and the Stakeholder Working Group to arrive at a final draft that complies with current Armenian law and is consistent with the ENTSO-E Grid Code requirements. Toward this end, USEA will conduct two to three meetings of the Stakeholder Working Group to finalize the draft Grid Code. Between meetings, the local consultants will advance the draft such that it can be reviewed by Mr. Bowman and discussed and revised at subsequent Working Group meetings.

Responsible Parties: USEA; Scientific Research Institute for Energy; Doug Bowman; Araksya Isakhanyan

Action Party Date Submit Consulting Agreements for OAA Approval USEA December 22, 2014 Conduct Legal Review of Chapter One Grid Code Isakhanyan January 15, 2015 Stakeholder Working Group Meeting USEA March 2015 Stakeholder Working Group Meeting USEA May 2015 Final Draft Grid Code SRIE; Bowman June 2015 Legal/Regulatory Compliance Review Isakhanyan June 2015 Presentation to Ministry & Stakeholders USEA July 2015 Presentation to Stakeholder Ministry & Stakeholder USEA September 2015 Working Group

ETAG Quarterly Report October – December 2014 Page 35

QUARTERLY UPDATE Since submitting the draft Grid Code, USEA has not received comment from the Ministry of Energy. It should be noted that the point of contact within the Ministry passed away in December 2014, leaving a void as the Chair of the Expert Stakeholder Working Group. USEA plans to conduct a scoping mission to Yerevan during the first quarter of calendar year 2015 to confer with the Mission, Ministry and key stakeholders to determine the next steps toward finalizing the draft Grid Code.

7. GEORGIA (Co-funded by Black Sea Regional Transmission System Planning Project)

Objective 2: Develop technical rules, guidelines, and network infrastructure assessments to accelerate integration of clean and innovative energy technologies

1. Purchase Electricity Market Complex Adaptive System (EMCAS) software and provide technical training on its use and application to the Georgian State Electrosystem

In coordination with USAID’s support for the Georgian Electricity Market Model (GEMM), USEA will arrange for the GSE to execute a license for the ownership of the EMCAS software and contract with Argonne National Laboratory to provide technical training on its application for developing forecasts of the day ahead electricity markets in accord with GEMM.

EMCAS probes the possible operational and economic impacts of various external events on the electricity sector. The analysis is completed on an hourly basis over a user-specified period of time. Market participants are represented as “agents” with their own set of objectives, decision-making rules, and behavioral patterns. Agents are modelled as independent entities that make decisions and take actions using limited and/or uncertain information available to them, similar to how organizations and individuals operate in the real world. EMCAS includes all the entities participating in power markets, including consumers, generation companies (GenCos), Transmission Companies (TransCos), Distribution Companies (DisCos), Demand Companies (DemCos), Independent System Operators (ISO) or Regional Transmission Organizations (RTO), and regulators.

In coordination with USEA provided training, GSE will develop a model of the Georgian electricity market to be used to simulate day ahead electricity market transactions.

Responsible Parties: USEA, Argonne National Laboratory Milestones:

Action Date

Install software and Conduct One Week Training April 2015 Submit Trip Report with Recommendations and Agenda for May 2015 Second Training Week Review Initial Draft of Georgian EMCAS Market Model and July 2015 Conduct Second Week Training Submit Trip Report with Review of Draft EMCAS Model, July 2015 Recommendations for Revisions and Draft Agenda for Third Week Training Review Final Draft of Georgian EMCAS Model and Provide September 2015 Third Week of Training

ETAG Quarterly Report October – December 2014 Page 36

Submit Final Report Reviewing Georgian EMCAS Model with September 2015 Recommendations for Follow-up, as Necessary

QUARTERLY UPDATE No actions were taken on this workplan element pending USAID/Tbilisi buy-in to the ETAG Cooperative Agreement.

2. Renewable Energy Integration Study for Azerbaijan and Georgia

Under the Azerbaijan-Georgia-Turkey Working Group, USEA will assist GSE and Azerenerji to conduct a study to determine the maximum intermittent renewable energy capacity that may be integrated in the synchronous interconnection between Azerbaijan and Georgia. This study will enable the transmission system operators to accurately forecast the optimal locations and maximum amounts of clean energy capacity that can be safely and securely added to their interconnected networks and exported to Turkey through the Akhaltske (GE) – Borcka (TR) interconnection.

The study will consist of the following two components:

1. A contingency based Renewable Energy Source (RES) capacity allocation by substation in Azerbaijan and Georgia for wind and solar power generation 2. Verification of the capacity allocation through a study to determine compliance with N-1 security and reliability standards and planning criteria.

The Working Group will allocate RES capacity by individual substation based on existing wind and solar maps of each country. After prioritizing and allocating RES capacity by substations, members of the Working Group will evaluate the maximum permissible levels RES capacity that may be integrated based on the planning criteria of each national power system. To do so, the Working Group will conduct a load flow study employing N-1 contingency criteria to determine the maximum RES integration for each TSO. After the defining the permissible RES integration capacity based on the N-1 contingency analysis, the Working Group will conduct a transient stability study to verify the permissible RES integration capacity. The transient stability analysis will be based on the use of a commonly agreed-to grid code. Recognizing that grid code studies are currently in progress in Azerbaijan and Georgia and that TEIAS developed and has utilized a wind power grid code for five years, the Working Group will employ the Turkish power grid code as guide for conducting the transient stability analysis. Responsible Party: EPRA Milestones:

Action Date

Allocation of Wind and Solar Capacity to Substations February 2015 N-1 Contingency Analysis June 2015 Commence Transient Stability Analysis September 2015 Review Initial Transient Stability Analysis Results December 2015 Final Report January 2016

ETAG Quarterly Report October – December 2014 Page 37

QUARTERLY UPDATE No actions were taken on this workplan element pending USAID/Tbilisi buy-in to the ETAG Cooperative Agreement.

Objective 3: Support utility commercialization, privatization and market transformation to improve overall network efficiency and support clean energy market development

1. Project Management Support for the Georgian State Electrosystem Under an existing utility partnership between Bonneville Power Administration and the Georgia State Electrosystem, USEA will conduct two executive exchange programs to improve the capacity of GSE to manage large infrastructure construction projects. The programs will focus on:

• Project management human resource applications – job descriptions, division of responsibilities and assignments; • Developing and tracking project budgets; • Developing and tracking project timelines; • Utility Procurement best practices; • Contactor and vendor relations; • Software Applications; and • Project Close-0ut

One exchange program will be conducted in Portland, Oregon for 4-5 senior GSE managers to introduce them to the fundamentals of project management. A second exchange visit conducted in Tbilisi, where a more detailed treatment of these subjects for a larger number of GSE project management specialists.

Responsible Parties: USEA, Bonneville Power Administration Milestones:

Action Date

Exchange Visit to BPA for 4-5 Senior GSE Project Managers May, 2015 Workshop Conducted in Tbilisi for GSE Projects Management August, 2015 Specialists

QUARTERLY UPDATE No actions were taken on this workplan element pending USAID/Tbilisi buy-in to the ETAG Cooperative Agreement.

ETAG Quarterly Report October – December 2014 Page 38

8. MONITORING AND EVALUATION PLAN

The United States Energy Association will monitor the following indicators through quarterly, annual, and final reports. Meetings and trainings will also be evaluated based on surveys.

Program Objective Program Area Program Element Indicator FY 2015 Targets Economic Program Design and Growth Infrastructure Learning Element Number of Special Studies 13 Economic Program Design and Number of Information Gathering or Growth Infrastructure Learning Element Research Activities 26 Number of energy agencies, regulatory bodies, utilities and civil society organizations Economic EG 4.1 Modern Energy undertaking capacity strengthening as a result of Growth Infrastructure Services USG assistance 23 Economic EG 4.1 Modern Energy Number of energy enterprises with improved Growth Infrastructure Services business operations as a result of USG assistance 18 Number of people receiving USG supported Economic EG 4.1 Modern Energy training in energy related policy and regulatory Growth Infrastructure Services practices 50 Economic EG 4.1 Modern Energy Number of people receiving USG supported Growth Infrastructure Services training in technical energy fields 57 Number of utilities with increased adaptive capacity to cope with impacts of climate Economic EG 8.2 Clean Productive variability and change as a result of USG Growth Environment Environment assistance 17

ETAG Quarterly Report October – December 2014 Page 39

Energy Technology and Governance Program

SECI TRANSMISSION SYSTEM PLANNING MEETING:

AGENDA

November 3, 2014 Skopje, Macedonia

Monday, November 3, 2014

9:00 Opening and Welcoming Remarks Sinisha Spasov, MEPSO General Director Jamshid Heidarian, United States Agency for International Development Albert Doub, United States Energy Association Kliment Naumoski, MEPSO, SECI Technical Coordinator • Introductions • Approval of the meeting agenda

09:30 Updating the Regional Transmission System Models, RTSM Djordje Dobrijevic, EKC • Overview of RTSM status: 2020/2025/2030 • Preparation of snapshot for January & July 2014 • Model updates • RTSM compatibility issues • Schedule of tasks Elena Ackoska / Kliment Naumoski, MEPSO • MK models update: old forecast 2020 VS new forecast 2025/2030

10:15 Regional Dynamic System Model, RDSM Djordje Dobrijevic & Nebojsa Jovic, EKC • Status of RDSM

10:30 MORNING BREAK

11:00 Possibility of merging SECI and BSTP transmission planning models Djordje Dobrijevic & Nebojsa Jovic, EKC All • Database structure, compatibility issues, approach, benefits

This program is made possible by the support of the American people through the United States Agency for 1 International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

11:30 Study on SEE Electricity Market Perspectives until 2030 Goran Majstrovic & Davor Bajs, EIHP Djordje Dobrijevic & Nebojsa Jovic, EKC • Presentation of ToR for the Study • Elaboration of scope of work, main tasks and schedules

12:00 LUNCH BREAK

13:30 Study on SEE Electricity Market Perspectives until 2030 (continued) Djordje Dobrijevic, EKC Goran Majstrovic, EIHP • Collection of input data • Presentation of market and grid simulation tools and concept

14:30 Sustainability of SECI TSP Project Albert Doub, United States Energy Association Kliment Naumoski, SECI Technical Coordinator • Report from SECI Sustainability Executive Committee • Presentation of drafted Business Plan

15:00 AFTERNOON BREAK

15:30 Establishment of CAO for SEE Vojislav Pantic, NOSBiH • Info on project development

15:45 Flooding Consequences on Electricity Sector in SEE Goran Majstrovic, EIHP

16:00 Feasibility Study on Synchronous Interconnection of Ukrainian and Moldovan Power Systems to ENTSO-E Continental European Power System Nenad Sijakovic, EMS, WG1 Leader

16:15 Discussion of Transmission System Updates and Issues in TSOs All

16:45 Any Open Issues

17:00 End of the Meeting

This program is made possible by the support of the American people through the United States Agency for 2 International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

SECI TSP Project Transmission System Planning Project Meeting 3rd November, 2014, Skopje, Macedonia

Meeting Report

Meeting of the Southeast Europe Cooperation Initiative (SECI) Transmission System Planning Project (TSP) was conducted in Skopje, 3rd November 2014. The meeting was chaired by K.Naumoski, the Project Technical Coordinator.

3rd November 2014 (WG meeting) Opening and Welcoming Remarks Mr. Spasov, MEPSO General Director, welcomed participants. He acknowledged good results and excellent study reports of SECI TSP Project. He expressed thanks to support of United State Agency for International Development, and to efforts and commitment of all SECI TSP members. Mr. Spasov emphasized that SECI Project has been proven as a valuable tool for planning the grid – it provides efficient platform for network and market analyses. He sincerely expressed MEPSO position to support the transition of the Project to a kind of regional planning institution. Mr. Heidarian, USAID, appreciated work of TSOs so far, especially support provided by EKC and EIHP. He emphasized two main goals of SECI TSP project that are: preparation/promotion of regional transmission plans and developing of harmonized methodology for planning. Mr Heidarian showed gratitude to MEPSO willingness to support the transition of SECI TSP project and for hosting the future planning institution. Mr. Doub, USEA Program Coordinator, welcomed participants and excused Mr. Polen, USEA Senior Director, who cannot been present at the meeting because of urgent obligations. Mr. Naumoski, MEPSO, welcomed participants, introduced agenda and gave overview of the main topics for discussion on the meeting.

Updating the Regional Transmission System Models, RTSM Mr. Dobrijevic, EKC, reported on the current status and next steps for future update of Regional Transmission System Model (RTSM). Current planning horizons that are: - 2020 (mid-term planning horizon), update . Winter Peak, Summer Peak, Summer Off-Peak and Absolute MIN - 2025 (long-term planning horizon), under construction

1 . Winter Peak and Summer Peak - 2030 (extended long-term planning horizon), under construction . Winter Peak - Snapshots (the most recent) – continuously developing . Winter Peak and Summer Peak. The RTSM is updated twice yearly. National modeling experts send their updates to Model Integrator (EKC) by the end of April and October. Accordingly, the new release of the RTSM should be done by the end of May and November. Updates must include load flow model, sequence data and dynamic data as well as list of planned/realized projects. In the next period, focus will be put on completion of 2025 and 2030 winter peak models, due to necessity of them for preparation of the Study on SEE Electricity Market Perspectives until 2030. Preparation of snapshots for winter and summer peak 2014 will have second priority. RTSM 2014 snapshot should be done by downgrading the RTSM 2020 winter peak in order to keep models compatibility. RTSM 2025 and 2030 should be done by upgrading the RTSM 2020 winter peak in order to keep models compatibility. Next steps: - National models for 2025 and 2030 winter peak, should be collected till 30th November. Models from GR, TR and SI are still missing. - EKC will compile the RTSM 2025 and 2030 for winter peak afterwards. - EKC will issue e-mail with instructions for preparation of snapshots for winter and summer peak 2014. Regional Dynamic Simulation Model (RDSM) is developed in parallel with RTSM and full compatibility should be preserved. Full official release of RDSM & RTSM for 2015 and 2020 is available since January 2014. Mr. Rafajlovski, FEIT – Skopje, raised the question on generic values of Xsource when such data for new power plants are not known in advanced. Mrs. Achkoska, MEPSO, presented considerations on MK models update: old forecast 2020 VS new forecast 2025/2030. Presentation was followed with extensive discussion of other participants who have faced similar problems with planning uncertainties. Mr. Majstrovic, EIHP, emphasized the idea for combined planning of electricity and gas sector as challenge for transmission system planners. It could be one of the tasks that SECI TSP should deal with in the future.

Possibility of Merging SECI and BSTP Transmission Planning Models Mr. Dobrijevic, EKC, presented possibilities of merging SECI and BSTP transmission system planning models. Models have same level and quality of modeling, as well as similar modeling principles. So, prerequisites for merging the models are generally fulfilled. Concerning current planning horizons and data in both SECI and BSTP projects, the target model for pilot merging could be load flow model for winter peak 2020. Mr. Heidarian, USAID, supported the idea for merging the models in direction to investigate possibilities for electricity trade between both regions and beyond the rest of

2 interconnected system. International financing institutions (such as World Bank) has shown interest for this kind of analyses. Next steps: - Idea and concept should be presented on next regular meeting of SECI TSP and BSTP projects (February 2015). - Joint meeting between SECI TSP and BSTP projects will be organized next (June 2015).

Study on SEE Electricity Market Perspectives until 2030 Mr. Majstrovic, EIHP and Mr. DobrijevicVlaisavljevic, Mr. Jovic, EKC presented terms of reference for the study. They gave overview of study objectives, issues that should be analyzed, organization of work in phases and tasks, expected results, definition of input data, description PLEXOS software and timeline of tasks. Two basic concepts for execution of market simulation are on disposal: - either to run simulation for all 8760 hours during the reference year, or - to simulate 4 typical weeks that represent each season. Selection of the concept for market simulation will be determined by availability of dataset (weakly, yearly) for: - hourly consumption curves - hourly hydrology changes - maintenance period for TPPs - wind production hourly profile Decision will be made after collection and review of input data. Next steps: - Final ToR for the Study added with division of tasks between EKC and EIHP, together with timeline for their execution will be distributed to participants after the meeting. - Excel tables for collection of input data will be distributed till 17th November 2014. - EKC and EIHP to define average hydrology year form the past period that will be reference for investigations. - Phase 1: input data collection and verification, common market model creation, will be executed in the period December 2014 – June 2015. - Phase 2: market and network analyses, draft study report, will be executed in the period June 2015 – December 2015.

Sustainability of SECI TSP Project Mr. Doub, USEA Program Coordinator, reported on the evolution of the work of Sustainability Committee with task to prepare Sustainability Business Plan. Over a two- year transition period, USAID and USEA plan to gradually reduce financial support to SECI TSP Project while preparing the playground for transition the project into self- sustainable institution. The Committee meets regularly on Skype based on a pre-approved agenda.

3 SECI Working Group members are invited to join the Sustainability Committee. Till now, few items are already drafted: - A value proposition & mission statement - Two-year workplan of studies and capacity building consistent with the mission statement - Two year budget establishing member contributions In the next period, the Committee will proceed on drafting of: - Governance plan - Staffing Plan - MOU to be signed by each TSO at the conclusion of transition period - Legal & taxation analyses and recommendations MEPSO has tentatively agreed to serve as organizational host. USAID and USEA are considering hiring a professional during transition period to eventually serve as SECI Secretariat. SECI Secretariat will serve the following responsibilities: - Primary Point of contact with SECI members - Coordination of Working Group meetings - Coordination of Training Workshops - Coordination with Consultants USAID and USEA will conduct a regional tour to all TSOs management when Sustainability Business Plan is finalized (year 2016). Goal is to have MOU signed by each TSO at the conclusion of transition period.

Establishment of CAO for SEE Vojislav Pantic, NOSBiH, informed on development of the project for establishment of Coordination Auction Office for SEE.

Flooding Consequences on Electricity Sector in SEE Goran Majstrovic, EIHP, presented catastrophic consequences on electricity sector of the flood during the spring this year.

Feasibility Study on Synchronous Interconnection of Ukrainian and Moldovan Power Systems to ENTSO-E Continental European Power System Nenad Sijakovic, EMS, WG1 Leader, presented the Feasibility Study on Synchronous Interconnection of Ukrainian and Moldovan Power Systems to ENTSO-E Continental European Power System. This Study is funded/conducted directly by the European Commission. He put request for use of SECI RTSM 2020. SECI TSP Project is honored to provide the requested models and continue fruitful cooperation with European Commission, ENTSO-E and Energy Community on developing transmission projects.

4 Discussion of Transmission System Updates and Issues in TSOs Participants shared news and updates in national electricity sector during period between two consecutive meetings.

Remark All presentations are available in the DropBox’s “SECI Working Group Shared Folder”.

November, 2014 | report prepared by: K. Naumoski

5 Planning for SECI Sustainability

Albert Doub Acting Deputy Director United States Energy Association

November 3, 2014 Current Status of SECI Support

• SECI is a component of the USAID/USEA Energy Technology and Governance (ETAG) Program

• The ETAG Cooperative Agreement between USAID and USEA has been extended for two more years through September 2016

2 Plans for Continued Support and Transition to Sustainability • USAID and USEA will continue to provide support for the SECI Working Group through September 2016

• Over a two-year transition period, USAID and USEA will gradually reduce financial support to SECI

• It is envisioned SECI will be financially sustainable through membership contributions by September 2016

3 Getting to Sustainability

• USEA convened a SECI Sustainability Committee to brainstorm the path to sustainability in April 2014

• The objective of the Committee is to develop a SECI Sustainability Business Plan

• The Committee meets regularly on Skype based on a pre-approved agenda

• SECI Working Group members are invited to join the Sustainability Committee 4 How Do We Get to Sustainability? • Some questions the Committee is asking: • What is the value proposition SECI provides the TSOs? • Will SECI members make contributions to ensure its sustainability? If so, at what level of funding? • How should SECI be organized following phase-out of USAID support? • What tasks must be completed during the transition to ensure sustainability? • How can we secure the support of the TSO senior management for the SECI Sustainability Business Plan?

5 SECI Sustainability Business Plan • Develop a consensus based business plan containing: • A value proposition & mission statement - Drafted • Two-year Workplan of studies and capacity building consistent with the mission statement – Drafted • Two year budget establishing member contributions – Drafted • Governance plan • Staffing Plan • Recommendation for organizational host – MEPSO has tentatively agreed to serve as organizational host • MOU to be signed by each TSO at the conclusion of transition period • Legal & taxation analyses and recommendations • Plan vetted at SECI Working Group meetings as it is being developed • Secure support of TSO Senior Management 6 • USAID and USEA regional tour when Sustainability Plan is Finalized SECI Value Proposition

“The SECI TSP provides a cost effective and efficient platform for strengthening our capacity to peform network and market based analyses of the high voltage transmission system in Southeast Europe. The capacity building provided by the SECI TSP is demand driven, nimble, and unique in its ability to meet the specific training requirements of the TSOs in Southeast Europe.”

“Using the knowledge provided by the capacity building programs and through its cooperative data sharing arrangements, the SECI TSP has developed the most detailed transmision planning models in Europe at significantly less cost than developing them on a commercial basis. Our TSOs employ the SECI TSP models on a daily basis for national and regional planning studies. Use of the models has acelerated nearly €1 billion of investment that has been or is currently being added to the Southeast Europe transmission network.” 7 SECI Value Proposition (continued)

“We find that the SECI TSP project structure, which employs a regional model integrator to harmonize our national models and ensure fidelity to the regional network, enables us to significantly reduce the labor requirements for fulfilling our European Network of Transmission System Operators for Electricity (ENTSO-E) modeling requirements. We take special pride in the fact that ENTSO-E has adopted our models as the de-facto network model for Southeast Europe.”

8 SECI Mission Statement “THE SECI TSP supports regional cooperation in transmission planning in Southeast Europe to identify priority investment within national networks and on the interconnections between neighboring systems that improve the security and reliability and enhance market based trade and exchange of electricity.”

“To support this goal, the SECI TSP will:

• Develop and update common regional models for transmission system planning and analysis among the TSOs in Southeast Europe; • Provide ongoing training in the use and application of transmission planning software; • Identify potential transmission investment projects to expand electric power trade, while maintaining the security and reliability of the regional network; and • Promote the results of the SECI TSP analyses to a wide audience of senior TSO, policy and regulatory authorities”

9 SECI Budget Considerations

• USAID Fiscal Year (FY) is October 1 – September 30

• USAID and USEA will continue to provide full organizational support and funding for FY 2015

• USAID will continue to provide funding for consultants for FY 2015 and FY 2016

• USAID will gradually reduce funding for SECI Working Group meetings and training workshops during FY 2016

• SECI to be fully self-sustainable beginning in October 2017

10 FY 2016 Budget USAID and USEA will gradually reduce funding during FY 2016 for Working Group Meetings and Workshops

FY 2015 USAID FundingSECI ParticipantsFY 2016 USAID FundingSECI Participants

Consultant Studies Faculty Tuition for Training Workshops Meeting Costs (Room Rental, Coffee Breaks, Audio-Visual)

Lodging

Meals and Incidental Expenses

11 Next Steps

• Continue to Develop SECI Sustainability Business Plan

• MEPSO has tentatively agreed to serve as SECI Organizational Host

• USAID and USEA are considering hiring a professional during transition period to eventually serve as SECI Secretariat.

• SECI Secretariat will serve the following responsibilities: • Primary Point of contact with SECI members • Coordination of Working Group meetings • Coordination of Training Workshops • Coordination with Consultants

12 Next Steps

• USAID and USEA regional tour during FY 2016 to secure support of TSO Senior Management

• Goal is to have MOU signed by each TSO at the conclusion of transition period

13 Terms of Reference

SEE Electricity Market Perspectives until 2030

Background The ultimate goal in today electricity business in Europe is market integration on pan-European level that will introduce transparency and competition between market players, incentives to clean energy development, as well as high quality of supply to the end customers. Transmission system planers are devoted on reaching these objectives. All planning efforts are focused on development such environment for smooth transition and coupling of national markets while securing reliable operation of transmission network. The main objective of transmission system planning is to ensure the development of an adequate transmission system which contributes to:

- Security of supply (Transmission grid ensures safe system operation and provides a high level of security of supply) - Sustainability (Transmission grid allows for the integration of renewable energy sources RES) - Competitiveness (Transmission grid facilitates grid access to all market participants and contributes to social welfare through internal market integration and harmonization)

Figure 1. Structure of six ENTSO-E planning regions Recent and on-going investigations on European level apply regional approach. For example, ENTSO-E planning process identify 6 regions (Figure 1) and runs in parallel several market studies at regional levels, in order to better adapt to specifics of every region on the one hand, and mutually challenge the models to derive more robust results. The variety of outcomes of market studies are presented in Regional Investment Plans. The simulations are derived from a single database (Pan European Market Modelling Database - PEMMDB) depicting the scenarios to ensure consistency between all six European regions.

Simplified pan-European simulation is firstly done, in order to provide input for boundary conditions of every region. Every regional group undertake more detailed regional market and network studies in order to explore every vision and perform the CBA assessment of the projects.

In South-East Europe (SEE) 1there are uncertainties for the East-West and North-South transmission adequacy linked with the possible new undersea HVDC connections between SEE and Italy, the connection of Ukraine to the rest of the Europe and a huge potential of RES in the overall region that could, with new transits from Ukraine, Turkey, Romania and Bulgaria, make congestions on the above mentioned directions.

Investigation in this Study should go one step further in market analyses by applying wider outlook of the market integration. Challenges in the market evolution process that deserves further detailed analyzes are:

• Mutual influence of SEE and Italian electricity markets with focus on new HVDC connections between SEE and Italy

1 SEE region in the scope of present project considers: HR, BA, RS, ME, RO, BG, AL, GR, TR, HU, SI

• Influence of Continental Central East region of Europe to the SEE electricity market • Integration of renewable energy sources in SEE • Perspective transmission corridors to support the electricity trading patterns across SEE

Objectives

This project is divided in two phases:

1) preparation of common market model and relevant network model for 2025/2030, 2) SEE market perspectives study.

The first phase consists of:

1) definition of relevant input data needed for the market analyses on the regional level, as well as to be detailed enough for internal TSO analyses, 2) collection of existing input data from existing PSS/E models, TSOs and PEMDB , 3) clarification of missing input data, 4) verification of common market model and 5) decision on the market study methodology, future versions and format of common market models, as well as eventual common market software platform.

The second phase is to assess perspective electricity market behavior in SEE region considering:

1) influence of generation development involving RES, 2) markets integration and 3) the subsequent needs for transmission investments.

Market and network calculation in the second project phase should be applied iteratively. Regional market studies provide perspective generation and load patterns and consequential exchange patterns. The most critical patterns such as highest utilization of HVDC cables towards Italy, highest consumption or highest RES penetration should be further analyzed as selected cases for network studies. Regional network studies should analyze the capability of SEE transmission grid to handle these various cases of generation dispatch identified in the market study, recognize possible network congestions and suggest corresponding infrastructure strengthening.

Scenarios

Initial (“loose”) cross-border constraints

As an input for the market modelling, the cross-border constraints (NTC values) will be assessed among the SEE countries, in a way to roughly limit the extensive cross-border exchanges resulting from market analyses outcomes, but still to leave space for determination of weak transmission corridors.

Market analyses

• Target year for the analyses is 2025/2030, depending on the available input data horizon • Market modelling should involve at least 4 typical weeks in a target year, representatives of four seasons; average hydrology • Generation scenario is with high RES penetration • Consumption scenario is with realistic consumption forecast • Transmission scenarios: o Base case scenario: with planned HVDC ME-IT o Alternative scenario: with planned HVDC ME-IT, and HVDC HR-IT, and HVDC AL-IT Final network analyses

• Among the observed market cases (typical 4 weeks), the selected cases (hours) will be further investigated through the network analyses, such as: o highest consumption o highest RES penetration o highest cross-border exchanges resulting from market modelling

Scope of work

As given above, due to the complexity of the study objectives, the whole project will be divided in two phases:

• Phase 1 – Creation of market database and network models • Phase 2 – SEE electricity market perspectives study

PHASE 1 – CREATION OF MARKET DATABASE AND NETWORK MODELS

TASK ONE – CREATION OF DATABASE FOR MARKET AND NETWORK ANALYSES

• definition of relevant input data needed for the market analyses on the regional level, as well as to be detailed enough for internal TSO analyses • collection of existing input data from existing PSS/E models, TSOs and PEMDB and other available sources • clarification of missing input data and suggestions for solution (typical data etc.) • verification of common regional market database by checking of compatibility with regional network model • upgrade of existing PSS/E network model for 2025/2030

Starting point will be Pan-European Market Modelling Database (PEMMDB) constructed by TSOs for the scope of ENTSO-E studies. PEMMDB should be reviewed in detail by TSOs and upgraded where find appropriate.

The following approach will be considered in modelling of generation cost:

- Turkey and Italy will be modelled as spot market (market price insensitive to fluctuations of prices in SEE; constrained with transmission capacity) - Greece, Hungary and Slovenia will be modelled per technology clusters (hydro by type, thermal by fuel type, nuclear, RES) - Albania, BIH, Bulgaria, Croatia, Kosovo, Macedonia, Montenegro, Romania and Serbia will be modelled on plant-by-plant level of details

EIHP should be responsible for necessary data and network and market models for the following countries:

• Italy, modelled as spot market • Hungary and Slovenia, modelled per technology clusters • Croatia, Bosnia – Herzegovina and Romania modelled on plant-by-plant level of details

The rest of the region will be modelled by EKC (Turkey, Greece, Albania, Bulgaria, Kosovo, Serbia, Macedonia and Montenegro). EIHP and EKC will merge these two models and prepare common market model for SEE countries and distribute it to all SECI WG participants.

Action Date Task Type Phase1 – Task 1: Creation of database for market March 01, 2014 Deliverable analyses for Italy (spot market), Hungary and

Slovenia (per technology) and Croatia, Bosnia – Herzegovina and Romania (plant by plant)

TASK TWO – METHODOLOGY FOR MARKET STUDIES

• decision on the market study methodology, future versions and format of common market models, as well as eventual common market software platform

Action Date Task Type Phase1 – Task 2: Methodology for market studies June 01, 2015 Milestone

TASK THREE – DEVELOPMENT OF NETWORK MODELS FOR TARGET YEARS (2025/2030)

• collection of national/TSO network models for 2025 and 2030 • checking adequacy of national models • creation of bordering TSO models as well as equivalence of the rest of ENTSO-E • creation of regional SECI model by merging of national/TSO models • checking adequacy of SECI model

Action Date Task Type Phase1 – Task 3: Development of network models June 01, 2015 Deliverable for target years (2025/2030)

PHASE 2 – SEE ELECTRICITY MARKET PERSPECTIVES STUDY

TASK ONE - MARKET STUDIES

Market studies should investigate perspective generation pattern and power exchanges in SEE region that are expected, taking into account inter-regional SEE electricity market synergies and the integration with Italian market, as well as high level of RES integration in SEE region. Existing main power trade corridors in the SEE region that is North-South and East-West are expected to be highly congested in the future, becoming even more so with market integration.

• Considerable power exchanges in East-West direction are related to the fact that Bulgaria and Romania are the main exporters in SEE • Significant power exchanges in the North-South/Southeast direction are related to the fact that the GR, MK, ME, HR and AL are mainly importing, plus the influence of Italy importing over HVDC cable(s)

In order to perform a market study, the demand must be modeled in GWh through the whole year on hourly basis. At the same time, the generation cost function must be modeled, together with constraints of generation dispatch (must-run units, weather conditions, etc.). Market and grid model should maintain compatibility to run iteratively.

Results of market simulation with assumed “loose” network constraints will comprise:

- Overview of countries electricity balance in SEE region (production, consumption and exchanges) - Electricity prices for each country after applying such “loose” network constraints - Cross-border power exchanges (MWh/h) for each border in the region on hourly basis - HVDC link loadings (MWh/h) for each HVDC submarine cable on hourly basis - Location and frequency of market congestions in SEE region (NTCs full between areas with price difference)

Calculation will be done using software for electricity market simulation - Plexos.

Market study comprises the following tasks:

• creation of simulation model in software for electricity market simulation based on regional market database created in the phase 1 • electricity market simulation for target year on “base case scenario” with one planned HVDC cable to Italy, namely HVDC Montenegro-Italy, • analyses of the simulation results • creation of the report

Market simulation should give the following results for analyzed “base case scenario”:

• Overview of countries electricity balance in SEE region (production, consumption and exchanges) • Electricity prices for each country after applying such “loose” network constraints • Cross-border power exchanges (MWh/h) for each border in the region on hourly basis • HVDC link loadings (MWh/h) for each HVDC submarine cable on hourly basis • Location and frequency of market congestions in SEE region (NTCs full between areas with price difference)

Alternative scenario with three HVDC cables (Montenegro-Italy, Croatia-Italy and Albania-Italy) will be analyzed by EKC. EIHP and EKC will merge these two scenarios and prepare common market study for SEE countries and distribute it to all SECI WG participants.

Action Date Task Type Phase2 – Task 1: Development of market model June 30, 2015 Deliverable Phase2 – Task 2: Market simulation September 01, Milestone • Overview of countries electricity balance 2015 in SEE region (production, consumption and exchanges) • Electricity prices for each country after applying such “loose” network constraints • Cross-border power exchanges (MWh/h) for each border in the region on hourly basis • HVDC link loadings (MWh/h) for each HVDC submarine cable on hourly basis Location and frequency of market congestions in SEE region (NTCs full between areas with price difference) Phase2 – Task 3: Analyses of simulation results October 01, 2015 Milestone Phase2 – Task 4: Draft report (market analyses) October 31, 2015 Deliverable

TASK TWO - NETWORK STUDIES

In the assessment of this Study, network calculations are coupled with market calculation scenarios. Assessment of network-related indicators should be performed using selected snapshots from market analysis. Specific generation and load dispatch pattern in selected snapshots from the market studies are mapped in regional network models.

The following network calculations will be performed:

- Load flow, voltage profile and losses variation - Security analyses (N-1) - NTC (re)-assessment on highly loaded transmission corridors

As an outcome of network studies, perspective congested transmission corridors should be recognized and corresponding strengthening of network infrastructure should be identified in order to support higher market benefits.

Network bottlenecks should be clearly identified and efficient solutions should be addressed.

Network calculations will be performed on most recent SECI Regional Transmission Simulation Models for winter and summer maximum year 2025/2030, updated with generation profile resulting from market analysis.

Network study comprises the following tasks:

• network simulations for target year on “base case scenario” with one planned HVDC cable towards Italy, namely HVDC Montenegro-Italy • Analyses of network related indicators using selected snapshots with specific generation and load dispatch obtained from the market studies • Identification of possible network bottlenecks and suggestions for efficient solutions for network strengthening • creation of the report

Alternative scenario with three HVDC cables (Montenegro-Italy, Croatia-Italy and Albania-Italy) will be analyzed by EKC. EIHP and EKC will merge these two scenarios and prepare common network study for SEE countries and distribute it to all SECI WG participants.

Action Date Task Type Phase2 – Task 5: Network simulations September 01, 2015 Milestone Phase2 – Task 6: Analyses of network simulation October 01, 2015 Milestone results Phase2 – Task 7: Identification of possible October 01, 2015 Milestone network congestions Phase2 – Task 8: Final draft report December 31, 2015 Deliverable

Project schedule

The following is a schedule of project milestones and deliverables:

Action Date Task Type PHASE 1 Phase 1 - Creation of database for market analyses March 01, 2015 Deliverable Phase 1 - Methodology for market studies June 01, 2015 Milestone Phase 1 - Development of network models for June 01, 2015 Deliverable target years (2025/2030)

PHASE 2 Phase 2 – Task 1: Creation of market model June 30, 2015 Milestone Phase 2 – Task 2: Market simulation September 01, 2015 Milestone Phase 2 – Task 3: Analyses of market simulation October 01, 2015 Milestone results Phase 2 – Task 4: Draft report (market analyses) October 31, 2015 Deliverable Phase 2 – Task 5: Network simulations September 01, 2015 Milestone Phase 2 – Task 6: Analyses of network simulation October 01, 2015 Milestone results Phase 2 – Task 7: Identification of possible network October 01, 2015 Milestone congestions Phase 2 – Task 8: Final draft report (market and December 31, 2015 Deliverables network analyses)

Schedule of deliverables

Action Date Task Type PHASE 1 Creation of database for market analyses March 01, 2015 Deliverable Development of network models for target years June 01, 2015 Deliverable (2025/2030) PHASE 2 Development of market model June 30, 2015 Deliverable Draft report (market analyses) October 31, 2015 Deliverable Final draft report (market and network analyses) December 31, 2015 Deliverable

Schedule of payments

Action Payment Date Payment percentage PHASE 1 Creation of database for market analyses March 31, 2015 50% Development of network models for target years June 30, 2015 50% (2025/2030)

PHASE 2 Development of market model July 31, 2015 30% Draft report (market analyses) October 31, 2015 30% Final draft report (market and network analyses) January 15, 2016 40%

Energy Technology and Governance Program AZERBAIJAN-GEORGIA-TURKEY (AGT) POWER BRIDGE PROJECT WORKING GROUP MEETING

October 27, 2014 Baku, Azerbaijan

JW Marriott Hotel Absheron Baku 674 Azadlig Square, Baku, AZ-1010, Azerbaijan

AGENDA

The objectives of the Working Group Meeting are to: • Review the results of the September and October 2014 NTC calculations performed on the basis of the procedures prescribed in its AGT Power Bridge Business Process Manual; • Review and approve the final non-technical report for stakeholders describing the cause of congestion in Northeast Turkey and plans to alleviate it; • Review wind and solar data sorce provided by Azerbaijan, Georgia and Turkey for the proposed study on the potential to integrate renuable energy in eash country.

