Associated with PA Consulting Group Technical, Management, and Economic Counsel Technical Audit Study of Jamshoro, Guddu and Muzaffargarh Thermal Power Stations in Pakistan Final Report HBP REF.: R1V02TAG April 27, 2011 Advanced Engineering Associates International Islamabad
Executive Summary An energy audit of the thermal power stations (TPSs) of the following three state owned power plants, collectively referred to as GENCOs was carried out: TPS Jamshoro, or the Jamshoro Power Company Ltd., commonly referred to as GENCO I, TPS Guddu, which is a part of Central Power Generation Company Ltd. commonly referred to as GENCO II), and, TPS Muzaffargarh, which is a part of Northern Power Generation Company commonly referred to as GENCO III.D The main objective of the study was to carry out a baseline evaluation or a benchmarking for determining efficiency gains and operational improvements to be achieved through the implementation of the USAID Fixed Amount Reimbursement Agreements (FARA) Repair and Maintenance Plan currently under implementation at these GENCOs. The key terms of reference of the study were: Assess performance parameters such as effective output capability, heat rate and efficiency and power plant availability of each unit Identify reasons for drop of plant performance from the design parameters Carry out a spot fuel oil analysis to determine the heat contents and quality of the fuel oil being supplied to the power stations Carry out a brief technical review to assess the potential for using high-viscosity fuel oil to reduce the plants generation costs The standard methodologies used by the industry to determine the baseline performance evaluation of steam and combined cycle power plants are ANSI/ASME PTC-6 and ANSI/ASME PTC-46 respectively. However, these methodologies could not be followed for a number of limitations for GENCOs. These limitations include: Lack of availability of accurate and calibrated instrumentation in the power station for online or off-line evaluation of efficiency Lack of trained staff and manpower to carry out detailed measurement procedures under controlled testing conditions Software tools to carry out the component-wise heat balance analysis of the plant Extensive data that includes ambient conditions, design data, correction curves and operating conditions for the main heat path components such as boilers, turbines, condensers, and cooling towers. A specific testing protocol was devised for each unit on the basis of its fuel supply systems, instrumentation status, and other operating conditions. A number of units were not available for testing due to different operational reasons. Exhibit I provides a R1V02TAG: 04/27/11 Executive Summary ii
summary of units that were tested and those not tested along with the reasons for their unavailability. Exhibit I: Unit-wise Testing Status of GENCOs Power Station Units Tested Units Not Tested Reasons for Not Testing the Units TPS Jamshoro Units 1-4 TPS Guddu Steam Block Units 1-2 Energy input could not be measured due to absence of gas flow meters TPS Guddu CCP Block Block 2-A (GT 7, GT8, ST 5) Block 1 (GT 11, GT12, ST 13) Unit 3 Unit 4 Block 2-B (GT 9, GT10, ST6) Energy input could not be measured accurately due to due to errors in gas and RFO flow meters On prolonged shutdown from December 2010 to March 2011 due to break down of air preheater Energy input could not be measured accurately due to lackof functional and calibrated gas flow meters TPS Muzaffargarh Units 2-6 Unit 1 On prolonged shutdown from November 2010 to mid- April 2011 due to delay in replacement of super heater tubes The heat rates and efficiency parameters for the power stations have been calculated only for the purpose of baseline evaluation or a benchmark for determining efficiency gains and operational improvements to be achieved after the implementation of the USAID FARA Repair and Maintenance Plan currently under implementation at these GENCOs. It should be noted that heat rates in this study were determined under steady loading and specific ambient and operating conditions of the units during the winter season. Average annual heat rates for the power stations are likely to be higher due to variations in ambient conditions and loading levels, inclusive of startups and shutdowns. Findings and Results All the steam units of TPS Jamshoro and TPS Muzaffargarh are dual fuel plants having gas and residual fuel oil (RFO) firing facilities except for Unit 1 of Jamshoro that has only fuel oil firing capability. However, these plants were only operating on RFO firing due to shortage of natural gas. TPS Guddu uses medium calorific raw gas from Mari and Kandhkot. Steam Unit 3 and 4 at Guddu can also operate on mixed firing with RFO as secondary fuel. Due to poor maintenance of the power stations, GENCOs have lost nearly one third of their capacity and nearly 17% of their thermal efficiency due to plant degradation. The Exhibit II shows the unit-wise results of performance evaluation tests for the power stations. R1V02TAG: 04/27/11 Executive Summary iii
Exhibit II: Results of Output Capability, Heat Rate and Availability of GENCOs Installed Capacity MW Present Gross Capability MW Present Net Capability MW Capacity Degradation Design Heat Rate Design Net Efficiency Gross Heat Rate Gross Efficiency Net Heat Rate Net Efficiency Average Availability in FY2010 Average Availability in FY2011 TPS Jamshoro Unit 1 250 191 176 23% 9,315 36.6% 9,829 34.7% 10,720 31.8% 73% 80% Unit 2 200 119 112 41% 10,068 33.9% 11,727 29.1% 12,492 27.3% 88% 69% Unit 3 200 125 113 38% 10,068 33.9% 11,879 28.7% 13,262 25.7% 85% 58% Unit 4 200 146 133 27% 10,068 33.9% 10,909 31.3% 11,935 28.6% 91% 79% Total Jamshoro 850 581 535 32% 84% 72% TPS Guddu CCP Block Block 2-A GT 7 100 93 92 7% 10,763 31.7% 12,840 26.6% 12,896 26.5% 78% 96% GT 8 100 85 85 15% 10,763 31.7% 13,412 25.4% 13,467 25.3% 98% 92% ST 5 100 71 69 29% - - - - 98% 97% Total Block 2-A 300 248 246 17% 9,572 35.6% 9,658 35.3% 98% 95% Block 1 GT 11 136 80 80 41% 10,629 32.1% 12,196 28.0% 12,261 27.8% 99% 100% GT 12 136 80 80 41% 10,629 32.1% 12,236 27.9% 12,272 27.8% 99% 100% ST 13 143 84 81 41% 97% 86% Total Block 1 415 244 240 41% 8,081 42.2% 8,218 41.5% 98% 95% Total Guddu CCP 715 493 487 31% 95% 95% R1V02TAG: 04/27/11 Executive Summary iv
Installed Capacity MW Present Gross Capability MW Present Net Capability MW Capacity Degradation Design Heat Rate Design Net Efficiency Gross Heat Rate Gross Efficiency Net Heat Rate Net Efficiency Average Availability in FY2010 Average Availability in FY2011 TPS Muzaffargarh Unit 2 210 168 156 20% 9,279 36.8% 10,060 33.9% 10,784 31.6% 88% 83% Unit 3 210 140 127 33% 9,279 36.8% 9,943 34.3% 10,773 31.7% 81% 96% Unit 4 320 202 181 37% 9,297 36.7% 10,129 33.7% 11,312 30.2% 97% 60% Unit 5 200 97 86 51% 10,780 31.7% 11,384 30.0% 13,026 26.2% 47% 72% Unit 6 200 73 64 63% 10,780 31.7% 12,380 27.6% 14,392 23.7% 77% 78% Total Muzaffargarh 1,140 680 614 40% 80% 62% R1V02TAG: 04/27/11 Executive Summary v
The key results of the performance evaluation tests are described below. TPS Jamshoro The average capacity degradation was found to be 32% compared to the installed capacity with a maximum degradation of 40% for Unit 2 and a minimum degradation of 23% for Unit 1. The average drop in the net efficiency is about 20% from the design efficiency of the power station. Unit 1 is most efficient with 32% net efficiency against the design efficiency of 36.6%. The net efficiencies of Units 2-4 ranged between 25.7% to 28.6% against the design efficiency of 34%. The average availability of the power station was 84% in FY2010 and 72% in FY2011 (till November 2010). However, if this availability is corrected for lost output of the plant due to degradation, the availability factor would drop by about 35%, indicating poor performance of the plant. TPS Guddu CCP Block 1 has shown 40% degradation in its capacity from the installed capacity whereas CCP Block 2-A appears to be in better condition with only 17% capacity degradation. The gas turbines (GTs 7 and 8) in Block 2-A showed net efficiencies of 27.8% each against the design efficiency of 31.7%. The GT 11 and GT 12 in Block 1 showed the net efficiencies of 26.5% and 25.3% respectively against the design efficiency of 32.1%. The net efficiency of the Block 2-A and Block 1 were calculated to be 35.3% and 41.5% respectively. The average availability of the units tested under the study at power station was in excess of 95% but if this availability is corrected for lost output of the plant owing to degradation, the availability factor would drop by about 30%, quite low from industry standards. TPS Muzaffargarh The power station is operating with an overall capacity degradation of around 40%. Capacity degradation for the units varied between 20% for Unit 2 to 63% for Unit 6. The power station is facing an overall degradation of around 18% in its net efficiency. Units 2 and 3 are in better condition with 31% net efficiency compared with their design efficiency of 36.8%. Unit 4 has a net efficiency of 30% against 36.7% design efficiency. Units 5 and 6 have efficiencies of 26% and 24% respectively against the design efficiency of 31.7% for both units. The average availability of the power station was in 80% and 62% in FY2010 and FY2011. The availability of TPS Muzaffargarh would also drop by 40% if corrected for lost output of the plant. The auxiliary consumption and energy sent out on many units could not be measured with accuracy due to indiscrete or absent metering. Therefore gross output capability and heat rates should be used for the benchmarking purpose in this study. Conclusions Based on the observations of the audit team, interviews with the power stations management and operational staff and review of historic records of the plants, and capacity and heat rate tests conducted at the operational units, a number of reasons were identified behind the overall decline in the performance of the power stations studied. R1V02TAG: 04/27/11 Executive Summary vi
Quality of RFO None of the samples complied with Pakistan Standard and Quality Control Authority (PSQCA) specifications for RFO. High specific gravity values were obtained due to higher water contents. Only one sample met the standard calorific value of 18,200 Btu/lb. Moreover, the low calorific value up to 8.5% below the minimum permissible limit was observed due to high specific gravity, water and ash contents. Measurement Accuracy of Energy Input and Output The discrete measurement of fuel supplied and energy generated and sent out for each unit of the plant was found to be inadequate. No credible measurement system exists for RFO received from the supplier as well as fed to the installed units from the storage facilities of the plant. The same applies to natural gas supplied and consumed at Guddu power station. At Guddu, the gas supplied to residential colony is not measured. Measurement instruments are either not calibrated, non-functional, or absent. No uniform standards are followed for measurement of energy output. Auxiliary supply is not discrete or fully measured for each unit resulting in inappropriate accounting of auxiliary consumption. Testing quality and procedures adopted by plants internal laboratories are also highly questionable as they lack transparency and quality control. None of the RFO samples complied with Pakistan Standard and Quality Control Authority (PSQCA) specifications in one or more tests. Water and ash contents were found to be higher than the maximum limits prescribed by the PSQCA Lack of Preventive Maintenance A number of maintenance activities are long overdue and have already resulted in loss of output capability, increasing heat rates and lower availability. GENCO managements are forced to delay the overhauling of the plants and are not able to carry out regular preventive maintenance to avoid break-down of the plants for the following reasons: Refusal of shut-down time by the system operator (NTDC) due to shortages in power supply in the country, Delay in payments to GENCOs against power sales, and Delay in procurements of parts and services for plants major overhauling. Poor Housekeeping GENCO managements are paying little attention to simple housekeeping activities which do not require large expenditures. Examples include: Frequent steam leakages in boiler and other steam usages increase heat loss at the plant as well as raise water purification cost due to excessive use of chemicals. A number of critical plant components are not operating at their optimal conditions, causing frequent tripping and breakdowns of the units. R1V02TAG: 04/27/11 Executive Summary vii
Plant management is generally oblivious to environmental conservation and protection. Massive oil spills and un-optimal combustion results in higher rate of toxic emissions and effluent discharges causing environmental threats to adjacent population, flora and fauna. Lack of Performance Evaluation, Monitoring, and Reporting No attention is given to the performance evaluation of the plants and as such no standards are observed to assess the performance of the plants. The present monitoring and reporting system covers a few technical parameters and is not capable to provide a detailed assessment of the plants. Plants are running in manual mode in the absence of modern monitoring and control systems. The absence of performance evaluation standards and an on-line integrated management information system (MIS) severely limits the ability of the management to take prompt decisions and initiate actions and remedial measures for efficient operation of the plants. Limited Financial and Administrative Autonomy Managements of GENCO plants have limited financial autonomy to take independent decisions. Payments to GENCOs are not made on time which results in deferment of maintenance routines which is a major reason behind plant output and efficiency degradation. Approval process for procurement of spare parts and services through international tendering is cumbersome and time consuming. Management is not empowered to initiate a performance-based human resource management system to promote efficiency and competition. The plants are suffering from overstaffing with majority of staff working without specialized industrial training to perform their duties Occupational health, safety, and environmental management system and relevant trainings are not observed at the plants increasing the potential of a safety hazard at the plant Recommendations In order to improve the performance of the GENCOs, the following recommendations are made: A standard measurement and testing protocol needs to be devised for GENCOs for all measurement to avoid errors in financial transactions. GENCOs should carry out a detailed exercise to devise a robust measurement mechanism for RFO receipts at the plants to reduce oil pilferages and acceptance of substandard oil. A third party RFO testing mechanism should be established on regular basis to ensure the quality of fuel received from supplier. The contracts with the fuel R1V02TAG: 04/27/11 Executive Summary viii
supplier should include penalties or correction in price for supply of substandard oil. A detailed management study is required to prescribe key performance indicators pertaining to financial, human and environmental performance of the plant and the procedures to evaluate them on sustainable basis. The Inspection, Testing and Records (ITR) and Maintenance Management System (MMS) sections may be merged to form a Performance Monitoring Section (PMS) at each power station to provide a wider range of performance evaluation and monitoring services. On-line analyzers and instruments with communication channels to a central performance modeling system should be installed to assess the performance and efficiency of the plant on a continuous basis. The PMS should operate this system and advise the operations and maintenance staff on corrective and preventive actions to be taken to meet the performance targets. Special training and workshops should be arranged to educate and train the management and staff about best industrial practices to operate and maintain the power stations. The capacity of in-house repair and maintenance workshops should be enhanced with modern machines, tools and training of staff to provide maintenance services of critical parts locally to reduce down-time There is a need to establish an R&D or a Technical Services section to carryout research on technical and management problems of the power stations and devise solutions Switching to heavier grade RFO will require capital investment in the infrastructure for storage, handling, transportation, and utilization of RFO. A detailed feasibility study including the infrastructure analysis of PSO and required modifications at the steam turbine and diesel engine based power plants and assessment of the resulting cost savings is recommended to ascertain the economics of burning heavier grade fuel oils. The government is currently implementing a Generation and Transmission Improvement Plan (GTIP) for the GENCOs. The resolution of management and operational issues identified in this study require a complete change in the management approach and operational environment of the GENCOs. The government could consider bringing in independent management under a performance based O&M contract based on a structure of incentives and penalties against the performance of the power stations. The terms and conditions of the O&M contract could be designed in a manner to make the contractor responsible for injecting investment for rehabilitation of the units and bringing in highly trained and experienced senior managers. The O&M contractor may be given extended authority to reward and motivate employees and to take disciplinary action and adjust the size of the work force. This approach will help in establishing and expanding the O&M industry and in improving the efficiency of the power sector in the country. R1V02TAG: 04/27/11 Executive Summary ix
Contents 1. Introduction... 1-1 1.1 Objectives and Scope of Work... 1-1 1.2 Study Team... 1-3 1.3 Acknowledgement... 1-3 1.4 Organization of the Report... 1-3 2. Methodology... 2-1 2.1 Limitations of Standard Methodologies and Approach Adopted for the Study... 2-1 2.2 Measurements and Collection of Data on Plant Performance... 2-2 2.3 Testing of Fuel Quality... 2-2 2.4 Testing Arangements and Schedule... 2-3 3. Description of GENCO Plants... 3-1 3.1 Fuel Supply Arrangements... 3-1 3.2 TPS Jamshoro... 3-5 3.3 TPS Guddu... 3-6 3.4 TPS Muzaffargarh... 3-7 4. Maximum Present Capability... 4-1 4.1 General Approach and Overall Limitations... 4-1 4.2 TPS Jamshoro... 4-1 4.3 TPS Guddu... 4-2 4.4 TPS Muzaffargarh... 4-2 5. Heat Rate Analysis... 5-1 5.1 Definitions... 5-1 5.2 Limitations in Assessment of Heat Rates... 5-1 5.2.1 Testing Schedule... 5-1 5.2.2 Measurement of Fuel Flow... 5-1 5.2.3 Metering of Electrical Output... 5-2 5.2.4 Application of Heat Rate Assessment... 5-3 5.3 TPS Jamshoro... 5-3 5.3.1 Testing Procedures and Data Analysis... 5-3 5.3.2 Results... 5-3 5.4 TPS Guddu... 5-5 5.4.1 Testing Procedures and Data Analysis... 5-6 5.4.2 Results... 5-6 5.5 TPS Muzaffargarh... 5-8 5.5.1 Results... 5-8 R1V02TAG: 04/27/11 Contents x
6. Power Plant Availability... 6-1 6.1 Definitions and Limitations... 6-1 6.2 Data and Results... 6-2 6.2.1 TPS Jamshoro... 6-2 6.2.2 TPS Guddu... 6-2 6.3 TPS Muzaffargarh... 6-3 7. Major Reasons for Degradation of Performance... 7-1 7.1 Technical Issues... 7-1 7.1.1 Measurement Accuracy of Fuel Received... 7-1 7.1.2 Fuel Oil Quality... 7-2 7.1.3 Lack of Preventive Maintenance... 7-3 7.1.4 Poor Housekeeping... 7-5 7.2 Management Issues and Recommenadations... 7-7 7.2.1 Lack of Performance Evaluation... 7-7 7.2.2 Limited Financial and Administrative Autonomy... 7-7 7.2.3 Absence of Plant Automation and Management Information System... 7-8 7.2.4 Other Management Issues... 7-9 7.3 Detailed Technical Assessment of GENCOs... 7-10 7.3.1 TPS Jamshoro... 7-10 7.3.2 TPS Guddu... 7-16 7.3.3 TPS Muzaffargarh... 7-26 8. Usage of High Viscosity Fuel Oil in GENCO Power Plants... 8-1 8.1 Fuel Oil Standards... 8-1 8.2 Potential for use in Power Generation in Paksitan... 8-1 8.3 Modifications Required in Fuel Oil Handling at the Power Plants... 8-2 8.4 Modification and Adjustments Required in the Boilers... 8-2 8.5 Fuel Oil Procurement and Supply... 8-3 APPENDICES Appendix A: Fuel Oil Analysis Results Appendix B: Data and Results of the GENCOs Capacity Test Appendix C: Testing Procedures for Measurment of GENCOs Gross and Net Heat Rates Appendix D: Calculation of GENCOs Gross and Net Heat Rates Appendix E: Power Plant Availability R1V02TAG: 04/27/11 Contents xi
Exhibits Exhibit 1.1: Locations of Power Stations Studied... 1-2 Exhibit 1.2: Formation of the Consulting Team... 1-3 Exhibit 3.1: Natural Gas Supply Arrangements at the Power Stations... 3-2 Exhibit 3.2: GENCO wise Installed and Derated Capacities, Plant and Fuel Types, and Efficiencies from PEPCO Statistics... 3-3 Exhibit 3.3: 200 MW Steam Unit No. 2 at TPS Jamshoro... 3-5 Exhibit 3.4: Oil Storage Tanks at TPS Jamshoro... 3-6 Exhibit 3.5: 200 MW Steam Unit No. 3 at TPS Guddu... 3-6 Exhibit 3.6: RFO Storage Capacity at the Power Stations-TPS Guddu... 3-7 Exhibit 3.7: 200 MW Steam Unit No. 6 at TPS Muzaffargarh... 3-8 Exhibit 3.8: Oil Decanting from Railway Wagons and Tank Lorries attps Muzaffargarh... 3-9 Exhibit 3.9: RFO Storage Capacity at the Power Stations-TPS Muzaffargarh... 3-9 Exhibit 3.10: Oil Storage Tanks at TPS Muzaffargarh... 3-10 Exhibit 4.1: Exhibit 4.2: Exhibit 4.3: Unit-wise Installed Capacity and Present Capability TPS Jamshoro... 4-1 Unit-wise Installed Capacity and Present Capability of Units Tested Under the Study TPS Guddu... 4-2 Unit-wise Installed Capacity and Present Capability of Units Tested Under the Study TPS Muzaffargarh... 4-3 Exhibit 5.1: Exhibit 5.2: Exhibit 5.3: Unit-wise Gross and Net Heat Rate and Efficiency TPS Jamshoro... 5-4 Unit-wise Gross and Net Heat Rate and Efficiency TPS Guddu... 5-7 Unit-wise Gross and Net Heat Rate and Efficiency TPS Muzaffargarh... 5-9 Exhibit 6.1: Unit-wise Availability TPS Jamshoro... 6-4 Exhibit 6.2: Unit-wise Availability TPS Guddu... 6-5 Exhibit 6.3: Unit-wise Availability TPS Muzaffargarh... 6-7 R1V02TAG: 04/27/11 Exhibits xii
Exhibit 7.1: Average Degradation in Performance of GENCOs... 7-1 Exhibit 7.2: Summary of Results of Fuel Oil Testing... 7-2 Exhibit 7.3: Poor Maintenance of Insulation at TPS Jamshoro... 7-4 Exhibit 7.4: Steam Leakages at TPS Muzaffargarh... 7-5 Exhibit 7.5: View of a Nonfunctional Soot Blower at TPS Jamshoro... 7-6 Exhibit 7.6: Oil Spillage at Storage Facility at Muzaffargarh... 7-6 Exhibit 7.7: View of the Joint Control Room of Units 3 and 4 at TPS Jamshoro... 7-8 Exhibit 7.8: Smoke Showing Poor Combustion at Unit No. 6 at TPS Muzaffargarh... 7-9 Exhibit 7.9: River Water Quality Supplied at TPS Jamshoro in January 2011... 7-11 Exhibit 7.10: Reasons for Drop in Performance of the Plant TPS Jamshoro... 7-12 Exhibit 7.11: Damaged Air Pre-heater due to Fire of Unit No. 4 at TPS Guddu... 7-16 Exhibit 7.12: Poor Cooling of Turbine Section of Unit No. 3 at TPS Guddu... 7-18 Exhibit 7.13: Reasons for Drop in Performance of the Steam Units TPS Guddu... 7-19 Exhibit 7.14: View of Under Repair Induced Draft Fan of Unit No. 1 at TPS Muzaffargarh... 7-26 Exhibit 7.15: Unit-wise Reasons for Drop in Performance of the Steam Units TPS Muzaffargarh... 7-28 Exhibit 8.1: RFO Specifications ISO 8217:2010... 8-4 R1V02TAG: 04/27/11 Exhibits xiii
1. Introduction Advanced Engineering Associates International (AEAI) engaged to carry out an energy audit of the thermal power stations (TPSs) of the following three state owned power plants: 1. TPS Jamshoro, or the Jamshoro Power Company Ltd., commonly referred to as GENCO I, 2. TPS Guddu, which is a part of Central Power Generation Company Ltd. commonly referred to as GENCO II), and, 3. TPS Muzaffargarh which is a part of Northern Power Generation Company commonly referred to as GENCO III. These thermal power stations are collectively referred to as GENCOs in this report. The locations of these thermal power stations in the country are shown in Exhibit 1.1. 1.1 Objectives and Scope of Work The main objective of the study was to carry out a baseline evaluation or a benchmarking for determining efficiency gains and operational improvements to be achieved through the implementation of the USAID Fixed Amount Reimbursement Agreements (FARA) Repair and Maintenance Plan currently under implementation at these GENCOs. The main features of the scope of work of the study were: Visual inspection of all units of three GENCO power stations, review of the station logbooks and other available records to establish main reasons for the poor performance of the plants and the present generation capacity. Interviews and discussions with the plant managers/operators and determine the reasons for poor performance. Drawing of performance profile of each unit including operating parameters, such as effective output capability, power plant availability, heat rate and efficiency of each unit. Determination of specific fuel consumption and monitor on line calorific value of fuel being injected into each machine. Carrying out a spot fuel oil analysis to determine the heat contents and quality of the fuel oil being supplied to the power stations. Determination of heat rate and efficiency of each unit. Carrying out a brief technical review to assess the potential for using highviscosity fuel oil to reduce the plants generation costs. Preparation and submission of Energy Audit Report for each of the GENCOs. Three teams of power generation experts were formed to carry out the site visits and conduct tests to assess the capacity and heat rates of the operational units of the plants. Introduction R1V02TAG: 04/27/11 1-1
Exhibit 1.1: Locations of Power Stations Studied Introduction R1V02TAG: 04/27/11 1-2
1.2 Study Team The study team consisted of experienced engineers who have been extensively involved in the construction and operation of the power stations studied, and have retired from senior positions at the GENCOs. The names and specific assignment of the consultants involved in the study are listed in Exhibit 1.2. Name of Consultant Exhibit 1.2: Formation of the Consulting Team 1 Manzar Naeem Qureshi Team Leader 2 Muhammad Qasim Shaikh TPS Jamshoro Responsibility 3 Abdul Waris Khan TPS Guddu Combined Cycle Power Station Block 4 Abdul Aziz Chandio TPS Guddu Steam Power Station Block 5 Abdul Karim Leghari TPS Muzaffargarh Additional staff was engaged at each power station to assist the Consultants in taking concurrent meter readings of input and output energy measurements at the power stations. 1.3 Acknowledgement The management of the GENCOs extended their generous cooperation in facilitating the audit teams, and allowed unhindered and unlimited access to power station equipment, instruments, data records and personnel for interviews. HBP management would like to extend their profound gratitude to the management of the GENCOs for their support in completing the assignment. 1.4 Organization of the Report Section 2 of the report describes the methodology used to carry out the capability and efficiency tests for the GENCOs. Section 3 provides an overview of the power stations in terms of configuration and fuel supply arrangements. Section 4 presents the results of the unit-wise maximum capability tests for each power station. Section 5 provides detailed procedures employed for carrying out the heat rate tests and presents the results of heat rate and efficiency for each unit of the power stations. Section 6 shows the unitwise annual availability in terms of load factor, utilization factor and availability. Section 7 provides a detailed account of the main technical and management reasons causing the drop in performance of these power stations. Section 8 sums up the conclusions and recommendations of the study. Introduction R1V02TAG: 04/27/11 1-3
