Document Title

Report Technology

Title: Generation Plant Engineering Unique Identifier: 474-10961 Life Cycle Planning/Strategic Report for Air Pollution Control for 2016 Alternative Reference Number: N/A

Area of Applicability: Engineering

Documentation Type: Report

Revision: 1

Total Pages: 36

Next Review Date: N/A

Disclosure Classification: CONTROLLED DISCLOSURE

Compiled by Functional Responsibility Authorised by

………………………………….. ………………………………….. …………………………………..

E.M. Patel K.B. Naicker Dr Z.T. Mathe Senior Consultant: Senior Manager: Production Senior Manager: Air Pollution Control Engineering Integration Coal Power Plant Engineering Boilers (Acting)

Date: …………………………… Date: …………………………… Date: ……………………………

Template Identifier: 240-60988962 Generation Plant Engineering Strategic Report for Area for 201x Template (Rev 2)

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CONTENTS

Page 1. INTRODUCTION ...... 4 2. SUPPORTING CLAUSES ...... 4 2.1 SCOPE ...... 4 2.1.1 Purpose ...... 4 2.1.2 Special Projects (Major Upgrades)...... 5 2.1.3 Risks ...... 7 2.1.4 Applicability...... 7 2.2 NORMATIVE/INFORMATIVE REFERENCES ...... 7 2.2.1 Normative ...... 8 2.2.2 Informative ...... 8 2.3 DEFINITIONS ...... 8 2.3.1 Classification ...... 8 2.4 ABBREVIATIONS ...... 8 2.5 ROLES AND RESPONSIBILITIES ...... 9 2.5.1 Flue Gas Cleaning System Teams...... 10 3. AIR POLLUTION CONTROL REPORT ...... 13 3.1.1 GENERIC LONG TERM LIFE CYCLE PHILOSOPHY (2016 VERSION – CAPEX CONSTRAINED) ... 13 3.1.2 GENERIC SHORT AND MEDIUM TERM LIFE CYCLE PHILOSOPHY...... 16 3.1.2.1 PLANT CONDITION AND STATUS REPORT ...... 16 3.1.2.2 SHORT AND MEDIUM TERM ACTIONS ...... 27 3.1.2.2.1 Outage Scopes of Work ...... 27 3.1.2.2.2 Continuous Emissions Monitoring (CEM) ...... 27 3.1.2.2.3 FFP Bag Routine Replacements ...... 28 3.1.2.2.4 Offset Project in Compliance with the MES Postponement Application ...... 28 3.2 STRATEGIC INITIATIVES (AS NECESSARY) ...... 28 3.3 POWER STATION SPECIFIC RECOMMENDATIONS ...... 28 3.3.1 ARNOT POWER STATION ...... 28 3.3.2 CAMDEN POWER STATION ...... 28 3.3.3 DUVHA POWER STATION ...... 29 3.3.4 GROOTVLEI POWER STATION ...... 29 3.3.5 HENDRINA POWER STATION ...... 30 3.3.6 KENDAL POWER STATION ...... 30 3.3.7 KOMATI POWER STATION ...... 31 3.3.8 KRIEL POWER STATION ...... 31 3.3.9 KUSILE POWER STATION ...... 32 3.3.10 LETHABO POWER STATION ...... 32 3.3.11 MAJUBA POWER STATION...... 33 3.3.12 MATIMBA POWER STATION ...... 33 3.3.13 MATLA POWER STATION ...... 33 3.3.14 MEDUPI POWER STATION ...... 33 3.3.15 TUTUKA POWER STATION ...... 34 3.3.16 PEAKING (GAS TURBINES) ...... 34 4. AUTHORISATION ...... 35 5. REVISIONS ...... 35 6. DEVELOPMENT TEAM ...... 35 7. ACKNOWLEDGEMENTS ...... 36

CONTROLLED DISCLOSURE When downloaded from the EDMS database, this document is uncontrolled and the responsibility rests with the user to ensure it is in line with the authorised version on the database.

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FIGURES

Figure 1: Generation Coal UCLF and Relative Emissions (FY2012 to YTD January 2016) ...... 16 Figure 2: YTDJan16 FY2016 UCLF Categories ...... 18 Figure 3: Arnot UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 20 Figure 4: Camden UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 20 Figure 5: Duvha UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 21 Figure 6: Hendrina UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 21 Figure 7: Kendal UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 22 Figure 8: Kriel UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 22 Figure 9: Lethabo UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)...... 23 Figure 10: Majuba UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 24 Figure 11: Matimba UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 24 Figure 12: Matla UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 25 Figure 13: Tutuka UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)...... 25 Figure 14: Grootvlei UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 26 Figure 15: Komati UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 26 Figure 16: Medupi UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016) ...... 27

TABLES

3 Table 1: Emission limits (mg/Nm , daily averages at 101.3 kPa, 273 K and 10% O2) granted in the Minimum Emission Standards postponement decision ...... 6 Table 2: Resources Allocated per Power Station ...... 11 Table 3: Summary of Activities ...... 14 Table 4: Summary of High Level Costs ...... 15 Table 5: YTD Feb 15FY2015 Relative Emissions Contribution Index ...... 19

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1. INTRODUCTION The objective of this exercise is to achieve compliance with air quality legislation and licences and strive for excellence by focusing on all projects relating to the Flue Gas Cleaning Systems currently in the life of plant plan (LOPP). The focus will be to ensure that the projects currently in the LOPP are prioritized by following a comprehensive risk assessment process, ensure the projects are phased correctly and additional important projects not currently captured on the LOPP are added. The projects will then be phased by the power station as accurately as possible. The most important key performance indicators on the flue gas cleaning plants are:  The number of times the emission limit values are exceeded,  The time operating under NEMA Section 30 and the total number of NEMA section 30s and legal contraventions incurred, and  The number of legal contraventions of Atmospheric Emission Licences (AELs). From the current performance indicators, it is clear that this part of the business is currently not being managed and monitored effectively/sufficiently and the current emission performance is not to the acceptable standards. In future, compliance with the stricter emission limits will be required in terms of the Minimum Emission Standards and the conditions of the approved/postponement requests, is also a key performance indicator.

2. SUPPORTING CLAUSES

2.1 SCOPE To achieve compliance with legislation, strive for excellence and to ensure no compromise on quality, it is also necessary to focus on the short term issues to ensure that the integrity and sustainability of the flue gas cleaning systems receives the necessary attention to improve on the current environmental performance. This document gives effect to the objectives of Eskom’s Air Quality Strategy. The main focus areas will be to assist the current System Engineers and Maintenance Supervisors by facilitating on-the-job training programmes on Electrostatic Precipitators (ESP’s), Fabric Filter Plants (FFP’s), Flue Gas Conditioning (FGC) plants and all gaseous and particulate monitoring equipment. In addition, the Flue Gas Cleaning Consultants and Engineers will assist the System Engineers and Maintenance Supervisors at the Power Stations with current plant problems such as ESP, FFP and FGC optimization and monitoring care programmes. Assistance will be given to ensure proper short term and planned outage scope of works and the identification of plant risks, complete with mitigation action plans.

2.1.1 Purpose The main objective of this document is therefore is to give guidance on how Eskom complies with South Africa’s emission standards and moves towards world class standards by reducing all particulate emissions to below 50 mg/Nm3 to achieve environmental compliance. In addition, all existing stations 3 3 need to comply with the new plant SO2 and NOX emission limits of 500 mg/Nm and 750 mg/Nm respectively by 01 April 2020. As a minimum, all plans contained here-in must ensure compliance with the station specific AEL and with the conditions in the decisions on the Minimum Emission Standards postponement applications, in the management of the asset base. Guiding principles: 1. Compliance with environmental legislation. 2. Continual improvement in emissions performance.

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3. Safety of plant and people will not be compromised. 4. The environment is to be prioritized when decisions are to be made regarding expenditure. 5. The integrity and sustainability of the flue gas cleaning asset base is to be maintained. 6. Reporting high emissions in terms of NEMA section 30 is always treated as a last resort. 8. Maintenance of the existing asset base. In the context of emissions, this also includes the up-stream (air heaters, ducts and combustion) and down-stream (materials handling) plants and processes.

