Environmental Management Programme Report for the Development of the Kudu Gas Field on the Continental Shelf of Namibia

CSIR REPORT: CSIR/NRE/ECO/2005/0004/C

ENVIRONMENTAL MANAGEMENT PROGRAMME REPORT FOR THE DEVELOPMENT OF THE KUDU GAS FIELD ON THE CONTINENTAL SHELF OF NAMIBIA

Prepared for:

ENERGY AFRICA KUDU LIMITED

Prepared by:

P D Morant CSIR NATURAL RESOURCES AND ENVIRONMENT P O Box 320 Stellenbosch 7599 South Africa

Tel: +27 21 888 2400 Fax: +27 21 888 2693

Keywords: Namibia Hydrocarbon production Coast Offshore Environmental management programme

JUNE 2006

ENERGY AFRICA KUDU LIMITED

ENVIRONMENTAL MANAGEMENT PROGRAMME REPORT FOR THE DEVELOPMENT OF THE KUDU GAS FIELD ON THE CONTINENTAL SHELF OF NAMIBIA

SCOPE

The CSIR’s Natural Resources and Environment Unit was commissioned by Energy Africa Kudu Limited to provide an environmental management programme report (EMPR) for the development and operation of the Kudu gas field on the southern Namibian continental shelf. The EMPR is based on the environmental impact assessment (EIA) for the development of the Kudu gas field (CSIR Report ENV-S-C 2004-066, December 2004 plus Addendum, December 2005). The EMPR includes an updated description of the project reflecting the finally selected design and a re-assessment of the resulting environmental impacts.

The EMPR includes:

An overview of the project and various component activities which may have an impact on the environment; A qualitative assessment of the various project actions on the marine and coastal environment of southern Namibia; A management plan to guide the implementation of the mitigation measures identified in the EIA.

The format of the EMPR is modelled on the South African Department of Minerals and Energy’s Guidelines for the preparation of Environmental Management Programme Reports for prospecting for and exploitation of oil and gas in the marine environment, Pretoria 1996.

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia

Part A, Section 1, page i ENERGY AFRICA KUDU LIMITED

Frontispiece: Location of the Kudu gas field and proposed power station at Uubvlei near Oranjemund, Namibia

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CONTENTS

Environmental Management Programme Report

Introduction...... 1.1

PART A

SECTION 1: GENERAL INFORMATION 1.1 HOLDER OF PRODUCTION LICENCE ______1.2 1.2 NAMIBIA: MANAGER/RESPONSIBLE PERSON______1.2 1.3 KUDU PRODUCTION LICENCE______1.3 1.3.1 The Production Licence ______1.3 1.3.2 Location of Kudu Gas Field and Production Area______1.4 1.3.3 Surface Area ______1.4 1.3.4 Infrastructure ______1.4 1.3.5 Location of other projects ______1.6 1.4 DESCRIPTION OF THE KUDU GAS FIELD DEVELOPMENT PROJECT __ 1.7

SECTION 2: DETAILED DESCRIPTION OF THE KUDU GAS FIELD DEVELOPMENT PROJECT 2. PROJECT DESCRIPTION ______2-1 2.1 HISTORY OF THE KUDU GAS DISCOVERY ______2-1 2.1.1 Geological history ______2-1 2.1.2 Exploration history______2-1 2.2 NEIGHBOURING LICENCE HOLDERS ______2-3 2.2.1 Petroleum Exploration Licence Areas______2-3 2.2.2 Diamond Prospecting and Mining Licence Areas ______2-3 2.3 DRILLING ______2-5 2.3.1 Introduction ______2-5 2.3.2 Drilling Unit ______2-6 2.3.3 Drilling Operations______2-6 2.3.4 Drilling Muds ______2-11 2.3.5 Logging ______2-12

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2.3.6 Testing______2-12 2.4 PRODUCTION FACILITIES ______2-12 2.5 SUBMARINE PIPELINE ______2-14 2.5.1 Introduction ______2-14 2.5.2 Laying of the Pipeline ______2-14 2.5.3 Monoethylene Glycol (MEG Piggy Back line) ______2-17 2.6 CONTROL UMBILICALS ______2-17 2.7 PIPELINE LANDFALL ______2-18 2.8 ONSHORE PIPELINE ______2-18 2.9 ONSHORE GAS CONDITIONING PLANT ______2-20 2.10 SUPPLY BASE ______2-22 2.11 PRODUCTION OPERATIONS ______2-22 2.11.1 Introduction ______2-22 2.11.2 Production Wells and Subsea Production System ______2-22 2.11.3 Pipeline ______2-24 2.11.4 Onshore Gas Conditioning Plant ______2-24 2.11.5 Non-routine operations ______2-27 2.12 DECOMMISSIONING ______2-28

SECTION 3: DESCRIPTION OF THE ENVIRONMENT 3. DESCRIPTION OF THE ENVIRONMENT______3.1 3.1 MARINE ENVIRONMENT ______3.1 3.1.1 Meteorology ______3.1 3.1.1.1 Offshore wind and atmospheric conditions ______3.1 3.1.1.2 Nearshore wind and atmospheric conditions______3.1 3.1.1.3 Fog______3.6 3.1.2 Physical and Biological Oceanography______3.6 3.1.2.1 Waves ______3.6 3.1.2.2 Tides ______3.10 3.1.2.3 Topography and Sediments______3.10 3.1.2.4 Water masses and temperature/salinity relationships ______3.12 3.1.2.5 Water circulation ______3.13 3.1.2.6 Upwelling ______3.13 3.1.2.7 Nutrient and Oxygen Distributions______3.13 3.1.2.8 Plankton______3.17 3.1.2.9 Benthos ______3-19 3.1.2.10 Fishes ______3-19 3.1.2.11 Birds______3-21 3.1.2.12 Cetaceans ______3-27 3.1.2.13 Seals ______3-31 3.1.3 Commercial Fisheries ______3-32 3.1.3.1 The distribution and abundance of Hake off southern Namibia______3-35 3.1.3.2 Monkfish ______3-41 3.1.3.3 The Namibian Tuna Fishery ______3-41 3.1.3.4 Pelagic species (clupeoids and mackerels)______3-42

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3.1.3.5 Fishing Activities ______3-44 3.1.4 Conservation Areas______3-54 3.1.5 Shipping and Navigation ______3-54 3.2 REFERENCES ______3-57

SECTION 4: LEGISLATION AND LEGAL OBLIGATIONS 4. LEGISLATION AND LEGAL OBLIGATIONS______4-1 4.1 NAMIBIAN ENVIRONMENTAL LEGISLATION ______4-1 4.1.1 Constitution of the Republic of Namibia, 1990 ______4-1 4.1.2 The Petroleum (Exploration and Production) Act, No. 2 of 1991 ______4-1 4.1.3 Namibia’s Environmental Assessment Policy (1995) ______4-2 4.1.4 Draft Environmental Management Act Bill ______4-3 4.1.5 Territorial Sea and Exclusive Economic Zone of Namibia (Act 3 of 1990, amended by Act 30 of 1991) ______4-3 4.1.6 Prevention and Combatting of Pollution of the Sea by Oil Act 1981 and the 1991 Amendment Act (Act No 24) ______4-4 4.1.7 The Marine Traffic Act (Act 2 of 1981 amended by Act 15 of 1991)______4-4 4.1.8 Marine Resources Act, 2000______4-4 4.1.9 Acts covering aspects of Health, Safety and Environmental Protection______4-5 4.2 INTERNATIONAL CONVENTIONS TO WHICH NAMIBIA IS PARTY ______4-5 4.2.1 The United Nations Law of the Sea Convention, 1982 (UNCLOS) ______4-5 4.2.2 International Convention for the Prevention of Pollution from Ships, 1973, as modified by the Protocol of 1978 relating thereto (MARPOL 73/78) ______4-5 4.2.3 The Convention on Biological Diversity (CBD) 1992 ______4-5 4.3 MARPOL REGULATIONS RELEVANT TO THE MARITIME ASPECTS OF THE KUDU GAS FIELD DEVELOPMENT OPERATIONS ______4-6 4.3.1 Machinery space drainage ______4-6 4.3.2 Sewage ______4-6 4.3.3 Galley wastes ______4-7 4.3.4 Solid waste ______4-8 4.3.5 Atmospheric emissions ______4-8 4.4 CONTRACTS BETWEEN TULLOW OIL AND CONTRACTORS ______4-14

SECTION 5: STAKEHOLDER MEETINGS 5. STAKEHOLDER MEETINGS ______5-1 5.1 IDENTIFICATION OF KEY ISSUES ______5-1 5.2 THE APPROACH TO THE SCOPING PHASE OF THE EIA STUDY______5-1 5.3 IDENTIFICATION OF I&APS ______5-1 5.4 PROCEDURE FOR THE SCOPING MEETINGS ______5-2 5.4.1 Joint Kudu gas field development/KPP scoping meetings ______5-2

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5.4.2 Separate Kudu gas field development scoping meetings______5-2 5.4.3 Separate Kudu gas field development postal scoping ______5-2 5.4.4 2004: Interministerial Review Group and public information meetings ______5-2 5.5 RESULTS OF THE SCOPING PROCESS ______5-2 5.5.1 Kudu Gas Field: Size, Economic Life, etc. ______5-3 5.5.2 Availability of Deep Drilling Technology ______5-4 5.5.3 Design and Capacity of Pipeline ______5-4 5.5.4 Pipeline Operation______5-5 5.5.5 Environmental Impact of the Pipeline ______5-5 5.5.6 Effect of the Pipeline on Fishing and Navigation ______5-6 5.5.7 Disposal of Effluent from the Gas Conditioning Plant______5-6 5.5.8 Impact of Discharges from Offshore Facility______5-7 5.5.9 Handling and Fate of Monoethylene Glycol (MEG) and Condensate______5-7 5.5.10 Safety/Contingency Plans______5-8 5.5.11 Post Construction Rehabilitation Plan______5-8 5.5.12 Effect on Transport Infrastructure ______5-8 5.5.13 Greenhouse Effect ______5-9 5.5.14 Desalination Plant at Lüderitz ______5-9 5.5.15 Sperrgebiet Management Plan ______5-9 5.5.16 Relationship between Kudu and Kunene (Epupa) Projects ______5-10 5.5.17 Research Co-operation______5-10

SECTION 6: ENVIRONMENTAL IMPACT ASSESSMENT 6. ENVIRONMENTAL IMPACT ASSESSMENT ______6-1 6.1 INTRODUCTION ______6-1 6.2 DEVELOPMENT ______6-1 6.2.1 Supply Base ______6-1 6.2.2 Production Drilling______6-2 6.2.2.1 Mooring of the semi-submersible drilling unit/production platform______6-3 6.2.2.2 Interference with shipping and fisheries ______6-3 6.2.2.3 Interference with nocturnal animals______6-4 6.2.2.4 Disposal of drilling muds and cuttings, and surplus cement ______6-5 6.2.2.5 Waste discharges to sea and atmosphere ______6-7 6.2.2.6 Discharge of wastes to land______6-10 6.2.2.7 Helicopter operations______6-11 6.2.3 Production Facilities ______6-13 6.2.3.1 Phase 1 Development ______6-13 6.2.3.2 Phase 2 Development ______6-13 6.2.4 Submarine Pipeline______6-13 6.2.5 Landfall Structure ______6-14 6.2.6 Onshore Pipeline______6-14 6.2.7 Onshore Gas Conditioning Plant ______6-15 6.3 PRODUCTION______6-18 6.3.1 Operation of the Subsea Production Facility______6-18

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6.3.2 Pipeline ______6-18 6.3.3 Gas Conditioning Plant ______6-19 6.4 DECOMMISSIONING ______6-20 6.5 CONCLUSIONS AND RECOMMENDATIONS ______6-20 6.5.1 Key Finding ______6-20 6.6 RECOMMENDATIONS ______6-20 6.7 REFERENCES ______6-22

PART B : ENVIRONMENTAL MANAGEMENT PROGRAMME

SECTION 1: TULLOW OIL’S ENVIRONMENTAL MANAGEMENT SYSTEM 1.1 INTRODUCTION ______1-1 1.2 THE ENVIRONMENTAL MANAGEMENT PROGRAMME (EMP) ______1-3

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2.2.3.5 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refueling, blow-out, etc.) ______2-10 2.2.3.6 Blow out prevention during well drilling ______2-11 2.2.3.7 Disposal of drilling mud and cuttings ______2-12 2.2.3.8 Well testing ______2-12 2.2.3.9 Pollution control and waste management of products disposed of into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), and to land (used oils, metals, plastics, glass, etc) ______2-13 2.2.3.10 Transport, storage and handling of explosives ______2-14 2.2.3.11 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels) ______2-15 2.2.3.12 Equipment loss ______2-16 2.2.3.13 Oil bunkering / refueling at sea ______2-16 2.2.3.14 Use of helicopters for crew changes, servicing, etc. ______2-17 2.2.4 Decommissioning ______2-17 2.2.4.1 Well completion ______2-17 2.2.4.2 Drilling unit to leave area ______2-18 2.2.4.3 Inform relevant parties of completion of well drilling ______2-18 2.2.4.4 Final waste disposal ______2-19 2.2.5 Monitoring, compliance auditing and the submission of information ______2-19 2.2.5.1 Monitoring activities and effects______2-19 2.2.5.2 Compile well drilling “close-out” report for all activities relating to environmental management ______2-20 2.3 INSTALLATION OF GAS PIPELINE AND PRODUCTION FACILITIES ___2-21 2.3.1 Introduction ______2-21 2.3.2 Pre-establishment ______2-32 2.3.2.1 Pre-operation planning ______2-32 2.3.2.2 Financial provision______2-32 2.3.2.3 Preparation for emergencies ______2-33 2.3.2.4 Approval of EMPR ______2-34 2.3.3 Establishment ______2-34 2.3.3.1 Compliance with Environmental Management Programme______2-34 2.3.3.2 Notifying other users of the sea______2-35 2.3.3.3 Anchor position to avoid any other seabed obstacles/installations ______2-35 2.3.3.4 Anchor laying______2-36 2.3.3.5 Ensure integrity of anchor system ______2-36 2.3.4 Operations______2-37 2.3.4.1 Adherence to the EMP______2-37 2.3.4.2 Continue to communicate with other users of the sea and resource managers ______2-38 2.3.4.3 Prevention of emergencies ______2-39 2.3.4.4 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refuelling, blow-out, etc.) ______2-39 2.3.4.5 Pollution control and waste management of products disposed of: into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), to land (used oils etc, metals, plastics, glass, etc) ______2-40 2.3.4.6 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels) ______2-42 2.3.4.7 Equipment loss ______2-43 2.3.4.8 Oil bunkering / refueling at sea ______2-43 2.3.4.9 Use of helicopters for crew changes, servicing, etc. ______2-44 2.4 CONSTRUCTION OF THE SHORE CROSSING ______2-45 2.4.1 Introduction ______2-45 2.4.2 Pre-establishment ______2-45 2.4.2.1 Pre-establishment planning ______2-45 2.4.2.2 Financial Provision______2-45

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2.4.2.3 Emergency procedures ______2-46 2.4.2.4 Development and implementation of EMP compliance system______2-46 2.4.3 Construction ______2-48 2.4.3.1 Responsibility, timing and reporting______2-48 2.4.3.2 Site clearing and landscaping ______2-48 2.4.3.3 Site Management______2-49 2.4.3.4 Water Use Management Plan ______2-52 2.4.3.5 Materials Handling and Storage Management ______2-53 2.4.3.6 Fire Control and Emergency Procedures ______2-55 2.4.3.7 Leak and Spillage Management ______2-57 2.4.3.8 Solid Waste Management ______2-59 2.4.3.9 Dust management ______2-61 2.4.3.10 Wastewater Management ______2-62 2.4.3.11 Transportation Management ______2-63 2.4.3.12 Noise Management ______2-64 2.4.3.13 Management of recruitment, labour, skills development and training ______2-65 2.4.3.14 Investment, Procurement and Sales Management ______2-66 2.4.3.15 Environmental and HIV/AIDS awareness training for employees and contract workers ______2-67 2.5 CONSTRUCTION OF THE GAS CONDITIONING PLANT ______2-69 2.5.1 Pre-establishment Phase ______2-69 2.5.1.1 Pre-establishment planning ______2-69 2.5.1.2 Financial Provision______2-69 2.5.1.3 Emergency procedures ______2-70 2.5.1.4 Development and implementation of EMP compliance system______2-70 2.5.2 Construction ______2-72 2.5.2.1 Responsibility, timing and reporting______2-72 2.5.2.2 Site clearing and landscaping ______2-72 2.5.2.3 Site Management______2-74 2.5.2.4 Water Use Management Plan ______2-77 2.5.2.5 Materials Handling and Storage Management ______2-77 2.5.2.6 Fire Control and Emergency Procedures ______2-79 2.5.2.7 Leak and Spillage Management ______2-81 2.5.2.8 Solid Waste Management ______2-83 2.5.2.9 Dust management ______2-85 2.5.2.10 Wastewater Management ______2-86 2.5.2.11 Transportation Management ______2-87 2.5.2.12 Noise Management ______2-88 2.5.2.13 Management of recruitment, labour, skills development and training ______2-89 2.5.2.14 Investment, Procurement and Sales Management ______2-91 2.5.2.15 Environmental and HIV/AIDS awareness training for employees and contract workers ______2-91

SECTION 3: PRODUCTION 3.1 OPERATION OF LÜDERITZ BASE ______3-1 3.1.1 Compliance with EMP______3-1 3.1.2 Pollution control and waste management______3-1 3.2 OPERATING PIPELINE AND PRODUCTION FACILITIES ______3-3 3.3 OPERATING GAS CONDITIONING PLANT ______3-3

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SECTION 4: DECOMMISSIONING 4.1 WELL ABANDONMENT ______4-1 4.2 PIPELINE AND PRODUCTION FACILITIES ABANDONMENT ______4-1 4.3 DECOMMISSIONING AND ABANDONMENT OF TERRESTRIAL COMPONENT – GAS CONDITIONING PLANT, ETC. ______4-2

APPENDIX A Tullow Oil: Integrated Management System APPENDIX B MARPOL Regulations relevant to the maritime aspects of the Kudu Gas Field development operations APPENDIX C Disposal of drilling muds and cuttings

Glossary

API American Petroleum Industry (standards) BOP Blow out preventer CCGT Combined - cycle gas turbine (power station) DWAF Department of Water Affairs and Forestry (South Africa) CFC Chlorofluorocarbon (compounds) EH&S Environmental Health and Safety EIA Environmental impact assessment EIS Environmental impact statement EMP Environmental management programme EMPR Environmental management programme report GACG Government Action Control Group GDP Gross domestic product GNDI Gross national disposable income HIV/AIDS Human immunodeficiency virus / acquired immune deficiency syndrome IMS Integrated Management System (Tullow Oil's in-house system) LOSC (United Nations) Law of the Sea Convention MARPOL International Convention for the Prevention Pollution from Ships Medivac Medical (emergency) evacuation MET Ministry of Environment and Tourism MFMR Ministry of Fisheries and Marine Resources MME Ministry of Mines and Energy MWTC Ministry of Works, Transport and Communication MSDS Material safety data sheets Namdeb Namibia Diamond Corporation (Pty) Ltd Namport National Ports Authority of Namibia NamPower Namibia Power Corporation (Pty) Ltd SAMSA South African Maritime Safety Authority SABS South African Bureau of Standards SAN South African Navy WBM Water-based (drilling) mud

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Part A, Section 1: General Information

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia

Part A, Section 1 ENERGY AFRICA KUDU LIMITED

Part A, Section 1: General Information:

1.1 HOLDER OF PRODUCTION LICENCE ______1-2 1.2 ORGANISATION: MANAGER/RESPONSIBLE PERSON ______1-2 1.3 KUDU PRODUCTION LICENCE______1-3 1.3.1 The Production Licence ______1-3 1.3.2 Location of Kudu Gas Field and Production Area______1-4 1.3.3 Surface Area ______1-4 1.3.4 Infrastructure______1-4 1.3.5 Location of other projects ______1-6 1.4 DESCRIPTION OF THE KUDU GAS FIELD DEVELOPMENT PROJECT __1-7

Figures

Figure 1.1: Location of the Kudu Gas Field______1-5 Figure 1.2: Kudu Production Area ______1-6 Figure 1.3: Relationship between the Kudu gas field and diamond prospecting and mining licences ______1-7

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia

Part A, Section 1 ENERGY AFRICA KUDU LIMITED

INTRODUCTION

Energy Africa Kudu Limited and Namcor plan to proceed with the development of the Kudu gas field on the Namibian continental shelf approximately 150 km west of Oranjemund (Frontispiece). The objective of the Kudu gas field development project is to provide gas to the planned Combined Cycle Gas Turbine (CCGT) power station to be located at Uubvlei approximately 25 km north of Oranjemund. The terrestrial components of the gas field development, namely the gas conditioning plant, which includes the subsea gas production control system, will be located immediately adjacent to the CCGT power station.

This Environmental Management Programme Report has been modelled on the South African Department of Minerals and Energy’s well-established guidelines for the preparation of EMPRs and is designed to comply with the requirements of:

Namibia’s Environmental Assessment Policy (1995). The Petroleum (Exploration and Production) Act, No. 2 of 1991 and its subsequent amendments. The Petroleum Agreement for the Kudu licence. The International Finance Corporation’s Environmental, Health and Safety Guidelines: Oil and Gas Development (Offshore). The World Bank Group’s Pollution Prevention and Abatement Handbook: Guidelines for Oil and Gas Development (Onshore).

A key component of the EMPR is the environmental impact assessment (EIA) prepared for the Kudu gas field development project (CSIR Report ENV-S-C2004-066, December 2004) and updated for the revised development concept in December 2005 (Addendum to CSIR Report ENV-SC2004-066, December 2004). This EIA was undertaken in accordance with the Integrated Environmental Management (IEM) approach, as described in Namibia’s Environmental Assessment Policy (1995).

Both this EMPR and the EIA illustrate the fact that the planned development of the Kudu gas field will be a benign process. Essentially, once the installation of the production infrastructure has been completed, the effect of the operation of the gas field on the marine and coastal environment will be negligible.

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Environmental Management Programme Report

Part A

Section 1: General Information

1.1 Holder of Production Licence

Energy Africa Kudu Limited is the joint holder of the production licence with the National Petroleum Corporation of Namibia (Pty) Ltd and is the operator for the Kudu gas field development,

Note: Energy Africa Kudu Limited is owned and managed by Tullow Oil plc.

Registered office Energy Africa Kudu Limited 5 Parliament Square Casteltown Isle of Man IM9 1LA United Kingdom

Phone: +44 1624 82 7310 Fax: +44 1624 82 7301

1.2 Organisation: Manager/Responsible Person

Tullow Oil plc Chiswick, London United Kingdom

Telephone: +44 208 996 1000 Fax: +44 208 994 5332

Chief Operating Officer: Mr. Paul McDade Senior International Drilling Manager: Mr. John Welding General Manager Projects: Mr. Matthew O’Donoghue Kudu Project Manager: Mr. Donald Macraild

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Tullow Oil plc Dublin Republic of Ireland

Telephone: +353 1 213 7300 Fax: +353 1 293 0400

International Drilling Manager: Mr. Didier Mutti

Tullow Oil plc Cape Town Republic of South Africa

Telephone: +27 21 400 7600 Fax: +27 21 400 7660

Kudu Business Unit Manager: Mr. Kevin Stallbom Regional Drilling Manager: Mr. Rudolf Nel HSE Manager: Ms. Monique Beattie

Tullow Oil subsidiary Energy Africa Kudu Limited Windhoek Namibia

Telephone: +264 61 37 6600 Fax: +264 61 24 9501

Country Manager: Mr. Ger Kegge

1.3 Kudu Production Licence

1.3.1 The Production Licence

Following the successful drilling and testing of the Kudu-4 exploration well a petroleum field was declared in July 1997 for the whole of the exploration licence area 2814A granted in May 1993 after the signing of a Petroleum Agreement between the Government, and the then licence holders Shell Exploration and Production Namibia B.V. and Energy Africa Kudu Limited. Further appraisal work and gas marketing efforts resulted in the application for a Production Licence for the potential aerial extent of the Kudu gas field in July 2005. The Production Licence was granted on 31 August 2005.