2. Methodology 2.1 Limitations of Standard Methodologies and Approach Adopted for the Study The standard methodologies used by the industry to determine the baseline performance evaluation of steam and combined cycle power plants are ANSI/ASME PTC-6 and ANSI/ASME PTC-46 respectively. Application of these methodologies helps in accurate determination of performance of the power stations and generation of analysis and information for optimization of their performance. These standard methodologies have the following requirements: Availability of accurate and calibrated instrumentation in the power station for online or off-line evaluation of efficiency Trained staff and manpower to carry out detailed measurement procedures under controlled testing conditions Software tools to carry out the component-wise heat balance analysis of the plant Extensive design data and correction curves for the main heat path components such as boilers, turbines, condensers, and cooling towers. Ambient conditions including temperature and humidity, and Data on operating conditions at the inlet and outlet of the main heat path components, such as temperatures, flow rates, and stream composition. None of the GENCOs studied fulfill the requirements listed above. Preparing the GENCOs to fulfill these requirements would require extensive capacity building and installation of necessary instrumentation, which was beyond the scope and schedule of this study. It was therefore not possible to conduct a comprehensive audit of the performance of the GENCOs using the standard industry methodologies given the prevailing conditions and the operating environment in the GENCOs and the time constraints for the study. In view of these limitations, the standard industry methodologies were modified and applied in a simplified manner to measure the capacity and input and output energy of the plants to calculate the heat rate and efficiency, and to work out the plant availability on monthly and annual basis. Industry experience indicates that heat rate test conducted by using formal ASTM-6 procedure has an accuracy of about 3%. Given the poor condition of instrumentation that were not properly calibrated, unusual operating conditions for testing, and improvised test protocols, the accuracy of the heat rate tests under this study could range between 5-10% as per expert judgment. This aspect should be kept in view while comparing the results of benchmarking conducted under this study with the follow-up tests to be conducted after completion of FARA program. Methodology R1V02TAG: 04/27/11 2-1
2.2 Measurements and Collection of Data on Plant Performance Special teams, comprising of instrumentation experts, were formed to carry out tests at each unit. A specific testing protocol was devised for each unit on the basis of its fuel supply systems, instrumentation status, and other operating conditions. The measurement points were marked beforehand and measurement procedures were established keeping in view the operating constraints of the unit. Special proformas were designed to prescribe the measurement specifications and to maintain testing records. Standard conversions and definitions were used to calculate the output and heat rates of the units. The measurement procedures were documented and are presented in Section 5 of this report. Residual fuel oil (RFO) consumption was calculated by using dip-tape, calibration charts of the feeding tanks, and specific gravity of RFO at observed temperatures. Natural gas consumption at TPS Guddu was measured through the meters installed at the units in the power station. Electrical outputs at gross and sent-out meters, and auxiliary consumption were recorded at the metering locations of the units studied. All the readings were taken concurrently and coordination was managed through mobile phones and hand held radio phones. The Consultants did not engage any serving person from the GENCOs for the purpose of assisting the teams in reading of instruments or recording the observations. No unit logsheet entries and event registers were used or consulted for extracting the information and data for the purpose of calculation of heat rates. The Consultants ensured uninterrupted operation of the plants throughout the testing period. The testing schedule was designed to avoid interference with operations and management of the power station. The Consultants relied to the extent possible on the installed measurement instruments, and used their own equipment such as dip-tapes to carry out the assignment where required. 2.3 Testing of Fuel Quality RFO RFO samples were drawn from the main storage tanks of these power stations in accordance with the ASTM methodology; Standard Practice for Manual Sampling of Petroleum and Petroleum Products: D 4057 95 (Reapproved 2000). The parameters studied to assess the quality of RFO included specific gravity, flash point, pour point, water contents, sulfur, ash content and calorific value. A composite sample was drawn from each of the storage tanks consisting of a blend created from the upper, middle, and lower samples from a single tank. The sample was obtained with the help of a specially designed sampling tube also called special thief. The bottom sample was taken from the height of 1.5 to 2.0 meters from bottom of the tank as the outflow of the tank was drawn from the height of 1.0 meters. The samples were packed in aluminum bottles and dispatched to an independent laboratory for testing. In all, eighteen samples were drawn; 4 from TPS Jamshoro; 5 from TPS Guddu; and 9 from TPS Muzaffargarh. Samples were collected during the period of December 29, 2010 to January 5, 2011 and analysis was carried out by Quality Control Laboratory of Attock Refinery Limited, Morgah Rawalpindi. Methodology R1V02TAG: 04/27/11 2-2
2.4 Testing Arangements and Schedule The detailed procedures developed for performance testing of each unit are described in Section 5 of this report. TPS Jamshoro Prior to conducting the performance tests, inspections of all the units at the power plant were carried out in the presence of the representatives of the power station management. The operational conditions of the units were observed and necessary information and details were gathered. Although all the units were in operating condition, the plant management could run only one unit at a time due to shortage of demineralized water. Further, the units could not operate at optimum load on continuous basis for longer periods on RFO firing due to choking of rotary air pre-heaters. Therefore, the Consultant s team faced considerable difficulty in finding an appropriate window of time to carry out heat rate and capacity tests for continuous three days without interruption at optimum operating conditions. Heat rate and capacity tests at the plants were performed in the following sequence: TPS Guddu Unit 1: January 19-21, 2011 for heat rate tests and January 21-23, 2011 for capacity tests Unit 2: January 21-23, 2011 for both heat rate and capacity tests Unit 3 & 4: February 17-19, 2011 for both heat rate and capacity tests Meetings were held with the concerned management of each unit before the beginning of testing. Block 2 B comprising of Units 6, 9 and 10 did not have functional gas flow meters and therefore could not be tested. Similarly, Unit 4 was on long shut down due to break down of air pre-heater. Units 1 & 2 also do not have gas flow meters and therefore were not tested. The testing of these units was deferred until gas flow meters are made operational on all of these units and repair/replacement of air pre-heater of Unit 4. Capacity and Heat Rate Tests at the plants were performed in the following sequence: Unit 3: December 30, 2010 to January 1, 2011 Block 2 A (Unit 5, 7& 8): December 30, 2010 to January 2, 2011 Block 1 (Unit 13, 11& 12): January 3-6, 2011 TPS Muzaffargarh Before undertaking the performance tests, inspection of all the units installed in different phases (1 & 2) was carried out in the presence of representatives of the power station management. The operational conditions of the units were observed and necessary information and details were gathered. Unit 1 was placed under a long shutdown since November 11, 2010 for repair/replacement of super heater tubes. However, the repair/replacement of ends of super-heater tubes was delayed due to arrival of Russian experts of the Original Methodology R1V02TAG: 04/27/11 2-3
Equipment Manufacturer (OEM). The unit could not be restarted until the middle of April 2011 and therefore the performance testing of this unit could not be conducted. Heat Rate Tests & Capacity Tests at the plants were performed in the following sequence: Unit 2 & 3: January 9-11, 2011 Unit 4: January 5-7, 2011 Unit 5 & 6: January 2-4, 2011 Methodology R1V02TAG: 04/27/11 2-4
3. Description of GENCO Plants Total installed capacity of the three power plants studied is 3,855 1 MW out of which 2,840 MW consists of dual fuel steam turbines, and 1,015 MW of gas fired gas turbine combined cycle (CCGT) power plants installed at Guddu. The dual fuel plants operate on pipeline quality natural gas and residual fuel oil (RFO), whereas CCGT units installed at Guddu use medium calorific value (MCV) gas (780-800 Btu/scft). Nearly 90% of the installed capacity of GENCOs is over 15 years old, and is generally in poor condition. Due to the weak financial conditions prevailing amongst power sector entities, the Water and Power Development Authority (WAPDA) which owned the units until 1998 and the Pakistan Electric Power Company Ltd. (PEPCO) which owns them now, have not been able to allocate adequate funds to meet the operational and maintenance expenditures of these plants. These factors have contributed to a gradual loss of effective capacity, efficiency, and dispatch availability of these plants. Consequently, the GENCOs are currently operating their plants at a derated capacity that is 25% below their respective nameplate capacities. The combined cycle units at Guddu, however, are an exception and can operate on full capacity if natural gas injection pressures are restored to the design levels. The average forced outage rate for the GENCOs has been about 12%, compared with 6% for thermal IPPs in the country. Nearly all of the GENCO power plants studied are operating at a much lower efficiency levels than the industry-wide standards for plants of similar age and configuration. Exhibit 3.2 provides a snapshot of the current status, age, and origin of these plants. 3.1 Fuel Supply Arrangements Most of the steam units at the power stations have the provision of dual fuel combustion on natural gas and RFO. Unit 1 at TPS Jamshoro can only operate on RFO. The Steam Units 1-2, and combined cycle units at TPS Guddu operate on MCV gas supplied from Mari, Kandhkot, and Zamzama gas fields. The power station-wise details of the fuel supplies are given below. Natural Gas All the power stations have connections with the utilities for supply of natural gas. However, gas utilities used these plants as swing customers and curtailed the gas supplies during winter to meet the heating demand of the residential and commercial consumers. TPS Jamshoro and TPS Muzaffargarh do not have firm supply contracts with their respective gas supply utilities and therefore receive natural gas only when there is surplus in the national gas network. The county is presently facing a shortfall in the natural gas supplies due to rising gas demand and the gas utilities have been unable to maintain supply of pipeline quality gas to these power stations even during the summer period. 1 Power System Statistics, 34th Edition, 2009 Description of GENCO Plants R1V02TAG: 04/27/11 3-1
Exhibit 3.1 contains the sources and fuel supply arrangements for natural gas for the GENCO plants. Exhibit 3.1: Natural Gas Supply Arrangements at the Power Stations Power Station Gas Supply Source Contract Status TPS Jamshoro Sui Southern Gas Company No firm contract as and when available TPS Guddu Mari Gas Mari Gas Company* 60 MMscfd Kandhkot gas Pakistan Petroleum Limited Zamzama Gas through SNGPL and SSGC networks (110 + 90) MMscfd No firm contract Not supplied since 2005 TPS Muzaffargarh Sui Northern Gas Pipelines No firm contract as and when available * Gas supplies to Guddu from Mari have been reduced to 60 MMscfd from 110 MMscfd after diversion of 50 MMscfd to Fatima Fertilizer from November 27, 2009. Residual Fuel Oil (RFO) RFO is supplied to all GENCOs by Pakistan State Oil (PSO). However, only TPS Muzaffargarh has a fuel supply agreement with PSO, whereas the government has advised TPS Jamshoro and TPS Guddu to purchase RFO from PSO exclusively. PSO mainly supplies the RFO from Karachi through railway tank wagons and tank lorries. GENCO plants are designed to operate on fuel oil having kinematic viscosity of 180 centistokes (cst) during summer and 120 cst during winter. RFO Measurement The GENCOs follow a uniform procedure for measurement of the quantity of RFO received from PSO. The initial volumetric measurement is taken by using dip-sticks for both railway tank wagons and tank lorries and fuel oil volumes are converted to weight for the calculation of payments by using specific calibration charts for the lorries/wagons after applying corrections for temperature and specific gravity of RFO. For tank lorries, the weighbridges are also present at all the power stations. The weight of RFO calculated using dip-sticks is verified at the weighbridges by taking measurements of the tank lorries before and after the oil decanting. Several checks are applied to ensure complete decanting of RFO from tank lorries and railway wagons. The weighbridge measurement is not used for making payments to fuel supplier. All tank lorries and railway wagons are tested for temperature and specific gravity of the fuel oil and about 20-25% are randomly selected for detailed analysis of RFO specifications in the local laboratory of the concerned power station. A small proportion of the samples are also tested through independent laboratories to verify the result of the internal laboratory. RFO that does not meet specifications is rejected for procurement. The results of the third party analysis of the RFO samples collected from GENCO power stations are presented in Appendix-A. Oil Storage All the power stations have their own RFO storage facilities at their premises for storage of 20-30 day requirement of RFO. Description of GENCO Plants R1V02TAG: 04/27/11 3-2
Plant TPS Jamshoro Exhibit 3.2: GENCO wise Installed and Derated Capacities, Plant and Fuel Types, and Efficiencies from PEPCO Statistics Installed Capacity Year of Commissioning Fuel Country of Origin Thermal Efficiency (Design) Unit 1 250 January 1990 RFO Japan 36.6% Unit 2 200 December 1990 Natural Gas/RFO China 33.9% Unit 3 200 June 1990 Natural Gas/RFO China 33.9% Unit 4 200 January 1991 Natural Gas/RFO China 33.9% TPS Guddu Steam Unit 1 110 1974 Natural Gas Czech Slovakia 28.0% Unit 2 110 1974 Natural Gas Czech Slovakia 28.0% Unit 3 210 1980 Natural Gas/RFO USSR 30.0% Unit 4 210 1980 Natural Gas/RFO China 30.0% CCGT Block 2-A GT-7 100 December 1985 Natural Gas USA 31.7% GT-8 100 March 1986 Natural Gas 31.7% ST-5 100 December 1987 N/A CCGT Block 2-B GT-9 100 April 1986 Natural Gas USA 31.7% GT-10 100 April 1986 Natural Gas 31.7% ST-6 100 March 1988 N/A Description of GENCO Plants R1V02TAG: 04/27/11 3-3
Plant CCGT Block 1 Installed Capacity Year of Commissioning Fuel Country of Origin Thermal Efficiency (Design) GT-11 136 September 1992 Natural Gas Germany 32.1% GT-12 136 December 1992 Natural Gas 32.1% ST-13 143 May 1994 N/A TPS Muzaffargarh Unit 1 210 September 1993 Natural Gas/ RFO Russia 36.8% Unit 2 210 March 1994 Natural Gas/ RFO Russia 36.8% Unit 3 210 February 1995 Natural Gas/ RFO Russia 36.8% Unit 4 320 December 1997 Natural Gas/ RFO China 36.7% Unit 5 200 February 1995 Natural Gas/ RFO China 31.7% Unit 6 200 August 1995 Natural Gas/ RFO China 31.7% Source: Power System, Statistics, 34 th Edition, 2009. Description of GENCO Plants R1V02TAG: 04/27/11 3-4
3.2 TPS Jamshoro TPS Jamshoro is one of the major generation installation connected to the National Grid System in the south of Pakistan. The present installed capacity of TPS Jamshoro is 850 MW consisting of four steam power units. Exhibit 3.3 shows 200 MW Steam Turbine Unit No. 2 at TPS Jamshoro. Exhibit 3.3: 200 MW Steam Unit No. 2 at TPS Jamshoro The staff strength at the power station is 1,550. About 50% of the staff is residing in the residential colony with their families built adjacent to the power house. The residential colonies provide all the basic and civil amenities like school, hospital, recreational centers, playgrounds, mosques, and shopping centers to cater for the needs of the employees. Water supply for cooling and drinking is taken from the Indus River through a pipeline and pumping station network. For drinking purpose, the river water is only clarified whereas for supply to the power plant it is treated further to produce demineralized water for boilers. RFO decanting: TPS Jamshoro has decantation arrangements for both railway tank wagons and road tankers. However, the power station receives RFO only through tank lorries from Karachi as delivery through railway was discontinued in 2003. The station has two arrangements for decanting of RFO from tank lorries and railway wagons; an open channel and an oil receiving header. The channel is normally used during dry weather whereas the oil header was initially constructed to decant oil during rainy periods but it is used round the year due to increasing number of incoming tank lorries. Oil is lifted by transfer pumps from the channel and header into storage tanks. In recent times, Description of GENCO Plants R1V02TAG: 04/27/11 3-5
RFO Storage: TPS Jamshoro has common RFO storage facilities for all units. It has 4 main storage tanks of 26,500 tonnes each having a total storage of 106,000 tonnes at the plant. These tanks are interconnected and used as common storage for all units. Exhibit 3.4 shows the oil storage facilities at TPS Jamshoro. Exhibit 3.4: Oil Storage Tanks at TPS Jamshoro 3.3 TPS Guddu TPS Guddu has both steam and combined cycle units that operate on medium calorific value (MCV) gas from Mari, Kandhkot and Chachar. Exhibit 3.5 shows a view of the turbine hall of 200 MW Steam Unit No. 3 at TPS Guddu. Exhibit 3.5: 200 MW Steam Unit No. 3 at TPS Guddu Description of GENCO Plants R1V02TAG: 04/27/11 3-6
The plant has a staff of about 1,950 persons living with their families at the residential colony built adjacent to the powerhouse. Civil amenities like schools, hospitals, recreational centers, playgrounds, mosques, and shopping centers have been provided at the cost of the company to cater for the needs of the employees. Water supply for cooling and for boiler feed water is taken from the Indus River through a pipeline and pumping station network at the nearby Begari Feeder, Sindh. For drinking purposes, the water taken from the canal is clarified and supplied through overhead tanks. Water is treated to produce demineralized water for boiler feed and other usage at the plant. TPS Guddu is the major generation installation connected to the national grid system in Pakistan in the middle of the country. The other important feature of this plant is that it generates electricity on MCV gas to provide electricity at a comparatively lower cost to national grid. Oil Decanting: The power station has decantation arrangement for road tankers. Oil is decanted into a channel and lifted by transfer pumps into storage tanks. Oil Storage: TPS Guddu has common storage facilities for the steam units 3 & 4. The plant has 9 storage tanks with total capacity of 56,400 tonnes of RFO. Exhibit 3.6 shows the RFO storage facilities at the power stations. Exhibit 3.6: RFO Storage Capacity at the Power Stations-TPS Guddu Power Station Unit No. No. of FO Tanks Capacity of each Tank (Tonnes) Total Storage Capacity (Tonnes) TPS Guddu 2 12,000 24,000 3.4 TPS Muzaffargarh 4 5,000-5,500 21,000 3 3,800 11,400 Total 9 56,400 TPS Muzaffargarh is connected to the National Grid System in the mid-country near major load centers. The present installed capacity of TPS Muzaffargarh is 1,350 MW consisting of six steam power units. The Exhibit 3.7 shows the 200 MW Steam Turbine of Unit No. 6 at TPS Muzaffargarh. Description of GENCO Plants R1V02TAG: 04/27/11 3-7
Exhibit 3.7: 200 MW Steam Unit No. 6 at TPS Muzaffargarh The plant has staff strength of around 1,500 personnel most of which live with their families in the residential colony built adjacent to the powerhouse. Like other GENCO plants, the staff residential colony provides the civil amenities like school, hospital, recreational centers, playgrounds, mosques, and shopping centers. Water for cooling and drinking purpose is supplied through 35 Tube-wells, which are installed along the banks of Taliri canal flowing 8Km away in the east. Muzaffargarh Thermal Power Plant is the major generation installation connected to the National Grid System in Pakistan in the middle of the country. Oil Decanting: The power station has decantation arrangements for both railway tank wagons as well as tank lorries. Similar to TPS Jamshoro, the oil is decanted into a deep channel and lifted by transfer pumps into storage tanks. The decantation of RFO at Unit 4 as well as Unit 5 & 6 is carried out through oil receiving headers. Presently, only the header for Unit 4 is operational. Exhibit 3.8 shows the RFO decanting station with both railway wagons and tank lorries off-loading oil. Description of GENCO Plants R1V02TAG: 04/27/11 3-8
Exhibit 3.8: Oil Decanting from Railway Wagons and Tank Lorries at TPS Muzaffargarh Oil Storage: Each phase of TPS Muzaffargarh has its own dedicated storage facilities that have now been interconnected and can supply fuel to all the operating units. The power station has 11 storage tanks with a maximum capacity of around 241,000 tonnes. Exhibit 3.9 shows the phase-wise installed RFO storage capacity at the power stations. Exhibit 3.10 shows the Oil Storage Facilities at TPS Muzaffargarh. Exhibit 3.9: RFO Storage Capacity at the Power Stations-TPS Muzaffargarh Power Station Unit No. No. of FO Tanks Capacity of each Tank (Tonnes) TPS Muzaffargarh Total Storage Capacity (Tonnes) 1, 2 & 3 6 20,000 18,500 120,000 to 111,000 4 2 20,000 ~ 18,500 40,000 37,000 5 & 6 3 27,000 ~ 25,000 81,000 75,000 Total 11 241,000-223,000 Description of GENCO Plants R1V02TAG: 04/27/11 3-9
Exhibit 3.10: Oil Storage Tanks at TPS Muzaffargarh Description of GENCO Plants R1V02TAG: 04/27/11 3-10
4. Maximum Present Capability 4.1 General Approach and Overall Limitations The capacity tests were carried out under certain limitations and restrictions specific to each unit of the power plants. Most of the units could not be operated, even for a shorter duration of time, under full opening of the turbine steam control valve, as recommended under ASME PTC-6, to assess their maximum output capability. Based on their experience, the management had apprehended risk of damage to heater tubes in the boilers and other risks if the boilers were operated above certain loads. Owing to these reasons and the prevailing shortage of power generation capacity in the country, it was agreed with the power station managements that the units will be operated in safe mode for testing purposes to avoid any disruption in operations. The capacity tests were carried out for continuous operation of each unit for 3-4 hours at a time with gross and net output capacity observed and recorded at an interval of one hour. The test was carried out for three days at a unit. The gross and net capability of the unit was calculated on the basis of average readings over the testing period. Detailed data on capacity measurements for each unit of the Jamshoro, Guddu and Muzaffargarh power stations is provided in Appendix B as Exhibit B.1, B.2 and B.3 respectively. 4.2 TPS Jamshoro Limitations of Test: The speed governors of Units 2-4 were not functioning on auto control. The load was therefore adjusted manually to maintain output at a certain level. In case of Unit 1, the output of the unit was temporarily reduced to 187 MW from 200 MW because of overheating of turbine bearing. Results: The results of the capacity tests for TPS Jamshoro are presented in Exhibit 4.1. The capacity tests indicated a maximum degradation of around 40% for Unit 2 from its design capacity and a minimum degradation of around 23% for Unit 1. The overall power station capability has dropped by 32% in the present operating conditions. Unit No. Exhibit 4.1: Unit-wise Installed Capacity and Present Capability TPS Jamshoro Installed Capacity Present Gross Capability Auxiliary Load Present Net Capability MW MW MW MW Capacity Degradation Unit 1 250 191 15 176 23% Unit 2 200 119 6 112 41% Unit 3 200 125 12 113 38% Unit 4 200 146 13 133 27% Total 850 581 46 535 32% Maximum Present Capability R1V02TAG: 04/27/11 4-1
4.3 TPS Guddu Limitations of Test: The gas flow meters of steam Unit 1 and Unit 2 and CCP Block 2B were not functional and therefore tests could not be carried out for these units. Steam Unit 4 was on extended shut down from December 11, 2010 to March 15, 2011 due to damaged air preheater and therefore could not be tested in the timeframe of this study. Gas flow meters for CCP Block 1 and Block 2-A were functional and capacity tests were therefore carried out at these two units only. Results: CCP Block 1 has shown 40% degradation in its capacity from the installed capacity whereas CCP Block 2-A appears to be in better condition with only 17% capacity degradation, most of which was contributed by the steam turbine Unit 5 which has lost about 29% of its capacity. Exhibit 4.2 provides the unit-wise installed capacity and present capability of the units assessed under the testing procedures. Exhibit 4.2: Unit-wise Installed Capacity and Present Capability of Units Tested Under the Study TPS Guddu CCP Block 1 Installed Capacity Present Gross Capability Auxiliary Load Present Net Capability MW MW MW MW Capacity Degradation GT 11 100 93 92 7% GT 12 100 85 85 15% ST 13 100 71 1 69 29% Total Block 1 300 248 2 246 17% CCP Block 2-A GT 7 136 80 80 41% GT 8 136 80 80 41% ST 5 143 84 3 81 41% Total Block 2-A 415 244 4 240 41% Total 715 493 6 487 31% 4.4 TPS Muzaffargarh Limitations of Test: Unit 1 was on extended shut down from November 2010 to end of March 2011 due to delay in arrival of experts from the Russian manufacturer of equipment to supervise the replacement work. Units 2-6 were tested. Results: Results of capacity tests for Units 2-6 are presented in Exhibit 4.3. Significant degradation was observed on all units when compared with their respective design capacities. Unit 2 was in the best operating condition with 20% degradation in capacity whereas Unit 6 was the worst with 63% degradation in capacity. Maximum Present Capability R1V02TAG: 04/27/11 4-2