2.1.2 Special Projects (Major Upgrades)

With the publishing of the Minimum Emissions Standards by the Department of Environmental Affairs in April 2010, the new standards applicable to the Eskom coal fired plant are as follows: Emissions Compliance Limits Existing Power Stations by Existing and New Power 3 April 2015 Stations by April 2020 (mg/Nm , normalised to 10% O2 on a dry basis) Particulate matter (PM) 100 50

Sulphur dioxide (SO2) 3 500 500

Oxides of nitrogen (Total NOX) 1 100 750

• All plant to have as a minimum continuous emissions monitoring systems in place for PM, SO2, NOX by 1 April 2015 or the date contained in the AEL. • Mercury (not part of minimum emissions standards): • Reduce relative emissions (by FFP and Flue Gas Desulphurisation (FGD) installations)

• All concentrations are normalised to the following: standard temperature and pressure at 10% O2 on a dry basis (maximum hourly releases). As of 01 April 2014, all emissions reporting is being normalised to this standard (this can only be done effectively and accurately with the installation of on-line O2 analysers in the stack). In terms of emissions abatement control on Eskom’s fleet, the focus to date has primarily been on particulate control. With the advent of the minimum emissions standards, focus is now moving toward De-SOX and De-NOX abatement technology. • Kusile (new build) will be Eskom’s first coal fired power station to employ a wet flue gas desulphurisation plant (FGD). • Medupi (new build) will be retrofitted with a wet-FGD during the first general overhaul (GO) cycle.

• Both Medupi and Kusile (new build) will comply with the NOX limits for new plant from inception. • Majuba, Matla and Tutuka will be retrofitted with Low NOx Burners to comply with the new plant NOx limit. It is anticipated that Kriel may not be required to comply with the 750 mg/Nm3 limit but will most likely be required to comply with the 1 100 mg/Nm3 limit until the station is de-commissioned. • Kendal (subject to confirmation through legal processes) will be retrofitted with FGD to comply with the new plant SO2 limit. Matimba is being contested by Eskom. • Feasibility studies have commenced for the upgrade of existing power stations in order for them to comply with the Minimum Emissions Standards. • The particulate upgrade strategy completed at the end of 2014.

• The NOX and SOX upgrade strategies are to be completed by the end of 2016 and 2017 respectively.

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Due to the serious impact of the legislative requirements on Eskom’s business, a dedicated team from PDD, CMD, GTE and Generation has been set up to look at developing a strategy for compliance, the business cases, feasibility studies, designs and execution strategies for each gaseous limit across the fleet. The filtering of these projects into the technical and life-of-plant plan will be communicated to the relevant power stations as and when they get approved. In the interim, all stations are to ensure that their current assets are maintained to ensure compliance with their emission licenses. In February 2015, the Department of Environmental Affairs (DEA) responded to Eskom’s applications for postponements of the MES. While the response was largely positive, compliance at certain stations remains a risk. The response is summarised below: SUMMARY OF MINIMUM EMISSION STANDARDS POSTPONEMENT DECISION, 24 February 2015

3 Table 1: Emission limits (mg/Nm , daily averages at 101.3 kPa, 273 K and 10% O2) granted in the Minimum Emission Standards postponement decision

PM SO2 NOX Other conditions 2015-2020 2020- 2015- 2020- 2015- 2020- 2025 2020 2025 2020 2025 Acacia 75 50 3500 500 1100 600 Arnot 100 50 3500 3500 1200 Re-apply Offsets Camden 100 50 3500 3500 1300 Re-apply Offsets Duvha 100 Re-apply 3500 2300 1100 1100 Offsets Grootvlei 1Apr15- Re-apply 3500 3500 1100 1100 Offsets 31Dec16: 350 1Jan17- 31Mar18: 200 1Apr18-31Mar20: 100 Hendrina 100 50 3500 3200 1200 Re-apply Offsets Kendal 100 Re-apply 3500 2600 1100 750 Offsets & FGD by 1 April 2025 Komati 100 Re-apply 3500 2600 1300 Re-apply Offsets Kriel 125 Re-apply 3500 2800 1600 Re-apply Offsets & FFP by 2025 Lethabo 100* Re-apply 3500 2800 1100 1100 Offsets Majuba 100 50 3500 3200 1500 Re-apply Offsets Matimba 100 50 3500 3500 1100 750 FGD by 1 April 2025 Matla U1-4: 200 Re-apply 3500 2600 1200 Re-apply Offsets U5-6: 100 Medupi 100 50 3500 3500 1100 750 FGD by 1 April 2025 Port Rex 75 50 3500 500 1100 600 Tutuka 1Apr15- Re-apply 3500 3400 1200 Re-apply Offsets and 31Dec18: 350 FFP by 1 Jan 1Jan19- 2020 31Dec19: 200 1Jan20: 100 * Monthly average until 31 Dec 2015 All cases where leniency from the Minimum Emission Standards was granted are indicated in bold font.

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An additional postponement application will be required: - For stations which cannot achieve a PM emission limit of 50 mg/Nm3 from 1 April 2020. The postponement decision did not consider requests for postponement of the 2020 PM emission standard, since a more stringent ambient limit is coming into effect. Moreover, there is no legal mandate for granting a postponement of PM emission limits, since there is non-compliance with ambient PM limits everywhere in the vicinity of Eskom’s power stations. - For stations which were granted leniency from the 2015 standard, and require leniency beyond 2020. The maximum period for the postponement granted could be 5 years.

Additional conditions are: 1. All Highveld stations (Highveld and Vaal Priority areas) require offsets to address ambient PM concentrations. These offsets are being driven by Eskom Environmental Management at present. 2. Kriel needs FFP by 1 April 2025, and Tutuka needs FFP by 1 January 2020 (subject to confirmation by the National Air Quality Officer) 3. Medupi, Matimba and Kendal need FGD by 1 April 2025

While the full compliance dates for the above are impractical, it will be addressed through the next postponement application. This report provides the system engineers with considerations necessary to develop a life cycle plan for the related plant system. The report will highlight areas of concern illustrated by poor plant performance and plant health parameters and recommend corrective actions that will be planned over the remaining life of the plant.

2.1.3 Risks

In the development of this report, it is assumed that the stations will operate and maintain their asset base in accordance with the design specifications of the plant. There have been a number of events in the last year in which the plant was injudiciously operated. This has led to the need for significant repairs and/or modifications. While the extent of some of these events has been incorporated into this report, there is still major uncertainty in the scope until adequate access is given for a proper evaluation. Failure to ensure compliance with Atmospheric Emission Licences and the decision on the Minimum Emission Standards may well result in power stations losing their licence to operate and/or criminal prosecution of individuals. The lack of funding as a result of the MYPD 3 tariff determination has forced Eskom to re-prioritise some of the air quality control projects. These have changed significantly from the 2015 version of this report and the new 2016 proposal which is discussed further in later sections of this document.

2.1.4 Applicability This document shall apply to all Eskom Power Stations and specifically to the relevant plant system.

2.2 NORMATIVE/INFORMATIVE REFERENCES Parties using this document shall apply the most recent edition of the documents listed in the following paragraphs.

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2.2.1 Normative [1] ISO 9001 Quality Management Systems. [2] Eskom Air Quality Strategy (32-1143). [3] Eskom Atmospheric Emission Management Policy (32-419).

2.2.2 Informative [4] The individual station specific Atmospheric Emissions Licence (AEL). [5] Eskom Standard for Emissions Monitoring and Reporting (240-56242363). [6] Continuous Emission Monitoring System Selection Specification (240-56242850). [7] Fabric Filter Plant Bag Specification (240-53113965). [8] Consistent Data Set for Eskom Generation Plant (36-623).

2.3 DEFINITIONS Definition Description 3 o mg/Sm Concentrations normalised to 0 C and 101.3 kPa at actual O2 on a wet basis. 3 o mg/Nm Concentrations normalised to 0 C, 101.3 kPa, at 10% O2 on a dry basis (note the international standard requires the O2 normalisation to 6%)

2.3.1 Classification Controlled Disclosure: Controlled Disclosure to external parties (either enforced by law, or discretionary).