The Production Licence allows for an initial 4-year period, essentially to develop the field followed by 25 years of production. There is a provision to renew the licence for an additional 10 years. The conditions of the Production Licence are essentially those already agreed in the Petroleum Agreement.

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1.3.2 Location of Kudu Gas Field and Production Area

The Kudu gas field lies approximately 170 km west of Oranjemund, Namibia (Figure 1.1). The Production Licence boundary encloses the known potential extent of the Kudu gas field (Figure 1.2). The focus of the first phase of the gas field development will be the drilling of up to four wells in an area near the sub sea manifold position at X 462 333 m, Y 6 843 055 m (WGS84, UTM Zone 33, CM 15ºE), the installation of a sub sea production system, the laying of a 180 km long sub sea pipeline to the shore landing at Uubvlei and the construction of a gas conditioning plant at Uubvlei.

1.3.3 Surface Area

The surface area of the Production Licence is 4567 km2.

1.3.4 Infrastructure

As a result of the arid climate, the rugged coastline with few sheltered bays, and the tight security required by the diamond mining operations in both Namibia and South Africa, the coast to the east of the Kudu gas field has little infrastructure available to support the offshore component of the gas field development.

Nearest coastal towns: Oranjemund, 170 km E Lüderitz, 250 km NNE Port Nolloth, 150 km SE

Nearest harbours: Lüderitz, 250 km NNE Port Nolloth, 150 km SE

Lüderitz will be used as the supply base for the gas field development. Walvis Bay, 650 km to the north, and Cape Town, 700 km to the south are the nearest centres which could provide additional support services should they be required.

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Figure 1.1: Location of the Kudu Gas Field

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Figure 1.2: Kudu Production Area

1.3.5 Location of other projects

The Kudu Production Area is bounded to the north by the Greendale Exploration Licence Area, and to the south and west, where it is partly overlapped, by the BHPBilliton Licence areas (Figure 1.1). The Kudu Production Area overlaps a Diamond prospecting licence (Figure 1.3). The prime area of diamond mining activity is Atlantic 1, operated by De Beers Marine Namibia for Namdeb, across a portion of which the gas pipeline will be laid. During the life of the Kudu gas

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field it is almost certain that additional licences will be granted in the general Kudu area and the area between the Kudu gas field and the coast for prospecting and, possibly, mining of diamonds.

1.4 Description of the Kudu gas field development project

Energy Africa Kudu Limited is the operator in a joint venture with Namcor for the Kudu gas field development project. The prime aim of the project is to develop the Kudu gas field so as to supply gas to the combined cycle gas turbine (CCGT) electricity generating station to be built at Uubvlei some 25 km north of Oranjemund by the national power company of Namibia, NamPower (Pty) Ltd.

A full description of the proposed project is presented in Part A, Section 2 of this report.

Figure 1.3: Relationship between the Kudu gas field and diamond prospecting and mining licences

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Part A, Section 2: Detailed Description of the Kudu Gas Field Development Project

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Part A, Section 2: Detailed Description of the Kudu Gas Field Development Project:

2. PROJECT DESCRIPTION______2-1

2.1 HISTORY OF THE KUDU GAS DISCOVERY ______2-1 2.1.1 Geological history ______2-1 2.1.2 Exploration history______2-1 2.2 NEIGHBOURING LICENCE HOLDERS ______2-3 2.2.1 Petroleum Exploration Licence Areas______2-3 2.2.2 Diamond Prospecting and Mining Licence Areas ______2-3 2.3 DRILLING ______2-5 2.3.1 Introduction ______2-5 2.3.2 Drilling Unit ______2-6 2.3.3 Drilling Operations______2-6 2.3.4 Drilling Muds ______2-11 2.3.5 Logging ______2-12 2.3.6 Testing______2-12 2.4 PRODUCTION FACILITIES ______2-12 2.5 SUBMARINE PIPELINE ______2-14 2.5.1 Introduction ______2-14 2.5.2 Laying of the Pipeline ______2-14 2.5.3 Monoethylene Glycol (MEG Piggy Back line) ______2-17 2.6 CONTROL UMBILICALS ______2-17 2.7 PIPELINE LANDFALL______2-18 2.8 ONSHORE PIPELINE ______2-18 2.9 ONSHORE GAS CONDITIONING PLANT ______2-20 2.10 SUPPLY BASE ______2-22 2.11 PRODUCTION OPERATIONS ______2-22 2.11.1 Introduction ______2-22 2.11.2 Production Wells and Subsea Production System ______2-22 2.11.3 Pipeline ______2-24 2.11.4 Onshore Gas Conditioning Plant ______2-24 2.11.5 Non-routine operations ______2-27 2.12 DECOMMISSIONING ______2-28

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Figures

Figure 2.1: Location of the Kudu gas field______2-4 Figure 2.2: Relationship between the Kudu gas field and neighbouring diamond prospecting licence areas __ 2-5 Figure 2.3: Schematic Kudu gas field development ______2-8 Figure 2.4: Typical Kudu well stratigraphy ______2-9 Figure 2.5: Trouble-free Drilling Curve: Typical Kudu well ______2-10 Figure 2.6: Route of the gas pipeline between the Kudu gas field and the power station ______2-15 Figure 2.7: Typical Offshore Pipeline Installation Method using a Laybarge ______2-16 Figure 2.8: Route of gas pipeline from the landfall to the gas conditioning plant ______2-19 Figure 2.9: Main components of onshore gas conditioning plant ______2-20 Figure 2.10: Layout of onshore gas conditioning plant ______2-21

Tables Table 2.1: Main components of Water Based Drilling Muds ______2-11 Table 2.2: The characteristics of a typical Kudu well ______2-12 Table 2.3: Phase 1 Emissions Summary from the Uubvlei gas conditioning plant______2-29

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2. PROJECT DESCRIPTION

2.1 HISTORY OF THE KUDU GAS DISCOVERY

2.1.1 Geological history

The Kudu gas accumulation occurs at a depth of more than 4 km below sea level. The reservoirs are up to 30 m thick aeolian sand sheets (dunes) encased in lavas.

The history of the Kudu reservoir starts some 140 million years ago when South America and Africa formed one continent, Gondwanaland. A rift valley, similar to the present East African rift system, developed along what later became the fissure between the two continents. Some 5 million years later continuous drifting apart resulted in a narrow ocean on the border of which dune fields developed. These dune fields were occasionally overrun by lavas bursting through fissures caused by the stretching of the crust during the early phase of drifting. New oceanic crust was formed in the widening gap between South America and Africa. The distance between the mantle upwelling from which new oceanic crust in the central part of the proto-Atlantic was formed gradually increased and the mantle underneath the continents bordering the proto-Atlantic Ocean started to cool resulting in the subsidence of the dune and lava fields below the level of the sea. This process continues to the present day and the layer of sediments on top of the Kudu reservoir is more than 4 000 m thick.

In early geological history, narrow sediments rich in organic debris accumulated. During the process of burial the organic remains slowly started to crack (break down) into smaller hydrocarbon components as a result of increasing temperature and pressure at depth. The temperature at the reservoir level is 166°C. In this high temperature environment the organic remains were cracked down to the smallest hydrocarbon molecules, methane, which is the main hydrocarbon component of the Kudu field.

2.1.2 Exploration history

The Kudu gas field was discovered in 1974. A further two wells were drilled during 1987-1988. Following Namibia’s independence in March 1990 an extensive Licensing Round was initiated in which the entire Namibian continental shelf was divided into blocks of one-degree squares for licensing purposes.

Shell Exploration and Production Namibia BV (SEPN) and Energy Africa Kudu Ltd (then Engen (Kudu) Ltd) were awarded the licence for Area 2814A containing the Kudu gas discovery (Figure 2.1) on 6 May 1993 with SEPN as the operator. In 1996 Energy Africa divested two thirds of its holding to Texaco whereupon the equity share of the companies in the Kudu Joint Venture became SEPN – 75%, Energy Africa – 10% and Texaco – 15%. Subsequently Chevron took over Texaco and became an equity holder as ChevronTexaco.

The initial objective was to appraise the gas field for a development which would export gas to a new 1600 MW combined cycle gas turbine (CCGT) power station in South Africa, based on a

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Letter of Intent (LOI) with Eskom. Subsequently the LOI lapsed in 1996 when no agreement could be reached on timing of delivery and gas price.

During late 1993, a 1600 km 2-D and 300 km2 3-D seismic survey were completed. This was followed in the second half of 1996 by the drilling of the Kudu-4 well, which confirmed that the Kudu gas discovery was commercially exploitable. A further 400-km of 2-D and 400 km2 of 3-D seismic were shot in late-1996 and early-1997 to investigate the extension of the gas field into the southern extension of the Licence area awarded during the second Licensing Round.

SEPN and Energy Africa applied for the Declaration of Petroleum Field on 6 May 1997. This was confirmed on 21 July 1997 requiring the preparation of an appraisal programme and plans for the marketing of the Kudu gas. In November 1997 a Memorandum of Understanding (MoU) was signed between SEPN and its partners, NamPower and Eskom to promote the construction of a nominal 800 MW CCGT power station at Oranjemund to be sourced by Kudu gas. Later National Power, a UK based Independent Power Producer, also joined the consortium. This project was known as the Kudu Power Project (KPP) included a first phase development of the gas field to be followed by a second phase for the export of gas to South Africa. A feasibility study conducted by independent consultants demonstrated the commercial viability of the development to everyone’s satisfaction except Eskom, the planned purchaser of the excess power generated over Namibia’s needs, who felt the timing was premature and the cost too high. As a result the MoU was allowed to lapse at the end of 1998.

At that time a new commercialisation strategy was adopted comprising the development of a smaller power station in Oranjemund (400 MW – the OPP) in parallel with the development of a large power station in the Western Cape (1600 MW – the CPP) in conjunction with the Cape Municipal Area Local Authorities (CAMALA). This was termed the integrated project reflecting the fact that by combining the fuel demand of the two power stations the offshore gas field infrastructure could be integrated into a single development rather than two separate developments.

In 2000 an independent feasibility study commissioned by SEPN and CAMALA clearly demonstrated the commercial viability of a 1200 – 2000MW gas fired power station in the Western Cape as the cheapest next new generation option for South Africa within the targeted time window (2005 – 2008). The findings of the study were communicated to the South African Government. Various political reasons delayed the decision to proceed with the CPP project.

SEPN continued work on a new phased development strategy for the Kudu gas field. This strategy comprised the construction of a 400 MW CCGT power plant at Oranjemund and the investigation of installing a floating liquefied natural gas (FLNG) plant in the Kudu gas field. A 3-D seismic survey conducted in 2001 and an appraisal drilling campaign was expected to confirm the presence of sufficient gas to make the FLNG project viable. The first two wells, Kudu-6 and -7 were both “dry” and SEPN relinquished the licence shortly thereafter as did ChevronTexaco a year later. Energy Africa then took over as operator with the view to develop the Kudu gas field to supply gas to a CCGT power station to be built by NamPower in the vicinity of Oranjemund. Energy Africa Kudu Limited holds 90% of the equity in the venture and Namcor the balance of 10%. A production licence for the Kudu gas field area (“Kudu Production Area”) was granted on

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31 August 2005. The part of the Kudu Production Area west of longitude 14º 30’E overlaps the licence area in which BHP Billiton has exploration rights in the geological sequence above the Kudu reservoir sequence.

2.2 NEIGHBOURING LICENCE HOLDERS

2.2.1 Petroleum Exploration Licence Areas

The original Licence Area 2814A was extended in 1996 to include the remaining two 15 minute sub-blocks to the south. Whilst evaluation of the extension demonstrated the existence of potential gas bearing sands the associated risks were considered to be too high to warrant the drilling of a dedicated exploration well, required as commitment if the blocks were to be retained beyond May 1998. As a result these two blocks were relinquished in May 1998.

Chevron Overseas (Namibia) Limited (operator) in a joint venture with Eagle Energy (Namibia) Limited and Shell Namibia Exploration B.V. drilled a single well in Licence Area 2815 immediately to the east of Licence Area 2814A (Figure 2.1) in 1996. The well proved to be dry and the area was relinquished in 1997.

Ranger Oil held an Exploration licence for an area of several degree square blocks immediately to the north of Licence Area 2814A but relinquished the area after carrying out a seismic survey in 1998. Recently Exploration licences were granted to BHP Billiton for areas to the immediate west (and partly overlapping the Kudu Production Area) and south of the Kudu Production Area, to Greendale for the former Ranger Oil licence area and to Hunt Oil for an area further to the north, to the west of Lüderitz (Figure 2.1).

2.2.2 Diamond Prospecting and Mining Licence Areas

Licence Area 2814A overlaps diamond prospecting areas, primarily those held by Namdeb but also some deepwater prospecting licence areas held by other parties (Figure 2.2).

Atlantic 1 Diamond Mining Licence Area Of critical concern to the Kudu gas field development is the Atlantic 1 Diamond Mining Licence Area which lies in the path of the most economical pipeline route from the Kudu gas field to Oranjemund.

The Atlantic 1 Licence area, held by Namdeb, is being mined under contract by De Beers Marine Namibia (Pty) Ltd (DBMN). A Right of Way agreement has been pursued with Namdeb since 1998, initiated by the former operator of the gas field development, Shell Exploration and Production Namibia B.V. An in-principal agreement has been reached on a pipeline route which avoids, as much as is technically possible, the potentially high value areas which DBMN intends to mine. This agreement will have to be concluded before pipeline construction commences.

Atlantic 1 Mining Licence Area is approximately rectangular in shape and covers 6098 km2 of seabed in the south-eastern corner of the Namibian Exclusive Economic Zone (EEZ). Separated

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from the shore by the 3 nautical mile wide territorial waters, the south-eastern limit of Atlantic 1 is the international boundary between the EEZs of the Republics of Namibia and South Africa, which is still under dispute. The area extends 110 km to the north-west and is about 60 km wide. Most of the mining occurs in water depths exceeding 100 m beyond the 12 nautical mile territorial limit in the contiguous zone. A new development being considered for implementation in Atlantic 1 is extensive dredge mining using a cutter-suction dredger.

Other Diamond Mining Licence Areas The territorial waters are part of the mainly terrestrial Mining Area 1 Licence Area in which Namdeb is active. Along the border with Namibia, Grant Areas 1c and 2c are in geographic contact with Atlantic 1 Licence Area. Grant Area 1c is controlled and operated by Alexkor, Area 2c is leased to De Beers Consolidated Mines and De Beers Marine is the contracted operator (Figure 2.2).

Figure 2.1: Location of the Kudu gas field

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Figure 2.2: Relationship between the Kudu gas field and neighbouring diamond prospecting licence areas

2.3 DRILLING

2.3.1 Introduction

A full environmental impact assessment (EIA) was prepared by CSIR prior to the drilling of Kudu-4 in 1996 and was extended to include the Kudu-5 drilling operations in 1998. Two further wells (Kudu-6 and Kudu-7) were drilled in 2002 for which a new EIA was prepared. The earlier drilling EIAs provide detailed information on the process of drilling a well. For completeness however a brief description is presented here together with pertinent details of synthetic based mud systems and chemicals.

Subsequent to the completion and approval by the earlier version of this EIA plans were developed to drill two exploration wells prior to the start of the Kudu gas field development. The drilling operations and consequently the impact of these wells on the environment will be very similar to the production wells.

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2.3.2 Drilling Unit

The current field development plan is to drill up to four subsea wells using a semi-submersible drilling unit. Three wells will be drilled at the start of field life, while the last one may be drilled some time in the future, if required for maintaining the required gas production rate. The wells will be completed with a subsea tree containing a series of remotely controlled valves and connected by a flowline to a subsea manifold from which a subsea pipeline will transport well fluids to Uubvlei where the CCGT power station is to be located. This will provide up to 140 MMscf/d of gas during the first few years of the gas field (Figure 2.3).

If through production history and/or appraisal drilling additional gas reserves are established, further subsea wells will be drilled to provide for an increased gas production rate. Such a second phase would require a second subsea manifold connected to the first. The pipeline will have sufficient capacity to transport a higher field output of up to 280 MMscf/d as would be required by the presently envisaged Phase 2.

Safety precautions to minimise the possibility of an offshore accident require that a 1000 m radius exclusion zone be enforced around the drilling unit. Collision prevention equipment including radar, multi-frequency radio, foghorns, etc. will be installed onboard the unit. Additional precautions, in addition to the exclusion zone, that may be utilised include a 24-hour standby vessel, 24 hour watches, cautionary notices to mariners, and access to current weather service information. Equipment and training to ensure the safety and survival of the crew in the event of an accident is a requirement. It is envisioned that two supply vessels will service the drilling unit, either of which may double as a stand-by vessel, and crew changes via Oranjemund will be performed utilising helicopters.

2.3.3 Drilling Operations

The water depth in the Kudu gas field is approximately 170 m and the total depth of the wells will be between 4,500 and 5,000 m. The wells will be vertical. Details of the anticipated well profiles are shown in Figure 2.4.

Drilling is initiated by lowering a drill bit to the sea floor on the drill string and rotating the drill string, causing the bit to crush the rock into small particles. The small rock particles generated at the bit are removed from the well bore by the drilling fluid or “mud”, a specially formulated mixture of natural clays, polymers, weighting agents and/or other materials suspended in a fluid medium. These drilling muds are usually based on water (water-based mud - WBM) but in some cases mineral oil (oil-based mud - OBM) or synthetic oil (synthetic-based mud - SBM) which is biodegradable, are used. The use of oil-based mud would require prior permission by the Ministry of Mines and Energy. Although the use of WBM is preferred, sometimes OBM or SBM are used when drilling conditions are more difficult. Additional details are given in Section 2.3.4.

Drilling mud systems perform a number of important functions during the drilling of the well. The primary functions are the removal of drill cuttings from the bottom of the hole and the control of sub-surface pressures. Cuttings are transported to the surface by circulating mud down the drill

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string, through the bit and up the annular space between the borehole and drill pipe.

The continuous motion of a semi-submersible drilling unit requires that the wellhead and the Blow Out Prevention (BOP) unit be installed on the ocean floor. A movable marine riser is utilised to connect the BOPs and the wellhead to the floating vessel. The riser is a tubular conduit that is assembled from pre-fabricated 15 m sections. The marine riser system guides the drill string to and from the well, provides a conduit for mud returns from the ocean floor to the drilling vessel, provides running and connecting components, and compensates for rig motion.

Drill cuttings are separated from the mud at the surface by the solids control equipment before the mud is re-circulated. The density or weight of the drilling fluid (mud) can be altered to adjust to changing down-hole pressure conditions. With WBM the drilling fluids are usually not discharged to the sea before the well is finished. The drilled rock cuttings are continuously removed from the mud and are discharged to the sea. In normal drilling operations OBM and SBM are never discharged to the sea but after use are sent to a land based mud processing facility for recycling or disposal. Whilst cuttings generated from OBM are collected, treated and disposed of separately, cuttings generated using SBM can, subject to an EIA, be discharged to the sea in safety as the specially formulated synthetic oil which covers the cuttings is biodegradable and will disperse without significant impact on marine life. A possible schedule for the drilling operations once the rig is positioned over the well location is shown in Figure 2.5.

Drilling is periodically stopped to allow new sections of pipe to be added to the drill string or to replace the drill bit. Casing (pipe) will be run and cemented into previously drilled hole to isolate subsurface formations, and to provide structural support to the borehole. The casing is designed to ensure the safe and efficient drilling of the well. Drilling continues beyond the cased hole in subsequently smaller sized holes until the total depth of the well is reached.

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Figure 2.3: Schematic Kudu gas field development

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Figure 2.4: Typical Kudu well stratigraphy

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Figure 2.5: Trouble-free Drilling Curve: Typical Kudu well

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2.3.4 Drilling Muds

As indicated in Section 2.3.3, drilling muds are an essential element in drilling operations without which the drilling operations cannot be conducted. Drilling mud systems perform a number of important functions during the drilling of a well including: The removal of drill cuttings from the bottom of the hole and transportation to surface, The control of sub-surface pressure to avoid loss of well control thereby ensuring drilling can be safely continued, To cool and lubricate the drill bit, To provide lubricity to the drill string which lies in contact with the bore-hole wall over long sections of its length, To stabilize the still open just drilled sections to prevent them from swelling or collapsing thereby hampering ongoing drilling operations, To prevent excessive fluid loss and consequent productivity damage of porous hydrocarbon bearing intervals. Provide support to a part of the drill string (buoyancy).

Cuttings brought up from the bore-hole have to be disposed of, together with any drilling fluid that remains attached to them. The degree of impact drilling fluids have on the environment depends on the type of mud used and the prevailing environmental conditions.

The mud which will be used in the Kudu production wells is so-called Water Based Mud (WBM) which is primarily made up of fresh water, or if not sufficiently available, sea water with added chemicals to provide weight and viscosity as described in the Kudu-4 EIA (Section 5.4 pages 3 - 6) (CSIR, 1996) 1 and Table 2.1 below.

Table 2.1: Main components of Water Based Drilling Muds

COMPONENT MAIN FUNCTION Sea water Mixed with dry components to form the continuous or liquid phase of the drilling fluid. Bentonite Types of clay minerals that swell when mixed with water. It is added to increase viscosity and gel strength. Barite Used as a weighting agent to increase the density of the drilling fluid. Polymers Organic substances used to reduce fluid loss and to thicken the drilling fluids e.g. starch, xanthan gum and guar gum. Gypsum Used to control ionic balance Various other Used to control pH, inhibit corrosion, kill micro-organisms, etc. chemicals (Source: Kudu-4 EIA, Table 3.2).

1 CSIR (1996) Environmental impact assessment for gas exploration drilling in Licence Area 2814A on the continental shelf of Namibia. Stellenbosch. CSIR Report EMAS-C95053b.

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The drilled cuttings from WBM are generally considered not to be damaging to the environment and are normally discharged to the sea.

The profile of a typical Kudu well indicating the drilling fluid to be used in each section is presented in Table 2.2.

Table 2.2: The characteristics of a typical Kudu well

HOLE CASING CUTTINGS HOLE DEPTH DRILLING FLUID SIZE SIZE VOLUME (metres below (inches) (inches) (m3) sea level) 200 36 30 131 Water returns to seabed 1400 26 18.625 411 Water Based Mud 3300 17.5 13.375 295 Water Based Mud 4700 12.25 9.625 106 Water Based Mud

2.3.5 Logging

Evaluation of the properties of the formations penetrated by a well is carried out routinely during the drilling operation. Mud logging refers to an examination of the drill cuttings brought to the surface by the drilling fluid. It also monitors the occurrence of hydrocarbon gases that relate to changes in formation pressure which can aid in controlling the well and determining if a natural gas reservoir has been penetrated. Electric wireline logging is utilised for downhole formation evaluation. The use of wireline logging tools requires the drillstring to be removed from the well; therefore these logs are generally run at casing points. Radioactive sources may be used in the logging tools for certain types of data acquisition. Data obtained from wireline logging tools are used to assess the quality of petroleum reservoirs and the presence of oil and/or gas. Well log data are also utilised by geologists to identify specific rock layers penetrated by the well.