Unit No. Exhibit 4.3: Unit-wise Installed Capacity and Present Capability of Units Tested Under the Study TPS Muzaffargarh Installed Capacity Present Gross Capabilit Auxiliary Load Present Net Capability MW MW MW MW Capacity Degradation Unit 2 210 168 11 156 20% Unit 3 210 140 13 127 33% Unit 4 320 202 21 181 37% Unit 5 200 97 11 86 51% Unit 6 200 73 10 64 63% Total 1,140 680 66 614 40% Maximum Present Capability R1V02TAG: 04/27/11 4-3
5. Heat Rate Analysis 5.1 Definitions The following definitions were followed in the analysis of heat rates: Heat Rate: Heat rate of a plant is the amount of thermal energy required to generate one unit of electrical energy and is generally expressed as K calories/kwh or Btu/kWh. In this report, Btu/kWh has been adopted as the standard units for heat rate. Thermal Efficiency: Thermal efficiency of the power plant also simply referred to as the efficiency of the plant is the ratio of the output energy to the input energy of the plant. It is usually calculated as 3,412/ (heat rate of the plant) expressed in Btu units. Gross and Net Efficiency: Both the heat rate and efficiency could be gross or net depending on the point of measurement of the output of the plant. The gross efficiency is the ratio of the total energy generated from the plant to the total energy input whereas the net efficiency is calculated as the ratio of total energy sent-out from the plant to the total energy input of the plant. The energy sent-out is calculated by subtracting auxiliary consumption of the plant and losses of plant s cable and step-up transformer from the gross generation of the plant. In certain cases, a discrete sent-out meter is installed at the plant that can provide a direct measure of the energy sent out from the plant. 5.2 Limitations in Assessment of Heat Rates A number of limitations were encountered in carrying out the heat rate tests and efficiency in nearly all the cases. These are summarized in the following sections. 5.2.1 Testing Schedule The GENCO power stations do not have functional flow meters to measure the fuel oil supplied to each unit in continuous manner over a specified period. Oil measurements were taken by using dip-tapes from the service tank or main storage tank depending on the specific arrangement for each unit. Service tanks are smaller in size and provide storage of 3-4 hours of unit s consumption and need to be refilled every 4 hours. The refilling process takes about 1-2 hours. The testing team was working in single shift and therefore could only record observations during daytime working hours. Owing to these reasons, heat rate tests were carried out for continuous operation of each unit for 2-3 hours at a time with input and output energy observed and recorded. The test was carried out once in the morning and once in the afternoon and continued for three days to capture variations in the heat rates under different operating conditions of the unit. The present gross and net heat rates and resulting efficiency of the plant were calculated on the basis of average of the observed readings over the testing period. 5.2.2 Measurement of Fuel Flow The steam units at the power stations studied have the provision of dual fuel combustion on natural gas and RFO with the exception of Unit 1 at TPS Jamshoro that can only operate on RFO and the Units 1-2 and combined cycle units at TPS Guddu that operate Heat Rate Analysis R1V02TAG: 04/27/11 5-1
on medium calorific value (MCV) gas. However, as gas was not being supplied to the plants during the study period, the heat rates of all the dual fuel steam units were tested on RFO. It was observed that the GENCOs have not followed a standard fuel supply arrangement. No credible measurement system was in place for the RFO received from supplier at the power plants. Similarly, no credible measurements were being taken for the RFO fed to each unit from plant s main storage. Most of the measurement instruments were either not calibrated, non-functional, or simply missing. At TPS Muzaffargarh and TPS Guddu, many units have common fuel supply pipelines without adequate measurement instruments at each unit. Similarly, a number of units do not have RFO service tanks to monitor their fuel flow. The same is the case at Guddu where gas flow meters are mostly missing and gas is supplied through common pipelines to the steam and CCGT units. It was therefore quite a challenge to discretely measure the fuel input at most of the units. RFO consumption was calculated by using dip-tape, calibration charts of the feeding tanks (the specific day storage or service tank or the main storage tank, where a day tank is not present), and specific gravity of RFO at observed temperatures. The input valves of the respective feeding tanks of the concerned units were closed before the beginning of the tests and sealed with locks to stop inflow of RFO and recirculation of RFO and condensate. Electrical outputs at gross and sent-out meters, and auxiliary consumption were recorded at the respective meter locations. All the readings at a specific time were taken concurrently and coordination was managed through use of devices such as mobile phones and RF radio equipment. Special teams, comprising of instrumentation experts, were formed to concurrently read the measurement instruments to carry out tests at each unit. At TPS Guddu, the residential colony is also supplied gas from the header meant for steam Units 1 and 2 with no gas measurement for the residential colony. The residential gas consumers have individual gas meters at their premises but due to severe leakages in the gas distribution network, the consumers are charged a flat rate with respect to size of their houses. 5.2.3 Metering of Electrical Output The same applied to the output side of the plants as no uniform standards are followed for measurement of energy output. Auxiliary supply is not discrete for certain units resulting in inappropriate accounting of auxiliary consumption. In many instances, auxiliary consumption is not even fully measured. The units at TPS Muzaffargarh do not have discrete sent-out meters at each unit to record net output. In case of TPS Jamshoro, the measurement scale of the sent-out meter was in GWh at the NTDC grid station, giving little resolution to measure the difference in kwh. The cable and step-up losses could not be calculated at any instance due to absence of appropriate metering protocol and therefore were not included in the calculation of net heat rate and efficiency. It was therefore recommended to use the gross heat rates and efficiency as the baseline or benchmark for the purpose of this study instead of net heat rate and efficiency. Heat Rate Analysis R1V02TAG: 04/27/11 5-2
5.2.4 Application of Heat Rate Assessment The heat rates and efficiency parameters for the power stations have been calculated only for the purpose of baseline evaluation or a benchmark for determining efficiency gains and operational improvements to be achieved after the implementation of the USAID FARA Repair and Maintenance Plan currently under implementation at these GENCOs. It should be noted that heat rates in this study were determined under steady loading and specific ambient and operating conditions of the units during the winter season. Average heat rates for the power stations are likely to be higher due to variations in ambient conditions and loading levels, inclusive of startups and shutdowns. 5.3 TPS Jamshoro 5.3.1 Testing Procedures and Data Analysis TPS Jamshoro has four dual fuel steam units that were operating on RFO only during the testing period. Heat rate tests were carried out for all the units of the power station. The specific procedure for calculation of heat rates for TPS Jamshoro is illustrated in Appendix C. The unit-wise detailed data compiled on heat rate measurements for TPS Jamshoro is presented in Appendix D as Exhibit D.1. 5.3.2 Results The gross and net heat rate and efficiency for the generation units at TPS Jamshoro are presented in Exhibit 5.1. Unit 1 is most efficient with 32% net efficiency against the design efficiency of 36.6%. The net efficiencies of Units 2-4 ranged between 25.7% to 28.6% against the design efficiency of 34%, corresponding to an overall drop in the efficiency of the power station of about 20% compared to the design. Heat Rate Analysis R1V02TAG: 04/27/11 5-3
Unit No. Gross Energy Generation (kwh) Exhibit 5.1: Unit-wise Gross and Net Heat Rate and Efficiency TPS Jamshoro Fuel Consumption (Mmbtu) Gross Heat Rate (Btu/kWh) Gross Efficiency* Auxiliary Consumption (kwh) Net Sent-out Energy (kwh) Net Heat Rate (Btu/kWh) Net Efficiency (%) Unit 1 2,786,946 27,392 9,829 34.7% 231,862 2,555,084 10,720 31.8% Unit 2 1,361,912 15,971 11,727 29.1% 83,370 1,278,542 12,492 27.3% Unit 3 1,242,596 14,761 11,879 28.7% 129,597 1,112,999 13,262 25.7% Unit 4 1,422,838 15,521 10,909 31.3% 122,336 1,300,502 11,935 28.6% * Gross heat rates and efficiency is recommended to be used for benchmarking purpose. Heat Rate Analysis R1V02TAG: 04/27/11 5-4
5.4 TPS Guddu TPS Guddu has two main set of power generation units, a steam block and a Combined Cycle Power Station (CCP) block. In the steam block complex, the plant has four (4) steam units out of which Units 1 and 2 can operate only on natural gas. Units 3 and 4 are dual fuel on natural gas and RFO. In the CCP block, the plant has three combined cycle sub-blocks of (2 GT+1 ST) gas fired CCGT. The plant receives MCV gas from Mari, Kandhkot and Chachar. Measurement of Fuel Supply TPS Guddu has major shortcomings with respect to fuel measurement both on supply side as well as for the consumption in the power plant. No gas sales meters are installed by the gas suppliers at the premises of the plant and gas is billed from the meters installed at the supplier end of the pipelines. Gas from various supply sources is mixed at a gas mixing station on the plant s premises. The mixing station has separate headers for steam and CCP blocks from where it is branched through separate pipelines to each unit. The gas is supplied at a pressure for of 11 bar to steam units and at 23 bar to CCP. No measurements are taken for the outflow of gas from mixing headers. Units 3 and 4 have functional gas flow meters whereas Units 1 and 2 are operating without the gas flow meters. Units 1 and 2, therefore, have no gas inflow measurements to establish the input energy for the purpose of calculation of heat rate and efficiency. The heat rate and capacity testing of Units 1 and 2 was postponed until installation of appropriate gas metering system on supply of gas to each unit. Fuel oil is also supplied to Units 3 and 4 through a common line with no service tanks but the two units have separate RFO flow meters to measure their respective RFO consumption. The testing of Unit 4 could not be carried out due long shut down caused by damage of air pre-heater. Testing was limited to Unit 3 for these reasons. The pipelines supplying gas to CCP block also do not have a gas meter at the gas mixing header. Out of three CCP sub-blocks, the Block 2-B does not have functional gas flow meters to measure gas consumed in the gas turbines (Unit 9 and 10). Gas consumption of Block 2 B could therefore not be ascertained for calculation of the heat rate and efficiency of this block. Attempts were made to establish fuel input of the steam Units 1 and 2 and that of CCGT Block 2-B by using secondary data from the plant operations. Due to absence of credible data, gas consumption of these units could not be segregated. It was therefore decided to postpone the heat rate and capacity testing of these units until installation of appropriate gas metering system. Measurement of Energy Output On the output side, all units at TPS Guddu have their individual gross energy generation meters. However, the steam units do not have adequate metering on their auxiliary supply as well as that of sent-out energy. Unit wise auxiliary load for steam units was calculated on the basis of connected auxiliary load at a fixed rate of 8% of gross generation. The sent-out energy was calculated by subtracting the estimated auxiliary consumption from gross generation. All the CCP blocks have appropriate meters for Heat Rate Analysis R1V02TAG: 04/27/11 5-5
gross generation, auxiliary consumption and energy sent-out. Therefore, it is again recommended to use gross heat rates and efficiency for the benchmarking of steam units. 5.4.1 Testing Procedures and Data Analysis Specific procedures were developed to carry out energy measurements for steam and CCP blocks of the power station which have been illustrated in Appendix C. The unitwise detailed data compiled on heat rate measurements for TPS Guddu is presented in Appendix D as Exhibit D.2. 5.4.2 Results The summary of results of heat rate tests for TPS Guddu is presented in Exhibit 5.2. The heat rate test of the Guddu Steam Unit 3 showed inaccurate results in terms of its efficiency higher than the design efficiency of the unit. It appears the measurement of the existing gas flow meter is not reliable and it was showing lower consumption of gas than the actual. The heat rate test of Unit 3 therefore was rejected. The gas turbines (GTs 7 and 8) in Block 2-A showed the net efficiencies of 27.8% each against the design efficiency of 31.7%. The GT 11 and GT 12 in Block 1 showed the net efficiencies of 26.5% and 25.3% respectively against the design efficiency of 32.1%. The net efficiency of the Block a-a and Block 1 were calculated to be 35.3% and 41.5%. The design efficiencies of these clocks under combined cycle operations were not provided by the management. Heat Rate Analysis R1V02TAG: 04/27/11 5-6
CCP Block 1 Gross Energy Generation (kwh) Exhibit 5.2: Unit-wise Gross and Net Heat Rate and Efficiency TPS Guddu Fuel Consumption (MMBtu) Gross Heat Rate* (Btu/kWh) Gross Efficiency* (%) Auxiliary Consumption (kwh) Net Sent-out Energy (kwh) Net Heat Rate (Btu/kWh) Net Efficiency (%) GT 11 7,192,000 92,347 12,840 26.6% 31,360 7,160,640 12,896 26.5% GT 12 6,633,000 88,962 13,412 25.4% 26,880 6,606,120 13,467 25.3% ST 13 5,116,000 110,000 5,006,000 0.0% Total Block 1 18,941,000 181,309 9,572 35.6% 168,240 18,772,760 9,658 35.3% CCP Block 2-A GT 7 6,346,000 77,396 12,196 28.0% 33,685 6,312,315 12,261 27.8% GT 8 6,320,000 77,331 12,236 27.9% 18,701 6,301,299 12,272 27.8% ST 5 6,482,000 267,000 6,215,000 0.0% Total Block 2-A 19,148,000 154,727 8,081 42.2% 319,386 18,828,614 8,218 41.5% * Gross heat rates and efficiency is recommended to be used for benchmarking purpose. Heat Rate Analysis R1V02TAG: 04/27/11 5-7
5.5 TPS Muzaffargarh TPS Muzaffargarh has six steam units installed in two phases. Phase 1 consists of Units 1-3, and Phase 2 units 5-6. Unit 4 at TPS Muzaffargarh is managed separately by a Resident Engineer. Unit 1 of phase 1 was on extended shut down during the testing period so heat rate tests could not be carried out. TPS Muzaffargarh does not have individual net output meters at each unit as each unit directly feeds to common busbars at the switchyards. Unit wise net output, therefore, was calculated by subtracting auxiliary consumption from gross generation. The detailed procedure for calculation of heat rate for each unit is given here under. The specific procedures for calculation of heat rates for TPS Muzaffargarh at each phase of the power station are illustrated in Appendix C. The unit-wise detailed data compiled on heat rate measurements for TPS Muzaffargarh is presented in Appendix D as Exhibit D.3. 5.5.1 Results The unit wise gross and net heat rate and efficiency of TPS Muzaffargarh are presented in Exhibit 5.3. Units 2 and 3 are in better condition with 31% net efficiency compared with their design efficiency of 36.8%. Unit 4 has a net efficiency of 30% against 36.7% design efficiency. Units 5 and 6 have efficiencies of 26% and 24% respectively against the design efficiency of 31.7% for both units. The power station is facing an overall degradation of around 18% in its net efficiency. Heat Rate Analysis R1V02TAG: 04/27/11 5-8
Unit No. Gross Energy Generation (kwh) Exhibit 5.3: Unit-wise Gross and Net Heat Rate and Efficiency TPS Muzaffargarh Fuel Consumption (MMBtu) Gross Heat Rate* (Btu/kWh) Gross Efficiency* (%) Auxiliary Consumption (kwh) Net Sent-out Energy (kwh) Net Heat Rate (Btu/kWh) Net Efficiency (%) Unit 1 Unit 2 3,665,000 36,870 10,060 33.9% 246,074 3,418,926 10,784 31.6% Unit 3 3,083,000 30,655 9,943 34.3% 237,521 2,845,479 10,773 31.7% Unit 4 4,982,400 50,468 10,129 33.7% 521,000 4,461,400 11,312 30.2% Unit 5 1,757,700 20,010 11,384 30.0% 221,585 1,536,115 13,026 26.2% Unit 6 1,409,940 17,455 12,380 27.6% 197,128 1,212,812 14,392 23.7% * Gross heat rates and efficiency is recommended to be used for benchmarking purpose. Heat Rate Analysis R1V02TAG: 04/27/11 5-9
6. Power Plant Availability 6.1 Definitions and Limitations The availability of the plant is best represented by the Plant Availability Factor which is calculated as: Plant Availability = (Running Hours / Total Hours over the period x 100) Equation 6.1 This expression is further expanded to include the capacity lost due to constrained low load operations over certain duration and is modified as: Plant Availability = (Σ Running Hours x load served during low load operations+ Running Hours x Rated Capacity of the plant) x 100/ (Total Hours over the period x Rated Capacity of the plant) Equation 6.2 As power plants are subject to planned and unforeseen shutdowns, it is normal practice to calculate plant availability over a longer duration such as on monthly or annual basis. In view of the short visits to the plants during this study, no tests were carried out to calculate the plant availability. Instead, plant availability was assessed on the basis of the data compiled and reported by the power station management under the monthly E-forms 2 for the period of July 2009-November 2010. GENCOs also do not follow any standards for plant availability. In Pakistan, the Independent Power Producers (IPPs) set up under the 1994 Power Policy were allowed a minimum of 85.7% plant availability that include allowances of 8.3% and 6% for planned and forced outages respectively. The partial outages are also counted for the IPPs in their availability calculations. Further IPPs outages during high demand months are given higher weightage than those during low demand months. In later power policies, government has further tightened the standards for IPPs by raising the plant availability top 89%. Plant availability factor for GENCOs should be worked out using Equation 6.2 by including the impact of both the outages and the low load operations (partial outages). However, GENCOs report availability factor in E-forms on the basis of full outages only, by using the simplified Equation 6.1. However, the impact of low load operations (partial outages) can be captured by taking the other performance indicators in to consideration such as Plant Utilization Factor 3 and Plant Load Factor 4 for the same 2 3 4 E-forms is a standard reporting template used by GENCOs to assess and report the performance of individual units and power station on monthly basis. At the completion of a fiscal year, an annual E-form is generated at the pattern of monthly E-form. Major parameters indicated in the E-form are units generated, units sent out, auxiliary consumption, fuel consumption, heat rates, maximum load, minimum load, load factor, utilization factor, capacity factor, forced and planned shut-down hours, and plant availability. Plant Utilization Factor is the ratio of Units generated in KWh and the product of the de-rated Load in KW and hours of the period over which the calculations are made. Plant Load Factor is the ratio of Units generated in KWh and the product of the maximum Load in KW and hours of the period over which the calculations are made Power Plant Availability R1V02TAG: 04/27/11 6-1
period. These indicators give a good indication of the generation capability of the plant over that period. It must be noted that GENCOs report Plant Utilization Factor on the basis of derated capability of the units that shows higher plant utilization. In order to provide the true perspective of the plant availability, it is recommended that all power plant performance indicators, such as load factor, utilization factor, capacity factor and availability factor, should be worked out on the basis of the installed capacity so as to reflect the true picture of the plant. 6.2 Data and Results The consultants requested the management of GENCOs to provide hourly loading profile and outage record in electronic form for all units for the period of July 2009 to November 2010 to assess the plant availability parameters. The management claimed that they do not prepare the hourly loading and outage profile in electronic form due to shortages of trained staff. Instead they provided unit-wise tripping data and monthly E-form for the specified period that contained summary of the availability parameters. Despite the definitions and quality issues, the availability data was taken from the E-forms of the power stations after carrying out spot checks on the accuracy of data. 6.2.1 TPS Jamshoro Unit wise data compiled on power plant availability on monthly basis for TPS Jamshoro is presented in Appendix E as Exhibit E.1. Unit wise performance parameters representing power plant availability on annual basis for TPS Jamshoro are summarized in Exhibit 6.1. Units 2-3 have shown good availability ranging between 84% to 90% during FY2010 as the units were operated in safe (derated) mode by the management. However, if the Plant Availability Factor was corrected for derated output of the units, the availability of the units would have dropped further by 20-25%, well below the standards maintained by the IPPs. Lower availability of the Units 2-4 ranging between 58% tom 78% during FY2011 is mainly due to shortage of demineralized water for boiler operations. The large difference in the load factor and utilization factor based on installed capacity is a good indicator that plant was not able to operate on its rated output for most of the time. 6.2.2 TPS Guddu Unit wise data compiled on power plant availability on monthly basis for TPS Guddu is presented in Appendix E as Exhibit E.2. Unit wise performance parameters representing power plant availability on annual basis for TPS Guddu are shown in Exhibit 6.2. The availability of CCP Block 2-A and Block 1 was mostly above 90% due to operation on natural gas. CCP Block 2-B was low during FY2010 due to extended shut downs from November 2009 to May 2010 needing major overhaul that has been delayed due to procurement of spare parts and availability experts from the supplier. The availability of this block improved in FY2011 due to improvement in gas turbine operations. Steam Unit 6 was not available till November 2010 due to a major overhaul. The availability of steam Unit 1 has been low at 60% during FY2011. The availability of steam block otherwise has generally been shown good ranging between 82% to 93% but Power Plant Availability R1V02TAG: 04/27/11 6-2
like TPS Jamshoro, it should be interpreted with caution due to operation on derated output. 6.3 TPS Muzaffargarh The unit wise data compiled on power station availability on monthly basis for TPS Muzaffargarh is presented in Appendix E as Exhibit E.3. Unit wise performance parameters representing power plant availability on annual basis for TPS Muzaffargarh are shown in Exhibit 6.3. The output capability of all units of Muzaffargarh has declined over the past two years with average degradation recorded over 40%. It appears that management is gradually reducing the output capability of these units to improve the availability of the units. Unit 5 was operated at a maximum of 120 MW in FY2010 compared with 200 MW of installed capacity and performed poorly with 47% availability but it improved 74% at lower load. The availability of Unit 4 dropped from 97% in FY2010 to 60% in the FY2011 along with a reduction in the maximum output of the unit of about 20% from the previous year. Units 1 and 2 have shown consistent availability of over 80% but have shown a decline of 31% and 45% in their respective output capabilities from the previous year. The availability of Unit 6 has been steady at around 75% but this unit too was operating at only 135 MW during FY2010 and further decreasing to 95 MW during FY2011 compared with 200 Mw of installed capacity. These performance indicators clearly indicate low reliability levels in GENCOs that are mainly due to lack of preventive maintenance and curtailing the operational and maintenance expenditures. Power Plant Availability R1V02TAG: 04/27/11 6-3
Unit No. Period Installed Capacity (IC) Derated Capacity (DC) Exhibit 6.1: Unit-wise Availability TPS Jamshoro Maximum Load Minimum Load Load Factor Utilization Factor Scheduled Outage Forced Outage Availability Availability Factor (Time-base) MW MW MW MW (%) (%) (Hrs.) (Hrs.) (Hrs.) (%) Unit 1 FY2010 250 187 200 63 64% 50% 1,592 737 6,431 73% FY2011 YTD 180 63 68% 53% 481 245 2,946 80% Unit 2 FY2010 200 160 180 90 75% 75% 140 889 7,731 88% FY2011 YTD 170 100 60% 49% 806 318 2,549 69% Unit 3 FY2010 200 160 180 100 75% 69% 770 572 7,417 85% FY2011 YTD 170 100 49% 49% 864 673 2,134 58% Unit 4 FY2010 200 160 175 100 81% 79% 141 688 7,931 91% FY2011 YTD 170 100 55% 52% 88 298 2,886 79% Note: Data available till November 2010 for FY2011 Power Plant Availability R1V02TAG: 04/27/11 6-4
Unit No. Period Installed Capacity (IC) Derated Capacity (DC) Exhibit 6.2: Unit-wise Availability TPS Guddu Maximum Load Minimum Load Load Factor Utilization Factor Scheduled Outage Forced Outage Availability Availability Factor (Time-base) MW MW MW MW (%) (%) (Hrs.) (Hrs.) (Hrs.) (%) Unit 1 FY2010 110 60 60 10 81% 45% 361 777 7,622 87% FY2011 YTD 55 20 53% 33% 1,154 289 2,229 61% Unit 2 FY2010 110 60 70 10 83% 52% 850 7,910 90% FY2011 YTD 65 15 68% 45% 251 3,421 93% Unit 3 FY2010 200 170 170 20 77% 70% 558 1,057 7,145 82% FY2011 YTD 130 10 52% 51% 393 128 3,151 86% Unit 4 FY2010 200 150 150 10 73% 59% 1,786 6,974 80% CCP Block 2-A FY2011 YTD 150 10 21% 18% 394 3,278 89% Unit 7 FY2010 100 90 92 10 93% 85% 149 81 8,530 78% FY2011 YTD 103 50 87% 87% 133 3,539 96% Unit 8 FY2010 100 90 90 40 93% 79% 142 8,618 98% FY2011 YTD 85 42 87% 74% 282 8 3,382 92% Unit 5 FY2010 100 82 82 5 81% 62% 144 8,616 98% FY2011 YTD 70 7 77% 46% 102 3,570 97% Block 2-A FY2010 300 262 259 60 89% 76% 50 122 8,588 98% FY2011 YTD 240 124 84% 69% 94 81 3,497 95% Power Plant Availability R1V02TAG: 04/27/11 6-5
CCP Block 2-B Unit 9 FY2010 100 90 70 16 27% 24% 6,367 70 2,323 27% FY2011 YTD 100 20 26% 63% 913 1,237 1,521 41% Unit 10 FY2010 100 90 108 10 30% 32% 5,591 294 2,875 33% FY2011 YTD 105 10 62% 78% 250 399 3,023 82% Unit 6 FY2010 100 82 67 5 20% 18% 6,311 281 2,167 25% FY2011 YTD 0% 0% 3,672 0% Block 2-B FY2010 300 262 212 28% 24% 6,090 215 2,455 28% FY2011 YTD 200 20 52% 47% 1,612 545 1,515 41% CCP Block 1 Unit 11 FY2010 136 90 100 16 96% 60% 126 8,634 99% FY2011 YTD 80 20 99% 60% 1 3,671 100% Unit 12 FY2010 136 80 80 13 101% 60% 96 8,664 99% FY2011 YTD 80 20 90% 58% 7 3,665 100% Unit 13 FY2010 143 98 98 11 91% 55% 269 8,491 97% FY2011 YTD 84 20 80% 36% 507 3,165 86% Block 1 FY2010 415 268 278 111 95% 58% 165 8,595 98% FY2011 YTD 244 78 90% 51% 177 3,495 95% Note: Data available till November 2010 Power Plant Availability R1V02TAG: 04/27/11 6-6