2.4 ABBREVIATIONS Abbreviation Description AEL Atmospheric Emission Licence AM Asset Management APPA Air Pollution Prevention Act CARU Coarse Ash Removal System CCS Carbon Capture and Sequestration CEMS Continuous Emissions Monitoring Systems CFD Computation Flow Dynamics DHP Dust Handling Plant ERAP Engineering Risk Assessment Program ESP Electrostatic Precipitator FFP Fabric Filter Plant FGC Flue Gas Conditioning Plant FGD Flue Gas Desulphurisation GTE Group Technology Engineering

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Abbreviation Description GO General Overhaul Gx Generation Division

H2O Water HF High frequency IDC Interest During Construction kg/MWh SO Kilograms emitted per megawatt hour sent out LC Life Cycle

LNB Low NOX Burner/s LOPP Life of Plant Plan MES Minimum Emissions Standard mg/Nm3 Milligrams emitted per normal cubic meter mg/Sm3 Milligrams emitted per standard cubic meter MYPD Multi Year Price Determination

NOX Oxides of Nitrogen

O2 Oxygen PAN Polyacrylonitrile PJFFP Pulse Jet Fabric Filter Plant PEIC Production Engineering Integration (Coal) PM Particulate Matter PPS Polyphenelyene Sulphide PS Power Station RE Relative Emissions RoE Rate of Exchange SE System Engineer

SO3 Sulphur Tri-oxide

SOX Oxides of Sulphur SOW Scope of Work UCLF Unplanned Capability Loss Factor

2.5 ROLES AND RESPONSIBILITIES Power Stations Managers: Manager with the accountability to effectively, reliably and efficiently operate the generating assets covered under the life cycle plans. Engineering Manager: Manager with the responsibility to identify the technical plant risks relevant to the Power Station Manager fulfilling his mandate and proposing corrective actions to mitigate the risks. The Engineering Manager must incorporate the costs and associated outages into the station LOPPS and Outage and Maintenance plans. PEIC: Responsible for the fleet-wide strategy and recommendations for implementation in the life cycle plans.

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Life Cycle Management: Responsible for overseeing the life cycle planning process including the circulation, development and review of life cycle plans. Project Management: Responsible to interpret the LOPP and integrate the requirements into the Project Allocation List (PAL). Group Technology Division’s Engineering Department: Responsible for compiling the annual strategic report. Power Stations Engineering Managers are responsible for reviewing the content of the report and making use of the contents to guide them when compiling their annual life of plant plans and technical plans. PDD: Responsible for leading project teams in developing projects emanating from/mentioned in this strategy, to CRA/DRA/ERA, as applicable, if and when requested to do so by Generation. CMD: Responsible for leading project teams in executing projects emanating from/mentioned in this strategy, to CRA/DRA/ERA, as applicable, if and when requested to do so by Generation.

This document has been accepted by the following: Anton Hart GTE – Boiler Auxiliary Plant Engineering Manager Leon Van Wyk GTE – Air Quality Control Engineering Manager (Acting) Robbie van Rensburg GTE – Corporate Consultant: Fabric Filter Plants Hendre Grobbelaar GTE – Senior Consultant: Air Pollution Control Eddie Viviers GTE – Consultant: Air Pollution Control Rakesh Rampiar GTE – Senior Technologist: Air Pollution Control Mthoko Dlamini GTE – Senior Engineer: Air Pollution Control

2.5.1 Flue Gas Cleaning System Teams

A major concern is the experience level of the System Engineers, as approximately 70 to 80% have three to six years of experience each. The suggestion is to appoint a second Engineer/EIT at each Power Station to represent GTE. The ideal situation would be to appoint an EIT at each Power Station to create a pipeline to take over from the existing longer serving System Engineers. This was done through an Emissions Recovery Team which has been functioning since April 2011. This recovery team is currently being phased out and it is expected that the stations take full accountability of emissions management. The Engineering Managers have to ensure that sufficient numbers / resources and competent skills are available at all times to manage the plants.

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Table 2: Resources Allocated per Power Station Plant Team Leaders Contact System Engineers RT & D (Primary / Number Secondary) Arnot Hendre Grobbelaar 082 452 6073 Nomathemba Spinola Baloyi / Mpulo Irish Phiri Camden Hendre Grobbelaar 082 687 8488 / Charlene Naicker Irish Phiri / 082 452 6073 Spinola Baloyi Duvha Ebrahim Patel / 083 309 5098/ Moloko Radipabe Spinola Baloyi / FFPs Robbie Van 083 657 0632 Irish Phiri Rensburg Duvha Eddie Viviers / 082 560 0834 / Moloko Radipabe Naushaad ESPs Jaco Burger 083 470 3733 Haripersad / Jovita Juodaityte Grootvlei Hendre Grobbelaar 082 452 6073 / Charmaine Ntanzi Irish Phiri / FFPs / Hendrik Van Riel 083 379 9100 Spinola Baloyi Grootvlei Hendre Grobbelaar 082 452 6073 / Charmaine Ntanzi Naushaad ESPs / Vernon Van 084 621 5883 Haripersad / Emmenis Jovita Juodaityte Hendrina Hendre Grobbelaar 082 452 6073 Jan-Louis Human Spinola Baloyi / (GTE secondment) Irish Phiri Kendal Mthoko Dlamini 083 736 9880 Jacob Zwane / Naushaad Tendani Haripersad / Rasivhetshelel Jovita Juodaityte Komati Jan-Louis Human / 082 687 8488 / Fayaaz Manan Naushaad Hendre Grobbelaar 082 452 6073 Haripersad / Jovita Juodaityte Kriel Mthoko Dlamini 083 736 9880 Itumeleng Naushaad Uyangaphi Haripersad / Jovita Juodaityte Lethabo Eddie Viviers / 082 560 0834 / Jan Myburg / Naushaad Vernon Van 084 621 5883 Yaseen Waja Haripersad / Emmenis Jovita Juodaityte Majuba Ebrahim Patel / 083 309 5098 / Lindani Madonsela Irish Phiri / Vernon Van 084 621 5883 Spinola Baloyi Emmenis Matla Rishon Burger / 082 398 8565 / Fred Hoffman / Naushaad Jaco Burger 083 470 3733 Francois Bruwer Haripersad / Jovita Juodaityte Matimba Eddie Viviers / 082 560 0834 / Johan v d Walt Naushaad Jaco Burger 083 470 3733 Haripersad / Jovita Juodaityte

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Plant Team Leaders Contact System Engineers RT & D (Primary / Number Secondary) Tutuka Mthoko Dlamini 083 736 9880 Mike Molepo Naushaad Haripersad / Jovita Juodaityte Medupi Ebrahim Patel / 083 309 5098 / Lerato Moira Naushaad Robbie Van 082 897 8584 / Chauke / Christo Haripersad / Rensburg / Hendrik 083 379 9100 Holtshausen Jovita Juodaityte Van Riel Kusile Ebrahim Patel / 083 309 5098 / Paul Malomane Naushaad Hendre Grobbelaar 082 452 6073 / (FFP) / Tsholofelo Haripersad / / Hendrik Van Riel 83 379 9100 Lekhuleni (FGD) Jovita Juodaityte CEMS Ebrahim Patel / 083 309 5098 / Lindi Vilakazi / Rakesh Rampiar / 084 206 7618 / Pieter Swart Vernon Van 084 621 5883 Emmenis FFP Leon Van Wyk / 082 320 2374 / Irish Phiri / Robbie Van 082 897 8584 Pieter Swart Rensburg FGD Puseltso Godana / 082 218 4293 / Naushaad Ebrahim Patel 083 309 5098 Haripersad / Jovita Juodaityte / Pieter Swart