2.3.6 Testing

It is not foreseen that the Kudu production wells will be tested for any length of time. If flow testing is required, produced hydrocarbons will be burnt at the wellsite. Surface testing equipment will be installed and tested on the drilling vessel prior to flow testing. A high efficiency flare will be used to maximise combustion of the gas. Produced water, if any, will be treated and discharged overboard according to acceptable international standards.

2.4 PRODUCTION FACILITIES

The Kudu gas field lies in approximately 170 m of water about 170 km west of Oranjemund on the Namibian coast. Energy Africa’s objective with the Kudu gas field development is to monetise Kudu’s presently proven reserves of ca. 1.3 TCF gas-in-place. Eventually this will comprise four subsea wells tied to a pipeline subsea manifold from which a pipeline transports the well fluids to onshore production facilities for final conditioning prior to sale. The entire production from the

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Kudu gas field will be used to generate electricity at Uubvlei in the vicinity of Oranjemund. Initially an 800 MW CCGT power plant will be supplied with gas. This may be doubled to 1600 MW at a later date after additional gas reserves have been established which is the presently envisaged Phase 2.

The primary offshore component for both developments will be the wells completed at the seabed with subsea trees, flowlines, manifolds, and pipeline to shore, together with the control provided from onshore through a subsea power and control umbilical to a subsea control distribution manifold (CDU) and from there via smaller umbilicals to the individual wells, all of which will be installed during Phase 1 (Figure 2.3).

Although the Kudu gas field lies inshore of the trawling exclusion zone (demarcated by the 200 m isobath) the wellheads and trees will be designed such that there will not be catastrophic damage should illegal fishing take place.

Phase 1 Development The development of the gas field at a maximum gas flow rate to shore of ca. 140 MMscfd for a 800 MW CCGT power station at Uubvlei comprises the following: Production Wells and Subsea Production System: 4 subsea production wells, to be drilled with a semi-submersible drilling unit, to be connected by 10” flow lines to a subsea manifold. Evacuation: 18” multiphase gas pipeline from the manifold to shore. Hydrate management: 4" piggyback line from shore to the gas field end of the pipeline to supply hydrate inhibitor chemical (MEG) and corrosion inhibitor. Methanol can be supplied to the wellheads through the umbilical from shore at a rate of up to 100 bpd during a couple of hours only if required during well start-up or to remove a hydrate blockage. There will be no discharge. Onshore Gas Conditioning: Final liquid removal, separation of hydrate inhibition chemical (MEG) and condensate, gas conditioning and superheating and storage of MEG and stabilized condensate. The MEG is regenerated to remove water and recycled. The facilities comprise a single slug catcher and 2 parallel conditioning units, each capable of conditioning the maximum 140mmscfd well production. The incoming gas contains condensate, water and MEG. At maximum production rates condensate rates could be up to 300 bpd and water/MEG could be up to 900 bpd depending on operating conditions. In the event of formation water breakthrough the MEG/water rate could increase up to 1,600 bpd. The condensate is separated from the water/MEG mix then degassed and stored prior to sale. The separated gas is used in the fuel gas system. The water/MEG mixture is treated in a regeneration unit, the MEG recovered and recycled, and the water is disposed of via a heater exhaust stack. The amount of water vapour is dependent on operating conditions and the presence of formation water. The maximum at 140 MMscft production is estimated to be 6,100 kg/hr, although typical rates are likely to be about 3,000 kg/hr. The water vapour may contain about 0.3ppm hydrocarbons, of which 99% would be methane. The MEG content of the water vapour will typically be less than 650ppm, although this will need to be confirmed with the MEG regeneration

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package supplier during detail design. The gas is dried and heated prior to entering the power station via a fiscal meter.

Phase 2 Development The possible expansion to meet the requirements of an additional 800 MW CCGT power generating capacity at a maximum gas flow rate to shore of ca. 280 MMscfd comprises the following: Production Wells and Subsea Production System: 4 subsea production wells, to be drilled with a semi-submersible drilling unit, to be connected by 10” flow lines to a second subsea manifold. Subsea tie-back: The Phase 2 manifold connected by a 14” pipeline to the existing Phase 1 manifold. Onshore Gas Conditioning: Expansion of existing facilities by the addition of a third conditioning unit (the slug catcher is already sized for the Phase 2 case).

2.5 SUBMARINE PIPELINE

2.5.1 Introduction

A single 18” pipeline is to be installed from the Kudu gas field to transport the gas from the subsea manifold to the gas conditioning plant adjacent to the power station. The pipeline will be laid on the sea bottom and will be provided with an anti-corrosion coating and sacrificial anodes to resist external corrosion. In addition the pipe will be coated with concrete in order to stabilize it on the seabed. Near shore, the pipeline will also be trenched in places and/or covered with rock, to ensure that the pipeline does not move under the influence of wave and current induced forces. As a minimum, all pipelines will be designed to meet the requirements of the American Society of Mechanical Engineers (ASME) B31.8 which is the most widely recognised international design code for gas transmission pipelines. The pipeline route has been selected on the basis of the finally chosen power station site at Uubvlei in consultation with Namdeb to avoid, within the technical pipe laying limitations, potentially high value parts of their diamond mining licence area (Figure 2.6).

2.5.2 Laying of the Pipeline

Laying of the submarine flowlines and pipeline for the Kudu gas field development is expected to be performed using the conventional laybarge technique. This involves transporting lengths of pipe (nominally 12 m each) to a moored barge where they are welded to form the pipeline. The barge moves forward length by length, and in doing so, the pipe moves along a ramp on the barge through a series of welding stations, at which the weld is completed. The pipe then moves through a radiography station where the weld is X-rayed or ultrasonically tested and finally through a field joint station where the weld is coated as protection against external corrosion and the gap in any concrete weight coating is filled. The pipeline leaves the barge over a curved ramp, called a stinger and is lowered through the water in a long suspended span. The curvature of the pipe in the suspended span is controlled by tension, applied through a tracked or wheeled tensioner system at the end of the ramp. A typical installation layout is provided in Figure 2.7.

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Figure 2.6: Route of the gas pipeline between the Kudu gas field and the power station

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Figure 2.7: Typical Offshore Pipeline Installation Method using a Laybarge

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The piggyback MEG line is constructed in similar fashion and clamped to the 18” pipeline, before lowering into the sea. Laying of the pipeline is expected to start at the coast and finish at the location of the manifold. The first section of pipeline and piggyback lines will be pulled from the laybarge to the shore using a winch.

At the offshore location the laybarge will lower the ends of the lines to the sea bottom into a pre- defined target area close to the manifold. Divers will then be used to install connecting pieces from the flow lines and pipeline end manifolds to the subsea manifold. The complete pipeline will then be flooded with water and pressure tested to a level of at least 1.25 times the value which it will experience during its operational life.

In addition to the laybarge vessel a typical installation spread will also include one or two pipe transportation vessels, one or two anchor handling vessels and a general support vessel.

The pipeline will be laid during the good sea state window, which typically runs from November to March each year. The total installation time is estimated to be around 120 days excluding contingency time for bad sea state or weather conditions.

2.5.3 Monoethylene Glycol (MEG Piggy Back line)

A 4” piggyback line will be required to transport monoethylene glycol (MEG) from the onshore gas conditioning plant to the distribution manifold located adjacent to the pipeline manifold at the seabed. From there, the MEG will be transported to the subsea trees through the infield umbilicals. A technique termed “piggybacking” will be employed for its installation. This involves strapping the smaller lines to the main line as it is passed over the ramp at the stern of the laybarge. This system has been used extensively during the past 15 years in the petroleum industry. The pipeline installation will be controlled such that the smaller piggyback line will be orientated at either 10 o’clock or the 2 o’clock position relative to the main line.

2.6 CONTROL UMBILICALS

A power and control umbilical line will connect the shore installation to the subsea control distribution manifold (CDU) from which smaller umbilicals (termed infield umbilicals) connect to each well. The piggyback MEG line will also terminate at this CDU. The CDU is located close to the pipeline subsea manifold. The umbilical from shore and the CDU are sized to be able to handle Phase 1 and Phase 2 wells. The umbilical is a flexible armoured cable with cores to carry electrical power, instrument signals, tubing for hydraulic power and methanol for hydrate prevention at the well heads at start up. The Kudu infield umbilicals besides methanol will also transport MEG for continuous prevention of hydrate formation.

The umbilicals will be laid separately from the pipelines by a suitable vessel. At the shoreline the umbilical will terminate at an instrument panel in a small building constructed for this purpose. From there a buried umbilical will connect to an instrument panel in the gas conditioning plant.

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2.7 PIPELINE LANDFALL

The key factor involved in bringing a pipeline to shore is to perform the work in such a way that the pipeline is adequately protected throughout its lifetime. As a result of the high wave energy experienced along the south-west African coast the pipeline has to be buried to at least 2-3 m below the normal sea bottom level in the breaker zone and/or be positioned above the wave action.

The method selected for the Kudu pipeline is to concrete coat the pipeline, bury it in some areas and additionally to cover the affected areas with rock dumped from a barge.

Away from the breaking wave area, it may still be necessary to cover the pipeline to ensure that the line will not move when subjected to storm weather conditions. The need for this approach is highly dependent upon the orientation of the pipeline relative to the storm direction and how quickly the water depth increases along the route of the line. This will be analysed during detail design and appropriate measures taken to ensure pipeline on-seabed stability. Methods of stabilization could include trenching, rock dump, or stabilizing weighted mattressing. This will be performed over the affected length, potentially the first 50 km of pipeline length from shore up to a water depth of approximately 60 m.

During the course of the detailed engineering design studies, the landfall method and any nearshore stabilization requirements will be confirmed.

2.8 ONSHORE PIPELINE

The gas conditioning plant will be located adjacent to the power station close to the shoreline at Uubvlei (Figure 2.8). The onshore pipeline route will be approximately 800m in length.

The onshore section of the pipeline will have a bonded polyethylene coating and be buried, with a cover of at least 1 m, along the same causeway as the power plant cooling water intake and discharge pipelines. In addition, the pipeline will be protected against corrosion by an impressed current cathodic protection system.

A culvert will protect the pipeline where it passes under the haul road. The MEG line and the umbilical will also be run through the culvert.

The buried onshore section of the pipeline will have markers every 100 m and at changes in direction.

At the entrance of the gas conditioning plant, an emergency shutdown valve (ESDV) will isolate the pipeline from the plant in the event of an emergency. It is operated by dedicated process sensors and from a separate system than that used for the normal control of the plant. Manual valves upstream of the ESDV will allow it to be tested and maintained.

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O S 0 4 U1

Figure 2.8: Route of gas pipeline from the landfall to the gas conditioning plant

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2.9 ONSHORE GAS CONDITIONING PLANT

The gas conditioning plant with its associated slug catcher will be constructed adjacent to the CCGT power station. The key components of the gas conditioning plant are presented schematically in Figure 2.9. Gas and liquids from the pipeline are led into a slug catcher, which permits the separation of the gas from the condensate, which is a light fraction petroleum liquid, and water/monoethylene glycol (MEG) mixture. The slug catcher will be designed for Phase 2 gas rates and for a slug size of approximately 500 m3. In the event that a slug exceeds the design capacity of the slug catcher, automatic level and pressure sensors will shut the ESD valve and safely flare any excess gas. The gas is dried and heated before passing through the fiscal meter and thence into the power station. The proposed plant layout is presented in Figure 2.10.

The condensate and water/MEG mixture is processed in a separation system. The condensate is heated to remove gas (stabilize it), then cooled, stored and shipped by road tanker. The water/MEG mixture is further treated in a regeneration unit which separates the MEG from the water. The water vapour released is disposed of in the fired heater exhaust stack. The MEG is stored and then returned to the wells via the piggyback line.

Emergency 1 LT Superheater Flare PT Separator Gas to Power Station M Fiscal Meter

Pre-cooler Condensate Stabilisation Pipeline LP Gas LP Gas

Slugcatcher Heater

Vent 3 Roadcar Loading

Rich MEG Condensate LP Gas Storage

MEG Water 4 Degasser Vent 2 Vapour

Lean MEG Storage MEG Lean MEG Degasser to Wells

MEG Regeneration Package

Figure 2.9: Main components of onshore gas conditioning plant

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Figure 2.10: Layout of onshore gas conditioning plant

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2.10 SUPPLY BASE

It is planned to use the Port of Lüderitz as the base for the Kudu gas field development operations. It will serve as the base for the support vessels and drilling supplies, pipeline sections and other construction materials will be stockpiled there. Concrete coating of the pipeline sections may also be undertaken in Lüderitz. If this option is selected the pipeline sections will be delivered to Lüderitz already corrosion coated. The facility will consist of bulk cement storage tanks, water tanks, mixing facilities and the concrete coating plant. The port of Walvis Bay is an alternative in case no dedicated wharf space and pipe yard can be secured at Lüderitz before the start of the gas field development.

2.11 PRODUCTION OPERATIONS

2.11.1 Introduction

The presently envisaged development of the Kudu gas field consists of four subsea wells, possibly followed in Phase 2 by four more subsea wells, all of which will be tied back to a subsea manifold. From the manifold the gas will pass into the main export pipeline and on to a gas conditioning plant located adjacent to the power station.

The production operations are described below with reference to the component parts of the project infrastructure: Production Wells and Subsea Production System Manifold Pipeline Onshore Gas Conditioning plant.

2.11.2 Production Wells and Subsea Production System

The Phase 1 development will entail four subsea wells with a possible further four subsea wells in Phase 2 to cope with the demand of the full 1600 MW power station.

The subsea wellheads will stand some 2 - 3 m clear of the sea floor and the flowlines will not be buried. Each flowline will have a gas meter installed. An infield umbilical will connect each well to the controls distribution unit (CDU) for control and for supply of hydrate chemical and of hydraulic fluids. A 4" monoethylene glycol (MEG) piggyback line from shore will supply the CDU with continuous hydrate chemical for injection into the flow lines and pipeline via the wellheads.

Following start up, there will be continuous injection of MEG into the flowlines to prevent methane hydrate formation. Methane hydrate is a form of ice and MEG is an alcohol which acts as an antifreeze preventing formation of hydrate by effectively lowering the freezing point. No discharges of MEG offshore are foreseen.

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For the first field start up, where there is a greater chance of hydrate formation due to a greater pressure drop over the subsea tree choke valve and with cold fluid present in the well tubing, special measures will be taken. These consist of:

• Filling the flowline with MEG • Filling the space between the subsea tree valves with methanol • Pressurizing the pipeline and flowlines to 70bar with nitrogen.

Flow assurance studies, using the industry standard OLGA dynamic modelling package, have confirmed the effectiveness of above approach.

Methanol is more volatile than MEG and is more effective at the lower temperatures occurring during well start up. However, this volatility leads to large losses into the gas phase. Physically this merely results in a slightly higher calorific value of the gas to the power station. However, these losses would constitute a high operating expense and consequently, MEG is used in normal operations as the hydrate inhibitor. There will also be injection of corrosion inhibitor into the MEG to augment its corrosion inhibiting properties.

Once in production, the minimum of intervention with the subsea facilities is foreseen. Gas offtake rates per well will vary up to 80 mm scfd (Phase 1 - Phase 2) and temperatures at the well head will peak at 120°C. Flow from each well will be controlled by a production choke. The choke position is controlled by a hydraulic stepping motor with power provided by the umbilical. The flowlines to the pipeline inlet manifold will be designed for full reservoir pressure minus the static column of gas pressure. This pressure is known as the Closed in Tubing Head Pressure (CITHP). In addition, a High Integrity Pressure Protection System (HIPPS) will be installed on each well. The HIPPS consists of two high integrity emergency shutdown valves (ESDVs) and three each pressure sensors on the flowline. An electronic voting system will close the well ESDVs in the event of 2 out of 3 sensors detecting an overpressure.

The subsea system will be designed to be completely diver-less for maintenance purposes and all maintenance other than well re-entry and workover, will be by remotely operated vehicle (ROV).

If for any reason a well re-entry is required, then the provision of a mobile drilling unit will be necessary. Any maintenance of subsea wells will require a mobile drilling rig. Current planning is that two interventions per well will be required over the life of the field.

Four additional wells may be drilled for Phase 2 and the facilities will be operated in the same manner as described above. The requirement may arise for future compression to maintain production as reservoir pressure declines, in which case the compressors will be located in the onshore gas conditioning plant, downstream of the slug catcher. The wells will be controlled by an umbilical and infield umbilicals providing power and methanol.

The hydraulic fluid is provided when needed on a once through basis, i.e. it is discharged to sea. The selected fluid is water based and environmentally friendly, low toxicity (typically 96hour LC50 = >1020mg/l) and is approved for use in the North Sea and in other locations where stringent

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requirements apply. The estimated hydraulic fluid discharge is 21 m3/year in relatively small volumes per individual operation.

Safety precautions to minimise the possibility of an offshore accident require that a 500 m radius exclusion zone should be enforced around the subsea wells and manifold and 250 m each side of subsea flowlines and pipelines.

2.11.3 Pipeline

In the operational phase there will be no discharges from the pipeline and piggyback MEG pipeline. All production fluids that enter the pipeline will arrive at the shore. Only in the event of a leak or a rupture would fluids be released. Of greatest concern is an impact by a fishing trawl board or anchor. There will however be an exclusion zone of 250 m on either side of the pipeline along its entire route. Emergency shut down (ESD) valves will be provided to stop production immediately should a leak be detected.

A corrosion analysis of the pipeline has been carried out, assuming the highest reported carbon dioxide levels in the gas (0.17%) and taking account of the temperatures in the various sections of the system. The study takes account of the injection of MEG and corrosion inhibition and assumes a maximum corrosion inhibitor availability of 95%. Based on these considerations, appropriate corrosion allowances have been added to the flowlines and pipeline design to ensure a design life of 22 years. In addition, there will be corrosion monitoring of the flowlines and pipeline to check that the calculations are correct and to ensure that any additional measures are implemented if required.

2.11.4 Onshore Gas Conditioning Plant

The onshore gas processing plant is depicted in Figure 2.9. The production fluids from the pipeline enter the slug catcher which is a vessel able to store large quantities of liquid and separate it from the gas. When the gas flow rate in a multi phase pipeline, i.e. one carrying gas, condensate and water, is increased there is a temporary but sometimes, significant increase in liquid received onshore due to the higher pipeline velocity pushing it from low points in the pipeline where it has accumulated. This liquid arrives as a “slug” hence the term “slug catcher”.

The gas and liquid are bulk separated in the slug catcher. From the slug catcher, the gas is cooled, then passed through a Joule-Thompson valve (J-T Valve) to a high efficiency gas/liquid separator. The Joule Thompson effect is a natural phenomenon in which high pressure gas, when depressurized, cools rapidly and separates out liquids, in this case, condensate and water. Part of this occurs across the wellheads choke valve and the rest is done under controlled conditions, to dehydrate the gas to the required specification for the power plant. This separator removes the remaining free liquid from the gas.

The gas is then used to pre-cool the incoming gas to the J-T valve, further superheated to provide a temperature margin above the dew point and then filtered in a filter/coalescer, to ensure that liquids cannot be introduced into the power generator turbines. The dry gas is then metered and sent through a buried pipeline to the power station.

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Power station demand is essentially controlled by means of gas pressure; as the gas turbines speed up they demand more gas causing the pressure to fall, the plant inlet control valve then opens to compensate, hence maintaining an even flow of gas to the turbines. On reduction of the flow demand, the gas backs up in the subsea pipeline (line pack). If the pipeline pressure continues to increase, a decision will then be made to reduce production, or temporarily close the wells. Shutting-in the wells is to be avoided to prevent possible adverse effects on the reservoir.

The liquids in the slug catcher are drained, heated and gravity separated in two steps into a water/MEG mixture and condensate. The condensate phase is depressured and heated thereby releasing dissolved gas which is removed in a separator vessel. The gas is then used in the gas conditioning plant fuel gas system. The resulting stabilized condensate is cooled, metered and then stored in one of two bunded atmospheric tanks. The volume of condensate to be stored will be in the order of 5,000 barrels. The condensate will be removed periodically by road tankers.

The MEG/water mixture is first passed to a MEG Degasser, where the bulk of any dissolved gases are removed at a pressure sufficient to allow them to be used in the gas conditioning plant fuel gas system. Any remaining liquid hydrocarbons are also gravity separated and sent to the condensate stabilisation system. The remaining MEG/water is then sent to the MEG regeneration package. The MEG/water is dropped to close to atmospheric pressure to allow any further gas to be released to the atmospheric vent – these are negligible amounts. It is then heated in the fired reboiler to regenerate the lean MEG by boiling off the excess water, which is turned to steam that is disposed of in the fired heater stack. The lean MEG is cooled and sent to atmospheric bunded storage tanks for re-use. The total hydrocarbons in the water vapour released to atmosphere will be approximately 0.3 ppm, of which 99% will be methane. Any traces of aromatic components such as benzene, toluene and xylene are too small to be detectable. Some MEG will also be lost, and this is expected to be less than 650 ppm, but will need to be confirmed by the MEG regeneration package supplier during detailed design.

Power will be drawn from the local electricity grid. There will be two plant flares to handle safely any emergency depressurizations that may occur and to facilitate plant or pipeline gas pressure blowdown. A small flare will handle any small releases of gas that might occur. In the event of a large emergency depressurization, a valve in the flare line will open automatically to allow gas to flow to the large flare. In the event of a failure of the valve to respond, a bursting disc located in a line around the relief valve, will fail (burst) at a predetermined pressure to ensure safety is not compromised.

Pipeline depressurization is not anticipated during the lifetime of the field; it is only likely in the event of a pipeline failure.

Blowdown of sections of the gas conditioning plant may be necessary for periodic inspections of the high pressure vessels. Inspections are required on a 3-5 year cycle. Blowdown of one conditioning unit should take little more than 15 minutes. The slugcatcher is designed with two parallel isolatable halves. Even at the maximum operating pressure of 120 bar, blowdown is likely to take only 15 to 30 minutes. Normal slugcatcher operating pressures will however be between 15 bar and 69 bar depending on the required power station supply pressure and time

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throughout field life. Emergency relief of the plant and/or pipeline may also be required for safety reasons when, for example, pressure builds up as a result of equipment failure. A pressure sensor, normally set 10% below the operating pressure of the emergency relief valves, will activate the emergency shut down system and also alert the operator. Depending on the type of problem, the Emergency Shut Down System (ESD) system will close, in order of escalation:

• The equipment concerned • The system in which it operates • The process section of which it is a part • The onshore plant • The wells/field

If the pressure build up continues, perhaps as a result of a failure of a component in the ESD system, the emergency relief valves will open automatically and release gas to the flare.

In the event of a fire, fire detectors will alert the ESD system. If a single detector is activated, an alarm will alert the operator. If two detectors are activated, the ESD system will carry out a shut down as described above and, in addition, will:

• Depressure the equipment concerned to the flare • Activate the automatic deluge (fire fighting) system

The heat radiation and noise levels generated by the flare have been calculated. For an emergency relief situation, full flow of the plant would occur over some two minutes. In the event of fire relief, the system is designed to reduce the pressure of the equipment to 50% of design, or 7bar (105psi), whichever is the lower, in 15 minutes.