Unit No. Period Installed Capacity (IC) Derated Capacity (DC) Exhibit 6.3: Unit-wise Availability TPS Muzaffargarh Maximum Load Minimum Load Load Factor Utilization Factor Scheduled Outage Forced Outage Availability Availability Factor (Time-base) MW MW MW MW (%) (%) (Hrs.) (Hrs.) (Hrs.) (%) Unit 1 FY2010 210 160 160 110 81% 61% 852 7,908 90% FY2011 YTD 110 65 59% 31% 515 3,157 86% Unit 2 FY2010 210 200 200 110 85% 76% 703 378 7,671 88% FY2011 YTD 110 65 73% 64% 471 155 3,046 83% Unit 3 FY2010 210 160 160 50 71% 47% 899 7,117 81% FY2011 YTD 160 100 66% 53% 163 3,509 96% Unit 4 FY2010 320 250 250 130 89% 88% 240 8,520 97% FY2011 YTD 205 110 49% 41% 1,222 327 2,205 60% Unit 5 FY2010 200 120 120 20 38% 25% 3,426 1,712 4,121 47% FY2011 YTD 95 20 58% 31% 436 593 2,643 72% Unit 6 FY2010 200 135 135 20 65% 46% 624 1,568 6,729 77% FY2011 YTD 95 20 63% 35% 807 2,865 78% Note: Data available till November 2010 for FY2011 Power Plant Availability R1V02TAG: 04/27/11 6-7
7. Major Reasons for Degradation of Performance The analysis presented in Section 4 to Section 6 of this report indicates significant degradation in the performance of the GENCOs from their design parameters. The degradation in the output, efficiency, and availability for the power stations studies is summarized in Exhibit 7.1. Based on the observations of the audit team, interviews with the plants management and operational staff and review of historic records of the plants, a number of reasons were identified behind the overall decline in the performance of the power stations studied. These reasons were categorized as technical and management to facilitate the identification of remedial measures. Exhibit 7.1: Average Degradation in Performance of GENCOs Installed Capacity Present Gross Capability Present Net Capability MW MW MW Capacity Degradation Average Design Net Efficiency Average Net Efficiency Average Availability in FY2011 Jamshoro 850 581 535 32% 34.7% 28.6% 72% Guddu 715 493 487 31% N/A* 38.9% 80% Muzaffargarh 1,140 680 614 40% 35.2% 28.9% 78% * The design heat rate of CCP Guddu was not available. 7.1 Technical Issues The power stations are suffering from a number of chronic technical problems that are severely affecting the operational and financial performance of the plants. 7.1.1 Measurement Accuracy of Fuel Received GENCOs purchase 1.5-2.0 million tonnes of RFO annually amounting to Pak Rs 75-100 billion at the present price of Rs 50,000/tonne. RFO measurement system through dip-stick or dip-tapes is generally considered to be reasonably accurate if carried out by a trained person and in stable tank conditions, and volumes converted to weight by using accurate calibration charts and temperature corrections. This method is applied in most of the RFO transactions in the country. Application of this measurement procedure, however, requires strict adherence to specified procedures, documentation of measurements, and skilled and experienced operators and monitoring supervisors. The procedures being practiced by the GENCOs for measurement of fuel oil are lacking in most of these elements. There is excessive human intervention at every stage of transactions and the system is highly prone to errors and malpractices. Following observations were made during the inspection of GENCOs. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-1
No fuel flow measurements are taken for natural gas and for the RFO supplied from storage tanks in the units where flow meters are not present. On units where flow meters are available for RFO or natural gas, the meters are either non-functional or not calibrated on regular basis. Fuel consumption at the units is not measured in real time on regular basis and instead the power station management relies on estimated consumption rates worked out through accounting exercise derived from invoices of the fuel purchased, inventory levels, and energy generated over an operating period. Such calculations have serious limitations in determining accurate heat rates and efficiency as they ignore critical parameters such as quality of fuel received in each batch, and allocation of fuel to individual units for a multi-unit power station from common storage facilities. The validity of such accounting exercises is highly questionable for setting up the heat rate and efficiency benchmark for the plants or individual units. 7.1.2 Fuel Oil Quality Procedures for sampling and analysis of RFO are described in Section 2 of this report. None of the samples complied with Pakistan Standard and Quality Control Authority (PSQCA) specifications for RFO in one or more tests. High specific gravity values were obtained due to higher water contents. Moreover, the low calorific value was observed due to high specific gravity, water and ash contents. Results of fuel oil testing are summarized in Exhibit 7.2. The detailed testing results of the analysis are provided in Appendix A. Exhibit 7.2: Summary of Results of Fuel Oil Testing Test PSQCA Specifications TPS Jamshoro TPS Guddu TPS Muzaffargarh Min Max Min Max Min Max Specific Gravity @ 15.6 C 0.970 Max 0.969 0.985 0.950 0.972 0.966 0.971 Water Contents Vol. % 0.5% Max 1.2% 1.8% 8.0% 4.2% 1.4% 2.8% Sulfur, Total, % mass 3.5% Max 2.8% 3.2% 2.5% 2.9% 2.7% 3.0% Ash Content, % Wt. 0.1% Max 0.3% 1.4% 0.0% 0.5% 0.0% 4.2% Clorific Value, Gross, BTU/Ib 18,200 Min 17,844 18,202 16,660 17,438 17,076 18,089 All the power stations have their own laboratories to analyze fuel oil on a daily basis. However, it was observed that the laboratory staff assigned for collection of samples was not adequately trained, and the testing procedures prescribed under the standards are not likely being fully complied with. This is evident from the results of the analysis of RFO tested from an independent reputed laboratory as part of this assignment and summarized in Exhibit 7.2. All of the 18 samples taken from three plants did not meet the Pakistan Standards for Quality Control Authority (PSQCA) specifications on specific gravity, water contents, ash content, and calorific value. Substandard RFO coupled with Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-2
inaccurate measurements impacts plant performance and results in financial losses to GENCOs due to high fuel costs. A third party RFO testing mechanism should be established on regular basis to ensure the quality of fuel received from supplier. The contracts with fuel supplier should include penalties or correction in price for supply of substandard oil. Moreover, GENCOs should carry out a detailed exercise to devise a robust measurement mechanism for RFO receipts at the plants to reduce oil pilferages and acceptance of substandard oil. 7.1.3 Lack of Preventive Maintenance A number of maintenance activities are long overdue and have already resulted in loss of output capability, increasing heat rates and lower availability. GENCO managements are forced to delay the overhauling of the plants and are not able to carry out regular preventive maintenance to avoid break-down of the plants for the following reasons: Refusal of shut-down time by the system operator (NTDC) due to shortages in power supply in the country, Delay in payments to GENCOs against power sales, and Delay in procurements of parts and services for plants major overhauling, GENCO plants were designed to run on dual fuel with natural gas as primary fuel. RFO is only used as backup fuel supply during infrequent gas outages. However, TPS Muzaffargarh and Jamshoro have not received gas from the gas utilities on a regular basis since 2005 and have run on RFO on continuous basis. The RFO supplied to GENCOs contain up to 3.5% sulfur and other undesired impurities such as vanadium. Continuous operation of steam units on RFO has increased the breakdown frequency and lost time due to excessive corrosion caused by formation of sulfuric acid in the flue gas circulation path and depositions of vanadium oxide and ash on heat exchanging metal surfaces of boiler, reducing their performance. Poor quality of RFO supplied to GENCOs has only exacerbated this problem. Most of the GENCO units urgently need detailed inspections for the hot gas/steam path components to plug leakages and heat losses. Key plant components such as soot blowers, a significant proportion of boiler tubes, high pressure (HP) feed water heaters, and auxiliary equipment are not functioning. These have a direct impact in the form of reduction in output and efficiency of the units Exhibit 7.3 show examples of poor maintenance at TPS Jamshoro resulting in damaged insulation and flue gas ducts. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-3
Exhibit 7.3: Poor Maintenance of Insulation at TPS Jamshoro Poor Maintenance of Flue Gas Duct at TPS Jamshoro The capacity of in-house workshops should be enhanced with modern machines, tools, and training of staff to provide maintenance services for critical parts locally to reduce down-time. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-4
7.1.4 Poor Housekeeping GENCO managements are paying little attention to simple housekeeping activities which do not require large expenditures. Examples include: Frequent steam leakages in boiler and other steam usages increase heat loss at the plant as well as raise water purification cost due to excessive use of chemicals. Exhibit 7.4 shows steam leakages at RFO heating system at Muzaffargarh. Such leakages on continuous basis cause significant drop in efficiency. A large number of soot blowers have become non-operational due to their metallurgy or poor design. This increases the rate of clogging of heater elements. A non-functional soot blower at Unit 3 of TPS Jamshoro is shown in Exhibit 7.5. Plant management is generally oblivious to environmental conservation and protection. Massive oil spills and un-optimal combustion results in higher rate of toxic emissions and effluent discharges causing environmental threats to adjacent population, flora and fauna. Exhibit 7.6 shows significant oil spillage at Muzaffargarh RFO decanting and storage facility. There is a need to establish a Research and Development (R&D) or a Technical Services section to carryout research on such problems and devise solutions. Exhibit 7.4: Steam Leakages at TPS Muzaffargarh Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-5
Exhibit 7.5: View of a Nonfunctional Soot Blower at TPS Jamshoro Exhibit 7.6: Oil Spillage at Storage Facility at Muzaffargarh Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-6
7.2 Management Issues and Recommenadations Management of the power station is responsible to carry out safe, economic, and reliable operation of the plants. Deficiencies highlighted below were common to all the plants. 7.2.1 Lack of Performance Evaluation No attention is given to the performance evaluation of the plants and as such no standards are observed to assess the performance of the plants. Each power station has an Inspection, Testing and Record (ITR) section but their role is limited to monitoring of a few technical parameters. The power stations also have a Maintenance Management System (MMS) which evaluates and compiles the performance parameters of the power station and generates E-forms on monthly and annual basis. A detailed management study is required to prescribe key performance indicators pertaining to financial, human and environmental performance of the plant and the procedures to evaluate them on sustainable basis. The ITR and MMS sections may be merged to form a Performance Monitoring Section (PMS) at each power station to provide a wider range of performance evaluation and monitoring services. In addition to the activities carried out by ITR and MMS, the PMS should develop a 24-hour capability for continuous analysis of trends in performance and losses. With this capability the PMS will be in a position to provide definitive advice on discrepancies on fuel receipts, inventories, and heat rates. By adding analyses and instruments over time, the trend analysis can help identify emerging problems and form the basis for management decisions for improvement of plant performance. 7.2.2 Limited Financial and Administrative Autonomy Managements of GENCO plants have limited financial autonomy to take independent decisions. Payments to GENCOs are not made on time which results in deferment of maintenance routines which is a major reason behind plant output and efficiency degradation. Approval process for procurement of spare parts and services through international tendering is cumbersome and time consuming. It takes on the average 18 months from initiating the tendering process to procure spare parts and services from international sources due to time consumed in preparation of tender documents, advertisement notices and evaluation of tenders, tender awards and inspections, and manufacturing and transportation of goods. In addition, it takes significantly long time before the tendering process can be initiated to get internal approvals for procurement. Best industry practices are not observed for financial management of the power plants and important financial instruments such as a maintenance reserve fund to cater for the financial needs of plants maintenance cycles are not available. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-7
7.2.3 Absence of Plant Automation and Management Information System Exhibit 7.7 shows the control room of Units 3 & 4 at the Jamshoro power plant mainly consisting of manual and analogue instrumentation. General observations are summarized below. Plants are running in manual mode in the absence of modern monitoring and control systems. Most of the instrumentation is analogue in nature and readings are recorded manually in the log sheets. Limited data is organized in electronic form and therefore it is difficult to carry out meaning full analyses on plant performance and identify problem areas. Vital on-line analyzers necessary for optimization and control of plant operation are missing. The absence of performance evaluation standards and an on-line integrated management information system (MIS) severely limits the ability of the management to take prompt decisions and initiate actions and remedial measures for efficient operation of the plants. Exhibit 7.7: View of the Joint Control Room of Units 3 and 4 at TPS Jamshoro The impact of absence of such on-line facilities and controls could be observed frequently at the plants where air-fuel mixing ratio is not monitored due to absence of on-line analyzers that allows escape of un-burnt fuel through plant s exhaust which is visible as black smoke (Exhibit 7.8). This not only contributes heavily towards degradation of air quality in the surroundings of the plant but also increases the fuel consumption of the plant raising the heat rate and cost of fuel. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-8
Exhibit 7.8: Smoke Showing Poor Combustion at Unit No. 6 at TPS Muzaffargarh All the units of GENCOs should be upgraded with installation of on-line analyzers and instruments with communication channels to a central thermal model should be provided to assess the performance of the plant on continuous basis. 7.2.4 Other Management Issues The plants are suffering from overstaffing with majority of staff working without specialized industrial training to perform their duties. No occupational health, safety, and environmental management system and relevant trainings were observed at the plants increasing the potential of a safety hazard at the plant. Inventory control system is primitive and in certain instances not operational that result in un-optimal inventory levels at the plant, causing a direct financial burden in the form of working capital. GENCOs, like other power sector entities, lack any performance based human resource management systems to promote efficiency and competition. Simple housekeeping and safety measures such as firefighting facilities are inadequate and completely missing in certain cases. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-9
The government is currently implementing a Generation and Transmission Improvement Plan (GTIP) for the GENCOs. Under this Action Plan, the Board of Directors of GENCOs will be reconstituted by induction of directors from private sector to bring in improvements in the GENCOs performance. In the absence of financial stakes, the effectiveness of the new management at a higher level may be doubtful. Furthermore, the resolution of a number of management and operational issues identified in the study need a complete change in the management approach and operational environment of the GENCOs which could prove to be a major challenge for the new management. Under these circumstances, government could consider bringing in independent management under a performance based O&M contract based on a structure of incentives and penalties against the performance of the power stations. The terms and conditions of the O&M contract could be designed in a manner to make the contractor responsible for injecting investment for rehabilitation of the units and bringing in highly trained and experienced senior managers capable of using state-of-the-art management tools and industry standard O&M procedures. The O&M contractor may be given extended authority to reward and motivate employees and to take disciplinary action and adjust the size of the work force. This approach will help in establishing and expanding the O&M industry and in improving the efficiency of the power sector in the country. 7.3 Detailed Technical Assessment of GENCOs 7.3.1 TPS Jamshoro Reasons for the degradation of performance of each unit at TPS Jamshoro are listed in Exhibit 7.10. Significant among these are summarized below: All the units have too many leaking points and need nearly 8-10% make up water per day for generation of steam in the boiler. Such high leakages not only increase the operating cost of the plant but also result in heat losses in the form of leaking steam and injection of cold make up water. The water treatment facilities and other chemical plants are in poor condition and require complete rehabilitation. The situation becomes critical if the treatment facilities come under stress. An example of this is the significant increase in the level of total dissolved solids (TDS) in the fresh water supply of the plant from the Indus River following the floods in July 2010. The comparison of the recommended quality and the actual water received during the month of January 2011 are shown below in Exhibit 7.9 below. This severely affected the availability of plant during the period of October 2010 to January 2011 period. High levels of TDS in water significantly reduced the purification capacity of demineralization plant and substantially increased the consumption of chemicals adding to the O&M cost of the plant. The demineralization plant could not produce enough water to operate even two out of four installed power generation units simultaneously. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-10
Exhibit 7.9: River Water Quality Supplied at TPS Jamshoro in January 2011 ph T.H (ppm) Chloride (ppm) Conductivity (µs/cm) Total Desolved Solvents (TDS) (ppm) 7.5-8.5 96-120 40-80 350-500 320 8 900 514 3,260 2,445 A common reverse osmosis (RO) plant needs to be installed to meet the requirements of demineralized water. The Units 2-4 show a general pattern of decline in output and efficiency while running on RFO due to deposit of soot on heat exchange metal surfaces of heaters and gradual chocking of air pre-heater. Most of the soot blowers are not operational and cleaning of soot cannot be carried out. This results in eventual shut down of unit for cleaning when output reaches the minimum loading limits of the units. The use of chemical additives (magnesium) should be allowed at all units to covert vanadium to magnesium vanadium pentoxide to avoid vanadium deposits on tube and element surfaces. So far, the budget for chemicals additives of only one unit has been included in FARA. The funds for other three units should be provided for reliable and continuous operation of these units on RFO The High Pressure (HP) heaters have become non-functional since long and need replacement after thorough review of design and metallurgy of the tubes. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-11
Boiler Exhibit 7.10: Reasons for Drop in Performance of the Plant TPS Jamshoro Unit 1 Unit 2 Unit 3 Unit 4 Detailed Inspection of boiler needs to be carried out. Last carried out in 2000 Total of 38 soot blowers are installed, but mostly inoperative and need replacement Final super heater coils are damaged and need immediate replacement Detailed Inspection of boiler needs to be carried out. Last carried out in 2002-2003 Total of 36 soot blowers are installed, but mostly inoperative and need replacement Final super heater coils are damaged and need immediate replacement (Included in FARA) 3-way burner valves are damaged and need replacement Furnace Safety Supervisory System (FSSS) along with furnace flame monitoring are damaged and need replacement (Included in FARA) Actuators of boiler feed pumps are damaged and need replacement (Included in FARA) Detailed Inspection of boiler needs to be carried out. Last carried out in 2002-2003 Total of 36 soot blowers are installed, but mostly inoperative and need replacement Inal super heater coils are damaged and need immediate replacement (Included in FARA) 3-way burner valves are damaged and need replacement (Included in FARA) FSSS along with furnace flame monitoring are damaged and need replacement (Included in FARA) Actuators of boiler feed pumps are damaged and need replacement (Included in FARA) Spares are required for overhauling of steam turbine Detailed Inspection of boiler needs to be carried out. Last carried out in 2002-2003 Total of 36 soot blowers are installed, but mostly inoperative and need replacement Final super heater coils are damaged and need immediate replacement (Included in FARA) 3-way burner valves are damaged and need replacement FSSS along with furnace flame monitoring are damaged and need replacement (Included in FARA) Actuators of boiler feed pumps are damaged and need replacement (Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-12
Turbines Unit 1 Unit 2 Unit 3 Unit 4 Spares reqquired for overhauling of turbine (Included in FARA) High pressure feed water (HP) are bypassed due to severe leakages in heater tubes. Needs tube replacements Unit does not have electronic hydraulic governor (EHG) are missing aand turbine is presently manually operated. EHG along with data acquisition system need to installed to automated unit output controls (Included in FARA) Digital recorder/event recorder system needs to be installed Data loggers and data plotter on turbine need to be installed HP are bypassed due to severe leakages in heater tubes. Needs tube replacements Unit does not have EHG and is presently manually operated. EHG along with data acquisition system need to installed to automated unit output controls (Included in FARA) Digital recorder/event recorder system needs to be installed Auto control on turbine needs to be installed Temperature scanners on turbine need to be installed Data loggers and data plotter on turbine need to be installed HP are bypassed due to severe leakages in heater tubes. Needs tube replacements Unit does not have EHG and is presently manually operated. EHG along with data acquisition system need to installed to automated unit output controls (Included in FARA) Digital recorder/event recorder system needs to be installed Auto control on turbine needs to be installed Temperature scanners on turbine need to be installed Data loggers and data plotter on turbine need to be installed HP are bypassed due to severe leakages in heater tubes. Needs tube replacements Unit does not have EHG and is presently manually operated. EHG along with data acquisition system need to installed to automated unit output controls (Included in FARA) Digital recorder/event recorder system needs to be installed Auto control on turbine needs to be installed Temperature scanners on turbine need to be installed Data loggers and data plotter on turbine need to be installed Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-13
Air Handling System Unit 1 Unit 2 Unit 3 Unit 4 Flue gas duct & air-preheater bottom hoppers needs repair & maintenance (Included in FARA) Air pre-heater elements and seals are damaged and need replacement (Included in FARA) Cooling System Air pre-heater elements and seals are damaged and need replacement Induced draft (ID) fans dampers are damaged Air pre-heater elements and seals are damaged and need replacement Induced draft (ID) fans dampers are damaged ID fan Impellers are damaged ID fan Impellers are damaged (Included in FARA) Cooling tower fans need redundance and require additionla bank All 12 cooling tower fans need overhauling (Included in FARA) Drive shafts of cooling tower fans need replacement (Included in FARA) Gear stystem for cooling tower fans needs to be added All 12 cooling tower fans need overhauling (Included in FARA) Drive shafts of cooling tower fans need replacement (Included in FARA) Gear stystem for cooling tower fans needs to be added Air pre-heater elements and seals are damaged and need replacement Induced draft (ID) fans dampers are damaged ID fan Impellers are damaged (Included in FARA) All 12 cooling tower fans need overhauling (Included in FARA) Drive shafts of cooling tower fans need replacement (Included in FARA) Gear stystem for cooling tower fans needs to be added Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-14
Miscellaneuos Unit 1 Unit 2 Unit 3 Unit 4 Last major overhauling was carried out in Y1999 and is long overdue since 2007. Supervisory experts needed for overhaul ($2-3 million) Drain valve (high pressure & high temperature), safety, by-pass spray control valves need replacement. Off-line efficiency monitoring system and training need to be provided (Included in FARA) Steam convertor needs repair and maintenance Demineralization/ deionization plan needs complete rehabilitation. Drain valve (high pressure & high temperature), safety, by-pass spray control valves need replacement. Clorination plant for treatment of water for boiler use is not functional and needs complete rehabilitation. Instrumentation and auto operating system of Demineralization plant is not functional and needs rehabilitation Demineralization/ deionization plan needs complete rehabilitation. Instrumentation and auto operating system of Demi neralization plant is not functional and needs rehabilitation Off-line efficiency monitoring system and training need to be provided (Included in FARA) Drain valve (high pressure & high temperature), safety, by-pass spray control valves need replacement. Off-line efficiency monitoring system and training need to be provided (Included in FARA) Drain valve (high pressure & high temperature), safety, by-pass spray control valves need replacement. A common steam convertor unit with condensate recirculation needs to be installed for Units 2-4 Clorination plant for treatment of water for boiler use is not functional and needs complete rehabilitation Demineralization/ deionization plan needs complete rehabilitation. Instrumentation and auto operating system of Demineralization plant is not functional and needs rehabilitation Clorination plant for treatment of water for boiler use is not functional and needs complete rehabilitation Demineralization/ deionization plan needs complete rehabilitation. Instrumentation and auto operating system of Demineralization plant is not functional and needs rehabilitation Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-15