NOX Sandile Peta / 083 677 8183 / Naushaad Ebrahim Patel 083 309 5098 Haripersad Strategy Ebrahim Patel / 083 309 5098 / Naushaad Hendre Grobbelaar 082 452 6073 Haripersad Enviro. Kristy Langerman / 083 704 2543 / Gabi Mkhatshwa Bianca Wernecke / 079 745 4089 / Olga Makhakenele 072 226 0853 CFD Preeya Sukdeo 082 331 4227

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3. AIR POLLUTION CONTROL REPORT

3.1.1 GENERIC LONG TERM LIFE CYCLE PHILOSOPHY (2016 VERSION – CAPEX CONSTRAINED)

Due to the complexities associated with funding the above projects, based on the latest MYPD determination, a scaled back version of the plan has been proposed below. Engineering will investigate the reductions achievable in this context and Environmental Management will explore implications of this in terms of the MES postponement decision in parallel and will provide guidance during the course of the year. A revised postponement application will be submitted in 2019. This plan looks at minimising the impact of particulate emissions on the stations where fabric filter plants will not be retrofitted (Duvha 4-6, Kendal, Lethabo, Matimba and, Matla). It also considers what work must be carried out on the ESP, SO3 Plant, Dust and Ash Handling Systems. The cost is broken down into Capital and GO-Capital as some of the interventions are concerned with re-instating the system back to design capabilities. It is assumed that the Grootvlei and Tutuka FFP retrofits are catered for in the GCD plan, as they have already been approved and are in execution. The costs for the Kriel FFP retrofit are contained here-under.

For the NOX reduction, only Matla, Majuba and Tutuka are considered, as recommended by the fleet NOX reduction concept studies. For Majuba and Tutuka, it essentially entails the replacement of the burner tips and the pulverised fuel tubes. For Matla, it entails the complete burner replacements. The costs contained here-under are more than the concept study estimates to allow for certain execution risks to be catered for as the contracting strategy has not been discussed as yet.

No provision has been made for any SOX reduction in this plan. The Medupi FGD retrofit is catered for in the GCD plan and therefore not included here. PDD has a budget for the Kendal FGD development. Routine operational related projects for these stations are covered under the details for that station under section 3.3. The System Engineer are expected to revise their outage scopes of works to reflect as a minimum the activities listed below and ensure that the timeous motivations for the costs and durations are provided.

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Table 3: Summary of Activities

High Level Scope of Work Duvha CAPEX HF Transformers (4-6) Installation of HF Transformers on first 3 fields CAPEX NH3 Injection New Ammonia Injection plant to assist with ash aglomeration Major refurbishments of Unit 6 (as was done on Units 4 and 5)m and normal GO scope to re-instate damaged fields and wear components on Units 4 and 5. GO Capital ESP Refurb (4-6) Reburbishment of conventional tranformers on remaining no HFT fields. Refurbishment of all unitised dust handling system conveyors and ash conditioners. Does not include ash dump GO Capital DHP Refurb (4-6) area as it must be planned for within the material handling section. GO Capital SO3 Refurb (4-6) Rotuine refurbihment of SO3 plants, pumps, heaters, flow control valves, fans/blowers and instrumentation.

Kendal CAPEX HF Transformer Installation of HF Transformers on first 3 fields Major refurbishments to re-instate damaged fields and wear components on ESP. Replacement of guide and flow distribution screens and duct repairs. Reburbishment of conventional tranformers on remaining non HFT fields. GO Capital ESP Refurb ESP controller replacement dur to obsolesence from 2020. Rotuine refurbihment of SO3 plants, pumps, heaters, flow control valves, fans/blowers and instrumentation. GO Capital SO3 Refurb Replacement of SO3 injection lances and erosion protection channels. Refurbishment of all unitised dust handling system conveyors and ash conditioners. GO Capital DHP Refurb Does not include ash dump area as it must be planned for within the material handling section.

Kriel CAPEX FFP (incl. DHP) FFP Retrofit planned to commence with first unit in FY2020. CAPEX HF Transformers If the FFP retrofit is delayed, the installation of HFTs will assist in sustain emission levels below 100 mg/Nm3. GO Capital SO3 Planr Control System If the FFP retrofit is delayed, the installation of HFTs will assist in sustain emission levels below 100 mg/Nm3.

Lethabo CAPEX HF Transformer Installation of HF Transformers on first 3 fields Major refurbishments to re-instate damaged fields and wear components on ESP. Replacement of guide and flow distribution screens and duct repairs. Reburbishment of conventional tranformers on remaining non HFT fields. GO Capital ESP Refurb ESP controller replacement due to obsolesence from 2019. Upgrade of the SO3 plant to increase the capacity from to 40 ppm to cater for the sustained high back end temperature. Relocation of the elctrical and instrumentation cubicles into the boiler house. CAPEX SO3 Upgrade Replacement of SO3 injection lances and erosion protection channels. CAPEX NH3 Injection New Ammonia Injection plant to assist with ash aglomeration Refurbishment of all unitised dust handling system conveyors and ash conditioners. GO Capital DHP Refurb Does not include ash dump area as it must be planned for within the material handling section.

Majuba CAPEX NOX Replacement of burner tips and pf tubes to achieves desired NOX emissions.

Matla CAPEX HF Transformer Installation of HF Transformers on first 3 fields CAPEX ESP Upgrade Completion of the ESP upgrade (Hamon SoW) on Unit 1, 2 and 4. CAPEX NH3 Injection New Ammonia Injection plant to assist with ash aglomeration CAPEX NOX Full burner replacement to achieve desired NOX emissions. This includes hopper level detection, duct repairs, flow, temperatrue and SO3 injection distribition optimisation GO Capital ESP Optimisation and general repairs.

Matimba CAPEX HF Transformer Installation of HF Transformers on first 3 fields Major refurbishments to re-instate damaged fields and wear components on ESP. Replacement of guide and flow distribution screens and duct repairs. Reburbishment of conventional tranformers on remaining non HFT fields. GO Capital ESP Refurb ESP controller replacement due to obsolesence from 2021. Rotuine refurbihment of SO3 plants, pumps, heaters, flow control valves, fans/blowers and instrumentation. GO Capital SO3 Refurb Replacement of SO3 injection lances and erosion protection channels. Refurbishment of all unitised dust handling system conveyors and ash conditioners. GO Capital DHP Refurb Does not include ash dump area as it must be planned for within the material handling section.

Tutuka CAPEX NOX Replacement of burner tips and pf tubes to achieves desired NOX emissions.

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Table 4: Summary of High Level Costs

CAPEX Plan (High Level) Bottom Up Approach (2016 Nominal Cost, R'm). Excluded Grootvlei & Tutuka FFP Project and Medupi FGD Project. Excluding IDC, Forex and C2C.

FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 Duvha 0 0 159 87 92 28 30 31 0 0 0 0 0 0 0 427 CAPEX HF Transformers (4-6) 0 0 29 31 33 0 0 0 0 0 0 0 0 0 0 93 CAPEX NH3 Injection 0 0 0 0 0 28 30 31 0 0 0 0 0 0 0 89 GO Capital ESP Refurb (4-6) 0 0 94 19 20 0 0 0 0 0 0 0 0 0 0 132 GO Capital DHP Refurb (4-6) 0 0 29 31 33 0 0 0 0 0 0 0 0 0 0 93 GO Capital SO3 Refurb (4-6) 0 0 6 6 7 0 0 0 0 0 0 0 0 0 0 19 Duvha CAPEX 0 0 29 31 33 28 30 31 0 0 0 0 0 0 0 183 Duvha GO Capital 0 0 129 56 59 0 0 0 0 0 0 0 0 0 0 245

Kendal 0 61 65 68 132 140 148 71 75 79 0 0 0 0 0 839 CAPEX HF Transformer 0 0 0 0 53 56 59 63 67 71 0 0 0 0 0 368 GO Capital ESP Refurb 0 22 23 25 33 35 37 8 8 9 0 0 0 0 0 201 GO Capital SO3 Refurb 0 6 6 6 7 7 7 0 0 0 0 0 0 0 0 39 GO Capital DHP Refurb 0 33 35 37 40 42 44 0 0 0 0 0 0 0 0 232 Kendal CAPEX 0 0 0 0 53 56 59 63 67 71 0 0 0 0 0 368 Kendal GO Capital 0 61 65 68 79 84 89 8 8 9 0 0 0 0 0 471