A fence will be installed around the flare to ensure that personnel cannot enter. The distance of the fence from the flare, 225 m, is based on not exceeding a maximum noise level of 85dB(A) at the fence. The maximum expected heat intensity at the fence is 0.1kW/m2, resulting in an insignificant temperature increase. This is significantly below the level of 1.58kW/m2 which is reckoned to be safe for an exposure of up to 12 hours.

Electrical power is supplied by one of two 11kV feeders from the grid. In the event of a failure of one feeder, the other will take over automatically. In the event of a total failure of the power supply an emergency diesel powered generator will start up automatically and provide sufficient power to shut down the plant and/or field safely. An Uninterruptible Power Supply (UPS) system, based on a battery back up, also provides power for essential equipment.

The instrument air system has receiver vessels that will store sufficient air to shut down the plant safely in the event of a failure of the instrument air compressors. Hydraulic ESD valves have accumulators that will allow three operations without the normal hydraulic fluid supply.

Occasionally disposal of small quantities of water will be necessary, including rainwater run-off. The onshore plant is divided into oily areas and non oily areas and separate collection drains are provided in each. Liquids from the oily areas will be treated by two-stage gravity separation to

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remove any hydrocarbons to below 10mg/l free oil, then mixed with water from uncontaminated areas. In normal operation, this treated water will be disposed of into the MEG/water system. However, it is intended that a connection will also be provided to allow water disposal into the power station cooling water discharge pipeline in the event that an occurrence such as a heavy storm overloaded the normal disposal system. The maximum designed disposal rate into the cooling water discharge pipeline would be 5m3/h.

The environmental emissions from the Phase 1 facilities are presented in Table 2.4.

2.11.5 Non-routine operations

Although few non-routine operations are envisaged, those that do arise will be as a consequence of unplanned shutdowns or maintenance of the wells or facilities. Unplanned shutdowns will require rapid response to restore the gas supply and the mobilisation of additional personnel.

No well testing is planned. Each well will be equipped with a flow meter which can be calibrated by a tracer technique. The following non-routine well entry operations may be necessary during the life of the field: Simple wireline trip retrievable Sub Surface Safety Valve (SSSV) replacement, caliper logging to detect any internal corrosion Wireline BHP (Bottom Hole Pressure) measurement CHRFT ( Cased Hole Repeat Formation Tester) evaluation Additional perforations Tubing replacement Sand control (plug back and drill to new subsurface location, gravel pack and complete ) Subsea tree replacement ROV (remote operated vehicle) override of subsea valves ROV replacement of failed subsea instrumentation, control modules, or choke valves. Intelligent pigging of the pipeline to monitor wall thickness along its length.

Some non-routine operations would require the mobilisation of a semi-submersible drilling unit.

Hydrate blockage in either the flowlines or pipeline can be remedied by injection of methanol. In rare cases where this does not remove the plug, depressurization of the pipeline might be required, but that is not expected to occur during the life of the field.

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2.12 DECOMMISSIONING

All abandonment of facilities will be carried out in an environmentally responsible way and in accordance with Namibian, Energy Africa and international environmental statutes. A full facility abandonment philosophy will be prepared through project specification and execution, and the initial draft will be submitted formally to the relevant ministries six months before project approval. The general approach will be:

Well abandonment: the wells will have their trees removed, the casing stubs will be cut to below the sea bed and the well cemented. The removed wellheads and trees will be taken to shore for disposal. Abandonment of submarine flowlines: the flowlines will be cleared of hydrocarbons, cleaned, flooded and abandoned in situ. Abandonment/removal of submarine manifold: the manifold will be retrieved and taken to shore for disposal. Abandonment of submarine pipeline: the pipeline will be cleared of hydrocarbons cleaned, flooded and abandoned in situ. Abandonment of subsea umbilicals: the subsea umbilicals will be cleared of hydraulic fluids, cleaned, flooded and abandoned in situ. Abandonment/removal of onshore pipeline: The buried pipe will be cleared of hydrocarbons, cleaned and abandoned in situ. Any above ground portions will be removed and scrapped. Abandonment/removal of onshore umbilical: This umbilical will be cleared of hydrocarbons cleaned and abandoned in situ. Any above ground portions will be removed and scrapped. Closure/removal of gas conditioning plant: The gas plant will be decommissioned and dismantled, effectively leaving a green field site after removal.

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Table 2.3: Phase 1 Emissions Summary from the Uubvlei gas conditioning plant

SLUG MEG CONDENSATE MEG SOURCE CATCHER REGENERATION STORAGE OVERHEAD INLET GAS DEGASSER VENT VENT

Location on Figure 2.9 1 2 3 4 Phase Vapour Vapour Vapour Vapour Release Units Emergency Normal Normal Normal Flaring only Operating Operating Operating Release Release Release during tank fill

Vapour Fraction 1 1 1 1 Temperature degC -30 10 30 106 Pressure kPa 150 100 100 100 Molar Flow kgmol/hr 7,330 0 0.1 336 Mass Flow kg/hr 118,200 0 3 6,120 Liquid Volume Flow m3/hr 0 0 0 0 Heat Flow kJ/hr -543,960,000 0 -6,140 -8,035,200 Molar Enthalpy kJ/kgmol -77,130 -76,030 -107,400 -238,900 Component mol% CO2 0.010 0.126 0.023 0.001 Nitrogen 0.561 0.877 0.035 0.000 Methane 96.384 97.214 40.358 0.000 Ethane 2.213 1.379 10.350 0.000 Propane 0.380 0.011 6.708 0.000 i-Butane 0.099 0.000 3.512 0.000 n-Butane 0.118 0.000 5.296 0.000 i-Pentane 0.047 0.000 3.104 0.000 n-Pentane 0.037 0.000 2.768 0.000 Hexane 0.062 0.000 6.945 0.000 m-Cyclopentane 0.007 0.000 0.809 0.000 Benzene 0.020 0.000 2.624 0.000 Cyclohexane 0.019 0.000 2.400 0.000 n-Heptane 0.009 0.000 1.816 0.000 m-Cyclohexane 0.007 0.000 1.225 0.000 Toluene 0.006 0.000 1.208 0.000 n-Octane 0.003 0.000 1.016 0.000 m-Xylene 0.000 0.000 0.264 0.000 n-Nonane 0.001 0.000 0.455 0.000 n-Decane 0.000 0.000 0.128 0.000 C11 0.000 0.000 0.037 0.000 Water 0.017 0.393 8.867 99.612 MEG 0.000 0.000 0.052 0.387 Total 100.000 100.000 100.000 100.000

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Part A, Section 3: Description of the Environment

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Part A, Section 3: Description of the Environment

3. DESCRIPTION OF THE ENVIRONMENT______3-1

3.1 MARINE ENVIRONMENT ______3-1 3.1.1 Meteorology ______3-1 3.1.1.1 Offshore wind and atmospheric conditions ______3-1 3.1.1.2 Nearshore wind and atmospheric conditions______3-1 3.1.1.3 Fog______3-6 3.1.2 Physical and Biological Oceanography______3-6 3.1.2.1 Waves ______3-6 3.1.2.2 Tides ______3-10 3.1.2.3 Topography and Sediments ______3-10 3.1.2.4 Water masses and temperature/salinity relationships ______3-12 3.1.2.5 Water circulation ______3-13 3.1.2.6 Upwelling ______3-13 3.1.2.7 Nutrient and Oxygen Distributions ______3-13 3.1.2.8 Plankton ______3-17 3.1.2.9 Benthos ______3-19 3.1.2.10 Fishes ______3-19 3.1.2.11 Birds ______3-21 3.1.2.12 Cetaceans ______3-27 3.1.2.13 Seals______3-31 3.1.3 Commercial Fisheries ______3-32 3.1.3.1 The distribution and abundance of Hake off southern Namibia ______3-35 3.1.3.2 Monkfish ______3-41 3.1.3.3 The Namibian Tuna Fishery ______3-41 3.1.3.4 Pelagic species (clupeoids and mackerels) ______3-42 3.1.3.5 Fishing Activities______3-44 3.1.4 Conservation Areas______3-54 3.1.5 Shipping and Navigation ______3-54 3.2 REFERENCES ______3-57

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Figures

Figure 3.1: Location of the Kudu gas field on the Namibian continental shelf. ______3-2 Figure 3.2: Seasonal wind roses for the offshore area 28°-29°S; 14°-15°E (contains Licence Area 2814A). Voluntary Observing Ship (VOS) data from the Southern Africa Data Centre for Oceanography (SADCO). ______3-3 Figure 3.3: Seasonal wind roses for the offshore area 28°-29°S; 15°-16°E (Oranjemund). Voluntary Observing Ship (VOS) data from the Southern Africa Data Centre for Oceanography (SADCO).______3-4 Figure 3.4: Seasonal wind roses for the offshore area 26°-27°S; 14°-16°E (Lüderitz). Voluntary Observing Ship (VOS) data from the Southern Africa Data Centre for Oceanography (SADCO).______3-5 Figure 3.5: Katabatic winds along the west coast of southern Africa carrying aerosol plumes of sand up to 150 km offshore (from Shannon and Anderson, 1982). ______3-7 Figure 3.6: Lüderitz and Port Nolloth: Percentage Frequency and speeds of coastal winds in winter and summer (after Hart and Currie, 1960). ______3-8 Figure 3.7: 1984 Fog day frequency using Meteosat Images (after Olivier, 1992 and 1995). Note: Contours indicate iso-lines (days) of fog occurrence. ______3-9 Figure 3.8: Seasonal wave roses for the Kudu gas field (28°-37.6°S; 14°-35.0°E recorded during the period 8 March 1998 and 13 April 1999) (Source: Shell Exploration and Production Namibia B.V.)______3-11 Figure 3.9: Sediment distribution off the west coast of southern Africa (from Rogers, 1977). Depths in metres. ______3-12 Figure 3.10: Surface currents off the west coast of southern Africa (from Shannon, 1985). ______3-14 Figure 3.11: Probable movement of central water between 100 m and 300 m off the west coast of southern Africa (from Shannon, 1985). ______3-15 Figure 3.12: Upwelling centres on the west coast of southern Africa with schematic of currents (from Shannon, 1985). ______3-16 Figure 3.13: Surface nutrient distributions during upwelling conditions near the Lüderitz upwelling centre, August 1976: all figures in µM (from Chapman and Shannon, 1985).______3-18 Figure 3.14: The location and timing of whaling operations off the southern African west coast A - Modern whaling, B – boat whaling (after Best and Ross, 1986) ______3-29 Figure 3.15: Colonies of the Southern African (Cape) Fur Seal (From David, 1987). ______3-32 Figure 3.16: The main spawning areas of commercially important fish along the Namibian coast. ______3-33 Figure 3.17A: Areas of main commercial fishing activity and dolphin occurrence along the Namibian coast. ______3-34 Figure 3.17B: Principal fishing areas south of Lüderitz______3-34 Figure 3.18: Recruitment areas of Cape hake Merluccius capensis (a) and deep water hake Merluccius paradoxus (b) along the Namibian continental shelf (after Alheit and Pitcher, 1995). Darker areas denote higher concentrations. ______3-37

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Figure 3.19A: Distribution and abundance of Cape hake (tonnes per square nautical mile) off the southern coast of Namibia during May 1994. (Anon, 1994). ______3-38 Figure 3.19B: Distribution and abundance of deepwater hake (tonnes per square nautical mile) off the southern coast of Namibia during May 1994. (Anon, 1994). ______3-39 Figure 3.20: Monthly catches of albacore made by the pole and line fishery in 1994 off the Namibian coast (after Lehmensiek, 1995). ______3-43 Figure 3.21: Catches of albacore made by the pole and line fishery at Tripp Seamount between 1985 and 1994 off the Namibian coast ______3-43 Figure 3.22: Mackerel catch positions, 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-46 Figure 3.23: Mackerel catch positions, 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-46 Figure 3.24: Depth distribution of mackerel catches, 2000 and 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-47 Figure 3.25: Mackerel catches vs time of day, 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)______3-47 Figure 3.26: Depth distribution of mackerel catches, 2000 and 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-48 Figure 3.27: Monthly distribution of hake trawling, 1999 and 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)______3-50 Figure 3.28: Depth distribution of hake trawling, 1999 and 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)______3-50 Figure 3.29: Positions of hake long-line catches, 1998 – 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)______3-52 Figure 3.30: Monthly distribution of hake long-lining in study area, 1998 – 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-52 Figure 3.31: Depth distribution of hake long-lining in study area, 1998 - 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-53 Figure 3.32: Setting and retrieving times for hake long lines in study area, 1998 – 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund) ______3-53 Figure 3.33: Shipping routes off the west coast of southern Africa. ______3-56

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Tables

Table 3.1: The seabirds of southern Namibia______3-22 Table 3.2: Southern African seabirds breeding in the region under consideration______3-25 Table 3.3: Estimates of the breeding populations of coastal seabirds in study area (based on Crawford et al., 1991) ______3-26 Table 3.4: The distribution and seasonal abundance of mysticetes (baleen whales) in southern Namibian waters. ______3-29 Table 3.5: The distribution and seasonal abundance of odontocetes (toothed whales and dolphins) in southern Namibian waters. ______3-30 Table 3.6: Summary of hake trawling operations in study area in 1999 and 2000 (extracted from MFMR catch records) ______3-49 Table 3.7: Summary of hake long-line operations in study area from 1998 to 2001 (extracted from MFMR catch records) ______3-51

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3. DESCRIPTION OF THE ENVIRONMENT

The baseline environmental study (CSIR, 1993) and the description of the environment contained in this chapter encompass the Namibian coastline immediately adjacent to the Kudu gas field in Licence Area 2814A and provides information on the coast between Lüderitz, Namibia and Port Nolloth, South Africa (Figure 3.1). This larger region has been identified as being potentially affected by the proposed Kudu gas field development activities e.g. pipeline and supply vessel routes.

3.1 MARINE ENVIRONMENT

The following sections summarise the nature of the marine environment through short descriptions of its important constituents and by referring to specific items of importance where considered relevant.

3.1.1 Meteorology

3.1.1.1 Offshore wind and atmospheric conditions

The meteorological conditions along the Namibian coast are controlled by the ever-present South Atlantic anticyclone, the northward-flowing Benguela Current (with associated upwelling) and the divergence of the south-east trade winds along the coast. The semi-permanent temperature inversion caused by the warm, dry air mass overlapping the cool air mass above the ocean is ideal for the formation of fog and low stratus cloud.

Wind conditions characteristic of Licence Area 2814A (Figure 3.2) were inferred from data from voluntary observing ships (VOS) collected in the immediate vicinity over a 32 year period. These data are presented in the form of seasonal wind roses and an annual average wind rose. These predominant winds are from the south and south east quadrant and generally are stronger in spring and summer than in autumn and winter.

3.1.1.2 Nearshore wind and atmospheric conditions

The wind regime closer to the coast i.e. in degree-square 2815 is similar to that in the area of the Kudu gas field in degree-square 2814 (Figure 3.3). The main difference is a small north-westerly component in autumn-winter-spring reflecting the influence of low pressure systems passing to the south. Latitude 28° is considered to be the northern limit of the influence of these low pressure systems (Emery et al, 1973).

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Figure 3.1: Location of the Kudu gas field on the Namibian continental shelf.

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Figure 3.2: Seasonal wind roses for the offshore area 28°-29°S; 14°-15°E (contains Licence Area 2814A). Voluntary Observing Ship (VOS) data from the Southern Africa Data Centre for Oceanography (SADCO).

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Figure 3.3: Seasonal wind roses for the offshore area 28°-29°S; 15°-16°E (Oranjemund). Voluntary Observing Ship (VOS) data from the Southern Africa Data Centre for Oceanography (SADCO).

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Figure 3.4: Seasonal wind roses for the offshore area 26°-27°S; 14°-16°E (Lüderitz). Voluntary Observing Ship (VOS) data from the Southern Africa Data Centre for Oceanography (SADCO).

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The VOS wind data for Lüderitz (degree square 2614) show a stronger southerly component than for squares 2814 and 2815. There is some seasonality with southerly winds strongly predominating in summer whereas in winter the south-easterly component is almost as frequent as the southerly (Figure 3.4). The VOS data do not reflect the strong easterly to north-easterly katabatic winds that can occur in winter. These events can carry aerosol plumes of sand and dust up to 150 km offshore. Shannon and Anderson (1982) present a striking NIMBUS-7 satellite image of such dust plumes between Lüderitz and Port Nolloth (Figure 3.5).

On the coast itself wind patterns reflect the diurnal and thermal response of the land. During the summer southerly winds predominate with an easterly component in the mornings. The winds intensify and veer to the south and southwest in the afternoons, averaging 11-13 m/sec (22-27 knots) at Lüderitz and approximately 10 m/sec (20 knots) at Port Nolloth (Figure 3.6). In winter, wind conditions are more variable with an increased morning easterly component.

3.1.1.3 Fog

Fog is the most distinctive feature of the coastal climate of the Namib. It is usually considered to be a hazard since it reduces visibility and may contribute to weathering and mineral breakdown. On the other hand, it is a significant source of moisture for desert animals and plants. The semi- permanent temperature inversion caused by the warm, dry air mass overlying the cool mass above the ocean is ideal for the formation of fog and low stratus cloud. The fog lies close to the coast extending about 20 nautical miles (~35 km) seawards (Olivier, 1992, 1995). Within a 15 - 20 nautical mile zone offshore, fog frequency may be as high or even higher than at coastal stations. This fog is usually quite dense, visibility less than 300 m, and appears as a thick bank hugging the shore.

The coast from Elizabeth Bay northwards (including Lüderitz) and from Chameis Bay south to Port Nolloth experiences an average of 50 fog days per annum. Between Elizabeth and Chameis bays a lower fog frequency occurs, namely 25 fog days per year (Figure 3.7). Fog precipitation often exceeds rainfall and is considerably more reliable. At Swakopmund 130 mm of fog precipitation was measured in 1958 - seven times the mean annual rainfall. In the Central Namib, fog precipitation averages 34 mm/year at the coast.

3.1.2 Physical and Biological Oceanography

3.1.2.1 Waves

Wave conditions offshore of the Namibian coast consist not only of locally generated seas induced by local winds but also of swells of noticeable intensity propagating into the area from distant generating sources. These generating sources are formed by the low pressure systems of the South Atlantic Ocean which, once formed, move from west to east, passing the southern tip of Africa with great regularity.

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Figure 3.5: Katabatic winds along the west coast of southern Africa carrying aerosol plumes of sand up to 150 km offshore (from Shannon and Anderson, 1982).

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Figure 3.6: Lüderitz and Port Nolloth: Percentage Frequency and speeds of coastal winds in winter and summer (after Hart and Currie, 1960).

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Figure 3.7: 1984 Fog day frequency using Meteosat Images (after Olivier, 1992 and 1995). Note: Contours indicate iso-lines (days) of fog occurrence.

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Good quality wave data in the form of 20 minute records at six-hourly intervals, collected from Waverider buoys off the Orange River mouth in a depth of 106 m, for the period November 1981 to May 1988 and off Port Nolloth in a depth of 100 m, since April 1987 to the present are available for detailed information on wave conditions.

Wave data were recorded in the Kudu gas field (28°37.6’S; 14°35.0’E) for a year-long period between 8 March 1998 and 13 April 1999. These data show that the south-south westerly swell direction is predominant throughout the year except in summer when the direction is more southerly (Figure 3.8).

Significant wave heights range, for most of the time, between 1.5 and 3.5 m with an annual mean of about 2 m to 2.5 m. Local sea conditions can be associated with wave period of 5s and 8s and swell with wave periods of 11s and 16s. Seasonal differences in wave conditions are small.

3.1.2.2 Tides

Tides in the area are semi-diurnal and statistics listed below for Lüderitz apply. Lowest Astronomical Tide -0,20 m Highest Astronomical Tide 1,76 m Mean Low Water Springs 0,06 m Mean High Water Springs 1,41 m Mean Low Water Neaps 0,44 m Mean High Water Neaps 1,03 m Mean level 0,74 m

All levels quoted are relative to Chart Datum which is -0,865 m.

3.1.2.3 Topography and Sediments

Licence Area 2814A is located on the seaward portion of the 180 km wide Orange Shelf and incorporates the shelf break and slope. Water depths range from <200 m to ~1500 m. The location of the Licence Area in relation to bathymetry and sediment texture is shown in Figure 3.9.

Rogers and Bremner (1991) state that the Orange Banks developed during the high sedimentation rates of the Mesozoic. The sediments lying adjacent to the coast are terrigenous whereas those occurring in the region of the quadrant are biogenic in origin (Rogers and Bremner, 1991). Calcium carbonate content of these latter sediments are greater than 76% with organic carbon concentrations between 5 and 10% (Shannon, 1985).

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Figure 3.8: Seasonal wave roses for the Kudu gas field (28°-37.6°S; 14°-35.0°E recorded during the period 8 March 1998 and 13 April 1999) (Source: Shell Exploration and Production Namibia B.V.)

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3.1.2.4 Water masses and temperature/salinity relationships

Shannon (1985) has summarised the characteristics of the water masses that occur in the Benguela current system. The water masses occurring in, and inshore of, the quadrant will be predominantly South Atlantic Central Water (SACW) with temperatures of origin between 6°and 16°C and salinities in the range of 34,5-35,5 ‰. The temperature characteristics at the surface can be modified by sun-warming of previously upwelled, or upwelled and mixed, SACW. Shannon (1985) indicates that the SACW found in the region of the quadrant enters the area from the south and south-west. There may be some Indian Ocean Central Water mixed in this water but its contribution is probably small. Further to this Visser (1969), quoted in Bailey et al (1985), by comparing oxygen concentrations, indicates that there is also some contribution of southward flowing SACW in the Lüderitz region. Thus although all apparently uniform in T/S characteristics there are some complicated mixing processes occurring in the region of the Licence Area 2814A. At the surface in the western sectors of the degree square 2814 subtropical surface water (temperatures 15° - 23°C and salinities 35,3-36,0‰) will overlie the SACW (Shannon, 1985).

There is a seasonal variation in surface temperature, with the average summer and autumn temperatures being ~2°C higher than in winter and spring. In the short term this is modified by upwelling (see below) and in the longer term by El Niño events (Boyd and Agenbag, 1985; Shannon, 1985).

Figure 3.9: Sediment distribution off the west coast of southern Africa (from Rogers, 1977). Depths in metres.

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3.1.2.5 Water circulation

A schematic of the surface currents in the Benguela system is shown in Figure 3.10. The currents in the vicinity of Licence Area 2814A tend predominantly NW with a mean speed of 17 cms-1 (Shannon, 1985). There is some evidence of ‘topographic’ steering (Nelson and Hutchings, 1983) in that the currents follow the shelf break and velocities vary with the gradient of the shelf slope.

Figure 3.11 depicts the probable movement of water in the 200-300 m depth range. As pointed out in the section on water masses there is an indication of southward flow penetrating to the latitude of Lüderitz. Andrews and Hutchings (1980) present evidence of this southward flow reaching south of Cape Columbine.

3.1.2.6 Upwelling

Licence Area 2814A lies between the Lüderitz and Namaqua upwelling cells, the former of which is the principal upwelling centre of the Benguela (Shannon, 1985 and authors cited therein). Upwelling at this site is semi-permanent, there is sometimes a short quiescent period in autumn, and the upwelling cell acts as a major physical and biological barrier in the Benguela system.

During the upwelling process, driven by southerly winds, 13°C and <35‰ salinity water is uplifted and may breach the surface at the coast. In vigorous upwelling events tongues of cold water extend offshore to the NW with the upwelling effect detectable at the surface up to 30-50 nautical miles offshore (Shannon 1985, Figure 3.12 from Bang 1971). Stander (1964) presented data that showed that the upwelling effect was detectable to 400 m depth in the form of distortions to temperature and salinity distributions.