7.3.2 TPS Guddu Reasons for the degradation of performance at TPS Guddu are given in Exhibit 7.13. Like other GENCOs, poor maintenance of the plant has resulted in damage to key plant components. Significant problems are summarized below: The CCP Block 1 is facing significant load reduction as it requires major over hauling. The units are run in safe mode as inspection of hot gas path components has not been carried out since 2002. The management apprehends break down of hot gas path components if run on full load. On CCP Block 2, the auxiliary supply is not secured in case of total plant shut down (black out). This can cause damage to plant and excessive outage in case of black out. Black start capability for auxiliaries needs to be ensured through installation of a diesel generator and connection with grid. Silting of intake water structure at Begari Sindh Feeder Canal reduces the supply of condenser cooling water for all units that results in drop in plant output and efficiency. Problem can be solved with dredger or remodeling of intake water channel. The Kandhkot and Mari gas pipeline need to be re coated as its coating has deteriorated at places and the pipeline is exposed to corrosion. Gas leakage from rupture in the pipeline can result in extended outage at the plant. Exhibit 7.11 shows pictures of the damaged air preheater of Unit 4 due to fire resulting in an outage of nearly three months for the unit. Exhibit 7.12 shows inadequate cooling of the turbine section of Unit 3 Exhibit 7.11: Damaged Air Pre-heater due to Fire of Unit No. 4 at TPS Guddu Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-16
Damaged Air Pre-heater Elements due to Fire of Unit No. 4 at TPS Guddu Melted Air Pre-heater due to Fire of Unit No. 4 at TPS Guddu Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-17
Exhibit 7.12: Poor Cooling of Turbine Section of Unit No. 3 at TPS Guddu Poor Cooling of Unit No. 3 at TPS Guddu Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-18
Boiler Exhibit 7.13: Reasons for Drop in Performance of the Steam Units TPS Guddu Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 All of the boiler tubes are week and cannot sustain full temperatures and pressures. All boiler tubes should be replaced. Boiler feed pumps performance reliability has significantly dropped and therefore need replacement for the safe and continuous operation of the boiler. High pressure (HP) heaters are out of service since long and require replacement after modified metallurgy of tubes. If replaced, it can significantly reduce the fuel consumption The performance of operation feed water pump has dropped significantly due to impellor damage and need repair/replacement The performance of operation condensate pump has dropped significantly due to damaged impellor and inter-stage seals and need repair/replacement. Their respective regulating valves are also not functioning properly and need repair/replacement. Inlet/outlet motorized valves of feed water and condensate lines are not functioning properly and need repair/replacement. Boiler insulation is very poor and damaged Super heater and reheater temperature control injection regulators are not working resulting in temperature variations at the inlet of turbine. Safety valves of boiler drum, super heaters and reheater have leakage and need repair/replacement. HRSG by-pass and Isolation damper have leakages, need to be replaced (Only Block 2A Included in FARA) Feed water controllers not functioning and need to be replaced (Only Block 2A Included in FARA) HRSG drum insulation has deteriorated and need to replaced (Only Block 2A Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-19
Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 Refractory of boiler is badly damaged causing heat loss and need rebuilding. Hydraulic seal of boiler is damaged since long resulting in heat loss and needs to be reinstalled. HP heaters are out of service since long and require replacement after modified metallurgy of tubes. If replaced, it can significantly reduce the fuel cost. Soot blowing system is not effective both in furnace and air pre-heaters need rehabilitation. No analyzers for exhaust gases are present resulting in ineffective control on combustion. HP heaters are out of service since long and require replacement after modified metallurgy of tubes. If replaced, it can significantly reduce the fuel cost. No analyzers for exhaust gases are present resulting in ineffective control on combustion. Drum s level transmitter malfunction and causing tripping, and need to be replaced. (Only Block 2A Included in FARA) Flue gas leakages due to damage in Heeat recovery staem generator (HRSG) bypass dampers and isolation damper controllers, damage control system, need to be replaced. (Only Block 2A Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-20
Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 No analyzers for exhaust gases are present resulting in ineffective control on combustion. Turbine Super heater tubes are week and cannot sustain full temperatures and pressures. The tubes need to be replaced. Boiler safety valves are leaking and needs repair. Periodic blow-down valves of the boiler are leaking and needs replacement. Boilers burners are chocked and need replacement. No analyzers for exhaust gases are present resulting in ineffective control on combustion. Control cable deterioration because of overheating from flue gases (Only Block 2A Included in FARA) SSS clutch vibration on gas turbines, need rebalancing The present instruments and controls system is obsolete and spare parts are no more available. The complete system need to be replaced. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-21
Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 Air Handling System GRC fans are out of order and need replacement to reduce fuel consumption. Cooling System Circulating cooling water pumps are not delivering water at the full output resulting into low vacuum and hence lower turbine output Flue gas ducts on both sides is leaking and needs repair. 20% condenser tubes have been plugged due to leakages and need replacement to improve the condenser vacuum to increase output and efficiency of turbine Both regulators of flue gas recirculation fan (GRC) fans are not working thereby affecting the performance of boiler and need replacement Steam inlet air-heater (calorifier) are not working resulting in entry of cold air in the boiler and need replacement. The filer screens at the inlet of CW pumps are damaged due to which the debris flows into the condenser and causes tube chocking resulting in load reduction and stoppage of unit. The screens need replacement. GT lift oil pumps don t build required pressure. Need to be replaced Evaporator cooler not functioning, filling material needs to be replaced (Only Block 2A Included in FARA) Silting of intake water structure at Begari Sindh Feeder results in reduction in the quantity of condenser cooling water. Problem can be solved with dredger or remodelling of intake water channel Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-22
Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 Reverse flow valves of condenser cooling are not functioning therefore backwashing of the condenser ids not carried out. These valves require replacement. Impellers of cooling water (CW) pumps have been eroded and need replacement. The reliability of 6 kv Motors of CW pumps, condensate pumps, ID/FD fans, feed pumps, cooling tower pumps has significantly dropped due to local rewinding and need replacement of an appropriate rewinding solution. At Unit 1, a number of condenser tubes need replacement due to leakage. Cooling Water (CW)pumps are not providing sufficient water for the condenser cooling. Also the fine screens installed ion the inlet of CW pumps are damaged. One bay of cooling towers need to be added for Unit 5 & 6 to improve condenser vacuum The RCC structure of cooling towers has developed cracks, Need to be reinforced Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-23
Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 Cooling tower structure is completely damaged and result in closure of the plant during canal closure and floods. Generator Generators are not able to take maximum load due drop in hydrogen supply from Hydrogen generation plant. Hydrogen generation plant needs transformer replacement to get to its full capacity. Miscillenous AUX Standby auxiliary transformer (6/0.4 kv) T7 requires replacement to ensure standby arrangements. Leakage of acidic water from demi-water plant seeped into cable trenches and damaged control cables resulting in excessive nuisance tripping Reduction in amp-hour of station battery bank due to aging, needs replacement The air filters get clogged in fog resulting in reduction of load or shut down of the gas turbines. A solution such as use of protective cover at KAPCO power plant may be able to solve the problem. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-24
Unit 1-2 Unit 3 Unit 4 CCP Block 2-A and 2-B CCP Block 1 Overhead crane bus bar deforms in hot weather. Needs to be replaced The governing system of Diesel generator for black is not functioning therefore DG set is no more in service. Need repair/replacement Work is under progress at Unit No. 9 and stat of the art controlling and monitoring system is being installed by G.E. The unit is not being completed due to trouble in its exciter. Performance to be evaluated after the completion of work. Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-25
7.3.3 TPS Muzaffargarh Major reasons for the degradation of performance at TPS Muzaffargarh are listed in Exhibit 7.15. Significant problems are summarized below: Soot blowers of Unit 5 and 6 are not functional and cause significant degradation in plants output and efficiency with continuous operation. The use of chemical additives (magnesium) should be allowed to avoid vanadium deposits on tube and element surfaces. The budget for chemicals additives has been included in FARA. Nearly 50% of the cooling tower fans of Units 2, 3 and 6 are not functioning thereby significantly affecting the condenser operations of these units due to lower vacuum. The immediate replacement/repair of the damaged fans of all the units is needed as lower efficacy of cooling tower results in drop of output and efficiency of the turbine to back pressure at the condenser end. Cooling water treatment needs to be improved with modifications in the treatment systems to avoid damage to cooling water system components from scaling. The up-gradation has been included in FARA for all units of TPS Muzaffargarh. The calorifiers of Units 2, 3, 5 and 6 are not fully operational due to damage to headers resulting in loss in efficiency for these units. Unit 1 requires major overhaul and has been out of service since November 2011due to non-availability of experts from the manufacturer of the equipment (OEM). The unit is expected to be back in service around end March 2011. Exhibit 7.14 show the under repair induced draft (ID) fan of Unit 1. Exhibit 7.14: View of Under Repair Induced Draft Fan of Unit No. 1 at TPS Muzaffargarh Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-26
Under Repair Induced Draft Fan of Unit No. 1 at TPS Muzaffargarh Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-27
Boiler Exhibit 7.15: Unit-wise Reasons for Drop in Performance of the Steam Units TPS Muzaffargarh Unit 1-3 Unit 4 Unit 5 & 6 Frequent leakages in boiler super-heater tubes, causing load restriction and also forced shut downs. The ends of super-heater tubes need to be replaced (Included in FARA) Soot-blowing system is defective. Rehabilitation of soot-blowers installed at superheaters, reheaters and regenerative airheaters is required urgently Formation of scale on heat transfer surfaces including superheaters and reheaters is a common phenomenon. Fuel additive system is required to be launched (Included in FARA) Formation of scale deposits on heating surfaces is a frequent phenomenon. Fuel additive system for the fuel oil is required to be launched Performance of boiler feed water pumps is not upto the mark. Major overhauling of feed water pumps is required to be carried out FSSS system is not functioning effectively and needs to be up-graded. (Included in FARA) Soot blowing system is non-functional. Rehabilitation of furnace soot blowers and regenerative air preheater is essentially required Steam coil air heaters are deteriorated. The air heaters are required to be repaired/replaced FSSS system is not functioning effectively and needs to be up-graded. (Included in FARA) Frequent economizer tubes leakages occur causing load restriction beyond 100 MW. The rehabilitation of economizer tubes is required (Included in FARA) Formation of scale on heating surfaces is too frequent. Fuel additive system is required to be introduced Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-28
Turbine Unit 1-3 Unit 4 Unit 5 & 6 Low Pressure turbine rotor blades of last stage were removed after damages. The blades need to be reinstalled with new ones and balancing of turbine is essentially required (Included in FARA) Turbine Supervisory Instrumenttaion (TSI) needs upgradation (Included in FARA) DEH system needs to be replaced. (Included in FARA) Feed water pumps hydraulic coupling problem is experienced. The hydraulic coupling problem is required to be set right (Included in FARA) HP Heaters tubes are damaged. Damaged tubes are required to be replaced/repaired Intermidiate Pressure (IP) and Low Pressure (LP) turbine rotors are badly deteriorated. The replacement of rotors is needed urgently (Included in FARA) Gland seals of HP/IP turbines are deteriorated. Replacement is required The performance of turbines DEH-III and data acquisition systems DAS-100 is not funtioning in a satisfatory manner. Installation of a complete distribution control system (DCS), including sensors, transmitters, and actuators ffor Turbiner governing system DEH-III and boiler tuurbine auto regulation system needs to be installed. (Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-29
Air Handling System Unit 1-3 Unit 4 Unit 5 & 6 Flue gas ducts are worn-out & damaged at several points. The affected areas of flue gas ducts should be repaired/replaced GRC motor is defective. The Motor needs replacement. (Included in FARA) Regeneraytive airheater (RAH) elements are badly deteriorated. Cold & hot elements are required to be replaced (Included in FARA) ID fans (both sides A & B) are badly damaged. The major components of ID fans need to be replaced Cooling System Condenser Vacuum system is faulty. The condenser Vacuum system and allied cooling water system need to be rectified Air preheater elements are deteroated. Elements of pre-heater need to be replaced with new ones (Included in FARA) Flue gas duct is worn out and damaged. The flue duct is in bad shape hence its rehabilitation is essentially required Working of gooling tower is not satisfactory. Special cooling water treatment system should be introduced ID fans impellers, its casing and inlet dampers are badly deteriorated. The deteriorated components of ID fans require replacement. (Included in FARA) GRC fans impellers are defective. The defective components GRS fans require replacement. (1 set Included in FARA) Air flue duct is damaged and leaking at several points. Rehabilitation of flue gas duct, air plennum and expansion joints is required (Included in FARA) Air pre-heater hot and cold elements are damaged. The calorifiers have also deteriorated. Replacement of air preheater with the new one is required, Calorifiers aso need to be repaired/replaced (Included in FARA) Gear boxes of cooling water fans & blades are worn out. Replacement of damaged parts is required (Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-30
Unit 1-3 Unit 4 Unit 5 & 6 Cooling tower fans are defective. Existing fans of cooling towers need to be replaced with new ones and chemical treatment system is to be managed on regular basis (Cost of Electric motor is included in FARA) Generator Performance of excitation system is not satisfactory. Modification of excitation system need to be carried out. (Included in FARA) Miscillenous AVR system is not functioning properly. Its modification is required (Included in FARA) Uninterupted power supply (UPS) for control systems system is not working properly. Existing UPS system need to be replaced (Included in FARA) Water showering louvers and their fittings are deteriorated. Rehabilitation of these components is needed Generator Hydrogen coolers of unit no. 6 are defective. Replacement of hydrogen coolers is required to be done urgently The Bearings of TURBO genmerator are damaged and need replavcement. (Included in FARA)` The generator excitation system needs modifications. Protection relays of genertor also need to be replaced. (Included in FARA) Boiler ingnition system needs to be converted from natural gas to HSD/furnace oil ddue to absence of gas (Included in FARA) 6.6 kv motors of cooling water pumps, CP, ID fans, FD Fans and Boiler Feed pumps are damagaed and ned replacement (Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-31
Unit 1-3 Unit 4 Unit 5 & 6 Technical problems on turbine and generators are being faced. Major overhauling and balancing of turbines is essentially required 0.4 kv motors of cooling towers are damaged and need to be replaced. (Included in FARA) Major Reasons for Degradation of Performance R1V02TAG: 04/27/11 7-32
8. Usage of High Viscosity Fuel Oil in GENCO Power Plants RFO is used in dual fuel power stations when natural gas is not available. RFO is available in several grades with kinematic viscosity ranging from 30 centistoke (cst) to 700 cst. In Pakistan, power plants use RFO with kinematic viscosity of 180 cst during summer and 120 cst during winter. Generally the price of RFO decreases as its viscosity increases. A suggestion was made to assess the potential of using RFO having the viscosity of 380 cst and above in GENCO power stations as a cost saving measure. Higher viscosity fuel oils tend to have a higher ash and metals content compared to those with lower viscosity. Oils with higher viscosity also require additional heating to make them pump-able and transportable through the piping systems in cold weather. The ToRs for the study required an investigation of the technical feasibility of using fuel oils with kinematic viscosity of 380 cst (referred to as heavier RFO in this section) in the GENCO power stations to reduce the cost of fuel for power generation in the country. This section discusses the major factors that need to be considered for switching to fuel oils with higher viscosity. 8.1 Fuel Oil Standards In Pakistan power stations and industrial plants are designed to operate on 180 cst during summer and 120 cst during winter. The country as such does not have any experience of using more viscous fuel oil to date. Pakistan Standards for Quality Control Authority (PSQCA) therefore does not have any reference to the more viscous fuel oil grades. Internationally, residual fuel oil is also referred to as marine fuel and its specifications are guided by ISO 8217: 2010 Classification of marine fuels. Exhibit 8.1 shows the specifications of various grades of Marine Residual Fuel Oil. The specifications indicate an increasing trend of vanadium, metals, and ash contents with increasing viscosities. Increasing concentrations of these parameters lead to a decline in performance of steam plants and increase in operations and maintenance (O&M) cost. 8.2 Potential for use in Power Generation in Paksitan Heavier fuel oils of 380 cst and above are used in power generation in many countries including India and Brazil. The following is a summary of factors that could limit their usage in the power plants in Pakistan. Steam Plants Heavier residual fuel oils can be used with greater flexibility in steam power plants than in diesel sets due to the external combustion mode of firing and minimal retrofits of oil burners to burn fuels of varying viscosities. Steam power plants can therefore be designed to use heavier grades of fuel oil. However, in existing steam power stations, use of heavier fuel oils can affect the output and operational efficiency due to the limitations of the installed oil handling system. Usage of High Viscosity Fuel Oil in GENCO Power Plants R1V02TAG: 04/27/11 8-1
Diesel Engines In addition to modification of the oil storage and handling system, the fuel injection systems of the power plants using diesel engine technology would require replacement. In addition, presence of higher concentration of vanadium will cause hot corrosion at the exhaust valves thereby increasing the operational and maintenance cost of the plant. The use of heavier RFO in existing diesel engine plants therefore should be considered only after careful assessment of the economics of operations on such RFO grades. Gas Turbines The experience of use of RFO being marketed in Pakistan in gas turbines in Pakistan at the KAPCO and Rousch CCGT power stations show a significant 10-15% degradation of power output and loss of thermal efficiency of the plant and about 8-10% additional shut down time required for periodic washing of turbine blade due to deposition of vanadium. Due to these problems, Rousch power plant switched to gas firing for reliable operation of the plant. The use of even heavier grades of RFO in gas turbines with substantially higher vanadium content (higher by a factor of three) and 50% higher ash content will not be feasible. The above discussion indicates that the steam power stations are the only units where use of RFO of higher viscosity of the order of 380 cst could be considered. 8.3 Modifications Required in Fuel Oil Handling at the Power Plants Significant modifications can be required at the oil handling system of steam power stations right from decanting from railway or road tankers to final consumption at the boiler. Decanting time: Due to higher viscosity, decanting will take much longer time especially during winter as the oil will have to be heated to its pour point to permit pumping. Up-gradation of decanting facilities: The capacity of the decanting facility may have to be enhanced to accommodate larger number of tankers at a time to decant desired amount of oil in a day. Modification in oil heating system: The heating system would need modification to provide higher amount of heat to raise the temperature of the oil. Besides additional heat input, heat losses in the oil storage and handling system would also increase, which will have a negative impact on the overall thermal efficiency of the plant. Pumping requirements: In order to flow more viscous oil, the capacity of fuel oil filling pumps from decanting stations to storage tanks and oil feed pumps from storage tanks to boilers will need replacement or revamping. 8.4 Modification and Adjustments Required in the Boilers Heavier oils have different physical properties that may require modifications in the boiler components to attain optimal efficiencies for the plants. Burner design: Burner design may need modifications to allow for adequate fuel atomization and combustion in the furnace. Usage of High Viscosity Fuel Oil in GENCO Power Plants R1V02TAG: 04/27/11 8-2
Soot blowing frequency: With nearly 50% higher ash contents in the oil, the frequency of the soot blower operations is likely to increase. The GENCO power plants have manually operated soot blowers and majority of them are not even operational. In such conditions, the plants may need more frequent shut downs for washing of heater elements and tubes in the boiler. Oil additives/chemical usage: The higher concentration of vanadium in heavier fuel oil will increase the rate of depositions on heat exchanging surfaces of boiler needing frequent washing causing frequent shutdowns. These depositions can be reduced through use of fuel additives that will add to the existing O&M costs. Emissions: Due to higher concentration of micro carbon residue in the oil, the overall emissions from the plant may increase. All of the above factors would require capital investment at the plant to modify the oil handling system and plant O&M procedures to accommodate the usage of high viscous oil and will cost additional O&M expenses on recurring basis. 8.5 Fuel Oil Procurement and Supply RFO of 120 cst and 180 cst kinematic viscosity is produced by local refineries which meets nearly 50% of the country demand. GENCOs power stations contribute nearly 25-30% in the total demand of RFO in the country. Pakistan State Oil Company (PSO) manages the fuel oil supply in the country through oil imports from the Middle East on a regular basis to meet the domestic deficit. Since the specifications of local and imported oil are similar, PSO maintains a uniform infrastructure for storage, handling, and transport of RFO for the market in the country. Fuel oil availability: PSO will need to develop special tendering mechanism for import of heavier grade of RFO. In the absence of firm quantity contracts with GENCOs, it will always be a challenge for PSO to estimate the order size and frequency of supply to minimize its market risks. Modification of port handling facilities: Modification of decanting facilities from ships to port storage and onward handling of oil to depots will be required on the lines similar to that of fuel oil handling systems at the power plants. Dedicated storage: PSO will have to maintain dedicated storage for heavier RFO and will have to modify oil handling systems at their depots. PSO may not be willing to serve the market of heavy heavier grade RFO within the prevailing pricing mechanisms and may look for premiums to cover the risks. Such premiums will add to the delivered price of the heavier grade RFO, which may eliminate the advantage offered by the lower international market price. Use of Heavier Grade Fuel Oil in GENCOs Switching to heavier grade RFO will require capital investment in the infrastructure for storage, handling, transportation, and utilization of RFO. A detailed feasibility study including the infrastructure analysis of PSO and required modifications at the steam turbine and diesel engine based power plants and the assessment of resulting cost savings is recommended to ascertain the economics of burning heavier grade fuel oils. Usage of High Viscosity Fuel Oil in GENCO Power Plants R1V02TAG: 04/27/11 8-3
Exhibit 8.1: RFO Specifications ISO 8217: 2010 Paramenter Unit Limit RMA RMB RMD RME RMG RMK 10 30 80 180 180 380 500 700 380 500 700 Viscosity at 50 C mm 2 /s Max 10 30 80 180 180 380 500 700 380 500 700 Density at 15 C kg/m 3 Max 920 960 975 991 991 1010 Micro Carbon Residue % mm Max 2.5 10 14 15 18 20 Aluminium + silicon mg/kg Max 25 40 50 60 Sodium mg/kg Max 50 100 50 100 Ash % mm Max 0.04 0.070 0.10 0.15 Vanadium mg/kg Max 50 150 350 450 CCAI Max 850 860 870 Water % V/V Max 0.30 0.50 Pour point (Upper) a Summer Pour Point (Upper) b Winter C Max 6 30 C Max 0 30 Flash Point C Min 60 Sulphur c % m/m Max Statutory requirements Total Sediment, aged % m/m Max 0.10 Acid Number* mgkoh/g Max 2.5 Used Lubricating Oils (ULO) 1 Calcium and Zinc 1 or Calcium and Phosphorus mg/kg Max The fuel shall be free from ULO, and shall be considered to contain ULO when either one of the following conditions is met: Calcium >30 and Zinc >15 or Calcium >30 and phosphorus >15 Usage of High Viscosity Fuel Oil in GENCO Power Plants R1V02TAG: 04/27/11 8-4