Kriel 0 61 91 682 1174 2522 1318 1442 595 0 0 0 0 0 0 7885 CAPEX FFP 0 0 55 644 1141 2487 1318 1442 595 0 0 0 0 0 0 7681 CAPEX HF Transformers 0 61 35 37 33 35 0 0 0 0 0 0 0 0 0 201 GO Capital SO3 Planr Control System 0.0 0.5 0.5 0.6 0.6 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3 Kriel CAPEX 0 61 90 682 1174 2522 1318 1442 595 0 0 0 0 0 0 7882 Kriel GO Capital 0 0 1 1 1 1 0 0 0 0 0 0 0 0 0 3

Lethabo 0 116 247 218 231 245 104 110 117 0 0 0 0 0 0 1387 CAPEX HF Transformer 0 44 94 50 53 56 0 0 0 0 0 0 0 0 0 297 GO Capital ESP Refurb 0 72 153 87 92 98 7 8 8 0 0 0 0 0 0 526 CAPEX SO3 Upgrade 0 0 0 19 20 21 22 24 25 0 0 0 0 0 0 130 CAPEX NH3 Injection 0 0 0 25 26 28 30 31 33 0 0 0 0 0 0 174 GO Capital DHP Refurb 0 0 0 37 40 42 44 47 50 0 0 0 0 0 0 260 Lethabo CAPEX 0 44 94 93 99 105 52 55 58 0 0 0 0 0 0 601 Letabo GO Capital 0 72 153 124 132 140 52 55 58 0 0 0 0 0 0 786

Majuba 26 50 88 124 231 245 259 275 291 309 0 0 0 0 0 1899 CAPEX NOX 26 50 88 124 231 245 259 275 291 309 0 0 0 0 0 1899 0 Majuba CAPEX 26 50 88 124 231 245 259 275 291 309 0 0 0 0 0 1899 Majuba GO Capital 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Matla 53 260 205 429 396 482 474 503 533 565 37 0 0 0 0 3938 CAPEX HF Transformer 0 55 29 62 0 35 0 0 0 0 0 0 0 0 0 182 CAPEX ESP Upgrade 0 105 0 118 0 0 0 0 0 0 0 0 0 0 0 223 CAPEX NH3 Injection 0 0 0 0 0 28 30 31 33 35 37 0 0 0 0 195 CAPEX NOX 53 100 176 249 396 420 445 471 500 530 0 0 0 0 0 3338 GO Capital ESP Optimisation 0 0 0 6 0 7 7 8 8 9 0 0 0 0 0 46 Matla CAPEX 53 260 205 429 396 482 474 503 533 565 37 0 0 0 0 3938 Matla GO Capital 0 0 0 6 0 7 7 8 8 9 0 0 0 0 0 46

Matimba 0 0 0 0 0 150 159 168 178 189 200 0 0 0 0 1044 CAPEX HF Transformer 0 0 0 0 0 56 59 63 67 71 75 0 0 0 0 390 GO Capital ESP Refurb 0 0 0 0 0 49 52 55 58 62 66 0 0 0 0 341 GO Capital SO3 Refurb 0 0 0 0 0 3 3 3 3 4 4 0 0 0 0 20 GO Capital DHP Refurb 0 0 0 0 0 42 44 47 50 53 56 0 0 0 0 293 Matimba CAPEX 0 0 0 0 0 56 59 63 67 71 75 0 0 0 0 390 Matmba GO Capital 0 0 0 0 0 94 99 105 112 118 125 0 0 0 0 654

Tutuka 26 50 88 124 231 245 259 275 291 309 0 0 0 0 0 1899 CAPEX NOX 26 50 88 124 231 245 259 275 291 309 0 0 0 0 0 1899 0 Tutuka CAPEX 26 50 88 124 231 245 259 275 291 309 0 0 0 0 0 1899 Tutuka GO Capital 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Summary CAPEX 105 465 595 1484 2216 3738 2511 2707 1902 1324 112 0 0 0 0 17160 Summary GO Capital 0 133 347 256 271 325 248 176 187 136 125 0 0 0 0 2204 Total 105 598 942 1740 2487 4064 2758 2883 2089 1460 238 0 0 0 0 19363

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3.1.2 GENERIC SHORT AND MEDIUM TERM LIFE CYCLE PHILOSOPHY

3.1.2.1 PLANT CONDITION AND STATUS REPORT From the detailed performance indicators shown below it is clear that the particulate matter emissions of the business is not being managed effectively and the current performance is not to the acceptable standards. Most of these indicators show red.

Figure 1: Generation Coal UCLF and Relative Emissions (FY2012 to YTD January 2016)

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In summary, the major factors that are influencing the particulate emissions performance are as follows (generic across the fleet): a. The inability of the dust and ash handling plants to timeously remove the collected ash from the ESP and/or FFP hoppers cause ash re-entrainment.As a result the hopper is allowed to fill up with the unit remaining on load to the point where the abatement control plant is damaged. b. Fuel oil/Unburnt carbon carry-over has been particularly challenging on the FFPs in maintaining their differential pressure. This requires that the bags be cleaned off-line and/or replaced prematurely. It also leads to the contamination of the ESP fields which also requires that they be cleaned off-line. c. Planned outages are being delayed more frequently, in some cases for up to three years, resulting in more maintenance being required when access is finally granted. Scopes of work and maintenance strategies are not being adjusted accordingly to address emission related problems and thus in a number of cases, units are returned to service without fully executing the scope that is identified at the start of the outage. A further challenge is the quality of workmanship and the knowledge of some of the service providers being used during outages resulting in poor plant performance. d. Coal quality variation does play a role in the poor particulate emissions performance and is particularly challenging at Tutuka, Grootvlei, Matla, Kriel and Duvha.

There is a misconception that the retrofit of FFPs at our existing ESP stations will solve Eskom’s problems. This may be true for the emissions compliance issue, but it is certainly going to have an unintended consequence, in that there will be a marked increase in UCLF.

This is illustrated below in Figure 2:

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Figure 2: YTDJan16 FY2016 UCLF Categories

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Of the ULCF allocated to the Gas Cleaning plant (4%) for this financial year, the FFP stations (currently 36% of the Gx-Coal capacity) account for in excess of 40% of the incurred UCLF. If one extrapolated this when 90% of the existing plants are converted to FFP, then the expected UCLF allocated to the Gas Cleaning plant will rise to approx. 10% of the total.

Table 5: YTD Feb 15FY2015 Relative Emissions Contribution Index FY 2016 Yearly Relative Emissions Contribution Index

April May June July August September October November December January February March Duvha 0.021 0.020 0.023 0.022 0.022 0.023 0.023 0.023 0.024 0.023 0.023 0.023 Kendal 0.032 0.035 0.039 0.040 0.040 0.040 0.043 0.045 0.049 0.054 0.054 0.054 Lethabo 0.055 0.053 0.053 0.052 0.052 0.051 0.052 0.051 0.052 0.051 0.051 0.051 Majuba 0.006 0.005 0.005 0.005 0.005 0.005 0.005 0.005 0.005 0.005 0.005 0.005 Matimba 0.006 0.008 0.009 0.008 0.009 0.010 0.010 0.009 0.009 0.009 0.009 0.009 Matla 0.038 0.047 0.049 0.052 0.053 0.052 0.053 0.055 0.054 0.053 0.053 0.053 Tutuka 0.121 0.118 0.112 0.103 0.102 0.098 0.096 0.099 0.101 0.104 0.104 0.104 Arnot 0.011 0.010 0.009 0.008 0.008 0.008 0.007 0.008 0.008 0.008 0.008 0.008 Camden 0.008 0.006 0.006 0.006 0.006 0.005 0.005 0.005 0.006 0.006 0.006 0.006 Grootvlei (Units 1-6) 0.053 0.034 0.026 0.021 0.017 0.015 0.014 0.013 0.013 0.016 0.016 0.016 Hendrina 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 0.004 Komati (1-9) 0.024 0.016 0.014 0.012 0.011 0.011 0.010 0.010 0.009 0.009 0.009 0.009 Kriel 0.044 0.042 0.043 0.051 0.058 0.057 0.057 0.059 0.060 0.061 0.061 0.061 Medupi 0.001 0.003 0.003 0.003 0.003 0.003 0.003

Contribution Index Top 5 Ranking Legend: No. 1 No. 2 No. 3 No. 4 No. 5 The above table provides an indication of the stations’ performance as a function of their MWh sent out. Based on the technologies employed, Tutuka, Matla, Kriel and Grootvlei should always be ranked in the highest emitting 5. The anomaly is that Lethabo and Kendal, closely followed by Duvha, are featuring high on the list. This is an indication of poor performance at these stations. This also implies that if focus is given to Duvha (4-6), Kendal and Lethabo, Eskom will achieve its relative emissions performance target.