During the decay phase of upwelling the newly upwelled water mixes with older, sun warmed and previously mixed upwelled water. The mixing events add nutrients to these waters and through stabilisation, support the very high biological productivity typical of the Benguela system.

3.1.2.7 Nutrient and Oxygen Distributions

As described above SACW comprises the bulk of the water in the study area either in its ‘pure’ form or mixed with previously upwelled water of the same origin. According to Jones (1971), cited in Chapman and Shannon (1985), ‘true’ SACW nutrient concentrations range from 10-18 ųM nitrate-nitrogen, 0,8-1,5 ųM phosphate and 6-15 ųM silicate.

Figure 3.13 shows surface nutrient concentrations measured during an upwelling event in the Lüderitz upwelling cell. It can be seen that, adjacent to the coast, the nutrient concentrations are considerably higher than specified by Jones (1971). Chapman and Shannon (1985) present data indicating that these higher values can be attributed to nutrient enrichment during transport of the upwelling water across the continental shelf. This is supported by the fact that water upwelling at offshore sites (i.e. away from the continental margin) has characteristically lower nutrient concentrations (Table IV, Chapman and Shannon, 1985).

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Namibe

Figure 3.10: Surface currents off the west coast of southern Africa (from Shannon, 1985).

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Namibe

Figure 3.11: Probable movement of central water between 100 m and 300 m off the west coast of southern Africa (from Shannon, 1985).

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Figure 3.12: Upwelling centres on the west coast of southern Africa with schematic of currents (from Shannon, 1985).

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During the relaxation phase of upwelling surface nutrient concentrations decline to < 10 ųM NO3 -

N and < 5 ųM SiO3. Phosphate concentrations appear to remain in the 1-2 FM range (Bailey, 1979 quoted in Chapman and Shannon, 1985). During the mixing process concentrations are modified. Further variation is added by nutrient take-up by phytoplankton. Thus, although generally high, nutrient concentrations and distributions are extremely variable.

In the area of the quadrant 2814 further modifications to nutrient distributions are caused by variations in the position of the oceanic front and the occurrence of filaments of upwelled water (e.g. Lutjeharms and Stockton, 1987). Thus nutrient concentrations range from low (oceanic water) to moderate to high.

The continental shelf waters of the Benguela system are characterised by low oxygen concentrations. SACW itself has depressed oxygen concentrations, ~80% saturation value, (Chapman and Shannon, 1985), but lower oxygen concentrations (<40% saturation) occur frequently (e.g. Visser, 1969, Bailey et al, 1985). The low oxygen concentrations are attributed to nutrient remineralisation in the bottom waters of the system.

Bailey et al (1985) showed that oxygen concentrations in the vicinity of Lüderitz were lower (1,0-2,0 ml l-1) during quiescent conditions than during active upwelling (> 2,0 ml l-1). These authors further showed that extremely low oxygen concentrations (<0,5 ml l-1) occurred in water overlying organically rich sediments north of Lüderitz. The low oxygen concentrations impact upon both pelagic and benthic organisms, the rock lobster Jasus lalandii specifically being restricted in depth distribution because of the low oxygen water (Bailey et al, 1985).

3.1.2.8 Plankton

Mean surface chlorophyll (/ phytoplankton biomass) concentrations in Licence Area 2814A range from 0,22-2,60 ‰g l-1 whilst those in the immediate surrounding areas peak at 3,13 ‰g l-1 (Brown et al, 1991). These are generally lower than values recorded further south in the Namaqua upwelling cell area and immediately north of Lüderitz (Brown et al, 1991). Primary production, estimated by regression, is 105-117 mg C m-2 hr-1 (Brown et al, 1991). The population doubling time (= turnover rate) is estimated at 12 days which is considerably lower than for the southern Benguela (Brown et al, 1991).

Estimates of zooplankton biomass for the Benguela system north of St. Helena Bay are sparse. Hutchings et al, (1991), however, report mesozooplankton standing stocks between 0,1 and 1,0 g Cm-2 for the northern Benguela system (incorporating Licence Area 2814A). Further, the estimated biomass of macrozooplankton (primarily euphausiids) is 0,6 g Cm-2.

Significant development of both phytoplankton and zooplankton require sufficient nutrients and water column stability. The area between the Namaqua and Lüderitz upwelling cells is usually cold and only weakly stratified, the latter leading to deep mixing in association with the strong winds that occur in the region. Thus high plankton biomasses are probably irregular occurrences in the region.

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North Rocks North Rocks North Rocks

Marshall Rocks Marshall Rocks Marshall Rocks

Lüderitz Lüderitz Lüderitz

(a) Phosphate (b) Nitrate (c) Silicate

Figure 3.13: Surface nutrient distributions during upwelling conditions near the Lüderitz upwelling centre, August 1976: all figures in µM (from Chapman and Shannon, 1985).

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3.1.2.9 Benthos

The initial study of the benthos on the continental shelf of southern Namibia was undertaken by Field et al. (1996). The study was carried out as part of the environmental impact assessment of Debmarine’s deep sea diamond mining operations in the Atlantic 1 Mining Licence Area. Comparisons of the benthic fauna of the unmined and mined areas were made. Subsequently a survey of the benthic fauna of the Kudu gas field in Licence Area 2814A was undertaken by ERM (2002) in which 104 species were identified.

The Namibian continental shelf is subject to periods when the water is hypoxic. The Namibian benthos may constitute, therefore, a distinct community able to survive oxygen-deficient conditions. Field et al. (1996) determined that the main phyla contributing to the benthic fauna are: Annelida e.g. Diopatra spp. and Terebellides spp.; Mollusca e.g. the gastropods Nassarius spp. and the bivalves Macoma spp; and Crustacea e.g. Hippomedon longimanus and Ampelisca spp. Notable is the paucity of echinoderms.

The ERM (2002) study identified four significantly different macrofaunal communities within the sampling area. Community No. 1 was dominated by the crab Ebalia tuberculosa, and Community No. 2 was characterised by the presence of the bivalve Macoma crawfordi ordinaria, the mussel Perna perna and the polychaete Onuphis geophiliformis. Both Communities No. 3 and No. 4 were dominated by the brittle star Amphiura capensis but the degree of dominance in Community No. 3 was much lower than in Community No. 4.

Deep sea marine diamond mining completely disrupts the sediment profile, the soft surface sediments and gravels are removed from above the bedrock, passed through the processing plant where the diamonds are extracted, and returned to the seafloor by discharge overboard. The sediment structure is thus completely changed with much of the fine material drifting a considerable distance (kilometres) before settling to the bottom. This altered sediment profile supports a modified fauna in which the gastropod Nassarius and the bivalve Macoma are much more common than in the unmined areas. In the case of drilling for petroleum the sediment profile remains intact (except in the immediate vicinity of the point of entry into the seafloor) and the impact on the benthic fauna would depend on the rate at which drilling muds and cuttings are discharged and the thickness of the deposited material. No studies of the response of benthic organisms to such discharges have been conducted in southern African waters, but impacts are expected to be negligible and limited to a radius of 200m around the point of discharge (Shell E&P Norway and DNV, 2001).

3.1.2.10 Fishes

The fish fauna of the Namibian coast is characterised by a relatively low diversity of species compared with warmer oceans: 76 fish species are known from or likely to be found in the area under consideration – an equivalent area on the east coast of Africa would probably be inhabited by over 800 species (Bruton, 1996).

The Namibian ichthyofauna is also characterised by high numbers of certain fish species which are of commercial importance, especially shallow-water and deepwater hake Merluccius

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capensis and M. paradoxus, Cape gurnard Chelidonichthys capensis, monkfish Lophius vomerinus, elephant fish Callorhinchus capensis, snoek Thyrsites atun, jacopever Helicolenus dactylopterus, maasbanker Trachurus trachurus, buttersnoek Lepidopus caudatus and kingklip Genypterus capensis. Three of these ten species (snoek, maasbanker and buttersnoek) are pelagic species as adults, but they do sometimes feed on benthic prey. The other species are benthic.

The vulnerability of a fish species to anthropogenic disturbance (fishing, mining, pollution or other impacts) is subject to three main factors: fish abundance, fish distribution and the particular life- history characteristics of the fish species affected.

The ichthyofauna of highly variable upwelling zones, such as the Benguela Upwelling System of the west coast of southern Africa, tends to have the following suite of characters: low species diversity, low species interdependence, rare species are uncommon, migratory species are common, sedentary species are uncommon, low speciation rates, low extinction rates, low species saturation, wide trophic niches, high fecundity, typically generalist life styles, high adaptability, and subject primarily to density-independent mortality (Bruton, 1989).

The fish occurring in Namdeb’s Atlantic 1 Diamond Mining Licence Area generally belong to groups with the above characteristics, although clearly there will be some exceptions. The situation with respect to the Kudu gas field area is expected to differ little, if at all, from that prevailing in Atlantic 1. Two of the fish species, Austroglossus microlepis and Sufflogobius bibarbatus, have relatively narrow distributions, being endemic to Namibia and the west coast of South Africa. None of the species on the list are known to be rare or endangered (none appear in the 1994 IUCN Red List of Threatened Animals, Groombridge, 1993), whereas some of those listed are very widespread and abundant. For instance, the jacopever is ubiquitous at depths of 55 – 550 m from Walvis Bay to Delagoa Bay (Smith and Heemstra, 1988).

Characteristically upwelling zones are inhabited by fishes which are typically altricial producing large numbers of small eggs which hatch into small, incompletely developed young that are mainly subject to density-independent mortality (Bruton, 1989). These fishes play a ‘low risk, high number’ game in that the parental investment in each individual young is low, but the risk of mortality is spread among a large number of offspring. Each individual young therefore has a low fitness compared with the young of fishes from a more stable environment that play a ‘high risk, low number’ game (Bruton, 1989). These more altricial species may, however, be vulnerable to long-term impacts on the survival rates of their eggs and larvae.

Some of the fishes that occur off Namibia are not altricial forms, such as the live bearing dogfish (Squalus species) and the mouth brooding white seacatfish Galeichthys feliceps, but the general trend of higher levels of altriciality in an upwelling zone does appear to hold. Altricial fishes are better able to adapt to random and even catastrophic mortalities; petroleum exploration and production and patchwork mining activities in a small part of their range are not likely to have a lasting detrimental impact. An exception is when the most vulnerable stages of the life cycle – the eggs, larvae and postlarvae are affected by a pervasive environment perturbation, such as the deoxygenation of the water column in the vicinity of the thermocline, where they typically accumulate. The possible impact of the offshore mining is likely to be greatest in the water

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column in places (below the thermocline) where vulnerable life-history stages (eggs, larvae and postlarvae) accumulate. The impact would therefore be on the breeding success of the adult fishes rather than on the adult fishes themselves. A similar potential impact could be expected as a result of the discharge of drilling muds and cuttings. However, unlike mining which is almost continuous, the impact is likely to be negligible because of the infrequent and short duration nature of production drillings.

3.1.2.11 Birds

Pelagic seabirds A total of 50 species of seabirds has been recorded in the waters of southern Namibia (Table 2.1). Of these, 13 (26%) are southern African breeding species, 13 (26%) are non-breeding migrants from the northern hemisphere, and 24 (48%) are non-breeding migrants from islands in the Southern Ocean.

Only 22 of these 50 species have been definitely recorded in the Kudu gas field area in Licence Area 2814A (Table 3.1). Other offshore species that have been recorded in southern Namibian waters almost certainly occur in Licence Area 2814: it is notable that most that have not are relatively rare in the region. Because Licence Area 2814 falls on the shelf break, seabird species occurring include those that do not normally venture onto the continental shelf of Africa, such as the Wandering Albatross Diomedea exulans (Ryan and Rose 1989). With its closest point to land being c. 65 km, no strictly inshore seabirds have been recorded. It is notable in this regard that the only southern African breeding species so far recorded in the Kudu gas field area is the Cape Gannet Morus capensis, known to occur farther offshore than the other locally breeding seabirds (African Penguin Spheniscus demersus, cormorants, gulls and terns, Table 3.2).

Of the 50 species, nine (18%) have been given a IUCN (World Conservation Union) category of threat, and five are considered Near Threatened (BirdLife International 2000, Table 3.1). Conservation concern has thus been expressed for nearly one third of the seabird species occurring in southern Namibian waters. Threatened species include both migrants (albatrosses and petrels) and southern African breeding species. Only one species is considered to be Critically Endangered (the Spectacled Petrel Procellaria conspicillata) and none is considered Endangered (Table 3.1). Five threatened species have been recorded from within Licence Area 2814, all Southern Ocean migrants, predominantly albatrosses and petrels.

Crawford et al (1991) reviewed the role of seabirds as consumers in the Benguela and western Agulhas ecosystems. Four regions were recognized: northern Namibia, southern Namibia, western South Africa and southern South Africa. The southern Namibia region corresponds to the area encompassed by the present study. Each region was further divided into inshore (water depth < 200 m) and offshore (water depth 200-500 m). The southern Namibian region covers 41 000 km2 comprising 25 000 km2 inshore waters and 16 000 km2 offshore waters. Populations of pelagic seabirds are highest during the austral winter when Southern Ocean species move north to temperate and subtropical regions. Large numbers of Prions Pachyptila spp. (17 500); Whitechinned Petrel Procellaria aequinoctialis (14 700); Sooty Shearwater Puffinus griseus (14 200) and Storm petrels mainly Oceanites oceanicus and Hydrobates pelagicus (7 000) are present in the southern Namibia region during the winter.

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Relative to the northern Namibia and western South Africa regions the study area is less important for pelagic seabirds. It supports about 68 000 individuals whereas the northern Namibia and the western South Africa regions support 652 000 and 1 332 000 birds respectively. In terms of biomass the difference is even greater since, unlike the northern Namibia and western Cape regions, relatively few albatrosses and large petrels occur in the southern Namibia region (Crawford et al, 1991).

Crawford et al. (1991) estimated that the seabird population of southern Namibia consumed 2 916 tonnes of carbon annually, mostly obtained from cape anchovy Engraulis capensis. Consumption was estimated to be slightly higher in winter, due to the presence of larger numbers of migrant species.

Table 3.1: The seabirds of southern Namibia

RELATIVE CONSERVATION SPECIES STATUS* SEASONALITY ABUNDANCE STATUS (IUCN) African Penguin B, inshore Common All year Vulnerable Spheniscus demersus Black-necked Grebe AM, inshore Locally WINTER, Podiceps nigricollis common summer Wandering Albatross SM, offshore Rare WINTER, Vulnerable Diomedea exulans summer Shy Albatrossa SM, offshore Uncommon All year Vulnerable Thalassarche cauta Black-browed Albatross SM, offshore Common WINTER, T. melanophris summer Grey-headed Albatross SM, offshore Rare Vagrant Vulnerable T. chrysostoma Yellow-nosed SM, offshore Common WINTER, Near threatened Albatrossa summer T. chlororhynchos Northern Giant Petrel SM, Common All year Near threatened Macronectes halli In/offshore Southern Giant Petrel SM, Uncommon All year Vulnerable M. giganteus In/offshore Pintado Petrel SM, offshore Common Winter Daption capense Antarctic Fulmar SM, offshore Rare Winter Fulmarus glacialoides Antarctic Prion SM, offshore Common All year Pachyptila desolata Great-winged Petrel SM, offshore Uncommon All year? Pterodroma macroptera Atlantic Petrel SM, offshore Rare Summer P. incerta Soft-plumaged Petrel SM, offshore Uncommon WINTER, P. mollis summer

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RELATIVE CONSERVATION SPECIES STATUS* SEASONALITY ABUNDANCE STATUS (IUCN) White-chinned Petrel SM, offshore Common WINTER, Vulnerable Procellaria aequinoctialis summer Grey Petrel SM, offshore Rare Winter Near threatened P. cinerea Spectacled Petrel SM, offshore Rare WINTER, Critical P. conspicillata summer Manx Shearwater NM, offshore Rare SUMMER, winter Puffinus puffinus Great Shearwater SM, offshore Uncommon Summer passage P. gravis Sooty Shearwater SM, offshore Common WINTER, P. griseus summer Cory’s Shearwater NM, offshore Common Summer Calonectris diomedea European Storm Petrel NM, offshore Common? SUMMER, winter Hydrobates pelagicus Wilson’s Storm Petrel SM, offshore Common WINTER, Oceanites oceanicus summer Leach’s Storm Petrel NM, offshore Uncommon Summer Oceanodroma leucorhoa Black-bellied Storm SM, offshore Rare Winter Petrel Fregetta tropica White-bellied Storm SM, offshore Rare Winter Petrel P. grallaria White-faced Storm Petrel SM, offshore Rare Winter Pelagodroma marina Great White Pelican B, inshore Rare All year Pelecanus onocrotalus Cape Gannet B, Common All year Vulnerable Morus capensis In/offshore Cape Cormorant B, inshore Common All year Near threatened Phalacrocorax capensis Bank Cormorant B, inshore Rare All year Vulnerable P. neglectus Crowned Cormorant B, inshore Uncommon All year Near threatened P. coronatus White-breasted B, inshore Uncommon All year Cormorant P. carbo Grey Phalarope NM, offshore Uncommon Summer Phalaropus fulicarius Arctic Skua NM, Common SUMMER, winter Stercorarius parasiticus In/offshore Pomarine Skua NM, offshore Common SUMMER, winter S. pomarinus Long-tailed Skua NM, offshore Common Summer S. longicaudus

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RELATIVE CONSERVATION SPECIES STATUS* SEASONALITY ABUNDANCE STATUS (IUCN) Subantarctic Skua SM, offshore Common WINTER, Catharacta antarctica summer Sabine’s Gull NM, Common Summer Larus sabini In/offshore Kelp Gull Common All year L. dominicanus Hartlaub’s Gull B, inshore Common All year L. hartlaubii Grey-headed Gull B, inshore Rare All year L. cirrocephalus Common Tern NM, inshore Common Summer Sterna hirundo Arctic Tern NM, offshore Uncommon Summer passage S. paradisaea Sandwich Tern NM, inshore Common Summer S. sandvicensis Swift Tern B, inshore Common All year S. bergii Damara Tern B, inshore Uncommon All year Near threatened S. balaenarum Caspian Tern B, inshore Rare All year S. caspia Black Tern NM, inshore Rare Summer Chlidonias niger

Common names in bold have been recorded from degree square 2814 (Swart 1988, K. Lambert in litt.). * B: breeding resident; AM: African migrant; SM: Southern Ocean migrant; NM: northern hemisphere migrant. a Recent taxonomic divisions not taken into account.

Coastal seabirds Twelve species of coastal seabirds have been recorded breeding in the study area (Table 3.2). The size of the breeding populations of these species along the southern Namibian coastline compared with the total southern African breeding populations is presented in Table 3.3 (based on Crawford et al., 1991). Significant proportions of the total breeding populations of the Kelp Gull (16%); Hartlaub's Gull (9%); Cape Cormorant (15%); Crowned Cormorant (26%); Bank Cormorant (11%) and Caspian Tern (8,5%) are present in the study area. The Greyheaded Gull is mainly an inland breeding species hence the small coastal breeding population.

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Table 3.2: Southern African seabirds breeding in the region under consideration

SCIENTIFIC NAME COMMON NAME REFERENCE Larus cirrocephalus Greyheaded Gull Maclean, 1985 Larus dominicanus Kelp Gull Crawford et al., 1982a Larus hartlaubii Hartlaub's Gull Williams et al., 1990 Morus capensis* Cape Gannet Crawford et al., 1983 Phalacrocorax capensis* Cape Cormorant Cooper et al., 1982 Phalacrocorax carbo Whitebreasted Cormorant Brooke et al., 1982 Phalacrocorax coronatus* Crowned Cormorant Crawford et al., 1982b Phalacrocorax neglectus* Bank Cormorant Cooper, 1981 Spheniscus demersus* Jackass Penguin Shelton et al., 1984; Crawford et al., 1990 Sterna balaenarum* Damara Tern Maclean, 1985 Sterna bergii Swift Tern Cooper et al., 1990 Heydorn and Williams, 1993 Sterna caspia* Caspian Tern Cooper et al., 1992 * = Red Data Book species

The breeding population of Jackass Penguins on the islands along the southern Namibian coast has declined drastically from ca. 27% of the total breeding population in the 1950s to < 2% today. Similarly, the Cape Gannet breeding population in the area has fallen from 9% of the total to about 2% at present (Crawford et al., 1991). Conversely the Cape Cormorant breeding population has risen from < 1% to nearly 15% of the total breeding population.

The decline in the Jackass Penguin population is ascribed primarily to the removal of the accumulated guano from the islands during the Nineteenth Century. Consequently the penguins, which used to breed in burrows in the guano, were forced to nest in the open thereby being exposed to much greater predation and thermal stress.

The Cape Gannet, a plunge diver feeding on epipelagic fish, is thought to have suffered as a result of the decline of the pilchard Sardinops sp. (Crawford, 1991). The rapid increase in the seal population has resulted in seals competing for island space to the detriment of the breeding success of both gannets and penguins (Crawford et al., 1989).

The African Penguin, Caspian and Damara terns are listed in the Red Data Book (Barnes (ed) 2000). The African Penguin is considered to be "Vulnerable" and the population along the west coast of southern Africa is in a severe decline. The Caspian Tern is considered to be "Near- threatened" and the population decreasing. The Damara Tern is rated as being "Endangered" with a stable population. Although the Red Data ratings in Barnes (ed) (2000) are specifically for the South African situation they apply equally to the Namibian populations of these three species.

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Table 3.3: Estimates of the breeding populations of coastal seabirds in study area (based on Crawford et al., 1991)

TOTAL BREEDING BREEDING POPULATION POPULATION (NUMBER OF SPECIES IN STUDY AREA (NUMBER PAIRS) IN THE BENGUELA AND OF PAIRS) WESTERN AGULHAS ECOSYSTEMS. Greyheaded Gull 1 36 Kelp Gull 1 816 11 199 Hartlaub's Gull 1 160 13 253 Cape Gannet 3 000 131 000 Cape Cormorant 41 000 277 000 Whitebreasted Cormorant 78 2 524 Crowned Cormorant 696 2 662 Bank Cormorant 1 000 9 022 African Penguin 1 000 55 000 Damara Tern 50 1 170 Swift Tern 175 4 835 Caspian Tern 12 141

The Damara Tern is endemic to the west and south coasts of southern Africa i.e. Angola, Namibia and South Africa. The population size of the Damara Tern is being reassessed as a result of the recent observation of a flock of some 5 000 individuals about 180 km south of the Cunene River (Braby et al., 1992). It appears that the total population may be nearer 7 000 individuals than the ca. 2 500 cited by Crawford et al., (1990).

The African Black Oystercatcher Haematopus moquini is a southern African endemic species occurring along the coasts of Namibia and South Africa. Its conservation status (“Near- threatened”) is of concern primarily as a result of the disturbance of nesting birds leading to severely reduced breeding success (Barnes (ed) 2000). The security status of Diamond Area 1 between Oranjemund and Lüderitz, provides de facto protection for this species in southern Namibia.