Monday, October 27 9:00 Welcome and Overview of Agenda  Hagen Maroney, Acting Deputy Chief of Mission, U.S. Embassy, Baku, Azerbaijan  Vugar Shahmuradov, Deputy Chief Engineer, Azerenergy  Jamshid Heidarian, Senior Energy Advisor, Energy and Infrastructure Bureau of Europe and Eurasia, USAID, Washington  William Polen, Senior Director, United States Energy Association

9:30 Narrative Assessment of the September/October/November 2014 NTC results (GE=>TR) TSO’s Presentation and Discussion of September/October/November 2014 NTC Calculation Results  Mahmut Erkut Cebeci, EPRA  Necip Fazil Bakir, Engineer, Research and Planning Department, TEIAS  Georgi Vakhtangadze, Engineer, System Stability and Development Department, Georgian State Electrosytem (GSE)  Aynura Mamedova, Engineer, Central Dispatch Office, Central Dispatching Service, Azerenergy

This program is made possible by the support of the American people through the United States Agency for International 1 Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

10:30 Morning Break

11:00 Alleviating Congestion in Northeast Turkey to Support Clean Energy Exports from the Caucaus. Review and Approve the Final Report for Stakeholders  Facilitator: Osman Bulent Tor, Partner, EPRA

11:30 Review TOR for Renewable Energy Integration Study and Update. Inventory of Renewable Energy Data Sorces  Facilitator: Osman Bulent Tor, EPRA

12:30 Lunch Break

TSO Updates Brief Updates on Transmission System Developments in Each AGT Country

13:30 Azerbaijan  Rauf Akhmedov, Head of Central Dispatching Service, Azerenergy 13:45 Georgia  Archil Kokhtachvili, Georgian State Electrosystem 14:00 Turkey  Necip Fazıl Bakir, TEIAS

14:15 Retrospective of the AGT Power Bridge Project Results from 2009-2014  William Polen, United States Energy Association

14:45 Afernoon Break

15:15 Meeting Report & To-Do List  William Polen, United States Energy Association

15:30 Adjourn

This program is made possible by the support of the American people through the United States Agency for International 2 Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

Azerbaijan-Georgia-Turkey (AGT) Power Bridge Project Working Group Meeting

Oktober 27, 2014 Baku, Azerbaijan

PARTICIPANT LIST

Azerbaijan

Azerenergy

1. Vugar Shahmuradov, Deputy Chief Engineer 2. Arif Gashimov, Advisor to President 3. Ilkham Agasiev, Chief of Central Dispatching Department, 4. Hafiz Mehdiyev, Head of Regional Power Markets Analysis Division 5. Rauf Akhmedov, Head of Central Dispatching Service 6. Aynura Mamedova, Engineer, Central Dispatch Office, Central Dispatch Service 7. Chinar Kerimova, Engineer, Maintenance of SCADA System Service 8. Ulvi Shirinov, Analyst, Regional Power Markets Analysis Division 9. Ziba Aghayeva, Analyst, Regional Power Markets Analysis Division

State Agency for Alternative and Renewable Energy Sources

10. Rahim Abdullaev, Deputy Director, Department of Energy Efficiency and Technologies

Azerbaijan Energy S&R Institute

11. Aziza Odzhagverdova, Senior Engineer, Azerbaijan Energy S&R Institute

Georgia

12. Archil Kokhtashvili, Chief of Electrical Regimes and Development Department, Georgian State Electrosytem (GSE) 13. Giorgi Vakhtangadze, Engineer, System Stability and Development Department, Georgian State Electrosytem (GSE) 14. Giorgi Arziani, Engineer, System Stability and Development Department, Georgian State Electrosystem (GSE)

Turkey

15. Necip Fazil Bakir, Engineer, Research and Planning Department, TEIAS

16. Abdussamet Kandemir, Engineer, Research and Planning Department, TEIAS

EPRA

17. Osman Bülent TÖR, Partner, EPRA 18. Mahmut Erkut Cebeci, Partner, EPRA

U.S. Department of State

19. Robert Ichord, Deputy Assistant Secretary, Bureau of Energy Resources

USAID

20. Jamshid Heidarian, Senior Energy Advisor, Energy and Infrastructure Bureau of Europe and Eurasia, USAID, Washington 21. Hagen Maroney, Acting Deputy Chief of Mission, U.S. Embassy, Baku, Azerbajan 22. Cennifer Tikka, Director, Economic Growth Office

USEA

23. William Polen, Senior Director, United States Energy Association 24. Natalia Fominykh, Senior Program Coordinator, United States Energy Association

Interpreters

25. George Lashkhi, Independent Interpreter 26. Irakli Todria, Independent Interpreter

Energy Technology and Governance Program

AGT Project Narrative Assessment of the September/October/November 2014 NTC results

Dr. Osman Bülent Tör

Baku, Oct. 27, 2014

This presentation is made possible by the support of the American people through the United States Agency for International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government. Outline

• Narrative reports of NTC calculations results: – Sep. 2014 – Oct. 2014 – Nov. 2014 (NTC calculation is ongoing) • No results yet

2 September 2014

3 September 2014 • The following factors are among the important determinants of NTC calculations: – Regional consumption; – Hydroelectric Power Plant (HPP) generation levels; – Loading levels of the transmission corridors. • The following are new regional developments that directly affect the NTC results: – The production of the 400kV OMV NGCCPP - KAYABASI line is close to completion. Therefore, it is assumed to be in service at the time of the NTC calculations. – TEIAS has completed the installation of the Special Protection System (SPS). – This installation will either reduce generation in Northeast Turkey or reduce imports from Georgia or both in the case of the loss of a transmission line that connects the region to the main demand centers. – The amount and selection of trip depends on the amount and location of the

disturbance. 4 Electrical Map of the Northeast Turkey (January 2014)

5 Some figures

6 Some factors

• TEIAS is currently under an observation period to become a member of the European Network for Transmission System Operators for Electricity (ENTSO-E) and is obligated to plan and operate its network based on the ENTSO-E N-1 system security criteria.

• When determining the September 2014 NTC of Georgia-Turkey interconnections, minimum loading conditions of the system were considered.

• The electricity generation of the Northeast Turkish region increased during the minimum loading periods, resulting in an increase of load on the transmission lines leading to N-1 security violation concerns.

7 NTC Calculations and Results

8 SPS activation!

9 • AGT Power Bridge monthly calculations for April 2014 in comparison with the November 26 pre-defined NTC calcultions for 2014.

• The NTC calculated by the Working Group is generally consistent with the pre- defined NTC for September 2014. 10 Sep. 2014 Conclusions • The September 2014 NTC values are considerably high when compared to the previous NTC calculations as a result of the assumed 400kV OMV NGCCPP – KAYABASI line. • This line provides an alternative path for the large OMV NGCCPP plant connecting to BORCKA through the main demand centers on one of the two 400kV corridors. • The 400kV network does not satisfy N-1 contingency criteria. – In the case of a lost 400kV corridor connecting to BORCKA, the special protection system (SPS) activates in order to prevent regional black out on the Turkish border. – In such a case, the SPS trips power plant units located along the two corridors in Turkey and/or 400kV tie line between Turkey and Georgia. • The amount and selection of trip depends on the severity and location of the disturbance based on prioritization rules as defined by TEIAS.

11 October 2014

12 13 14 Oct. 2014 Conclusions • If compared to September 2014 NTC value (500MW), October 2014 NTC value of GE => TR is low (300MW). • Limiting factor is the overloading of 220 kV "KOLKHIDA-1" OHL in GE in case of opening 500kV IMERETI transmission line in GE (i.e., N-1 contingency).

15 • This overloading is observed by the TSOs of both GE and TR.

• In this regard, the NTC results of October 2014 are different than those of previous months in which limiting factor was in the Turkish grid.

• This study also proves the progress of TSOs in NTC calculation process – NTC calculations are according to the BPM – TSOs are more comply with timing rules defined in BPM

16 Thanks for the attention

[email protected]

17 Energy Technology and Governance Program

AGT Project

Alleviating Congestion in Northeast Turkey to Support Clean Energy Exports from the Caucaus (Sensitivities of investments in Turkey on NTC from GE=>TR)

FINAL RESULTS

Dr. Osman Bülent Tör

Oct. 27, 2014 Baku

19 20 • Scope of the Study:

– To develop an interpretation of the results of the technical study for a non- technical audience on TEIAS’s short and medium term investment plans to alleviate congestion in Northeast Turkey.

– The consultant will analyze the effects of transmission investments on NTC values under the support of USAID/USEA.

– TEIAS performed: • Investment scenarios • NTC calculations

– EPRA performed: • Methodology • Assessment of the results 21 • Presentation • Studies

– Development of the scenarios to be investigated in load flow and n-1 contingency analyses (transmission investments, demand forecast and generation forecast)

– Assessment of the sensitivities of the transmission investments on NTC values

22 Transmission investments Loading Scenario for NTC sensitivity analyses Investments 2015 Spring 2015 Winter 2016 Spring 2016 Winter 2017 Spring Min Max Min Max Min Special Protection System (SPS) + + + + + 400 kV transmission line investments 400kV OMV - Kayabasi OHL + + + + + 400 kV Agri - Van - Tatvan - Siirt - Batman OHL + + + + + 400kV Resadiye - Kayabasi OHL + + + + + 400kV Arkun - Ispir OHL + + + + + 400kV Bagistas - Keban OHL + + + 400 kV Kursunlu - Baglum - Sincan OHL + + 400kV İspir - Bagistas OHL + 400kV Ordu - Resadiye OHL + 400 kV transmission substation investments 400 kV Ordu SS + + + + + 400 kV Resadiye SS + + + + + 400 kV Ispir SS + + + + + 400 kV Tortum SS + + + + + 400 kV Bagistas SS + + + Important generator investments at the region Ayvalı HPP - 128 MW connected to 154kV + + + + + Kotanlı HPP - 130 MW connected to 154kV + + + + + Akıncı HPP - 78 MW connected to 154kV + + + + + Artvin HPP - 330 MW connected to 400 kV + + + Darıca 2 HPP - 75 MW connected to 154kV + + + 23 Kozbuku HPP - 66 MW connected to 154kV + + + Transmission investments Special Protection System (SPS)

• TEIAS has completed the installation of the Special Protection System (SPS) in 2014 Summer. • Manufacturer is GE. • SPS either reduces generation in Northeast Turkey or reduces imports from Georgia or both in the case of the loss of a transmission line that connects the region to the main demand centers. • The amount and selection of trip depends on the amount and location of the disturbance. • SPS actions initiated by the df/dt relay with threshold of +0.75 Hz/sec. – More technical details are given in the report

25 The Load Flow Results for 2015 Spring Minimum Loading Conditions There is no 400 kV outage for imported power from Georgia to Turkey at 700 MW. New investments are marked in green. The most significant N-1 contingency is marked in red.

26 Tortum-Erzurum 400 kV line Outage and Overloaded Regions. The power imports from Georgia to Turkey are at 350 MW. New investments are marked in green. The most significant N-1 contingency is marked in red. Overloads relieved by the activation of the SPS are marked with red circle

27 Load flow Results for 2015 Winter Maximum Loading Conditions. There is no 400 kV outage when power imports from Georgia to Turkey are at 700 MW. New investments are marked in green. The most significant N-1 contingency is marked in red

28 Load flow Results for 2016 Spring Minimum Loading Conditions. There is no 400 kV outage when power imports from Georgia to Turkey are at 700 MW. New investments are marked in green. The most significant N-1 contingency is marked in red

29 Significant N-1 Contingency SPS activation cannot relieve the overload when the power import from Georgia to Turkey is 700 MW.

30 Load flow Results for 2016 Winter Maximum Loading Conditions. There is no 400 kV outage when power imports from Georgia to Turkey are at 700 MW. New investments are marked in green. The most significant N-1 contingency is marked in red

31 Load flow Results for 2017 Spring Minimum Loading Conditions. There is no 400 kV outage when power imports from Georgia to Turkey are at 700 MW. New investments are marked in green. The most significant N-1 contingency is marked in red

32 Results

2015 Spring 2015 Winter 2016 Spring 2016 Winter 2017 Spring Min Max Min Max Min NTC 350 MW 700 MW 350 MW 700 MW 700 MW SPS Operation in case of N-1

NTC calculations would amount to less than those in the table unless SPS is activated by TEIAS.

33 Conclusions • The transmission investments, along with the activation of SPS, contribute to the NTC values from Georgia to Turkey. • Although the NTC is 350 MW at both 2015 and 2016 spring minimum loading conditions, it increases to 700 MW at 2017 spring minimum loading conditions. • This increase is the result of transmission investments in Turkey. • The regional generator investments reduce the positive effects of the transmission investments on the NTC values. • In the case of a significant N-1 contingency on the 400 kV transmission lines in Turkey, the SPS is shedding generation at the Turkish border, power import from Georgia, or both. • TEIAS intends to make additional investments after 2017. In particular, the 400 kV Borcka - Ispir - Erzurum OHL (see Figure 3.1) will have a positive effect on the NTC values 34 Thanks for the attention

[email protected]

35 TURKISH POWER SYSTEM OVERVIEW

TEIAS GENERAL MANAGEMENT OCTOBER,2014 TURKISH POWER SYSTEM

NUMBER OF SUBSTATIONS LENGTH OF TRANSMISSION LINES •400 kV: 92 •400 kV: 17.328 km •220 kV: 1 •154 kV: 34.741 km •154 kV: 566 •220 kV: 85 km •66 kV: 14 •66 kV: 509 km Total 673 Subs. with 124.888 MVA transformer •154 & 400 kV UndergroundCable: 296 km 37 installed capacity. • Total 52.960 km ENERGY CONSUMPTION

38 INSTALLED CAPACITY

6.326,2; 9,3% 3.380,2; 5% 21.172,5; 31% NATURAL GAS COAL IMPORTED COAL HYDRO WIND OTHER 23.322,6; 34,2% 8.571,7; 12,5% INSTALLED POWER 5.462,6; 8% FUEL TYPE (MW) NATURAL GAS 21.172,5 COAL 8.571,7 IMPORTED COAL 5.462,6 HYDRO 23.322,6 WIND 3.380,2 OTHER 6.326,2 TOTAL 68.230,9 • Installed capacity is 68.230 MW by 30 September 2014. 39 INSTALL CAPACITY &PEAK LOAD

2013 Installed Capacity: 64.044 MW Consumption: 245,48 TWh Peak Load: 38.274 MW

2014

Installed Capacity: 68.230 MW

Peak Load: 41.003 MW

40 DARDANEL SUBMARINE CABLE PROJECT

Dardanel Submarine Cable 400 kV 2x1600 mm2 4,5 km

41 IN OPERATION WPP’s and PLANNED WPPS

* Red: In Operation Blue: Planned TOTAL PLANNED + INSTALLED WPP: ~12.000 MW 42 SOLAR ENERGY POTENTIAL OF TURKEY

Solar Installed Capacity: 28 MW Installed Capacity for 2015: 1.5 GW 43 Thank You For Your Attention Energy Technology and Governance Program Azerbaijan-Georgia-Turkey (AGT) Power Bridge Project

AGT Working Group Meeting October 27, 2014 Baku, Azerbaijan 45 AGT Participants Include:

Azerenergy Georgian State Electrosystem Turkish Electricity Transmission Corporation (TEIAS) United States Agency for International Development United States Energy Association

46 Project Milestones DATE LOCATION MILESTONE

April 2009 Tbilisi MOU Singing Ceremony September 2009 Baku TEIAS/GSE Advisory Mission. Azerbaijan National Network Model Completed November 2009 Istanbul WG Meeting – 2015 Scenarios Adopted January 2010 Istanbul WG Meeting – Preliminary Load Flow Analysis Report, Presented by TEIAS April 2010 Baku GSE Advisory Mission. Azerbaijan National Network Dynamic Model Completed March 2011 Istanbul WG Meeting – 2013;2015;2017 Scenarios Adopted

47 Project Milestones DATE LOCATION MILESTONE

November 2011 Tbilisi WG Meeting Stability & Load Flow Analysis Completed February 2012 Istanbul SC Meeting- Results of First Phases June 2012 Sofia WG Meeting- Phase III TOR for NTC Study Adopted October 2012 Istanbul WG Meeting/NTC Workshop January 2013 Baku PSS/E Workshop for Azerenergy. Load Flow & Dynamic Modeling, NTC Calculation February 2013 Tbilisi WG Meeting/NTC Workshop and Trial Calculation

48 Project Milestones DATE LOCATION MILESTONE June 2013 Turkey WG Meeting Stability & Load Flow Analysis Completed December 2013 Tbilisi WG Meeting NTC Business Process Manual Completed March 2013 Chisinau WG Meeting – Results of January, 2014 NTC Calculations June 2014 Tbilisi WG Meeting – May & June 2014 NTC Calculations

49 AGT Project Trainings DATE LOCATION MILESTONE September 2009 Baku TEIAS/GSE Advisory Mission. Azerbaijan National Network Model Completed

Objective:  Provide to support to JSC Azerenergy to develop its national network model in the PSS/E Format Participants: 1. Ilham Aghasiyev, Chief, Dispatch Department, Azerenergy 2. Nurali Yusifbeyli, Director, R&D Power Engineering Institute 3. Asaf Huseynov, Deputy Director, R&D Power Engineering Institute 4. Aynura Alieva, Engineer, Dispatch Department, Azerenergy 5. Anar Gasymov, Engineer, R&D Power Engineering Institute

50 AGT Project Trainings DATE LOCATION MILESTONE April 2010 Baku GSE Advisory Mission. Azerbaijan National Network Dynamic Model Completed

Objective:  Provide support to JSC Azerenergy in developing a dynamic model in the PSS/E format Participants: 1. Ilham Aghasiyev, Chief, Dispatch Department, Azerenergy 2. Asaf Huseynov, Deputy Director, R&D Power Engineering Institute 3. Aynura Alieva, Engineer, Dispatch Department, Azerenergy 4. Anar Gasymov, Engineer, R&D Power Engineering Institute 5. Ayten Garatagi, Leading Engineer, R&D Power Engineering Institute 6. Elmira Alikperova, Leading Engineer, R&D Power Engineering Institute 51 AGT Project Trainings DATE LOCATION MILESTONE October 2012 Istanbul WG Meeting/NTC Workshop

Objective:  Introduce NTC/ATC Calculation Methodologies Participants: Azerenergy – 2 participants Georgian State Electrosystem – 2 participants TEIAS- 2 participants

52 AGT Project Trainings DATE LOCATION MILESTONE January 2013 Baku PSS/E Workshop for Azerenergy. Load Flow & Dynamic Modeling, NTC Calculation

Training Topics:  Overview of Net Transfer Capacity (NTC) Calculation Methodologies Experience of Turkish TSO after Interconnection with ENTSO/E  AGT Project Phase I&II Conclusive Remarks from both Stability Concerns and NTC Calculations points of view  Combination of the Interdependent Power Systems in Calculating NTC  AGT Project Phase III-Verifications of Dynamic Models and LF based NTC Calculations by Dynamic Analysis 53

Azerbaijan-Georgia-Turkey (AGT) Power Bridge Project: NARRATIVE RESULTS OF NTC CALCULATIONS NOVEMBER 2014

Energy Technology and Governance Program: Cooperative Agreement: AID-OAA-A-12-00036

Energy Technology and Governance Program

Azerbaijan-Georgia-Turkey (AGT) Power Bridge Project

NARRATIVE RESULTS OF NTC CALCULATIONS MARCH 2014

Prepared for:

November, 2014 This report made possible by the support of the American people through the United States Agency for InternationalUnited StatesDevelopment Agency (USAID). for International The contents are Development the responsibility of the United States Energy Association and and United do not necessarilyStates Energy reflect theAssociation views of USAID or the United States Government.

Cooperative Agreement: AID-OAA-A-12-00036

NOVEMBER 2014 Narrative Results of NTC Calculations

Energy Technology and Governance Program

Azerbaijan-Georgia-Turkey (AGT) Power Bridge Project

NARRATIVE RESULTS OF NTC CALCULATIONS NOVEMBER 2014

Prepared for:

United States Agency for International Development and United States Energy Association

Cooperative Agreement: AID-OAA-A-12-00036

Authors:

Osman Bülent Tör (EPRA) Mahmut Erkut Cebeci (EPRA)

United States Energy Association 1300 Pennsylvania Avenue, NW Suite 550, Mailbox 142 Washington, DC 20004 +1 202 312-1230 (USA)

This report is made possible by the support of the American people through the United States Agency for International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

NOVEMBER 2014 Narrative Results of NTC Calculations

Contents

1. Introduction ...... 4 2. NTC Calculations using the AGT Power Bridge NTC Business Process Manual ...... 5 3. Load Flow Calculation Results in Turkey ...... 7 4. Conclusions ...... 9

NOVEMBER 2014 Narrative Results of NTC Calculations

1. Introduction On April 8, 2009 representatives of Azerbaijan, Georgia and Turkey signed a memorandum of understanding creating a partnership to support the AGT Power Bridge Project. Under the terms of the MOU, electric power transmission planning specialists from each country study and analyze the regional high voltage electricity network to evaluate its capacity to support increased trade and exchange of electricity. The partnership’s analysis provides engineers and policy makers with a tool to optimize the security and reliability of the sub-regional electricity network and prioritize reinforcements within the network that are necessary to support increased trade, improve system reliability and enhance energy security.

The Working Group’s initial analysis supported the development of the 500/400 kV high voltage direct current (HVDC) back-to-back (B2B) substation connecting the Georgian and Turkish electricity networks and identified network congestion in Turkey as a limiting factor to clean energy export from the Caucasus to Turkey. Subsequently, the Working Group adapted the European methodology for calculating the monthly cross-border transmission capacity on the Georgia-Turkey interconnection. The three members of the Working Group have employed this methodology on a monthly basis to calculate the throughput capacity of this new line, providing transmission system operators, regulators, electricity traders and investors with important information on the network’s capacity to support electricity trade between the Caucasus and Turkey.

This paper is for the month of November 2014 in a series of monthly narratives reporting on the Net Transfer Capacity (NTC) of the HVDC B2B substation and transmission line connecting Akhaltsikhe (Georgia) to Borcka (Turkey).

The following factors are among the important determinants of NTC calculations:

• Regional consumption; • Hydroelectric Power Plant (HPP) generation levels; • Loading levels of the transmission corridors; • N-1 contigency security criteria.

The following are the new regional developments: • The production of the 400kV OMV NGCCPP - KAYABASI line is close to completion. Therefore, it is assumed to be in service at the time of the NTC calculations. • TEIAS has completed the installation of the Special Protection System (SPS). This installation will either reduce generation in Northeast Turkey, reduce imports from Georgia or both, in the case of the loss of a transmission line that connects the region to the main demand centers. The amount and selection of trip depends on the amount and location of the disturbance.

NOVEMBER 2014 Narrative Results of NTC Calculations

2. NTC Calculations using the AGT Power Bridge NTC Business Process Manual The AGT Power Bridge Business Process Manual (BPM) describes the procedures for exchanging data, producing the common grid models (CGM) and calculating Net Transfer Capacity (NTC) on a monthly basis among the TSOs from Azerbaijan, Georgia and Turkey.

Figure 1: AGT Interconnections

The BPM harmonizes the following procedures among the TSOs:

• Processes and timeframes for exchanging data and exchanging and merging the models required by each party to calculate and verify NTCs; • Technical assumptions to be adopted in load flow and dynamic models to be used in the calculation of the NTCs; • Time intervals upon which NTCs will be calculated; • Process by which NTCs are agreed to by each TSO and how NTCs are adopted when calculations of the TSOs differ.

The TSOs from Azerenerji, the Georgian State Electrosystem and the Turkish Electricity Transmission Corporation have adopted the BPM for performing NTC calculations on the border between Azerbaijan and Georgia and on the border between Georgia and Turkey.

On November 26th 2013, TEIAS and GSE signed a memorandum defining 12 monthly NTC values for 2014 a full year in advance. Recognizing that this is a departure from the BPM methodology, the Working Group elected to perform monthly NTC calculations using the month -2 (m-2) approach prescribed in the BPM. The Working Group is using these monthly NTC calculations to validate the predefined calculations of the November 26th memorandum.

The follow chart describes the AGT Power Bridge monthly calculations for November 2014 in comparison with the November 26 pre-defined NTC calcultions for 2014.

NOVEMBER 2014 Narrative Results of NTC Calculations

Period: AGT Power Bridge November 26 Memorandum November Monthly NTC Calculations Pre-defined NTC Calculations for 2014 November 2014 Azerbaijan Georgia Turkey AGT Minimum NTC Maximum NTC NTC NTC NTC NTC for FY 2014 for FY 2014 GE -> TR - 400 400 400 700 700 TR -> GE - 100 50 50 0 0 AZ -> GE - 50 - 50 0 0 GE -> AZ - 200 - 200 0 0

Figure 2: Pre-defined and Monthly NTC Calculations

The NTCs calculated by Georgia and Turkey are same (i.e., 400 MW). The NTC is 300 MW less than that of the pre-defined values of the November 26 memorandum, in which parties agreed to a minimum NTC of 700 MW. A summary of the NTC results of TEIAS and GSE are presented in the following tables.

As illustrated in the tables above, the limiting factor of the NTC from Georgia to Turkey is the N-1 contingency security constraint in the GSE network. These results show the importance of the monthly calculations of the NTC values based on the recent network data.

NTC calculation results of TEIAS:

NTC calculation results of GSE:

NOVEMBER 2014 Narrative Results of NTC Calculations

3. Load Flow Calculation Results in Turkey Figure 3 describes the load flow results when Georgia exports 400 MW to Turkey at a time when all lines in Turkey are in service. The Load flow results for the most significant N-1 contingency is presented in Figure 4. There is no overload line in the Turkish network at this N-1 contingency. The limiting factor of 400 MW NTC from Georgia to Turkey is the overloading of a 220 kV OHL in Georgia, in the case of opening the 500 kV Zestafoni - Enguri transmission line in Georgia (i.e., N-1 contingency).

LEGEND

Figure 3: November 2014 Load Flow Diagram (Georgia => Turkey: 400 MW (Base Case: No 400 kV Outage))

NOVEMBER 2014 Narrative Results of NTC Calculations

LEGEND

Figure 4: November 2014 Load Flow Diagram (the most significant N-1 contingency)

NOVEMBER 2014 Narrative Results of NTC Calculations

4. Conclusions The NTC calculations made by Georgia and Turkey are the same (i.e., 400 MW). The NTC is 300 MW less than that of the pre-defined values of the November 26 memorandum, in which parties agreed to a minimum NTC of 700 MW. This result shows the importance of monthly calculations of the NTC values based on recent network data. The limiting factor of the NTC from Georgia to Turkey is the N-1 contingency security constraint in the GSE network. This limitation is observed by the TSOs of both Georgia and Turkey. In this regard, similar to the pre-defined October 2014 NTC results, the October 2014 NTC results are different than those of previous months in which the limiting factor was in the Turkish grid.

Terms of Reference DISTRIBUTION SYSTEM OPERATORS SECURITY OF SUPPLY WORKING GROUP

Connection of Distributed Generation to Distribution Networks: Recommendations for Technical Requirements, Procedures and Agreements

Background

The demand for the connection of Distributed Energy Resources (DER or Distributed Generation (DG)), mainly renewables, at the Medium Voltage (MV) and Low Voltage (LV) distribution networks is constantly growing, due to the drive for increasing renewable energy penetration in the energy mix and the favorable support policies adopted in many parts of the world. In many countries, Distribution System Operators (DSOs) are overwhelmed by unprecedented amounts of DER connection applications, which need to be evaluated in a fast and reliable manner. To assist distribution system operators in Southeast Europe with emerging issues that DSOs may need to address in the future, such as modifying interconnection rules to better address high penetration of distributed generation and revising screening criteria for a proposed interconnection, USAID together with the United States Energy Association (USEA), has established a Southeast Europe Distribution System Operators Security of Supply Working Group (SEE DSO SoS WG).

Working Group members currently includes representatives from nine DSOs:

Albania (Operatori i Shpërndarjes së Energjisë Elektrike sh.a. - OSHEE) Bosnia and Herzegovina JP Komunalno Brcko – EDB JP Elektroprivreda BIH – EPBIH JP Elektroprivreda Hrvatske Zajednice Herceg-Bosne – EPHZHB JP Elektroprivreda Republike Srpske - ERS

Croatia (HEP – Operator distribucijskog sustava d.o.o. – HEP) Kosovo (Kosovo Electricity Distribution and Supply- KEDS)

Macedonia (EVN Macedonia - EVNM) Serbia (Elektroprivreda Srbije - EPS).

Representatives of the national regulatory agencies (NRAs) in these countries participate as observers to the Working Group.

The activities of the DSO Security of Supply Working Group are demand driven to respond to the needs of the distribution companies in the region. Changes in the institutional context (deregulation), progress in generation technologies, cost reduction in materials, economic incentives systems (special purchase tariffs, subsidies), the concerns on environmental issues (reduction of CO2 emissions, promotion of environmentally sustainable resources), priority of dispatching and European or national policies, raised the awareness at the DSOs in the region of the need for development of adequate rules, codes, requirements and operational practices that shall keep a safe operation of distribution systems without unnecessary restrictions on DER penetration.

With the advent of DG on distribution networks different issues are at stake. Depending on the country, these issues may be more or less important or may be dealt with a rather different ways since distribution networks and other factors that play an important role in this field, are quite different (e.g. political or socio-economic factors, market models, regulations, voltage levels, configuration and architecture, characteristics, operation practices, among others). Nevertheless, electricity networks are in the era of major transition from passive distribution networks with unidirectional electricity transportation to active distribution networks with DG and hence bidirectional electricity transportation. Active distribution networks need to incorporate flexible and intelligent control systems in order to harness clean energy from renewable DG. They should also employ future network technologies for integration of DG as smartgrid or microgrid networks. The present ‘fit-and-forget’ strategy of DER deployment must be changed in active network management for accommodating a high degree of DG penetration.

Objectives of the Study

The last two decades have seen an unprecedented development of distributed energy resources all over the world. Several countries have adopted a variety of support schemes (feed-in tariffs, green certificates, direct subsidies, tax exemptions etc.) so as to promote DG, especially those exploiting renewable energy sources (RES). Under these circumstances DSOs are experiencing a strong pressure to respond to an often excessive demand for access to the network, while at the same time ensuring that DG connection does not violate the technical standards of the networks.

Connecting to the grid system is a fundamental requirement in an electricity supply system, for customers (users of the grid) who want to feed in power (generators), take off power (consumers) or to transport power further (distributors). In a deregulated environment each entity will seek to optimize their own position and be hindered as little as possible by rules.

This study shall assist the SEE DSOs develop set of rules and requirements related to connection procedure and in this sense to help DSOs in preparing for increased integration of distributed generation.

Scope of work

The scope of the study is to:

• survey the main aspects in the framework governing new DG connection process of the countries taking part in the study, • survey the main aspects in the grid/distribution codes (and/or other “equivalent” documents) of the countries taking part in the study regarding generators, • review of the current connection criteria (i.e. plant and system standards) applied in 9 DSOs for DG:

o steady-state and short-circuit current constraints, o power quality, o voltage profile, reactive power and voltage control, o contribution to ancillary services, o protection aspects, o islanding and islanded operation, o system safety, • analyze the technical evaluation practices adopted by DSOs in the region (i.e. system studies done as part of new connection offer process by which capacity of the grid is assessed), • analyze the performance obligations of DG in the countries taking part in the study, • make a technical assessment and comparative analysis of the different approaches in the region, • overview of rules/requirements for DG in utility(ies) in Western Europe and/or North America, • review the opportunity for improvement and harmonization of connection rules in the region, • survey the position of DG in the market model of the countries taking part in the study (balancing responsibility, ancillary services provision, pricing policies,…),

DSOs will be required to respond to questionnaires developed by Consultants related to the:

• connection procedures for DG, • connection criteria/requirements for DG, • technical evaluation practices, • performance obligations for DG,

• current and envisaged position of DG in the market model.

Expected Study Results

This study shall provide the DSOs, regulators, donors, customers and other interested parties insight in current legal framework and power market designs in 6 countries (9 DSOs) for DG. It is expected that based on the results of the study the Consultant will assist the Working Group to improve regulations, procedures, criteria and standards dealing with connection offer process. Besides, the current position of DG in the region shall be reviewed and market models that support more DG connections shall be proposed. The study shall also serve DSOs and other interested parties to get familiar with future technologies for integration of DG and in this sense to support transition to active distribution network management for accommodating a high degree of DG penetration.

In preparing the study the Consultants will perform the following four tasks:

TASK 1: THE CONNECTION PROCEDURE REVIEW

o identify the main issues that should be considered with the advent of DG on distribution network,

o preparation, harmonization and distribution of the questionnaires covering all relevant issues on DG connection

o preparation of detailed information for each participating DSO related to DG connection procedure (e.g. formal way of issuing the connection application, obligations, time span, validity period of the connection , denial of connection, user constraints),

o preparation of detailed information for each participating DSO related to rules and codes (i.e. technical aspects),

o preparation of detailed information for each participating DSO related to connection tariffs and costs governing DG connection.

TASK 2: RECOGNITION OF INADEQUACIES IN THE CURRENT PROCEDURE AND RECOMMENDATIONS FOR IMPROVEMENTS

o summarize in a comparative manner current connection criteria applied in 9 DSOs for DG, o identification of inadequacies in current procedures and criteria, o survey of technical evaluation practices adopted by DSOs in the region (i.e. system studies done as part of new connection offer process by which capacity of the grid is assessed),

o provide recommendations for technical requirements, procedures offering new connection and agreements,

TASK 3: SELECTED EU AND/OR U.S. RULES/REQUIREMENTS AND NOVEL CONCEPTS TO SUPPORT THE INTEGRATION OF DG (MICROGRIDS, VIRTUAL POWER PLANTS, ACTIVE DISTRIBUTION NETWORKS)

o description of rules and for DG in selected EU and/or U.S. DSOs, o workshop/course to introduce counterpart DSOs to: . practices of operating distribution network with high degree of DG, . novel concepts to support the integration of DG (microgrids, virtual power plants, active distribution networks),

TASK 4: POSITION OF DG IN THE MARKET MODEL

o survey the position of DG in the market model of the countries taking part in the study (balancing responsibility, ancillary services provision, pricing policies,…),

o identification of inadequacies in current market models and future recommendations. o envisaged future policy changes and developments in their countries.

Schedule of project deliverables and payments

Action Date Percent Payment

Task 1: March 15, 2015 30% The questionnaires preparation , distribution, analysis and connection procedure review

Task 2: June 15, 2015 30% Recognition of inadequacies in the current procedure and recommendations for improvements

Task 3: September 1, 2015 20% Selected EU and/or U.S. rules/requirements and novel concepts to support the integration of DG (microgrids, virtual power plants, active distribution networks)

Task 4: September 31, 2015 20% Position of DG in the market model

Prepared by EIHP, October 15, 2014

SOUTHEAST EUROPE DISTRIBUTION SYSTEM OPERATOR SECURITY OF SUPPLY WORKING GROUP

Extensive Flooding and Ice Storm Consequences in SEE Power System in 2014 and Lessons Learned

. Report coverage: . extensive flooding in Serbia, Bosnia and Herzegovina and Croatia (May 2014) (6 DSOs) . ice storm in Croatia (February 2014) . emergency procedures in all regional DSOs

. Workplan

Activity Actor Date

Questionnaire preparation and EIHP mid October, 2014 distribution

Questionnaire clarification and DSOs mid November, 2014 responses

Meeting and interview with relevant USEA, DSOs November/December 2014 DSOs and EIHP

Work on draft report EIHP December 2014 - January 2015

Draft report review, fine tuning and EIHP and DSOs end of December, 2015 harmonization

Final report EIHP February 2015

Questionnaire

1. Scope and scale of the event: a. Dates (period): When did it happen, from the first problem in your power system till its normal operation and reconnection of all customers? ______

b. Total population affected: How many people / consumers were affected by this event in terms of power supply interruption or power quality reduction? ______

c. Total affected area (km2): What is the size of the area affected by this event? ______

2. Impact on critical infrastructure - distribution system in affected areas a. Damaged lines: What is the number and length of damaged lines or feeders (by voltage levels)? ______

b. Disconnected lines: What is the number and length of disconnected lines or feeders (by voltage levels)? ______

c. Damaged substations: What is the number and installed capacity of damaged substations (by voltage levels)? ______

d. Disconnected substations: What is the number and installed capacity of disconnected substations (by voltage levels)?

2 ______

e. Destroyed metering devices: What is the number of destroyed metering devices? ______

f. Damaged metering devices: What is the number of damaged and later repaired metering devices? ______

g. Any other data on damaged equipment (warehouses, primary, secondary equipment etc.): ______

h. Please give a short description of conditions in which catastrophic event occurred (disaster outlook, aggravating factors, precipitation, how many days of rain you had, mudslides, generating units outage etc.) ______

i. Did you have any other comparable event in your power system in the recent history? ______

j. How often in average such events (of similar or smaller scale) occur in your power system? ______

3. Emergency measures a. Legal framework for operation under emergency conditions (Emergency strategy): i. Yes (if “Yes”, please shortly describe) ______

3 ______ii. No b. Re-energizing areas – realized actions: What were the actions taken and timeframes needed to re-energize the system? ______c. Reconnecting key customers/public services: What was your operational plan and procedure for prioritization of reconnection of key customers/institutions/public services? ______d. Cooperation/Mutual assistance from other DSOs: Were there any mutual assistance and help among different DSOs in terms of equipment, staff exchange and/or coordination? ______e. Material/Equipment needed, Staff involved: How many staff and equipment/material was involved/spent in system recovery (in addition to regular DSO activities in normal operational conditions)? ______

4. Consequences (damage assessment) a. Duration of supply interruption: How many disconnected consumers (and estimated electricity non-delivered, if available) did you have in the following timeframes: 1 hour, 3 hours, 8 hours, 1 days, 3 days, 5 days, 7 days)? ______

b. What was total electricity non-delivered? ______

c. What is the total set of equipment replaced due to this event (not included in regular replacement/maintenance)? Lines:______Transformers:______Meters:______Switching devices:______Other:______

d. What is the estimated cost of: i. Equipment, Assets:______ii. Work:______iii. Other:______

e. What are the estimated losses for DSO: i. Increase in operational losses (during flood periods and in the coming months): ______ii. Loss in revenues:______

5 f. Do you plan/expect to request revision of the network tariffs by the regulator or you will cover these expenses from your own cashflow/loan only? ______

5. Observations/Lessons learned/Recommendations a. Drawbacks observed: ______

b. Short description of special technical solutions you eventually used: ______

c. Recommendations derived from the experience gained (lessons learned) ______

d. Plans for improving performance under emergency events: 6 ______

7 Overhead distribution_short analysis of locations - USEA

JP „Komunalno Brčko“ d.o.o

Overhead distribution – Short analysis of locations for the reclosers instalation Power distribution Technical Service; Pero Ožegović

2014

Overhead distribution_short analysis of locations - USEA

Content

1. Purpose and Objective ...... 2 2. Locations for installation ...... 2 3. Analysis of named locations for reclosers instalation ...... 4 3.1. Recloser Potočari 1 ...... 4 3.2. Recloser Zovik ...... 7 3.3. Recloser Donji Rahić ...... 10 3.4. Recloser Brka ...... 12 4. Conclusion ...... 14

Overhead distribution_short analysis of locations - USEA

1. Purpose and Objective

Objectiv of this short analysis is to recognise which locations in MV distribution network where it would be optimal to instal two reclosers with posibilty of remote monitoring and control. Within this document will be discussed only some of the priority sites of overhead MV lines. This priority is based of experience, and their importance in the MV network. For illustration, figure 1. shows one of the disconector locations mounted at Tuzla power distribution company.

Figure 1. Overhead line disconector, with FPI

2. Locations for installation

Below is a list of four potential locations for reclosers installation. On this locations currently are instaled manualy operated disconectors. Selection of location is done on the basis of their importance in the overhead power line network as well as the number of manipulations to be performed on them.

Overhead distribution_short analysis of locations - USEA

No. Name of location Name of power line Description

PL 10 kV Potočari 1. Recloser Potočari 1 10 kV Potočari branch to MV/LV substation Pukiš 2 PL 10 kV Zovik, 2. Recloser Zovik 10 kV Zovik the main power line 10 kV Brka 3. Recloser Brka 10 kV Brka connection to Palanka PL 10 kV Ulice 4. Recloser Donji Rahić 10 kV Ulice the main power line

Table 1. List of locations for reclosers instalation

Figure 2. shows GIS view of power lines from table 1.

Figure 2. GIS view of Power lines from table 1.

Overhead distribution_short analysis of locations - USEA

3. Analysis of named locations for reclosers instalation

Below will be made analysis of locations from table 1. on the basis of known parameters, set of energy and existing radio communication crtieria as well as indicators of continuity of supply, i.e. number of failures of individual power lines.

3.1. Recloser Potočari 1

Location for recloser named Potočari 1, is show on the figure 3. Location belongs to 10 kV power line named Potočari. On the location is mounted concrete pillar, type 12/1600. For the evaluation of this location see table 2.

Recloser Potočari 1 0 1 2 (10 kV PL Potočari) The total length of the l < 7,5 km 7,5 km < l < 15 km l > 15 km power line (35,03 km) Number of MV/LV Nsub < 15 15 ≤ Nsub < 25 Nsub ≥ 25 substations (Nsub = 34) Number of end Nk < 1000 1000 < Nk < 2000 Nk ≥ 2000 customers (Nk =1688) Number of end customers on 10 kV 0 1 2 (Nk_10 kV = 0) Number of end customers for I tariff 0 ≤ NkI < 4 4 ≤ NkI < 8 8 ≥ group (NkI = 1) Average active power for power line from Pav < 0,6 MW 0,6 ≤ Pav < 1 Pav ≥ 1 29.10.13. (Pav = 0,70 MW) Total of energy 6 parameters No of failures Nf < 8 8 < Nf < 12 Nf ≥ 12 (Nf = 23) Total of indicators of 2 continuity of supply Availability of existing YES digital radio (YES/NO) RSSI (Satell network) - 79 < - 65 ≤ dBm < - 79 - 65 ≥ (-65 dBm) Reliability of radio link < 99,9 % ≥ 99,9 % (%) - ??? Total of existing radio 4 communication: TOTAL OF ALL: 12

Table 2. Recloser Potočari 1

In additon, as you can see, table 3. show SAIDI/SAIFI parametars for 10 kV PL Potočari, for period of last nine monts.

Overhead distribution_short analysis of locations - USEA

Planned Unplanned Planned Unplanned Month SAIDI SAIDI SAIFI SAIFI January 1,85 0,25 0,04 0,04 February 3,18 0,12 0,06 0,01 March 12,93 0,8 0,18 0,00 April 0,06 0,00 0,00 0,00 May 4,11 14,91 0,04 0,34 June 4,28 8,89 0,04 0,14 July 7,46 29,58 0,20 0,20 August 3,33 18,23 0,08 0,33 September 3,8 7,82 0,01 0,21 Sum 41 80,6 0,65 1,27

Table 3. SAIDI/SAIFI parametars for 10 kV PL Potočari

Overhead distribution_short analysis of locations - USEA

Figure 3. Location for recloser Potočari 1

Overhead distribution_short analysis of locations - USEA

3.2. Recloser Zovik

Location for recloser named Zovik, is show on the figure 4. Location belongs to same named 10 kV power line Zovik. Site is located next to an local asphalt road and nearby residential houses. On the location is mounted concrete pillar, type 12/1600. For the evaluation of this location see table 4.