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Figure 3: Arnot UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

An improvement in the management of bag leaks has led to an improvement in Arnot’s relative emissions performance.

Figure 4: Camden UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

Three units at Camden were rebagged in 2015 and three units are planned for in 2016. The performance is tracking the bag life cycle and the UCLF is as a consequence of the bag change. In recent months, the deterioration is due to high ash hopper levels.

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Figure 5: Duvha UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

The variation in the emissions at Duvha is due to plant process problems that occur from time to time. The major contributor has been the performance of unit 6’s ESP, the frequency of failures on the dust handling plant on units 4 to 6 and the periodic unavailability of the SO3 plant. The exclusion of unit 3 (FFP) from production also negatively affects the overall station relative emissions performance.

Figure 6: Hendrina UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

The UCLF and relative emissions at Hendrina are tracking each other. The deterioration in performance this year can be attributed to the number of full hopper events causing bag failures. This requires the respective units to run at half load while the bags are being replaced.

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Figure 7: Kendal UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

When there are no ash- and dust plant issues at Kendal, emissions are well below 50mg/Nm3. The very poor performance at Kendal has been its inability to resolve the issues around the dust- and ash handling plant, causing consequential damage to the plant and a long term environmental liability for Eskom. The emissions reported by Kendal during these prolonged periods are drastically under-stated because of the dust monitor range limitations. The low UCLF, almost zero, indicates that the station is prioritising production over environmental considerations. The station has reported 21 NEMA Section 30 incidents for particulate emission exceedances between April 2015 and February 2016.

Figure 8: Kriel UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

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Kriel’s performance between April 2014 and December 2015 has improved taking into account historical performance. However, a significant deterioration has been noted since January 2015 due to dust handling plant issues and the periodic unavailability of the SO3 plant on some of the units. The station has also lost focus on managing their emissions performance largely due to the emissions reduction management team not having management presence in driving solutions to problems.

Figure 9: Lethabo UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

Lethabo’s performance until November 2014 was trending in the right direction. However the catastrophic failure of the ash handling system in November 2014 coupled with the drive to ensure production output has led to significant damage (collapse of internals) to the ESPs. The recovery program was only scheduled to be completed by the end of December 2015 subject to the system capacity. Until such time that this is completed, Lethabo emissions are expected to remain high until these consequence of the November 2014 incidents have been addressed, as evident in their UCLF and RE trends.

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Figure 10: Majuba UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

The significant reduction in the UCLF at Majuba this year has been due to the forced pre-mature replacement of fabric filter bags on 4 units.

Figure 11: Matimba UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

Matimba has been performing exceptionally well due to efficient and optimised management of the existing plant. Matimba is an example of how a well maintained plant can operate well, even with exiting abatement technology.

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Figure 12: Matla UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

Significant effort has gone into Matla to reduce particulate emissions, despite the deferment of the ESP upgrade project (outstanding on 3 units). It must be noted at following an EXCO meeting in February 2016 where the need to reduce and re-phase the costs associated with environmental compliance was expressed, a decision was made to cancel the FFP retrofit project at Matla in preference for a less capital intensive non-FFP solution.

Figure 13: Tutuka UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

The emissions reported at Tutuka from approximately April 2014 to February 2016 have been under- stated due to an error in the clear path calibration of the dust monitors. The deterioration in the overall average performance for this financial year has been due to high back end temperatures and instances

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Figure 14: Grootvlei UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

The high UCLF and low relative emissions at Grootvlei are related to the ESP units being off for long durations.

Figure 15: Komati UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

The station’s management has been instrumental in driving the good performance at Komati.

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Figure 166: Medupi UCLF and Relative Emissions (FY2012 to YTDJan16 FY2016)

Medupi is currently experiencing a fundamental design flaws on the fabric filter plant. Unit 6 has already had a complete rebag and is currently replacing approximately a third of the second set of bags. Lessons learnt from this will need to be implemented for the remaining units to prevent repetition.

3.1.2.2 SHORT AND MEDIUM TERM ACTIONS

3.1.2.2.1 Outage Scopes of Work

The system engineers need to reflect, in the maintenance and outage plans, the work needed over and above the generic outage scopes due to the damage caused to the plant. GO-capital costing needs to reflect both the additional costs and durations required. Furthermore, in line with the ERAP recommendations, structural integrity surveys by a certified engineer need to be undertaken at every GO or after an incident. The Materials Handling engineer also needs to pay attention to the scope of work in the dust and ash handling plant. The unavailability and reliability of this plant area directly influences the emissions performance negatively.

3.1.2.2.2 Continuous Emissions Monitoring (CEM)

As of April 2015 all stations should have been able to report actual emissions of particulates, SO2, NOX, O2, H2O, CO, CO2 and stack process conditions of velocity, temperature and pressure. The integrity of the CEMs and its data is the cornerstone of the decisions that need to be made with respect to environmental reporting and compliance, and they are a requirement for legal compliance. It is therefore of utmost importance that these systems are operated and maintained to the highest standards. The following provisions must be made in the stations’ plans for the management of the CEMs: - CEMS equipment replacement cycle every 12 years. - Full dust monitor correlations every 2 years (R60k per monitor for unitised monitors and R120K per monitor for common stack monitors). - Parallel (QAL2/3) tests for the gaseous monitors every 2 years (R250k per monitor). - Provision for on-going service, calibration and maintenance of the CEMs (R125k for unit per year). - Stack lifts availability maintenance provision (R100K per lift per year).

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3.1.2.2.3 FFP Bag Routine Replacements

All stations need to update their replacement cycle in line with the reduced bag life expectations as contained in section 3.3 below. Due to the vulnerability of PPS fibre supply, the cost escalation is between 15 to 25 % from the 2014 actual prices, excluding rate of exchange fluctuations. The PAN fibre supply cost escalation is currently tracking the 5 to 7% range from the 2014 actual prices, excluding rate of exchange fluctuations. Arnot, Duvha, Hendrina and Majuba need to increase their provision for new cages (up another 50% from the last rebag) going forward. It is recommended that Duvha plan to replace all their cages at the next rebag. Note for RT&D: With the new build Power Stations being commissioned and FFP retrofit projects coming into play it might be advisable to expand the human resources capacity of the textile laboratory in terms of capability for testing.

3.1.2.2.4 Offset Project in Compliance with the MES Postponement Application

The air quality offsets were investigated by Eskom Environmental Management on a pilot scale near Hendrina town. The results were published at the start of 2016. The results are being used to inform the plan for the large-scale rollout of offsets that needs to be submitted to the Department of Environmental Affairs by 31 March 2016. The costs associated with the rollout are preliminarily estimated at over R4 billion (nominal) for Eskom. While individual offset projects will be associated with particular power stations, the costs will be provided for centrally and no provision needs to be made at a station level.