Orange River Mouth Ramsar Site The Orange River, the longest in the southern African region, enters the sea at 28°38'S; 16°28'E on the arid Atlantic coast of southern Africa. The Orange River is the only perennial river between the Olifants River (31°42'S; 18°11'E) and the Cunene River on the border between Namibia and Angola. There is very little tidal penetration and consequently the Orange River mouth has few estuarine features (Brown, 1959; Day, 1981). From a conservation standpoint the Orange River mouth is important as an "oasis" for birds on the arid coast between the Olifants River to the south and Walvis Bay to the north (Williams, 1986). The recent (1991) proclamation of the Orange River mouth area from the Oppenheimer Bridge to the sea as a "Wetland of International Importance" in terms of the Ramsar Convention gives official recognition to its vital importance to migrant and resident bird species.

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The following (based on Williams, 1986) clearly demonstrates the ornithological importance of the Orange River mouth. It supports more than 1% of the population of two species endemic to southwestern Africa: the Cape Cormorant and Hartlaub's Gull. The 7 000 – 10 000 Cape cormorants at the Orange River mouth in December 1985 represented 1-2% of the total population, currently believed to be not more than 500 000 individuals (Cooper et al., 1982), and the 7800 nests reported at the river mouth in 1976 (Frost and Johnson, 1977) represented about 3% of the breeding population. In April 1986 Williams (1986) recorded the presence of some 2 000 Hartlaub's gulls which constituted about 10% of the total population. A maximum of 58 Damara Terns were recorded during 13 surveys conducted since 1995 which constituted 0.4% of the estimated total population (Anderson et al., 2003).

On a southern African scale the Orange River mouth supports more than 1% of the sub continental population of Blacknecked grebes Podiceps nigricollis, 2,5% of the Lesser Flamingo Phoenicopterus minor population, 4% of the Chestnutbanded Plover Charadrius pallidus population, about 2,5% of the Curlew sandpipers Calidris ferruginea, 4% of the Swift Terns Sterna bergii and about 3% of the Caspian Terns Sterna caspia.

Grey Herons, Little Egrets, Cattle Egrets and Spoonbills have been recorded breeding on the vegetated islands in the lowermost reaches of the Orange River. Cape Cormorants, Kelp Gulls and Caspian Terns breed on the bare sandbanks just inside the estuary mouth. The islands and sandbanks in the lowermost reaches also provide predator-proof roosting sites for migrant birds and for resident species of gulls, terns and cormorants when the sea is too rough for foraging. The Orange River mouth is also an important roosting and feeding site for the White Pelican Pelecanus onocrotalus which is listed as "Near-threatened" in the Red Data Book (Barnes (ed) 2000). 3.1.2.12 Cetaceans

Information on cetaceans for the Namibian coastal area were obtained from a number of sources, including scientific and incidental sighting records, historical whaling catches and sightings and stranding records. These data sources are briefly described below.

Published literature The available published literature was reviewed for records of sightings or strandings from the southern Namibian region or the greater southern African region (in the case of further species, which are expected to be found in the southern Namibian region). Ross (1984) reviewed cetacean distribution patterns and biology from the south eastern coast of southern Africa. Findlay (1989 unpublished) reviewed the distribution patterns of all 37 species of cetaceans then found in southern Africa, from which Findlay et al. (1992) published the distribution patterns of smaller odontocete cetaceans from the region. Peddemors (1999) reviewed the distribution of the 18 delphinid species from southern African waters.

Historical whaling records Information on the seasonal abundance and distribution of large whales off the southern African west coast largely originates from historical open-boat and modern whaling. Whereas open boat

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whaling mainly targeted right and sperm whales, modern whaling targeted humpback, blue, fin, sei, Bryde’s and minke whales.

It is uncertain when open-boat whaling began on the southern African coast. American open-boat whaling fleets whaled off the coast of Guinea in 1763, and by 1770 had reached the coasts of Angola and Walvis Bay, Namibia. By 1785, Dutch, American and French fleets where whaling off the Cape Colony (Richards and du Pasqier 1989). Townsend (1935) described the distribution of whale catches from logbook records of American 19th century whale ships. Open boat whaling continued in certain localities until the early 20th century. Modern whaling in southern Africa began in 1908 in Durban and spread to the west coast at Saldanha Bay the following year. Expansion of the industry thereafter was rapid. Two stations operated at Saldanha Bay between 1909 and 1967, while further stations operated at Cape Hangklip (1913 – 1930), Mossel Bay (1911-1913) and Plettenberg Bay (1913-1916). Modern whaling in Namibia occurred from two land station localities in two episodes. A station operated from Luderitz (26º 37’ S; 15º 08’ E) between 1913 and 1914, while a factory ship and a land station operated from Walvis Bay (22º 56’ S; 14º 30’ E) between 1912 and 1914. The Walvis Bay land-station operated again between 1923 and 1930. Both land stations and floating factories operated off the coast of Angola between 1909 and 1928, while both floating factories and land stations operated off Gabon between 1912 and 1959. Best (1994) reviewed catches of baleen whales from southern Africa prior to 1930.

A further whaling episode in the south east Atlantic was the “pirate” whaling episode between 1968 and 1975. During this time the pirate whaler, the Run (later renamed the Sierra), took some 2894 sei (probably Bryde’s whales), 4 fin, 571 sperm, 14 minke and two killer whales (Best and Ross 1989).

Figure 3.14 (after Best and Ross 1986) provides the location and timing of whaling operations off the southern African west coast.

In particular, the seasonal abundance of whaling catches provide some information on the migrations of large baleen whales through whaling grounds on the southern African coast. Assuming equal catch effort, catches which show two peaks per season (a bimodal trend) suggest that the species migrated northwards and southwards through the grounds, while those that show unimodal trends (or one peak) suggest that the whaling ground was the destination of the migration.

Between 22 and 25 species of cetacean are recorded from southern Namibia, or expected to be found in the region based on their distributions elsewhere along the southern African west coast. Cetaceans can be divided into two major groups, the mysticetes or baleen whales which are largely migratory, and the toothed whales or odontocetes which may be resident or migratory. The range in the number of species reflects taxonomic uncertainty rather than a lack of information on distribution patterns. A summary of the distribution and seasonal abundance of baleen whales in southern Namibian waters is represented in Table 3.4.

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Figure 3.14: The location and timing of whaling operations off the southern African west coast A - Modern whaling, B – boat whaling (after Best and Ross, 1986)

Table 3.4: The distribution and seasonal abundance of mysticetes (baleen whales) in southern Namibian waters.

SPECIES SEASONALITY DISTRIBUTION Blue whales Migratory Pelagic (Balaenoptera musculus) Fin whales Migratory Pelagic – some association with the (B. physalus) shelf edge Sei whales Migratory Pelagic (B. borealis) Minke whales Migratory / year round Pelagic / Neritic (B. acutorostrata) Bryde’s whales Migratory Probable pelagic (B. edeni) Humpback whales Migratory / year round Pelagic / Neritic (uses coastal waters (Megaptera novaeangliae) (some summer residency) as migratory corridors) Southern right whales Migratory Neritic – extreme inshore (Eubalaena australis) Pygmy right whales Migratory unknown (Caperea marginata)

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The majority of toothed whales and dolphins have more resident than migratory distribution patterns. Findlay et al. (1992) investigated the distribution patterns of small odontocete cetaceans off the coast of Namibia and South Africa, and Figure 3.15 (from Findlay et al. 1992) defined the distributional provinces of resident cetaceans found off the west coast of Namibia and South Africa. The distribution and seasonal abundance of odontocetes (toothed whales and dolphins) in southern Namibian waters are summarized in Table 3.5.

Table 3.5: The distribution and seasonal abundance of odontocetes (toothed whales and dolphins) in southern Namibian waters.

SPECIES SEASONALITY DISTRIBUTION Sperm whales Some migration Pelagic (Physeter macrocephalus) Pygmy Sperm whales Unknown Pelagic (Kogia breviceps) Cuvier’s beaked whale Unknown possibly year round Pelagic (Ziphius cavirostris) Unknown though stranding Layard’s beaked whale data suggest a strong autumn Pelagic (Mesoplodon layardii) seasonality Gray’s beaked whale Unknown Pelagic (M. grayii) Killer whale Year round Cosmopolitan (Orcinus orca) False killer whale Year round Pelagic (Pseudorca crassidens) Pygmy killer whale Unknown Pelagic (Feresa attenuata) Long finned pilot whale Unknown Pelagic (Globicephala melas) Risso’s dolphin Unknown Pelagic – some association (Grampus griseus) with the shelf edge Common dolphin Unknown Pelagic (Delphinus delphis / capensis?) Dusky dolphin Year round Neritic (Lagenorhynchus obscurus) Heaviside’s dolphin Year round Neritic (Cephalorhynchus heavisidii) Southern right-whale dolphin Year round Pelagic / Neritic (localised) (Lissodelphis peronii) Bottlenose dolphin Year round Pelagic (Tursiops truncatus)

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3.1.2.13 Seals

The Cape fur seal Arctocephalus pusillus pusillus is abundant throughout the region. Numbers around the southern African coast have increased rapidly over the past seven decades, from an estimated 150 000 in 1920 to close to two million at present (Department of Environment Affairs and of Water Affairs and Forestry, 1990). Eight breeding colonies are located on islands and the shore between Lüderitz and Baker's Bay 120 km to the south (Department of Environment Affairs and of Water Affairs and Forestry, 1990; Wickens et al., 1992; Figure 3.15, from David, 1987). The major colonies at Wolf and Atlas bays some 30 km south of Lüderitz probably are the largest colonies of the Cape fur seal and arguably the largest mainland seal colony in the world. These colonies were completely deserted during the anomalous oceanographic event of 1994 when there was a 95% mortality of seal pups (Wickens, 1995).

Cape fur seals generally forage in shallow, shelf waters (Rand 1959; 1967; David 1989). South African fur seals range to over 150 km from the coast, with bulls ranging further out to sea than females. Tracking of South African fur seal with time depth recorders has shown that two females from Kleinsee dived to 200 m (although dives to 150 m comprised less that 10% of measured dive profiles) (David 1989). The Kudu gas field area falls within feeding range of South African fur seals.

Seals frequently are a problem to fishermen, damaging nets, eating fish and become entangled in fishing gear. Various explosive and other pyrotechnic methods have been used to scare seals. However, the effect is limited since the seals learn that the noise pulses are not harmful (Mate and Harvey, 1987). Experiments conducted in South Africa on the Cape fur seal have produced similar results (Shaughnessy et al., 1981).

Fur seal harvesting has had a marked effect on the population. Early Dutch sealing (as early as 1610) destroyed many of the colonies around the Cape. British and American sealers were active on the West Coast in the late 18th and early 19th century and the population was reduced to very low levels by the late 19th century. As a result legal control of sealing was initiated in 1893. Seals have been harvested at certain colonies almost every year between 1900 and 1990 (South Africa) and sealing has continued to the present day in Namibia. The population has shown a rapid increase rate since 1940.

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Figure 3.15: Colonies of the Southern African (Cape) Fur Seal (From David, 1987).

3.1.3 Commercial Fisheries

The Benguela current system supports one of the worlds' important commercial fisheries. Effort is primarily focussed on the demersal hake (Merluccius spp) and the pelagic/epipelagic anchovies (Engraulis). Pilchard (Sardinops) were previously dominant but have been depressed since 1968 (Crawford et al, 1987). Horse mackerel (Trachurus) have increased in importance in the overall tonnage landed since the decline of the pilchard. In the past this species was caught predominantly by purse-seine but is now mainly obtained midwater. Tunas, snoek, monkfish, kingklip, and chub mackerel are also significant resources in the Benguela as are rock lobster although the latter has declined significantly in recent years. The major spawning areas and fishing grounds are presented in Figures 3.16 and 3.17 A & B respectively.

The Kudu gas field area in Licence Area 2814A lies in the former ICSEAF Division 1.5 and statistics, summarised in Crawford et al (1987), indicate that the Division is an important

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contributor to hake catches, ~ 27% of the total Benguela landings being caught there. The bulk of the hake catch is made in the depth range 200-500 m (Botha, 1985, cited in Crawford et al, 1987). Previously Division 1.5 was important in terms of pilchard and anchovy but presently most of the catches of these species occur to the north and south of the Division (Crawford et al, 1987). Significant anchovy catches, however, used to be made immediately south of Lüderitz (Cruickshank et al, 1990).

Figure 3.16: The main spawning areas of commercially important fish along the Namibian coast.

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Figure 3.17A: Areas of main commercial fishing activity and dolphin occurrence along the Namibian coast.

Figure 3.17B: Principal fishing areas south of Lüderitz

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West Coast sole Austroglossus microlepis were previously caught in 50-100 m depth off the Orange River mouth (southern Namibian stock, Crawford et al, 1987) but the fishery declined to uneconomic levels in the 1970s and has not yet recovered. The reasons for the decline are unknown but high exploitation rates on a geographically restricted population were probably important.

Besides its obvious importance in terms of fish landings the region inshore of Licence Area 2814A is also important in terms of the pre-recruit and juvenile migration of anchovy and pilchard and as nursery grounds for hakes and horse mackerel (Crawford et al, 1987).

The commercial rock lobster fishery in Namibia is centred on Lüderitz and forms an important part of the coastal economy of southern Namibia. The commercial fishing season extends from November to April. The fishery is managed by setting a minimum size limit of 65 mm carapace length and an annually determined total allowable catch (TAC), which currently stands at 400 tonnes. Kerbe Huk is the most important fishing ground south of Lüderitz (Figure 3.17B) with an annual TAC of 70 tonnes. Although the areas around Plumpudding Island and Chameis Bay are also occasionally targeted, most of the effort is directed at the area between Mittag and Affenrücken.

The commercial fishing season opens in early November, and during the first two months of the season, fishing is restricted to the lobster grounds south of Lüderitz. Rock lobster fishing effort in the Kerbe Huk area is thus primarily limited to a relatively short period of time. Only in years when fishers struggle to fill their quotas will they continue fishing in the Kerbe Huk area into January or February. Catches from the southern fishing areas usually contribute 20-25% to the total Namibian landings (K. Grobler, MFMR Lüderitz, pers. comm.), although during seasons when catches are poor north of Lüderitz (e.g. during the 2003/2004 season) most of the quota may be caught in the Kerbe Huk area.

Thus the region is important from all aspects of sustainable commercial fisheries in that significant catches are made and the area supports juvenile stages of fish species caught elsewhere. The ecological integrity of the region is of paramount importance.

3.1.3.1 The distribution and abundance of Hake off southern Namibia

The two hake species, the shallow-water hake Merluccius capensis and the deep-water hake M. paradoxus, are found along the entire length of the Namibian shelf. Typically, shallow-water hake are found between the coast and about 400m depth, and deep-water hake between 150 and 800m, with a region of overlap at intermediate depths (e.g. Payne, 1989). M. paradoxus is the more common species in southern Namibia, although in recent years it has become increasingly abundant and more widely distributed to the north (Burmeister 2000). Larger individuals of both species are found at greater depths than smaller fish. There is little overlap in the distribution of mature fish. Shallow-water hake spawn over wide areas off Namibia, but there is no evidence of M. paradoxus spawning and recruitment in Namibian waters. (Gordoa et al., 1995 and Burmeister, 2000 contend that the Namibian stock of M. paradoxus is maintained by

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recruitment from the South African stock). There is little evidence of longshore migrations for either hake species (Boyer and Hampton, 2001a).

The importance of the hake fishery to Lüderitz and the location of the Kudu gas field in Licence Area 2814A in the hake fishing grounds warrants the more comprehensive discussion of hake presented below.

Prior to 1992, much of the Namibian hake catch was processed at sea and transhipped at Walvis Bay. During the last few years, however, Lüderitz has become an important fish processing centre with a significant proportion of the hake caught in Namibian waters being landed at the port. Much of this fish is caught by vessels exploiting the hake stocks off the southern continental shelf region.

The catches of hakes by bottom trawlers form an important component of the Namibian fishing industry with an annual landed value of over N$300 million. At present, over 40% of the catch is processed in factories onshore and exported mainly to Europe.

From 1990 to 1993, the hake stocks slowly recovered with an estimated 120 000 tonnes caught by Namibian trawlers in 1993 compared with only about 35 500 tonnes taken in 1986. However, results from the 1994 and 1995 hake biomass surveys of the R.V. Dr Fridtjof Nansen indicate that the hake stocks again declined with recruitment at a low level. Stocks of Cape hake, Merluccius capensis which were normally abundant on the central continental shelf region have also declined but in the southern region there has been an increase of both Cape hake and deep water hake Merluccius paradoxus species.

Resource surveys of hake undertaken by the R.V. Dr Fridtjof Nansen on the Namibian shelf between 1990 and 1995 indicated a total biomass of both species fluctuating between 500 000 and 1 000 000 tonnes. During the survey in May 1995, the total biomass was estimated at 575 000 tonnes of which 330 000 tonnes was fishable, i.e. above 36 cm in length. The main recruitment areas of hake over the Namibian shelf are shown in Figure 3.18. Availability in the different regions, however, can vary between years. In general, a larger proportion of hake (over 60%) are caught in the central and northern region and landed at Walvis Bay. The remainder are caught in the southern region and landed at the port of Lüderitz.

Hake stocks off southern Namibia Populations of Cape and deep water hake are widely distributed over the continental shelf off southern Namibia and occur as thick horizontal bands close to the bottom at depths of between 100 and 600 metres (Figures 3.19A and 3.19B).

The Cape hake occur predominantly closer inshore at bottom depths of 100 to 300 metres with densest concentrations occurring between 40 and 80 km from the coast. In contrast, deep water hake are most abundant along the edge of the continental shelf between 300 and 500 m depth and at distances of 80 to 120 km from the coast. Typical distribution and relative abundance of Cape hake and deep water hake on the southern Namibian shelf as determined by the R.V. Dr Fridtjof Nansen in May 1994 is shown in Figure 3.19A and 3.19B.

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(a) (b)

Figure 3.18: Recruitment areas of Cape hake Merluccius capensis (a) and deep water hake Merluccius paradoxus (b) along the Namibian continental shelf (after Alheit and Pitcher, 1995). Darker areas denote higher concentrations.

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< 10 tonnes/nm2

10 – 25

25 – 50

> 50

Figure 3.19A: Distribution and abundance of Cape hake (tonnes per square nautical mile) off the southern coast of Namibia during May 1994. (Anon, 1994).

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< 10 tonnes/nm2

10 – 25

25 –50

> 50

Figure 3.19B: Distribution and abundance of deepwater hake (tonnes per square nautical mile) off the southern coast of Namibia during May 1994. (Anon, 1994).

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Recruitment of Hake The swept area bottom trawl method currently used on hake stock assessment surveys captures both the smaller recently settled 2 year old fish as well as the larger demersal specimens.

Measurements and length distribution studies indicate that there is a clear gradation in size according to depth with the larger mature fish being found offshore west of the 250 m isobath whereas the smaller immature fish tend to occur closer to the coast in somewhat shallower water.

Although the main area of Cape hake recruitment occurs in the central region at depths of 100 to 250 m between Cape Cross (20°S) and Conception Bay (24°S), the area offshore to the northwest of Lüderitz (26°30'S) is also an important settlement zone.

The deep water hake recruit further offshore between Lüderitz and the Orange River (28°30'S) in southern Namibian waters at depths of between 150 and 300 metres.

Immature Cape hake, i.e. those between 20 and 35 cm total length occur over the entire shelf usually at depths shallower than 150 m. In contrast, immature deep water hake are found mainly distributed south of 26°S at depths ranging between 200 and 300 m.

The area inshore of the 100 m isobath between 26° and 27°S is unimportant as a fishing ground for hake. Most of the commercial trawlers fish for hake in deeper water along the continental shelf where most of the recruitment occurs.

Juvenile Hake There is little information available on the distribution and relative abundance of 0-group juvenile hake (>15 cm) along the south coast of Namibia when compared with the larger 2+ year old fish (20-30 cm). Such juveniles are normally not caught in large numbers because of the large mesh size and the method of trawl used during the stock assessment surveys.

0-group hake are known to be pelagic during the first year of life and inhabit the mid water and upper layers in the shallower waters nearer to the coast. Data suggest that the juveniles are randomly distributed over a large area and that the fish migrate offshore into deeper water during their second year and settle close to the bottom west of the 150 m isobath where they become more typically demersal in habit.

In a few cases, however, large quantities of 10-15 cm juvenile hake have been encountered and collected in the upper layers during swept area trawl surveys in the central and part of the southern region.

For example, in summer 1990, dense mid-water aggregations of juvenile hake were reported on the echosounder by the R.V. Dr Fridtjof Nansen and samples collected near the Orange River where depths ranged between 120 and 150 m.

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In summer 1991, catches of juvenile hake were also taken over a wider area in the central region but occurred in very localised concentrations along the coast between the 50 and 100 m isobath. The densities of juveniles in these aggregates were very high with most of the fish distributed in swarms or layers in mid-water extending over an area of several nautical miles. It was estimated that each aggregation could have contained several billion fish at densities ranging from 40 to 200 tonnes per square nautical mile and that such shoals could represent sizable proportions of young hake recruiting into the central region.

Sources: Alheit and Pitcher 1995; Anon 1990; Anon 1991; Anon 1994; Anon 1995a; Barange 1991; Barange and Boyd 1992; Barange et al. 1992; Macpherson et al. 1985; Macpherson et al. 1987; Macpherson and Gordoa 1992; Payne et al. 1987; Pillar and Barange 1993; Roel and Macpherson 1988; Roux 1993.

3.1.3.2 Monkfish

Two monkfish species (Lophius vomerinus and L. vaillanti) are exploited commercially in Namibia. However, only the former (the more common of the two) is found south of Walvis Bay, occurring from northern Namibia to the east coast of South Africa (Maartens and Booth 2001, Leslie and Grant 1990). It is found mainly at depths of between 150 and 500m. Densities off Namibia are highest between 300 and 400 m, off central Namibia (Maartens 1999). Two separate recruitment areas for L. vomerinus have been located in Namibia; off Walvis Bay, and near the Orange River. It is assumed (e.g. by Hampton et al. 1998 and Boyer and Hampton 2001a) that there is probably some interaction between the L. vomerinus populations found in the southernmost part of Namibia and on the South African West Coast.

3.1.3.3 The Namibian Tuna Fishery

The commercial tuna fishery and monitoring of catches in Namibian waters has been recently reviewed by Lehmensiek (1995) with the albacore Thunnus alalunga and big eye Thunnus obesus being the two most common tuna species caught.

The Albacore Fishery Albacore tuna have a wide distribution in the south Atlantic Ocean and migrate annually through their distribution range between 10° and 40°S (Penny et al. 1992). According to Crawford et al. (1987) juvenile and immature T. alalunga occur throughout the year in the Benguela system. After reaching sexual maturity they migrate (in summer) from feeding grounds off the west coast of southern Africa to the spawning grounds in the central Atlantic. T. obesus occurs in the Atlantic between 45o N and 45o S. Spawning takes place in the Gulf of Guinea and in the eastern central Atlantic north of 5o N. Talbot and Penrith (1962) maintain that T. obesus migrate to the Benguela system to feed. Maximum adult abundance occurs off Namibia, Brazil and Argentina (Yang and Sun 1984) and small albacore are present throughout the year in the Benguela region (Nepgen 1970). Concentrations of albacore are usually associated with hydrological features occurring at the shelf breaks or underwater features such as canyons and seamounts.

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The Namibian albacore fishery operates from November to May each year with catches taken predominantly by pole and line fishing vessels. These boats are usually 20 to 30 m long and have freezer capacity or chill the fish using ice wells.

The main area of fishing activity is located around the Tripp Seamount, about 200 km WNW of the Orange River mouth. Occasionally, in the southern Namibian region, well developed seasonal frontal systems can move close inshore bringing albacore tuna within 20 km of the coast.