Recloser Zovik 0 1 2 (10 kV PL Zovik) The total length of the l < 7,5 km 7,5 km < l < 15 km l > 15 km power line (28,89 km) Number of MV/LV Nsub < 15 15 ≤ Nsub < 25 Nsub ≥ 25 substations (Nsub = 19) Number of end Nk < 1000 1000 < Nk < 2000 Nk ≥ 2000 customers (Nk =1358) Number of end customers on 10 kV 0 1 2 (Nk_10 kV = 0) Number of end customers for I tariff 0 ≤ Nk < 4 4 ≤ Nk < 8 Nk ≥ 8 group (NkI = 1) Average active power for power line from Pav < 0,6 MW 0,6 ≤ Pav < 1 Pav ≥ 1 29.10.13. (Pav = 0,61 MW) Total of energy 5 parameters No of failures Nf < 4 4 < Nf < 8 Nf ≥ 8 (Nf =21) Total of indicators of 2 continuity of supply Availability of existing YES digital radio (YES/NO) RSSI (Satell network) - 79 < - 65 ≤ dBm < - 79 - 65 ≥ (-72 dBm) Reliability of radio link < 99,9 % ≥ 99,9 % (%) - ??? Total of existing radio 3 communication: TOTAL OF ALL: 10

Table 4. Recloser Zovik

In additon, as you can see, table 5. show SAIDI/SAIFI parametars for 10 kV PL Zovik, for period of last nine monts.

Overhead distribution_short analysis of locations - USEA

Planned Unplanned Planned Unplanned Mjesec SAIDI SAIDI SAIFI SAIFI January 0,00 0,00 0,00 0,00 February 0,00 0,00 0,00 0,00 March 0,00 0,00 0,00 0,00 April 0,00 10,99 0,00 0,12 May 0,00 60,96 0,00 0,36 Junei 0,00 2,13 0,00 0,08 July 0,28 0,00 0,08 0,00 August 4,34 10,62 0,04 0,08 September 16,52 0,00 0,08 0,00 Sum 21,14 84,70 0,20 0,64

Table 5. SAIDI/SAIFI parametars for 10 kV PL Zovik

Overhead distribution_short analysis of locations - USEA

Figure 4. Location for recloser Zovik

Overhead distribution_short analysis of locations - USEA

3.3. Recloser Donji Rahić

Location for recloser named Donji Rahić, is shown on the figure 5. Location belongs to 10 kV power line named Ulice. In the vicinity of location there is the low voltage network. On the location is mounted concrete pillar, type 12/1600. For the evaluation of this location see table 6.

Recloser Donji Rahić 0 1 2 (10 kV PL Ulice) The total length of the l < 7,5 km 7,5 km < l < 15 km l > 15 km power line (24,24 km) Number of MV/LV Nsub < 15 15 ≤ Nsub < 25 Nsub ≥ 25 substations (Nsub = 19) Number of end Nk < 1000 1000 < Nk < 2000 Nk ≥ 2000 customers (Nk =1787) Number of end customers on 10 kV 0 1 2 (Nk_10 kV = 0) Number of end customers for I tariff 0 ≤ Nk < 4 4 ≤ Nk < 8 Nk ≥ 8 group (NkI = 0) Average active power for power line from Pav < 0,6 MW 0,6 ≤ Pav < 1 Pav ≥ 1 29.10.13. (Pav = 0,64 MW) Total of energy 5 parameters No of failures Nf < 8 8 < Nf < 12 Nf ≥ 12 (Nf = 20) Total of indicators of 2 continuity of supply Availability of existing DA digital radio (YES/NO) RSSI (Satell network) - 79 < - 65 ≤ dBm < - 79 - 65 ≥ (-72 dBm) Reliability of radio link < 99,9 % ≥ 99,9 % (%) - ??? Total of existing radio 3 communication: TOTAL OF ALL: 10

Table 6. Recloser Donji Rahić

In additon, as you can see, table 7. show SAIDI/SAIFI parametars for 10 kV PL Ulice, for period of last nine monts.

Overhead distribution_short analysis of locations - USEA

Planned Unplanned Planned Unplanned Month SAIDI SAIDI SAIFI SAIFI January 0,00 4,47 0,00 0,08 February 0,00 0,00 0,00 0,00 March 0,14 0,00 0,01 0,00 April 1,41 0,89 0,09 0,05 May 1,46 18,77 0,05 0,40 Junei 2,49 0,00 0,11 0,00 July 6,57 5,39 0,07 0,17 August 20,78 0,00 0,06 0,00 September 0,45 0,39 0,00 0,09 Sum 33,30 29,91 0,39 0,79

Table 7. SAIDI/SAIFI parametars for 10 kV PL Ulice

Figure 5. Location for recloser Donji Rahić

Overhead distribution_short analysis of locations - USEA

3.4. Recloser Brka

Location for recloser named Brka, is shown on the figure 6. Location belongs to 10 kV power line named Brka and make connection to Palanka, i.e. to 10 kV PL Gornji Rahić. This is normaly open point in normal working scenario. On the location is mounted concrete pillar, type 12/1600. For the evaluation of this location see table 8.

Recloser Brka 0 1 2 (10 kV PL Brka) The total length of the l < 7,5 km 7,5 km < l < 15 km l > 15 km power line (23,77 km) Number of MV/LV Nsub < 15 15 ≤ Nsub < 25 Nsub ≥ 25 substations (NTS = 23) Number of end Nk < 1000 1000 < Nk < 2000 Nk ≥ 2000 customers (Nk = 1362) Number of end customers on 10 kV 0 1 2 (Nk_10 kV = 0) Number of end customers for I tariff 0 ≤ Nk < 4 4 ≤ Nk < 8 Nk ≥ 8 group (NkI = 6) Average active power for power line from Pav < 0,6 MW 0,6 ≤ Pav < 1 Pav ≥ 1 29.10.13. (Pav = 0,81 MW) Total of energy 6 parameters No of failures Nf < 8 8 < Nf < 12 Nf ≥ 12 (Nf = 35) Total of indicators of 2 continuity of supply Availability of existing YES digital radio (YES/NO) RSSI (Satell network) - 79 < - 65 ≤ dBm < - 79 - 65 ≥ (-79 dBm) Reliability of radio link < 99,9 % ≥ 99,9 % (%) - ??? Total of existing radio 2 communication TOTAL OF ALL: 10

Table 8. Recloser Brka

In additon, as you can see, table 9. show SAIDI/SAIFI parametars for 10 kV PL Brka, for period of last nine monts.

Overhead distribution_short analysis of locations - USEA

Planned Unplanned Planned Unplanned Month SAIDI SAIDI SAIFI SAIFI January 0 0 0 0 February 0 0 0 0 March 0,46 0,65 0,03 0,03 April 0 0 0 0 May 0 7,87 0 0,12 Junei 4,48 33,25 0,03 0,2 July 2,97 3,09 0,03 0,2 August 0 0,44 0 0,1 September 0 1,76 0 0,03 Sum 7,91 47,06 0,09 0,68

Table 9. SAIDI/SAIFI parametars for 10 kV PL Brka

Figure 6. Recloser Brka

Overhead distribution_short analysis of locations - USEA

4. Conclusion

Based of previous analysis of locations from table 1., we are comming to conclusion to the justification of installation of reclosers to overhead MV power lines to Brčko power distibution company would be optimal to the following two locations respectively:

No. Name of location Name of power line Description

PL 10 kV Potočari 1. Recloser Potočari 1 10 kV Potočari branch to 10/0,4 кV substation Pukiš 2 PL 10 kV Zovik, 2. Recloser Zovik 10 kV Zovik the main power line

Table 10. Priority for instalation two reclosers to overhead power line distribution network

Finally, after installation of two reclosers to this power lines, the goal would be to reduce the unplanned SAIDI and SAIFI parameters for this two power lines.

KOSOVO A4 & A5 Turbine Repairs

WEEKLY REPORT

WEEK ENDING 07 November 2014

(Note: The scope of work tasks and deliverables were taken from the sub agreement between United States Energy Association and Black & Veatch Corporation, Annex 1)

Prepared by: Carl Schaefer Black & Veatch Field Project Manager 08 November 2014

This Weekly Report is provided under Task 7 of the sub agreement. The following Weekly Summary is provided for each task performed.

Task 1: General. Maintain daily contact with USAID Kosovo, KEK management and TurboCare representatives while in and not in country through email, regular calls, and weekly progress reports.

Worked Performed: During the week, I met with Arben Gjukaj KEK Director Manager twice to discuss issues. I participated in KEK daily Steering Committee Meetings. These meetings were held to approve Non Conformance Reports which add additional work and time to the TurboCare unit 4 plan. I maintained contact with USAID through, Edi and Roxanne, and communicated with USEA Deputy Program Manager Albert Doub to discuss the issues with TurboCare units 4 & 5plans.

Activity 1: Review critical documents pertaining to the return of Kosovo A units 4 and 5 into operation including the contract with TurboCare.

Worked Performed: I reviewed the TurboCare contract, assessment reports produced by Black & Veatch and Alstom. I reviewed TurboCare Non Conformance Reports and provided comments on their schedule impact. Reviewed the TurboCare work plans and met with TurboCare daily to discuss their progress.

Recommended Actions: Due to the TurboCare management in Poland, they have not provided a unit 5 work plan. This plan is needed to determine if unit 5 is on schedule to meet the completion of 19 December 2014. To elevate I have made the KEK site management team aware of this issue. They appear to have received the same response from Poland. I suggested this issue needs to be advanced to the KEK executive’s team for resolution.

Activity 2: Provide initial assessment of the work plans established by TurboCare to monitor their progress and identify and implement recovery plans.

Worked Performed: I assessed the current unit 4 work plan. The work plans have numerous issues because they are not prepared according to planning standards. Examples: not all the remaining work activities are planned, activities are missing relationships, some activities have no durations and they have not developed the critical path toward meeting 19 December 2014. Without this information you don’t have a plan. Recommended Actions: USAID and I discussed the following actions with Arben on Friday 7 November 2014.

a) KEK to insist TurboCare provide a unit 5 work plan under their contract responsibilities, b) TurboCare needs to provide an experienced planner on site or I will need to provide them with training on how to develop work plans, c) TurboCare needs to provide a person who has the authority to make decisions on site (currently decisions are made from Poland which tends to add time), d) There are critical materials and the plan to send additional materials to Poland for repair. KEK needs a representative in Poland shop to track the progress of all KEK materials. This will ensure all materials would be delivered on schedule.

Activity 3: Collaborate with TurboCare and KEK to establish a Baseline Schedule to measure progress and identify issues.

Work Planned: On 11 November 2014, I will collaborate with TurboCare and them in developing a Baseline Schedule. This will enable the project to track progress, define critical activities and to provide the project with when the units will return to service.

Activity 4: Monitor TurboCare’s progress against their current work plans and the Baseline Schedule during the “plan of the days” meetings.

Worked Performed: On 4 November 2014, I established and started a “plan of the day” (POD) progress meeting. These meetings are with KEK, TurboCare and USAID and used to status their current unit 4 work plan, to identify and implement mitigating action and develop recover plans required to bring the units online by 19 December 2014. Unit 5 will be discussed at these meetings when TurboCare provides a Baseline Schedule.

Activity 5: Identify and facilitate that the obligations under KEK’s contract with TurboCare are achieved.

Worked Planned: When the Baseline Schedules for units 4 & 5 are developed, a comparison will be conducted using the Baseline Schedules deliverables and the TurboCare contract deliverables.

KOSOVO A4 & A5 Turbine Repairs

WEEKLY REPORT

WEEK ENDING 14 November 2014

(Note: The work tasks and deliverables were taken from the sub agreement between United States Energy Association and Black & Veatch Corporation, Article 5 Reporting and Annex 1 Scope or Work)

Prepared by: Carl Schaefer Black & Veatch Field Project Manager 15 November 2014

The following report is provided for each task performed.

General: Maintain daily contact with USAID Kosovo, KEK management and TurboCare representatives while in and not in country through email, regular calls, and weekly progress reports.

Worked Performed:

While in country this week, I met with the KEK Director Manager and USAID representatives and attended KEK Steering Committee Meetings. These meetings are held to approve Non Conformance Reports (NCR) which adds additional work and time to the TurboCare unit 4 plan. During the meeting I provided advice to KEK on schedule impact when approving the NCR’s. I met with KEK management to discuss customs impact on the work plans. I maintained daily contact with USAID and communicated with the USEA Deputy Program Manager to discuss the issues with TurboCare units 4 & 5plans.

While out of the country during the week of November 17th plans have been made to keep in contact with USAID, USEA and KEK. I will remain in contact with TurboCare through KEK providing me with daily information for review.

Task 1: Review critical documents pertaining to the return of Kosovo A units 4 and 5 into operation including the contract with TurboCare.

Worked Performed: I will continue to review the TurboCare contract to ensure all commitments are planned (this will not be finished until a unit 5 schedule is issued). I have continued to review Non Conformance Reports to provide comments on their schedule impact. I will continue to review the TurboCare work plans for accuracy of progress and to discuss the issues during daily progress meetings. In addition, I held a few planning sessions with TurboCare providing them with needed training.

Recommended Actions: TurboCare management in Poland have not released a unit 5 work plan. This plan is needed to determine if unit 5 is on schedule to meet the completion of 19 December 2014. I have made the KEK, USAID, and USEA management aware of this issue.

Task 2: Provide initial assessment of the work plans established by TurboCare to monitor their progress and identify and implement recovery plans. Worked Performed: I continued to assess the current unit 4 work plan. The work plans have numerous issues because they are not prepared according to planning standards. Examples: not all the remaining work activities are planned, activities are missing relationships, some activities have no durations and they have not developed the critical path toward meeting 19 December 2014. Without this information you don’t have a Baseline Plan.

Recommended Actions: The following actions were provided under the 7 November Report. Below is a current status. USAID and I continue to discuss the following actions with the KEK Director. a) KEK to insist TurboCare to provide a unit 5 work plan under their contract responsibilities (see e below); b) TurboCare needs to provide an experienced planner on site or I will need to provide them with training on how to develop work plans (see e below); c) TurboCare needs to provide a person who has the authority to make decisions on site. Currently decisions are made from Poland which tends to delay progress on site and possibly adding time to the completion date (see e below); d) There are critical materials currently in Poland and a plan to send additional materials to Poland for repair. KEK needs a representative in Poland shop to track the progress of all KEK materials. This will ensure all materials would be delivered on schedule (see e below); e) KEK executives have planned to meet with TurboCare in Poland during the week of 17 November to discuss all the issues above.

Task 3: Collaborate with TurboCare to establish a Baseline Schedule to measure progress and identify issues.

Work Performed: I have collaborated daily with TurboCare to assist in the development of a Baseline Schedule. This will enable the project to track progress, define critical activities and to provide the project with the visibility as to when the units will return to service.

Task 4: Monitor TurboCares’s progress of the work plan against the Baseline Schedule Plan.

Work Performed: Continue to Monitor TurboCare’s progress against their current work plans and the Baseline Schedule during the “plan of the days” meetings and daily walk downs of the both units 4 & 5.

Task 5: Identify any issues which may delay return to operation, and collaborate with TurboCare to identify and implement mitigating actions and recovery plans that may be required to bring the units online by December 19, 2014.

See Task 2 Recommended Actions

Task 6: Identify and facilitate that the obligations under KEK’s contract with TurboCare are achieved.

See Task 1 Worked Performed.

KOSOVO A4 & A5 Turbine Repairs

WEEKLY REPORT Number 3

WEEK ENDING 21 November 2014

(Note: The work tasks and deliverables were taken from the sub agreement between United States Energy Association and Black & Veatch Corporation, Article 5 Reporting and Annex 1 Scope or Work)

Prepared by: Carl Schaefer Black & Veatch Field Project Manager 15 November 2014

The following report is provided for each task performed.

General: Maintain daily contact with USAID Kosovo, KEK management and TurboCare representatives while in and not in country through email, regular calls, and weekly progress reports.

Worked Performed:

While not in country this week, I maintained contact with KEK, USAID and USEA. I remained in contact with TurboCare through KEK providing me with daily schedules and reports for review. .

Task 1: Review critical documents pertaining to the return of Kosovo A units 4 and 5 into operation including the contract with TurboCare.

Worked Performed: I will continue to review the TurboCare contract to ensure all commitments are planned (this will not be finished until a unit 5 schedule is issued).

Task 2: Provide initial assessment of the work plans established by TurboCare to monitor their progress and identify and implement recovery plans.

Worked Performed: I continued to assess the current unit 4 work plan. The work plans have numerous issues because they are not prepared according to planning standards. Examples: not all the remaining work activities are planned, activities are missing relationships, some activities have no durations and they have not developed the critical path toward meeting 19 December 2014. Without this information you don’t have a Plan.

KEK executives have planned to meet with TurboCare in Poland during the week of 17 November to discuss the following issues related to planning:

e) TurboCare must provide a unit 5 work plan under their contract responsibilities; f) TurboCare needs to provide an experienced planner on site; g) TurboCare needs to provide a person who has the authority to make decisions on site. Currently decisions are made from Poland which tends to delay progress on site. h) There are critical materials currently in Poland and a plan to send additional materials to Poland for repair. KEK needs a representative in Poland shop to track the progress of all KEK materials. This will ensure all materials would be delivered on schedule. Task 3: Collaborate with TurboCare to establish a Baseline Schedule to measure progress and identify issues.

Work Performed: This week I remained in contact with TurboCare through KEK. I developed and provided them information which when incorporated will enable the project to track progress, define critical activities and to provide the visibility as to when the units will return to service.

Task 4: Monitor TurboCares’s progress of the work plan against the Baseline Schedule Plan.

Work Performed: See Task 3.

Worked Performed: See Task 3

Task 6: Identify and facilitate that the obligations under KEK’s contract with TurboCare are achieved.

Worked Performed See Task 1

KOSOVO A4 & A5 Turbine Repairs

WEEKLY REPORT Number 4

WEEK ENDING 28 November 2014

(Note: The work tasks and deliverables were taken from the sub agreement between United States Energy Association and Black & Veatch Corporation, Article 5 Reporting and Annex 1 Scope or Work)

Prepared by: Carl Schaefer Black & Veatch Field Project Manager 9 December 2014

The following report is provided for each task performed.

General: Maintain daily contact with USAID Kosovo, KEK management and TurboCare representatives while in and not in country through email, regular calls, attending meetings and providing weekly progress reports.

Current Forecasted Return to Service Dates Unit 4 29-Dec-14

Unit 5 01-Mar-15 The Current Forecasts are from the contractor (TurboCare). The date for unit 4 could be met but only if none of the known risks become an issue. If any of the known risks happen, the most probable target date for unit 4 would be around the 10 January 2015 timeframe.

Worked Performed:

While in country this week, I met with the KEK Director Manager, USAID representatives and the TurboCare Director. We discussed the lack of providing schedules for both units A 4 and A 5. At first the TurboCare Director was not very cooperative stating he did not want his staff doing planning work but to be on the turbine deck where the work is being performed. After comments by the KEK Director, the TurboCare Director stated he would provide the unit 4 schedule and in the future we should attend the TurboCare morning meeting to receive schedule progress. No firm commitment was made on providing a unit 5 schedule.

Attended KEK Steering Committee Meetings held to approve Non Conformance Reports (NCR) which adds additional work and time to the unit 4 plan. During the meeting I provided advice to KEK to consider both time and cost impact when approving the NCR’s. I also discussed with KEK management the need to request from TurboCare a detailed breakdown of all costs which would support the NCR total number being requested for approval. I have maintained daily contact with USAID to discuss the TurboCare issues.

KEK and TurboCare met in Poland during the week of 17 November. The KEK Director provided me with a verbal debrief of the meeting: 1) The materials that were sent to Poland to be refurbished in their shop were being worked, 2) TurboCare made a commitment that all materials and spare parts would be delivered by 10 December, 3) TurboCare proposed Low Speed Balancing of the IP Rotor instead of High Speed Balancing. This would mean unit 4 final date of 23 December 2014. High Speed Balancing would mean unit 4 final date of 31 December 2014. KEK accepted the proposal providing: TurboCare warranties a safe unit operation and unexpected outages due to the non-balancing under high speed of the rotor will be under TurboCare responsibility including compensation as a consequence of not performing High Speed Balancing. 4) Bonuses will be offered to workers if unit 4 is complete before 24 December, 5) TurboCare will work through the holiday period, 6) Additional workers will be added to the craft labour, 7) The schedule for unit 5 will be issued by the 28 November.

See attached notes for additional detail of the meeting.

Services being provided by B&V Task Order shall conclude week ending 12 December 2014. Funds authorized by the current task order shall be expended on this day.

Task 1: Review critical documents pertaining to the return of Kosovo A units 4 and 5 into operation including the contract with TurboCare.

Worked Performed: I will continue to review the TurboCare contract to ensure all commitments are planned (this will not be finished until a unit 5 schedule is issued). I have continued to review the TurboCare work plans for accuracy of progress, to ensure all activities are scheduled and that the schedule includes realistic information.

Recommended Actions: TurboCare management in Poland have not released a unit 5 work plan. This plan is needed to determine the status of unit 5 and the impact on purchasing power. Although not on paper, all KEK and TurboCare understand unit 5 will not return to service until the 1st Quarter 2015.

Task 2: Provide initial assessment of the work plans established by TurboCare to monitor their progress and identify and implement recovery plans.

Worked Performed: I continued to assess the current unit 4 work plan. The work plans have numerous issues because they are not prepared according to planning standards. Examples: not all the remaining work activities are planned, activities are missing relationships, some activities have no durations and they have not developed the critical paths which would set the most likely date to return unit 4 to service. I have attended each morning meeting challenging the unit 4 schedule to determine the critical activities and the accuracy of the schedule.

Recommended Actions: The following actions were provided under the 7 November Report. Below is a current status. USAID and I continue to discuss the following actions with the KEK Director.

a) KEK to insist TurboCare to provide a unit 5 work plan under their contract responsibilities. During the meeting held in Poland a commitment was given to deliver the unit 5 schedule by 28 November 2014. Although there has been a continuous requests, to date this remains open. b) TurboCare needs to provide an experienced planner on site or I will need to provide them with training on how to develop work plans. TurboCare has provided a dedicated individual to provide the project with the daily schedule. The person has some scheduling experience. I have provided him training and continue each day to indicate where there are mistakes that need to be corrected. c) TurboCare needs to provide a person who has the authority to make decisions on site. Currently decisions are made from Poland which tends to delay progress on site and possibly adding time to the completion date. TurboCare has not provided a person at the site to make decisions. What has improved is the ability to reach Poland daily to discuss any issue. d) There are critical materials currently in Poland and a plan to send additional materials to Poland for repair. KEK needs a representative in Poland shop to track the progress of all KEK materials. This will ensure all materials would be delivered on schedule. KEK has not provided a person in Poland to track progress of materials. What has improved is a daily verbal report on the status of material deliveries. Note: Material delivery is a risk toward meeting unit 4 completion.

See attached notes under General

Task 3: Collaborate with TurboCare to establish a Baseline Schedule to measure progress and identify issues.

Work Performed: I have collaborated daily with TurboCare to assist in the development of a Baseline Plan. This would enable the project to track progress against the original plan.

Task 4: Monitor TurboCares’s progress of the work plan against the Baseline Schedule Plan.

Work Performed: Continue to Monitor TurboCare’s progress against their daily work plans. When a Baseline Schedule is prepared progress could be measured against the original plan. I have continued to walk through the turbine area to validate the reported progress of unit 4.

See Task 2 Worked Performed

Task 6: Identify and facilitate that the obligations under KEK’s contract with TurboCare are achieved.

See Task 1 Worked Performed

KOSOVO A4 & A5 Turbine Repairs

WEEKLY REPORT Number 5

WEEK ENDING 5 December 2014

(Note: The work tasks and deliverables were taken from the sub agreement between United States Energy Association and Black & Veatch Corporation, Article 5 Reporting and Annex 1 Scope or Work)

Prepared by: Carl Schaefer Black & Veatch Field Project Manager 6 December2014

The following report is provided for each task performed.

Worked Performed:

While in country this week, I met with the KEK Director Manager, Board of Directors during a tour of A4 & A5, the Steering Committee members, USAID representatives and the TurboCare Planner and Construction Supervision. With the KEK Board of Directors the discussions were generally around the status of A4 & A5. The Steering Committee meetings approve are to approve or disapprove the cost and time of NCR’s new work. Daily meetings are to review the accuracy of the A4 schedule with TurboCare.

Task 1: Review critical documents pertaining to the return of Kosovo A units 4 and 5 into operation including the contract with TurboCare.

Worked Performed: I will continue to review the TurboCare contract to ensure all commitments are planned (this will not be finished until a unit 5 schedule is issued). I have continued to review the TurboCare work plans for accuracy of progress, to ensure all activities are scheduled and that the schedule includes realistic information.

Work Performed:

TurboCare has made numerous commitments to issue the A5 schedule. As of this date, there has been no A5 schedule submitted that reflect work progress, critical activities or an agreed completion date. The current contract date is (December 19, 2014). An attachment was provided in my Weekly Report of 28 November which provides some insight on the status of unit 5 return to service depending on rotor blade replacement (February / March 2015).

Task 2: Provide initial assessment of the work plans established by TurboCare to monitor their progress and identify and implement recovery plans.

Worked Performed: I continue to assess the current unit 4 work plan. I have attended each morning meeting challenging the unit 4 schedule to determine the critical activities and the accuracy of the schedule. The work plan continues to have numerous issues because they are not prepared according to planning standards. Examples: not all the remaining work activities are planned and activities are missing logical relationships, and some of the risks are not planned which would provide the most likely date to return unit 4 to service.

Task 3: Collaborate with TurboCare to establish a Baseline Schedule to measure progress and identify issues.

Work Performed: Note: The definition of a Baseline Schedule is “The original plan, saved for later comparison with the revised or updated plan.” Since my arrival in country during the week of 7 November 2014, I have not been successful locating what could be defined as the original plan.

We have had some success having TurboCare issue daily schedules. These schedules provide progress and visibility as to when TurboCare plans unit 4 will return to service. Working with KEK this week, we have started to build a parallel plan which will provide us with a more reasonable date for unit 4 return to service. This incorporates known schedule risks and will improve schedule accuracy.

Action Needed: When the unit 5 plan is issued by TurboCare KEK should save the plan as the Baseline Schedule. This assumes a schedule will be issued prior to the majority of work being completed.

Task 4: Monitor TurboCare the progress of the current work plan against the Baseline Schedule Plan.

Work Performed: See Task 3.

Work Performed: I have defined the current risks and discussed these with the KEK Director and USAID. These risks are: 1) the level of the TurboCare work force over the holiday season. TurboCare has stated they will provide bonuses if unit 4 is finished before the start of the holiday season, 2) the delivery of parts and materials being refurbished in Poland. The TurboCare commitment was to have all parts and materials on site by 10 December. A few have already slipped beyond 10 December, 3) little time given to test and commission unit 4 and 4) the schedule impact of NCR’s. Unfortunately these continue to be found late in the plan. See attached latest NCR.

Currently the earliest date to have unit 4 operational as planned by TurboCare is 29 December 2014. See Attached Schedule, the critical path being through the Generator.

Task 6: Identify and facilitate that the obligations under KEK’s contract with TurboCare are achieved.

See Task 1: Worked Performed.

FINAL REPORT SUMMARY

Kosovo A Unit 4 and Unit 5

Prepared by: Carl Schaefer

Black & Veatch Project Manager

Date: January 13, 2015

Section A: Background

Kosovo Energy Corporation (KEK) the generating utility in Kosovo experienced explosions during the failure of electrolytic facility producing Hydrogen for the Kosovo A power plant. The explosion destroyed the facility and the resulting shockwave caused significant damage to units A4 & A5 Turbine – Generator and other mechanical, electrical and instrumentation equipment.

Black & Veatch performed a damage assessment and provided a detailed report on the repairs needed to bring the units back into service. KEK contracted with TurboCare (Ethos Energy Company) to perform the repairs. The contract called for the repairs to both units is completed by December 19, 2014.

Black & Veatch and The United States Energy Association (USEA) enter into a Subagreement NO. USEA /USAID - AID-OAA-A-12-00036-2014-703-05 to assist KEK in administering the contract for the repair work being performed by TurboCare to the generating units A4 & A5. During the month of November and until mid-December, I spent 5 weeks assisting KEK. The scope of my assistance included the following tasks:

1. To review critical documents pertaining to the return of units A4 & A5 to operation including the contract with TurboCare. 2. Provide initial assessment of the work plan established by TurboCare to monitor their progress on their work. 3. Collaborate with TurboCare to establish a Baseline Schedule Plan to measure the progress during the monitoring stage in order to identify delays. 4. Monitor TurboCare’s progress of the work against the Baseline Schedule Plan. 5. Identify any issues which may delay return to operation, and collaborate with Turbo Care to identify and implement mitigating actions and recovery plans that may be required to bring the units online by December 19, 2014. 6. Identify and facilitate that the obligations under KEK’s contract with TurboCare are achieved. 7. Provide weekly progress reports.

Note: My work performed to meet the scope is discussed in the following sections B,C,D, & E.

Section B: Project Introduction

During the first few days after my arrival, I spent my time meeting and discussing the project with the KEK Director Manager, KEK Field Manager, USAID contacts and the TurboCare management team. I also made contact with the USEA Deputy Program Manager.

I attended the KEK Steering Committee Meetings. Members of the committee are the Field Manager, the Engineering Manager, Contracts Manager and Operations persons. These meetings are held to approve or disapprove the contractor’s Non Conformance Reports (NCR’s). Essentially the NCR’s are to receive time and money to perform work outside their contract.

I reviewed TurboCare’s contract scope and reconciled their work plans with the contract. In addition I performed field inspections with KEK individuals to observe TurboCare’s performance against their work plan. Section C: Initial assessment when I arrived

The following were my initial assessments made during the first week at Kosovo:

1. TurboCare work plans had numerous issues and were not prepared according to planning standards. These issues result in not having the visibility if the contractor is on schedule are behind schedule toward meeting the December 19, 2014 contract commitment. 2. TurboCare does not have experience planners and they did not have support from their management in Poland. This was evident when I met the TurboCare Director and asked why he does not have experienced people developing the schedule. His response was he doesn’t want his people spending time planning but in the field driving the work. 3. TurboCare does not have a senior person on site with approval authority. All approvals need to be made from Poland. This added time to the schedule. 4. TurboCare was not focusing on units 4 & 5 to meet their contract commitment. Most focus was on unit 4. 5. KEK was not challenging TurboCare and pushing work in the field. 6. The NEC contract between KEK and TurboCare was poorly written. It did not follow NEC format and requirements which would have improved KEK positions on receipt of deliverables such as Work Plans, NDT Reports, time to approve NCR’s etc. 7. Most of the work to repair damaged equipment was sent to Poland. KEK has no representation in Poland to follow the repair work schedule and quality of the work. 8. When the KEK Steering Committee meets to discuss NCR’s and other additional work, they need to focus on both time and money before approval. Currently most of the meeting is discussing the approval money. 9. The TurboCare planners were not cooperative toward my suggestions to improve their work plan. Also, they did not meet their commitments made to KEK with providing information. 10. Both the KEK and USAID staff were very open and cooperative. 11. During my daily field inspections, the TurboCare construction workers were very open to discuss all issues. Their quality of work appeared to be very good. 12. To meet their objectives, both KEK and TurboCare need assistance with communication, strategic planning and thinking.

Section D: Accomplishments while in Kosovo

During my work at Kosovo between November 2, 2014 and December 13, 2014 I made the following accomplishments: 1. I started a Plan of the Day meetings with TurboCare, KEK management, and USAID representation. During the meeting TurboCare would report their daily progress, issues and recovery plans if the work scheduled was not accomplish. 2. To improve accuracy of the daily work plan, I conducted planning workshops with TurboCare, USAID and KEK management. I also would review and make corrections to the TurboCare daily plan prior to the meeting. 3. To improve the Steering Committee Meeting regarding NCR approval, I met with the KEK Chairman and made the following suggestions: a) the cost was provided as a total number. In order to make decision on a reasonable cost, KEK must require TurboCare to provide a breakdown by cost element such as salary, materials, transportation, shipping, overhead, etc. b) the committee focused on cost but needs to address the additional time and impact to the schedule. These suggestions were implemented, however, the cost information needs to be enhanced with additional detail. 4. I suggested to KEK management they should send a team to Poland and address: a) the delivery dates of all materials and equipment, b) why all site work is being focused on unit 4, c) KEK needs to receive a unit 5 work plan to determine if the completion of both units will meet the contracted date of December 19, 2014, d) to save time, request TurboCare provide a senior manager who can make decisions at the site, e) In addition to make the plans realistic and accurate, provide a senior planner to the Kosovo site. Note: TurboCare did not support either d or e requests. 5. To save time on the schedule I suggested: a) KEK and TurboCare investigate shops closer than Poland who could assist repairing the damaged equipment. A shop in Serbia was located and made a difference in receiving equipment on time or earlier for installation. 6. To ensure the installation dates would be met, I suggested TurboCare should start work on 2 shifts. This was agreed to by both KEK and TurboCare. 7. As we approached the Holiday Season, I requested TurboCare to provide a Staffing Plan. Depending on the number of resources that remain in Kosovo will determine if unit 4 December return to service date would be met.

Section E. Status of the Project when I departed on December 13, 2014:

The following activities remained open or will not continue when I departed:

1. The receipt of the requested Holiday Staffing Plan. 2. The development of the unit 5 Work Plan. I reviewed with both KEK and TurboCare how to build this plan using unit 4 information and risks. With both organizations lack of experience in building plans, I don’t feel comfortable an accurate unit 5 plan will be produced. 3. An experienced person to assist and guide KEK using Project Management Techniques and Processes. 4. An experienced person who will look ahead, develop schedule risks and assist KEK in problem solving. 5. A person that will be assertive and push the contractor to meet his contract deliverables. Due to the relationship between KEK and TurboCare this is difficult for KEK.

Energy Technology and Governance Program:

Advisory Mission to Kosovo: Power Asset Assessment Report of Major Findings

Cooperative Agreement: AID-OAA-A-12-00036

Wednesday, December 24, 2014 This report made possible by the support of the American people through the United States Agency for International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government. 1/24 Energy Technology and Governance Program

Advisory Mission to Kosovo: Winter Power Economics Report of Major Findings

Prepared for:

United States Agency for International Development and United States Energy Association

Cooperative Agreement: USEA/USAID‐2014‐703‐02

Author:

Jonathan Moore, Moore Ventures, LLC

United States Energy Association 1300 Pennsylvania Avenue, NW Suite 550, Mailbox 142 Washington, DC 20004 +1 202 312‐1230 (USA)

1. Brief Program Overview and Trip Scope Summary

KEK, the Kosovo Energy Corporation, JSC, is the generation arm of the former national/state- owned utility for Kosovo. The company is responsible for all power service to the nation of Kosovo. It is an independent Joint Stock Corporation (JSC), wholly owned by the national government of the Republic of Kosovo, reporting through the Ministry of the Economy & Energy. In late spring June 2014, a hydrogen explosion next to the power house of Kosovo-A plant rocked the facility so extremely that it severely damaged the operating units, and particularly the turbine/generators. The result was an extended outage on the generating units that was scheduled to extend to December 19, 2014, with contractor performance and the as-found conditions on inspection of the machinery extending the outage into the winter peak. USAID, through USEA, requested Jonathan Moore, an industry professional from Kentucky with existing knowledge of KEK and the energy industry of Kosovo, to travel to the country to investigate site conditions and provide in-country support in analyzing the power shortage for the 2014-2015 winter. Moore has worked with USEA on several projects in Eurasia over the last decade; including this project he has visited the region six occasions to consult on energy issues. The scope of the project consisted of support of research, plant site visits, meetings with the stakeholders, and other research resulting in an economic/power model that can be used to understand the situation for Kosovo for winter. This trip report is meant to summarize and consolidate those observations and the assumptions of the analysis into narrative report. Scope Tasks; the work scope which is always subject to changing conditions, but was follows: 1. Review key documents including damage reports and work scope; current winter load forecasts; and Kosovo's energy market rules. 2. Meet with the Kosovo energy market stakeholders to gain a clear understanding of the impact if the units were not brought back online as scheduled 3. Work closely with key KEK staff to develop and refine economic models to analyze the possible power supply scenarios for winter 2014-2015 4. Assist KEK to utilize the economic models and to interpret the results 5. Provide daily progress reports while in country 6. Conduct up to three (3) Skype calls per week with KEK and USAID Kosovo to review progress while in the U.S. 7. Provide the final economic models and final analysis report

Jonathan Moore traveled to the country for 2 trips the weeks of November 3-7 and December 1-5. The first of the trips was focused on understanding KEK’s forecasts, the unit repair status, and collecting data from KEDS, the distribution Utility. During the intervening time, Moore developed a draft economic model to be used to understand the Kosovo power and industry economic situation for the winter. Finally, the second trip provided a time to verify and update the model, work with all stakeholders to review the magnitude of the issues, and to present the findings to USAID and The Embassy. This document is a brief summarizing report of the economic analysis for USAID, which may serve as a preliminary basis for future, more in-depth work. The report provides observations for KEK and the Kosovo energy sector.

12/24/2014 Kosovo Winter Power Economic Assessment Report; USEA-AID Draft A Page 3 of 24

2. Purpose & History i. Winter Peak: The energy sector of Kosovo is typically stressed during the winter seasonal load peak. The generating units have not been maintained or invested in to be flexible in load following, and KEK refuses to operate more than two units in TPP-A at a time. Thus, Kosovo is typically in deficit during the winter, especially during the two daily peaks occurring in the morning and evening hours. ii. The Failure: The situation is heightened in 2014-'15 winter due to the much-publicized catastrophic failure of the Hydrogen production facility that was attached to TPP-A. This failure caused significant damage to the "A" plant units, particularly to the turbine-generator trains, and particularly on A-4 and A5, which were operating at the time of the explosion. iii. Unit A3 Status: A3 was returned to service in July, as its damage was relatively light. This unit has run continuously since being placed into service around July 10th, and this is reputed to be the longest continuous run for any "A" unit since the plant was placed into service in the 1970's. It should also be noted that a 5-month run would be considered an average to good continuous run on similarly-aged units in The United States, but those units would have received revitalization/life extension investments in the 1990's. To run this poorly-maintained unit which badly needs upgrade for this extended period is an impressive (and lucky) feat. iv. Contracted repair Work: KEK has undertaken a contract with TurboCare, which has a subsidiary or JP with a polish company, for the repair of the A4 & A5 units. This contract was supposed to be completed that both units could be placed into service on or before December 19th, 2014. At the time of v. Tariff: KEK and KEDS have received approval for an energy balance through the ERO that will allow for purchased power through the end of the year to cover the outages of one "A" unit through December 19th. (the basic plan of KEK is to always have one "A" unit in reserve, so the plan is never to have more than 2 operating). vi. Delay: Based on my review of the progress, and the additional review of a B&V engineer brought on through USEA, there is no possibly way that KEK will return either unit to service by 12-19-2014. At the point of the last trip in-country, it appears that the earliest dates for return to service are as follows: a. A4 > 1/10/2015 b. A5 ~ 2/28/2015 Also, it should be noted that this assumes that the units will return to service with no issues. The experience of both US engineers on the project is that there will be a substantial start-up period that will involve balancing the entire train by adding weights, testing instrumentation, verifying trips, and the inevitable but unknown rework that will require additional outage time but that will only be found when an attempt is made to start the machine. vii. Outage Size: The work undertaken at Kosovo-A is the largest amount of simultaneous major Turbine-Generator work I have ever seen attempted in a single plant in my career. The repairs, involving shipping-off turbine casings, generator rotor, partial generator rewind, exciter rebuild, etc. would amount the most work I've ever seen attempted on a T-G train if it were to be undertaken on a SINGLE unit; however, KEK, by necessity, has undertaken this major work on two units simultaneously. While many things could be

12/24/2014 Kosovo Winter Power Economic Assessment Report; USEA-AID Draft A Page 4 of 24

improved in the management of the contractor performing the work, we should not lose sight of the fact that the quantity of work here could exceed any T-G ever undertaken. 3. The Modeling Purpose & Structure USAID, through a contract with USEA, requested economic analysis be completed for various likely cases of outage delay for winter, so that the whole energy picture could be understood from both a power shortage and economic perspective. This modeling began with a fact-finding trip in-country the first week of November, and is being concluded this week, with the verification and improvement of the economic model developed for the project and final presentation. i. The Basis: As a basis for the model, I have worked with both KEK and KEDS, and have imported the planning spreadsheets they have used in building their estimates for the sector. I have spent several days working with the KEK Toskana office Regulatory and billing department to both understand what they are doing, and to build a presentation of the issues and costs of delay. These were presented to the Board of Directors, including the Managing Director of KEK at the conclusion of my first visit. Also, during this first trip, I met with KEDS and saw the sheets used for modeling their imports, load forecasts, and nominations. These are created on a 2-per-month basis and typically run until the 15th day of the month tabulating all power into (from KEK & Imports) and out-of the system. These were received during the period between in-country visits when I was working on building a model.