Appendix A: Fuel Oil Analysis Results See following pages. Appendix A R1V02TAG: 04/27/11 A-1
ATTOCK REFINERY LIMITED QUALITY CONTROL LABORATORY FURNACE FUEL OIL TEST REPORT Sample Report #: C-HBP-2 Sample Source: Date Received: 07-01-11 Time Received: 1600 Hrs Date Reported: 19-01-11 Time Reported: 1200 Hrs No. Test Method PSQCA 5 Specifications JT-1 6 (1-E02962) JT-2 (2-E02963) JT-3 (3-E02964) Results JT-4 (4-E02965) GT-1 7 (6-E02966) GT-3 (7-E02967) 1. Specific Gravity @ 15.6 C ASTM D1298 8 0.970 Max 0.9703 0.9710 0.9691 0.9851 0.9739 0.9722 2. Flash Point, PMCC, C ASTM D93 66 Min 83 80 85 82 95 85 3. Pour Point, C ASTM D97 24 Max 3 6 3 3 9 6 4. Water Contents Vol. % ASTM D95 0.5 Max 0.2 1.8 1.2 1.2 8.0 4.2 5. Sulfur, Total, % mass ASTM D4294 3.5 Max 3.1196 3.1467 2.8299 3.0688 2.8608 2.9092 6. Ash Content, % Wt. ASTM D482 0.1 Max 0.303 0.759 1354 0.272 0.014 0.505 7. Clorific Value, Gross, BTU/Ib ASTM D240 18,200 Min 18,208 17,844 17,981 17,929 16,813 17,438 5 6 7 8 PSQCA=Pakistan Standards for Quality Control Authority JT=Jamshoro Storage Tanks GT= Guddu Storage Tanks ASTM=American Society for Testing And Materials Appendix A R1V02TAG: 04/27/11 A-2
Sample Report #: C-HBP-2 Sample Source: Date Received: 07-01-11 Time Received: 1600 Hrs Date Reported: 19-01-11 Time Reported: 1200 Hrs No. Test Method PSQCA Specifications GT-5 (7-E02968) GT-8 (8-E02969) GT-9 (9-E02970) Results MT 9-2 (10-E02971) MT-3 (6-E02972) MT-A (Unit-4) (7-E02973) 1. Specific Gravity @ 15.6 C ASTM D1298 0.970 Max 0.9699 0.9626 0.9503 0.9749 0.9655 0.9700 2. Flash Point, PMCC, C ASTM D93 66 Min 81 71 88 89 52 52 3. Pour Point, C ASTM D97 24 Max 9 9 3 3 6 3 4. Water Contents Vol. % ASTM D95 0.5 Max 8 5.6 5.8 2.8 2.4 2.4 5. Sulfur, Total, % mass ASTM D4294 3.5 Max 2.5506 2.7017 2.5465 2.8807 2.7814 2.7327 6. Ash Content, % Wt. ASTM D482 0.1 Max 0.032 0.004 0.018 2.942 1.365 4.202 7. Clorific Value, Gross, BTU/Ib ASTM D240 18,200 Min 16,860 17,364 17,428 17,678 17,229 17,123 9 MT= Muzaffargarh Storage Tanks Appendix A R1V02TAG: 04/27/11 A-3
Sample Report #: C-HBP-2 Sample Source: Date Received: 07-01-11 Time Received: 1600 Hrs Date Reported: 19-01-11 Time Reported: 1200 Hrs No. Test Method PSQCA Specification s MT-B (Unit-4) (13-E02974) MT-1 (14-E02975) Results MT-2 (15-E02976) MT-4 (16-E02977) MT-5 (17-E02978) MT-6 (18-E02979) 1. Specific Gravity @ 15.6 C ASTM D1298 0.970 Max 0.9713 0.9699 0.9690 0.9710 0.9663 0.9683 2. Flash Point, PMCC, C ASTM D93 66 Min 58 54 66 68 67 68 3. Pour Point, C ASTM D97 24 Max 6 6 9 6 3 6 4. Water Contents Vol. % ASTM D95 0.5 Max 2.6 2 1.6 1.4 3 2.8 5. Sulfur, Total, % mass ASTM D4294 3.5 Max 3.0092 3.0396 3.0688 2.7182 2.8471 2.8318 6. Ash Content, % Wt. ASTM D482 0.1 Max 3.989 3.153 0.025 0.025 0.022 0.034 7. Clorific Value, Gross, BTU/Ib ASTM D240 18,200 Min 17,076 17,350 18,014 18,089 17,803 17,826 Remarks: All eighteen samples does not comply Pakistan Standard and Quality Control Authority (PSQCA) specifications for Furnace Fuel Oil (FFO) in one or more tests. High specific gravity values are obtained due to higher water contents. Moreover, the low calorific value is obtained due to high specific gravity, water and ash contents. This report shall not be produced/made part of any investigation/inquiry/ or used for any litigation purpose. Samples were collected by M/s Hagler Bailly Pakistan (HBP) and received at room temperature. Appendix A R1V02TAG: 04/27/11 A-4
Appendix B: Data and Results of the GENCOs Capacity Test Unit 1 Exhibit B.1: Results of the Capacity Test of TPS Jamshoro Date Time Gross Output Auxiliary Load Net Output 21/01/2011 11:00 200 16 184 12:00 200 16 184 13:00 187 15 172 14:00 187 15 172 22/01/2011 11:00 187 15 172 12:00 187 15 172 13:00 187 15 172 14:00 187 15 172 23/01/2011 11:00 200 16 184 12:00 200 15 185 13:00 187 15 172 14:00 187 15 172 Average 191 15 176 Unit 2 Date Time Gross Output Auxiliary Load Net Output 21/01/2011 11:00 125 7 118 12:00 125 6 119 13:00 125 6 119 14:00 125 7 118 22/01/2011 11:00 125 6 119 12:00 122 6 116 13:00 122 7 115 14:00 110 7 103 23/01/2011 11:00 102 6 96 12:00 112 6 106 13:00 117 7 110 14:00 113 6 107 Average 119 6 112 Appendix B R1V02TAG: 04/27/11 B-1
Unit 3 Date Time Gross Output Auxiliary Load Net Output 17/02/2011 11:00 132 12 120 12:00 130 11 119 13:00 125 12 113 14:00 124 11 113 18/02/2011 10:00 124 12 112 11:00 125 11 114 12:00 124 12 112 13:00 124 12 112 19/02/2011 10:00 124 12 112 11:00 118 12 106 12:00 125 12 113 13:00 125 12 113 Average 125 12 113 Unit 4 Date Time Gross Output Auxiliary Load Net Output 17/02/2011 11:00 152 13 139 12:00 150 13 137 13:00 150 13 137 14:00 152 13 139 18/02/2011 10:00 146 13 133 11:00 150 13 137 12:00 148 13 135 13:00 149 13 136 19/02/2011 10:00 145 13 132 11:00 130 13 117 12:00 138 13 125 13:00 141 12 129 Average 146 13 133 Appendix B R1V02TAG: 04/27/11 B-2
CCP Block 2-A (GT7, GT8, ST5) Exhibit B.2: Results of the Capacity Test of TPS Guddu Date Time Gross Output GT 7 GT 8 ST5 CCP Block 2-A Auxiliary Load Net Output Gross Output Auxiliary Load Net Output Gross Output Auxiliary Load Net Output 30/12/2010 1000 95 0.37 95 85 0.35 85 68 1 67 248 2 246 Gross Output Auxiliary Load 1100 95 0.37 95 85 0.38 85 69 1 68 249 2 247 1300 95 0.38 95 85 0.34 85 71 1 70 251 2 249 1500 80 0.40 80 85 0.36 85 72 1 71 237 2 235 1700 80 0.40 80 85 0.35 85 72 1 71 237 2 235 31/12/2010 0900 95 0.36 95 85 0.34 85 72 1 71 252 2 250 1100 95 0.39 95 85 0.34 85 72 1 71 252 2 250 1300 1600 90 0.39 90 85 0.34 85 73 1 72 248 2 246 1700 90 0.39 90 85 0.34 85 73 1 72 248 2 246 01/01/2011 0900 95 0.37 95 85 0.35 85 67 1 66 247 2 245 1100 95 0.37 95 85 0.37 85 67 1 66 247 2 245 1300 95 0.36 95 85 0.37 85 68 1 67 248 2 246 1600 95 0.36 95 85 0.35 85 71 1 70 251 2 249 02/01/2011 0900 95 0.38 95 85 0.36 85 72 1 71 252 2 250 1100 95 0.37 95 85 0.35 85 72 1 71 252 2 250 1300 95 0.38 95 85 0.36 85 69 1 68 249 2 247 1600 95 0.40 95 85 0.36 85 72 1 71 252 2 250 Average 93 0.38 92 85 0.35 85 71 1 69 248 2 246 Net Output Appendix B R1V02TAG: 04/27/11 B-3
CCP Block 1 (GT11, GT12, ST13) Date Time Gross Output GT 11 GT 12 ST 13 CCP Block 1 Auxiliary Load Net Output Gross Output Auxiliary Load Net Output Gross Output Auxiliary Load Net Output 03/01/2011 0900 Gross Output Auxiliary Load 1100 80 80 80 80 83 3 80 243 4 239 1300 80 80 80 80 83 3 80 243 4 239 1600 81 81 80 80 84 3 81 245 4 241 04/01/2011 0900 80 80 80 80 84 3 81 244 4 240 1100 80 80 80 80 84 4 81 244 4 240 1300 80 80 80 80 84 4 81 244 4 240 1600 80 80 80 80 85 4 82 245 4 241 05/01/2011 0900 80 80 80 80 83 4 80 243 4 239 1100 80 80 80 80 84 3 81 244 4 240 1300 80 80 80 80 83 3 80 243 4 239 1600 80 80 80 80 83 3 80 243 4 239 06/01/2011 0900 80 80 80 80 86 3 83 246 4 242 1100 80 80 80 80 86 3 83 246 4 242 1300 80 80 80 80 87 3 84 247 4 243 1600 80 80 80 80 87 3 84 247 4 243 Average 80 80 80 80 84 3 81 244 4 240 Net Output Appendix B R1V02TAG: 04/27/11 B-4
Exhibit B.3: Results of the Capacity Test of TPS Muzaffargarh Unit 2 Date Time Gross Output Auxiliary Load Net Output 09/01/2011 10:00 160 11 149 11:00 170 11 159 12:00 170 11 159 13:00 170 10 160 10/01/2011 10:00 170 11 159 11:00 170 11 159 12:00 170 11 159 13:00 170 11 159 11/01/2011 10:45 170 12 158 11:45 170 12 158 14:45 160 12 148 15:00 160 12 148 Average 168 11 156 Unit 3 Date Time Gross Output Auxiliary Load Net Output 09/01/2011 11:00 140 13 127 12:00 140 13 127 13:00 140 13 127 14:00 140 13 127 10/01/2011 10:00 140 13 127 11:00 140 13 127 12:00 140 13 127 13:00 140 13 127 11/1/2011 10:45 140 14 126 11:45 140 14 126 14:45 140 14 126 15:00 140 14 126 Average 140 13 127 Appendix B R1V02TAG: 04/27/11 B-5
Unit 4 Date Time Gross Output Auxiliary Load Net Output 05/01/2011 14:55 202 21 181 15:55 202 21 181 16:55 202 21 181 17:55 203 22 181 06/01/2011 10:15 201 21 180 11:15 202 21 181 12:!5 204 22 182 13:15 202 21 181 07/01/2011 9:30 202 21 181 10:30 201 21 180 11:30 202 20 182 12:30 202 21 181 Average 202 21 181 Unit 5 Date Time Gross Output Auxiliary Load Net Output 02/01/2011 12:00 100 11 89 13:00 100 11 89 14:00 100 12 87 15:00 95 9 86 03/01/2011 10:40 98 11 87 11:40 98 11 86 12:40 97 12 85 13:40 98 12 86 04/01/2011 9:45 96 11 85 10:45 96 11 85 11:45 96 11 85 12:45 95 11 84 Average 97 11 86 Appendix B R1V02TAG: 04/27/11 B-6
Unit 6 Date Time Gross Output Auxiliary Load Net Output 02/01/2011 10:30 71 9 61 11:30 71 9 62 12:30 70 9 61 13:30 71 10 61 03/01/2011 10:30 74 9 65 11:30 77 9 68 12:30 76 10 67 13:30 75 10 65 04/01/2011 21:30 74 10 64 10:30 74 10 64 11:30 73 10 63 12:30 73 9 64 Average 73 10 64 Appendix B R1V02TAG: 04/27/11 B-7
Appendix C: Testing Procedures for Measurment of GENCOs Gross and Net Heat Rates C.1 TPS Jamshoro All of the four units at TPS Jamshoro have similar instrumentation arrangement for measurement of fuel input and electrical output. Exhibit C.1 shows the energy measurement system at TPS Jamshoro. The diagram indicates the ideal location of the measuring instruments for appropriate measurement input and output energy of the plant along with the actual instrumentation on ground at each unit. As can be seen from the diagram, RFO received from the tank lorry is measured with dipstick because of the absence of RFO flow meters at the oil receiving terminal. The separate RFO pipelines feed each unit through a dedicated service tank (day tank) through a flow meter. The calibration status of the flow meter however was not available and therefore the readings of flow meters were not considered for the testing purpose. The power station has arrangements to measure gross generation and auxiliary consumption at each unit but have no meter at the sent-out of each unit within the power station premises. The sent-out electrical energy meters for each unit are located at the adjoining NTDC 500 kv grid station. Appendix C R1V02TAG: 04/27/11 C-1
Exhibit C.1: Schematic Diagram Show Status of Measurement of Fuel Input and Electrical Output TPS Jamshoro Unit 1-4 Appendix C R1V02TAG: 04/27/11 C-2
C.1.1 Power Testing Procedure and Data Collected TPS Jamshoro has net sent-out meters at each unit located at the incoming busbar of the NTDC switchyard. These meters are at the premises of the nearby NTDC grid station and record energy sent-out at the scale of GWh. It is therefore, recommended that gross heat rates and efficiency should be used for the benchmarking purpose in future. The detailed procedure for calculation of heat rate for each unit is given below. The input and output measurement arrangement is same for all the four units of this power station. 1. Heat rate tests were conducted in two (2) sessions (in morning and in evening) for a duration of 3½ hours. 2. These units have their individual service tanks where the RFO consumption was measured using dip-tape during the test period. Flow meters were present on all the units but calibration records of the flow meters were not available. The readings from flow meters were noted for record purposes but not used in the heat rate analysis. 3. The fuel feeding tank was isolated by closing respective valves of supply and recirculation. 4. Each unit has gross energy generation meter and a unit auxiliary meter. Some of the auxiliaries were fed from other sources such as starting transformer through a separate meter. All units have independent net sent-out energy meters for energy delivered at the busbar of the NTDC switchyard. However, the measurement scale of the sent-out meter at the busbar of the NTDC switchyard was in GWh and therefore it was not possible to accurately capture the variations in KWh. Therefore, net generation was calculated at the unit output point by subtracting total auxiliary consumption from gross generation. The step-up transformer and cable losses for the units from generator terminal up to NTDC switchyard could not be calculated. 5. The readings of all the input and output measurement points were taken concurrently in the presence of station staff: a. Unit fuel input: The RFO consumption volume (in kilo or 000 liters) was measured at the service tank of the unit by using dip-tape and calibration charts for the service tanks. Temperature at the service tank was also recorded simultaneously. RFO consumption in metric tonnes was calculated after applying corrections for temperature and specific gravity of RFO. b. Unit energy output: Readings from gross energy meters, station auxiliary meters and other meters of auxiliary consumption through starting transformers were taken to measure the gross and net output of the plant after applying appropriate multiplying factors for respective meters. The detailed procedures for calculation of heat rates for TPS Jamshoro Units 1-4 are presented in Appendix D.2. Appendix C R1V02TAG: 04/27/11 C-3
C.2 TPS Guddu All the units at TPS Guddu have similar instrumentation arrangement for measurement of fuel input and electrical output for its steam and CCP blocks. Only Steam Unit 3 of the steam block could be tested. Steam unit 3 and 4 are dual fired units capable of both natural gas and RFO firing. RFO received from the tank lorry is measured with dipstick because of the absence of RFO flow meters at the oil-receiving terminal. The RFO is fed to Unit 3 and 4 through a common pipeline directly from main storage tanks. Both units have separate flow meters, however, the calibration status of the flow meter was not available and therefore the readings of flow meters were not considered for the testing purpose. Guddu receives medium calorific value raw gas from Kandhkot, Mari and Chachar. Gas meters are not present to measure the gas received at the power station. Since the pipelines are owned by Guddu power station, gas suppliers bill the power station from the meters installed at gas fields nearly 70-80 kilometers away from the power station. No gas flow meters are present at Steam Units 1 and 2. The gas flow meters at Steam unit 3 and Block 2B were either not functional or not calibrated. The power station has arrangements to measure gross generation and auxiliary consumption at each unit but have no meter at the sent-out of each unit within the power station premises. The sent-out electrical energy meters for each unit are located at the adjoining NTDC 500 kv grid station. Exhibit C.2 shows the energy measurement system at the steam block Units 3 and 4 whereas Exhibit C.3 shows the energy measurement system at the CCP block of TPS Guddu. Appendix C R1V02TAG: 04/27/11 C-4
Exhibit C.2: Schematic Diagram Show Status of Measurement of Fuel Input and Electrical Output Steam Block Unit 3-4 Appendix C R1V02TAG: 04/27/11 C-5
Steam Unit 1-2 and Steam Unit 4 Steam Units 1 and 2 were not tested due to absence of gas flow meters. Unit 4 could not be tested due to long shutdown due to breakdown of air pre-heater. Steam Unit 3 The detailed procedure for calculation of heat rate for Unit 3 is given here under: 1. The unit was running on mixed firing. The unit has operational gas and RFO flow meters. The consumption of gas was noted from gas flow meters at the specified time intervals. 2. These units do not have their individual service tanks and RFO is directly fed from main storage tanks through a common line for Units 3 & 4. RFO Flowmeters were present on both the units but calibration status of the flow meters was not available. Since Unit 4 was on prolonged shutdown, RFO was measured directly at the feeding (main storage) tank using the dip-tape. 3. Since feeding tank did not require frequent refills, heat rate tests were conducted in one session in the morning for duration of 6 hours. 4. The feeding tank was isolated by closing respective valves of supply and recirculation. 5. The Unit has gross energy generation and sent-out meters with no discrete measurement of auxiliary consumption. 6. The readings of all the input and output measurement points were taken concurrently in the presence of station staff: a. Unit fuel input: The readings of flow-meters installed in respective units were noted down concurrently with the dip measurement at the feeding tank. Temperatures at storage tanks were also recorded simultaneously. b. Unit energy output: The measurements were taken from gross energy and sent out meters. The auxiliary consumption and losses in step-up transformer and cables/lines up to sent-out busbar of the power station were calculated by subtracting the sent-out energy from the gross energy generation. Appendix C R1V02TAG: 04/27/11 C-6
Exhibit C.3: Schematic Diagram Show Status of Measurement of Fuel Input and Electrical Output TPS CCP Block 2-A and CCP Block 1 Appendix C R1V02TAG: 04/27/11 C-7
CCP Blocks The detailed procedure for calculation of heat rate for Block 1 and Block 2-A is given here under: 1. Due to availability of functional flow meters for gas measurement, heat rate tests were conducted in single session over the day for the duration of 8 hours. 2. The gas consumption was measured at the gas flow meters installed at the inlet of each gas turbine. 3. The unit has meters for gross energy generation, auxiliary consumption and energy sent-out at all units. 4. The readings of all the input and output measurement points were taken concurrently in the presence of station staff: a. Unit fuel input: The reading of flow-meters installed in respective control rooms were noted down. b. Unit energy output: The measurements were taken from gross energy, auxiliary supply, and sent out meters. The detailed procedures for calculation of heat rates for TPS Guddu CCP Block are presented in Appendix D.2. C.3 TPS Muzaffargarh TPS Muzaffargarh was constructed in three phases and each phase has its own arrangements for input and output of energy. Phase 1 consists of Units 1-3, Phase 2consists of Units 5 and 6 whereas Unit 4 is managed as separate entity in the power station. Exhibit C.4, C.5 and C.6 present energy measurement system at Phase 1, Phase 2 and Phase 3 of TPS Muzaffargarh. The diagram indicates the ideal location of the measuring instruments for appropriate measurement input and output energy of the plant along with the actual instrumentation on ground at each unit. Similar to arrangements at other GENCO power stations, RFO received from the tank lorry is measured with dipstick because of the absence of RFO flow meters at the oil receiving terminal. Although power station has dedicated storage facilities for each phase, these facilities were interconnected and are now used as common storage facilities for units. Units 1-4 do not have service tanks are instead fed directly from main storage tanks. Units 5-6 have dedicated service tanks. RFO flow meters are present on all units but these were either not functional or their calibration status was not known and therefore the readings of flow meters were not considered for the testing purpose. The power station has arrangements to measure gross generation and auxiliary consumption at each unit but have no meter at the sent-out of each unit within the power station premises. A number of units did not have discrete sources for their auxiliary consumption and were sharing the sources with other units. The sent out electrical energy meters for the power station are located at the adjoining NTDC grid stations. Appendix C R1V02TAG: 04/27/11 C-8
Exhibit C.4: Schematic Diagram Show Status of Measurement of Fuel Input and Electrical Output TPS Muzaffargarh Unit 2-3 Appendix C R1V02TAG: 04/27/11 C-9
C.3.1 Unit 1 Testing Procedures and Data Analysis This unit was not available for testing due to an extended shut down. Units 2 and 3 1. Heat rate tests were conducted in two (2) sessions (in morning and in evening) for duration of 3½ hours. 2. These units do not have their individual service tanks and RFO is directly fed from main storage tanks through a common line for Units 1-3. Flow-meters were present on both the units but calibration records for the meters were not available. Prior to running main heat rate tests on the units, the flow meters were manually adjusted to bring their readings in close proximity to the oil consumption measured through the dip method from the main storage tank feeding oil to these units. 3. The feeding tank was isolated by closing respective valves of supply and recirculation 4. This unit has gross energy generation meter and station auxiliary meters. Some of the auxiliary requirement was fed from other sources such as starting transformers through a separate meter. This unit does not have an independent net output energy meter so net output was calculated by subtracting total auxiliary consumption from the gross generation. The losses in step-up transformer and cables/lines up to sent-out busbar of the power station could not be calculated due to absence of sent-out meter at the unit. 5. The readings of all the input and output measurement points were taken concurrently in the presence of station staff: a. Unit fuel input: The reading of flow-meters installed in respective control rooms were noted down concurrently with the dip measurement at the feeding tank. Temperatures at storage tanks and flow meters were also recorded simultaneously. b. Unit energy output: Readings from gross energy meters, station auxiliary meters and other meters of auxiliary consumption through starting transformers were taken to measure the gross and net output of the plant after applying appropriate multiplying factors for respective meters. The detailed procedures for calculation of heat rates for Units 2-3 TPS Muzaffargarh are presented in Appendix D.3. Appendix C R1V02TAG: 04/27/11 C-10
Exhibit C.5: Schematic Diagram Show Status of Measurement of Fuel Input and Electrical Output TPS Muzaffargarh Unit 4 Appendix C R1V02TAG: 04/27/11 C-11
Unit 4 1. Heat rate tests were conducted in two (2) sessions (in morning and in evening) for duration of 3½ hours. 2. Unit 4 does not have its individual service tanks and RFO is directly fed from a dedicated main storage tanks. Flow-meter was present but calibration status of the meter was not available. The actual RFO consumption was directly measured through dip method from the main storage tank feeding to the unit. 3. The feeding tank was isolated by closing respective valves of supply, recirculation and condensate etc. 4. The Unit has gross energy generation meter and station auxiliary meters. The Unit does not have an independent net output energy meter so net output was calculated by subtracting total auxiliary consumption from the gross generation. The losses in step-up transformer and cables/lines up to sent-out busbar of the power station could not be calculated due to absence of sent out meter at the Unit. 5. The readings of all the input and output measurement points were taking concurrently in the presence of station staff: a. Unit fuel input: The RFO consumption was measured at the feeding tank with the dip-tape. Temperature at storage tank was also recorded simultaneously. b. Unit energy output: Readings from gross energy meters and station auxiliary meters were taken to measure the gross and net output of the plant after applying appropriate multiplying factors for respective meters. The detailed procedures for calculation of heat rates for Unit 4 TPS Muzaffargarh are presented in Appendix D.3. Appendix C R1V02TAG: 04/27/11 C-12
Exhibit C.6: Schematic Diagram Show Status of Measurement of Fuel Input and Electrical Output TPS Muzaffargarh Unit 5-6 Appendix C R1V02TAG: 04/27/11 C-13
Units 5 and 6 1. Heat rate tests were conducted in two (2) sessions (in morning and in evening) for duration of 3½ hours. 2. The Units have their individual service tanks. Flow-meters were present but were not functional at these units so the actual RFO consumption was directly measured through dip method from the service tank feeding to the unit. 3. The feeding tank was isolated by closing respective valves of supply, recirculation and condensate etc. 4. The Unit has gross energy generation meter and station auxiliary meters. The Unit does not have an independent net output energy meter so net output was calculated by subtracting total auxiliary consumption from the gross generation. The losses in step-up transformer and cables/lines up to sent-out busbar of the power station could not be calculated due to absence of sent out meter at the Unit. 5. The readings of all the input and output measurement points were taking concurrently in the presence of station staff: a. Unit fuel input: The RFO consumption was measured at the feeding tank with the dip-tape. Temperature at storage tank was also recorded simultaneously. b. Unit energy output: Readings from gross energy meters and station auxiliary meters were taken to measure the gross and net output of the plant after applying appropriate multiplying factors for respective meters. The detailed procedures for calculation of heat rates for Units 2-3 TPS Muzaffargarh are presented in Appendix D.3. Appendix C R1V02TAG: 04/27/11 C-14
Appendix D: Calculation of GENCOs Gross and Net Heat Rates See following pages. Appendix D R1V02TAG: 04/27/11 D-1
22-1-2011 21-1-2011 20-1-2011 19-1-2011 Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Specific Gravity @ 0.55% 1 Water Contents RFO Weight in Tank 2 RFO Consumption RFO Average Heating Value 3 Total Heat Input Gross Generation Meter Readings Gross Generation Auxiliary Consumption Meter Readings Aux. Consumption Aux. through start-up transformer meter Readings Aux. Feed through Startup Tr. Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Exhibit D.1: Calculation of Gross and Net Heat Rate and Efficiency TPS Jamshoro Calculations of Gross and Net Heat Rates and Efficiency Unit 1 TPS Jamshoro Date Time Meter s C o Tonne s Tonnes MBtu/ Tonne MMBtu 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh 1430 3.918 62.00 0.922 0.922 150.5 32,399 184,644 22,712 000' kwh 000' kwh 1630 1.430 62.00 0.922 0.922 54.8 95.7 39,881 3,816 32,788 389 184,675 32 22,713 1 33 1000 4.850 59.00 0.931 0.931 188.3 35,776 184,936 22,724 1230 1.690 61.00 0.930 0.930 65.3 122.9 39,881 4,902 36,267 491 184,974 39 22,726 2 40 1515 4.540 61.00 0.930 0.930 176.0 36,795 185,017 22,728 1715 2.060 58.00 0.931 0.932 79.8 96.2 39,881 3,837 37,196 401 185,048 32 22,729 1 33 1000 4.715 58.00 0.931 0.932 183.1 40,535 185,313 22,739 1200 2.195 59.50 0.931 0.932 85.1 98.0 39,881 3,910 40,932 397 185,345 31 22,741 1 33 1430 4.370 59.50 0.931 0.932 169.6 41,402 185,383 22,742 1630 2.000 62.00 0.922 0.922 76.6 93.0 39,881 3,709 41,771 369 185,413 30 22,743 1 31 1015 4.333 64.00 0.928 0.928 167.6 45,159 185,684 22,754 1215 1.996 65.00 0.927 0.928 77.0 90.6 39,881 3,614 45,529 370 185,714 30 22,756 1 31 1515 4.115 48.00 0.937 0.938 160.8 46,088 185,759 22,758 1715 1.820 61.00 0.930 0.930 70.4 90.4 39,881 3,604 46,458 370 185,789 30 22,759 1 31 Total 687 27,392 2,787 232 Appendix D R1V02TAG: 04/27/11 D-2
1 Total Fuel Input 27,392 MMBtu 2 Gross Generation 2,787 000 kwh 3 Gross Heat Rate 9,829 Btu/kWh 4 Gross Efficiency 34.7% 5 Auxiliary Consumption 232 000 kwh 6 Sent Out Energy 2,555 000 kwh 7 Net Heat Rate 10,720 Btu/kWh 8 Net Efficiency 31.8% 1. Standard RFO specific gravity was adjusted for water contents in RFO. The RFO present at the TPS Jamshoro had average water contents of 1.1% at the main storage tanks. It was assessed to reduce by 50% at temperature range of 55-65 Co at the service tank. A water content of 0.55% was therefore assessed for be present at service tank stage. In future, however, a sample for RFO analysis should be taken from service tank instead of storage tank to calculate the exact concentration of water contents. 2. RFO volume converted to weight by using calibration charts of the service tanks. 3. The RFO present at the TPS Jamshoro had average heating value of 40,103 MMBtu/Tonne at water contents of 1.1% at the main storage tanks. The heating value was also corrected for the water contents of 0.55% at service tank stage which worked out to be 38,881 MMBtu/Tonne. Appendix D R1V02TAG: 04/23/11 D-3
Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Specific Gravity @ 0.55% 1 Water Contents RFO Weight in Tank 2 RFO Consumption RFO Average Heating Value 3 Total Heat Input Gross Generation Meter Readings Gross Generation Auxiliary Consumption Meter Readings Aux. Consumption Aux. through start-up transformer meter Readings Aux. Feed through Start-up Tr. Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 2 TPS Jamshoro Date Time Meters C o Tonnes Tonnes MBtu/ Tonne 21-1-2011 1030 4.010 62.00 0.922 0.922 175.8 457,286 82,265 7,227 MMBtu 1230 2.195 62.00 0.922 0.922 105.1 70.7 39,881 2,820 457,512 226 82,278 13 7,228 1 14 1500 4.060 63.00 0.929 0.929 179.1 457,795 82,294 7,229 1700 2.335 65.00 0.927 0.928 111.4 67.7 39,881 2,698 458,021 226 82,307 13 7,229 1 14 22-1-2011 1030 4.025 68.00 0.926 0.926 177.1 460,016 82,421 7,237 1230 2.333 68.00 0.926 0.926 111.1 66.0 39,881 2,633 460,241 225 82,434 13 7,238 1 14 1500 3.667 61.00 0.930 0.930 163.9 460,517 82,450 7,239 1700 1.997 61.00 0.930 0.930 98.4 65.5 39,881 2,612 460,747 230 82,463 13 7,239 1 14 23-1-2011 1000 3.535 57.00 0.932 0.932 159.1 462,700 82,574 7,246 1200 1.884 57.00 0.932 0.932 94.2 64.9 39,881 2,589 462,930 230 82,588 13 7,247 1 14 1400 3.915 56.00 0.933 0.933 174.1 463,157 82,601 7,248 1600 2.245 56.00 0.933 0.933 108.5 65.7 39,881 2,618 463,383 226 82,614 13 7,249 1 14 Total 400.5 15,971 1,362 83 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh Appendix D R1V02TAG: 04/23/11 D-4
1 Total Fuel Input 15,971 MMBtu 2 Gross Generation 1,362 000 kwh 3 Gross Heat Rate 11,727 Btu/kWh 4 Gross Efficiency 29.1% 5 Auxiliary Consumption 83 000 kwh 6 Sent Out Energy 1,279 000 kwh 7 Net Heat Rate 12,492 Btu/kWh 8 Net Efficiency 27.3% 1. Standard RFO specific gravity was adjusted for water contents in RFO. The RFO present at the TPS Jamshoro had average water contents of 1.1% at the main storage tanks. It was assessed to reduce by 50% at temperature range of 55-65 C at the service tank. A water content of 0.55% was therefore assessed for be present at service tank stage. In future, however, a sample for RFO analysis should be taken from service tank instead of storage tank to calculate the exact concentration of water contents. 2. RFO volume converted to weight by using calibration charts of the service tanks. 3. The RFO present at the TPS Jamshoro had average heating value of 40,103 MMBtu/Tonne at water contents of 1.1% at the main storage tanks. The heating value was also corrected for the water contents of 0.55% at service tank stage which worked out to be 38,881 MMBtu/Tonne. Appendix D R1V02TAG: 04/23/11 D-5
Date Time Dip-Tape Readings Tank Tempe-rature RFO Specific Gravity RFO Specific Gravity @ 0.55% 1 Water Contents RFO Weight in Tank 2 RFO Consumption RFO Average Heating Value 3 Total Heat Input Gross Generation Meter Readings Gross Generation Auxiliary Consumption Meter Readings Aux. Consump-tion Aux. through startup transformer meter Readings Aux. Feed through Start-up Tr. Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 3 TPS Jamshoro Meter s C Tonne s Tonne s MBtu/ Tonne MMBtu 17-2-2011 1130 3.870 64.00 0.928 0.928 185.3 908,168 164,906 35,505 1330 1.995 64.00 0.928 0.928 111.5 73.9 39,881 2,946 908,418 250 164,929 23 35,507 2 25 1500 1700 39,881 18-2-2011 1000 4.160 67.00 0.926 0.927 196.4 910,948 165,170 35,532 1200 2.260 67.00 0.926 0.927 121.7 74.7 39,881 2,980 911,193 245 165,193 23 35,535 2 26 1330 3.970 63.00 0.929 0.929 189.4 911,380 165,210 35,536 1530 2.065 63.00 0.929 0.929 114.3 75.1 39,881 2,995 911,636 256 165,235 25 35,539 2 27 19-2-2011 1000 4.105 57.00 0.932 0.932 195.4 913,950 165,170 35,562 1200 2.260 56.00 0.933 0.933 122.5 72.9 39,881 2,908 914,194 244 165,193 23 35,564 2 26 1330 4.050 58.00 0.931 0.932 193.1 914,378 165,499 35,566 1530 2.190 58.00 0.931 0.932 119.6 73.5 39,881 2,933 914,626 248 165,522 24 35,568 2 26 Total 370.1 14,761 1,243 130 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh 000' kwh Appendix D R1V02TAG: 04/23/11 D-6
1 Total Fuel Input 14,761 MMBtu 2 Gross Generation 1,243 000 kwh 3 Gross Heat Rate 11,879 Btu/kWh 4 Gross Efficiency 28.7% 5 Auxiliary Consumption 130 000 kwh 6 Sent Out Energy 1,113 000 kwh 7 Net Heat Rate 13,262 Btu/kWh 8 Net Efficiency 25.7% 1. Standard RFO specific gravity was adjusted for water contents in RFO. The RFO present at the TPS Jamshoro had average water contents of 1.1% at the main storage tanks. It was assessed to reduce by 50% at temperature range of 55-65 C at the service tank. A water content of 0.55% was therefore assessed for be present at service tank stage. In future, however, a sample for RFO analysis should be taken from service tank instead of storage tank to calculate the exact concentration of water contents. 2. RFO volume converted to weight by using calibration charts of the service tanks. 3. The RFO present at the TPS Jamshoro had average heating value of 40,103 MMBtu/Tonne at water contents of 1.1% at the main storage tanks. The heating value was also corrected for the water contents of 0.55% at service tank stage which worked out to be 38,881 MMBtu/Tonne. Appendix D R1V02TAG: 04/23/11 D-7
Time Dip-Tape Readings Tank Tempe-rature RFO Specific Gravity RFO Specific Gravity @ 0.55% 1 Water Contents RFO Weight in Tank 2 RFO Consumption RFO Average Heating Value 3 Total Heat Input Gross Generation Meter Readings Gross Generation Auxiliary Consumption Meter Readings Aux. Consump-tion Aux. through startup transformer meter Readings Aux. Feed through Start-up Tr. Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 4 TPS Jamshoro Date Meters C Tonnes Tonnes MBtu/ Tonne MMBtu 000' kwh 000' kwh 000' kwh 17-2-2011 1200 4.338 63.00 0.929 0.929 203.9 980,414 162,654 1400 2.200 66.00 0.927 0.927 119.4 84.5 39,881 3,370 980,766 352 162,680 26 26 1500 1700 39,881 18-2-2011 1030 4.330 67.00 0.926 0.927 203.1 983,751 162,947 1230 2.200 67.00 0.926 0.927 119.3 83.8 39,881 3,340 984,045 295 162,973 26 26 1400 4.370 61.00 0.930 0.930 205.4 984,264 162,992 1600 2.280 64.00 0.928 0.928 122.7 82.7 39,881 3,299 984,557 293 163,018 26 26 19-2-2011 1030 4.370 57.00 0.932 0.932 205.9 987,219 163,260 1230 2.370 60.00 0.930 0.931 126.5 79.4 39,881 3,165 987,495 277 163,285 25 25 1430 4.140 59.00 0.931 0.931 196.6 987,775 163,310 1600 2.650 59.00 0.931 0.931 137.7 58.9 39,881 2,348 987,981 206 163,329 19 19 Total 389.2 15,521 1,423 122 000' kwh 000' kwh 000' kwh 000' kwh Appendix D R1V02TAG: 04/23/11 D-8
1 Total Fuel Input 15,521 MMBtu 2 Gross Generation 1,423 000 kwh 3 Gross Heat Rate 10,909 Btu/kWh 4 Gross Efficiency 31.3% 5 Auxiliary Consumption 122 000 kwh 6 Sent Out Energy 1,301 000 kwh 7 Net Heat Rate 11,935 Btu/kWh 8 Net Efficiency 28.6% 1. Standard RFO specific gravity was adjusted for water contents in RFO. The RFO present at the TPS Jamshoro had average water contents of 1.1% at the main storage tanks. It was assessed to reduce by 50% at temperature range of 55-65 C at the service tank. A water content of 0.55% was therefore assessed for be present at service tank stage. In future, however, a sample for RFO analysis should be taken from service tank instead of storage tank to calculate the exact concentration of water contents. 2. RFO volume converted to weight by using calibration charts of the service tanks. 3. The RFO present at the TPS Jamshoro had average heating value of 40,103 MMBtu/Tonne at water contents of 1.1% at the main storage tanks. The heating value was also corrected for the water contents of 0.55% at service tank stage which worked out to be 38,881 MMBtu/Tonne. Appendix D R1V02TAG: 04/23/11 D-9
Exhibit D.2: Calculation of Gross and Net Heat Rate and Efficiency TPS Guddu CCP Block 2-A: GT 7 Date Time Gas Flow Gross Generation Auxiliary Consumption MCF MWh Reading 1. 30-12-2010 1000 801,690 83,904 5,503 2. 1100 803,240 84,000 5,504 3. 1300 806,290 84,189 5,505 4. 1500 809,210 84,370 5,507 5. 1700 811,840 84,530 5,508 6. 31-12-2010 900 834,350 85,935 5,518 7. 1100 837,360 86,122 5,519 8. 1300 9. 1600 844,750 86,583 5,522 10. 1700 846,110 86,670 5,523 11. 01-01-2011 900 869,830 88,162 5,533 12. 1100 872,800 88,350 5,534 13. 1300 875,850 88,542 5,535 14. 15. 1600 880,430 88,822 5,537 16. 02-01-2011 900 905,150 90,435 5,547 17. 1100 909,170 90,623 5,548 18. 1300 912,220 90,811 5,550 19. 20. 1600 916,820 91,096 5,552 1. Initial Gas Meters Reading 801,690 MCF 2. Final Gas Reading 916,820 MCF 3. Difference 115,130 MCF 4. Gas Calorific Value 802.11 Btu/Scf 5. Total Fuel Input 92,347 MMBtu 6. Intial Gross Generation Reading 83,904 MWh 7. Final Gross Generation Reading 91,096 MWh 8. Difference 7,192 MWh 9. Gross Generation 7,192,000 kwh 10. Gross Heat Rate 12,840 Btu/kWh 11. Gross Efficiency 27% 12. Intial Auxiliary Consumprion Reading 5,503 13. Final Auxiliary Consumprion Reading 5,552 14. Difference 49 15. Mutliplying Factor 640 16. Auxiliary Consumption 31,360 kwh 17. Sent Out Energy 7,160,640 kwh 18. Net Heat Rate 12,896 Btu/kWh 19. Net Efficiency 26% Appendix D R1V02TAG: 04/23/11 D-10
CCP Block 2-A: GT 8 Date Time Gas Flow Gross Generation Auxiliary Consumption MCF MWh Reading 1. 30-12-2010 1000 891,530 41,323 6,559 2. 1100 892,980 41,408 6,560 3. 1300 895,890 41,581 6,561 4. 1500 898,780 41,751 6,562 5. 1700 901,580 41,922 6,563 6. 31-12-2010 900 924,220 43,286 6,572 7. 1100 927,120 43,460 6,573 8. 1300 9. 1600 934,270 43,887 6,575 10. 1700 935,630 43,973 6,576 11. 01-01-2011 900 958,290 45,334 6,585 12. 1100 961,070 45,502 6,586 13. 1300 963,960 45,672 6,587 14. 15. 1600 968,300 45,928 6,589 16. 02-01-2011 900 992,330 47,358 6,598 17. 1100 995,220 47,529 6,609 18. 1300 998,090 47,699 6,600 19. 20. 1600 1,002,440 47,956 6,601 1. Initial Gas Meters Reading 891,530 MCF 2. Final Gas Reading 1,002,440 MCF 3. Difference 110,910 MCF 4. Gas Calorific Value 802.11 Btu/Scf 5. Total Fuel Input 88,962 MMBtu 6. Intial Gross Generation Reading 41,323 MWh 7. Final Gross Generation Reading 47,956 MWh 8. Difference 6,633 MWh 9. Gross Generation 6,633,000 kwh 10. Gross Heat Rate 13,412 Btu/kWh 11. Gross Efficiency 25% 12. Intial Auxiliary Consumprion Reading 6,559 13. Final Auxiliary Consumprion Reading 6,601 14. Difference 42 15. Mutliplying Factor 640 16. Auxiliary Consumption 26,880 kwh 17. Sent Out Energy 6,606,120 kwh 18. Net Heat Rate 13,467 Btu/kWh 19. Net Efficiency 25% Appendix D R1V02TAG: 04/23/11 D-11
CCP Block 2-A: ST5 Date Time Gas Flow Gross Generation Auxiliary Consumption MCF MWh Reading 1. 30-12-2010 1000 15,623 4,157 2. 1100 15,694 4,157 3. 1300 15,828 4,158 4. 1500 15,975 4,158 5. 1700 16,104 4,159 6. 31-12-2010 900 17,109 4,160 7. 1100 17,243 4,161 8. 1300 9. 1600 17,578 4,162 10. 1700 17,650 4,162 11. 01-1-2011 900 18,690 4,164 12. 1100 18,821 4,164 13. 1300 18,955 4,165 14. 15. 1600 19,159 4,165 16. 02-1-2011 900 20,276 4,167 17. 1100 29,400 4,167 18. 1300 20,533 4,168 19. 20. 1600 20,739 4,168 1. Initial Gas Meters Reading MCF 2. Final Gas Reading MCF 3. Difference MCF 4. Gas Calorific Value Btu/Scf 5. Total Fuel Input - MMBtu 6. Intial Gross Generation Reading 15,623 MWh 7. Final Gross Generation Reading 20,739 MWh 8. Difference 5,116 MWh 9. Gross Generation 5,116,000 kwh 10. Gross Heat Rate Btu/kWh 11. Gross Efficiency 12. Intial Auxiliary Consumprion Reading 4,157 13. Final Auxiliary Consumprion Reading 4,168 14. Difference 11 15. Mutliplying Factor 10,000 16. Auxiliary Consumption 110,000 kwh 17. Sent Out Energy 5,006,000 kwh 18. Net Heat Rate Btu/kWh 19. Net Efficiency Appendix D R1V02TAG: 04/23/11 D-12
CCP Block 2-A 1. Total Fuel Input 181,309 MMBtu 2. Gross Generation 18,941,000 kwh 3. Gross Heat Rate 9,572 Btu/kWh 4. Gross Efficiency 36% 5. Auxiliary Consumption 168,240 kwh 6. Sent Out Energy 18,772,760 kwh 7. Net Heat Rate 9,658 Btu/kWh 8. Net Efficiency 35% Appendix D R1V02TAG: 04/23/11 D-13
CCP Block 2-A: GT 11 Date Time Gas Flow Gross Generation Auxiliary Consumption MCF MWh Reading 1. 03-01-2011 2. 1100 256,005 952,690 729,322 3. 1300 256,713 952,855 730,200 4. 5. 1600 257,770 953,102 731,538 6. 04-01-2011 900 263,804 954,502 738,999 7. 1100 264,533 954,672 739,908 8. 1300 265,225 954,832 740,757 9. 10. 1600 266,288 955,079 742,077 11. 05-01-2011 900 272,323 956,481 749,434 12. 1100 273,034 956,646 750,322 13. 1300 273,743 956,811 751,225 14. 15. 1600 274,805 957,058 752,576 16. 06-01-2011 900 280,832 958,458 760,040 17. 1100 281,542 958,623 760,877 18. 1300 282,214 958,789 761,706 19. 20. 1600 283,328 959,036 763,007 1. Initial Gas Meters Reading 256,005 HCM 2. Final Gas Reading 283,328 HCM 3. Difference 27,323 HCM 4. Unit conversion 3.53 HCM to MCF 5. Gas Consumption 96,490 MCF 6. Gas Calorific Value 802.11 Btu/Scf 7. Total Fuel Input 77,396 MMBtu 8. Intial Gross Generation Reading 952,690 MWH 9. Final Gross Generation Reading 959,036 MWH 10. Difference 6,346 MWH 11. Gross Generation 6,346,000 kwh 12. Gross Heat Rate 12,196 Btu/kWh 13. Gross Efficiency 28% 14. Intial Auxiliary Consumprion Reading 729,322 15. Final Auxiliary Consumprion Reading 763,007 16. Auxiliary Consumption 33,685 kwh 17. Sent Out Energy 6,312,315 kwh 18. Net Heat Rate 12,261 Btu/kWh 19. Net Efficiency 28% Appendix D R1V02TAG: 04/23/11 D-14
CCP Block 2-A: GT 12 Date Time Gas Flow Gross Generation Auxiliary Consumption MCF MWh Reading 1. 03-01-2011 2. 1100 873,114 476,780 326,176 3. 1300 873,818 476,944 326,672 4. 5. 1600 874,899 477,193 327,448 6. 04-01-2011 900 880,922 478,579 331,606 7. 1100 881,632 478,743 332,118 8. 1300 882,360 478,910 332,639 9. 10. 1600 883,437 479,158 333,401 11. 05-01-2011 900 889,480 480,550 337,454 12. 1100 890,178 480,711 337,939 13. 1300 890,901 480,878 338,454 14. 15. 1600 891,941 481,119 339,193 16. 06-01-2011 900 897,970 482,515 343,244 17. 1100 898,684 482,678 343,689 18. 1300 899,413 482,845 344,145 19. 20. 1600 900,414 483,100 344,877 1. Initial Gas Meters Reading 873,114 HCM 2. Final Gas Reading 900,414 HCM 3. Difference 27,300.00 HCM 4. Unit conversion 3.53 HCM to MCF 5. Gas Consumption 96,409 MCF 6. Gas Calorific Value 802.11 Btu/Scf 7. Total Fuel Input 77,331 MMBtu 8. Intial Gross Generation Reading 476,780 MWH 9. Final Gross Generation Reading 483,100 MWH 10. Difference 6,320 MWH 11. Gross Generation 6,320,000 kwh 12. Gross Heat Rate 12,236 Btu/kWh 13. Gross Efficiency 28% 14. Intial Auxiliary Consumprion Reading 326,176 15. Final Auxiliary Consumprion Reading 344,877 16. Auxiliary Consumption 18,701 kwh 17. Sent Out Energy 6,301,299 kwh 18. Net Heat Rate 12,272 Btu/kWh 19. Net Efficiency 28% Appendix D R1V02TAG: 04/23/11 D-15
CCP Block 2-A: ST13 Date Time Gas Flow Gross Generation Auxiliary Consumption MCF MWh Reading 1. 03-01-2011 2. 1100 675,538 344,914 3. 1300 675,703 344,920 4. 5. 1600 675,956 344,931 6. 04-01-2011 900 677,382 344,990 7. 1100 677,551 344,997 8. 1300 677,721 345,004 9. 10. 1600 677,975 345,015 11. 05-10-2011 900 679,402 345,074 12. 1100 679,571 345,081 13. 1300 679,739 345,088 14. 15. 1600 679,989 345,099 16. 06-01-2011 900 681,409 345,157 17. 1100 681,583 345,164 18. 1300 681,758 345,171 19. 20. 1600 682,020 345,181 1. Initial Gas Meters Reading - MCF 2. Final Gas Reading - MCF 3. Difference - MCF 4. Gas Calorific Value - Btu/Scf 5. Total Fuel Input - MMBtu 6. Intial Gross Generation Reading 675,538 MWH 7. Final Gross Generation Reading 682,020 MWH 8. Difference 6,482 MWH 9. Gross Generation 6,482,000 kwh 10. Gross Heat Rate - Btu/kWh 11. Gross Efficiency 0% 12. Intial Auxiliary Consumprion Reading 344,914 MWh 13. Final Auxiliary Consumprion Reading 345,181 MWh 14. Difference 267 MWh 15. Mutliplying Factor 1,000 16. Auxiliary Consumption 267,000 kwh 17. Sent Out Energy 6,215,000 kwh 18. Net Heat Rate - Btu/kWh 19. Net Efficiency 0% Appendix D R1V02TAG: 04/23/11 D-16
CCP Block 1 1. Total Fuel Input 154,727 MMBtu 2. Gross Generation 19,148,000 kwh 3. Gross Heat Rate 8,081 Btu/kWh 4. Gross Efficiency 42% 5. Auxiliary Consumption 319,386 kwh 6. Sent Out Energy 18,828,614 kwh 7. Net Heat Rate 8,218 Btu/kWh 8. Net Efficiency 42% Appendix D R1V02TAG: 04/23/11 D-17
Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Weight in Tank 1 Total RFO Consump-tion for Unit 2 and 3 Proportion of RFO attributed to Unit 2 2 Total RFO Consump-tion for Unit 2 RFO Average Heating Value 3 Total Heat Input for Unit 2 Gross Generation Meter Readings Gross Generation Total Auxiliary Consumption from Table B Technical Audit Study of GENCO Power Plants Exhibit D.3: Calculation of Gross and Net Heat Rate and Efficiency TPS Muzaffargarh Calculations of Gross and Net Heat Rates and Efficiency Unit 2 TPS Muzaffargarh Table A Date Time Meters Co Tonnes Tonnes Tonnes MBtu/ Tonne MMBtu 000' kwh kwh kwh 9-01-2011 1015 12.888 81.00 0.918 14,794 5,277,770 1415 12.608 80.00 0.919 14,482 312.4 55% 171.6 39,278 6,740 5,278,445 675,000 41,976 1530 12.514 80.00 0.919 14,374 5,278,655 1730 12.368 80.00 0.919 14,206 167.7 55% 92.5 39,278 3,634 5,278,995 340,000 21,780 10-01-2011 945 11.217 81.00 0.918 12,876 5,281,765 1345 10.947 80.00 0.919 12,574 302.1 55% 166.3 39,278 6,534 5,282,445 680,000 42,240 1500 10.861 80.00 0.919 12,475 5,282,660 1900 10.584 79.00 0.919 12,165 310.6 56% 172.6 39,278 6,779 5,283,332 672,000 42,134 11-01-2011 1045 9.507 82.00 0.918 10,906 5,286,002 1445 9.232 80.00 0.919 10,604 302.3 54% 164.5 39,278 6,460 5,286,670 668,000 47,784 1500 9.214 80.00 0.919 10,583 5,286,710 1900 8.932 80.00 0.919 10,260 323.9 53% 171.2 39,278 6,724 5,287,340 630,000 50,160 Total 1,719.1 938.7 36,870 3,665,000 246,074 Appendix D R1V02TAG: 04/23/11 D-18
Auxiliary Consumption Meter A Readings Aux. ConsumptionSide A Aux. Consumption Side A4 Auxiliary Consumption Meter B Readings Aux. Consumption Side B4 Aux. Consumption Side B Aux. through start-up transformer meter Readings Difference Aux. Feed through Start-up Tr. Aux. Feed through Start-up Tr. For Unit 2 Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Table B Date Time kwh kwh kwh kwh kwh 9-01-2011 1015 8,993 6,565 3,181 1415 8,994 0.86 22,704 6,565 0.68 17,952 3,182 0.10 2,640 1,320 41,976 1530 8,994 6,566 3,182 1730 8,994 0.42 11,088 6,566 0.35 9,240 3,182 0.11 2,904 1,452 21,780 10-01-2011 945 8,998 6,569 3,181 1345 8,999 0.85 22,440 6,570 0.70 18,480 3,182 0.10 2,640 1,320 42,240 1500 8,999 6,570 3,182 1900 9,000 0.83 21,938 6,570 0.71 18,744 3,182 0.11 2,904 1,452 42,134 11-01-2011 1045 9,003 6,574 5,142 1445 9,004 0.82 21,648 6,574 0.75 19,800 5,142 0.48 12,672 6,336 47,784 1500 9,004 6,574 5,142 1900 9,005 0.81 21,384 6,575 0.80 21,120 5,143 0.58 15,312 7,656 50,160 Total 246,074 Appendix D R1V02TAG: 04/23/11 D-19
1 Total Fuel Input 36,870 MMBtu 2 Gross Generation 3,665,000 kwh 3 Gross Heat Rate 10,060 Btu/kWh 4 Gross Efficiency 33.9% 5 Auxiliary Consumption 246,074 kwh 6 Sent Out Energy 3,418,926 kwh 7 Net Heat Rate 10,784 Btu/kWh 8 Net Efficiency 31.6% 1. RFO volume converted to weight by using calibration charts of the storage tanks using the conversion of 1,250 Tonnes/meter. 2. Unit 1-3 are supplied RFO from a common storage tank. The total supply from the storage tank was divided on the basis of proportion of the consumption recorded by RFO flow meters installed at each of these units. Unit 1 was not operational so total consumption was divided between Unit 2 and 3 accordingly 3. The RFO present at the TPS Muzaffargarh had average heating value of 39,278 MBtu/Tonne at the main storage tank feeding Unit 2 and 3. 4. Auxiliary consumption of Sides A and B and start-up Transformer converted to kwh by using the multiplying factor of 26,400 for Auxiliary Meters. The start-up transformer was shared between Unit 2 and 3 so its total supply was divided equally between Units 2 and 3. Appendix D R1V02TAG: 04/23/11 D-20
Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Weight in Tank 2 Total RFO Consump-tion for Unit 2 and 3 Proportion of RFO attributed to Unit 2 3 Total RFO Consump-tion for Unit 2 RFO Average Heating Value 4 Total Heat Input for Unit 2 Gross Generation Meter Readings Gross Generation Total Auxiliary Consumption from Table B Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 3 TPS Muzaffargarh Table A Date Time Meters Co Tonnes Tonnes Tonnes MBtu/ Tonne MMBtu 000' kwh kwh kwh 9-01-2011 1015 12.888 81.00 0.918 14,794 6,055,416 1415 12.608 80.00 0.919 14,482 312.4 45% 140.8 39,278 5,532 6,055,974 558,000 41,712 1530 12.514 80.00 0.919 14,374 6,056,155 1730 12.368 80.00 0.919 14,206 167.7 45% 75.2 39,278 2,953 6,056,435 280,000 21,648 10-01-2011 945 11.217 81.00 0.918 12,876 6,058,735 1345 10.947 80.00 0.919 12,574 302.1 45% 135.8 39,278 5,334 6,059,295 560,000 40,656 1500 10.861 80.00 0.919 12,475 6,059,465 1900 10.584 79.00 0.919 12,165 310.6 44% 138.0 39,278 5,422 6,060,035 570,000 40,841 11-01-2011 1045 9.507 82.00 0.918 10,906 6,062,240 1445 9.232 80.00 0.919 10,604 302.3 46% 137.9 39,278 5,415 6,062,795 555,000 46,728 1500 9.214 80.00 0.919 10,583 6,062,830 1900 8.932 80.00 0.919 10,260 323.9 47% 152.7 39,278 5,999 6,063,390 560,000 45,936 Total 1,719.1 780.5 30,655 3,083,000 237,521 Appendix D R1V02TAG: 04/23/11 D-21
Auxiliary Consumption Meter A Readings Aux. Consumption Side A Aux. Consumption Side A5 Auxiliary Consumption Meter B Readings Aux. Consumption Side B4 Aux. Consumption Side B Aux. through start-up transformer meter Readings Difference Aux. Feed through Start-up Tr. Aux. Feed through Start-up Tr. For Unit 2 Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Table B Date Time kwh kwh kwh kwh kwh 9-01-2011 1015 9,815 9,576 3,181 1415 9,816 0.75 19,800 9,577 0.78 20,592 3,182 0.10 2,640 1,320 41,712 1530 9,816 9,577 3,182 1730 9,816 0.39 10,164 9,578 0.38 10,032 3,182 0.11 2,904 1,452 21,648 10-01-2011 945 9,819 9,581 3,181 1345 9,820 0.74 19,536 9,582 0.75 19,800 3,182 0.10 2,640 1,320 40,656 1500 9,820 9,582 3,182 1900 9,821 0.73 19,325 9,583 0.76 20,064 3,182 0.11 2,904 1,452 40,841 11-01-2011 1045 9,824 9,586 5,142 1445 9,825 0.73 19,272 9,586 0.80 21,120 5,142 0.48 12,672 6,336 46,728 1500 9,825 9,587 5,142 1900 9,826 0.73 19,272 9,587 0.72 19,008 5,143 0.58 15,312 7,656 45,936 Total 237,521 Appendix D R1V02TAG: 04/23/11 D-22
1 Total Fuel Input 30,655 MMBtu 2 Gross Generation 3,083,000 kwh 3 Gross Heat Rate 9,943 Btu/kWh 4 Gross Efficiency 34.3% 5 Auxiliary Consumption 237,521 kwh 6 Sent Out Energy 2,845,479 kwh 7 Net Heat Rate 10,773 Btu/kWh 8 Net Efficiency 31.7% 1. RFO volume converted to weight by using calibration charts of the storage tanks using the conversion of 1,250 Tonnes/meter. 2. Unit 1-3 are supplied RFO from common storage tank. The total supply from storage tank was divided on the basis of proportion of the consumption recorded by RFO flow meters installed at each of these units. Unit 1 was not operational so total consumption was divided between Unit 2 and 3 accordingly 3. The RFO present at the TPS Muzaffargarh had average heating value of 39,278 MBtu/Tonne at the main storage tank feeding Unit 2 and 3. 4. Auxiliary consumption of Sides A and B and start-up Transformer converted to kwh by using the multiplying factor of 26,400 for Auxiliary Meters. The start-up transformer was shared between Unit 2 and 3 so its total supply was divided equally between Units 2 and 3. Appendix D R1V02TAG: 04/23/11 D-23
Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Specific Gravity @ 0.55% 1 Water Contents RFO Weight in Tank 2 RFO Consumption RFO Average Heating Value 3 Total Heat Input Gross Generation Meter Readings Gross Generation Gross Generation Auxiliary Consumption Meter Readings Aux. Consumption Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 4 TPS Muzaffargarh Date Time Meters Co Tonnes Tonnes MBtu/ Tonne MMBtu kwh kwh 5-01-2011 1500 10.740 50.00 0.936 0.937 13,921 499,933 51,219 1830 10.608 50.00 0.936 0.937 13,749 39,278 500,079 51,293 1840 10.600 50.00 0.936 0.937 13,739 500,087 51,297 2210 10.455 50.00 0.936 0.937 13,551 369.4 39,278 14,509 500,234 301.0 1,444,800 51,373 154.0 154,000 6-01-2011 900 10.025 51.00 0.935 0.936 12,986 500,696 51,610 1230 9.888 52.00 0.935 0.936 12,801 39,278 500,843 51,683 1245 9.877 52.00 0.935 0.936 12,786 500,853 51,688 1645 9.717 52.00 0.935 0.936 12,579 406.6 39,278 15,972 501,022 326.0 1,564,800 51,775 165.0 165,000 7-01-2011 910 9.060 53.00 0.934 0.935 11,722 501,707 52,126 1310 8.900 53.00 0.934 0.935 11,515 39,278 501,877 52,209 1520 8.805 54.00 0.934 0.934 11,385 501,968 52,254 1850 8.672 54.00 0.934 0.934 11,213 508.8 39,278 19,986 502,118 411.0 1,972,800 52,328 202.0 202,000 Total 1,284.9 50,468 4,982,400 521,000 Appendix D R1V02TAG: 04/23/11 D-24
1 Total Fuel Input 50,468 MMBtu 2 Gross Generation 4,982,400 kwh 3 Gross Heat Rate 10,129 Btu/kWh 4 Gross Efficiency 33.7% 5 Auxiliary Consumption 521,000 kwh 6 Sent Out Energy 4,461,400 kwh 7 Net Heat Rate 11,312 Btu/kWh 8 Net Efficiency 30.2% 1. RFO volume converted to weight by using calibration charts of the storage tanks using the conversion of 1,384.74 Tonnes/meter. 2. The RFO present at the TPS Muzaffargarh had average heating value of 39,278 MBtu/Tonne at the main storage tank feeding Unit 4. 3. Auxiliary consumption converted to kwh by using the multiplying factor of 1,000 for Auxiliary Meters. Appendix D R1V02TAG: 04/23/11 D-25
Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Specific Gravity @ 1.08% Water Contents RFO Weight in Tank 2 Total RFO Consump-tion for Unit 2 RFO Average Heating Value 4 Total Heat Input for Unit 2 Gross Generation Meter Readings Difference Gross Generation Total Aux. Consump-tion from Table B Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 5 TPS Muzaffargarh Table A Date Time Meters Co Tonnes Tonnes MBtu/ Tonne MMBtu kwh kwh 2-01-2011 1230 5.345 38.00 0.943 0.943 197 5,827 1530 3.050 41.00 0.941 0.942 112 84.6 39,707 3,361 5,827 0.8 287,280 35,151 1630 5.135 38.00 0.943 0.943 189 5,828 1930 3.105 39.00 0.942 0.943 114 74.8 39,707 2,969 5,828 0.7 275,940 35,151 3-01-2011 1030 4.990 36.00 0.944 0.945 184 5,832 1400 2.985 36.00 0.944 0.945 110 73.9 39,707 2,933 5,833 0.6 245,700 30,615 1530 5.545 36.00 0.944 0.945 204 5,833 1900 3.100 36.00 0.944 0.945 114 90.1 39,707 3,577 5,834 0.8 317,520 41,010 4-01-2011 915 5.415 35.00 0.945 0.945 200 5,838 1245 2.925 36.00 0.944 0.945 108 91.8 39,707 3,647 5,838 0.8 317,520 39,593 1605 5.540 37.00 0.943 0.944 204 5,839 1935 3.130 37.00 0.943 0.944 115 88.7 39,707 3,523 5,840 0.8 313,740 40,065 Total 503.9 20,010 1,757,700 221,585 Appendix D R1V02TAG: 04/23/11 D-26