In 1990, after Namibian independence, there were only three vessels exploiting albacore stocks. However, the effort has greatly increased during the last few years with 34 vessels registered in 1993 and 26 vessels in 1994.

Subsequent catches have reflected this increase in fishing effort with 2 900 tonnes landed in 1994 compared with 215 tonnes in 1991. Monthly catches of albacore tuna taken in Namibian waters during 1994 are shown in Figure 3.20.

Samples of albacore tuna analysed from the fishery indicates that weights range from 4 to 21 kg with an average about 9 kg per fish. The size range usually varies from 61 to 99 cm fork length with an average of about 77 cm. In addition to the albacore taken by the pole and line fishery, there are also other species of tuna taken as by-catch. These fish make up about 5% of the catch and consist of bigeye, yellowfin Thunnus albacares and skipjack Katsuwonus pelamis.

The south Atlantic albacore resource has been heavily exploited over the last decade with the maximum sustainable yield currently being estimated at about 24 000 tonnes (Punt and Butterworth 1994). Albacore catches taken in Namibian waters make up approximately 10% of the total south Atlantic catches. Catches from the Namibian pole and line fishery from the period 1985 to 1994 are shown in Figure 3.21.

3.1.3.4 Pelagic species (clupeoids and mackerels)

Since the major collapse of the stock in the 1970s, pilchard spawning, larval drift and migrations of adults and juveniles are now largely confined to the area north of Walvis Bay where the fishery is now concentrated (Hampton et al. 1998, Boyer and Hampton 2001a). The spawning and migration patterns of anchovy in Namibian waters are similar, although there is a view that in anomalous years, when the upwelling off Lüderitz is unusually weak, anchovy larvae and pre- recruits spawned off South African may recruit into the southern Namibian fishery (Boyd and Badenhorst 1980, Cruickshank 1984, Cruickshank et al. 1990). This is thought to have occurred in 1987, for example, when a catch of anchovy recruits several times larger than during the previous and following years was made off southern Namibia (Hewitson 1988). There has not been a recurrence of this situation since then.

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Figure 3.20: Monthly catches of albacore made by the pole and line fishery in 1994 off the Namibian coast (after Lehmensiek, 1995).

Figure 3.21: Catches of albacore made by the pole and line fishery at Tripp Seamount between 1985 and 1994 off the Namibian coast (only 3 vessels licenced in 1991) (after Lehmensiek, 1995).

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Round herring appear to be widely distributed off Namibia, without any clear centres of abundance. Little is known about the location and seasonality of any spawning which may occur off Namibia. Catches have largely been confined to the area north of Walvis Bay. Juvenile Cape horse mackerel generally live inshore of the 100 m isobath. Spawning is heaviest in northern Namibia, between October and March (O’Toole 1977). Nursery areas are adjacent to the spawning areas, but are closer inshore. The juveniles are believed to migrate substantially, both alongshore and across the shelf (Boyer and Hampton, 2001a). Most of the juvenile catches are made north of Walvis Bay, within the 100m isobath. Little is known about chub mackerel spawning and migration patterns off Namibia, other than that the species appears to be highly migratory, resulting in them being only sporadically abundant in the catches (Crawford 1989).

3.1.3.5 Fishing Activities

Purse-seining The pelagic species which are exploited by the purse-seine industry in Namibia are sardine Sardinops sagax (known as pilchard in Namibia, and termed such in this report), anchovy Engraulis capensis, chub mackerel Scomber japonicus and round herring Etrumeus whiteheadi. Juvenile Cape horse mackerel Trachurus capensis, which occupy the epipelagic zone, are targeted by the same purse-seine fleet. Pilchards are taken primarily for canning, with off-cuts and fish of inferior quality being reduced to meal and oil. All the other species are taken only for meal and oil.

Pilchard catches rose rapidly from around 200 000 tonnes per annum in the 1950s to a maximum of around 1.4 million tonnes in 1968. Thereafter, there was a sharp decline to less than 300 000 tonnes in 1971, followed by a slight recovery and then a precipitous collapse in 1977 and 1978. Since then annual catches have rarely exceeded 50 000 tonnes, with the lowest catch of 2 000 tonnes being recorded in 1996. The catch in 2001 has amounted to only 12 000 tonnes. Little anchovy was caught in Namibia before 1966. In the 1970s and 1980s, catches were less variable than those of pilchard, fluctuating under quota control around a level of about 200 000 tonnes per annum, with the exception of a pronounced peak in 1987. Catches in the 1990s have averaged less than 50 000 tonnes per annum, and have recently declined to virtually zero. Round herring are taken as a by-catch. Annual catches usually amount to some 1 000 tonnes, but have been as high as 14 000 tonnes (in 1996). Catches of chub mackerel have been very sporadic, but have seldom amounted to more than a few thousand tonnes per annum. Juvenile horse mackerel were rarely taken before 1971. Since then there have been sporadic catches in excess of 100 000 tonnes per year, with an average of 59 000 tonnes and a maximum of 116 000 tonnes in 1992.

The purse-seine fleet now consists of some 30 vessels, down from more than 100 at the height of the pilchard fishery in the late 1960s. They range in length from 21 to 49 m, and in tonnage from 99 to 614 tons, and operate from Walvis Bay where the fish meal plants and the one cannery now operating are situated. Most of them have refrigerated seawater plants to enable them to bring in pilchard in canning condition from as far afield as the Kunene River (about 2 days steaming from Walvis Bay). Fishing takes place within a regulated fishing season which starts in mid-February and usually runs to the end of August, depending on when the quota is filled. Catches are made both by day and, more frequently, at night.

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Most of the purse seining off Namibia occurs north of Walvis Bay, 500 km and more from the Kudu gas field area and environs. An inspection of Ministry of Fisheries and Marine Resources (MFMR) pelagic catch records for 2000 and 2001 revealed that in these two periods no catches whatsoever of pilchard, anchovy, round herring or juvenile horse mackerel were made in the area. There were however significant catches of chub mackerel in the study area in 2000 (1 475 tonnes in total, made from 22 sets) and in 2001 (3 745 tonnes from 71 sets). The catches in 2000 were made over a one-week period, between 16 and 24 May, while those in 2001 were made over a six-week period, between 20 April and 31 May. It is interesting to note that these catches have made up virtually the entire catch of chub mackerel off Namibia since the beginning of 2000, and the entire Namibian pelagic catch south of Lüderitz in the last two years. It would appear from this that the area is in some sense a favourable one for mackerel, at least in autumn, although since mackerel in the south Atlantic are known to be highly migratory, and to fluctuate widely in abundance (Crawford 1989) the catch patterns observed in 2000 and 2001 may not be indicative of what can be expected in other years. Nonetheless, the catch records from these two years are examined in more detail below, since the information is recent and is the most comprehensive available on the chub mackerel fishery.

The positions of the mackerel catches in relation to the bathymetry in the study area in the two years, 2000 and 2001, are shown in Figures 3.22 and 3.23 respectively. The similarity in catch positions between the two years, and the fact that in both years they tend to lie within a narrow longitudinal range (centred on about 14o 30´ E in both years) suggests a strong relationship with depth. The data presented in Figure 3.24 indicate that in both years, the fish were caught between 200 and 500 m depth (mostly deeper than 300 m), with the catches in 2000 being slightly shallower. (Note however that there could be errors in some of the recorded depths since it was not always clear whether the skipper had measured depth in metres or fathoms. Note too that the catches indicated in Figure 3.24 were made in considerably deeper water than indicated by Figures 3.22 and 3.23. The reason for this discrepancy, which was also found in the hake long-lining data, is unclear at present, but could in part be due to inaccurate bathymetry in Figures 3.22 and 3.23). In Figures 3.25 and 3.26 the diel pattern in the catch frequency is shown for 2000 and 2001 respectively. It can be seen that in both years catches were made only at night. The average catch per set was 67 tonnes in 2000 and 57 tonnes in 2001, which is relatively small compared to the capacity of the vessels.

Demersal trawling The major species caught by demersal (bottom) trawl off Namibia are shallow-water hake Merluccius capensis and deep-water hake Merluccius paradoxus. By-catch species are monkfish Lophius spp., kingklip Genypterus capensis, snoek Thyrsites atun and the West Coast sole Austroglossus microlepis. In recent years a monk-directed fishery has developed, with hake as the most important by-catch (Maartens 1999). On the outer Namibian shelf there is also a deep-water trawl fishery directed at orange roughy Hoplostethus atlanticus and, to a lesser extent, alfonsino Beryx splendens. This fishery takes place in depths exceeding 600 m on three small grounds far removed from Licence Area 2814A (Boyer and Hampton, 2001b), so is not considered further in this Report.

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Figure 3.22: Mackerel catch positions, 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

Figure 3.23: Mackerel catch positions, 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

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14 2000 2001 12

10 hes c 8 cat of . o

N 6

0 225 275 325 375 425 475 525 575 625 Depth (m)

Figure 3.24: Depth distribution of mackerel catches, 2000 and 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

4 es h tc 3 ca f o . o N 2

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Time

Figure 3.25: Mackerel catches vs time of day, 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

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8 ches

cat 6

f o No. 4

0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Time

Figure 3.26: Depth distribution of mackerel catches, 2000 and 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

The Namibian hake fishery started in the late 1950s. In the early 1960s, with the arrival of foreign trawling fleets, there was an explosive increase in effort, and by 1972, the annual hake catch in Namibian waters had reached over 800 000 tonnes. Subsequently, catches declined, and with the introduction of strict conservation measures after Namibian Independence in 1990, they dropped to around 50 000 tonnes per annum. In the past decade the catch has risen gradually under quota control, and now amounts to around 200 000 tonnes per annum (the present quota), making the hake fishery the most valuable fishery in Namibia. Since Independence, annual catches of monkfish have risen from around 1 500 to more than 15 000 tonnes. The value of the product is high, making this fishery an important contributor to the Namibian economy (Maartens and Booth 2001a).

Hake and monkfish are exploited by a fleet of some 70 freezer and wet-fish bottom trawlers, based in Walvis Bay and Luderitz. There is also a long-line fishery for hake from a number of smaller vessels operating from these ports. Trawling takes place throughout the year, both by day and, to a lesser extent, at night, when the fish tend to be further off the bottom. The hake catch is controlled by quota. No trawling is permitted within 200 m anywhere on the Namibian shelf, at any time of the year. All vessels large enough to carry additional personnel are required to carry a trained Ministry observer to ensure compliance with this and other regulations. The introduction of a satellite-based vessel-monitoring system (VMS), which would enable the Ministry to monitor the position and activities of all licensed fishing vessels, is under investigation.

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Trawling for hake takes place over most of the Namibian shelf (to depths of 500 to 600 m) in water deeper than 200 m, the legal inshore limit for trawling. MFMR catch records show that there is a considerable amount of trawling in the vicinity of the Kudu gas field in Licence Area 2814A, although the catch positions are not recorded accurately enough for the small-scale distribution of trawls in the area to be mapped with any certainty.

The catches of hake in the area in recent years have been significant. For example, in 1999 and 2000, 1 880 and 1 350 tows respectively were made in this area, yielding 4 804 tonnes of hake in 1999 and 4 415 tonnes in 2000. Catches by month are shown in Figure 3.27, which demonstrates that trawling in the area is a year-round activity, with no pronounced peak at any time of the year, with the possible exception of March/April in 1999. The depth distributions of the catches in the two years are shown in Figure 3.28, which illustrates that there were very few catches shallower than 350 m, and that most of the trawling activity occurred between 350 and 500 m. Further details of the trawls and the catches are summarised in Table 3.6 below.

Table 3.6: Summary of hake trawling operations in study area in 1999 and 2000 (extracted from MFMR catch records)

1999 2000 Fishing period Jan. → Dec. Jan. → Dec. No. of trawler days 577 418 Number of tows 1880 1350 Total catch (tonnes) 4804 4415 Mean catch per tow (tonnes) 2.6 3.3 Number of tows per day 1 → 5 1 → 5 Mean number of hours 11 12 spent trawling per day Minimum trawling depth (m) 226 205 Maximum trawling depth (m) 669 648

Midwater trawling Midwater trawlers in Namibia primarily target adult Cape horse mackerel, which move into deeper water with age and are taken at depths of up to about 250 m to the edge of the shelf. Inspection of MFMR records as far back as 1997 revealed that during this period there were few commercial midwater trawls south of 25oS and none whatsoever in the vicinity of the Kudu gas field. It can therefore be safely concluded that the intended study would have no impact on the Namibian midwater trawl fishery.

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160

140 1999 2000 120 s y a 100 d r le

w 80 a r t f 60 . o o N 40

0 123456789101112 Month

Figure 3.27: Monthly distribution of hake trawling, 1999 and 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

200

180 1999 160 2000

140 s y a 120 ler d 100

80 . of traw o

N 60

0 225 275 325 375 425 475 525 575 625 675 Depth (m)

Figure 3.28: Depth distribution of hake trawling, 1999 and 2000 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

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Offshore hook-and-line fishing The most important line fisheries in Namibian waters beyond the coastal zone are those for hake and large pelagic species such as tuna (particularly longfin tuna or southern albacore Thunnus alalunga and bigeye tuna T. obesus), swordfish Xiphias gladius and large pelagic sharks. Hake are caught on deep long-lines by Namibian vessels operating from Walvis Bay or Lüderitz. The large pelagic species are caught by a fleet of Namibian and foreign bait-and pole vessels, and by foreign long-liners operating under license. Since 1999 the latter vessels have also targeted swordfish.

Hake fishing occurs throughout the year, whereas tuna catches are largely confined to the summer and autumn months, peaking between January and April (Botes, 2001). Catch statistics submitted by Namibia to the International Commission for Conservation of Atlantic Tunas (ICCAT) indicate that most of the bait boat catches of tuna are made in the extreme south of Namibia, in contrast to the long-line catches, which are more widely spread latitudinally, and are generally further offshore (often outside of the Namibian EEZ).

Long-line fishing for hake by Lüderitz vessels occurs throughout the year in the Kudu gas field area. MFMR records from 23 vessels show that between January 1998 and August 2001, there have been 2 151 reported hake long-line operations in the area, in the positions shown in Figure 3.29, with annual catches ranging from 307 tonnes in 1998 to 2 281 tonnes in 2000. Details of these operations are shown in Table 3.7.

Table 3.7: Summary of hake long-line operations in study area from 1998 to 2001 (extracted from MFMR catch records)

2001 1998 1999 2000 (to 13 August) Fishing period Jan. → Dec. Jan. → Dec. Jan. → Dec. Jan. → No. of shots 159 661 923 402 Total catch 307 1 465 2 281 926 (tonnes) Mean catch per 1.93 2.21 2.47 2.30 shot (tonnes)

Note (see Table 3.7) that the annual long-line catches are of the same order as the trawl catches of hake in the area (cf. Table 3.6). Considering that the total trawl catch of hake in Namibia is typically some 10 times greater than the national long-line catch, this suggests that the area is a preferred area of operation for the hake long-liners. The distribution of fishing effort through the year is shown in Figure 3.30 for each of the years, from which it would appear that although fishing takes place throughout the year, there is a minimum in spring. The depth distribution of the effort, for the four years combined, is shown in Figure 3.31. Comparison with Figure 3.28 indicates that the centre of the hake long-lining is some 100m shallower than that of the trawling operations in the area. Figure 3.31 also indicates that despite a prohibition on catching within 200 m, there has been activity inside this limit during the past four years.

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Figure 3.29: Positions of hake long-line catches, 1998 – 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

Figure 3.30: Monthly distribution of hake long-lining in study area, 1998 – 2001 (Source: 200

180 1998 1999 160 2000 140 2001 120

100

No. of sets 80

0 123456789101112

Month Ministry of Fisheries and Marine Resources, Swakopmund)

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600

500

400

300 No. of sets

200

100

0 175 225 275 325 375 425 475 525 575 625 675

Depth (m)

Figure 3.31: Depth distribution of hake long-lining in study area, 1998 - 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

1200

1000

Set time Retrieve time 800

600

No. of sets/retrievals 400

200

0 123456789101112131415161718192021222324

Hour

Figure 3.32: Setting and retrieving times for hake long lines in study area, 1998 – 2001 (Source: Ministry of Fisheries and Marine Resources, Swakopmund)

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This impression is supported by Figure 3.29, which suggests that a larger proportion of the long- lining operations has taken place in water shallower than 200 m than is indicated by Figure 3.31, which is based on reported depths. (Note, however, the caution regarding the bathymetry, expressed above. It is also noted that the catch records have not yet been validated, and that they could contain errors in position).

Considering the amount of effort in the vicinity of the Kudu gas field and the depths in which the vessels are operating, the hake long-lining vessels probably are the most likely to adversely interact with gas field development activities and operations. The fact that long-lining takes place during daylight hours greatly reduces the chances of adverse interactions between the fishing and gas field development operations (Figure 3.32).

As previously mentioned, bait-and-pole fishing for tuna is concentrated in the extreme south of Namibia, directly south of the study area. The available records give only a very crude indication of catch positions, but do suggest that catches of both T. alalunga and T. obesus are sometimes made between the longitudinal limits of Licence Area 2814A (i.e. 14o – 15o E) in the summer and autumn months. It therefore seems possible that tuna bait-boats could operate in the vicinity of the Kudu production facility at this time of the year. However, since these boats are free to move relatively easily, and would not be tied to particular localities to ensure viable catches, they would be little affected by the 1000 m-radius exclusion zone around the production platform.

3.1.4 Conservation Areas

There are no offshore marine conservation areas in the vicinity of the Production Licence Area.

3.1.5 Shipping and Navigation

The main shipping lanes off the west coast of southern Africa lie seawards of the Kudu gas field in Licence Area 2814A (Figure 3.33). However, both coastal shipping and fishing craft may be encountered in the area and between it and the coast between Lüderitz and Port Nolloth.

Fog is a particular navigational hazard for both sea and air operations. The coast from Elizabeth Bay northwards (including Lüderitz) and from Chameis Bay south to Port Nolloth experiences an average of 50 fog days a year (Figure 3.7). Between Elizabeth and Chameis Bays a lower fog frequency occurs, namely 25 fog days per year (Olivier, 1992, 1995). The fog lies close to the coast and extends perhaps 20 nautical miles (~35 km) offshore.

The coast between Lüderitz and Port Nolloth is rugged and provides little shelter from the strong southerly and south-easterly winds. Lüderitz is the largest port having a 500 m-long deepwater quay and two jetties approached by a channel dredged to a depth of 8.15 m below Chart Datum (CD). The water depth alongside the northernmost 300 m of the new quay is –8.75 m CD and alongside the remaining 200 m is between –6.15 m CD and –4.7 m CD. In addition there is good anchorage between Angra Point and Shark Island in Lüderitz Bay (Africa Pilot, 1977; South African Sailing Directions, 1979).

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Port Nolloth is a small harbour with a quay alongside which coasters berth, with cargo being handled by a single crane. The minimum depth alongside is 3.3 m. Ships often have to lie off whilst awaiting suitable conditions to enter the harbour since the approaches to Port Nolloth "are fraught with dangers" (South African Sailing Directions, 1979).

The small inlet of Alexander Bay lies 3.5 nautical miles south of the Orange River mouth. A short breakwater extending from the southern shore provides shelter for craft up to 25 m overall. Entrance is extremely hazardous in rough weather. Alexander Bay serves as a base for the inshore diamond mining craft belonging to Alexkor. Alexkor maintains workshop facilities and a 4-man decompression chamber at Alexander Bay harbour.

Buoyage in Namibian waters follows the IALA convention for region A. Apart from satellite navigation systems, Decca navigation is also provided for. Maritime radio services for emergency (Channel 16) services, weather bulletins and navigation warnings are provided by Walvis Bay Radio (Call sign ZSV).

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Figure 3.33: Shipping routes off the west coast of southern Africa.

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MATTHEWS, L H (1938b). The sei whale, Balaenoptera borealis. Disc. Rep. 17: 183-290.

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OLIVIER, J (1992). Aspects of the climatology of fog in the Namib. SA Geographer 19 (2): 107- 125. OLIVIER, J (1995). Spatial fog distribution pattern in the Namib using Meteosat images. J. Arid Environments 29:129-138.

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PAPASTAVROU, V and VAN WAEREBEEK, K (1997). A note on the occurrence of humpback whales (Megaptera novaeangliae) in tropical and sub-tropical areas: the upwelling link. Rep. int. Whal. Commn 47: 945-947.

PAYNE, A I L (1989). Cape hakes. In: Oceans of Life off Southern Africa (Payne, A.I.L. and R.J.M.Crawford –eds) Cape Town; Vlaeberg: 136-147.

PAYNE, A I L, ROSE, B and LESLIE, R W (1987). Feeding of hake and a first attempt at determining their trophic role in the South African west coast marine environment. In: The Benguela and comparable ecosystems (Ed. A.I.L. Payne, J.A. Gulland and K.H. Brink), S. Afr. J. Mar. Sci. 5, 471-501.

PEDDEMORS, V M (1999). Delphinids of southern Africa: a review of their distribution, status and life history. J. Cet. Res. Manage. 1 (2): 157-166.

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PENNEY, A J, PUNT, A E, BECKLEY, L E and VAN DER ELST, R P (1992). South African Marine Linefish Symposium, Fish, Fishers and Fisheries, Durban, 23 – 24 Oct. 1992. ORI, Durban: 140 – 142.

PILLAR, S C and BARANGE, M (1993). Feeding selectivity of juvenile Cape hake Merluccius capensis in the southern Benguela. S. Afr. J. Mar. Sci. 13: 255-268.

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PUNT, A E, BUTTERWORTH, D S and PENNY, A J (1994). Stock assessment and risk analysis for the south Atlantic population of albacore (Thunnus alalunga) for 1994. SCRS/94/131, Report for ICCAT.

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WICKENS, P A, JAPP, D W, SHELTON, P A, KRIEL, F, GOOSEN, P C, ROSE, B, AUGUSTYN, C J, BROSS, C A R, PENNEY, A J and KROHN, R G (1992). Seals and fisheries in South Africa - competition and conflict. S. Afr. J. Mar. Sci. 12: 773-789.

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Part A, Section 4: Legislation and Legal Obligations

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Part A, Section 4: Legislation and Legal Obligations

4. LEGISLATION AND LEGAL OBLIGATIONS ______4-1

4.1 NAMIBIAN ENVIRONMENTAL LEGISLATION ______4-1 4.1.1 Constitution of the Republic of Namibia, 1990 ______4-1 4.1.2 The Petroleum (Exploration and Production) Act, No. 2 of 1991 ______4-1 4.1.3 Namibia’s Environmental Assessment Policy (1995) ______4-2 4.1.4 Draft Environmental Management Act Bill ______4-3 4.1.5 Territorial Sea and Exclusive Economic Zone of Namibia (Act 3 of 1990, amended by Act 30 of 1991) ______4-3 4.1.6 Prevention and Combatting of Pollution of the Sea by Oil Act 1981 and the 1991 Amendment Act (Act No 24) ______4-4 4.1.7 The Marine Traffic Act (Act 2 of 1981 amended by Act 15 of 1991)______4-4 4.1.8 Marine Resources Act, 2000______4-4 4.1.9 Acts covering aspects of Health, Safety and Environmental Protection______4-5 4.2 INTERNATIONAL CONVENTIONS TO WHICH NAMIBIA IS PARTY ______4-5 4.2.1 The United Nations Law of the Sea Convention, 1982 (UNCLOS) ______4-5 4.2.2 International Convention for the Prevention of Pollution from Ships, 1973, as modified by the Protocol of 1978 relating thereto (MARPOL 73/78) ______4-5 4.2.3 The Convention on Biological Diversity (CBD) 1992 ______4-5 4.3 MARPOL REGULATIONS RELEVANT TO THE MARITIME ASPECTS OF THE KUDU GAS FIELD DEVELOPMENT OPERATIONS ______4-6 4.3.1 Machinery space drainage ______4-6 4.3.2 Sewage ______4-6 4.3.3 Galley wastes ______4-7 4.3.4 Solid waste ______4-8 4.3.5 Atmospheric emissions ______4-8 4.4 CONTRACTS BETWEEN TULLOW OIL AND CONTRACTORS ______4-14

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4. LEGISLATION AND LEGAL OBLIGATIONS

4.1 NAMIBIAN ENVIRONMENTAL LEGISLATION

Namibian legislation relevant to petroleum exploration and production consists of South African legislation, South West African legislation and Namibian legislation that has been passed since independence in 1990.