Figure 1: Snapshot of KEDS Forecasting Sheet

Hour of the day, for any given day in the quarter

Top of the table is generation assumed for Kosovo A & B

Bottom portion is the net imports purchased by KEDS

Lylac highlight are additional imports assumed to fill the gap of estimated demand.

Blue Tabs are KEDS ½ month forecast sheets

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ii. Model Product: Between trips to site, I began working with all the data provided. I have found these sheets from KEK and KEDS to be inadequate for the level of generation planning that is being requested (running of such scenarios for outages) and have substantially expanded these into a model that will complete this function. Ultimately, I focused on the KEDS sheets, as these contain both the assumed generation, the imported power that is already contracted, and the load forecast. The final product is a model that can literally model every single 60- minute period for the entire quart of a year -- from December 1 to March 1 – by duplicating the KEDS sheets and producing one customized sheet for every day of the model period (See Figure 2: Unit Running Status as calculated for a modeling case, green comment). Thus, it is possible for to live-model cases by turning any unit off or on from the assumptions in the summary sheet. Additionally, this Unit Status sheet collects the results from the individual sheets in the areas of “MWh Deficit”, weather forecast, etc.

Figure 2: Unit Running Status as calculated for a modeling case

The unit status for a day is set by assumptions taken on the Summary page. This occurs “under the hood.”

A green “Y” shows that the Unit is operating for a given day

An Orange “D” shows that the Unit is going off-line during the day. The number next to this shows the hour of the event

A red “N” shows that the Unit is NOT operating for a given day

A yellow “U” shows that the Unit is coming “UP” during the day

The gray “Unit Status” sheet is where the under-the hood work of turning generators off and on happens in the model.

Green sheets (December) created for EVER DAY, modeling every single 60-minute period of the 3-month modeling period. These follow the form of KEDS sheets.

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iii. Model Structure: This model is designed to perform calculations based on assumptions taken on the Summary sheet. Though data can be changed throughout the model, this is not recommended, as it will change calculations for all future model runs. The data input cells are highlighted with Orange, and these allow the modeler to change:  The outage duration for A 4&5 beyond December 19 baseline.  Additional run-time for A 3 – to run this unit into the winter instead of shutting down on December 19.  Net MW for each generator.  price for power. Also, the model has the flexibility to allow for additional outages for A3 or B1&2 beyond the days already planned. This allows the modeler to see the economic impact of unplanned outages, from an energy perspective (balancing through KOSTT is not yet implemented, and these costs are calculated in a separate model). Figure 3: Key of Color-Coding used in the Model shows the general cell color convention used in the models. Many of the cells are color-coded based on a conditional format formula.

Figure 3: Key of Color-Coding used in the Model

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iv. Model Summary Page: The summary sheet is the only sheet where user interface is needed for most tasks. This sheet provides cells for both input and output results to be show. Additionally, the cases can be tabulated by manually pasting results from the various runs in the table to collect various scenarios from an individual run of the model. See Figure 4: Summary Sheet Input & Report Design for more information and a visual break-down of how all inputs and reports are tabulated.

Figure 4: Summary Sheet Input & Report Design

Column for the current case results, Multiple prior case runs for showing both calculations and various assumptions assumptions for the present case. Case 4D appeared to be the most likely case based on the conversations with all Input Assumptions for stakeholders at the meeting in KEDS power cost, Hi and Low conference room on 12/3/2014

Case 6 was requested by the US Embassy Economic Chief during meetings on 12/4.

This row collects the economic cost the Kosovo energy sector

This row collects the economic cost to KEK only

Row collects the approximate outages if no power is purchased

Input Assumptions for power cost, Hi and Low

Input for Outage delay on A4&5 or extra run for A3

Input for net generation assumed for each unit. These are NET the ThermoKOS reductions.

Input for extra unplanned outages for A3, B1&2

Summary Tab location Original KEK forecast sheets (For Information)

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18 Weather Forecast KEDS & Model Variance of Model to Accuweather Forecast Assmptns Forecast Day Lo Hi Lo Hi Lo Δ Hi Δ 1‐Dec‐14 7.8 12.8 0 7 7.8 5.8 2‐Dec‐14 5.6 11.1 0 7 5.6 4.1 4. Major Assumptions 3‐Dec‐14 3.9 8.3 0 7 3.9 1.3 4‐Dec‐14 4.4 9.4 0 7 4.4 2.4 i. Consumption: This model uses the consumption as 5‐Dec‐14 6.7 9.4 0 7 6.7 2.4 6‐Dec‐14 3.3 8.9 0 7 3.3 1.9 estimated by KEDS in sheets forwarded in November 2014. 7‐Dec‐14 1.1 6.7 0 7 1.1 ‐0.3 8‐Dec‐14 0.0 3.3 0 7 0.0 ‐3.7 The KEDS assumptions appear to be conservative (i.e. high) 9‐Dec‐14 ‐3.3 0.6 0 7 ‐3.3 ‐6.4 10‐Dec‐14 ‐0.6 4.4 0 7 ‐0.6 ‐2.6 assuming a lower-than-expected temperature for much of the 11‐Dec‐14 ‐4.4 3.3 0 7 ‐4.4 ‐3.7 12‐Dec‐14 1.1 5.6 0 7 1.1 ‐1.4 winter. While I have downloaded and analyzed temperature 13‐Dec‐14 3.3 8.9 0 7 3.3 1.9 14‐Dec‐14 3.3 10.0 0 7 3.3 3.0 data from KEDS and a forecast from Accuweather, there is 15‐Dec‐14 1.1 7.8 0 7 1.1 0.8 16‐Dec‐14 0.0 3.9 0 7 0.0 ‐3.1 currently no reliable way to correlate load with temperature; 17‐Dec‐14 ‐0.6 3.9 0 7 ‐0.6 ‐3.1 18‐Dec‐14 ‐3.3 3.9 0 7 ‐3.3 ‐3.1 that said, it does appear that KEDS has assumed a cooler- 19‐Dec‐14 ‐6.1 0.6 0 7 ‐6.1 ‐6.4 20‐Dec‐14 ‐6.7 0.6 ‐43 ‐2.7 ‐2.4 than-average winter, while Accuweather is predicting a 21‐Dec‐14 ‐5.6 1.1 ‐43 ‐1.6 ‐1.9 22‐Dec‐14 ‐6.1 0.6 ‐43 ‐2.1 ‐2.4 warmer-than-normal one. Thus, some conservatism is built 23‐Dec‐14 ‐6.1 0.0 ‐43 ‐2.1 ‐3.0 24‐Dec‐14 ‐6.1 0.6 ‐43 ‐2.1 ‐2.4 into the model. This can be seen in Figure 5: Comparison of 25‐Dec‐14 ‐0.6 3.9 ‐43 3.4 0.9 26‐Dec‐14 0.0 3.9 ‐43 4.0 0.9 KEDS forecast vs Accuweather, which compares these two 27‐Dec‐14 0.0 2.8 ‐43 4.0 ‐0.2 28‐Dec‐14 ‐0.6 3.9 ‐43 3.4 0.9 assumptions with conditional formats. Not that the orange 29‐Dec‐14 ‐1.7 3.3 ‐43 2.3 0.3 30‐Dec‐14 ‐2.2 0.6 ‐43 1.8 ‐2.4 sections in the comparison table are the show more 31‐Dec‐14 ‐1.1 1.7 ‐43 2.9 ‐1.3 1‐Jan‐15 2.8 7.8 ‐91 11.8 6.8 conservative assumptions by KEDS 2‐Jan‐15 1.7 8.3 ‐91 10.7 7.3 3‐Jan‐15 1.7 6.7 ‐91 10.7 5.7 4‐Jan‐15 2.8 5.0 ‐91 11.8 4.0 ii. Baseline: I have worked to zero-out the base-line case where 5‐Jan‐15 2.8 7.2 ‐91 11.8 6.2 6‐Jan‐15 4.4 10.0 ‐91 13.4 9.0 the "B" units operate with no derate and the "A" units return 7‐Jan‐15 3.3 10.0 ‐91 12.3 9.0 8‐Jan‐15 3.3 7.2 ‐91 12.3 6.2 to service on December 19th. Note that the sheets, as 9‐Jan‐15 3.3 6.1 ‐91 12.3 5.1 10‐Jan‐15 1.7 8.9 ‐91 10.7 7.9 provided by KEDS, have a 2.06 M€ hole where not enough 11‐Jan‐15 0.6 5.0 ‐91 9.6 4.0 12‐Jan‐15 0.6 8.3 ‐91 9.6 7.3 power would be produced or imported to provide full power 13‐Jan‐15 ‐0.6 7.8 ‐91 8.4 6.8 14‐Jan‐15 ‐1.7 7.8 ‐91 7.3 6.8 to Kosovo -- however KEDS has assured us in meetings that 15‐Jan‐15 3.9 8.3 ‐91 12.97.3 16‐Jan‐15 2.8 11.1 ‐71 9.8 10.1 this can be covered by flexibility in the existing contracts and 17‐Jan‐15 0.6 8.9 ‐71 7.6 7.9 18‐Jan‐15 4.4 10.0 ‐71 11.4 9.0 by deviations of the predicted consumption due to warm- 19‐Jan‐15 4.4 12.2 ‐71 11.4 11.2 20‐Jan‐15 6.1 14.4 ‐71 13.1 13.4 spells. Thus, I have manually added imports to each 1/2 21‐Jan‐15 3.9 11.1 ‐71 10.9 10.1 22‐Jan‐15 5.0 8.9 ‐71 12.0 7.9 monthly period within the ±50% contract constraint that has 23‐Jan‐15 4.4 12.2 ‐71 11.4 11.2 24‐Jan‐15 2.8 10.0 ‐71 9.8 9.0 been communicated to zero-out the base case. These are 25‐Jan‐15 ‐3.3 5.6 ‐71 3.7 4.6 26‐Jan‐15 ‐5.6 ‐1.7 ‐71 1.4 ‐2.7 noted in the model on the sheets provided by KEDS, with 27‐Jan‐15 ‐6.7 0.0 ‐71 0.3 ‐1.0 28‐Jan‐15 ‐5.6 1.7 ‐71 1.4 0.7 comments and color-coding of changed cells. 29‐Jan‐15 ‐0.6 5.6 ‐71 6.4 4.6 30‐Jan‐15 ‐2.8 7.8 ‐71 4.2 6.8 31‐Jan‐15 2.2 8.3 ‐71 9.27.3 iii. Changes to baseline: There are 2 major changes to the 1‐Feb‐15 1.7 6.1 ‐73 8.7 3.1 2‐Feb‐15 ‐0.6 6.1 ‐73 6.4 3.1 baseline during my trip in December, and a few small ones: 3‐Feb‐15 ‐2.8 7.8 ‐73 4.2 4.8 4‐Feb‐15 ‐1.7 7.8 ‐73 5.3 4.8 5‐Feb‐15 0.6 8.9 ‐73 7.6 5.9 a. KEK states that ThermoKOS will take an average 6‐Feb‐15 1.1 6.1 ‐73 8.1 3.1 7‐Feb‐15 1.7 11.7 ‐73 8.7 8.7 of 15 MW from B1; thus the load for B-1 has been - 8‐Feb‐15 2.8 11.1 ‐73 9.8 8.1 9‐Feb‐15 6.1 11.7 ‐73 13.1 8.7 revised from 265 to 250. Presently, no parallel reduction 10‐Feb‐15 3.9 15.0 ‐73 10.9 12.0 11‐Feb‐15 2.2 17.2 ‐73 9.2 14.2 in consumption is assumed, as ThermoKOS is serving 12‐Feb‐15 6.7 12.8 ‐73 13.7 9.8 13‐Feb‐15 3.9 12.8 ‐73 10.9 9.8 only existing customers who would have used this same 14‐Feb‐15 2.2 10.6 ‐73 9.2 7.6 15‐Feb‐15 1.7 13.3 ‐7 3 8.7 10.3 heat source to offset electricity in the historical years 16‐Feb‐15 ‐1.1 17.2 ‐45 2.9 12.2 17‐Feb‐15 2.2 18.3 ‐45 6.2 13.3 from which KEDS has taken their consumption 18‐Feb‐15 4.4 19.4 ‐45 8.4 14.4 19‐Feb‐15 3.9 19.4 ‐45 7.9 14.4 estimates. 20‐Feb‐15 6.7 13.9 ‐45 10.7 8.9 21‐Feb‐15 5.0 13.9 ‐45 9.0 8.9 22‐Feb‐15 5.0 15.6 ‐45 9.0 10.6 b. KEK states that A3 must come down, probably 23‐Feb‐15 5.6 13.3 ‐45 9.6 8.3 24‐Feb‐15 3.9 10.0 ‐45 7.9 5.0 today, December 4th, for a 6-day outage to deslag the 25‐Feb‐15 ‐3.3 11.7 ‐45 0.7 6.7 26‐Feb‐15 ‐3.3 13.9 ‐45 0.7 8.9 boiler. This will enable A3 to run for the entire winter. 27‐Feb‐15 ‐0.6 14.4 ‐45 3.4 9.4 28‐Feb‐15 1.7 12.8 ‐45 5.77.8 c. KEK requested that A2 be revised to 260 MW. Figure 5: Comparison of KEDS forecast vs Accuweather

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d. A3 Deslagging outage: A3 was scheduled to come off-line on December 4 for needed maintenance (deslagging) and this was included in the model, but was not in the base-line modeling run. e. A3 Outage Freezing: If delaying both of the A-4/5 units & A3 suffers unexpected outage during cold weather, there is a serious risk that the plant will suffer from catastrophic freezing. iv. No unplanned outages: The model does not presently contemplate unplanned outages of the "B" units for most cases. I have built in the flexibility to make these assumptions, but there have been few requests to model these. That said, it is possible to turn "B" units "off" during any period with a few keystrokes to see the economic and shortage impacts. v. Balancing: No balancing charges through KOSTT are included in the analysis. I have developed separate spreadsheets to approximate these, but those costs are not applicable currently, due to delays in implementation of the market rules and due to the fact that they are only applicable in the case of an unplanned outage. vi. A3 Continued Run: To minimize risk to Kosovo, A3 must continue to run through the winter. If this is possible, the shortage and cost issues are mostly mitigated. Also, scenarios that assume that 3xA units will run if possible for the complete month that the A4 & A5 units return to service is possible but is not modeled. It is possible that all 3 units could be run during certain times of high demand, and this could be a big economic benefit to KEK and to Kosovo. The way the economic incentives under KOSTT market rules are structured, however, KEK has a major penalty for unplanned outages, and assuming one unit off-line at all times helps to minimize that risk. vii. The Model shows variance to accepted baseline: All calculation are based on the current tarriffs, assuming that energy balance provided by KEDS is accurate true (including closing the 2M import gap mentioned earlier). This model shows a variance from what we understand as the base case of tariff-allowed power production and import, under the parameters provided by the stakeholders. viii. Transmission Capacity: The ability of KOSTT to transmit and provide “right of way” access for imports is assumed to be adequate. However, the transmission capacity is dynamic due to regional energy balance, and this is not known and cannot be modeled or calculated either this far in advance or with the level of information currently available. ix. Outages are not “recommended”: The decision to raise rates to cover energy shortfall or to implement a rolling-outage schedule is a political one and not a technical decision. While it is my opinion that that the economic impacts of raising rates to cover the power short-fall would be dwarfed by the impact of rolling outages through Kosovo homes and businesses – where the cost will be seen in lost production and well-being. However, this cannot be reliability modeled and is a political decision to be made by others using the best available information. Outages are not “recommended” but are the do-nothing alternate.

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5. Major Findings The major findings are based on Case 4D, which has seemed like the likeliest case throughout the 7 weeks of my work on the project. Even at the writing of this report, the information remains the same. Case 4D assumes:  A4 doesn’t come back into service until January 10th. This is a delay of 22 days from the base, and it should be noted that even on in late December that the contractor maintains that the unit will be completed before the year end. However, unforeseen issues are likely to delay what is a most optimistic view.  A5 doesn’t come back until at least March 1. This puts A5 outside the modeling period, and it does not operate in any of the days that are being studied.  A3 continues to run the entire period, after the deslagging outage at the beginning of December. Thus, A3 had approximately 6 days at the beginning of December, but did not have any further interruptions.  Neither “B” unit experiences any outages.  ThermoKOS only pulls about 10 MW from the capacity of B1. With these assumptions, Case 4D has a €7.3M to €8.5M cost to Kosovo, and KEDS will save approximately €3.8M in payments to KEK. The savings in payments to KEK may be used to partially offset (about 40%) of the total outages that would otherwise be required, as this cash is free to purchase power from outside of Kosovo. i. Deviations from Base: With the deslagging outage of A3 and the reductions in "B" for ThermoKOS and conservatism on B2, we open with a NET hole of approximately 33 GWh. KEK lost revenue is 1.6 M€, and the loss to the whole sector is 3.2 M€. This is modeled in Case 1B, and truly resets the baseline. The numbers quoted above are include these impacts. ii. Delay of A4: Currently the delay of A4 is modeled for a NET hole of approximately 60 GWh. KEK lost revenue is an additional 1.5 M€, and the total loss to the whole sector (including B derates) is 7.3 M€. Again, only 40% of this power can be purchased under existing tariff's. iii. Importance of A3: It is absolutely critical that A3 continue to run through the winter, until A4 is repaired. The importance of this cannot be over-stated. iv. Purchases through Jan 5: Recent information just before the finalization of this report is that KEDS will be able to purchase adequate supplies through January 5th to avoid outages. This being the case, the major risk to Kosovo for outages is mitigated, assuming that A4 truly does return to service on schedule. Additionally, I understand that KEDS will be adding further purchases based on the schedule as it can be ascertained on January 5th. This could fully mitigate the power shortage for the winter if not further delays or failures are experienced.

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6. Conclusions & Recommendations i. KEK Economic Forecasting: KEK must add additional human resources and devote training and management attention to building economic modeling capacity of the type completed in this project. This function naturally would fall into the Regulatory Affairs department in the KEK Toscana office. Further this capacity must be leveraged in building strong cases that can be presented to regulators in support of everything from capital spending to support of cases to recoup repair expenses. As KEK becomes a market player, it will live and die by the way the economics of the market it is playing in and NOT by the number of MWh (energy) it produces. ii. KEDS Economic Forecasting: Of the players in the market, KEDS showed the greatest capacity to model the winter available capacity and expected load. However, KEDS should further develop its understanding of weather and the load curve due to economic activity. While in this short-duration, emergency support project, I was unable to correlate the high/low temperatures to the expected adjustment to load with any accuracy, with extended study of this and other factors, KEDS could build an accurate prediction model for day-ahead and even annual predictions to help them minimize the . iii. Regulatory Understanding: There is a great deal of complaining about the regulator by all parties in the sector. The regulator does need to independently build ERO institutional understanding of the market and economics of the power system thorough its own modeling (similar to the way this model explains the issues). However, it is the responsibility of THE REGULATED entities to explain and sell the regulator on the realities of their respective situation. Failures of the regulator to act in the best interests of the sector should be seen not as “regulatory failures”, but should be viewed as failures of the market players in educating the regulator on the competing pressures they face, and on selling the regulators and the larger public on appropriate solutions. iv. KEK Investment: Investment in KEK to make the units more reliable, stable, increase capacity, and to improve flexibility is the subject of an earlier report I produced from my travels in May. Most of the observations from this report remain operative, and the recommendations – particularly with respect to capital investment – are still very much needed.

Moore Ventures, LLC, through USEA, would be pleased to propose a seminar on the use of this model, along with more generally modeling skills needed to operate in the Kosovo and Balkan regional energy marketplace.

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APPENDIX A XL of market conditions developed with KEK

Document Number / Applicable Title Date/Status Filename Pgs. KEK Market Scenerios.xlsx KEK Market Scenarios; Case 1 7/7/2014 1 Multiple cases are captured in this model. See the attached XL file, which may be manipulated.

Notes: XL Modeling in conjunction with KEK Toscana, Nov‐Dec., 2014

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APPENDIX B Summary Presentation at conclusion of visit

Applicable Document Number / Filename Title Date/Status Pgs. Prezantimi për KEK‐JJM.pptx Notes on KEK, Kosovo All 11/7/2014 1 Presentation given to KEK Management, USAID, and Board of Directors Notes: Presentations made on 11/6/2014, from daily report:

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APPENDIX E Contacts from Trip to Kosovo List of contact information

Document Number / Applicable Title Date/Status Filename Pgs. KEDS & KEK Contacts 1 KOSTT & USEA Contacts 2 US Government Contacts 3

Notes:

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KEDS; Kosovo Electricity Distribution & Supply Company J.S.C Contacts from Trip, May 2014

KEK; Kosovo Energy Corporation J.S.C Contacts from Trip, Nov-Dec 2014

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KOSTT; Kosovo Transmission System & Market Operator Contacts from Trip, Nov-Dec 2014

USEA Contracts Contacts from Trip, Nov-Dec 2014

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USAID/USA Contracts Contacts from Trip, Nov-Dec 2014

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APPENDIX G Resume for Principal Engineer Jonathan Moore, Moore Ventures, LLC

Document Number / Applicable Title Date/Status Filename Pgs.

Notes:

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APPENDIX H Agenda and Daily Reports from Travel May 2014

Document Number / Applicable Title Date/Status Filename Pgs.

Notes:

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Locatn/ What was discussed Attendees Ref Docs. Time KEK‐A/ Traveled to Kosovo A to meet Carl Schaefer of B&V and to tour the outage work • Ardian Hasani, Electrical 1.TurboCare schedule, 1300 underway on Kosovo A4 & A5 Reviewed power plant project status with the engineer, Engineer, Kosovo A which is a MS Project looked over the printed schedule from TurboCare, and took a walking tour of the work. ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ document and is not Major items of note: • Edi Shyti (USEA) detailed enough to be a • This is the most major turbine outage I've ever seen in my career. I have never • Carl Schaefer (B&V) useful work‐plan. seen so many major components requiring so much work, and on 2 units • Jonathan Moore simultaneously. • I observe that the crane is going to be a serious limiting resource when parts begin coming back. No gantry has been assembled. This could help ‐‐ a portable gantry that would allow smaller parts to be rigged (Such as bolts, etc.) without tying‐up the Overhead crane. • During our walk‐through, I did not see a single worker. As we left, almost as if to make a demonstration there people are available to work, about 8 or so guys showed up (for both turbines. • There is major machining that will be required on many of the mating surfaces. This does appear to be started. • The generator #5 needs a partial re‐wind. The inner coils have been stripped out, and we are told that new windings are being made at a shop someplace. We were told it is only a week to reinstall ‐‐ I'd estimate much more than a week, as the coils will need to be fitted and installed, possibly with semiconductive paste, the coils shimmed in, ripple‐springs and wedges installed and tested, and then the coils will be individually brazed to the existing coils and ring bus. Then the whole mess gets insulated. All of this is in a limited space, and is the responsibility of KEK. Once all this work is done, they will need to test the machine, install the rotor/endbells, etc. It is not small work, and definitely not one week. • My gut from walking around the plant is that, if 2 shifts are worked, it might be possible to return the units to operation in 10‐14 weeks, but that is only a gut feel based on my plant experience. B&V Project Manager will have a much better feel after working with TurboCare and KEK. • The TurboCare schedule is not nearly detailed enough to function as a viable work‐plan. I judge this problem is in serious schedule trouble.

Evening Dinner with Carl Schaefer, with a wide ranging discussion of KEK, the conditions in • Kosovo, etc.

USAID-USEA Kosovo Page 1 Daily Report 2; Tuesday € Tuesday, November 4, 2014 10:30 PM

Location/ What was discussed Attendees Ref Docs. Time Hotel Started out with a wide‐ranging discussion of the issues with Kujtim's team. •Kujtim Hoxha, Director of 1. KEK sheet for energy Prishtina / Discussed the failure of TPP‐A and response, current status. Regulatory Affairs projection and billing for 0730 •Ali Hoxha, Manager for Tarriff 2014: Balanca Vjetore e Learned a great deal about the agreement for emergency supply with KESH: Design; Electrical Engineer by Energjisë Elektrike e KEK‐ •KESH responded to A with 40 GWh ‐‐ KESH has supported the imbalances and training with plant experience. Rishikuar 2014‐ Pas Toskana/ supplied additional power that KEK needed. •Osman Stullcaku, Specialist for aksidentit 09092014F.pdf 0800 •Presently, KEK has a due balance to KESH, 35GWh ‐‐ if we cannot turn back the Licensing & Regulation. Lawyer 2. KEK sheet for energy power, they have to pay actual cash. •Ms. Hanumshahe Ibrahimi, projection and billing for •Agreement for exchange since 2011 for emergencies. Manager of Planning & billing; 2015: Balanca Vjetore e •By the end of the year, must be 0‐0. Also, this balance is maintained on a Mining engineer new to Energjisë Elektrike e monthly basis. position. 2015.pdf •KOSTT may be able to help. •Eljas Jashari, Billing Expert 3. XL from previous work to •Discussed KESH surplus April ‐‐ June (wet season for the hydros). He is an economist who is very calculate balancing costs •Albania also has a deficit July‐Sept (tourism) smart and interested. titled KEK market •Yearly, books are also closed and this is moved to asset/liability accounts. • balancing scenarios; Nov •Can return energy or cash 2014.xls •Formula is something like: KESH gives 1 Gwh, KEK returns 1.5 at night. 1‐2 ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ summer to winter EMS. 1‐1 is with KESH. •Edi Shyti •KESH proposed 1‐2 day to night ratio for a new agreement. •Jonathan Moore •I discussed that this should really be a rolling agreement, with cash happening •Arif Hoti (translator) only on balances more than year old. Also, KESH tried to take advantage and renegotiate at the expiration of the contract term. •Agreement should have a term that would expire whenever the most recent month is balanced (maximum of 12 months). •Pricing for keeping books is set at an agreed price. KESH tried to get highest market price at the renegotiation. •Presently, the agreement expires on a date certain and not to do with the balances or rolling balance. So whoever, is down at expiration loses the leverage for renegotiation. The agreement will not allow for further exchange but to allow for payment of past debts.

According to Kujtijm, there are 3 bad things for KEK: •Units cannot minipulate •Heavy oil has additional cost, which is fired for stabilization. •Surplusses are a cost.

Spent time working through sheet with Kujtim. Very good tracking sheet ‐‐ needs other things as well, and he asked for a critique. Stepped through this tracking sheet, and I really need to make notes in a copy so I can remember the translation. Also,

KOSTT KEK is a trading company that happens also to sell a product into the marketplace. •Naim Bejtullahu, CEO KEK only makes money from it's trading arm ‐‐ generation supports that only. ‐‐ •Ms. Vjosa Rezniqi (Manager of Skender Operations) •Skender Gjonbalaj Miscellaneous notes including: •Nermine Arapi (KEDS) Supply •ERO approved KEK‐KEDS plan through year‐end only for repair of the units. Manager •KOSTT doesn't have direct relations with any other TSO ‐‐ everything is ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ through EMS presently. Market Rules agreement will solve this issue. •Edi Shyti •There has been an intra‐day issue, and it appears to have impacted the •Albert Doub transfers to and from KOSH (Albania) with KEK. This may be fixed at the end •Jonathan Moore of the week. •The market rules are delayed due to final tests of KEK secondary reserve. Testing of all connections are not completed. This will not happen until some time in the 1st quarter, which actually means that the market rules are probably delayed until April 2015. • Transmission Free Reserve Capacity ‐‐ this is the bartered shift of capacity that may be trued‐up over weeks (in approximately the same hour). May be 50

USAID-USEA Kosovo Page 1 MW or 30 MW. This was very confusing to me. •Long‐term transactions and D‐1 nominations may be trimmed by TSO due to transmission constraints. •Nominations work as follows: ○Day‐ahead nominations may be submitted at 3PM; 5:30 PM they are completely closed. These give "rights to the road" ○ Changes may take place from 1800 till 2200 (these are inter‐day, D‐0) ○Free Capacity that is not used is known at 1800 hrs; it may be taken on a first‐come / first‐served basis until 2200 ○Interday nominations are for primary reserve only. • Cost if interruption is ~200 Euro/MW minimum •OST is Albanian TSO •January 1, the Market Rules will be implemented. •There is an emergency provision that allows renomination 4 hours in advance. •KEK has some contacts for trading it doesn't use. It is a trader but it does not behave as one due to its feeling that power purchases are subject to public procurement rules. •KEK‐KEDS‐KOSTT did a simulation of market rules, and the outcome was 1 Million Euro for a 2 week period (money that changed hands)

Hotel Meeting with USAID to discuss observations and progress. ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ Prishtina / •Roxanne Suratgar 16:00 • Edi Shyti •Albert Doub •Jonathan Moore Evening Dinner with Carl Schaefer & Albert Doub, with a wide ranging discussion of KEK, the •Carl Schaefer • conditions in Kosovo, etc. •Albert Doub •Jonathan Moore

USAID-USEA Kosovo Page 2 Daily Report 3; Wednesday € Wednesday, November 5, 2014 11:30 PM

Locatn/ What was discussed Attendees Ref Docs. Time KEK‐A/ Learned that KEK has begun coding an SQL database • Kujtim Hoxha, Director of Regulatory 1. Began work on XL modeling work 1300 software that will provide KEK with a means of Affairs based on KEK sheets: institutionalizing some performance measures, and tracking • Ali Hoxha, Manager for Tarriff Design; • Balanca Vjetore e Energjisë unit performance. Testing is going on now, though what Electrical Engineer by training with plant Elektrike e Rishikuar 2014‐ they have so far is fairly crude. The ultimate goal is to get experience. Pas aksidentit 09092014F.xls the billing to be automated. Kujtim is the driver of this • Osman Stullcaku, Specialist for Licensing • Balanca Vjetore e Energjisë work. & Regulation. Lawyer Elektrike e 2015.xls • Ms. Hanumshahe Ibrahimi, Manager of 2. Kujtim Hoxha began a list of things They could definitely use this database to add performance Planning & billing; Mining engineer new that could be placed in a bullet indicators. Also, I expect there is commercially available to position. point list for powerpoint software that automates some of these tasks. • Eljas Jashari, Billing Expert presentation. He is an economist who is very smart and 3. Reviewed J. Moore presentation Worked on understanding the sheets Kujtim provided ‐‐ this interested. from May titled: XL sheets that estimate. Notes on KEK, Kosovo, 2014 May ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ 12‐23.ppt Took these and began building the outline of a model. • Edi Shyti • Carl Schaefer Kujtim began building a few bullet points for a presentation. • Jonathan Moore • Arif Hoti (translator)

Evening Dinner discussion with Carl Schaefer, • XL Model based on KEK sheets, Work on the economic analysis from afternoon till midnight newly titled Balanca Vjetore e at Hotel Pristina. Energjisë Elektrike e Rishikuar 2014‐ Pas aksidentit 09092014F; JJM Mods.xls

USAID-USEA Kosovo Page 1 Daily Report 4; Thursday € Thursday, November 6, 2014 6:00 PM

Locatn/ What was discussed Attendees Ref Docs. Time Hotel Met with Edi to run through the modeling XL sheet for winter •Edi Shyti 1. newly titled Balanca Prishtina impacts from outage delays. Discussed the model and its •Jonathan Moore Vjetore e Energjisë 0800 limitations, including the need to use 2 sheets for a unit trip ‐‐ Elektrike e Rishikuar 2014‐ one to calculated balancing costs (which are calculated by Pas aksidentit 09092014F; hour) and one for energy/Capacity costs, which are by day. Set JJM Mods.xls day's agenda, including to get the load forecast if possible. 2. Presentation Prezantimi për KEK‐JJM.ppt KEK‐ Work in KEK Toskana board room in preparation for meetings •Kujtim Hoxha, Director of 1. XL Model based on KEK Toskana/ in the afternoon: Regulatory Affairs sheets, newly titled 0830 •Went through the model to verify calculations with •Ali Hoxha, Manager for Tarriff Balanca Vjetore e Energjisë Kujtim. This model is based on spreadsheets that KEK Design; Electrical Engineer by Elektrike e Rishikuar 2014‐ normally uses. training with plant experience. Pas aksidentit 09092014F; •Created a presentation of major trends, to be used with •Osman Stullcaku, Specialist for JJM Mods.xls the XL spreadsheet. Worked extensively on findings, Licensing & Regulation. Lawyer 2. Presentation Prezantimi recommendations, and bullet points. •Ms. Hanumshahe Ibrahimi, për KEK‐JJM.ppt •Worked with Kujtim Hoxha on the presentation notes to Manager of Planning & billing; 3. XL from previous work to provide the presentation to the KEK BOD. Reviewed Mining engineer new to position. calculate balancing costs notes with the team. •Eljas Jashari, Billing Expert titled KEK market •Debated the market costs and thresholds. He is an economist who is very balancing scenarios; Nov •Ran through the presentation in practice for the smart and interested. 2014.xls afternoon's meeting. 4. Kujtim's quick daily sample •Kujtim worked on a potential XL model to be used for the ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ of how balancing works: real‐time updates. •Edi Shyti Realizimi‐ Planifikimi •Jonathan Moore 31.10.2014 ‐ versioni i ri.xl •Arif Hoti (translator) 5. Model that Kujtim is • preparing in SQL KEDS / Met with George Karagutoff to discuss load forecasting and •George Karagutoff • 1300 load shedding. •Nermine Arapi (KEDS) Supply •Load is in 18 groups of approximately 30 MW groups. Manager •KEDS has a load forecasting spreadsheet by half‐month increments. This will be provided to Edi. •Discussed the issue of purchases, and what is approved through ERO.

KEK‐ Meeting with MD and BOD KEK MD Toskana/ BoD 14:30 •Presented preliminary economics. Kujtim Hoxha's team from •Presented the power‐point presentation to the BOD. Regulatory Affairs. •Q&A and discussion followed regarding the KEK ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ economics and the costs and probabilities of extended •Edi Shyti unit outages. •Roxanne Suratgar •Jonathan Moore •Arif Hoti (translator)

USAID-USEA Kosovo Page 1 Daily Report 1; Monday Monday, December 1, 2014 9:00 PM Location/ What was discussed Attendees Ref Docs. Time Hotel Swiss Traveled to Kosovo; went to Swiss Diamond and met to meet with Edi and Roxanne to go over the ‐‐‐‐‐‐US Team‐‐‐‐‐‐ XL Model "KEK Diamond / modeling work complete thus far and to plan the week's agenda. Reviewed the model construction •Edi Shyti Outage purchase‐ 14:00 and the preliminary results. Modified the Case 4 (adding 4D) to assume: •Roxanne Suratgar deficit scenerios.xlsx" •A3 goes off‐line December 6th for 10 days for a review and inspection, then is on‐line for the •Jonathan Moore rest of winter. The cost of this little investigative outage (net to Kosovo) is between 1.0‐2.5 M €! 15:00 •Reviewed the rolling‐outage schedule and showed two possible examples. Discussed 8‐hour •Luis Guzman verses 4‐hour scenarios. Worked through live examples. •Carl Schaefer (B&V) •Reviewed the cases, and ran several live examples, after discussing with

From 3PM to after 4PM, Carl Schaefer of B&V and Luis Guzman arrived to further discuss the model and the assumptions. Major updates to the model included: •Modified Case 4D for A4 to return to service January 10th. Carl believes this is the most optimistic view. This is despite the internally conflicting views from TurboCare that A4 will still return to service on December 23, 26, and/or 31st. Discussed manpower issues over the Christmas and New year's holidays for the contractor. •Kept A5 not coming back till March 1st. Again, Carl seems to believe this a likely view, and it could be earlier or late. •Late in the day, KEK apparently decided not to turn‐off A3 after all for an inspection. It will run till it fails, then they'll fix whatever problem that took it off and run it again to failure, all winter. (as an aside, JJM believes this is a very good decision on the part of KEK, and is the one I would make in their shoes) •Discussed at length the rolling outage possibilities, and city verses country black‐outs. My contention is that this is a political decision and generally not a technical one (as is raising rates verses rolling black‐outs. I kept those black‐out scenarios the same as was. Discussed the week's plans and goals. Luis wanted to focus on where the smartest money could be spent to mitigate rolling outages. My feeling is that: •If perfect knowledge could be had with respect to when the units would come back, the smartest money would be to purchase blocks of power at THE END of winter. Purchasing further out, as those contracts are almost universally guaranteed to be for lower cost. Thus by purchasing power starting with the latest need and purchasing forward as soon as money runs out, the greatest quantity of outages could be avoided. This means that the pain of outage would be felt sooner, but would be over with in a shorter duration. •This implies actual knowledge of when the units might come back. In 4 the 4 weeks since I came, Unit 4 has slid backwards by 3 weeks, and Unit 5 has slid by 11 weeks. That is not very good performance. •It's all contingent on A3 being available. If A3 can continue to run all winter, much of the impacts are mitigated. Getting A4 back sooner will also help. As would over‐generating. Possibly the smart money would purchase a block of power in January, then if A4 does return to service, that power could be sold on the open market. If the winter is a harsh one, this could likely be sold at a profit. If it is mild, this may also be sold at a loss. However, it's a hedge, since it hedges both: 1.Harsh Winter and A4 returns to service quickly = profit. 2.Harsh winter and A4 does not return to service quickly = nearer to adequate power, for less money that could have been purchased on the spot market. 3.Mild winter and A4 does not return to service quickly = adequate power at prepaid and known costs. 4.Mild winter and A4 returns to service quickly = adequate power and loss on the hedge. The point here is that 1‐3 are broadly neutral or positive for Kosovo, and 2&3 are probably the most likely scenarios based on current trajectory. Maybe I can come up with some kind of Venn diagram to show this.

I stressed that this is a management decision requiring understanding of the technical data I am pulling together, but ultimately you either have to be clairvoyant or lucky to get this right. It is a judgment call that the Regulator should buy into.