Auxiliary Consumption Meter Readings Aux. Consumption Aux. Consumption 5 Aux. through start-up transformer meter Readings Difference Aux. Feed through Start-up Tr. Aux. Feed through Start-up Tr. For Unit 5 Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants Table B kwh kwh kwh kwh 19,929 1,314 19,929 0.72 34,020 1,314 0.01 2,263 1,131 35,151 19,930 1,314 19,930 0.72 34,020 1,314 0.01 2,263 1,131 35,151 19,934 1,314 19,935 0.62 29,295 1,314 0.01 2,640 1,320 30,615 19,335 1,314 19,336 0.84 39,690 1,314 0.01 2,640 1,320 41,010 19,940 1,314 19,940 0.81 38,273 1,314 0.01 2,640 1,320 39,593 19,941 1,314 19,942 0.82 38,745 1,314 0.01 2,640 1,320 40,065 Total 221,585 1 Total Fuel Input 20,010 MMBtu 2 Gross Generation 1,757,700 kwh 3 Gross Heat Rate 11,384 Btu/kWh 4 Gross Efficiency 30.0% 5 Auxiliary Consumption 221,585 kwh 6 Sent Out Energy 1,536,115 kwh 7 Net Heat Rate 13,026 Btu/kWh 8 Net Efficiency 26.2% 1. RFO volume converted to weight by using calibration charts of the service tanks using the conversion of 39 Tonnes/meter. 2. The RFO present at the TPS Muzaffargarh had an average heating value of 39,278 MBtu/Tonne at the main storage tank feeding Unit 2 and 3. 3. Auxiliary consumption was converted to kwh by using multiplying factor of 47,250 for Auxiliary Meters. In addition, reading of start-up Transformer was converted to kwh by using the multiplying factor of 264,000 for transformer Meters. The start-up transformer was shared between Unit 5 and 6 so its total supply was divided equally between Units 5 and 6. Appendix D R1V02TAG: 04/23/11 D-27
Dip-Tape Readings Tank Temperature RFO Specific Gravity RFO Specific Gravity @ 1.08% Water Contents RFO Weight in Tank 2 Total RFO Consump-tion for Unit 2 RFO Average Heating Value 4 Total Heat Input for Unit 2 Gross Generation Meter Readings Difference Gross Generation Total Aux. Consump-tion Table B Technical Audit Study of GENCO Power Plants Calculations of Gross and Net Heat Rates and Efficiency Unit 6 TPS Muzaffargarh Table A Date Time Meters Co Tonnes Tonnes MBtu/ Tonne MMBtu kwh kwh 2-01-2011 1035 4.710 40.00 0.942 0.942 173 3,650 1405 2.730 41.00 0.941 0.942 100 72.8 39,707 2,892 3,651 0.6 226,800 33,450 1540 4.710 39.00 0.942 0.943 173 3,651 1840 2.955 40.00 0.942 0.942 109 64.6 39,707 2,565 3,651 0.5 204,120 28,461 3-01-2011 1045 4.435 38.00 0.943 0.943 163 3,654 1400 2.445 40.00 0.942 0.942 90 73.3 39,707 2,912 3,655 0.6 238,140 32,505 1600 4.790 38.00 0.943 0.943 176 3,655 1930 2.705 38.00 0.943 0.943 100 76.7 39,707 3,046 3,656 0.7 253,260 34,395 4-01-2011 900 4.840 37.00 0.943 0.944 178 3,659 1230 2.795 39.00 0.942 0.943 103 75.4 39,707 2,995 3,659 0.6 241,920 33,922 1500 4.535 37.00 0.943 0.944 167 3,660 1830 2.455 39.00 0.942 0.943 90 76.7 39,707 3,045 3,661 0.7 245,700 34,395 Total 439.6 17,455 1,409,940 197,128 Appendix D R1V02TAG: 04/23/11 D-28
Auxiliary Consumption Meter Readings Aux. Consumption Aux. Consumption 5 Aux. through start-up transformer meter Readings Difference Aux. Feed through Start-up Tr. Aux. Feed through Start-up Tr. For Unit 5 Total Aux. Consump-tion Technical Audit Study of GENCO Power Plants kwh kwh kwh kwh 17,297 1,314 17,298 0.68 32,130 1,314 0.01 2,640 1,320 33,450 17,298 1,314 17,299 0.58 27,405 1,314 0.01 2,112 1,056 28,461 17,302 1,314 17,302 0.66 31,185 1,314 0.01 2,640 1,320 32,505 17,303 1,314 17,304 0.70 33,075 1,314 0.01 2,640 1,320 34,395 17,306 1,314 17,307 0.69 32,602 1,314 0.01 2,640 1,320 33,922 17,307 1,314 17,308 0.70 33,075 1,314 0.01 2,640 1,320 34,395 Total 197,128 1 Total Fuel Input 17,455 MMBtu 2 Gross Generation 1,409,940 kwh 3 Gross Heat Rate 12,380 Btu/kWh 4 Gross Efficiency 27.6% 5 Auxiliary Consumption 197,128 kwh 6 Sent Out Energy 1,212,812 kwh 7 Net Heat Rate 14,392 Btu/kWh 8 Net Efficiency 23.7% 1. RFO volume converted to weight by using calibration charts of the service tanks using the conversion of 39 Tonnes/meter. 2. The RFO present at the TPS Muzaffargarh had average heating value of 39,278 MBtu/Tonne at the main storage tank feeding Unit 2 and 3. 3. Auxiliary consumption was converted to kwh by using multiplying factor of 47,250 for Auxiliary Meters. In addition reading of start-up Transformer was converted to kwh by using the multiplying factor of 264,000 for transformer Meters. The start-up transformer was shared between Unit 5 and 6 so its total supply was divided equally between Units 5 and 6. Appendix D R1V02TAG: 04/23/11 D-29
Appendix E: Power Plant Availability See following pages. Appendix E R1V02TAG: 04/23/11 E-1
Steam Unit 1 Installed Capacity Derated Capacity Month 250 MW 187 MW Max. Load Min. Load Exhibit E.1: Power Plant Availability-TPS Jamshoro Load Factor (%) Utilization Factor @ DC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Total Hours of Month Availability Factor (Time-base) Jul, 09 135 100 85 52 5 739 744 99% Aug, 09 150 125 67 46 152 592 744 80% Sep, 09 165 125 77 57 91 629 720 87% Oct, 09 165 63 78 58 38 706 744 95% Nov, 09 150 125 58 39 216 504 720 70% Dec, 09 0 0 744 744 0% Jan, 10 200 63 12 11 632 1 112 744 15% Feb, 10 200 125 85 77 29 643 672 96% Mar, 10 180 140 80 65 114 630 744 85% Apr, 10 187 63 88 75 40 680 720 94% May, 10 180 125 90 74 744 744 100% Jun, 10 187 125 51 43 266 454 720 63% Jul, 10 180 63 84 69 63 681 744 92% Aug, 10 180 63 87 71 744 744 100% Sep, 10 160 70 77 56 28 692 720 96% Oct, 10 180 65 56 46 83 98 564 744 76% Nov, 10 150 63 34 23 370 84 266 720 37% Total FY2010 200 63 64 50 1,592 737 6,431 8,760 73% Total FY2011 YTD* 180 63 68 53 481 245 2,946 3,672 80% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-2
Steam Unit 2 Installed Capacity Derated Capacity Month 200 MW 160 MW Max. Load Min. Load Load Factor (%) Utilization Factor (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Total Hours of Month Availability Factor (Time-base) Jul, 09 180 100 79 81 116 628 744 84% Aug, 09 180 100 62 66 180 564 744 76% Sep, 09 165 90 84 81 4 716 720 99% Oct, 09 170 100 75 75 105 639 744 86% Nov, 09 175 100 61 63 208 512 720 71% Dec, 09 170 140 82 82 61 683 744 92% Jan, 10 170 120 80 80 10 734 744 99% Feb, 10 120 120 69 69 108 564 672 84% Mar, 10 170 100 76 76 78 666 744 90% Apr, 10 165 90 88 85 720 720 100% May, 10 165 90 64 63 140 5 599 744 81% Jun, 10 160 100 85 80 15 705 720 98% Jul, 10 140 100 94 77 744 744 100% Aug, 10 140 100 86 71 21 723 744 97% Sep, 10 130 100 60 46 134 586 720 81% Oct, 10 110 110 27 17 527 217 744 29% Nov, 10 170 100 31 31 279 162 279 720 39% Total FY2010 180 90 75 75 140 889 7,731 8,760 88% Total FY2011 YTD* 170 100 60 49 806 318 2,549 3,672 69% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-3
Steam Unit 3 Installed Capacity Derated Capacity Month 200 MW 160 MW Max. Load Min. Load Load Factor (%) Utilization Factor (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Total Hours of Month Availability Factor (Time-base) Jul, 09 130 100 72 55 142 602 744 81% Aug, 09 135 120 90 71 0 744 744 100% Sep, 09 140 100 90 74 0 720 720 100% Oct, 09 130 100 66 50 216 528 744 71% Nov, 09 175 100 38 39 398 1 322 720 45% Dec, 09 180 100 68 72 164 580 744 78% Jan, 10 170 100 74 74 744 744 100% Feb, 10 170 100 63 63 157 48 467 672 70% Mar, 10 170 100 85 85 25 719 744 97% Apr, 10 160 100 91 86 720 720 100% May, 10 160 100 65 62 193 551 744 74% Jun, 10 170 150 94 94 720 720 100% Jul, 10 170 100 91 91 744 744 100% Aug, 10 170 100 48 48 320 25 399 744 54% Sep, 10 170 100 58 58 156 564 720 78% Oct, 10 170 100 47 47 316 428 744 57% Nov, 10 0 0 544 176 720 0% Total FY2010 180 100 75 69 770 572 7,417 8,760 85% Total FY2011 YTD* 170 49 49 864 673 2,134 3,672 58% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-4
Steam Unit 4 Installed Capacity Derated Capacity Month 200 MW 160 MW Max. Load Min. Load Load Factor (%) Utilization Factor (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 165 130 86 83 24 720 744 97% Aug, 09 160 140 63 59 226 518 744 70% Sep, 09 150 100 84 74 73 647 720 90% Oct, 09 170 100 78 78 86 658 744 88% Nov, 09 175 100 94 97 720 720 100% Dec, 09 175 100 94 97 744 744 100% Jan, 10 170 100 86 86 58 686 744 92% Feb, 10 170 100 62 62 141 531 672 79% Mar, 10 170 100 91 91 744 744 100% Apr, 10 165 100 81 79 62 658 720 91% May, 10 160 150 90 85 744 744 100% Jun, 10 150 100 69 60 159 561 720 78% Jul, 10 155 100 60 55 253 491 744 66% Aug, 10 170 100 57 57 235 7 502 744 67% Sep, 10 170 100 17 17 125 595 720 83% Oct, 10 170 100 79 79 744 744 100% Nov, 10 140 100 62 51 166 554 720 77% Total FY2010 175 100 81 79 141 688 7,931 8,760 91% Total FY2011 YTD* 170 100 55 52 488 298 2,886 3,672 79% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-5
Steam Unit 1 Installed Capacity Derated Capacity Month 100 MW 60 MW Max. Load Min. Load Exhibit E.2: Power Plant Availability-TPS Guddu Load Factor (%) Utilization Factor @ DC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Total Hours of Month Availability Factor (Time-base) Jul, 09 50 15 83% 44% 101 643 744 86% Aug, 09 50 10 73% 43% 172 572 744 77% Sep, 09 50 25 88% 43% 42 678 720 94% Oct, 09 50 25 97% 44% 4 740 744 100% Nov, 09 55 30 80% 46% 91 629 720 87% Dec, 09 60 10 87% 48% 10 734 744 99% Jan, 10 60 10 85% 48% 29 715 744 96% Feb, 10 55 50 97% 49% 672 672 100% Mar, 10 55 30 92% 48% 34 710 744 95% Apr, 10 55 35 41% 41% 361 359 720 50% May, 10 50 20 73% 43% 162 582 744 78% Jun, 10 50 25 72% 40% 133 587 720 82% Jul, 10 50 20 47% 34% 268 476 744 64% Aug, 10 50 20 88% 42% 10 735 744 99% Sep, 10 50 20 92% 43% 11 709 720 98% Oct, 10 55 50 39% 47% 434 310 744 42% Nov, 10 720 720 Total FY2010 60 10 81% 45% 361 777 7,622 8,760 87% Total FY2011 YTD* 55 20 53% 33% 1,154 289 2,229 3,672 61% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-6
Steam Unit 2 Installed Capacity Derated Capacity Month 100 MW 60 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Total Hours of Month Availability Factor (Time-base) Jul, 09 50 10 70% 44% 204 540 744 73% Aug, 09 50 10 92% 43% 25 719 744 97% Sep, 09 50 10 74% 43% 3 717 720 100% Oct, 09 50 10 96% 49% 60 684 744 92% Nov, 09 70 30 75% 56% 106 614 720 85% Dec, 09 70 50 93% 60% 6 738 744 99% Jan, 10 70 50 93% 62% 30 714 744 96% Feb, 10 70 50 77% 62% 138 534 672 79% Mar, 10 70 10 81% 59% 96 648 744 87% Apr, 10 65 20 77% 51% 84 636 720 88% May, 10 60 10 87% 53% 78 666 744 90% Jun, 10 60 40 79% 45% 20 700 720 97% Jul, 10 50 50 93% 42% 3 741 744 100% Aug, 10 55 15 64% 43% 744 744 100% Sep, 10 55 15 43% 38% 149 571 720 79% Oct, 10 65 25 57% 46% 18 726 744 98% Nov, 10 65 40 85% 56% 81 639 720 89% Total FY2010 70 10 83% 52% 850 7,910 8,760 90% Total FY2011 YTD* 65 15 68% 45% 251 3,421 3,672 93% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-7
Steam Unit 3 Installed Capacity Derated Capacity Month 210 MW 170 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Total Hours of Month Availability Factor (Time-base) Jul, 09 140 60 51% 67% 325 40 380 744 51% Aug, 09 140 50 58% 65% 233 65 446 744 60% Sep, 09 140 30 68% 66% 70 650 720 90% Oct, 09 140 30 81% 69% 165 579 744 78% Nov, 09 155 50 92% 73% 47 673 720 93% Dec, 09 170 100 94% 76% 744 744 100% Jan, 10 170 100 74% 75% 151 593 744 80% Feb, 10 160 140 98% 75% 672 672 100% Mar, 10 160 20 83% 73% 100 644 744 87% Apr, 10 150 40 83% 69% 97 623 720 87% May, 10 150 50 79% 68% 125 619 744 83% Jun, 10 140 20 66% 60% 197 523 720 73% Jul, 10 120 30 79% 45% 4 740 744 99% Aug, 10 100 20 19% 45% 393 91 259 744 35% Sep, 10 130 10 9% 43% 32 688 720 96% Oct, 10 130 100 98% 61% 744 744 100% Nov, 10 130 80 56% 61% 720 720 100% Total FY2010 170 20 77% 70% 558 1,057 7,145 8,760 82% Total FY2011 YTD* 130 10 52% 51% 393 128 3,151 3,672 86% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-8
Steam Unit 4 Installed Capacity Derated Capacity Month 200 MW 150 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 110 20 81% 43% 6 738 744 99% Aug, 09 120 40 62% 45% 169 575 744 77% Sep, 09 100 20 6% 36% 666 54 720 7% Oct, 09 100 20 63% 63% 387 357 744 48% Nov, 09 150 20 88% 66% 36 684 720 95% Dec, 09 150 130 99% 71% 744 744 100% Jan, 10 150 130 81% 69% 116 628 744 84% Feb, 10 150 30 73% 65% 137 535 672 80% Mar, 10 150 30 92% 68% 26 718 744 96% Apr, 10 150 10 60% 57% 178 542 720 75% May, 10 150 110 92% 66% 744 744 100% Jun, 10 140 20 77% 56% 64 656 720 91% Jul, 10 120 20 32% 39% 391 353 744 47% Aug, 10 120 50 17% 51% 744 744 100% Sep, 10 0% 0% 720 720 100% Oct, 10 0% 0% 744 744 100% Nov, 10 150 10 56% 0% 3 717 720 100% Total FY2010 150 10 73% 59% 1,786 6,974 8,760 80% Total FY2011 YTD* 150 10 21% 18% 394 3,278 3,672 89% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-9
Block 2-A: GT Unit 7 Installed Capacity Derated Capacity Month 100 MW 90 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 85 10 94 81 13 731 744 98% Aug, 09 85 10 98 83 744 744 100% Sep, 09 85 80 78 85 1 719 720 100% Oct, 09 85 80 102 88 3 741 744 100% Nov, 09 90 25 100 90 5 715 720 99% Dec, 09 90 70 102 92 744 744 100% Jan, 10 90 60 99 91 17 727 744 98% Feb, 10 90 80 100 90 672 672 100% Mar, 10 90 42 78 88 149 595 744 80% Apr, 10 90 42 92 85 13 707 720 98% May, 10 92 55 83 77 6 738 744 99% Jun, 10 80 60 88 73 24 696 720 97% Jul, 10 90 70 79 82 96 648 744 87% Aug, 10 94 80 90 86 13 731 744 98% Sep, 10 97 90 93 92 10 710 720 99% Oct, 10 99 75 91 90 744 744 100% Nov, 10 103 50 81 86 14 706 720 98% Total FY2010 92 10 93 85 149 81 8,530 8,760 97% Total FY2011 YTD* 103 50 87 87 133 3,539 3,672 96% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-10
Block 2-A: GT Unit 8 Installed Capacity Derated Capacity Month 100 MW 90 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 80 40 91 74 9 735 744 99% Aug, 09 75 40 102 77 744 744 100% Sep, 09 75 75 80 77 720 720 100% Oct, 09 75 75 97 81 28 716 744 96% Nov, 09 85 80 99 85 4 716 720 99% Dec, 09 85 40 101 87 12 732 744 98% Jan, 10 85 40 99 86 16 728 744 98% Feb, 10 85 80 101 86 672 672 100% Mar, 10 90 65 91 82 744 744 100% Apr, 10 90 65 83 76 10 710 720 99% May, 10 85 55 72 67 60 684 744 92% Jun, 10 70 60 100 70 2 718 720 100% Jul, 10 80 70 88 70 3 741 744 100% Aug, 10 75 70 89 71 744 744 100% Sep, 10 70 70 102 71 720 720 100% Oct, 10 80 42 59 76 282 462 744 62% Nov, 10 85 65 96 82 5 715 720 99% Total FY2010 90 40 93 79 142 8,618 8,760 98% Total FY2011 YTD* 85 42 87 74 282 8 3,382 3,672 92% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-11
Block 2-A: Steam Unit 5 Installed Capacity Derated Capacity Month 100 MW 82 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 72 10 76 57 31 713 744 96% Aug, 09 70 10 82 59 14 730 744 98% Sep, 09 68 30 70 61 3 717 720 100% Oct, 09 68 30 94 68 23 721 744 97% Nov, 09 80 20 88 72 13 707 720 98% Dec, 09 78 34 90 70 744 744 100% Jan, 10 78 10 86 69 22 722 744 97% Feb, 10 82 65 87 72 672 672 100% Mar, 10 79 23 82 65 744 744 100% Apr, 10 79 23 68 56 29 691 720 96% May, 10 68 12 72 49 1 743 744 100% Jun, 10 66 5 74 49 8 712 720 99% Jul, 10 70 10 71 53 56 688 744 93% Aug, 10 67 36 74 51 32 712 744 96% Sep, 10 54 45 86 47 4 716 720 99% Oct, 10 48 7 74 36 744 744 100% Nov, 10 51 22 79 41 10 710 720 99% Total FY2010 82 5 81 62 144 8,616 8,760 98% Total FY2011 YTD* 70 7 77 46 102 3,570 3,672 97% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-12
CCP Block 2-A (GT7, GT8, ST5) Installed Capacity Derated Capacity Month 300 MW 262 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 237 60 88 71 18 726 744 98% Aug, 09 230 60 94 73 5 739 744 99% Sep, 09 228 185 76 74 1 719 720 100% Oct, 09 228 185 98 79 18 726 744 98% Nov, 09 255 125 96 82 7 713 720 99% Dec, 09 253 144 98 83 4 740 744 99% Jan, 10 253 110 95 82 18 726 744 98% Feb, 10 257 225 96 83 672 672 100% Mar, 10 259 130 84 78 50 694 744 93% Apr, 10 259 130 82 72 17 703 720 98% May, 10 245 122 76 64 22 722 744 97% Jun, 10 216 125 88 64 11 709 720 98% Jul, 10 240 150 79 69 52 692 744 93% Aug, 10 236 186 85 70 15 729 744 98% Sep, 10 221 205 94 70 5 715 720 99% Oct, 10 227 124 76 67 94 650 744 87% Nov, 10 239 137 86 70 10 710 720 99% Total FY2010 259 60 89 76 50 122 8,588 8,760 98% Total FY2011 YTD* 240 124 84 69 94 81 3,497 3,672 95% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-13
Block 2-B: GT Unit 9 Installed Capacity Derated Capacity Month 100 MW 90 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 70 44 101 71 4 740 744 99% Aug, 09 70 44 94 71 53 691 744 93% Sep, 09 70 16 101 71 720 720 100% Oct, 09 70 16 24 72 559 13 172 744 23% Nov, 09 720 720 Dec, 09 744 744 Jan, 10 744 744 Feb, 10 672 672 Mar, 10 744 744 Apr, 10 720 720 May, 10 744 744 Jun, 10 720 720 Jul, 10 744 744 Aug, 10 90 80 6 76 693 51 744 7% Sep, 10 100 80 39 84 383 337 720 47% Oct, 10 100 80 61 78 160 584 744 78% Nov, 10 100 20 23 76 169 1 549 720 76% Total FY2010 70 16 27 24 6,367 70 2,323 8,760 27% Total FY2011 YTD* 100 20 26 63 913 1,237 1,521 3,672 41% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-14
Block 2-B: GT Unit 10 Installed Capacity Derated Capacity Month 100 MW 90 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 75 45 90 72 50 694 744 93% Aug, 09 75 60 100 75 744 744 100% Sep, 09 75 10 89 75 720 720 100% Oct, 09 75 10 33 80 503 241 744 32% Nov, 09 720 720 Dec, 09 744 744 Jan, 10 744 744 Feb, 10 672 672 Mar, 10 744 744 Apr, 10 720 720 May, 10 744 744 Jun, 10 108 10 47 77 244 476 720 66% Jul, 10 90 20 80 79 72 672 744 90% Aug, 10 105 60 67 77 64 680 744 91% Sep, 10 100 70 78 88 82 638 720 89% Oct, 10 100 50 64 81 153 591 744 79% Nov, 10 100 10 18 63 250 28 443 720 61% Total FY2010 108 10 30 32 5,591 294 2,875 8,760 33% Total FY2011 YTD* 105 10 62 78 250 399 3,023 3,672 82% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-15
Block 2-B: Steam Unit 6 Installed Capacity Derated Capacity Month 100 MW 82 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 65 6 52 54 278 466 744 63% Aug, 09 66 5 82 54 3 741 744 100% Sep, 09 67 26 83 56 720 720 100% Oct, 09 67 26 25 52 503 1 240 744 32% Nov, 09 720 720 Dec, 09 744 744 Jan, 10 744 744 Feb, 10 672 672 Mar, 10 744 744 Apr, 10 720 720 May, 10 744 744 Jun, 10 720 720 Jul, 10 744 744 Aug, 10 744 744 Sep, 10 720 720 Oct, 10 744 744 Nov, 10 720 720 Total FY2010 67 5 20 18 6,311 281 2,167 8,760 25% Total FY2011 YTD* 3,672 3,672 0% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-16
CCP Block 2-B (GT9, GT10, ST6) Installed Capacity Derated Capacity Month 300 MW 262 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 210 95 82 66 111 633 744 85% Aug, 09 211 109 92 67 19 725 744 97% Sep, 09 212 52 91 67 720 720 100% Oct, 09 212 52 27 68 522 4 218 744 29% Nov, 09 720 720 Dec, 09 744 744 Jan, 10 744 744 Feb, 10 672 672 Mar, 10 744 744 Apr, 10 720 720 May, 10 744 744 Jun, 10 108 10 47 26 480 81 159 720 22% Jul, 10 90 20 80 26 496 24 224 744 30% Aug, 10 195 140 39 51 248 252 244 744 33% Sep, 10 200 150 59 57 240 155 325 720 45% Oct, 10 200 130 63 53 248 104 392 744 53% Nov, 10 200 30 20 46 380 10 331 720 46% Total FY2010 212 0 28 24 6,090 215 2,455 8,760 28% Total FY2011 YTD* 200 20 52 47 1,612 545 1,515 3,672 41% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-17
Block 1: GT Unit 11 Installed Capacity Derated Capacity Month 136 MW 90 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 80 60 101 60 744 744 100% Aug, 09 80 80 102 60 744 744 100% Sep, 09 80 16 88 59 2 718 720 100% Oct, 09 80 16 103 61 744 744 100% Nov, 09 80 80 101 60 5 715 720 99% Dec, 09 100 60 84 62 2 742 744 100% Jan, 10 100 60 80 59 10 734 744 99% Feb, 10 80 80 101 60 672 672 100% Mar, 10 80 80 91 60 88 657 744 88% Apr, 10 80 80 100 60 7 713 720 99% May, 10 80 80 101 60 4 740 744 99% Jun, 10 80 20 99 59 8 712 720 99% Jul, 10 80 60 102 60 1 743 744 100% Aug, 10 80 30 91 59 744 744 100% Sep, 10 80 40 102 60 720 720 100% Oct, 10 80 20 99 60 744 744 100% Nov, 10 80 70 100 60 720 720 100% Total FY2010 100 16 96 60 126 8,634 8,760 99% Total FY2011 YTD* 80 20 99 60 1 3,671 3,672 100% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-18
Block 1: GT Unit 12 Installed Capacity Derated Capacity Month 136 MW 80 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 80 13 101 60 2 742 744 100% Aug, 09 80 80 102 60 744 744 100% Sep, 09 80 70 100 59 720 720 100% Oct, 09 80 70 102 60 3 741 744 100% Nov, 09 80 80 102 60 720 720 100% Dec, 09 80 80 92 61 80 664 744 89% Jan, 10 80 80 102 61 10 734 744 99% Feb, 10 80 80 102 60 672 672 100% Mar, 10 80 80 103 61 744 744 100% Apr, 10 80 80 101 60 720 720 100% May, 10 80 40 101 59 1 743 744 100% Jun, 10 80 60 101 59 720 720 100% Jul, 10 80 80 102 60 744 744 100% Aug, 10 80 20 91 58 4 740 744 99% Sep, 10 80 20 58 53 720 720 100% Oct, 10 80 50 101 59 744 744 100% Nov, 10 80 70 100 60 3 717 720 100% Total FY2010 80 13 101 60 96 8,664 8,760 99% Total FY2011 YTD* 80 20 90 58 7 3,665 3,672 100% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-19
Block 1: Steam Unit 13 Installed Capacity Derated Capacity Month 143 MW 98 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 91 38 82 53 16 728 744 98% Aug, 09 90 11 97 62 11 733 744 99% Sep, 09 92 38 90 58 3 717 720 100% Oct, 09 92 38 99 64 744 744 100% Nov, 09 95 41 97 64 720 720 100% Dec, 09 98 43 90 62 744 744 100% Jan, 10 98 43 89 63 28 716 744 96% Feb, 10 65 54 142 65 4 668 672 99% Mar, 10 94 42 92 61 744 744 100% Apr, 10 91 38 54 48 205 515 720 72% May, 10 43 38 95 29 2 742 744 100% Jun, 10 83 38 60 35 720 720 100% Jul, 10 42 35 90 28 31 713 744 96% Aug, 10 40 28 95 28 32 712 744 96% Sep, 10 40 20 79 28 158 562 720 78% Oct, 10 82 30 47 43 285 459 744 62% Nov, 10 84 38 89 52 720 720 100% Total FY2010 98 11 91 55 269 8,491 8,760 97% Total FY2011 YTD* 84 20 80 36 507 3,165 3,672 86% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-20
CCP Block 1 (GT11, GT12, ST13) Installed Capacity Derated Capacity Month 415 MW 268 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Schdld. Outage Hours Forced Outage Hours Available Hours Total Hours of Month Availability Factor (Time Base) Jul, 09 251 111 94 57 6 738 744 99% Aug, 09 250 171 100 60 4 740 744 100% Sep, 09 252 124 93 59 2 718 720 100% Oct, 09 252 124 101 62 1 743 744 100% Nov, 09 255 201 100 61 2 718 720 100% Dec, 09 278 183 88 61 27 717 744 96% Jan, 10 278 183 89 61 16 728 744 98% Feb, 10 225 214 113 61 1 671 672 100% Mar, 10 254 202 95 61 29 715 744 96% Apr, 10 251 198 84 56 73 647 720 90% May, 10 203 158 100 49 2 742 744 100% Jun, 10 243 118 86 51 3 717 720 100% Jul, 10 202 175 99 49 11 733 744 99% Aug, 10 200 78 92 48 12 732 744 98% Sep, 10 200 80 80 47 54 666 720 92% Oct, 10 242 100 82 54 98 646 744 87% Nov, 10 244 178 96 57 1 719 720 100% Total FY2010 278 111 95 58 165 8,595 8,760 98% Total FY2011 YTD* 244 78 90 51 177 3,495 3,672 95% * Data available till November 2010 Appendix E R1V02TAG: 04/23/11 E-21
Steam Unit 1 Installed Capacity Derated Capacity Month 210 MW 160 MW Max. Load Min. Load Exhibit E.1: Power Plant Availability-TPS Muzaffargarh Load Factor (%) Utilization Factor @ DC (%) Utilization Factor @ IC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Availability Factor (Time-base) Jul, 09 155 110 86 66 51 744 100% Aug, 09 155 110 78 61 46 65 679 91% Sep, 09 145 110 80 58 44 37 683 95% Oct, 09 160 130 86 69 52 78 666 90% Nov, 09 160 110 99 79 60 3 717 100% Dec, 09 160 110 76 61 46 166 578 78% Jan, 10 160 130 86 69 53 64 680 91% Feb, 10 150 110 89 67 51 55 617 92% Mar, 10 150 110 58 44 33 122 622 84% Apr, 10 140 130 98 69 52 720 100% May, 10 140 115 61 43 32 242 502 68% Jun, 10 130 110 71 46 35 22 698 97% Jul, 10 110 105 69 38 29 118 626 84% Aug, 10 110 100 37 21 16 187 557 75% Sep, 10 100 95 80 40 30 101 619 86% Oct, 10 100 65 80 40 30 69 675 91% Nov, 10 100 65 31 16 12 40 680 94% Total FY2010 160 110 81 61 46 852 7,908 90% Total FY2011 YTD 110 65 59 31 23 515 3,157 86% Appendix E R1V02TAG: 04/23/11 E-22
Steam Unit 2 Installed Capacity Derated Capacity Month 210 MW 200 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Utilization Factor @ IC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Availability Factor (Time-base) Jul, 09 180 110 95 85 81 744 100% Aug, 09 180 110 99 89 85 744 100% Sep, 09 180 110 98 88 84 11 709 98% Oct, 09 180 170 99 89 85 744 100% Nov, 09 165 120 29 24 23 498 223 31% Dec, 09 200 175 53 53 51 206 91 447 60% Jan, 10 180 140 93 84 80 56 680 91% Feb, 10 150 110 82 74 70 95 577 86% Mar, 10 150 110 90 81 77 71 673 90% Apr, 10 140 130 100 90 86 1 719 100% May, 10 140 115 96 86 82 744 100% Jun, 10 130 110 82 74 70 54 666 93% Jul, 10 110 105 74 66 63 471 273 37% Aug, 10 110 100 62 48 46 31 713 96% Sep, 10 100 95 61 54 52 39 681 95% Oct, 10 100 65 82 74 70 86 658 88% Nov, 10 100 65 85 77 73 720 100% Total FY2010 200 110 85 76 73 703 378 7,671 88% Total FY2011 YTD 110 65 73 64 61 471 155 3,046 83% Appendix E R1V02TAG: 04/23/11 E-23
Steam Unit 3 Installed Capacity Derated Capacity Month 210 MW 160 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Utilization Factor @ IC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Availability Factor (Time-base) Jul, 09 150 110 86 64 49 744 100% Aug, 09 160 110 71 57 43 102 642 86% Sep, 09 140 105 82 57 44 38 682 95% Oct, 09 160 110 73 58 44 66 678 91% Nov, 09 160 80 89 71 54 36 684 95% Dec, 09 160 70 37 30 23 194 550 74% Jan, 10 90 50 68 31 23 131 613 82% Feb, 10 80 65 57 23 18 261 412 61% Mar, 10 130 70 61 39 30 Apr, 10 130 110 83 54 41 720 100% May, 10 110 80 94 52 39 6 738 99% Jun, 10 130 110 52 34 26 66 654 91% Jul, 10 160 145 34 28 21 2 742 100% Aug, 10 160 110 83 66 51 67 677 91% Sep, 10 160 110 78 62 47 14 706 98% Oct, 10 160 100 83 67 51 81 663 89% Nov, 10 160 100 54 43 33 720 100% Total FY2010 160 50 71 47 36 899 7,117 81% Total FY2011 YTD 160 100 66 53 41 163 3,509 96% Appendix E R1V02TAG: 04/23/11 E-24
Steam Unit 4 Installed Capacity Derated Capacity Month 320 MW 250 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Utilization Factor @ IC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Availability Factor (Time-base) Jul, 09 230 130 86 80 63 2 742 100% Aug, 09 235 145 87 83 65 3 741 100% Sep, 09 235 130 96 92 72 720 100% Oct, 09 245 215 82 82 64 91 653 88% Nov, 09 250 160 78 79 62 99 621 86% Dec, 09 250 160 96 98 77 19 725 97% Jan, 10 250 160 98 100 78 5 739 99% Feb, 10 250 220 88 100 78 672 100% Mar, 10 245 160 90 90 70 14 730 98% Apr, 10 235 160 89 88 69 720 100% May, 10 230 160 90 85 66 6 738 99% Jun, 10 220 160 87 78 61 720 100% Jul, 10 200 110 30 28 22 442 2 301 40% Aug, 10 185 140 37 28 22 333 102 310 42% Sep, 10 195 160 76 60 47 120 601 83% Oct, 10 205 165 75 63 49 145 14 886 119% Nov, 10 205 160 28 24 18 183 210 109 15% Total FY2010 250 130 89 88 69 240 8,520 97% Total FY2011 YTD 205 110 49 41 32 1,222 327 2,205 60% Appendix E R1V02TAG: 04/23/11 E-25
Steam Unit 5 Installed Capacity Derated Capacity Month 200 MW 120 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Utilization Factor @ IC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Availability Factor (Time-base) Jul, 09 80 80 57 31 18 161 583 78% Aug, 09 100 20 45 30 18 252 492 66% Sep, 09 90 40 34 20 12 425 295 41% Oct, 09 110 25 16 12 7 603 141 19% Nov, 09 120 110 22 17 10 424 111 185 26% Dec, 09 115 70 24 19 11 380 161 204 27% Jan, 10 110 50 79 58 35 98 646 87% Feb, 10 110 35 80 59 35 71 601 89% Mar, 10 110 25 30 22 13 351 393 53% Apr, 10 45 45 20 6 4 559 161 22% May, 10 100 20 8 5 3 647 97 13% Jun, 10 95 95 38 24 14 897 323 45% Jul, 10 95 30 70 44 27 15 729 98% Aug, 10 75 50 60 30 18 253 491 66% Sep, 10 75 20 72 36 22 2 718 100% Oct, 10 80 30 71 38 23 166 578 78% Nov, 10 80 80 16 9 5 593 127 18% Total FY2010 120 20 38 25 15 3,426 1,712 4,121 47% Total FY2011 YTD 95 20 58 31 19 436 593 2,643 72% Appendix E R1V02TAG: 04/23/11 E-26
Steam Unit 6 Installed Capacity Derated Capacity Month 200 MW 135 MW Max. Load Min. Load Load Factor (%) Utilization Factor @ DC (%) Utilization Factor @ IC (%) Schedld. Outage (Hrs.) Forced Outage (Hrs.) Availablity (Hrs.) Availability Factor (Time-base) Jul, 09 135 110 84 76 51 744 100% Aug, 09 120 40 64 51 35 169 575 77% Sep, 09 120 40 45 36 25 233 487 68% Oct, 09 100 20 72 48 32 162 743 100% Nov, 09 100 100 35 23 16 374 70 276 38% Dec, 09 100 25 53 35 24 250 15 479 64% Jan, 10 90 20 38 23 15 446 298 40% Feb, 10 105 20 66 46 31 180 492 73% Mar, 10 100 40 84 56 38 50 695 93% Apr, 10 95 95 92 59 40 720 100% May, 10 95 30 67 43 29 182 562 76% Jun, 10 95 60 80 51 34 62 658 91% Jul, 10 95 90 76 48 32 48 696 94% Aug, 10 90 30 56 34 23 174 570 77% Sep, 10 85 20 36 15 10 511 209 29% Oct, 10 85 30 75 44 30 74 670 90% Nov, 10 80 25 70 37 25 720 100% Total FY2010 135 20 65 46 31 624 1,568 6,729 77% Total FY2011 YTD 95 20 63 35 24 807 2,865 78% Appendix E R1V02TAG: 04/23/11 E-27