3.2 STRATEGIC INITIATIVES (AS NECESSARY)

Refer to section 3.1.1 above, for the preliminary program, schedule and cost KINDLY USE MOST UP-TO-DATE PROGRAM AVAILABLE FROM PDD (JUSTICE MARABWA/BRIAN MTWA)

3.3 POWER STATION SPECIFIC RECOMMENDATIONS

3.3.1 ARNOT POWER STATION • Projected bag life hours reduced from 40 000 to 32 000 for Units 1 to 3. • Projected bag life hours reduced from 36 000 to 30 000 for Units 4 to 6. o Estimated bag costs per unit for R1100/bag excluding installation, RoE, IDC and owner’s development costs. • Additional provision in the Routine Bag Replacement ERA for the station: o To increase the new cages allowance from 15% to 35% due to the age of the cages. o To increase the allowance for repairs of existing cage by 50% above the repair rate of the previous rebag.

3.3.2 CAMDEN POWER STATION

• Projected bag life hours reduced from 36 000 to 30 000 for Units 1 to 8.  Estimated bag costs per unit for Units 1-8 is R1100/bag excluding installation, RoE, IDC and owner’s development costs.

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• Additional provision in the Routine Bag Replacement ERA for the station:  To increase the new cages allowance from 10% to 20% due to the age of the cages.  To increase the allowance for repairs of existing cages by 25% above the repair rate of the previous rebag.

3.3.3 DUVHA POWER STATION

• Projected bag life hours of 36 000 for Units 1 to 3.  Estimated bag costs per unit for Units 1-3 is R1100/bag excluding installation, RoE, IDC and owner’s development costs. The station must install the original complement of bags on these units due to the deteriorating coal and process conditions. • Additional provision in the Routine Bag Replacement ERA for the station:  It is recommended that all the cages be rebagged at the next rebag.

• Unit 4 and 5 ESP and SO3 plants have been refurbished to the cost of approx. R80M. A similar scope of work (SOW) must be executed on Unit 6 in its upcoming outage.

• Independent annual review of SO3 plant and minor refurbishments must be catered for. This should be done to ensure the safe operation of the SO3 skid and the common sulphur storage system. Estimated annual cost for the station is R350k. • Provisions should be made in the dust handling plant area for an upgrade of the CARU system and an increase in the capacity of the DHP. • Replacement of the pulse tanks on units 1 to 3 as soon as possible. The cost for this is estimated at R 10 M per unit. • Refer to section 3.1.2 for additional compliance related activities.

3.3.4 GROOTVLEI POWER STATION

• Projected bag life hours of 32 000 for Units 1, 5 and 6.  Estimated bag costs per unit for these units are R1100/bag excluding installation, RoE, IDC and owner’s development costs. Note that due to the repeated oil carry-over incidents, the benefit of installing P84® on the surface of the bags is materialising. It may be advisable to rather install a standard fine denier PPS in place of the multi-lobal Polyimide-P84® fibres until such time the oil carry over incidents are resolved. The cost per bag is then estimated at R900. • Additional provision in the Routine Bag Replacement ERA for the station:  To increase the new cages allowance from 10% to 20% due to the age of the cages.  To increase the allowance for repairs of existing cage by 25% above the repair rate of the previous rebag. • The retrofit of units 2 to 4’s ESP to FFPs has commenced in 2015.

• The station should however continue to maintain and operate the ESP’s and SO3 plant in order to ensure the lowest possible emissions until such time that the retrofits are executed.

• The station is to make provision for the safe de-commissioning and dismantling of the SO3 plant including the electric boilers and sulphur storage tanks. These will be transferred to Komati.

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3.3.5 HENDRINA POWER STATION

• Projected bag life hours of 38 000 for Units 1 and 6 to 10 (PPS fabric). • Projected bag life hours of 34 000 for Units 2 to 5 (PAN fabric).  Estimated bag costs per unit for the PPS Units is R700/bag excluding installation, RoE, IDC and owner’s development costs.  Estimated bag costs per unit for the PAN Units is R420/bag excluding installation, RoE, IDC and owner’s development costs. • Additional provision in the Routine Bag Replacement ERA for the station:  To increase the new cages allowance from 15% to 30% due to the age of the cages.  To increase the allowance for repairs of existing cage by 50% above the repair rate of the previous rebag.

3.3.6 KENDAL POWER STATION

• Recommend that a CFD model (flow & particle distribution) be undertaken. Estimated cost of this is R350k.

• Re-instate the original design SO3 injection lances for better flue gas conditioning distribution. This work must commence during the next GO cycle at an estimated cost per units of R1M which includes the outcomes of the CFD study. • ESP upgrade project.  ESP transformer refurbishment project. To commence during the next outage cycle with an estimated cost of approx. R6.5M per unit.  ESP control and monitoring upgrade. To commence during the next outage cycle with an estimated cost of approx. R750k per unit. • Sulphur storage tank upgrade. This project has been in progress for the last four years. The station needs to get this plant in service as soon as possible. • Due to the high ash hopper levels, the failure rate of the discharge electrode wires is high. Provision needs to be made during the next outage to commence with a project of replacing and re-instating the broken wires. The estimated cost of the exercise is R2.25M per unit. • To ensure quick repair times within the ESP due to the frequency of plant damage, the hopper walkways project needs to be completed sooner rather than later. The estimated cost of this work is R2.5M per unit.

• Review of ash hopper level control and management system.

• Independent annual review of SO3 plant and minor refurbishment must be catered for. This should be done to ensure the safe operation of the SO3 skid and the common sulphur storage system. Estimated annual cost for the station is R350k. • Provisions should be made in the dust and ash handling plant areas for the complete refurbishment of these systems a.s.a.p. • Refer to section 3.1.2 for additional compliance related activities.

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3.3.7 KOMATI POWER STATION

Komati has been recently refurbished and as such no major projects are to be included in the technical plan. The following projects need to be considered however:

 Re-instate the original design SO3 injection lances for better flue gas conditioning distribution. This work must commence during the next GO cycle at an estimated cost per units of R1M which includes the outcomes of the CFD study.  The station currently does not have any spare transformers. All TR sets from unit 6 have been replaced. The ones taken out are to be refurbished and used as spares for the West Units. A project to replace all Unit 4 TR sets to be executed and the ones taken out are to be used as spares for the East Units. Estimated refurbishment cost per transformer is R125k.

 Independent annual review of SO3 plant and minor refurbishment must be catered for. This should be done to ensure the safe operation of the SO3 skid and the common sulphur storage system. Estimated annual cost for the station is R350k.  The existing Electropac Steam Boilers cannot provide the capacity for all 9 units if one of the 2 units is down for maintenance and/or repairs. It is recommended that the station consider the inclusion of a third boiler. Estimated cost: R7.5M. However, since the Grootvlei FFP Retrofit project is in execution, it is recommended that Komati transfer Grootvlei’s SO3 skid, ESP transformers, the sulphur storage tank and the electric boilers to site.  Refurbishment and upgrade of the CEMS at R250k per stack.  ESP casing outlet dust monitors at a cost of R400k per units is also urgently required.

3.3.8 KRIEL POWER STATION

Kriel has been recently refurbished and the projects contained here-under are in order for Kriel to comply with their stricter AEL conditions. • The electrical sectionalisation of the ESP is a highly recommended project. It is recommended that units 1 to 3 be given priority in scheduling the phasing and consideration be given to high frequency transformers. The estimated cost per unit is R20M. • ESP casing outlet dust monitors at a cost of R400k per units is also urgently required. • Continuous gaseous emission monitoring to be completed by 31 December 2014. o Estimated cost per system R 1M per stack.

• The SO3 plant requires a plant control and monitoring system upgrade. This projected has an estimated cost of R450k per units. This is an urgent project. • Review of ash hopper level control and management system. • It is assumed that the FFP retrofit for Kriel will be funded, as indicated in the latest 5 year (FY2016/17 – FY2020/21) Eskom Corporate plan and 10 year (FY2016/17 – FY2025/26) financial plan approved, by board on 19 Feb 2016.

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3.3.9 KUSILE POWER STATION

• Projected bag life hours of 30 000 (PAN fabric).  Estimated bag costs per unit for the PAN Units is R635/bag excluding installation, RoE, IDC and owner’s development costs. PPS bags are estimated at R1 300/bag. • Additional provision in the Routine Bag Replacement ERA for the station:  Allowance of 15% new cages with the first rebag.  Allowance for repairs of existing cage of 25% with the first rebag. • The station may need to consider a redesign of the inlet temperature control philosophy and potentially the attemperation and implosion protection system.