Edi recommended a presentation to the ERO at the end of my time here. Evening Dinner with Carl Schaefer, with a wide ranging discussion of KEK, the conditions in Kosovo, etc. •Jonathan Moore •Carl Schaefer (B&V)

USAID-USEA Kosovo Page 1 Daily Report 2; Tuesday Tuesday, December 2, 2014 4:30 PM Location/ What was discussed Attendees Ref Docs. Time KEK‐ Met at KEK‐Toskana to go over the modeling work complete thus far and review • Kujtim Hoxha, Director XL Model "KEK Toskana/ methodoloigy. Reviewed the model construction and the preliminary results. Modified of Regulatory Affairs Outage purchase‐ • Eljas Jashari, Billing deficit scenerios.xlsx" 0800 the Case 4D and ran several live cases to assume: Expert •KEK argued with the January 10th assumption. Kujtim believed that the December 23 was the correct date. Ultimately, I did not change this. ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ •KEK believes that the B units are only capable of; • Edi Shyti (USEA) B1 = 250 net, due to 10‐15 ThermoKOS • Jonathan Moore ○ • Arif Hoti (translator) ○B2 = 260, or 5 less than KEDS assumptions. •Discussed ThermoKOS at length. KEK believes that ThermoKOS might reduce the KEDS load by 1x‐2x the cost to KEK in MWH Need some way to model this. •Discussed the overall methodology. Kujtim had a good understanding of this and stated he broadly agreed with what he saw, and wants a copy of the final model to use on his own •A units were left at equivalent capacity (130). Kujtim stated that A4 might be capable of more after the outage. However, presently units are on de‐rate due to coal quality. Concluded discussions after about an hour and a half with Kujtim stating he understood and had no questions or concerns. I worked in their offices on model improvements and updates to daily reports until time to go to KEDS. KEDS / Met with KEDS to get major questions answered. It is apparent that they hold the keys to • George Karagutoff 1. XL Model "KEK 1100 most of the answers. Also, they have the ability to finance the deficit if the regulatory • Nermine Arapi (KEDS) Outage purchase‐ Supply Manager deficit uncertainty could be erased. Key notes follow: scenerios.xlsx" •KEDS has the flexibility of ±50% of import based on weather built into its contracts. ‐‐‐‐‐‐US Team‐‐‐‐‐‐ 2. KEDS sheet for Plan As such, if KEDS has contracted for 200 MW for an hour in January, it has the ability • Edi Shyti of December 4, to import up to 300 MW. The price negotiated for this is $56/MWh (for KEDS, this • Roxanne Suratgar 2014 is gross, but it would net the $26.62 avoided KEK cost). • Jonathan Moore 3. KEDS quick • Arif Hoti (translator) summary sheet of •Consumption is actually based on worst‐case temperatures. the temperature ○2012 was the coldest winter assumptions for the ○2013 was the average. This is the basis for the projections base cases. This ○2014 was really like spring all winter. was produced, I believe, while we •Jan‐March, total contracted amounts is around 10 M€. This is the cost based on the were sitting there. base‐line, contracted amounts, and the ±50% flexibility would be additional cost or credit to this $10M. The flexibility is built‐in to the contracts, but is not financed. However, no bank guarantees are necessary to activate these amounts of power ‐‐ just the ability for KEDS to collect the money with return. •For December, the cost if imported power is around 7M€ ‐‐ that amounts to the contracted amounts with some deviations assumed, I believe. The actual contracted amount is somewhere just over $6M€ + change, and there is around $0.5M€ KEDS is assuming they will have to import in addition ‐‐ not sure which baseline, but I think this included in the baseline of the current model I am using. •Calendar year ‐‐ have already exceeded regulatory allotment of purchases for the 2014 calendar year. Thus, KEDS is counting on the ERO granting tariff relief and allowing them to collect this. This is very generous, as KEDS is basically financing this short‐fall (my opinion). •Calendar year is the fiscal year for the tariff. However, the tariff year starts April 1 (shifted by a single quarter). Thus, for the first quarter, KEDS is working in the dark; not sure what the tarriff will be for the fiscal year they are operating in. •George made a big deal about the money that would not be paid to KEK. My model currently ignores this, as it is a deficit to Kosovo in any case (KEK is 90% or more fixed costs, so they will get the rate increase to cover those costs anyway). However, in the short‐term, KEDS can use that money to purchase power, and thus basically get spend that money without ERO approval. Thus, 40% of any power purchase (at 56€/MWh) is covered with KEK "losses", but 60% is not covered.

USAID-USEA Kosovo Page 1 •There is another 3M€ is available from KOST ‐‐ their tariff includes these charges built‐in for balancing. These represent moneys that KEK and KEDS have paid into KOSTT, but that KOSTT has not been required to tap into due to market rules implementation delays. In theory, the ERO could allocate these funds toward the gap in power. I do not totally buy this, and I expect it will be a topic of discussion tomorrow. •We discussed ThermoKOS; They will be taking power from KEK ‐‐ however, since they are not expanding the capacity, presently KEDS is not predicting any reduced consumption. This is because ThermoKOS had old oil burners that intermittently served its existing customer base. However, ThermoKOS has not consistently served its customers in the past, and now that service will be consistent. ○To the extent that ThermoKOS actually served its customers in the past, the displacement of the electricity load is already taken into account in the consumption that is based on the historical data that KEDS is using ○On the other hand, to the extent that ThermoKOS did not consistently support its customers in the past, the additional ThermoKOS steam service will displace some amount of electric consumption. It is impossible to tell what this will be, and it will become another variable that can be manipulated. ○ThermoKOS customers have no incentive to conserve. Presently, electricity customers may turn‐down the thermostat when leaving the house (Kujtim actually does this), but as steam is not metered, it will be left to comfort temperature 24X7. This further deminishes the co‐gen efficiency improvements. •ThermoKOS could take as much as 25 MW at the coldest days. This will vary to almost nothing (5MW yesterday) if the temperature is warm outside. Someday, A2 will also be connected. The model could be built to vary both consumption and offset. •KEDS will provide information on the temperature assumptions. I have one example of this, but they will be providing some curve on load verses temperature. •Discussed load shedding; The real answer for load shedding is that there are 18 X 30MW blocks. They are as follows: Cat Block A6 Total Blocks 18 B6 Total Residential MW's 540 C6 •Load shed should be done in 3‐4hr blocks. Ultimately, we decided to cancel my meetings with KOSTT ‐‐ they will be at stakeholders meetings tomorrow ‐‐ and focus on revisions to the modeling determined in the KEDS meeting. It is evident to me that KEDS holds the keys to the kingdom, so to speak. All questions I had were answered at this level.

The KEDS meeting and Roxanne/Edi's requests added a full additional layer of complexity to the model. It literally doubles the dependent variables (with temperature), and adds distortion of the regulatory structure that penalizes KEK / provides savings to KEDS. KEDS can use avoided KEK money to stretch the money it doesn't pay KEK (deferred rates) to buy power. Also, the KOSTT money. The remainder is load‐shed. I have to figure out how to show all of this, while also varying temperature.

Hotel / Daily report and modeling work, in preparation for meetings tomorrow, expected all XL Model "KEK afternoon afternoon, evening, and early AM. Outage purchase‐ deficit scenarios; to Evening TEMP sensative.xlsx"

USAID-USEA Kosovo Page 2 Daily Report 3; Wednesday Wednesday, December 3, 2014 6:00 PM Location/ What was discussed Attendees Ref Docs. Time Swiss Daily report and modeling work, in preparation for meetings. Worked toward ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ • XL Model "KEK Diamond understanding the complex relationship between weather and load. I did find an • Jonathan Moore Outage purchase‐ deficit Hotel Accuweather forecast that says this winter is to be more mild than the one that KEDS is scenerios.xlsx" predicting, which is helpful. While I placed the accu‐weather forecast alongside the KEDS • Temperature data forecast in the model, I was ultimately unable to achieve reliable equation to do that modeled in KEDS with. Thus, this temperature data is the model color‐coded for information, but right now sheet Copy of KEDS it’s not doing anything mathematically. There appears to be another independent Consumption Diagrame.xls variable operating under the data someplace that adds significant error, because I could not get my equations to "predict" the load based on temperature accurately for 2013.

Ultimately, I was able to get the model to show several important things though these hours of work: •The model and KEDS forecasts are very conservative, due to colder predictions. • I was able to get the "B" units automated so that they can be turned off and on from the summary page to run scenarios. •I automated further the summary page and re‐ran all scenarios. •I inserted a new key to color‐codes on the summary page. •I added more data on the summary page and reformatted this to be more clear. • I added a step that shows the avoided cost of KEK lost revenue, and showed this reduction as purchasing additional power. •I added a row for outages, assuming 4‐hour rolling outages. •I cleaned‐up a great number of other items, and added some conditional formats.

Swiss Reviewed the model and the work completed. Discussed temperature and the difficulty • Edi Shyti • XL Model "KEK Diamond in modeling this. Went over all the issues and prepared for the meetings with the market •Roxanne Suratgar Outage purchase‐ deficit Hotel / players. •Jonathan Moore scenerios.xlsx" 1500 •Carl Schaefer • Temperature data (B&V) modeled in KEDS sheet Copy of KEDS Consumption Diagrame.xls KEDS / Met with KEDS to get discuss the model with all parties. I spent probably 30 minutes ‐‐‐‐‐‐ KEDS ‐‐‐‐‐‐ • XL Model "KEK 16000 running through the way the model is constructed with the parties, and answering • George Karagutoff, Outage purchase‐ CEO deficit questions. George would frequently ask for a scenario, then run his own calculation on a • Nermine Arapi (KEDS) scenerios.xlsx" calculator, and he would check and verify my modeling results. Key notes follow: Supply Manager • Temperature data • KEDS has the flexibility of ±50% of import based on weather built into its contracts. modeled in KEDS As such, if KEDS has contracted for 200 MW for an hour in January, it has the ability ‐‐‐‐‐‐ KOSTT ‐‐‐‐‐‐ sheet Copy of KEDS to import up to 300 MW. The price negotiated for this is $56/MWh (for KEDS, this • Naim Bejtullahu, CEO Consumption • Skender Gjonbalaj, Diagrame.xls is gross, but it would net the $26.62 avoided KEK cost). ALSO, related to this, KEDS Market Operations has all consumption in the base case covered, and they are assuming they will need Director to tap the negotiated €56/MWh. This cleans out my €2M in the base case. I must clean this up overnight before presentation to USAID. ‐‐‐‐‐‐ KEK ‐‐‐‐‐‐ • Arben Gjukaj, MD •Consumption is actually based on worst‐case temperatures. Discussed my • Kujtim Hoxha, Director comparative analysis. Many notes were taken. of Regulatory Affairs • We discussed ThermoKOS; They will be taking power from KEK ‐‐ however, since • Salih Bytyqi, CFO they are not expanding the capacity, presently KEDS is not predicting any reduced consumption. This is because ThermoKOS had old oil burners that intermittently ‐‐‐‐‐‐US Team‐‐‐‐‐‐ served its existing customer base. However, ThermoKOS has not consistently • Edi Shyti served its customers in the past, and now that service will be consistent. • Roxanne Suratgar ○ To the extent that ThermoKOS actually served its customers in the past, the • Jonathan Moore displacement of the electricity load is already taken into account in the • Arif Hoti (translator) consumption that is based on the historical data that KEDS is using ○ On the other hand, to the extent that ThermoKOS did not consistently support its customers in the past, the additional ThermoKOS steam service

USAID-USEA Kosovo Page 1 will displace some amount of electric consumption. It is impossible to tell what this will be, and it will become another variable that can be manipulated. ○ ThermoKOS customers have no incentive to conserve. Presently, electricity customers may turn‐down the thermostat when leaving the house (Kujtim actually does this), but as steam is not metered, it will be left to comfort temperature 24X7. This further diminishes the co‐gen efficiency improvements. Based on all of this, it was determined by the entire group of sector players to assume the reduction in KEK generation of 15MW, but to NOT make any assumptions about reduce load. •KEDS wishes to have my information on temperature (the forecast and conditional formats) to update their own modeling of loads with. •All parties requested to get the final economic model to use. KOSTT seemed particularly interested in having this. • Discussed load shedding; The real answer for load shedding is that there are 18 X 30MW blocks. •Tested a failure of one of the B units. Arben G. was adamant that 2 days was the maximum. • A3 outage starting December 4 was confirmed by Arben G. on the telephone during the meeting. I modeled this live to see the impact. •Arben G. stated uneqivocally that B1 maximum (ThermoKOS) should be 250 and B2 should be 260 (I believe this is a conservative derate). Hotel / Daily report and modeling work, in preparation for meetings tomorrow at USAID. XL Model "KEK afternoon Outage purchase‐ deficit scenarios; to Evening TEMP sensative.xlsx"

USAID-USEA Kosovo Page 2 Daily Report 4; Thrusday Thursday, December 4, 2014 6:00 PM Location/ What was discussed Attendees Ref Docs. Time Swiss Daily report and modeling work, in preparation for meetings. Updating the model to the ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ • XL Model "KEK Diamond major things we found last night in our meetings. The most important are: • Jonathan Moore Outage purchase‐ deficit Hotel• I have manually cleared all the deficit/excess inherent in the KES model to make the scenerios.xlsx" base‐line as close to zero MW as I can. This is basically now at under ½GWh for the • Temperature data entire period. I am not very comfortable with this, because it is not totally clear to modeled in KEDS me that KEDS has this money in their tariff. However, all the indications from sheet Copy of KEDS George is that he is good for it. And, if the projections hold, he can decline some of Consumption Diagrame.xls the contracted values starting in late January and all of February, so maybe this is • 2‐page narrative OK. summary requested • I have added and automated a de‐slagging outage in December on A3, starting by Edi Shyti: USAID‐ tonight. This can now be changed on the summary sheet and USEA Kosovo Modeling Narrative extended/shortened/moved/eliminated. This is a ½M€impact to KEK and the Summary.pdf sector, as communicated by Arben last night. document. • I am reran all of the cases with these assumptions as my base‐line. None of the cases as seen previous to these changes are correct.

Once this was done, sent Edi the model in xl. However, he was unable to open my 2013 workbook in the version of .xl used by USAID. Ultimately, Edi got clearance for me to bring my lap‐top and projector to present to USAID.

Further, after these changes were complete, I wrote and sent a 2‐page narrative summary of this work before walking up to the embassy. Please see that summary for a good executive summary of the work completed on this trip.

USAID, Reviewed the model and the work completed. Meeting consisted of 45 minute discussion ‐‐‐‐‐‐US Team‐‐‐‐‐‐ • XL Model "KEK Embassy / of the means and methods of modeling. Discussed temperature and the difficulty in • Edi Shyti, USAID Outage purchase‐ • Arben Nagavci, USAID deficit 1100 modeling this. Take‐aways are: • Roxanne Suratgar scenerios.xlsx" • The embassy wished to have a Case 6, poorer case scenario, which I created real‐ USAID • Temperature data time. I communicated that 4D, in my opinion, is the best‐case at this point. That is • Scott Cameron USAID modeled in KEDS to say, it is maybe the most likely case that we have studied, but a great number of • Todd Christiansen sheet Copy of KEDS things could go wrong compared with this case. It assumes: (US Embassy) Consumption • Jonathan Moore Diagrame.xls ○A3 has NO further unplanned outages. • USAID‐USEA Kosovo ○B units have NO unplanned outages. Modeling Narrative ○Coal remains good quality and no derates are required. Summary.pdf ○A4 repair comes along at the best pace we can imagine. ○A4 comes on‐line with no issues or delays due to commissioning or balancing, or rework. The additional case added at the request of the Todd Christiansen took into account some additional delay on A4 and a short additional outage on B2. • I added a line that would allow subsidy from the government to be added, and it would reduce the number of outages real‐time. Wide‐ranging discussion for about an hour‐and‐a‐half.

KEK Met with KEK Regulatory & Billing department, at their request, to discuss the model and • Kujtim Hoxha, Director Toskana / broad ranging issues of the regulatory department, over coffee. of Regulatory Affairs • Eljas Jashari, Billing 1500 Expert

‐‐‐‐‐‐US Team‐‐‐‐‐‐ • Jonathan Moore

Hotel / Daily reports completed. Some additional modeling work. ‐‐‐‐‐‐US Team‐‐‐‐‐‐‐‐‐‐ XL Model "KEK afternoon • Jonathan Moore Outage purchase‐ deficit scenarios;

USAID-USEA Kosovo Page 1 deficit scenarios; to Evening TEMP sensative.xlsx" Restaurant Dinner with KEK and USAID • Arben Gjukaj, KEK Renissance • Scott Cameron, USAID • Luis Guzman, USAID 2 / 1800 • Edmond Shyti, USAID • Carl Schaefer B&V • Jonathan Moore

Total Blocks 18 Total Residential MW's 540

USAID-USEA Kosovo Page 2 Results of Studied cases; Kosovo energy balance for December Case #1A (BASE) Case #1B Case #2 Current A4 & A5 on 19th A4 & A5 on 19th A4 ON 12-19 A4 & A5: Case Result December December A5 ON 2-1 A3 Status: A3 Off 12-19 A3 Off 12-19 A3 Off 12-19 Actual Energy deficit inherent in the KEDS sheets; Unpurchased pow -219.1 GWh GWh Deficit: -0.1 -63.0 -199.1 (€ 12,269,040) -12269 € 56.00 (€ 3,640) (€ 3,525,760) (€ 11,147,920)

(€ 14,240,850) -14241 Power C € 65.00 (€ 4,225) (€ 4,092,400) (€ 12,939,550) cross-check Only the KEK component of the shortage -- to KEK to plan on Tarrif b -219.1 GWh GWh Deficit: -0.1 -63.0 -199.1 (€ 5,832,176) -5832 € 26.62 (€ 1,730) (€ 1,675,995) (€ 5,299,243) None of these Euro numbers consider the credit to KEDS for not pay Net Euro Short-fall at the (€ 6,436,864) difference, calculated: 56€ - (€ 1,910) (€ 1,849,765) (€ 5,848,677) 26.62€ = -29.38€ Net GWh short-fall after -114.9 purchase power with 0.0 -33.0 -104.4 KEK savings € 0 Hypothetical Subsidy € 0 € 0 € 0 -114.9 919 0.0 -33.0 -104.4 # of 4-hr 30 MW load- 958 0 275 870 shed outages # outages experienced 53 0 15 48 per customer Maximum Hrs /outage 4 Assumptions of Delays for the current case, Kosovo TPP-A 71 A3 Days Additional Run 0 0 0 44 A4 Days delay past 12-19 0 0 0 71 A5 Days delay past 12-19 0 0 44

Assumptions of total days of A-3 or "B" extra outage? 6 B1 Outage days 0 6 6 0 B1 Outage days 0 0 0 3 B2 Outage Days 0 0 0 Assumed maximum Unit Values Max

130 A3 MWnet MAX Pwr 130 130 130

130 A4 MWnet MAX Pwr 130 130 130

130 A5 MWnet MAX Pwr 130 130 130 250 B1 MWnet MAX Pwr 265 250 250

260 B2 MWnet MAX Pwr 265 260 260 Case information stops above this line Additioanl Days of unplanned outage on the B units: Nov Dec 01-19 Dec 20-31 Jan 01-15 Days of Outage, A3 before Dec. 19 6 Outage Start Date 4 Days of Outage, B1 0 0 0 0 Outage Start Date Dasy of Outage, B2 0 0 3 0 Outage Start Date 25 All of the above are Exclusive of balancing penalty for the trip-off-line day! Go to separate sheet to Temperature assumptions for Consumption Estimates THIS CASE KEDS Average Lo Hi Lo Hi D01-19 1 6 D20-31 -3 0 J01-15 -4 2 J16-31 0 4 F01-15 -3 7 F16-28 0 7 NOT PRESENTLY USED! Serious Risks or other issues/assumptions: 1 All numbers above do not include balancing costs that are applied by KOSTT for imbalances. These m 2 A3 is currently scheduled to come off-line immedately for needed maintenance 3 If delaying both of the A-4/5 units & A3 suffers unexpected outage during cold weather, there is a ser 4 Scenerios assume that 3xA units will run if possible for the complete month that the units return to s 5 This calculatoin is based on the current tarriff's, assuming that energy balance is true. This shows a v 6 Transmission Capacity is assumed to be adequate. 7

Key of Color Codes: Orange Highlight = Data input (independent Variable) Green Highlight = Current likliest case € 40.00 Light yellow highlight, orange text, red trim = future flexibility to be added. Gray Highlight = simple formula or if/then formaula Brown highlgiht, bold = summation -38 Red/Blue = conditional formats. Red is 62 increasingly negative, blue is increasingly -10 postivie. -60 White highlight = original KEK/KEDS data Purple highlight = area of data manipulation of original sheets red text can mean: 1. negative numbers or 2. data manipulated from original sheets. Y Referring to Unit status, these signify N Red N = Unit Off; Green Y= On U U = Coming Up; D D = Going off (Down) #VALUE! White on light gray is a cross-check cell. r 2014 to February 2015 Case #3 Case #4A Case #4C Case #4D Case #5 Case #6 A4 & A5 ON A4 Dec 24 A4 Dec 31 A4 Jan 10 B1 and B2 only A4 Feb 1; 3-day B 2-28-2015 A5 Feb 1, 2015 A5 Mar 1, 2015 A5 Mar 1, 2015 A4&5 OFF A5 Mar 1, 2015 A3 ON till 2-28 A3 OFF 12-24 A3 OFF 12-31 A3 OFF 3-1-'15 A3 OFF 12-19 A3 OFF 3-1-'15 wer for any reason -283.6 -199.3 -283.6 -130.7 -504.3 -219.1 (€ 15,879,920) (€ 11,162,480) (€ 15,879,920) (€ 7,318,640) (€ 28,241,360) (€ 12,269,040) (€ 18,432,050) (€ 12,956,450) (€ 18,432,050) (€ 8,494,850) (€ 32,780,150) (€ 14,240,850) basis -283.6 -199.3 -283.6 -130.7 -504.3 -219.1 (€ 7,548,633) (€ 5,306,165) (€ 7,548,633) (€ 3,478,968) (€ 13,424,732) (€ 5,832,176) ying for generation to KEK.

(€ 8,331,287) (€ 5,856,315) (€ 8,331,287) (€ 3,839,672) (€ 14,816,628) (€ 6,436,864)

-148.8 -104.6 -148.8 -68.6 -264.6 -114.9

€ 0 € 0 € 0 € 0 € 0 € 0 -148.8 -104.6 -148.8 -68.6 -264.6 -114.9 1,240 871 1,240 571 2,205 958

69 48 69 32 122 53

71 5 11 71 0 71 71 5 11 22 71 44 71 44 71 71 71 71

6 6 6 6 6 6 0 0 0 0 0 0 0 0 0 0 0 3

130 130 130 130 130 130 130 130 130 130 130 130 130 130 130 130 130 130 250 250 250 250 250 250 260 260 260 260 260 260

Jan 16-31 Feb 01-15 Feb 16-28 March April May

0 0 0 0 0 0

o calculate.

KEDS Worst-Case Base-Line KEDS 2013 Historical Accuweather 2014-'15 Forecast Lo Hi Lo Hi Lo Hi 0 7 -8 13 1.2 6.5 -4 3 8 13 -3.1 1.9 -9 1 -10 13 2.0 7.6 -7 1 -10 13 0.8 7.9 -7 3 -3 15 2.0 10.6 -4 5 -3 15 2.3 14.9

must be calculated on a case-by-case basis using a different sheet.

rious risk that the plant will suffer from catestrophic freezing. service; further spring outage cancillation is likely but not modeled. variance from what we understand as the base case.

June

Ukraine Power System Support Project: Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Energy Technology and Governance Program Cooperative Agreement USEA/USAID/TETRA TECH - 789-2015-1

Monday, April 15, 2019 This report made possible by the support of the American people through the United States Agency for International Development (USAID). The contents are the responsibility of the United States Energy Association and do not necessarily reflect the views of USAID or the United States Government.

Black Sea Regional Transmission Planning Project (BSTP)

Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Ukraine Power System Support Project

Prepared for:

TETRA TECH USEA/USAID/TETRA TECH - 789-2015-1

Authors:

Miloš Stojković, Electricity Coordinating Center (EKC) Andrija Oros, Electricity Coordinating Center (EKC) Maja Marković, Electricity Coordinating Center (EKC) Slobodan Marković, Electricity Coordinating Center (EKC) William L. Polen, United States Energy Association

United States Energy Association 1300 Pennsylvania Avenue, NW Suite 550, Mailbox 142 Washington, DC 20004 +1 202 312-1230 (USA)

CONTENTS

Abbreviations ...... 2 1 Introduction ...... 4 2 Methodology and Approach ...... 8 2.1 Power System Analysis and Models ...... 9 2.2 PSS/E Software ...... 10 3 Load Flow Analysis ...... 14 3.1 Load Flow Model Developed in 2014 Based on 2013 data ...... 17 3.2 Summary Results from 2014 Load Flow Study ...... 20 3.3 Changes Made to the Load Flow Model in Phase II of UPSSP ...... 22 3.3.1 Initial Model Checking and Adjustment ...... Error! Bookmark not defined. 3.3.2 Model Creation ...... Error! Bookmark not defined. 3.4 Updated Load Flow Analysis Results ...... 29 3.4.1 Steady State Analyses to be performed ...... 30 3.4.2 Scenario Models Description and Possible Remedial Actions ...... 32 3.4.3 Load Flow Analysis with Basic Load Shedding Remedial Actions ...... 33 3.4.4 Voltage Profile and Contingency Analysis (N-1) with Additional Remedial Actions ...... 38 3.4.5 Local Remedial Actions and Additional Power System Devices for Potential Local Problems ...... 43 4 Dynamic Stability Model Creation ...... 45 4.1 Questionnaire Data Collection ...... Error! Bookmark not defined. 4.2 Data Available within BSTP ...... Error! Bookmark not defined. 4.3 Ukraine and BSTP Power System Model Description ...... Error! Bookmark not defined. 5 Conclusions and Next Steps ...... 61 6 References ...... 67 Annexes ...... lxix

ABBREVIATIONS

General

TSO - Transmission System Operator Ukrenergo - Ukrainian Transmission System Operator CIGRÉ - International Council on Large Electric Systems UCTE - Union for the Coordination of Transmission of Electricity ENTSO/E - USDopean Network of Transmission System Operators for Electricity (former UCTE) SEE - South East USDope SECI - South East USDopean Cooperation Initiative BSTP - Black Sea Transmission Project LF - Load flow OPF - Optimal power flow IPS/UPS - Interregional Power System/Unified Power System DONBAS - Donets Basin

Transmission

AC - Alternating Current DC - Direct Current HV - High Voltage MV - Medium Voltage LV - Low Voltage HVAC - High Voltage AC HVDC - High Voltage DC SS - Substation OHL - Overhead Lines TR - Transformer OLTC - On Load Tap Changer NTC - Net Transfer Capacity TTC - Total Transfer Capacity

Generation

HPP - Hydro Power Plant PHPP - Pumping Hydro Power Plant TPP - Thermal Power Plant NPP - Nuclear Power Plant CCGT - Combined cycle gas turbine CCS - Carbon Capture and Storage CHP - Combined Heat and Power Generation RES - Renewable Energy Sources VAR - Volt-Ampere-Reactive, reactive power BTU - British Thermal Unit = 1055J = 0.293Wh = 252cal, mBTU = 1000000BTU tcm - thousand cubic meter 1000m3 2

Countries

ISO Country Car Austria AT AUT A Albania AL ALB AL Bosnia and Herzegovina BA BIH BiH Bulgaria BG BUL BG Croatia HR CRO CRO Germany DE GER D Greece GR GRE GR Hungary HU HUN HU Italy IT ITA I FYR of Macedonia MK FYRM MAK Montenegro ME MNE MNE Romania RO ROM ROM Serbia RS SRB SRB Slovenia SI SLO SLO Switzerland CH SUI CH Turkey TR TUR TUR Ukraine UA UKR UKR Armenia AM ARM ARM Georgia GE GEO GEO Moldova MD MLD MLD Russia RU RUS RUS Azerbaijan AZ AZB AZB Belorussia BY BLR BLR Iran IR IRN IRN

3 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

1 INTRODUCTION

4 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report The Ukraine Power System Support Project (UPSSP) was established in September 2014, as a sub- regional project of the Black Sea Regional Transmission System Planning Project to investigate the Ukrainian high voltage network’s capacity to remain stable and secure in light of rising electricity demand, curtailments in Russian gas deliveries and curtailed domestic coal supply. In the Project’s first phase conducted from September – December 2014, nine scenarios were developed and analyzed that related to varying national and regional electricity loads; the capacity to supply domestic coal and Ukraine’s capacity to import coal; supplies of imported natural gas; and the ability to section parts of Ukraine’s network with Moldova and Romania. The scenarios were analyzed through standard load flow studies and resulted in recommendations for a hierarchy of remedial actions that could network stability.

The UPSSP first phase steady state analysis identified critical points on the Ukrainian network that its stability in response to frequently changing loads, coal and natural gas supplies. The data used to construct the scenarios and conduct the first phase load flow simulation models were provided by Ukrenergo based on its system records for 2013 and the winter of 2014, prior to the acceleration of hostilities in east Ukraine.

A recommendation of the first phase study is to update the analysis with data from December 2014 to provide a closer to real-time analysis of the grid’s performance in light of the new topology in Ukraine. The UPSSP first phase report also recommends an in-depth dynamic stability analysis of the grid’s response to rapidly changing loads, fuel supply and large generator outages.

In January 2015, the United States Energy Association contracted with Tetra Tech to commence the second phase of the UPSSP. This report summarizes the steps taken in phase two to refine the load flow model developed in phase one to reflect changes in the topology of Ukraine’s high voltage network (particularly as it relates to separatist held East Ukraine); and to develop an accurate dynamic model of Ukraine’s transmission network that will be employed in a third, analytical phase of the UPSSP. The objectives of this second phase of the project are to:

• Investigate the current status of the Ukrainian power system, including lines, substations and transformers, power plants and generators units , paying specific attention to the network elements in east Ukraine;

• Update the phase one load flow model assumptions and simulation models in response to he current network topology;

• Conduct a load flow study with the updated load flow model;

• Recalculate the hierarchy of remedial actions provided in phase one and identify critical points on the network that require in-depth dynamic stability analysis;

• Based on the updated load flow model, prepare a revised transient stability model (dynamic model) reflecting the current topology of the network to be used in phase three to conduct a dynamic analysis of the network.

To support these objectives the following actions were taken:

5 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report 1. A simulation Base Case load flow model corresponding to the actual Winter 2014/2015 network topology was developed, consisting of the following: a. Current and forecasted status of network elements including lines, substations and transformers, power plants and generators units, with an emphasis on eastern Ukraine; b. Current and forecasted power generation based on the availability of different coal types used to generate electricity in Ukraine; and c. An equivalent of the Russian high voltage network bordering Ukraine.

2. Data needed to update the dynamic model was collected on the following list of network elements: a. Protection system settings; b. Turbine generator regulators for each generating unit in Ukraine; c. Generator voltage regulators for each generating unit in Ukraine; and d. For certain North-Eastern power stations (those affected by damaged parts of the network): i. Generator reactive power limiters ii. Transformer load tap change controls iii. Complex dynamic loads

3. Scenarios for the updated load flow analysis to be conducted in this phase of the UPSSP and for the dynamic stability analysis to be conducted in phase three of the UPSSP were constructed, consisting of the following: a. Topology variation: i. Cases where the Russian electric power network is interconnected with the Ukrainian power network ii. Cases where the Russian power network is disconnected from the Ukrainian power system b. Production variation: i. Cases with minimal estimated production from anthracite fired power plants (given in Base Case model) ii. Cases with no production from anthracite fired power plants

For each scenario, the following analyses and calculations were performed:

• Load Flow analysis with network element loadings for non-contingency status

• Voltage profile analysis of the transmission network for non-contingency status

• Contingency analysis (N-1)

• Recommendations for remedial actions

6 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

The process of collecting model input data, developing the model and verifying its accuracy was completed in cooperation with Ukrenergo and local consultants. The PTI Power System Simulator for Engineers (PSS/E) software package was used as the basis for modelling and analysis.

This report consists of 6 chapters, including this Introduction chapter. Chapter two describes the methodology used to conduct the revised load flow study. Chapter three reports on the study calculations and load flow analysis performed with special reference to phase one of the UPSSP. Chapter 4 describes the input data for dynamic model development, as well as an analysis of the questionnaires used to gather the dynamic data. The main conclusions and findings with next steps are provided in Chapters five. Chapter six provides references and the annex contains supporting material and data.

7 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

2 METHODOLOGY AND APPROACH

8 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

2.1 Power System Analysis and Models

Electric power systems are real-time energy delivery systems. Real time implies that power is generated, transported, and supplied at the exact moment it is called for. Unlike water or natural gas networks, electric power systems cannot store electricity. Generators must produce energy as the demand calls for it.

The power system generally exists in a steady state of equilibrium. While there are constant small changes in load, switching actions on the network, and other transients that occur, these variations are considered very small. As a result, for steady state analysis it is not necessary to analyze the stability of the simulation model over time.

In steady state analysis it is most important to calculate the voltages and currents to which different parts of the network are exposed. This is necessary to ensure that the different power system components such as generators, lines, transformers, shunt elements, etc. can withstand the stress associated with steady state operation without risk of damage to the network. To perform steady state analysis it is necessary to map voltages at each node on the system. Equipped with this information, currents, active and reactive power flows can be calculated. This is the load flow analysis that is performed through a set of nonlinear equations to ensure the system can withstand every day stresses to which it is exposed.

On the other hand, the power system is subjected to a great variety of dynamic behavior. Dynamic phenomena originate from different physical phenomena and occur over different time scales. A system is considered to be in a dynamic state if any time derived system parameter is non-zero. Dynamic stability analysis essentially examines the network’s ability to restore its equilibrium after being subjected to a physical disturbance that knocks it out of its steady state.

Dynamic behavior of the network can result from many different types of disturbances. The phenomena can be local in nature, in which case they affect a small part of the system or a single network component. But, they can also involve interactions between different parts of the system that might be geographically distant from each other. In many cases system-wide interactions are initiated by a local disturbance that can involve many power system components, e.g. generators and loads and other network elements. When this occurs, it can cause system instability that may lead to wide-spread black outs, i.e., interruptions of power supply for many consumers.

All analysis, whether it is for load flow or dynamic studies, begins with formulation of appropriate simulation models. A simulation model (in power system analysis this is a mathematical model), is a set of equations describing the interactions between different quantities of parameters being observed over a specified time frame studied, such that the model is faithful to the behavior of a physical or engineered component or system.

While it is nearly impossible to develop simulation models that can describe all static or dynamic issues in a power system and still be of practical use, today’s modeling software enables modelers to construct very detailed models with ever increasing accuracy.

The models used for this study derive from the regional models developed by the Black Sea Regional Transmission System Planning Project (BSTP) using the PTI PSS/E software platform.

9 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report 2.2 PSS/E Software

The PSS/E package is a set of computer programs designed to handle the basic functions of power system simulation, including: • Data handling, updating, and manipulation • Power Flow calculation • Optimal Power Flow analysis • Fault Analysis • Dynamic Simulations + Extended Term dynamic Simulations • Open network Access and Price calculation • Equivalent Construction

The program employs the latest technology and numerical algorithms to efficiently resolve contingencies identified in large and small networks. It is comprised of the following modules: • PSS/E Power Flow (load flow) • PSS/E Optimal Power Flow (PSS/E OPF) • PSS/E Balanced or Unbalanced Fault Analysis • PSS/E Dynamic Simulation

This software package enables modelling of different network elements, including: substations (SS), overhead lines (OHL), loads (L), generators (G), transformers (TR), fixed shunts (FS), switched shunts (SW), DC links (DC) and FACTS devices (SVCs, STATCOMs,…). PSS/E uses nodal network presentation so that each distribution area is reduced to the supplying substation and its busses within the transmission network.

Figure 2-3 shows a simplified diagram of PSS/E’s modules and data organization. Figure 2-4 shows demonstrates it capacity to model different transmission network elements.

10 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Figure 2-1 – PSS/E software package data and modules organization

Figure 2-2 – Power system elements which could be modelled within PSS/E software package

11 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

As discussed earlier, in the scope of this phase of the UPSSP, only steady state load flow analysis was conducted. Load flow analysis is the basic PSS/E program module (PSS/E interface module) and it is apowerful and easy-to-use for basic power flow network analysis (see Figure 2-5).

Command Buttons

Data Spreadsheet

Single Line Diagram Network Data Tree

Output Window

Figure 2-3 – PSS/E software package interface

The PSS/E interface supports a variety of interactive facilities including: • Introduction, modification and deletion of network data using a spreadsheet • Creation of networks and one-line diagrams • Steady-state analyses (load flow, fault analysis, optimal power flow, etc.) • Presentation of steady-state analysis results.

2.3 Ukraine PSS/E Power System Model Description

The Ukrainian power system models created within the framework of the BSTP include the following (see Figure 3-6): • 750kV, 500kV, 400kV, 330kV, 220kV, 150kV, and 110kV networks • Generator units at their nominal voltage level • Small generator units (mainly CHPPs) are aggregated and directly modelled at the appropriate transmission network voltage level

12 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

• Step-up transformers for the large generation plants • Turbine governors, voltage and other regulators for the large generation units.

Figure 3-4 – Ukraine transmission network

The Ukrainian BSTP models used as the basis for the UPSSP phase one and phase two model updates facilitate the following type of analysis: • Load Flow • Dynamic Stability • Optimal Power Flow

The models contain more than: • 700 connection nodes • 200 power plants generator units • 1200 AC branches including high voltage lines and transformers

13 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

3 LOAD FLOW ANALYSIS

14 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

During the first phase of the UPSSP, we developed a comprehensive collection of data on the operational and technical characteristics of the Ukrainian power system’s facilities for the winter period 2014/2015. Historical data on electricity demand and load distribution characteristics were carefully reviewed and modified to represent the then current situation in the power system.

The first phase of data collection included the following information sent by Ukrenergo: • Technical recommendations for standards of network operation • Generation data on fuel types and limits of units • Power System topology – Substations, transformers, high voltage power lines • Demand and exchanges forecast • Appropriate Russian power system equivalent • Possible operation modes of Odessa region • Simulation models as a final result and main input, based on the BSTP 2015 winter max PSS/E model.

In addition, the Base Case Load Flow Model contained data for energy and power balance from before the escalation of hostilities in east Ukraine. As a result, 2013 was used as the reference. Figure 3-1 shows the structure of installed generation capacity with dispatchable, available and unavailable percentages of installed capacity for the winter peak hour. According to Ukrenergo practice, peak demand is defined as the electricity consumption measured at the 17th hour of the 3rd Wednesday in December (in this case, 2013). Thus, in 2013, for reference winter peak load level, about 50 % of 54.5 GW installed capacity was dispatched and 17% of installed capacity was unavailable due to the reconstruction or conservation.

Figure 3-1 – Ukraine Power System – Electricity Generation Capacity in 2013

Over the course of 2013, the Ukrainian power system produced approximately 193 TWh, with total gross consumption of 187 TWh (Figure 3-2).

15 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Figure 3-2 – Ukraine Power System – Electricity Production and Consumption in 2013

About 46% of electricity was produced from nuclear power plants and 44% from thermal power plants, including gas and coal fuelled generation units.

The largest component of electricity consumption was in industrial sector, which accounted for approximately 36% of all consumption.

Electricity consumption for 2011-2013 years, [GWh]

Type of consumption: 2011 2012 2013 Public utilities 25,872 26,583 20,921 Industrial 73,001 70,761 66,339 Residential 38,460 40,267 41,378 Agricultural 3,548 3,831 3,936 Transport 9,887 9,279 8,690 PPs self-consumption and network losses 36,449 37,218 35,667 Export 6,450 9,752 9,870 Commonly gross consumption + Export 193,667 197,691 186,801

Figure 3-3 – Electricity consumption for 2011-2013 with Load Diagram Curve for 2013

16 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report 3.1 Load Flow Model Developed in 2014 Based on 2013 data

Electricity consumption in the base case developed in the UPSSP phase one as defined based on the measurement for the 17th hour of the 3rd Wednesday in December 2013. This represented the peak demand for the Ukrainian power system. Selecting this hour enabled the use of coincidental data for both internal substations in Ukraine and interconnection lines with neighboring countries. This simulation model, based on a single snapshot reference to the peak demand, was used as the basis for the set of different scenario simulation models.

Hostilities in Ukraine have resulted in a significant reduction in the available sources of primary energy, resulting in several changes to the network over the winter of 2014/2015. Each of these challenges was directly or indirectly incorporated in the scenario simulation models.

Expected peak hour consumption was slightly increased in comparison with the previous year’s values. Household increases in electricity consumption for heating were estimated to be between 15% and 30%. Due to a 50% reduction of industrial consumption in eastern Ukraine, the model did not assume a dramatic increase in overall electricity consumption.

Secondly, considering the actual availability of primary fuel, the model assumed Ukraine could not expect to cover more than 25,000 MW of domestic consumption, even in the optimistic generation scenario. The available installed capacity, in terms of available primary energy taking into account required system reserves, was approximately 26,500 MW. Additionally, the average losses for this regime were estimated to be 700 MW, while programmed and contractually committed exchanges of electricity were modeled at 560 MW. The model considered that worsening supplies of primary fuel could limit electricity production and, hence consumption, to 23,000 MW.

The lack of primary energy affects both power generation and consumption. The shortage of gas increases household consumption for electric heating, but decreases production electricity production from gas fired power plants. At the same time, the lack of anthracite coal (which is primarily mined in the conflict zone) further decreases the production of electricity in during the observed period.

In addition to the aforementioned supply and demand balancing problems, the system was confronted with damaged parts of the network in the conflict zone. While there is little accurate data on the dimensions of the damage, it remained possible to supply these parts of the system, but with technical restrictions limiting supply. A similar situation was found in the Crimean peninsula, where consumption in the model was limited to 600 MW during peak simulation regimes.

The models simulated different possibilities in terms of support from neighboring networks. For example, the simulation models considered the potential for working both with and without IPS/UPS interconnection, either by switching on or switching off all Ukrainian tie lines towards Russia and Belarus. For voltage and reactive power analysis, these scenarios were very important when considering the stability of the eastern Ukrainian grid, because of the of the low production levels of plants in this region.

A second interconnection scenario was constructed to provision of 250 MW of generation capacity 17 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report from Romania. This was found to be infeasible due to a single line interconnection that violates n- 1 security principles and because the location of the interconnection in Romania is characterized by a high degree of wind power plants and a lack of balancing reserves.