3.3.10 LETHABO POWER STATION

The primary focus at Lethabo is to get the plant including upstream and down-stream plant back to within the design base. This is being executed during outages and will require at least 2 GO cycles to complete. • Transformer Refurbishment of the last four fields at an estimated cost of R2M per unit. • HF Transformer Upgrade at an estimated cost of R25M per unit. • Hopper Walkways at an estimated cost of R4M per units (project in execution and nearing completion) • Hopper Level Detection at R5M per unit.

• SO3 Plant Minor Refurbishment at R5M per unit.

• SO3 Plant (Skid) enclosure to be pressurises to avoid dust entering enclosure. • Dust Monitor Replacement at R250k per unit. • ESP HT Panels at R2.5M per unit including the sectionalisation between the high voltage side and the C&I controllers.

• Independent annual review of SO3 plant and minor refurbishment must be catered for. This should be done to ensure the safe operation of the SO3 skid and the common sulphur storage system. Estimated annual cost for the station is R350k. • Since it is highly unlikely that the station will get an FFP, Lethabo should commence with the project of replacing the existing SO3 plant with a newer, more robust, safer and higher capacity (40 ppm) plant. This project should commence in MYPD4. Estimated Cost of R200M per station. • Provisions should be made in the dust and ash handling plant areas for the complete refurbishment of these systems as soon as possible. • In order to ensure the boiler back end temperatures are maintained, it is recommended that the station reduce the air heater pack replacement schedules from current base-lines. • The damage caused to the ESP internal over the last 5 years, will require extensive repairs during the next 2 outage cycles. This cost is estimated to be between R45-55M per unit per GO. Provision for this needs to be made in the GO Capital costs. • The fleet FFP strategy indicates that an FFP is not recommended at Lethabo due to the ability of the existing ESP to meet the 50 mg/Nm3 limit. In light of this, the projects and interventions contained in section 3.1.2 must be catered for in the TP/LOPP.

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3.3.11 MAJUBA POWER STATION

• Projected bag life hours of 25 000 for Units 1 to 6.  Estimated bag costs per unit for Units 1-6 is R470/bag excluding installation, RoE, IDC and owner’s development costs. Additional provision in the Routine Bag Replacement ERA for the station:  The station is to make provision to replace unit 1, 3, 4 bags before the end of the 2015 financial year and units 2 and 5 at the beginning of FY2016 and unit 6 in FY2017. This is due to the damage caused by the fuel oil carry over and high hopper level incidents. • To increase the new cages allowance from 15% to 30% due to the age of the cages. • To increase the allowance for repairs of existing cage by 50% above the repair rate of the previous rebag. • Provision is to be made in the next outage cycle (GO Capital) for the repair of internal structural support beams and diffusion screens that have worn excessively due to the high hopper level incidents. Estimated Cost of R2.5M per unit.

• The NOX Project as detailed in section 3.1.2 must be included in the TP/LOPP.

3.3.12 MATIMBA POWER STATION

• An independent annual review of the SO3 plant and minor refurbishments must be catered for. This should be done to ensure the safe operation of the SO3 skid and the common sulphur storage system. Estimated annual cost for the station is R350k. • Review of ash hopper level control and management system. • The fleet FFP strategy indicates that an FFP is not recommended at Matimba due to the ability of the existing ESP to meet the 50 mg/Nm3 limit. In light of this, the projects and interventions contained in section 3.1.2 must be catered for in the TP/LOPP. • The FGD Project as detailed in section 3.1.1.3 must be included in the TP/LOPP.

3.3.13 MATLA POWER STATION

Matla has commenced with the major refurbishment of the ESPs. Units 3, 6 and 5 are currently complete with the program for the remaining 3 units being delayed due to the capacity and funding constraints.

• An independent annual review of the SO3 plant and minor refurbishments must be catered for. This should be done to ensure the safe operation of the SO3 skid and the common sulphur storage system. Estimated annual cost for the station is R350k. • Review of ash hopper level control and management system. • Provision to be made at the start of MPYD4 for the installation of high frequency transformers at an estimated cost of R20-25M per unit. • An FFP retrofit should be budgeted for. Should funding for the FFP retrofit be an issue, the projects and interventions contained in section 3.1.2 must be catered for in the TP/LOPP.

• The NOX Project as detailed in section 3.1.2 must be included in the TP/LOPP.

3.3.14 MEDUPI POWER STATION

• Projected bag life hours of 30 000 (PAN fabric).

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• Estimated bag costs per unit for the PAN Units is R635/bag excluding installation, RoE, IDC and owner’s development costs. PPS bags are estimated at R1 300/bag. Due to the design deficiency of the air heater, the FFP and the sustained high average coal sulphur content there is currently discussions on changing the material selection from PAN/PI to PPS/PI. • Additional provision in the Routine Bag Replacement ERA for the station: • Allowance of 15% new cages with the first rebag. • Allowance for repairs of existing cage of 25% with the first rebag. • The station may need to consider a redesign of the inlet temperature control philosophy and potentially the attemperation and implosion protection system. • The FGD Project as detailed in section 3.1.1.3 must be included in the TP/LOPP.

3.3.15 TUTUKA POWER STATION

Tutuka’s FFP retrofit program was approved in August 2013 and is currently going through ERA Rev. 1 approval for commencement of the first unit late in 2017/18 (including addition of DHP Upgrade scope). Until such time, Tutuka will need to ensure the integrity of the current system via frequent maintenance interventions. • Review of ash hopper level control and management system.

• The NOX Project as detailed in section 3.1.2 must be included in the TP/LOPP.

3.3.16 PEAKING (GAS TURBINES)

CEMs are required at these stations, according to the AELs.

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4. AUTHORISATION This document has been seen and accepted by: Name & Surname Designation Z T Mathe Senior Manager: Power Plant Engineering Y Singh Senior Manager: Production Engineering Integration Coal B Naicker Senior Manager: PEIC – Boilers (Acting) A Hart Boiler Auxiliary Discipline Manager R Van Rensburg Corporate Consultant: Fabric Filter Plant H Grobbelaar Senior Consultant: Air Pollution Control E Viviers Consultant: ESPs M Dlamini Senior Engineer: Air Pollution Control R Rampiar Senior Engineer: CEMS and Data Integrity L Van Wyk Engineer: FFP Retrofit Projects R Nieuwoudt Engineer: FFP Retrofit Projects J Burger Engineer: ESPs JL Human Engineer: ESPs V Van Emmenis Engineer: ESPs H Van Riel Engineer: FFP Retrofit Projects J Fourie Engineer: FFP Retrofit Projects

S Peta Engineer: NOX Retrofit Projects

P Godana Engineer: SOX Retrofit Projects P Swart Engineer: RT&D K Langerman Senior Consultant: Air Quality, Environmental Management

5. REVISIONS Date Rev. Compiler Remarks 04 March 2016 0.1 E. M. Patel First Draft Issue for Review 09 March 2016 0.2 E. M. Patel Second Draft Issue following key stake holder feedback 17 March 2016 0.3 E. M. Patel Final Draft completed March 2016 1 E. M. Patel Final Document for Authorisation and Publication

6. DEVELOPMENT TEAM The following people were involved in the development of this document: Robbie Van Rensburg GTE – Corporate Consultant : FFP Hendre Grobbelaar GTE – Senior Consultant: Air Pollution Control Eddie Viviers GTE – Consultant: Air Pollution Control Mthoko Dlamini GTE – Senior Engineer: Air Pollution Control

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7. ACKNOWLEDGEMENTS All power station based flue gas cleaning engineers. Justice Marabwa Group Capital, PDD Brian Mtwa Group Capital, PDD Nolukhanyo Mqhayi Group Capital, PDD Kristy Langerman Group Sustainability – Environmental Management Bianca Wernecke Group Sustainability – Environmental Management