By combining assumptions about the availability of primary fuel, generation capacity, load, network topology and interconnections, different simulation scenarios could be created to take into account the potential for as many situations as possible. Figure 2-1 shows a simplified approach for the creation of both the scenarios and models used in this analysis.

Initial model checking Main Assumptions Scenario and model and adjustment creation

•Status of all •Estimated peak from •Topology variation transmission network measurements for •UA with RU elements (lines, 17th 3rd Wednesday •UA without RU transformers, December 2013 •Regional support generation units...) •Minimum level of CHP possibilities •Level of generation production •Option for island operation that depends on coal •Certain PPs in DONBAS of Odesa region with RO type and MD are not available •No option for island •Appropriate equivalent •Certain coal mines in operation of Odesa region of RU power system DONBAS are not with RO and MD available •Production variation •Crimea works syn. with •Coal re-allocation possible UA but with limitation •No possible coal re- allocation •Load variation •Case 1 - with higher load increase •Case 2 - with lower laod increase

Figure 3-4 – Basic assumption and necessary input data in the process of scenario and model creation

Taking into account the system data available from the previous year (for the same period) and the simulation model developed within BSTP, nine scenarios were established and nine simulation models with the following characteristics were created in phase one of the UPSSP:

Topology Possible regional Production variation Consumption variation variation support

Low level of load increase realized by 15% of household consumption increase in total and Scenario 1 50% decrease of industrial and transport Optimistic (high) consumption in industrial areas Ukraine works There are no level of production synchronously regional support based on current High level of load increase realized by 30% of with Russia – all parts of situation household consumption increase in total and Scenario 2 and Belarus Ukrainian power 50% decrease of industrial and transport with 0 system are in consumption in industrial areas programed domestic exchange balance. Pessimistic (low) Low level of load increase realized by 15% of household consumption increase in total and Scenario 3 level of production which means further 50% decrease of industrial and transport 2000 MW decrease consumption in industrial areas

18 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report in anthracite fired High level of load increase realized by 30% of power plants household consumption increase in total and Scenario 4 50% decrease of industrial and transport consumption in industrial areas

Some SSs in Odessa region Optimistic (high) Low level of load increase realized by 15% of work level of production household consumption increase in total and Scenario 5 synchronously based on current 50% decrease of industrial and transport with parts of situation consumption in industrial areas Moldova and Romania

Low level of load increase realized by 15% of household consumption increase in total and Scenario 6 50% decrease of industrial and transport Optimistic (high) consumption in industrial areas level of production based on current High level of load increase realized by 30% of situation There are no household consumption increase in total and Scenario 7 regional support 50% decrease of industrial and transport Ukraine – all parts of consumption in industrial areas switched off Ukrainian power from Russia system are in Low level of load increase realized by 15% of and Belarus domestic household consumption increase in total and Scenario 8 Pessimistic (low) balance. 50% decrease of industrial and transport level of production consumption in industrial areas which means further 2000 MW decrease High level of load increase realized by 30% of in anthracite fired household consumption increase in total and Scenario 9 power plants 50% decrease of industrial and transport consumption in industrial areas

From a power balance perspective, we identified four important scenarios with low and high generation and low and high consumption levels. Figure 3-5 shows their structure in terms of different primary fuel as well as a comparison with the Base Case (December 2013).

19 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Figure 3-5 – Base Case vs. Study High and Low Generation Scenarios and High and Low Load Scenarios

It can be seen that in both cases of load variation (high and low), when taking into account grid losses and programed exports, even in the optimistic generation portfolio scenario, total electricity consumption was greater than expected level of electricity production. These discrepancies suggested a set of remedial actions required to maintain the possible balance between production and consumption.

3.2 Summary Results from 2014 Load Flow Study

Taking into account Ukrenergo’s operational procedures and the results of scenario analyses, the following hierarchy of remedial actions was recommended in the phase one study: • Applying nation-wide load shedding on a proportional basis, including proportional load shedding in the power deficit areas of Donbas, North and Center, in an effort to preserve a constant power factor (ratio between active and reactive power). The objective of this remedial action is to match domestic consumption with production with domestic generation resources without active support from Russia and Belarus, while maintaining a forecasted national power exchange program of 560 MW.

20 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report • After applying nation-wide load shedding, the resulting voltages are observed to be significantly higher. However, if the tie lines to Russia and Belarus are disconnected, voltages were observed to be significantly lower in some parts of the network. To restore equilibrium according to the scenario operational conditions, we recommend adjusting and regulating the voltages by manipulating the transformer ratios. • Depending on the scenario and operations therein, we recommended the strategic use of reactor controls. In certain cases, we recommended that reactors be activated, but in other cases, we found that to be unnecessary. The use of reactor controls was dependent on the specific operational conditions observed in the model. • A fourth remedial action is the use of generator unit output voltage control to restore voltage and reactive power support. This remedial action is limited by the generator reactive power capability curves, the upper and lower limits of which are provided in the standard power system load flow model. • Localized load shedding was recommended to remedy continued disturbances associated with voltage and reactive power when the previously mentioned remedial actions are ineffective.

Using the remedial actions described above, the analysis conducted on the study scenarios revealed the following: • Nation-wide load shedding provided the majority of the benefits associated with restoring system-equilibrium. Roughly estimated, about 24,000 MW of distribution consumption could be supplied with an optimistic forecasted generation and about 22,000 MW in case of a more pessimistic generation forecast.

• Because this year’s total load was significantly reduced compared to the previous year, we didn’t expect to find an overload of the transmission network. Therefore, the contingency analysis (n-1) was mainly focused on the problem of voltage fluctuation. The analysis primarily involved checking the voltage profiles of every voltage level of the transmission network, in particular, all control points related to the stability of the system. Adjustments to the control settings of transformers, reactors, and generators improved voltage conditions under all scenarios following load shedding remedial actions. The 750/330 kV transformers, in coordination with reactors and generator voltage controls, had a significant role in transmission network adjustments in cases where the Ukrainian power system operates without Russia and Belarus. • Any remaining problematic voltage contingencies were considered local disturbances and were managed through additional localized load shedding.

Total generation and consumption balances for the UPSSP phase one scenarios following remedial actions are given below:

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Scenario 1 Scenario Scenario Scenario Scenario Scenario Scenario Scenario Scenario Base with 3 with 5 with 6 with 8 with 2 with 4 with 7 with 9 with Case load load load load load load load load load Zone Load/ shedding shedding shedding shedding shedding shedding shedding shedding shedding Name Gen. P P P P P P P P P P

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) UA- Load 5,604 3,874 3,253 3,925 3,684 3,253 3,701 3,102 3,525 2,969 DONBAS Gen. 6,016 3,556 3,556 3,556 3,556 3,556 3,556 3,556 3,556 3,556 Load 2,838 2,628 2,179 2,665 2,541 2,179 2,524 2,086 2,524 2,086 UA-NORTH Gen. 1,511 565 565 565 565 565 565 565 565 565 Load 6,312 6,459 6,316 6,459 6,459 6,316 6,584 6,441 6,584 6,441 UA-DNIEPR Gen. 7,648 9,244 7,292 9,198 8,894 7,060 9,247 7,288 9,029 7,142 Load 1,178 710 707 707 710 707 713 710 713 710 UA-KRIM Gen. 126 126 126 126 126 126 126 126 126 126 Load 2,338 2,466 2,466 2,466 2,466 2,466 2,595 2,595 2,595 2,595 UA-SOUTH Gen. 3,445 2,424 2,424 2,424 2,424 2,424 2,424 2,424 2,424 2,424 UA- Load 4,595 4,352 3,624 4,413 4,352 3,624 4,203 3,490 4,203 3,490 CENTAR Gen. 2,605 2,135 2,135 2,135 2,135 2,135 2,135 2,135 2,135 2,135 UA- Load 1,749 1,817 1,817 1,817 1,817 1,817 1,911 1,911 1,911 1,911 SOUTHW Gen. 3,966 4,360 4,360 4,360 4,360 4,360 4,360 4,360 4,360 4,360 Load 1,850 1,963 1,963 1,963 1,963 1,963 2,068 2,068 2,068 2,068 UA-WEST Gen. 2,404 2,446 2,446 2,446 2,446 2,446 2,446 2,446 2,446 2,446 Load 952 992 992 992 992 992 1,039 1,039 1,039 1,039 UA-BUISL Gen. 1,412 1,759 1,759 1,749 1,759 1,759 1,809 1,809 1,809 1,809 Load 27,416 25,262 23,317 25,408 24,985 23,317 25,339 23,443 25,163 23,310 UA-TOTAL Gen. 29,133 26,614 24,662 26,558 26,264 24,430 26,667 24,708 26,449 24,562

We found that the most significant problem were reductions in anthracite fuel supply, which we observed created significant voltage instability in the eastern part of the power system when interconnections with Russia were severed in the model. This would occur primarily in conflict zones, where only provisional data on the state of the network is available. Using coordinated dispatch actions, this potential transmission voltage reactive problem was effectively eliminated.

However, a more detailed analysis of the effects of changes in consumption and their impact on voltage requires a dynamic voltage stability analysis.

3.3 Changes Made to the Load Flow Model in Phase II of UPSSP

Selecting the 2014 Peak Load The winter peak 2015 model created in the Black Sea Regional Transmission Planning Project (BSTP) was used as a basis to develop the UPSSP phase one simulation model development. This model was created based on load data measured in the time of winter peak loads of 2013 for the third Wednesday of December 2013, at 17:00 h.

Following the same logic and practice, the updated model for 2015 developed in the second phase of the UPSSP would typically have been based on December 17th, 2014 metering data. However,

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on that day to prevent emergency operating conditions resulting from a deficit of generating capacity a special load shedding scheme was applied to prevent a significant voltage and frequency drop. So, we determined that December 17th, 2014 was not a typical winter peak day to use to calculate the winter peak load. Accordingly, it was decided to use the data from December 30th, 2014 at 17:00 when ambient temperature was -8 °C and the load shedding measures were not applied.

Updating the network topology of east Ukraine Special attention was given to the jeopardized parts of the transmission network in Eastern Ukraine (see Figure 2-2). Due to the continuation of military operations in the Donetsk and Lugansk areas, the number of the damaged 110-500 kV transmissions lines has increased. The following is a list of overhead lines that are in disables status in the simulation model for phase two of the UPSSP:

• OHL 500 kV Donbaska – Peremoha • OHL 500 kV Donbaska – Novodonbaska • OHL 330 kV Slovianska TPP – Zmiivska TPP • OHL 330 kV Slovianska TPP – Kupiansk • OHL 330 kV Kurakhivska TPP – Chaikine # 1 • OHL 330 kV Kurakhivska TPP – Chaikine # 2 • OHL 330 kV Vuhlehirska TPP – Makiivska • OHL 330 kV Vuhlehirska TPP – Mykhailivka 330 • OHL 330 kV Vuhlehirska TPP – Tsentralna # 1 • OHL 330 kV Vuhlehirska TPP – Tsentralna # 2 • OHL 220 kV Novodonbaska – Mykhailivka 330 • OHL 220 kV Chaikine – Novodonbaska • OHL 220 kV Chaikine – Mykhailivka 330 • OHL 220 kV Starobeshivska TPP – Azovska # 1 • OHL 220 kV Starobeshivska TPP – Azovska # 2 • OHL 220 kV Starobeshivska TPP – Azovska # 3 • OHL 220 kV Starobeshivska TPP – Amvrosiivka • OHL 220 kV Mykhailivka – Yuvileina • OHL 220 kV Luhanska TPP – Lysychanska • OHL 220 kV Mykhailivka – Cherkaska – Lysychanska # 1.2 • OHL 220 kV Luhanska TPP – Komunarska # 1 • OHL 220 kV Luhanska TPP – Mykhailivka A • OHL 220 kV Luhanska TPP – Mykhailivka B • OHL 220 kV Slovianska TPP – Lipetsk # 1 • OHL 220 kV Luhanska TPP – Peremoha • OHL 220 kV Luhanska TPP – Peremoha is now reconnected to the 220 kV SS Cherkaska.

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Possible line of damaged Jeopardized part of and disconnected lines and power system substations

Figure 2-6 – Status of transmission network elements in Eastern part of the power system

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The 330 kV OHL Khartsyzka – Zoria is now disconnected in phase two the simulation model. This line was operational in the phase one simulation model, but was damaged in a military operation in January.

It is important to note that compared with the phase one simulation model, the eastern part of the power system is faced with these additional damaged and switched-off lines: • OHL 220 kV Starobeshivska TPP – Azovska # 2 • OHL 220 kV Starobeshivska TPP – Azovska # 3 • OHL 220 kV Starobeshivska TPP – Amvrosiivka • OHL 220 kV Luhanska TPP – Lysychanska

The Chaikine – Khartsyzka #1 OHL line has been restored and is in active status in the phase two simulation model.

The following 110 kV lines were confirmed to be damaged and are in inactive in the updated model:

600010 UKIROV51 600103 ULUTEC51 1 600010 UKIROV51 600117 ULUGAN51 1 600010 UKIROV51 600117 ULUGAN51 2 600010 UKIROV51 600112 UKADIE51 1 600130 USBTEC51 600168 UZUTEC51 1 600137 UENAKI51 600198 UHARCI51 1 600148 UCENTR51 600180 UUGTEC51 1 600149 UCENTR52 600180 UUGTEC51 1 600163 USOLJ151 600176 UJUBIL51 1

As a result of damage to a nearby 110-220 kV substation, the area near the Luganska TPP has been isolated and disconnected from the Ukrainian national power grid. It is operating in island mode in the simulation model. The Luhanska TPP balances the load of the Luhansk, Lysychansk, Mykhailivka and Komunarsk – approximately 260 MW.

Updating the equivalent of Russian high voltage network The equivalent of the Russian high voltage developed in phase one was updated to provide a more detailed network model of IPS Centre and South UDO regions of the Russian transmission network. The more distant parts of the Russian network that influence the behavior of the Ukrainian network remained an equivalent for voltages in the 250-750 kV range.

In the current simulation model, the following cross-border tie-lines to the IPS Centre region of Russia were activated: • OHL 750 kV Kursk NPP – Pivnichnoukrainska • OHL 500 kV Donbaska – Novovoronezhskaya NPP • OHL 330 kV Kursk NPP – Shostka • OHL 330 kV Kursk NPP – Sumy Pivnichna

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• OHL 330 kV Shebekino – Losievo • OHL 330 kV, branch line to Losievo – Bielgorod • OHL 330 kV Zmiivska TPP – Valuiky

The following cross-border tie-lines to the South IPS control region of the Russian network were activated in the phase two simulation model: • OHL 500 kV Peremoha – Shakhty • 220 kV Sysoievo – Velykotsk • 220 kV Amvrosiivka – Taganrog

It is important to note that the OHL 220 kV Luhanska TPP – Sysoievo is not activated in the phase two simulation model. The OHL 330 kV Pivdenna – Rostov is cut on a tower and withdrawn for repairs, and the line from the tower is energized from the Russian 500 kV substation at Rostov.

Updating load level and forecast of load variations The values of power flows recorded on international tie-lines at 17:00 hours on December 30th, 2014 are as follows:

Burshtyn TPP Island 310 MW Poland 0 MW Moldova 37 MW Belarus 71 MW Centre IPS -305 MW South UDO -533 MW

These data were used to build the load forecast for the Ukrainian model. According to the forecasted power balance for the winter 2015 for average daily temperatures in the range of -10 – -15 °C, the peak load should be 28,000 MW.

The increased load (as compared to the load forecast in the phase one model) results from power import contracts with Russia enabling Ukraine to import up to 1,500 MW. As a result, Ukraine no longer limits power consumption in Crimea and Sevastopol. In the phase one model, these regions were limited to a combined 600 MW due to a generation capacity deficit. Based on the data of the actual operational conditions in the Ukrainian power system on 30.12.2014 and projected data from Phase I of UPSSP, we were able to forecast new loads for each load center in Ukraine and incorporate them into the phase two model.

Updating fuel supply From November 2014 – January 2015 Ukraine experienced a rapid deterioration in the fuel supply to thermal power plants. The table below shows a comparison of coal stocks in TPP’s storages for 23.10.2014 and 15.01.2015:

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Stocks as of Stocks as of 15.01.15, TPP +/– 23.10.14, thsd tons. thsd tons. Luhanska TPP 11.86 51.91 40.05 Starobeshivska TPP 37.6 125.85 88.25 Slovianska TPP 43.15 15.24 -27.91 Vuhlehirska TPP* 39.33 71.66 32.33 Kurakhivska TPP 377.84 252.52 -125.32 Zuivska TPP 25.47 59.51 34.04 Prydniprovska TPP 28.55 9.31 -19.24 Kryvorizka TPP 79.34 16.14 -63.2 Zaporizka TPP 123.55 109.61 -13.94 Zmiivska TPP 17.7 10.35 -7.35 Trypilska TPP 16.92 9.81 -7.11 Ladyzhynska TPP 224.02 124.99 -99.03 Dobrotvirska TPP 97.85 42.65 -55.2 Burshtynska TPP 380.99 194.21 -186.78 * supply of fuel for TPPs is complicated due to damage of driveways, TPPs, using the coals of G, DG brands TPPs, using the coals of A brand TPPs, located in the occupied territories

The main reasons for the decline in coal supply is the termination of anthracite supplied from mines located in the occupied territory and a deteriorating logistical infrastructure to transport coal produced in that region. Anthracite is currently imported from the Republic of South Africa and the Russian Federation. Import from South Africa is limited by the turnover capacity of the seaport infrastructure and the significant distance between South Africa and Ukraine. Imports from the Russian Federation are complicated by vague an opaque business practices resulting in significant delivery delays.

As a result, anthracite fired power plants are functioning at minimal power output to provide heat to the surrounding areas.

We have incorporated significant reductions in the coal stockpiles for other types of coals use by Ukrainian thermal power plants: G and DG coal. This occurs because plants employing these coals are working at maximum capacity to make up for the lost generation capacity in eastern Ukraine. Like plants using anthracite, the plants using D and DG coal are unable to sources from east Ukraine. Nevertheless, we model them at full production levels.

The situation in east Ukraine is volatile. The coal supply to plants in this region continues to be be difficult. In particular, the supply of fuel to the Zuivska and Starobeshivska plants may be terminated at any time, even though there has been a significant increase in the stockpile at these power plants. Currently, during peak hours, these TPPs are working with a total capacity of 1100 MW. With the ambient temperature decreasing, we expect the load to increase in the Eastern part of the Donbas power system. Accordingly, the production of these power plants may be required to top 1500 MW.

Deliveries of coal to the Luhanska and Vuhlehirska TPPs are also complicated. Access roads to the plants are periodically damaged by artillery fire (particularly bridges).

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Thus, the Luhanska TPP has been relegated to island mode of operation in reality and in the simulation model.

Forecast of generation level Based on fuel availability, it is possible to make the following assumptions about power plant generation. Because the supply of anthracite is possible only through imports, it will be insufficient to meet generation requirements to serve load. Anthracite fuelled power plants are anticipated to work at a minimum production level. The capacity of the CHP plants will be determined by the mode of operation for thermal energy.

Name of TPP Estimated capacity of TPP Luhanska TPP (2 units) 280 Starobeshivska TPP (5 units) 950 Slovianska TPP (0.5 units) 35 Prydniprovska TPP (2 units) 270 Kryvorizka TPP (2 units) 564 Zmiivska TPP (2 units) 350 Trypilska TPP (2 units) 530 Darnytska CHP 160 Myronivska CHP 63 Chernihivska CHP 150 Sumska CHP 50 Kramatorska CHP 119 Eskhar CHP 100

The production level of TPPs using G and DG coal ocated outside the conflict zone are modeld at maximum generation capacity after taking into account their reserve requirements.

Name of TPP Estimated capacity of TPP Kurakhivska TPP (5 units) 1050 Vuhlehirska TPP (3 units) 840 Zaporizka TPP (4 units) 1220 Zuivska TPP (2 units) 420 Ladyzhynska TPP (6 units) 1620 Dobrotvirska TPP 511 Burshtynska TPP (units will be switched 360 to the IPS of Ukraine)

We assumed CHPs will operated based on the thermal load of municipal heating systems. Based on forecasted of temperatures, the power of CHPs during peak load operating conditions are modeled as follow:

Name of CHP Plant generating capacity, MW Kyivska CHP-5 400 Kyivska CHP-6 400 Kharkivska CHP-5 400

The forecast for the operation of the nuclear fleet is in accord with the Schedule of NPP Equipment Repairs developed by NNEGC "Energoatom" (the operator of nuclear power plants of Ukraine) and approved by Ukrenergo.

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Unit capacity of nuclear Total capacity of NPP, NPP Number of units units, MW MW ZNPP 4 1000 5280 1 730 1 550 RNPP 2 1000 2420 1 420 YuUNPP 2 1000 2000 KhNPP 2 1000 2000

Accordingly we have modeled 13 units with a total generating capacity of 11,700 MW (two units will be under according to the plan).

In developing the hydropower plant production forecast, we took into account the current deficit of water resources in the Dnieper cascade during this season of low water storage (below 50% of normal). Generation of HPPs 1800 MW Generation of PSPPs 1100 MW

Finally, we incorporated miscellaneous generation capacity, including local generating plants and small CHPs plants with a total capacity of 1700 MW, as well as wind power plants with a capacity of 100 MW.

Updating Power exchange programs The electricity export for the period January-February of 2015 is forecasted in the model as follows:

• To Belarus = 0 • To Europe, at night = 650 MW; evening on-peak load = 350 MW (from Burstyn) • To Moldova = 0 • To Poland = 0

3.4 Updated Load Flow Analysis Results

Based on the forecasted situation in the Ukraine power system discussed above and building on the base case model from phase one, the corresponding phase two models were developed through the following procedure:

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• Updating Winter 2014/2015 Ukraine Power System Analysis Study model - Base Case is used as starting model Step 1 •Input data collection for model adjustment

•Checking of model elements status taking into account current situation (generator units, substations with Step 2 transformer units, lines, shunts, etc.)

•Preparation of current demand portfolio taking into account consumption structure, existing load schedding portfolito and mesured peak level in December 2014. Step 3 •Preparation of appropriate current generation portfolio •Draft model creation from starting models and collected input data

•Adjusted simulation model (Draft Model) checking Step 4

•Previously created simulation model (Draft Model) upgrading according to the main assumptions (forecast of load variations, PP's fuel supply issues, forecast of generation level, Crimea works synchronously with Ukraine - suspended limitation on power supply, allowed import from Russia up to 1500 MW) Step 5 •Russian power system equivalent model updating •Updating of regional power balances

•Adjusted simulation model with incorporated previous assumptions (Base Case Model) checking Step 6

•Scenario models creation taking into account different asspect which could be analyzed (varition of Step 7 generation - anthracite PP's out of operation, variation on topology - operation without Russia)

The updated phase two Base Case model was used to analyze the following scenarios: • Scenario 1 – disconnection of Russian power system from synchronous operation with Ukraine (consequentially it leads to disconnection of Belarus); • Scenario 2 – no generation from remaining anthracite power plants; • Scenario 3 – the worst case scenario with separation of Russian and Ukrainian power system and no generation from remaining anthracite power plants. These scenarios cover a wide enough range of potential situations in the Ukrainian power system conditions during the observed period (winter 2014/2015). Moreover, they are a framework for identifying potential critical points from a voltage and reactive power perspective. We performed a classic steady state analysis on these scenarios in a manner similar to the analysis conducted in phase one of the UPSSP.

3.4.1 Steady State Analyses performed

Load flow analysis Load flow analysis was used to check the security margins of the network. The Load flow analyses included: • Power flows for transmission network elements (including transmission lines and transformers)

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• Voltage profile and reactive power analyses • Regional power flows • Power flows at Ukraine’s borders • Security analyses (contingency (n-1) analysis) Special attention was paid to the permissible voltage levels in normal and emergency operational conditions to take into account the reactive power needs in the damaged parts of the ransmission network created by a lack of generation capacity. Security criteria The network model was checked with respect to its security criteria. The security assessment analyzed the system’s behavior after being subjected to disturbances in the model, including the loss of HV and EHV overhead line outages and transformers: 700/x, 500/x, 400/x, 330/x, 220/x outages.

Violation of security limits can occur on internal lines or on the tie lines between between neighboring countries. The upper acceptable limits for the loading of the network elements used in our analysis were:

• Current rating (Imax) for transmission lines (in Amps)

• Nominal apparent power (Snom) for the transformers (in MVA)

According to Ukrenergo’s operational practice (obtained in response to our data Questionnaire), these limits can be extended if reasonable preventive and fast post-event measures can be taken by the system operator of the network affected by the contingency, i.e., meshing of lower voltage network, generation restrictions and re-dispatching) for: • A short-time (less than 1 hour) when the overload of overhead lines is 20% • A short-time (less than 1 hour) whent the overload of transformers is 40%

These values may be reconsidered depending on the condition of the equipment.

The (n-1) security check was completed for outages of the following branches: • Interconnection lines in the region; • 220 kV and higher voltage level lines in Ukraine and neighboring power systems; • All transformers with voltage levels between 750 kV – 110 kV in Ukraine • All 110 kV and 154 kV lines in Ukraine

The analysis of the voltage profile in Ukraine takes into account voltage limits based on Ukrenergo’s practices and standards (received in response to Questionnaire):

Classification Nominal voltage (kV) Minimal voltage (kV) Maximum voltage (kV) 750 - 787.5 Ultra-high voltage 500 - 525 (UHVTL) 330 297 363

31 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report High voltage 220 198 252 (HVTL) 154 138.6 169.4 110 99 121

The following elements were monitored: • All Ukraine tie lines; • 220 kV and higher voltage lines in Ukraine, as well as 400 kV and higher in neighboring power systems; • All transformers with voltage levels between 750 kV – 110 kV in Ukraine • All 110 kV and 154 kV lines in Ukraine

When examining the static stability of the network, special attention was devoted to both minimal and emergency voltage levels in specified control points (minimum level is defined for 20% of static stability reserve):

Substation name Nominal voltage (kV) Minimal voltage (kV) Emergency voltage (kV) Luganska TPP 220 225 210 Uglegirska TPP 330 330 310 Harciskaya TPP 330 330 310 Kremenchukska HPP 330 320 310 Krivorozhska TPP 330 330 310 Zaporozhska TPP 330 330 310 Zaporozhska NPP 750 720 700 Zmievska TPP 330 325 315 Tripolska TPP 330 335 315 Ladzhinska TPP 330 335 315 Hmeljnicka NPP 330 335 315 Burshtinska TPP 330 335 315 Yuzhnoukrainska NPP 330 335 315 PS Dzankoy 330 315 285

The following limits were used to determine overloads of the monitored elements: • 100% of the imposed current limit [A] for the transmission lines • 100% of the Snom [MVA] for the transformers

3.4.2 Scenario Models Description and Possible Remedial Actions

Based on the scenarios developed above and the Ukrenergo operational procedures used in the steady state analysis, we chose to employ the same regime of remedial actions as were specified in UPSSP phase one to our analysis: • National-wide load shedding on a proportional basis, including proportional load shedding in the power deficit areas of Donbas, North and Center. The objective of this remedial action is to match domestic consumption with production from domestic generation resources if possible. Due to continuous and non-limited supply of Crimea, additionally active support from Russia is available up to 1500 MW hourly. Forecasted national power 32 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report exchange program that considers export is related to Burshtin Island. That available power (see Base Case Exchanges see chapter 3.3) is isolated from the rest of Ukraine power system with no operating mutual transmission lines. • The voltages can be significantly higher after the load decreases, taking into account the typical transformer tap ratio winter control, which considers high level of consumption. At the same time, if the tie lines to Russia and Belarus were switched off, voltages could be significantly lower in some parts of the network. In order to adjust the voltages to scenario operational conditions, it was necessary to regulate the voltages using transformer ratio manipulation. • With the same aim, it is necessary to strategically use reactors control. In some cases, reactors should be activated, but in other cases, they are unnecessary. This depends on specific conditions in each scenario. • Another possibility in terms of voltage and reactive power support is generator units output voltage control. This option is only limited by active generator reactive power capability curves, which are indirectly limited by upper and lower limits given within the standard power system load flow model. Dynamic analyses may temporarily extend these limits according to machines capabilities in transient regimes to keep system stability through disturbance events. • Last of all, in order to ensure stabile operational conditions while considering disturbances associated with voltage-reactive power control, it is necessary to utilize precise local consumption decreasing or to involve local additional reactive power support (realized by possible installation of appropriate compensation devices). This will be analyze in more detail within next stage. The model scenarios (taking into account generation levels and the status of interconnections) are the Base Case 2014/2015; Scenario 1; Scenario 2; and Scenario 3. The following table shows the forecasted generation level in comparison with realized situation in normal operational conditions for 2013 for the same observed peak hour:

Model Pgen (MW) Base Case 2013 29,133 Base Case 2014/2015 27,811 Scenario 1 27,887 Scenario 2 25,248 Scenario 3 25,161

For each scenario, including the updated Base Case (winter 2014/2015), the starting forecasted consumption level was approximately 28,000 MW, which account for losses of approximately 800 MW and planned imports of 200 MW (export of 300 MW towards ENTSO-e and import of 500 MW from Russia). The remedial actions, such as they are prescribed below, are intended to establish power system balance. It should be noted that the Donbas region works in island operation with self-covered power balance of a 250 MW in the UPSSP phase two model.

3.4.3 Load Flow Analysis with Basic Load Shedding Remedial Actions

Ukraine’s power system consists of seven regional control zones with the following share of total consumption under normal operational conditions: 33 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report • Centar 17% • Dniepr 23% • Donbas 20% • Krim 4% • South 9% • South-West 6% • West 7% • North 10%

Half of Ukraine’s total consumption is concentrated in the North and North-East of the country (Center, North and Donbas), where there is a higher population density, a concentration of energy intensive industry, and a concentration of anthracite fired power plants. As a result, these are most affected by the load shedding remedial actions, but only for scenarios where there is no production from anthracite fueled power plants (Scenario 2 and Scenario 3). In case of Scenario 1 (disconnection from Russian power system), there is no need for such operations because a significant part of the Ukrainian transmission network effectively becomes island supplied from Russia in the amount of 500 MW (which is the same exchange amount assumed in the Base Case). As a result, the total power balance of Ukraine power system would remain the same.

The following maps and accompanying explanations provide an overall perspective of the wide area power exchanges assumed in different study scenarios.

Figure 4-1 shows a comparison between the Base Case from the UPSSP phase one and the current Base Case for UPSSP phase two in terms of zone and area power exchanges. It is evident that in normal operational conditions the Ukrainian power system was an electricity exporter of approximately 1000 MW in the peak hour. However, this year the situation has reversed itself due to the hostilities in eastern Ukraine. Ukraine must import at least 500 MW from neighboring systems in order to cover peak demand. The biggest changes are in the North, Central and Donbas zones. Conversely, the Dnieper zone has become a significant surplus zone, as the large NPPs located there are maximizing their production.

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Figure 4-7 – Area and zone power exchanges for Base Case 2013 (normal operation conditions) and actual Base Case

Figure 4-2 illustrates the moment of disconnection from the Russian power system (Scenario 1). In this case, approximately 500 MW of demand in the Donbas region is assumed to be covered from the Russian power system in island mode.

However, the lack of anthracite production in Scenario 2 significantly alters the generation portfolio in the North, Dnieper and Donbas zones. This results in a production decrease of 2900 MW, which could only partially be mitigated by 1500 MW of contracted imports from Russia during peak hours. The situation and zone power exchanges for this scenario are given in Figure 4-3. In this study case Ukraine would require an additional 1000 MW of capacity. As a result, to maintain system equilibrium approximately 1400 MW of load shedding must be applied.

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Figure 4-8 – Area and zone power exchanges for Scenario 1 and actual Base Case

Figure 4-9 – Area and zone power exchanges for Scenario 2 and actual Base Case

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The most critical study case assumed a simultaneous complete reduction of anthracite production and a disconnection from the Russian power system. This is an extreme situation and could result in both power balance instability and a but also very close to voltage collapse. To avoid this from occurring, Ukraine peak consumption would have to decrease by 2400 MW (Figure 4-4).

Figure 4-10 – Area and zone power exchanges for Scenario 3 and actual Base Case

The Base Case and Scenario 2 consider active interconnections between Ukraine, Russia and Belarus. However, disconnection from these lines (Scenario 1 and Scenario 3) could result in voltage-reactive problems, particularly in the generation deficit areas, which would be affected by a decline in reactive power.

The Base Case and Scenario 1 maintain stability with no need for load shedding actions. In contrast to this, Scenario 2 and Scenario 3 require significant load shedding to reduce peak demand and preserve system stability.

Table 4.1 presents the total electricity consumption reduction at the distribution level resulting from the recommended load shedding remedial actions. The biggest decrease is provided in Scenario 3, with a 10% reduction in total and almost a 20% reduction in major deficit areas. Assuming the per capital consumption of electricity in Ukraine is 670 MW/capita, this equates to approximately 4 million consumers without electricity or, approximately 1.3 million households. The lowest decrease (with the exception of Scenario 1 where there is no load reduction) occurs in Scenario 2, with approximately a 6% reduction in total and approximately a 13% reduction in major deficit areas.

37 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Roughly estimated, about 27,000 MW of distribution consumption could be supplied with an optimistic forecasted generation (Base Case and Scenario 1) and about 24,500 MW in case of a more pessimistic generation forecast (Scenario 3).

Table 4.1 – Total zone consumption before (Base Case for winter 2014/2015) and after load shedding remedial actions for all scenarios (Scenario 1, 2 and 3) Base Case Base Case Scenario 1 2014/2015 Scenario 2 2014/2015 Scenario 3 2014/2015 2013 2014/2015 Zone Load/ Name Gen. P P P Load shedding P Load shedding P Load shedding No of No of No of (MW) (MW) (MW) (MW) (%) (MW) (MW) (%) (MW) (MW) (%) Consumers Consumers Consumers Load 5,604 4,163 4,163 0 0 0.0% 3,647 516 771,225 12.4% 3,375 789 1,178,070 18.9% UA-DONBAS Gen. 6,016 3,843 3,843 2,880 2,870 Load 2,838 2,877 2,877 0 0 0.0% 2,478 399 595,260 13.9% 2,226 651 972,880 22.6% UA-NORTH Gen. 1,511 993 993 643 643 Load 6,312 6,486 6,486 0 0 0.0% 6,427 59 88,131 0.9% 6,427 59 88,131 0.9% UA-DNIEPR Gen. 7,648 8,585 8,662 7,866 7,788 Load 1,178 937 937 0 0 0.0% 937 0 0 0.0% 937 0 0 0.0% UA-KRIM Gen. 126 158 158 158 158 Load 2,338 2,290 2,290 0 0 0.0% 2,290 0 0 0.0% 2,290 0 0 0.0% UA-SOUTH Gen. 3,445 2,436 2,436 2,436 2,436 Load 4,595 4,993 4,993 0 0 0.0% 4,317 676 1,009,925 13.5% 3,883 1,110 1,658,512 22.2% UA-CENTAR Gen. 2,605 2,499 2,499 1,969 1,969 Load 1,749 2,030 2,030 0 0 0.0% 2,030 0 0 0.0% 2,030 0 0 0.0% UA-SOUTHW Gen. 3,966 4,639 4,639 4,639 4,639 Load 1,850 2,374 2,374 0 0 0.0% 2,374 0 0 0.0% 2,374 0 0 0.0% UA-WEST Gen. 2,404 3,320 3,320 3,320 3,320 Load 952 996 996 0 0 0.0% 996 0 0 0.0% 996 0 0 0.0% UA-BUISL Gen. 1,412 1,338 1,338 1,338 1,338 Load 27,416 27,147 27,147 0 0 0.0% 25,497 1,650 2,464,541 6.1% 24,537 2,609 3,897,594 9.6% UA-TOTAL Gen. 29,133 27,811 27,887 25,248 25,161

3.4.4 Voltage Profile and Contingency Analysis (N-1) with Additional Remedial Actions

We do not foresee a network overload occurring as this year’s total load is significantly reduced when compared to the load of previous years. Parts of the system in the eastern regions have are significantly degraded as a result of hostilities. This has altered the structure and operation of the local transmission network. Though reliable information on the degree of degradation is difficult to obtain from one day to the next, the influence of system degradation can be measured indirectly by the behavior of nodes in the surrounding area. Taking into account the lack of reactive power production, the condition of damanged networks in east Ukraine and the for the IPS/UPS to disconnect from Ukraine, our contingency analysis focused primarily on the problem of voltage fluctuation. This involved checking the voltage profiles of every voltage level of the transmission network, in particular, all control points related to the stability of the system.

The authorized voltage limits for control nodes are described in section 3.4.1. The voltage fluctuation for the control nodes was analyzed following a simulated load reduction for each of the of the outages defined by the standard contingency list for the transmission network (given in 3.4.1). 38 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Accordingly, (n-1) contingency analysis was performed for all 14 control buses within each scenario. The voltage value was recorded and drawn for each of the control points for each of the outages in the contingency list. A comprehensive analysis was conducted in to identify critical contingencies and control points within the jeopardized power system.

To improve voltage conditions after implementing wide area load shedding, next set of remedial actions were considered. This consisted of resetting transformer, reactor, and generator settings. The new settings were not the result of an optimization process as is typically the case for transmission networks. They are simply the minimum changes required to stabilize the network from the voltage-reactive perspective.

Most of the changes were made on the 330/x and 220/x kV transformers that are closest to modelled consumption. The balance of the changes were made to the 750/330 kV transformers which possess the capability to control voltage ratio and angles simultaneously.

Adjusting generator voltage settings was the final remedial action to be considered to restore desirable voltages at the control nodes. This provided a certain reactive power security margin.

Figure 4-18 through Figure 4-29 provide the voltage fluctuation for all of the chosen control nodes within each scenario, and for every contingency, taking into account the authorized voltage control limits. To achieve a satisfactory voltage profile for all control nodes, each of the above mentioned remedial actions were applied to the simulation model.

Problems arose primarily for the Krivorozhje TPP, the Zmyivska TPP and the Trypilskaya TPP control nodes (see Figure 4-23, Figure 4-25 and Figure 4-26). Their voltages were significantly below the authorized limits before remedial actions for a significant number of contingencies in almost all of the scenarios. This was particularly evident in the most sensitive scenarios (Scenario 2 and Scenario 3) for the Krivorozhje TPP and Trypilskaya TPP. For all of the scenarios the Zmiyivska TPP control point demonstrated voltages below authorized limits. To achieve a minimum level of stability, for the most critical case, roughly 100-150 Mvar of localized reactive power is required (Situations with and without compensation as well as additional load shedding actions in order to stabilize voltages are given in next section).

We verified that as in the UPSSP phase one findings, reductions in anthracite fueled electricity production could create voltage instability in the eastern part of the power system when interconnections with Russia are severed. A more precise analysis dedicated to the voltage stability issues could not be covered by this type of analysis. It is possible only to identify critical control points (in this case Zmiyivska TPP 330 kV) and roughly estimate the size of compensation required by the region. To more deeply analyze this and to determine whether compensation is necessary, in which amount and where it should be located, requires a more detailed dynamic simulation model.

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42 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

3.4.5 Local Remedial Actions & Power System Devices to Resolve Localized Problems

The Zmyivska TPP 330 kV control point was previously identified as the most critical node from a voltage/reactive power perspective. This is because of its location within the Ukrainian power system (see Figure 4-29) and because it uses anthracite coal to produce electricity. The simultaneous effects of disconnecting tie-lines with Russia and the lack of fuel lead to a significant voltage sag in this control point (below authorized limits of 325 kV for normal operation and 315 kV in emergency cases).

Russian power system

Zmyivska TPP 330 kV control node

Figure 4-25 – 330 kV control node Zmyivska TPP

In normal operational conditions during the winter peak hour (December 2013), the Zmyivska TPP worked with approximately 1330 MW of active power output and maintained voltage at the 330 kV bus at 340 kV. For 2014/2015 winter peak Base Case Model, we observed this plant was giving 350 MW of active power and maintaining the authorized voltage levels on the 330 kV in control node. In Scenario 2 we observed that wide area load shedding provided positive results, bringing the voltage to slightly above authorized limits (328 kV). This was to be expected bearing in mind that Scenario 2 provides for interconnections with Russia, which we observed provides reactive power for this region.

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In Scenarios 1 and 3 the voltage was significantly below 325 kV. To recover voltages in these critical scenarios after exhausting the complete hierarchy of remedial actions, we recommend the following options: • Apply additional localized load shedding until the voltages are within the authorized limit • Install compensation devices

In Scenario 1 we observed it was necessary to further decrease load by 140 MW within this region or to install approximately 150 Mvar of compensation devices. On the other hand for Scenario 3 we observed it would be necessary to shed only 50 MW of consumption in local areas or to install approximately compensation devices with 50 Mvar of capacity. It can be seen that situation in Scenario 3 is, we can say, three times better than in Scenario 1. However, this is reasonable taking into account that Scenario 3 already had global load shedding and its starting voltage conditions were much better.

This steady state analysis provides tentative conclusions regarding voltage and reactive power. It cannot provide precise results regarding the place and level of the actions discussed above. Answers to these questions will be provided in phase three of the UPSSP when a detailed dynamic network is performed.

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4 DYNAMIC STABILITY MODEL DEVELOPMENT

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4.1 Introduction to Dynamic models

A dynamic model simulates the behavior of a power system over a specified period of time. It is used when the behavior of the power system is described as a set of states that occur in a defined sequence in reaction to a disturbance in the system. A system is considered in a dynamic state if the time derivative of any system parameter is non-zero.

Dynamic simulation and analysis of power systems are necessary for both planning and operation. Dynamic analysis requires an appropriate mathematical model of the system that includes many inter-related linear/nonlinear differential and algebraic equations as well as appropriate sets of power system model data to perform such mathematical calculations.

Dynamic analysis of system security determines the robustness of the power system relative to prospective disturbances. There are two important components of security analysis. When a power system is subjected to changes (small or large), it is important that the system settles to a new equilibrium. In the process of doing so, system elements must survive the transition process.

This highlights two aspects of security analysis (Figure 4-1): • Static security analysis—this involves steady-state analysis of post-disturbance system conditions to verify that no equipment ratings and voltage constraints are violated. • Dynamic security analysis—this involves examining different categories of system stability, including: rotor angle stability, frequency stability, voltage stability.

Flow on power Line 1 Flow on power Line 2 Flow on power Line 3 Flow on power Line 4 Flow on power Line 5 Power Flow (MW) Power

Time (seconds)

Steady State 1 Event – Disturbance (fault) Steady State n Static analysis – Load Flow t=0sec Dynamic analysis t=x sec Static analysis – Load Flow t=0sec

Figure 4-1 – Characterization of steady state and dynamic analysis regarding the time frame and states – output of dynamic analyses

Dynamic stability analysis is an integral component of system security and reliability assessment.

46 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report The most commonly used definition of stability is the following:

Power system stability is the ability of an electric power system, for a given initial operating condition, to regain a state of operating equilibrium after being subjected to a physical disturbance, with most system variables bounded so that practically the entire system remains intact.

4.2 Updating Ukraine BSTP dynamic model

The primary purpose of the dynamic model of Ukraine developed through the BSTP is to observe dynamic network behavior on a regional level. Often, one develops a model particularly suited to the investigation at hand. Depending on the purpose of the study the appropriate model of a power system component can vary significantly. The level of detail included in a model is dependent on what the model is intended for. The granularity of the BSTP dynamic model is not suitable for the detailed observations required for the UPSSP. As a result, the BSTP model must be updated with additional detailed data.

For the purpose of the UPSSP, the updated dynamic model will be used to investigate the security weak points in the Ukrainian power system identified during the load flow analyses in phases one and two. The updated dynamic model will support the following analyses in phase three: • Steady State Stability analyses of Ukraine Power System - investigates the ability of the system to bring itself back to its stable configuration following a small disturbance in the network (normal load fluctuation or in response to the action of an automatic voltage regulator). This will be considered for a very gradual and infinitesimally small power change. Should the power flow through the circuit exceed the maximum power permissible by specifications and network standards, there is a chance that generators or a particular group of generators will cease to operate synchronously, resulting in additional disturbances. In such a situation, the steady state limit of the system is said to have been reached.

• Transient Stability analyses of Ukraine Power System - investigates the ability of the system to reach a stable condition following a large disturbance in the network condition. In all cases related to large changes in the system such as the sudden application or removal of load, switching operations, line faults loss due to excitation, observing the transient stability of the system becomes essential. Such analysis is used to ensure synchronism following a disturbance over a relatively long period of time.

• Dynamic Stability analyses of Ukraine Power System – investigates the potential to artificial restore stability unstable system by automated controls. This generally examines small disturbances lasting from about 10 to 30 seconds.

For this analysis, we focused on updating power system elements that were not obtained within the BSTP dynamic model, which instead relied on generic data. Working with Ukrenergo, we examined and verified the dynamic model settings for the following network elements: • Generators • Exciters • Turbines

47 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

• Power system stabilizers • Load • Protective devices and protective schemes

During next phase of the UPSSP, which will focus on dynamic analysis, we will fine tune the excitation system models and their accompanying power system stabilizers. Detailed dynamic analysis will show whether is necessary to create user defined models or keep solutions with combinations of standard exciters and power system stabilizer models. We also intend to check and verify the small power plants modelled on the lowest transmission network voltage level and determine whether it is necessary to model them as a negative load or as an equivalent machine with generic model including inertia.

The models developed in this current phase of the UPSSP will provide detailed system data to perform the system security analyses referenced above within the bounds of the current network topology. It will enable observation of voltage stability in the northern parts of the system during system disturbances, outage of the principal generators units within the whole system, protection device activity and the effects of load shedding schemes.

4.2.1 Updating Ukraine BSTP dynamic load model

Limited anthracite coal supply has resulted in minimum operating levels of thermal power plants fueled by anthracite. The analyses in Phase I and Phase II identified weakened area in north- eastern part of the Ukrainian power system where we observed potential for voltage instability. One of the main issues associated with dynamic analyses of voltage instability is developing an accurate model of the system load. In standard dynamic analyses PSS/E represents load in a static manner, where all active power is represented as constant current and all reactive power as constant impedance. This gives unified characteristics of all loads (Figure 4-2) within the system.

Active (P) load charteristic in PSSE

Reactive (Q) load charteristic in PSSE

Figure 4-2 – Active and reactive load characteristic in function of system voltage

48 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

This representation of load is simplified and inadequate. Detailed local analyses demand accurate and detailed representation of the loads of various types of consumer equiopment drawing power from the system, such as motors, pumps, lightning, heating, electronic devices, etc., each with their individual characteristics. A model that represents a complex load in the PSS/E stability program is designated as the CLOD(BL) model. It includes aggregated dynamic models of large and small motors, a non-linear model of discharge lighting, transformer saturation effects, constant MVA, shunt capacitors, and other static load characteristics, as well as series impedance and tap ratio to represent the effect of intervening sub transmission and distribution elements (Figure 4-3).

The CLOD(BL) model represents the load as an aggregation of the following five submodels: • Induction motors: Labeled Large Motors and Small Motors, these two submodels are each characterized by typical torque-speed, current-speed, and power factor-speed curves. • Discharge lighting: For voltages above 0.75 pu, the real power is modeled as constant current, and the imaginary as exponential with an exponent of 4.5. As voltage decreases below 0.75 pu, both P and Q drop linearly until the light is completely extinguished below 0.65 pu voltage. • Transformer losses: These are further divided into core losses (saturation) and copper losses (R+jX)/P0. Transformer losses may be neglected since they are relatively insignificant. • Constant MVA: Constant real and reactive power consumption. • Remaining loads: The real power is modeled as constant current (KP =1) and the imaginary power as constant impedance. This is abbreviated as PI/QZ.

Figure 4-3 – Load structure that is enabled using CLOD dynamic load model

The first step in developing detailed load profiles is to break utility loads into the following four distinct customer classes: residential, agricultural, commercial, and industrial. Furthermore, for each of these customer classes, the load is broken into the six different categories. Percentages of load are then assigned to each category (Table 4.1). This table provides load values for the winter period only, as the structure of load does changes with the seasons.

49 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Table 4-1 – Load characteristics and customer class for northern zone of Ukrainian transmission network, winter 2014 - 2015 Ukraine WINTER load characteristics Percentage of: XFMR Discharge KP of Large Motor Small Motor Constant Power Remaining KP typical range Customer Class: Saturation lightning Remaining Residential 0 44.4 1 3.7 4.1 46.8 1.5 0.9 to 1.7 Agriculture 5 30 1 20 4.5 39.5 1 Commercial 0 36.7 1 31.5 4.5 26.3 0.6 0.5 to 0.8 Industrial 65 15 1 10 5 4 1 0.1 to 1.8 Poltavska 34.60 28.00 1.00 9.10 4.60 22.74 1.17 Sumska 26.50 31.60 1.00 8.90 4.50 27.56 1.21 Harkivska 16.30 35.90 1.00 9.00 4.40 33.39 1.25 Power Factor [%] 88.7 82 0 92.8 90 Calculated IEEE '93

The next step is to allocate customer classes for each load to substations within northern zone. This distribution is presented in (Figure 4-3).

50 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report Table 4-2 – Load characteristics and customer class customer class for each load in substations within northern zone of Ukrainian transmission network, winter 2014 - 2015

PSS % transformer % discharge KP of BUS NAME kV ID PSS Type % large motor % small motor % constant power MODEL Comment NODE exciting current lighting Remaining UZMTZST1 15.8 609201 1 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZALJUG1 10 609231 1 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZMTZSTA 20 609210 10 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZALJUG2 10 609232 2 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZMTZST3 15.8 609203 3 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZALJUG3 20 609233 3 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZMTZST5 15.8 609205 5 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZMTZST6 15.8 609206 6 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZMTZST7 20 609207 7 Industrial 65 15 1 10 5 1 CLODBL Generator Load UZMTZS51 110 600200 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UZMTZS52 110 600202 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UGRAKO51 110 600203 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UARTE151 110 600205 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UZALJU52 110 600207 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UARTMA51 110 600208 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution ULOSEV52 110 600210 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UVASTO51 110 600212 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UKANAT51 110 600215 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution UKURIL51 110 600217 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UKREME31 150 600219 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution UPOLTA51 110 600220 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution USUMI151 110 600222 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution USOSTK51 110 600223 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution ULAZAV51 110 600224 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UTROJC51 110 600225 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UPM_SE51 110 600227 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UKUPJA52 110 600229 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution ULOZ_R51 110 600230 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UKAZ_L51 110 600233 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UIPZ1 51 110 600234 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UGREBE51 110 600235 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution UKRMTC31 150 600236 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution UZALJU51 110 600237 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UBUKIN51 110 600238 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UESHAR51 110 600239 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UMIRGO51 110 600244 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution ULOSEV51 110 600246 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution USUMIS51 110 600248 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution UKUPJA51 110 600249 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UBALAK51 110 600250 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UCIGAN51 110 600251 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UKRJUK31 150 600256 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution UBARVE51 110 600257 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UJAZIK51 110 600258 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UPREDD51 110 600259 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UVOLCA51 110 600261 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution UPIRJA51 110 600262 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution UOBOLO31 150 600263 1 Poltavska 34.6 28 1 9.1 4.6 1.17 CLODBL Distribution UTERES51 110 600264 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution USOSTT51 110 600265 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution UPOMNJ51 110 600266 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution US_BUD51 110 600267 1 Sumska 26.5 31.6 1 8.9 4.5 1.21 CLODBL Distribution UGABRI52 110 600268 1 Harkivska 16.3 35.9 1 9 4.4 1.25 CLODBL Distribution

4.3 Ukraine dynamic model

Here, we provide a brief description of the updated dynamic model of the Ukrainian power system. A power system consists of many different types of elements. Some of these are purely passive, like resistances, capacitances and inductances and others, like rotating machines (generators) are highly complex, dynamic, and controlled devices. The updated dynamic model of the Ukrainian power system includes models for the following network elements: • Generator data • Excitation system data • Turbine and governor data Stabilizer model data

51 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

• Protective relay data • Load model data

This data set is recorded in the PSS/E format - *.dyr file. This file contains the data used by the mathematical model of each element of power system used in the mathematical calculations. The dynamic Data file must correspond to the load flow model in terms of element numeration.

The per unit system is generally assumed to be used for expressing voltages, currents, power and impedances. We considered only balanced (symmetrical) operation of the power systems. Single- line diagrams were used to describe the three-phase systems.

The following table summarizes models used from the PSS/E library for each element in the Ukrainian power system.

Table 4-3 – Summary of models used to represent dynamics of Ukrainian power system, winter 2014 - 2015 Element of Power PSSE Librady No. Of Units/Elements System model name GENROU 118 Generator GENCLS 78 ESST1A 3 ESAC4A 8 Exciter EXPIC1 86 EXAC4 55 URST5T 44 WSHYGP 45 WSIEG1 77 Turbine Governor IEEEG3 33 TGOV 41 Stabilizer IEEEST 55 LVSHBL 53 Relay elements LDSHBL 336

4.3.1 Generator models

The PSS/E library includes a family of generator models that allows generator rotor effects to be modeled in different levels of detail depending upon study requirements, availability of data, and users’ preferences. There are two types of generator models used in the dynamic model of the Ukrainian power system. These are GENSAL, GENROU.

GENSAL – is the salient pole detailed dynamic model (hydro power plant) of a machine at the subtransient level.

52 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 4.274 T´do (>0) (sec) J+1 0.0713 T''do (>0) (sec) J+2 0.123 T''qo (>0) (sec) J+3 3.7 H, Inertia J+4 0 D, Speed damping J+5 0.644 Xd J+6 0.454 Xq J+7 0.287 X´d J+8 0.2 X''d = X''q J+9 0.124 Xl J+10 0.03 S(1.0) J+11 0.25 S(1.2)

DYRE DYNAMIC DATA FORMAT: 609004 'GENSAL' H4 4.274 0.0713 0.123 3.7 0 0.644 0.454 0.287 0.2 0.124 0.03 0.25 /

Figure 4-4 – GENSAL model of salient pole synchronous generator, representative data

GENROU - represents solid rotor generators at the subtransient level (thermal power plants turbogenerators)

MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 6.85 T´do (>0) (sec) J+1 0.21 T''do (>0) (sec) J+2 2 T'qo (>0) (sec) J+3 0.42 T''qo (>0) (sec) J+4 3.17 H, Inertia J+5 0 D, Speed damping J+6 1.845 Xd J+7 1.8 Xq J+8 0.295 X´d J+9 0.59 X´q J+10 0.19 X''d = X''q J+11 0.156 Xl J+12 0.1 S(1.0) J+13 0.3 S(1.2)

DYRE DYNAMIC DATA FORMAT: 609108 'GENROU' 8 6.85 0.21 2 0.42 3.17 0 1.845 1.8 0.295 0.59 0.19 0.156 0.1 0.3 /

Figure 4-5 – GENROU model of round rotor synchronous generator, representative data

4.3.2 Exciter models

URST5T - static excitation system for presenting UNITROL (ABB).

53 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report - MATHEMATICAL DIAGRAM/PSSE LIBRARY

PSSE DYNAMIC DATA CONs Value Description J 4.274 Tr (sec) J+1 0.0713 TC1 (sec) J+2 0.123 TB1 (sec) J+3 3.7 TC2 (sec) DYRE DYNAMIC DATA FORMAT: J+4 0 TB2 (sec) J+5 0.644 KR 609001 'URST5T' H1 0.02 0.5 10 J+6 0.454 VRMAX 0.02 0.0155 500 3.5 -2.2 0.02 J+7 0.287 VRMIN 0.40000E-01/ J+8 0.2 T1 J+9 0.124 KC

Figure 4-6 – URST5T model of IEEE type ST5B Excitation System, representative data

ESST1A – is a model of a potential source controlled rectifier-exciter excitation system intended to represent systems in which excitation power is supplied through a transformer from the generator terminals and is regulated by a controlled rectifier. The maximum exciter voltage available from such systems is directly related to the generator terminal voltage. In this type of system, the inherent exciter time constants are very small and exciter stabilization as such is normally not required.

CONs Value Description MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA J 0.047 TR (sec) J+1 10 VIMAX J+2 -10 VIMIN J+3 0.097 TC (sec) J+4 0.039 TB (sec) J+5 0 TC1 (sec) J+6 0 TB1 (sec) J+7 50 KA J+8 0.04 TA (sec) J+9 20 VAMAX J+10 -20 VAMIN J+11 7.9 VRMAX J+12 -6.32 VRMIN J+13 0.05 KC DYRE DYNAMIC DATA FORMAT: J+14 0 KF J+15 0.001 TF > 0 (sec) 09185 'ESST1A' 5 1 2 0.047 10 J+16 0 KLR -10 0.097 0.039 0 0 50 0.04 20 -20 7.9 J+17 0 ILR -6.32 0.05 0 0.001 0 0 /

Figure 4-7 – ESST1A model of IEEE Type ST1A Excitation System, representative data

Models EXAC4 and ESAC4A emulate an alternator-supplied rectifier excitation system. This high initial response excitation system utilizes a full thyristor bridge in the exciter output circuit and the voltage regulator operates directly on these elements. The exciter alternator uses an independent voltage regulator to control its output voltage to a constant value.

54 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 0.04 TR J+1 0.1 VIMAX J+2 -0.1 VIMIN J+3 0.5 TC J+4 1.5 TB (sec) J+5 50 KA J+6 0.02 TA DYRE DYNAMIC DATA FORMAT: J+7 5.2 VRMAX 609311 'GENROU' 1 8.8 0.031 2 0.07 6 0 2.35 J+8 -5.2 VRMIN 2.24 0.452 0.904 0.321 0.24 0.1 0.5 / J+9 0.05 KC

Figure 4-8 – EXAC4 model of IEEE Type AC4 Excitation System, representative data

MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 0.04 TR J+1 0.1 VIMAX J+2 -0.1 VIMIN J+3 0.5 TC J+4 1.5 TB (sec) J+5 50 KA DYRE DYNAMIC DATA FORMAT: J+6 0.02 TA J+7 5.2 VRMAX 609047 'ESAC4A' E3 0.04 0.1 -0.1 0.5 1.5 50 0.02 5.2 -5.2 J+8 -5.2 VRMIN J+9 0.05 KC

Figure 4-9 – ESAC4A model of IEEE Type AC4A Excitation System, representative data

EXPIC1 is recommended to be used for excitation systems where voltage regulator control element is a proportional plus integral type (PI). A specific excitation system was not used as a starting point. Judicious choice of constants can allow this model to be used to model a variety of manufacturers’ implementation of a PI type exciter.

55 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 0 TR (sec) J+1 0.01 KA J+2 2000 TA1 (sec) J+3 20 VR1 J+4 -20 VR2 J+5 0.04 TA2 (sec) J+6 0 TA3 (sec) J+7 0 TA4 (sec) J+8 10 VRMAX J+9 -10 VRMIN J+10 0 KF J+11 1 TF1 (>0) (sec) J+12 0 TF2 (sec) J+13 5.16 EFDMAX J+14 -4.128 EFDMIN J+15 1 KE DYRE DYNAMIC DATA FORMAT: J+16 0.04 TE (sec) J+17 0 E1 609005 'EXPIC1' H5 0 0.01 2000 20 -20 0.04 0 0 10 J+18 0 SE1 J+19 0 E2 -10 0 1 0 5.16 -4.128 1 0.04 0 J+20 0 SE2 J+21 1 KP 0 0 0 1 1.806 0 0.0000 J+22 1.806 KI 0.46000 0.10000 1.0000 0.0000 2.3000 0.10000 3.1000 0.33000 /

Figure 4-10 – EXPIC1 model of IEEE Type DC1A Excitation System, representative data

4.3.3 Turbine and Governor Models

Model WSHYGP is a special model required for hydro units. It is a double derivative hydro governor. The WSHYGP represents the old WSCC GP governor plus turbine model. A proportional, integral derivative controller is modeled in WSHYGP.

MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 0 db1 J+1 0 err J+2 0 Td (sec) J+3 0.08 KI J+4 1 Tf (sec) J+5 0 KD J+6 0.9 KP J+7 0.02 R J+8 0 Tt J+9 1 KG J+10 0.5 TP (sec) J+11 0.046 VELOPEN (>0) J+12 0.062 VELCLOSE (>0) J+13 1 PMAX J+14 0.172 PMIN J+15 0 db2 J+16 0 GV1 J+17 0 PGV1 J+18 1 GV2 J+19 1 PGV2 J+20 1 GV3 J+21 1 PGV3 J+22 1 GV4 DYRE DYNAMIC DATA FORMAT: J+23 1 PGV4 609001 'WSHYGP' H1 0 0 0 0.08 1 0 J+24 1 GV5 J+25 1 PGV5 0.9 0.02 0 1 0.5 0.046 0.062 1 0.172 J+26 -0.86 Aturb 0 0 0 1 1 11 1 1 1 J+27 0.5 Bturb (> 0) 1 -0.86 0.5 2.89 58.5 / 0 J+28 2.89 Tturb (sec) J+29 58.5 Trate Figure 4-11 – WSHYGP model of WECC GP Hydro Governor Plus Turbine, representative data

56 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

TGOV1 is a simple model representing governor action and the reheater time constant effect for a steam turbine. The ratio, T2/T3, equals the fraction of turbine power that is developed by the high-pressure turbine. T3 is the reheater time constant, and T1 is the governor time constant.

MATHEMATICAL DIAGRAM/PSSE LIBRARY

PSSE DYNAMIC DATA CONs Value Description J 0.04 R J+1 0.01 T1 (>0) (sec) J+2 0.904 VMAX J+3 0.565 VMIN J+4 3 T2 (sec) J+5 9 T3 (>0) (sec) DYRE DYNAMIC DATA FORMAT: J+6 0 Dt 09185 'TGOV1' 5 0.04 0.01 0.904 0.565 3 9 0 /

Figure 4-12 – TGOV1 model of Steam Turbine-Governor, representative data

WSIEG1 models the IEEE-recommended general model for steam turbine speed governing systems (IEEEG1) with some nonlinearities. By the appropriate choice of parameters, this model can be used to represent a variety of steam turbine systems including non-reheat, tandem compound, and cross compound types. IEEEG1 can also approximate the behavior of hydro turbine-governors.

MATHEMATICAL DIAGRAM/PSSE LIBRARY PSSE DYNAMIC DATA CONs Value Description J 20 K J+1 0.1 T1 (sec) J+2 0 T2 (sec) J+3 0.3 T3(> 0) (sec) J+4 0.05 Uo J+5 -0.05 Uc (< 0) J+6 0.854 PMAX J+7 0.427 PMIN J+8 0.3 T4 (sec) J+9 0.3 K1 J+10 0 K2 J+11 7 T5 (sec) J+12 0.4 K3 J+13 0 K4 J+14 0.5 T6 (sec) J+15 0.3 K5 J+16 0 K6 J+17 0 T7 (sec) J+18 0 K7 J+19 0 K8 J+20 0.002 db1 DYRE DYNAMIC DATA FORMAT: J+21 0 err J+22 0 db2 609108 'WSIEG1' 8 0 0 20 0.1 J+23 0 GV1 0 0.3 0.05 -0.05 0.854 J+24 0 PGV1 J+25 1 GV2 0.427 0.3 0.3 0 7 J+26 1 PGV2 0.4 0 0.5 0.3 0 J+27 1 GV3 0 0 0 0.002 0 J+28 1 PGV3 0 0 0 1 1 J+29 1 GV4 1 1 1 1 1 J+30 1 PGV4 1 0 / J+31 1 GV5 J+32 1 PGV5 J+33 0 IBLOCK

57 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report Figure 4-13 – WSIEG1 model of WECC Modified IEEE Type 1 Speed-Governing Model, representative data

IEEEG3 are alternative representations of hydro turbine speed governing systems. In some cases, where data may be more easily obtainable for these representations or because they are more exact, these representations may be preferred over that of IEEEG1.

MATHEMATICAL DIAGRAM/PSSE LIBRARY

PSSE DYNAMIC DATA

CONs Value Description J 0.5 TG, (>0) (sec), gate servomotor time constant J+1 0.04 TP (>0) (sec), pilot value time constant J+2 0.05 Uo (pu per sec), opening gate rate limit J+3 -0.05 Uc (pu per sec), closing gate rate limit (< 0) J+4 0.86 PMAX maximum gate position (pu on machine MVA rating) DYRE DYNAMIC DATA FORMAT: J+5 0.073 PMIN minimum gate position (pu on machine MVA rating) J+6 0.05 σ, permanent speed droop coefficient 609011 'IEEEG3' H1 0.5 0.04 0.05 J+7 1.88 δ, transient speed droop coefficient -0.05 0.86 0.073 0.05 1.88 20.7 J+8 20.7 TR, (>0) (sec) 4.14 0.5 1 1.575 1.05/ J+9 4.14 TW (>0) (sec), water starting time J+10 0.5 a11 (>0) J+11 1 a13 J+12 1.575 a21 J+13 1.05 a23 (>0)

Figure 4-14 – IEEEG3 Type 3 Speed-Governing Model, representative data

4.3.4 Stabilizer model

IEEEST - Supplementary Excitation Controller Model with high transient gain and small time constants tend to reduce the damping of generator rotor angle oscillations. This negative damping effect can be counteracted by making the excitation system respond to rotor angle motion as well as deviations of terminal voltage under transient conditions, while being sensitive only to terminal voltage in the steady state.

58 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report MATHEMATICAL DIAGRAM/PSSE LIBRARY

PSSE DYNAMIC DATA

CONs Value Description J 0 A1 J+1 0 A2 J+2 0 A3 J+3 0 A4 J+4 0 A5 J+5 0 A6 J+6 0 T1 (sec) J+7 0.05 T2 (sec) DYRE DYNAMIC DATA FORMAT: J+8 0 T3 (sec) J+9 0 T4 (sec) 609127 'IEEEST' 7 2 0 0 0 J+10 0.02 T5 (sec) 0 0 0 0 0 J+11 0.02 T6 (sec) 0.05 0 0 0.02 0.02 J+12 100 KS 100 0.05 -0.05 0 0 / J+13 0.05 LSMAX J+14 -0.05 LSMIN J+15 0 VCU (pu) (if equal zero, ignored) J+16 0 VCL (pu) (if equal zero, ignored.)

Figure 4-15 – IEEEST Stabilizing Model, representative data

4.3.5 Relay elements

The LVSHBL type undervoltage load shedding relay model represent a solid-state type load- shedding relay that disconnect load based on low voltage. The model has three stages. The fractions of load to be shed are specified in CON(J+2), CON(J+5) and CON(J+8) given in relative units where 100% load is 1. Respectively there are three stages defined with voltage values when load shed is applied CON (J+3), CON (J+6), CON (J+9). Undervoltage load shed schemes are developed within the system locally, therefore are applied to the area of interest – Northern region of Ukrainian power system.

DYRE DYNAMIC DATA FORMAT: PSSE DYNAMIC DATA CONs Value Description 609210 'LVSHBL' 10 0 0.88 J 0.88 V1, first load shedding point (pu) 4 0.1 0.85 0.25 0.2 J+1 4 T1, first point pickup time (sec) 0.8 0.22 0.3 0.1 / J+2 0.1 F1, first fraction of load to be shed J+3 0.85 V2, second load shedding point (pu) J+4 0.25 T2, second fraction pickup time (sec) J+5 0.2 F2, second fraction of load to be shed J+6 0.8 V3, third load shedding point (pu) J+7 0.22 T3, third point pickup time (sec) J+8 0.3 F3, third fraction of load to be shed J+9 0.1 TB, breaker time (sec)

Figure 4-16 – Undervoltage Load Shedding Model, representative data

The LDSHBL type model represent solid-state type load-shedding underfrequency relay. The models disconnect a fraction of the load at which the model is applied when frequency falls below each of its pickup points. The load to be shed at each of three steps is specified in CON(J+2), CON(J+5), and CON(J+8) as a fraction of the original load. Each of the above loads is reduced to a fraction of its original value, with the fraction being equal to the value specified for the stage, as 59 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report corrected to account for load already shed in the prior stage. For example, if the three load- shedding stages are set to shed 0.3, 0.3, and 0.2 per-unit of the original load. The principle is very same to previously described undervoltage relay, the most significant difference is that these relays are set globally in whole power system.

DYRE DYNAMIC DATA FORMAT: PSSE DYNAMIC DATA

600001 'LDSHBL' 1 0 49.7 20 0.1 49.2 5 0.15 49 0.3 0.15 0.1 /

Figure 4-17 – Underfrequency Load Shedding Model, representative data

4.3.6 Load model

CLOD is a complex load model that enables us to model large and small motors, discharge lightning, transformer losses, household consumers and electronic devices. Detailed explanation of complex load is given in chapter 4.2.1.

DYRE DYNAMIC DATA FORMAT: PSSE DYNAMIC DATA CONs Value Description 609201 'CLODBL' 1 65 15 1 J 0 % large motor 10 5 1 0 1.00E-02 / J+1 0 % small motor J+2 0 % transformer exciting current J+3 0 % discharge lighting J+4 0 % constant power J+5 1 KP of remaining J+6 0 Branch R (pu on load MW base) J+7 0.01 Branch X (pu on load MW base)

Figure 4-18 – CLOD Load model, representative element

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5 CONCLUSIONS AND NEXT STEPS 61 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

The current status of the Ukrainian power system is characterized by a significant reduction in the available sources of primary energy and locally, by significant damage to parts of the transmission network. In this environment, the UPSSP is provides analytical support to mitigate these circumstances.

The first phase of the project was an emergency study to analyze power system stability in response to curtailed gas and coal fueled electric power generation and expected increased electricity consumption resulting from switching to electrical heat. In addition we analyzed potential regional support possibilities and coal resource re-allocation for different power plant generation portfolios.

The results of the UPSSP first phase were: • Established an emergency study methodology to deal with the current situation within the power system; • Developed simulation scenarios to cover a wide range of potential power system conditions; • Developed a hierarchy of remedial actions including global and local load shedding necessary to keep the system in balance; • Conducted load flow analysis on 9 different scenarios plus a Base Case reference model (based on normal operation conditions of Ukraine power system in December 2013) which considered different variations of generation, demand, network topology and possible regional support.

We found there is a very strong influence of the generation portfolio, network topology and interconnection status of the IPS/UPS synchronous zone in relation to voltage stability, particularly in the North-Eastern regions of Ukraine.

We found that in the scenario with minimal production from anthracite units, the maximum level of peak demand that could be supplied reliably from domestic resources is approximately 23,000 MW, out of generation capacity of 24,500 MW. We also, found there was no possibility to obtain support from ENTSO-E through the Romanian power system.

We identified critical weak points in the network where voltage stability is a challenge. We found that more detailed dynamic analysis of the effects of changes in consumption and their impact on voltage requires a dynamic voltage stability analysis.

We determined that for these points the second phase of UPSSP should analyze the potential for new specific power system equipment and devices to preserve power system stability. In doing so, we reaffirmed the importance of the dynamic stability analysis requiring an updated dynamic model.

In phase two of the UPSSP, we developed three scenarios to further examine the critical stability points from the voltage/reactive perspective based on new updated Base Case model for winter peak hour 2014/2015 there are defined 3 simulation scenarios:

62 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

• Scenario 1 – disconnection of Russian power system from synchronous operation with Ukraine (consequentially it leads to disconnection of Belarus); • Scenario 2 – no generation from remaining anthracite power plants; • Scenario 3 – the worst case scenario with separation of Russian and Ukrainian power system and no generation from remaining anthracite power plants.

These scenarios were used to describe a wide range of potential conditions in the Ukrainian power system during the winter 2014/2015 period. For each scenario, including an updated Base Case (winter 2014/2015), the starting forecasted consumption level was about 28,000 MW, which included losses in supply of approximately 800 MW and planned imports of 200 MW (export of 300 MW to ENTSO-E and import of 500 MW from Russia). We assumed the Donbas region worked in island operation and covered its own load of 250 MW. We conducted a classic load flow analysis for each scenario.

The table below presents the total electricity consumption reduction at the distribution level as a result of recommended load shedding remedial actions taken from the load flow analysis:

Zone Load/ Base Case Base Case Scenario 1 Scenario 2 Scenario 3 Name Gen. 2013 2014/2015 2014/2015 2014/2015 2014/2015 P P P P P (MW) (MW) (MW) (MW) (MW)

UA- Load 5,604 4,163 4,163 3,647 3,375 DONBAS Gen. 6,016 3,843 3,843 2,880 2,870

Load 2,838 2,877 2,877 2,478 2,226 UA-NORTH Gen. 1,511 993 993 643 643

Load 6,312 6,486 6,486 6,427 6,427 UA-DNIEPR Gen. 7,648 8,585 8,662 7,866 7,788

Load 1,178 937 937 937 937 UA-KRIM Gen. 126 158 158 158 158

Load 2,338 2,290 2,290 2,290 2,290 UA-SOUTH Gen. 3,445 2,436 2,436 2,436 2,436

UA- Load 4,595 4,993 4,993 4,317 3,883 CENTAR Gen. 2,605 2,499 2,499 1,969 1,969

UA- Load 1,749 2,030 2,030 2,030 2,030 SOUTHW Gen. 3,966 4,639 4,639 4,639 4,639

Load 1,850 2,374 2,374 2,374 2,374 UA-WEST Gen. 2,404 3,320 3,320 3,320 3,320

Load 952 996 996 996 996 UA-BUISL Gen. 1,412 1,338 1,338 1,338 1,338

63 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report Load 27,416 27,147 27,147 25,497 24,537 UA-TOTAL Gen. 29,133 27,811 27,887 25,248 25,161

The largest load shed was recommended for Scenario 3, with a 10% reduction in total and almost a 20% reduction in major deficit areas. The lowest decrease (with the exception of Scenario 1 where no load reduction was required) was for Scenario 2, with approximately a 6% reduction in total and approximately a 13% reduction in major deficit areas. Approximately 27,000 MW of distribution consumption could be supplied with an optimistic forecasted generation (Base Case and Scenario 1) and about 24,500 MW in case of a more pessimistic generation forecast (Scenario 3).

We reset the voltage settings of the transformers, reactors and generators within the simulation model as the next step within the hierarchy of remedial actions. The new settings were not the result of an optimization process, but represented the minimum changes required to stabilize the network from the voltage-reactive power perspective.

Continued problems were observed for all control nodes, but the problems were especially evident in the control nodes at the Krivorozhje TPP, Zmyivska TPP and Trypilskaya TPP, where voltages were significantly below the permissible limits for a significant number of contingencies in almost all scenarios.

For almost all scenarios Zmiyivska TPP control point showed an inadequate voltage fluctuation (voltage below authorized limits). To achieve a minimum level of stability, roughly 100-150 Mvar of additional reactive power was necessary in that region.

Reductions in anthracite fuel generation could create voltage instability in the North-Eastern part of the power system when interconnections with Russia are severed. However, to deeply examine this issue and to define whether compensation devices are necessary and in which amount and where they should be located, a more detailed, dynamic simulation model is necessary.

This current phase two of the UPSSP supports development of a dynamic model to conduct a more detailed stability analysis in phase three. Due to its complexity the development of the dynamic model was divided into two stages: • Stage 1 – Dynamic stability data collection, scenarios and load flow models preparation and steady state calculation and analysis • Stage 2 – Dynamic stability model fine tuning, calculation and analysis

The dynamic model for Ukraine created for the BSTP was suitable for regional analyses, but lacked sufficient detail for localized analysis. In this phase of the UPSSP we moved from the regional BSTP approach to local observability. Accordingly, we updated and upgraded the BSTP dynamic model, such that it is now suitable for local observation within the Ukrainian power network.

64 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

The updated dynamic model will be used to investigate the dynamic security of weak points in the Ukrainian power system identified in the load flow analyses in Phase I and the updated analysis conducted in this phase.

The update of dynamic model during the UPSSP phase two involved following: 1. Collecting necessary input data for dynamic stability model development; 2. Verifying data and by rechecking the folloiwing: a. Data on protection system settings for the Ukrainian transmission network which are regulated with Special emergency procedure guidelines. These procedure include activation of undervoltage protection locally in cases of voltage instability. At the system level, frequency protection relays are set across the entire network to react in cases of active power imbalances. Both undervoltage and underfrequency protective relays are set to operate in several stages depending on system conditions. b. Data on turbine generator regulators for each generation are described with four turbine generator types included in PSS/E library. c. Defining individual sets of data for generators corresponding to two PSS/E library models. The first is salient pole detailed dynamic model (hydro power plant) of a machine at the subtransient level and second is solid rotor generator represent at the subtransient level (thermal power plants turbogenerators). d. Data on generator voltage regulators for each generation unit in Ukraine together with exciter types. All exciters are defined with five distinctive types of voltage regulators. e. For certain North-Eastern power stations (mostly affected by damaged parts of the network): i. Data on generator reactive power limiters; ii. Data on transformer load tap change controls showed that within the Ukrainian power system there are no on-load tap changer transformers that operate in automatic mode. Therefore the updated dynamic model does not include on- load tap changer transformer models.

3. Advanced load modeling was introduced to Ukrenergo. Specific local analyses demand adequate representation of various load types such as motors, pumps, lightning, heating, electronic devices, etc. with their individual characteristic. The standard static load model, where all active power is represented only as constant current and all reactive power as constant impedance, was replaced with a complex dynamic load model. This complex – CLOD model was developed particularly for the Northern region for further dynamic analyses of voltage instability.

65 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

Further steps The detailed dynamic model developed in this second phase of the UPSSP provides sufficient data to perform all necessary system security analyses - steady state stability, transient stability and dynamic stability analyses considering present conditions of Ukraine Power System.

In the UPSSP phase three, the upated dynamic model will enable the following analyses: • observation of voltage stability in northern parts of the system during the disturbances, • outage of main production units within the whole system, • in general capability of the system to maintain stability for each type of disturbance, • protection device activity and • effects of load shedding schemes • compensation devices sizing and placing.

66 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

6 REFERENCES

67 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

[1] “UCTE Operation Handbook”; UCTE; 2011. [2] “Power plant engineering”; A.K. Raja, A.P. Srivastava, M.Dwivedi; New Age International (P) Ltd., Publishers; 2006 [3] “PSS/E 33.5.2 Documentation”, PTI-Siemens, May 2011 [4] “Power System Stability and Control”, P. S. Kundur, McGraw Hill Inc., New York 1994. [5] “Annual Energy Outlook 2013”; Energy Information Administration; April 2013 [6] “Black Sea Regional Transmission Planning Project Phase III - PSSE/OPF Regional Model Construction Report”; USEA; September 2012 [7] Ukraine – Country analysis note; EIA; March 2014

68 Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report ANNEXES

Ukraine Power System Support Project/Проект поддержки энергосистемы Украины Winter 2014/2015 Ukraine Power System Dynamic Model Development – Questionnaire 1 / Зима 2014/2015 Динамическая Модель Украинской энергосистемы This questionnaire is structurally divided into several parts that cover different aspects of both, dynamic model development and envisaged analysis input data collection. Its main purpose is to be used as good foundation for basic simulation model’s establishment, in first step, and afterwards to develop appropriate scenario models according to ToR. Complete questionnaire material consists of this word document with questions and their clarifications, and Annex which includes appropriate sav, dyr and xls files. Word document covers the following issues: Этот вопросник структурно разделён на несколько частей, которые покрывают разные аспекты обеих моделей, разработку динамической модели и предусмотренный сбор данных для проведения анализа. Главной целью является использование его в качестве фундамента для создания базовой имитационной модели на первом этапе с последующей разработкой адекватных сценарных моделей согласно ТЗ. Полный вопросник состоит из данного документа в формате word с вопросами и пояснениями и приложения, которое включает адекватные sav, dyr и xls файлы. Документ в формате word содержит следующее:

• Existing Reactive Power Compensation Devices connected to the Ukrainian transmission network – overview of existing compensation devices in terms of their location, technology, manufacturer, size and year of installation. • Существующие устройства компенсации реактивной мощности, подсоединённые к Украинской системе электропередачи – обзор существующих компенсирующих устройств по их расположению, технологии, производителю, размеру и году установки • Load Flow Model updating – in order to refine and update the 2014/2015 Load Flow Model developed in Phase I of the UPSSP (given by sav file in Annex) to reflect the network topology and actual data for electricity consumption at various load centres based on the snapshot hour for the 3rd Wednesday in December 2014 at 17:00. This practically means updating the following data: • Обновление модели потокораспределения – с целью обновления и актуализации 2014/2015 Модели потокораспределения, разработанной на Фазе I проекта UPSSP (приводится в sav. Файле в Приложении) для отражения топологии сети и актуальных сведений электропотребления по различным центрам нагрузки согласно замеру, проведённому в 17:00 часов 3-ей среды декабря 2014 г.: o Generation – with aim to give actual and expected status of power plants in Ukraine power system in terms of realized (possible) power production in specific representative hour in the observed period. o Генерация – с целью получения актуального и предполагаемого статуса электростанций в Украинской энергосистеме в отношении реального (возможного) производства электроэнергии в определённое замерное время в рассматриваемый период

lxix Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report o Substations and transformers – necessary for actual and expected status of these elements within the transmission network including actual and expected protection settings if any. o Подстанции и трансформаторы – необходимо для актуального и ожидаемого статуса этих элементов сети электропередачи включая существующие и ожидаемые установки, если они предусматриваются o Load – gives review of the actual (if any) and expected load shedding schemes as well as estimation of the most critical and representative load snapshot hour during the observed period taking into account possible variation (if any). o Нагрузка – даёт обзор существующих (если есть) и ожидаемых схем аварийного отключения нагрузки наряду с оценкой наиболее критичных и представление результатов замерного часа за рассматриваемый период, с учётом возможных вариантов (при их наличии) o Lines – necessary for actual and expected status of these elements within the transmission network including actual and expected protection settings if any. o Линии – необходимо для существующего и предполагаемого статуса этих элементов сети электропередачи, включая существующую и предполагаемую установку защитного оборудования при его наличии o Exchanges – necessary for actual and expected status of tie lines including protection settings (if any) as well as actual and expected exchange programs between power systems in the region. o Обмен – необходим для существующего и предполагаемого статуса линий, включая установленную защиту (ели есть) наряду с существующими и предполагаемыми программами обмена между энергосистемами в регионе o Russian power system equivalent – updating of actual and expected behaviour of neighbouring system taking into account previously defined power exchange programs. o Эквивален Российской энергосистемы – обновление существующей и предполагаемой работы соседней системы с учётом ранее определённых программ энергообмена All of above mentioned should be given in both, appropriate PSS/E load flow model format (sav file) and filled in Excel sheets from Annex. Всё выше упомянутое должно быть представлено в обеих, соответствующих моделях потокораспределения PSS/E (sav file) и заполненных таблицах формата Excel Приложения • Dynamic Model Development – based on the updated 2014/2015 Load Flow Model, refine the existing BSTP Dynamic Stability Model (given in dyr file within Annex) which practically means updating and adding the following data: • Разработка динамической модели – на основе обновленной модели 2014/2015 потокораспределения актуализировать существующую Модель динамической стабильности, разработанную в рамках проекта BSTP (предоставляется в формате dyr файла Приложение), что практически означает обновление и добавление следующих данных: o Turbine generator regulators – reviewing and updating of both, modelled regulator types and appropriate parameter values. o Регуляторы турбин генераторов – актуализация и обновление обеих, моделирование типов регуляторов и соответствующее значение параметров o Generator voltage regulators (including Power System Stabilizers (if any)) – reviewing and updating of both, modelled regulator types and appropriate parameter values.

lxx Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report o Регуляторы напряжение генераторов (включая энергосистемные стабилизаторы (при их наличии) – рассмотрение и обновление обеих, моделирование типов регуляторов и соответствующее значение параметров o Models for additional generation plant equipment – different devices necessary for local dynamic stability analysis, such as reactive power limiters and similar (if any). o Модели для дополнительного оборудования генерирующих станций – для проведения анализа локальной динамической стабильности необходимы различные устройства, такие как ограничитель реактивной мощности и другие подобные им устройства (если они необходимы) o Models for on-load tap changer controls – important for dynamic stability analysis in general. o Модели для управления изменения напряжения на выходе трансформатора под нагрузкой – в целом важные для анализа динамической стабильности o Models for complex dynamic loads – necessary for local dynamic stability analysis. o Модели комплексных динамический нагрузок – необходимые для анализа местной динамической стабильности As already mentioned, Questionnaire Annex consists of PSS/E sav file as 2014/2015 Load Flow Model developed in Phase I of the UPSSP, dyr file as dynamic part of planning model for BSTP 2015 winter max regime and corresponding xls file. On the other hand this xls file contains the following sheets:

Как отмечалось ранее Приложение к Вопроснику состоит из фала PSS/E sav как в модели потокораспределения нагрузки 2014/2015, разработанной в Фазе I программы UPSSP, файла dyr как динамической части модели BSTP 2015 зимнего максимума и соответствующего файла xls . С другой стороны этот файл xls содержит следующие таблицы:

• Generation – necessary for the definition of generation portfolio. • Генерация – необходимая для определения пакета генерации • Demand – necessary for the definition of consumption portfolio. Cells in yellow should be filled in. There are also optional cells (regarding consumption type percentages) which could be skipped if some data are not available. • Спрос – необходимая для определения пакета потребления. Ячейки, выделенные желтым, необходимо заполнить. Есть также дополнительные ячейки (касающиеся процентного выражения по типу потребления) которые можно пропустить в случае отсутствия данных • Bus, Fixed Shunt, Branch, Breaker, 2 Winding, 3 Winding and Area sheets – exported tables from PSS/E model to be checked. • Шина, фиксированный шунт, отвод, прерыватель, обмотка 2, обмотка 3 и региональные листы – таблицы, взятые из модели PSS/E должны быть проверены, • Dynamic Models Overview – exported tables from PSS/E BSTP model • Обзор динамических моделей – таблицы, взятые из модели PSS/E - BSTP • Generator dynamic data (1 and 2) – exported tables from PSS/E BSTP model to be checked. • Динамические данные генератора (1 и 2) - таблицы, взятые из модели PSS/E должны быть проверены • Turbine generator regulators (1-4) – exported tables from PSS/E BSTP model to be checked. • Регуляторы турбогенератора (1-4) - таблицы, взятые из модели PSS/E должны быть проверены • Generator voltage regulators (1-5) – exported tables from PSS/E BSTP model to be checked.

lxxi Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report • Регуляторы напряжения генератора (1-5) - таблицы, взятые из модели PSS/E должны быть проверены • Power System Stabilizers – exported tables from PSS/E BSTP model to be checked. • Стабилизаторы энергосистемы - таблицы, взятые из модели PSS/E должны быть проверены Existing Compensation Devices/Существующие устройства компенсации

1. Please check the possible presence of some FACTs (Flexible Alternating Current Transmission System) devices within the Ukrainian power system connected to the transmission network, such as: static synchronous compensators (STATCOMs), static VAR compensators (SVCs) or similar. Просьба проверить наличие устройства FACTs (Гибкие системы передачи переменного тока) в энергосистеме Украины, подключенных к сети элетропередачи, таких как: статические синхронные компенсаторы (STATCOMs), статические реактивные компенсаторы VAR (SVCs) и других аналогичных устройств

There are no FACTS devices directly connected to transmission network, but there are compensation batteries in particular within DONBAS.

2. If such devices exist, give a technical overview for each of them in terms of its location, technology, manufacturer, size and year of installation. Если такие устройства существуют дайте техническое описание каждого из них касательно их расположения, технического устройства, изготовителя, размера и года установки

The list of compensation batteries with necessary data is provided in hard copy (Document 1).

Generation/Генерация

3. Please review the whole power plant list with their units. Check if they are present in the model (Sheets Plants and Machines in both, sav and xls file within Annex), check out their parameters (including active and reactive power output for snapshot hour as well as their maximum and minimum limits) and indicate if there are any differences and how to correct it. Просьба сделать обзор всего перечня электростанций со всеми устройствами по блокам. Проконтролируйте, присутствуют ли они в модели (таблицы электростанций и агрегатов в обоих файлах, sav и xls в Приложении к Вопроснику), проверьте их параметры (включая выход активной и реактивной мощности на установленный замерный час, а также их максимальные и минимальные пределы) и укажите, если есть расхождения и как их скорректировать

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx) and UPSSP II Phase Questionnaire 1 - _BC0111.xlsx. Forecasted generation portfolio which should be used for appropriate model creation is given in баланс.docx file.

4. Taking into account that is quite possible to expect variation in HPPs production depending on different hydrology conditions and different generation pattern of small TPPs (mainly gas and oil fuel), please suggest one pessimistic generation scenario based on minimum possible level of both, HPP and small TPP production. In other words, please define one pessimistic generation scenario which will be used for sensitivity analysis within the capacity calculation process of possible reactive power compensation

lxxii Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report devices. The idea is to see the worst option in terms of power system reactive power production possibilities without any additional support from possible devices. Принимая во внимание, что вполне возможно ожидать различия в генерации ГЭС-й при различных гидрологических условиях и различных типов генерации малых ТЭЦ (преимущественно на газе и нефти), пожалуйста, предложите один пессимистический сценарий генерации на основе минимально возможного уровня совместного производства гидроэлектростанций и малых теплоэлектростанций. Другими словами, пожалуйста, определите один пессимистический сценарий генерации, которой можно будет использовать для проведения анализа чувствительности в процессе расчёта мощности возможных устройств компенсации реактивной мощности. Идея заключается в том, чтобы рассмотреть наихудший сценарий в смысле возможностей производства реактивной энергии энергосистемы без дополнительной поддержки от возможных устройств.

The power balance is forecasted taking into account minimum level of power production from both HPPs and CHPPs, and only anthracite fired PPs will be switched off for sensitivity analysis.

Substations and transformers/Подстанции и трансформаторы

5. Please review the whole power substation list with their units. First, check if they are present in the model (Sheets 2 Winding and 3 Winding in both, sav and xls file within Annex), check out their parameters and indicate if there are any differences and how to correct it. Пожалуйста, рассмотрите весь список подстанций с их элементами. Во-первых, проверьте присутствуют ли они в модели (Таблицы Обмотка 2 и Обмотка 3 в обоих файлах sav и xls в Приложении к Вопроснику), проверьте их параметры и укажите, если есть расхождения и как их скорректировать

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx).

6. Please check the presence of OLTCs for each transformer unit and review them in both, sav and xls file within Annex. Taking into account that modelling of OLTCs could be very complicated, if it is easier, please provide the rough list of these transformer units with necessary input data, such as nominal voltage for all windings, place of OLTC instalment (winding where it is physically), number of tap positions and percentage of voltage change per tap. Проверьте наличие устройств переключения напряжения онлайн (OLTC) для каждого трансформатора и представьте их в обоих файлах sav и xls в Приложении к Вопроснику. Принимая во внимание, что моделирование в OLTC может быть очень сложным, для его упрощения, пожалуйста, представьте приблизительный список этих трансформаторов с необходимыми вводными данными, такими как номинальное напряжение для всех обмоток, места установки OLTC (обмоток, где это возможно физически), количества отводов трансформатора и процент изменения напряжения на каждом отводе.

The list was checked and given in АТ.xlsx file.

7. Specify the settings for under/over voltage protection in substations, if any. Укажите установки защиты от повышения/понижения напряжения на подстанции, если они присутствуют

lxxiii Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

To be provided after the Technical Meeting and clarification.

8. Specify the settings for under/over frequency protection in substations including the lowest, if any. Укажите установки защиты от превышения/понижения частоты на подстанциях, включая самую низкую, если они присутствуют

I was given in Document 2 (hard copy) dedicated to under frequency protection principles.

Loads/Нагрузки

9. Please review the list of all nodes with the corresponding modelled loads within the power system. First, check if they are present in the model (Sheet Load in both, sav and xls file within Annex) and update their values for both, active and reactive power, taking into account snapshot hour. Проверьте список всех узлов, относящихся к соответствующим моделированным нагрузкам в энергосистеме. Во-первых, проверьте, имеются ли они в модели (Таблица нагрузок в обоих файлах sav и xls в Приложении к Вопроснику) и обновите их величины для активной и реактивной мощности, принимая во внимание установленный замерный час

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx) as well as Прогноз навантаження.xlsx, UPSSP II Phase Questionnaire 1 -_BC0111.xlsx and electricity consumption structure.xlsx.

10. Please review the consumption structure list for snapshot hour for the observed period (Sheet Load in xls file) taking into account changes in structure due to the political issues. Проверьте список структуры потребления для установленного замерного часа в рассматриваемый период ((Таблица нагрузок в файле xls), принимая во внимание изменения в структуре, вызванное политическими моментами.

The list was checked and given in electricity consumption structure.xlsx.

11. Indicate where the load shedding schemes were applied during the previous months and estimate shaded power for those areas for snapshot hour. Confirm whether this schemes is applicable in general or it is necessary to be adjusted. This is important for sensitivity analysis scenario with low production from HPPs and small TPPs (mentioned before) as well as for cases without interconnection with Russia. Укажите, где использовались схемы отключений нагрузки в предыдущие месяцы и оцените объём отключенной мощности для этих районов для установленного замерного часа. Подтвердите, применимы ли эти схемы в общем или их необходимо корректировать. Это важно для сценария анализа чувствительности при низкой производительности ГЭС и малых ТЭС (упоминавшихся ранее) а также для случаев без соединения с Россией

This is given in ГАВ_17_12_14.xlsx and ГОП_17_12_14.xlsx where ГАВ_17_12_14 is load shedding for 17.12.2014 in specified hours according to predefined scheme and ГОП_17_12_14 additional protection load shedding for the same hours.

Lines/Линии

lxxiv Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report 12. Examine in detail all the power lines in the system. First, see if they are all present in the model, check their parameters and indicate if there are any differences and how to correct it. Проверьте в деталях все линии электропередачи в этой системе. Во-первых, посмотрите, присутствуют ли они в модели, проверьте их параметры и укажите, существуют ли разногласия и возможности устранения

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx).

13. Check the availability of modelled elements with corresponding substations in the war affected areas. Проверьте наличие смоделированных элементов соответствующих подстанций в районах конфликта

This is included in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx). More detailed description is given in Modelling Report.

14. For all lines, please review: nominal rate, permissible thermal limit and overcurrent protection setting for each individual line (please specify within the PSS/E model by using A, B and C rates, respectively). Для всех линий, пожалуйста, проверьте: номинальные величины, допустимые тепловые пределы и установки защиты превышения тока для каждой отдельной линии (пожалуйста, укажите в модели PSS\Е используя уровни А, В, С, соответственно)

To be provided after the Technical Meeting and clarification.

Exchanges/Обмен

15. Examine in detail all the interconnection ties. First, see if they are all present in the model, check the interchange for snapshot hour and indicate if there are any differences and how to correct it. Please pay special attention to war affected areas. Проверьте в деталях все межсистемные связи. Во-первых, их присутствие в модели, проверьте изменения для установленного замерного часа и укажите, если есть расхождения и возможность их корректировки. Обратите особое внимание на зоны конфликта.

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx).

16. For all tie lines, review: nominal rate, permissible thermal limit and overcurrent protection setting for each individual line (the same as for lines). Для всех системных связей, рассмотрите: номинальный показатель, разрешённый тепловой предел и установок защиты от превышения тока для каждой отдельной линии (также, как для линий)

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx).

Russian power system equivalent updating/Обновление эквивалента Российской энергосистемы

lxxv Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report 17. Please update relevant parts of the Russian power system equivalent making necessary adjustments of simulation model. Обновите соответствующие части эквивалента энергосистемы России, внося необходимы изменения в модель

The list was checked and given in Ukraine Project WMAX LF 2014-2015_Win_КОРИГ.sav.

Generator dynamic data/Динамические данные генератора

18. Check and review existing model lists with their appropriate parameters given in xls file within Annex and indicate if there are any differences and how to correct it taking into account either, standard PSS/E data base models or user defined models. Проверьте перечни существующей модели с соответствующими параметрами в файле xls в Приложении к Вопроснику, и укажите, есть ли различия и как их исправить, принимая во внимание стандартные модели базы данных PSS/E или модели, определённые пользователем

The list was checked and given in BSR SUMMIN2020 LF ENTSOE.sav and BSR SUMMIN 2020 September 2014_UA_MD_ver2.dyr together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx). Some of machine input data were given in generator_ver2.xls as well.

Turbine generator regulators/Регуляторы турбогенератора

19. Check and review existing model lists with their appropriate parameters given in xls file within Annex and indicate if there are any differences and how to correct it taking into account either, standard PSS/E data base models or user defined models. Проверьте перечни существующей модели с соответствующими параметрами в файле xls в Приложении к Вопроснику, и укажите, есть ли различия и как их исправить, принимая во внимание стандартные модели базы данных PSS/E или модели, определённые пользователем

To be provided after the Technical Meeting and clarification.

Generator voltage regulators (including Power System Stabilizers)/Регуляторы напряжения генератора (включая стабилизаторы энергосистемы)

20. Check and review the existing model lists with their appropriate parameters given in xls file within Annex and indicate if there are any differences and how to correct it taking into account either, standard PSS/E data base models or user defined models. Проверьте перечни существующей модели с соответствующими параметрами в файле xls в Приложении к Вопроснику, и укажите, есть ли различия и как их исправить, принимая во внимание стандартные модели базы данных PSS/E или модели, определённые пользователем

The list was checked and given in BSR SUMMIN2020 LF ENTSOE.sav and BSR SUMMIN 2020 September 2014_UA_MD_ver2.dyr together with appropriate xls file (UPSSP II Phase Questionnaire 1 - Ukrenergo.xlsx). Some of data were given in excitation system_ver2.xls and UDM_DMCC.docx as well.

Models for additional generation plant equipment/Модели дополнительного оборудования генерирующей станции

lxxvi Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report 21. Indicate potential presence of some kind of reactive power limiter devices in Ukraine power plants. If they exist, give a little overview in terms of their technical parameters relevant for appropriate modelling within PSS/E (taking into account explanations in 27.4.4 Maximum Excitation Limiters, MAXEX1 and MAXEX2 in the end of this questionnaire). Укажите потенциальное наличие устройств ограничения реактивной мощности на украинских электростанциях. Если они существуют, дайте небольшое описание в плане их технических параметров, соответствующих моделированию в PSS/E( принимая во внимание объяснения, приведённые в разделе 27.4.4 Maximum Excitation Limiters/ ограничители максимального возбуждения, MAXEX1 и MAXEX2 в конце данного опросника)

Some of data which could be used for the modelling were given in hard copy (Document 3).

Models for on-load tap changer controls/Модели управления переключателем напряжения онлайн

22. As upgrading of data collected within Substations and transformers paragraph, please include additional technical parameters relevant for appropriate modelling within PSS/E, such as time constants TD, TC, and TSD (according to 27.4.1 Online Tap Changer, OLTC1 in the end of this questionnaire). These parameters are necessary for each OLTC for each transformer and they could be add to the list of transformer units input data (nominal voltage for all windings, place of OLTC instalment, number of tap positions and percentage of voltage change per tap) В качестве обновления данных, содержащихся в параграфе Подстанции и трансформаторы укажите дополнительные технические параметры, относящиеся к соответствующему моделированию в PSS/E такие как, постоянные времени TD, TC , TSD (согласно разделу 27.4.1 Переключатель напряжения онлайн, OLTC1 в конце данного вопросника). Эти параметры необходимы для каждого OLTC каждого трансформатора, и они могут быть добавлены в список входных данных трансформаторов (номинальное напряжение для всех обмоток, место установки OLTC, количество расположений отводов и процент изменения напряжения на каждом отводе)

Such kind of automatic control is disabled in Ukrainian power system and due to that fact there is no need for its modelling.

Models for complex dynamic loads/Модели комплексных динамических нагрузок

23. As upgrading of data collected within Loads paragraph, please include additional technical parameters relevant for appropriate modelling within PSS/E (according to 20.2.3 Complex Models in the end of this questionnaire). Please note that for complex load the most important are % of typical consumption taking into account previously mentioned explanation. However, due to the easier communication between load flow and dynamic data, fill in this in appropriate (Demand) sheet within xls file (cells in yellow). Due to the complexity of such kind of precise data collection process, pay special attention to the vicinity of bordering nodes towards Russian power system. In other words, this data have to be collected at least if we want to see dynamic stability behaviour of voltages in both, North-Eastern and Eastern part of Ukraine power system in case of switched-off tie-lines towards Russia. В качестве обновления данных, взятых из параграфа Нагрузки, пожалуйста, добавьте дополнительные технические параметры, относящиеся к соответствующему моделированию в PSS/E (соответственно разделу 20.2.3 Комплексные модели в конце данного Вопросника.) Обратите ваше внимание, что для комплексной загрузки наиболее важным является процент типичного lxxvii Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report потребления, принимая во внимание приведённое ранее объяснение. Однако, благодаря более простой связи между потокораспределением загрузки и динамическими данными заполните соотвествующую таблицу (Спрос) в файле xls (ячейка, выделенная желтым цветом). Ввиду сложности процесса сбора точных данных, обратите внимание на близость расположения пограничных узлов с энергосистемой России. Другими словами, эти данные должны быть собраны по меньшей мере, если мы хотим рассмотреть поведение динамической стабильности напряжения в Северо-восточной и Восточной частях Украинской энергосистемы в случае отключения межсистемных связей с Россией.

Some of data which could be used for the modelling were given in hard copy (Document 4).

======Relevant specific PSS/E Model necessary for UPSSP Second Phase Dynamic Model Development / Соответствующего конкретного PSS/E Модель, необходимых для развития UPSSP Второй этап динамической модели

20.2.3 Complex Models/Комплексные модели

20.2.3.1 CLOD Type Models (CLODBL, CLODOW, CLODZN, CLODAR, CLODAL)/Типовые модели (CLODBL, CLODOW, CLODZN, CLODAR, CLODAL)

The CLOD type models (CLODBL, CLODOW, CLODZN, CLODAR, CLODAL) replace all constant MVA, current, and admittance load with a composite load consisting of induction motors, lighting, and other types of equipment such as would be fed from many typical substations. The models may represent a composite load of induction motors, lighting, and other types of equipment such as would be fed from many typical substations. It is intended for use in situations where it is desirable to represent loads at the dynamic level, as distinct from the algebraic characteristic level used in power flow, but where detailed dynamics data is not available. The models allow the user to specify a minimum amount of data stating the general character of the composite load. It uses this data internally to establish the relative sizes of motors modelled in dynamic detail and to establish typical values for the detailed parameter lists required in the detailed modelling. Типовые модели CLOD (CLODBL, CLODOW, CLODZN, CLODAR, CLODAL) замещают все типовые постоянные MVA, текущую и проводимую нагрузку смешанной, состоящей из индукционных моторов, осветительного и другого типового оборудования, которое будет питаться от многих типовых подстанций. Это предназначено для использования в ситуациях при которых желательно представить нагрузки на динамической уровне, в отличии от алгебраического характеристического уровня, используемого в протоке энергии, на при которых детальные данные динамики недоступны. Эти модели позволяют пользователю определить минимальный объём данных, описывающих общий характер смешанной нагрузки. Эти данные используются внутри программы для определения относительных размеров моторов, смоделированных в динамических параметрах и для определения типичных величин списков детальных параметров, требуемых для детального моделирования.

lxxviii Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report

27.4.1 Online Tap Changer, OLTC1/Переключатель напряжения онлайн, OLTC1 The online tap changing model, OLTC1, allows the modelling of transformer tap adjustments to help control system voltage: it has two main components. The first is the voltage sensor, which compares the input voltage to the preselected setting (voltage level) and a tolerance, or spread, in voltage level (bandwidth). If the voltage input to the sensor is out of the control band, the control will operate after the time delay has been exceeded. Thus, the output of the regulator will be either raised or lowered until the voltage feedback into the sensor is again within the control band. Because the time delay is generally magnitudes greater than the voltage sensor transducer time constant, the transducer time constant is not modelled. OLTC1 operates only on transformers controlling voltage in the power flow. If the power flow was solved without adjusting taps and the voltages are outside the control band, OLTC1 will print a message during activity STRT stating that the timer is started. A positive tap step is also required in the power flow. Модель переключения напряжения онлайн, OLTC1, позволяет моделировать корректировку отводов трансформаторов, позволяющую контролировать напряжение в системе: она состоит из двух компонентов. Первый представляет собой датчик напряжения, которых сравнивает входное напряжение с предварительно установленными (уровень напряжения) и допустимость, или колебание уровня напряжения (ширины диапазона). Если входное напряжение на датчике выходит за пределы управляемого диапазона, то управление будет осуществляться с превышением задержки по времени. Таким образом, выходная величина регулятора будет либо повышена или понижена до тех пор, пока обратная связь по напряжению в датчике не вернётся в пределы управляемого диапазона. Поскольку временная задержка обычно превышает постоянную времени датчика напряжения трансформатора, постоянная времени первичного преобразователя не моделируется. OLTC1 работает только на трансформаторах, управляющих напряжением в потоке энергии. Если поток энергии рассчитан без корректировки напряжения на выходных обмотках и напряжения выходит за

lxxix Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report пределы управляемого диапазона, OLTC1 напечатает сообщение во время действия STRT, указывающего, что таймер запущен. Положительный шаг выходных обмоток трансформатора также требуется в потоке энергии.

The second major component of OLTC1 is the time-delay circuit. It permits the regulator to ignore brief, self- correcting voltage variations. The time delay enables the transformer to correct only those voltage variations that exist for longer than a pre-set time. The time delay for subsequent tap changes can be specified independently of the first time delay.

Вторым основным компонентом OLTC1 является схема временной задержки. Она позволяет регулятору игнорировать короткие, самокорректирующиеся изменения напряжения. Эти временная задержка позволяет трансформатору корректировать только те колебания напряжение, которые длятся дольше, чем установленное время. Эта временная задержка позволяет трансформатору задерживать во времени последовательное изменение напряжения на выходных обмотках и может быть определена независимо от первой временной задержки.

OLTC1 incorporates the most common type of timer, an integrator that adds the total amount of time that the voltage is outside the preselected control band and subtracts the time it is inside the control band. When the voltage is outside more than inside by an amount greater than the time-delay setting, TD, the time-delay sends a tap signal to the tap changer motor. The tap changer motor operates TC seconds later. Using a timer setting of TD = 30 sec, Figure 27-8 shows a voltage that is out-of-range for 13 sec and returns within the bandwidth for 5 sec. Therefore, a tap signal is not sent until another 22 sec (30 - (13 - 5)) elapses with the voltage below the minimum value. OLTC1 also allows for a subsequent delay for sending additional signals to the tap changer motor. The user can enter a delay, TSD, to get additional delay. Delay TSD must be greater than TC to be effective. A common practice in distribution transformer control is line-drop compensation. OLTC1 recognizes when a remote bus voltage is being controlled, as defined by the power flow data. The user represents the feeder circuit, possibly including a dummy bus, to represent line-drop compensation. Typical data for this model would be 25.0 sec for TD, 10 sec for TC, and 15 sec for TSD.

OLTC1 включает в себя наиболее распространённый тип таймера, интегратор, который увеличивает общее количество времени, в течении которого напряжение находится за пределами установленного диапазона управления и вычитает количество времени в течение которого напряжение находится в пределах управляемого диапазона. Когда напряжение находится вне пределов управляемого диапазона больше, чем установленная временная задержка, ВЗ, временная задержка посылает сигнал на мотор, изменяющий напряжение на выходных обмотках. Мотор изменения напряжения на выходных обмотках управляет TC на несколько секунд позже. Используя установку таймера с TD = 30 sec, на Рисунок 27-8 показано напряжение, которое находится за пределами диапазона управления в течении 13 sec и возвращается в диапазон управления на 5 sec. Таким образом сигнал на выходных обмотках трансформатора посылается по истечении 22 sec (30 - (13 - 5)) при напряжении ниже минимальной величины. OLTC1 также позволяет осуществлять последовательную задержку посылки дополнительных сигналов на мотор изменения напряжения на выходных обмотках. Пользователь может ввести задержку,, TSD, для получения дополнительной задержки. Задержка TSD должна превышать задержку TC чтобы быть эффективной. Обычная практика управления распределения трансформаторов состоит в компенсации падения напряжения в линиях. OLTC1 фиксирует, когда напряжение на удаленных шинах контролируется, как это определяется данными потока энергии. Пользователь представляет схему питания, возможно включая ложную шину, чтобы представить компенсацию падения напряжения в линиях. Типичными данными для данной модели будут 25.0 sec = TD, 10 = TC, и 15 = TSD.

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Figure 27-8. Example of Integration Timer for the OLTC1 and OLPS1 Models

27.4.4 Maximum Excitation Limiters, MAXEX1 and MAXEX2/Ограничители максимального возбуждения, MAXEX1 и MAXEX2 Maximum excitation limiters are designed to protect the generator field of an ac machine with automatic excitation control from overheating due to prolonged over excitation, which can be caused either by failure of a component of the voltage regulator or an abnormal system condition. Model MAXEX1 acts through the regulator to correct an over excitation problem. This model assumes an inverse time characteristic as shown in Figure 27-9; i.e., operating time is a function of the magnitude of the overvoltage. Ограничители максимального возбуждения предназначены для защиты поля генерации машин переменного тока с системой автоматического контроля возбуждения от перегрева в результате длительного перевозбуждения, причиной которого может быть либо проблема с компонентом регулятора напряжение или нарушения системных условий. Модель MAXEX1 действует через этот регулятор для корректировки проблемы перевозбуждения. Эта модель предполагает характеристику инверсионного времени такой, как это показано на Figure 27-9; т.е. оперативное время является показателем степени перенапряжения.

MAXEX2 allows limiting of either field voltage or field current; for the sake of simplicity, this text uses field voltage but field current would be limited in an equivalent manner. After the unit has timed-out, the signal sent to the regulator is a function of field voltage deviation from a desired value, as shown in Figure 27-10 for MAXEX1 and MAXEX2. MAXEX2 allows позволяет лимитировать или напряжение возбуждения генератора или ток обмотки возбуждения; в целях упрощения данный текст использует напряжение возбуждения генератора, при этом ток обмотки возбуждения будет лимитирован подобным же образом. После превышения блоком лимита времени этот сигнал поступает на регулятор – это функция отклонения напряжения возбуждения генератора от желаемой величины, как это показано на Figure 27-10 для MAXEX1 и MAXEX2.

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Figure 27-9. Inverse Time Characteristics of MAXEX1 and MAXEX2

Figure 27-10. Block Diagrams of MAXEX1 (Top) and MAXEX2 (Bottom)

After timeout, the model does not reset (i.e., it is assumed that the operator must reset the device). The following assumptions are also made by the model.

1. Below EFD1, the device is inactive. 2. Above EFD3, the time to operate is constant and equal to TIME3. 3. If EFD goes below EFD1 at any time before the device has timed-out, the timer resets. После таймаута, эта модель не перезагружается (т.е. предполагается, что оператор должен переустановить устройство. Следующие допущения также проводятся этой моделью: 1. Ниже EFD1, это устройство неактивно. 2. 2. Выше EFD3, оперативное время постоянно и равно TIME3. 3. Если EFD опускается ниже EFD1 в любой время до паузы в работе устройства, таймер переустанавливается. Most General Electric and Westinghouse excitation systems have either an optional device or an integral part of the excitation limiter that trips the exciter and/or the generator. These devices are provided for regulator failure, and are not modelled by MAXEX1 or MAXEX2. The user must manually trip the exciter or generator to model a regulator failure. Typical values for the inverse characteristic would be the following:

Большинство систем возбуждения Дженерал Электрик и Вестингауз содержат или не- входящее в основной комплект устройство или в качестве обязательной составной части ограничителя возбуждения, который осуществляет остановку возбудителя и/или генератор. Данные устройства

lxxxii Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report предназначены для отказов регулятора, и не моделируются MAXEX1 и MAXEX2. Пользователь должен в ручную осуществлять остановку возбудителя или генератора в целях моделирования отказов регулятора. Типичные величины инверсных характеристик приводятся ниже:

The characteristics of the MAXEX1 model require a low gain for the KMX constant because the model output feeds directly into the voltage regulator input of the exciters. For high-gain exciters a value of 0.01 is suggested. If the gain is too high, the network may not converge. To overcome the drop of the exciter and interaction with terminal voltage, a value of 0.9 is suggested for EFDDES. The MAXEX2 model is a more accurate representation of the physics of actual maximum excitation limiters than the MAXEX1 model. MAXEX2 can also be used to approximate the actions of operators attempting to relieve field overload by reducing voltage set points. The MAXEX2 model uses an integral controller and hence controls the field voltage/current to the desired value with the drop inherent in MAXEX1. Typical values would be 0.002 for KMX and 1.0 for EFDDES. Характеристики модели MAXEX1 требуют низкого прироста постоянной KMX т.к. эта выход модели подается непосредственно на вход регулятора напряжения возбудителя. Для возбудителей с большими величинами прироста предлагается величина 0.01. Если прирост слишком большой передающая сеть может не конвергироваться. Для преодоления отклонения возбудителя и взаимодействия с терминальным напряжением, предлагается величина 0.9 для EFDDES. Модель MAXEX2 является более точным представлением физических процессов в ограничителях реального максимального возбуждения, чем модель MAXEX1. MAXEX2 может также использоваться для приблизительного представления действий, направленных на смягчения перегрузки поля путем снижения установленных величин напряжения. Модель MAXEX2 использует встроенный контроллер и поэтому контролирует поле напряжения/тока в желаемом диапазоне с понижением, полученным в MAXEX1. Типичные величины для KMX составляют 0.002 и 1.0 для EFDDES.

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Ukraine Power System Support Project – Phase II Winter 2014/2015 Ukraine Power System Dynamic Model Development Technical Meeting with Ukrenergo representatives

5-6.02.2015 Kiev, Ukraine

Ukrenergo hosted a meeting of the Ukraine Power System Support Project -Phase II in Kiev, Ukraine on February 5-6, 2015. Participants in the meeting were representatives from the following companies:

• Ukrenergo with local consultants • Electricity Coordinating Center (EKC) • United Sates Energy Association (USEA) This was the working technical meeting for the Ukraine Power System Support Project –Phase II, which focuses on dynamic model development as well as load flow model accuracy improvement from Phase I according to up-to date information of Ukrainian power system operation.

The first day of the meeting, February 5th, was dedicated to the adjustment of the models and additional assumptions and operational issues which should be taken into account at it follows:

• Existing Reactive Power Compensation Devices connected to the Ukrainian transmission network – Ukrenergo provided information of existing compensation devices -their location, technology and size in appropriate form for PSS/E load flow model of Ukraine power system.

• Ukrenergo submitted Load Flow Model update – in order to refine and update the 2014/2015 Load Flow Model developed in Phase I of the UPSSP to reflect the network topology and actual data for electricity consumption at various load centres based on the snapshot hour for the 3rd Wednesday in December 2014 at 17:00. Practically, following data update was obtained:

o Generation pattern was set in detail for available generation units of hydro plants, pump units in hydro plants, nuclear units, thermal power plants and small distributed generation. Special attention is given to hydro units and pumps which are set to expected production level for midterm period (winter) with no changes expected by the end of the season. Anthracite power plants generation was updated, resulting with minimum generation level required for heating of residential buildings. It is clarified possibilities of several generation units to operate as gas fuelled units within anthracite plants. List of distributed small generation units is updated regarding their power output for observed snapshot hour.

rd o This generation pattern is direct input for balance sheet for snapshot hour for the 3 Wednesday in December 2014 at 17:00

o Substations and transformers – Ukrenergo provided status of substations, particularly in the area of eastern Ukraine. Detailed list of transformer types with their specific functions is given in excel sheet table. Ukrenergo stated that under frequency relays are set at the system level and will provide typical settings for cases of power system under frequency conditions

lxxxiv Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report o List of transformers and their characteristics provided information that within Ukrainian power system there are transformers with on load tap changing transformers (OLTC) with automatic regulation. However these automatic operation is blocked, therefore update of dynamic model of Ukrainian power system will not include dynamic OLTC models for these transformers.

rd o Power Lines – according to 3 Wednesday in December 2014 at 17:00 actual status these elements within the transmission network is presented by Ukrenergo. Significant changes are identified for the transmission lines towards war affected area, where comparing to the system model from Phase I additional list of unavailable transmission lines are identified and given in excel spread sheet list. o The result of new conditions in power system with additional list of unavailable transmission lines resulted with present state of island operation of war affected area in eastern Ukraine. o Within the 110 kV network important modelling issues are identified for the contingency analyses. There are group of 110 kV power lines that are representing the equivalent of several nearby 110 kV power lines. This directly implicates drawn conclusion that N-1 analyses cannot be performed on these group of lines. o For this group equivalent of 110 kV lines it is not possible to determine limits of power transfer (protection settings). o For the rest of the 110 kV lines, which are not equivalent, Ukrenergo will provide typical load limits-protection setting. o Most of 110 kV lines that are back-up ring for the higher transmission lines and supplying power to lad are operating in radial topology regime.

st o Exchanges – Starting from the January 1 additional power supply is possible from Russian power system. The limitation is set to 1500 MW. History data from the first week in February showed that this import varies from 100 MW to 1000 MW depending on the current state of balance in Ukrainian power system (generation/load portfolio). Typical value cannot be identified, therefore for further analyses in Phase II import is set to 500 MW. o Import from Russia is stipulated by no restriction of power supply towards Crimea, which was established in Phase I at 600 MW maximum. Current peak load of Crimea is included in Ukraine power system balance. o Programed power exchange with other countries is changed comparing to load flow model in Phase I and now Ukraine imports from Russia 500 MW and export from Burstyn island 300 MW. o Ukrenergo provided update of Russian power system equivalent – within Phase II model equivalent has detailed topology of Russian power system. o Ukrainian power system balance sheet is set according to above presented data, system conditions and limitations. o Detailed Load shedding scheme is presented by Ukrenergo. Cut of supply is conducted at different level depending of the system conditions, with maximum power shed of around 6000 MW.

lxxxv Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report The second day of the meeting, February 6th, all agreed adjustment and results from the first day meeting were adopted, and some of them were implemented directly to the PSS/E models. All developed changes within the updated Phase II load flow model were confirmed by Ukrenergo. The main issue of second day of the meeting was related to dynamic model of Ukraine power system. Starting point was BSTP dynamic model data as general input. Special attention is given to advanced modelling of load in the area of interest, excitation system limitation, turbine governor models.

• There are no FACTS devices directly connected to transmission network, but there are compensation batteries in particular within DONBAS and the list of compensation batteries with necessary data is provided in hard copy (Document 1). • Preliminary analyses performed in PSS/E model for Phase II after adopted load based on the snapshot hour for the 3rd Wednesday in December 2014 at 17:00, showed some issues of instability in eastern region where transmission grid is operating in island operations. After clarifications and suggestions with Ukrenergo representatives this issues are solved. • EKC has presented concept of advanced load modelling for dynamic analyses within PSS/E software package. • Ukrenergo and EKC agreed that advanced load modelling will be used for area of interest (week part of transmission network in Ukraine) to obtain more precise dynamic analysis regarding power system stability. • Load model that will be used within the dynamic analysis is CLOD. • EKC has presented concept of undervoltage, underfrequency protection in substations that supply load and maximum excitation limiter for generator models. • Load Shedding will be applied only in three characteristic deficit regions as it was case in previous phase (North, Centre and DONBAS). • Ukrenergo provided detailed load structure data for area of interest (North), containing types of load for substations of interest (Document 4) as well as hard copy of document dedicated to under frequency protection principles (Document 2). • EKC will prepare obtained load characteristic in CLOD model form for dynamic analyses. • EKC indicated necessity for updated data of turbine generator regulators – reviewing and updating of both, modelled regulator types and appropriate parameter values. Ukrenergo consultant will receive actual turbine data in appropriate form from EKC and perform the revision. • EKC indicated necessity for updated data of generator excitation systems – reviewing and updating is done by Ukrenergo and local consultant during the meeting and changes are implemented to PSS/E dynamic model. • Ukrenergo with local consultant will obtain additional information about the existence of maximum excitation limiters in power plants and provided some information about their reactive power limits (Document 3).

Next steps/deliverables: • For the rest of the 110 kV lines, which are not equivalent, Ukrenergo with local consultant will provide typical load limits-protection setting by February 13th 2015.

lxxxvi Ukraine Power System Support Project Winter 2014/2015 Ukraine Power System Dynamic Analysis – Data Collecting and Load Flow Analysis Report • Ukrenergo consultant will receive actual turbine data in appropriate form from EKC and perform the revision by February 13th 2015. • Ukrenergo consultant will check status of installed WAMS devices and provide necessary data for dynamic model checking by February 13th 2015. • Ukrenergo consultant will check status of installed Arc Furnaces devices (large consumers) and provide necessary data for dynamic model by February 13th 2015. • Ukrenergo consultant will check status of installed undervoltage devices and provide necessary data for dynamic model by February 13th 2015. • EKC will develop appropriate Load Flow scenario models and send Ukrenergo for the approval with all scenario models contingencies by February 12th 2015. • Ukrenergo will send confirmation of the model and necessary priority for the resolving of certain contingencies by February 13th 2015. • EKC will prepare obtained load characteristic in CLOD model form for dynamic analyses. • After the remain models approval EKC will start with the finalization of necessary analysis, dynamic model development and Final Draft Report (by February 23rd 2015).

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