4.1.1 Constitution of the Republic of Namibia, 1990

The constitution is the supreme law in Namibia, providing for the establishment of the main organs of state (the Executive, the Legislature and the Judiciary) as well as guaranteeing various fundamental rights and freedoms. Provisions relating to the environment are contained in Chapter 11, article 95, which is entitled “promotion of the Welfare of the People”. This article states that the Republic of Namibia shall – “actively promote and maintain the welfare of the people by adopting, inter alia, policies aimed at … maintenance of ecosystems, essential ecological processes and biological diversity of Namibia and utilisation of living natural resources on a sustainable basis for all Namibians, both present and future; in particular, the Government shall provide measures against the dumping or recycling of foreign nuclear waste on Namibian territory”. Note, however this is a directive principle of state policy rather than a right, i.e. not really enforceable.

While a number of pre-independence laws were expressly repealed by the Constitution (section 112), in accordance with Clause 140 of the Constitution all other laws in force immediately before the date of independence, remain in force until they are repealed or amended by new legislation or are declared unconstitutional by a competent court. Many of the South African acts that were applicable at the time of independence are thus applicable. Many of them have been amended since this time, and a number of new laws have been passed or are nearing completion.

4.1.2 The Petroleum (Exploration and Production) Act, No. 2 of 1991

In accordance with the Petroleum (Exploration and Production) Act, No. 2 of 1991, a Petroleum Agreement is has been established between the government of Namibia (Ministry of Mines and Energy) and the licence holders, Energy Africa Kudu Limited and Namcor. Clause 11 of the Petroleum Agreement deals with environmental protection and describes the requirement for an exploration phase environmental assessment to be conducted by the operator:

11.3 “The Company undertakes to take all necessary and adequate steps – (b) to minimise environmental damage to the licence area and adjoining or neighbouring lands.

11.6 The measures and methods to be used by the Company for purposes of complying with the terms of paragraph (b) of clause 11.3 shall be determined in timely consultation with the Minister upon the commencement of petroleum operations or whenever there is a significant change in the scope or method of carrying out petroleum operations, and the Company shall take into account the

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international standards applicable in similar circumstances and the relevant environmental impact study carried out in accordance with clause 11.7.

11.7 The Company shall cause a person or persons, approved by the Minister on account of their special knowledge of environmental matters to carry out two environmental impact studies, in order –

(a) to determine the prevailing situation relating to the environment, human beings, wildlife or marine life in the licence area and in the adjoining or neighbouring areas at the time of the studies; and

(b) to establish what the effect will be on the environment, human beings, wildlife or marine life in the licence area in consequence of the petroleum operations to be made under this Agreement, and to submit for consideration by the parties measures and methods contemplated in clause 11.6 for minimising environmental damage and carrying out site restoration in the licence area.

11.10 The studies mentioned in Clause 11.7 shall contain proposed environmental guidelines to be followed in order to minimise environmental damage …..”

The Petroleum Act (2 of 1991) prohibits any spilling of water or drilling fluids in the licence area. However, the subsequent Petroleum Amendment Act (11 of 1997) provides for such discharges only on application by the licence holder to the Ministry of Mines and Energy who will consult with the Ministers of Fisheries, and of Environment and Tourism whereafter the Minister will then exempt the holder by notice in the Government Gazette from the provision of the Petroleum Act.

4.1.3 Namibia’s Environmental Assessment Policy (1995)

The Ministry of Environment and Tourism published the Environmental Assessment Policy which was approved by Cabinet in 1994. The Government of Namibia recognises that Environmental Assessments (EAs) are key tools to further the implementation of a sound environmental policy which strives to achieve Integrated Environmental Management (IEM). The Government also recognises that EAs seek to ensure that the environmental consequences of development projects and policies are considered, understood and incorporated into the planning process. In the context of IEM, the term environment is broadly interpreted to include biophysical, social, economic, cultural, historical and political components.

The principles of the Environmental Assessment Policy have been applied to this EA. The principles set out to:

better inform decision-makers; consider a broad range of options and alternatives when addressing specific projects; strive for a high degree of public participation and involvement; take into account the environmental costs and benefits;

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incorporate internationally accepted norms and standards where appropriate; take into account secondary and cumulative environmental impacts; promote sustainable development, and, especially to ensure that a reasonable attempt is made to minimise possible negative impacts and maximise benefits; (Source: Ministry of Environment and Tourism, 1995).

4.1.4 Draft Environmental Management Act Bill

The draft Environmental Management Act Bill is in preparation has been compiled under the guidance of the Ministry of Environment and Tourism since (1995). In terms of the proposed legislation it will be possible to exercise control over certain listed coastal developments activities and activities within defined sensitive areas. The listed activities and sensitive areas require an Environmental Assessment to be completed before a decision to permit development can be taken. The draft legislation describes the circumstances requiring Environmental Assessments. In Schedule A of the draft Act, activities are listed which require Environmental Assessment unless the Environmental Commissioner, in consultation with the relevant Authority, determines otherwise. The list of activities for which Environmental Assessments are compulsory has not yet been finalised. However, the draft Act states that Schedule A will contain the list of activities described in the Environmental Assessment Policy document, as well as certain other activities which may be appended in due course.

Section 3.2 of the draft Act states that should one of the listed activities take place in, or have an effect on an area listed in Schedule B, an Environmental Assessment has to be carried out. No official list of sensitive areas exists at present, but a preliminary draft of such a list has been compiled. If it is determined that a project or development which is not included in Schedules A & B could have a significant impact on the environment the relevant authority may require an Environmental Assessment under section 3.3 of the draft Act.

4.1.5 Territorial Sea and Exclusive Economic Zone of Namibia (Act 3 of 1990, amended by Act 30 of 1991)

This Act determines Namibia’s territorial sea, internal waters, contiguous zone, exclusive economic zone (EEZ) and continental shelf in conformity with international law.

It defines Namibia’s territorial sea as the sea within a distance of 12 nautical miles from baseline (the low water mark). It establishes Namibia’s internal waters as waters landward of its low water line or any other baseline.

The contiguous zone is established as the sea outside the territorial sea but within a distance of 24 nautical miles. In this zone Namibia may exercise any powers deemed necessary to prevent the contravention of any laws, for example on immigration.

In the 200 nautical mile EEZ established under the Act, Namibia may exercise powers to control the use and conservation of living marine resources. When it comes to exploiting non-living resources, such as precious stones, the continental shelf is regarded a State land.

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4.1.6 Prevention and Combatting of Pollution of the Sea by Oil Act 1981 and the 1991 Amendment Act (Act No 24)

The Act provides for the prevention of oil pollution of the sea within 50 nautical miles of the coast. A “discharge” in relation to oil, means any discharge of oil from a ship, tanker or offshore installation. The Act empowers the Minister to delegate tasks for the purpose of preventing oil pollution. Thus the National Oil Spill Contingency Organisation (NOSCO) was established to draft and implement a National Oil Spill Contingency Plan (NOSCP).

The National emergency response team, is under the overall control of the Government Action Control Group (GACG) in Windhoek. It consists of a 24 hour response team, with the capacity to handle a major incident. The GACG coordinates the efforts of the various Ministries that will be involved in the event of a spill, and responds on request from the parties involved in a spill.

4.1.7 The Marine Traffic Act (Act 2 of 1981 amended by Act 15 of 1991)

This Act provides for the regulation of marine traffic in the waters that fall under the sovereignty of the Republic of Namibia. In terms of section 14 the Minister of Works, Transport and Communication is empowered to make regulations pertaining to marine traffic in the territorial sea and internal waters, including the prescription of sea lanes and traffic separation schemes for ships in general, or for any class of ship, or for ships carrying nuclear or other dangerous or noxious substances. Section 14 also provides for the protection of navigation aids and facilities, and offshore installations.

To date no regulations have been promulgated in terms of section 14.

4.1.8 Marine Resources Act, 2000

This Act is designed to provide for the conservation of the marine environment in Namibia, for the responsible utilisation, protection and promotion of marine resources, and for control over marine resources. This act replaces the Sea Fisheries Act, 1992 and the Sea Birds and Seals Protection Act, 1973. It provides for the appointment of fishery inspectors and observers, and for the establishment of a Fishery Observer Agency, a Marine Resources Advisory Council, and a Marine Resources Fund. It lists requirements for commercial harvesting of resources and measures for the management and control of fisheries.

Article 51 of the The Act allows in article 51 for the establishment of Marine reserves, while article 52 imposed imposes penalties on dredging or extraction of sand and gravel in Marine Reserves, discharges or deposits of waste or any other polluting matter and discharges in Namibian waters of anything which may be injurious to marine resources or which may disturb the ecological balance.

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4.1.9 Acts covering aspects of Health, Safety and Environmental Protection

Atmospheric Pollution Prevention Ordinance, 1976 Hazardous Substances Schedules and Regulations, 1979 Explosives Act, 1956 Public Heath Act 1919, as amended to 1976 International Health Regulations Act, 1974 Labour Act, 1992.

4.2 INTERNATIONAL CONVENTIONS TO WHICH NAMIBIA IS PARTY

4.2.1 The United Nations Law of the Sea Convention, 1982 (UNCLOS)

This convention came into force in 1995 and deals with the prevention of marine pollution and with the compensation for damage caused by this pollution. It contains provisions relating to the prescription and enforcement of pollution standards; in addition it emphasises unilateral action by states with regard to pollution control, and provides for contingency plans against pollution. The convention requires states to adopt legislation to reduce marine pollution from: sea-bed activities in the EEZ and on the continental shelf (Articles 208 and 214), and from land based sources (Articles 194 and 207). It also contains provisions relating to marine pollution resulting from dumping of waste at sea (Articles 210 and 216).

4.2.2 International Convention for the Prevention of Pollution from Ships, 1973, as modified by the Protocol of 1978 relating thereto (MARPOL 73/78)

The International Convention for the Prevention of Pollution from Ships, 1973, was adopted in 1973. This convention was subsequently modified by the Protocol of 1978. This convention provides regulations covering the various sources of ship-generated pollution (IMO, 1992). Namibia is a party to Annexes I, II, III, IV and V of MARPOL 73/78.

4.2.3 The Convention on Biological Diversity (CBD) 1992

Namibia signed the Convention on Biological Diversity on 12 June 1992 in Rio de Janeiro , at the United Nations Conference on Environment and Development, and ratified it on 18 March 1997. Namibia is accordingly now obliged under international law to ensure that its domestic legislation conforms with the CBD’s objectives and obligations.

The Convention’s overall objectives are set out in its Article 1:

the conservation of biodiversity; the sustainable use of its components; the fair and equitable sharing of benefits arising from the use of genetic resources.

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4.3 MARPOL REGULATIONS RELEVANT TO THE MARITIME ASPECTS OF THE KUDU GAS FIELD DEVELOPMENT OPERATIONS

4.3.1 Machinery space drainage

MARPOL Annex 1: Regulations for the Prevention of Pollution by Oil, Regulation 9(1)(b) Control of discharge of oil.

"... any discharge into the sea of oil or oily mixtures from ships to which this Annex applies shall be prohibited except when all the following conditions are satisfied:

(b) from a ship of 400 tons gross tonnage and above other than an oil tanker and from machinery space bilges excluding cargo pump-room bilges of an oil tanker unless mixed with oil cargo residue: i. the ship is not within a special area; ii. the ship is proceeding en route; iii. the oil content of the effluent is less than 15 parts per million; and iv. the ship has in operation equipment as required by regulation 16 of this Annex."

Regulation 16, Oil Discharge Monitoring and Control System and Oil Filtering Equipment

(1) Any ship of 400 tons gross tonnage and above but less than 10,000 tons gross tonnage shall be fitted with oil filtering equipment complying with paragraph (4) of this regulation. Any such ship which carries large quantities of oil fuel shall comply with paragraph (2) of this regulation or paragraph (1) of regulation 14.

(4) Oil filtering equipment referred to in paragraph (1) of this regulation shall be of a design approved by the Administration and shall be such as will ensure that any oily mixture discharged into the sea after passing through the system has an oil content not exceeding 15 parts per million. In considering the design of such equipment, the Administration shall have regard to the specification recommended by the Organization. 1

4.3.2 Sewage

MARPOL Annex lV: Regulations for the Prevention of Pollution by Sewage from ships, Regulation 8 Discharge of sewage.

"(1) Subject to the provisions of regulation 9 of this Annex, the discharge of sewage into the sea is prohibited, except when:

1 Refer to the Recommendation on International Performance and Test Specifications for Oily-Water Separating Equipment and Oil Content Meters adopted by the Organization by resolution A.393(X).

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(a) the ship is discharging comminuted and disinfected sewage using a system approved by the Administration in accordance with regulation 3(1)(a) at a distance of more than four nautical miles from the nearest land, or sewage which is not comminuted or disinfected at a distance of more than 12 nautical miles from the nearest land, provided that in any case, the sewage that has been stored in holding tanks shall not be discharged instantaneously but at a moderate rate when the ship is en route and proceeding at not less than 4 knots; the rate of discharge shall be approved by the Administration based upon standards developed by the Organization; or

(b) the ship has in operation an approved sewage treatment plant which has been certified by the Administration to meet the operational requirements referred to in regulation 3(1)(a)(i) of this Annex, and

(i) the test results of the plant are laid down in the ship's International Sewage Pollution Prevention Certificate (1973);

(ii) additionally, the effluent shall not produce visible floating solids in, nor cause discolouration of, the surrounding water; or

(c) the ship is situated in the waters under the jurisdiction of a State and is discharging sewage in accordance with such less stringent requirements as may be imposed by such State.

(2) When the sewage is mixed with wastes or waste water having different discharge requirements, the more stringent requirements shall apply."

4.3.3 Galley wastes

MARPOL Annex V: Regulations for the Prevention of Pollution by Garbage from Ships, Regulation 3(1)(b), (1)(b)(ii) and (1)(c) Disposal of garbage outside special areas.

"(1)(b): the disposal into the sea of the following garbage shall be made as far as practicable from the nearest land but in any case is prohibited if the distance from the nearest land is less than: (ii) 12 nautical miles for food wastes and all other garbage including paper products, rags, glass, metal, bottles, crockery and similar refuse;

(1)(c): disposal into the sea of garbage specified in subparagraph (b)(ii) of this regulation may be permitted when it has passed through a comminuter or grinder and made as far as practicable from the nearest land but in any case is prohibited if the distance from the nearest land is less than 3 nautical miles. Such comminuted or ground garbage shall be capable of passing through a screen with openings no greater than 25 millimetres."

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4.3.4 Solid waste

MARPOL Annex V: Regulation 3(1)(a) and (1)(b).

"(1) Subject to the provisions of regulations 4, 5 and 6 of this Annex:

(a) the disposal into the sea of all plastics, including but not limited to synthetic ropes, synthetic fishing nets and plastic garbage bags is prohibited; (b) the disposal into the sea of the following garbage shall be made as far as practicable from the nearest land but in any case is prohibited in the distance from the nearest land is less than:

(i) 25 nautical miles for dunnage, lining and packing materials which will float;

(ii) (ii) 12 nautical miles for food wastes and all other garbage including paper products, rags, glass, metal, bottles, crockery and similar refuse;"

4.3.5 Atmospheric emissions

MARPOL ANNEX VI: REGULATIONS FOR THE PREVENTION OF AIR POLLUTION FROM SHIPS

Regulation 12: Ozone Depleting Substances

(b) Subject to the provisions of regulation 3, any deliberate emissions of ozone depleting substances shall be prohibited. Deliberate emissions include emissions occurring in the course of maintaining, servicing, repairing or disposing of systems or equipment, except that deliberate emissions do not include minimal releases associated with the recapture or recycling of an ozone depleting substance. Emissions arising from leaks of an ozone depleting substance, whether or not the leaks are deliberate, may be regulated by Parties to this Annex.

(c) New installations which contain ozone depleting substances shall be prohibited on all ships, except that new installations containing hydro-chlorofluorocarbons (HCFCs) are permitted until 1 January 2020.

(d) The substances referred to in this regulation, and equipment containing such substances shall be delivered to appropriate reception facilities when removed from ships.

Regulation 13: Nitrogen Oxides (NOx)

(1) (a) This regulation shall apply to:

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(i) each diesel engine with a power output of more than 130 kW which is installed on a ship constructed on or after 1 January 2000; and

(ii) each diesel engine with a power output of more than 130 kW which undergoes a major conversion on or after 1 January 2000.

(b) This regulation does not apply to:

(i) emergency diesel engines, engines installed in lifeboats and any device or equipment intended to be used solely in case of emergency; and engines with a rated engine speed of [2000 rpm] or greater and installed on ships not engaged in voyages to ports or offshore terminals under the jurisdiction of other Parties to the Protocol of [1997].

(c) Notwithstanding the provisions of sub-paragraph (a) of this paragraph, the Administration may allow exclusion from the application of this regulation to any diesel engine which is installed on a ship constructed, or on a ship which undergoes a major conversion, before the date of entry into force of the present Protocol, provided that the ship is solely engaged in voyages to ports or offshore terminals within the State the flag of which the ship is entitled to fly.

(2) (a) For the purpose of this regulation, "major conversion" means a modification of an engine where:

(i) the engine is replaced by a new engine built on or after 1 January. 2000, or

(ii) any substantial modification, as defined in the N0x Technical Code, is made to the engine, or

(iii) the maximum continuous rating of the engine is increased by more than 10%.

(b) The N0x emission resulting from modifications referred to in the sub-paragraph (a) of this paragraph shall be documented in accordance with the N0x Technical Code for approval by the Administration.

(3) (a) Subject to the provision of regulation 3 of this Annex, the operation of each diesel engine to which this regulation applies is prohibited, except, when the emission of nitrogen oxides (calculated as the total weighted emission of N02) from the engine is within the following limits:

(i) 17.0g/kWh when n is less than 130 rpm

(ii) 45.0*n(-0.2)g/kWh when n is 130 or more but less than [2000 rpm]

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(iii) [9.8] g/kWh when n is [2000 rpm] or more

where n = rated engine speed (crankshaft revolutions per minute).

Test procedure and measurement methods shall be in accordance with the N0x Technical Code, taking into consideration the Test Cycles and Weighting Factors outlined in appendix V to this Annex.

(b) Notwithstanding the provisions of sub-paragraph (a) of this paragraph, the operation of a diesel engine is permitted when:

(i) an exhaust gas cleaning system, approved by the Administration in accordance with the N0x Technical Code, is applied to the engine to reduce onboard N0x emissions at least to the limits specified in sub- paragraph (a), or

(ii) any other equivalent method, approved by the Administration in accordance with the relevant guidelines to be developed by the 0rganization, is applied to reduce onboard N0x emissions at least lo the limit specified in sub-paragraph (a) of this paragraph.

(4) (a) Every diesel engine which is designed to operate within the limits specified in sub-paragraph (3)(a) of this regulation shall be provided with a ready. means of verification, approved by the Administration in accordance with the N0x Technical Code, which ensures that the operation of the engine is in compliance with such limits. Such ready means of verification can take the form of either an equipment requirement or an inspection procedure.

(b) A ship may be fitted with a monitoring and recording device as a ready means of verification. This device shall be approved by the Administration in accordance with the N0x Technical Code. These monitoring records shall be kept on board for three months for verification purposes by the Parties to the Protocol of [1997].

(5) Every marine diesel engine to which this regulation applies shall be provided with a Technical File in accordance with the N0x Technical Code. The Technical File shall be prepared by the engine manufacturer and approved by the Administration.

Regulation 14: Sulphur Oxides (SOx)

General requirements

(1) The sulphur content of any fuel oil used on board ships shall not exceed [5.0% m/m].

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(2) The worldwide average sulphur content of residual fuel oil supplied for use on board ships shall be monitored in accordance with guidelines to be developed by the 0rganization.

Requirements within SOx Emission Control Areas

(3) For the purpose of this regulation, SOx Emission Control Areas shall include:

[(a) The Baltic Sea area as defined in regulation 10(1)(b) of Annex I:]

(b) Any [other] sea, including port, areas designated by. the 0rganization in accordance with the criteria and procedures for designation of S0x Emission Control Areas with respect to air pollution from ships contained in appendix II.

(4) While ships are within S0x Emission Control Areas, at least one of the following conditions shall be fulfilled.

(a) The sulphur content of fuel oil used on board ships in a S0x Emission Control Area does not exceed 1.5% m/m.

(b) An exhaust gas cleaning system, approved by the Administration in accordance with the guidelines developed by the Organization, is applied to reduce the total emission of sulphur oxides from ships, including both auxiliary and main propulsion engines, to 6.0 g S0x/kWh or less calculated as the total weight of sulphur dioxide emission. Waste streams from the use of such equipment shall not be discharged into enclosed ports, harbours and estuaries unless it can be thoroughly documented by the ship that such waste streams have no adverse impact on the ecosystems of such enclosed ports, harbours and estuaries based upon criteria provided by the authorities of the port State to the Organisation.

(c) Any other technological method that is verifiable and enforceable to limit SOx emissions to a level equivalent to that described in sub-paragraph (b) is applied. These methods shall be approved by the Administration in accordance with the guidelines developed by the 0rganization.

(5) The sulphur content of fuel oil referred to in paragraph (1) and sub-paragraph (4)(a) of this regulation shall be documented by the supplier as required by regulation 18 of this Annex.

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equal to 1.5% sulphur content) in each tank as well as the date, time and position of the ship when any fuel-changeover operation is completed, shall be recorded in such log-book as prescribed by the Administration.

[(7) During the first year immediately following entry into force of the instrument designating a specific S0x Emission Control Area, ships entering that S0x Emission Control Area are exempted from the requirements in paragraphs (4) to (6) of this regulation.]

Regulation 15: Volatile Organic Compounds

(1) If the emissions of volatile organic compounds (VOCs) from tankers are to be regulated in ports or terminals under the jurisdiction of a Party to the Protocol of [1997], they shall be regulated in accordance with the provisions of this regulation.

(2) A Party to the Protocol of [1997] which designates ports or terminals under its jurisdiction in which VOC emissions are to be regulated, shall submit a notification to the 0rganization. This notification shall include information on the size of tankers to be controlled, on cargoes requiring vapour emission control systems, and the effective date of such control. The notification shall be submitted at least six months before the effective date.

(3) The Government of each Party to the Protocol of [1997] which designates ports or terminals at which VOC emissions from tankers are to be regulated shall ensure that vapour emission control systems, approved by that Government based on the standards developed by the Organization2 , are provided in ports and terminals designated, and are operated safely and in a manner so as to avoid undue delay to the ship.

(4) The Organization shall circulate a list of the ports and terminals designated by the Parties to the Protocol of [1997] to other Member States of the Organization for their information.

(5) All tankers which are subject to vapour emission control in accordance with the provisions of paragraph (2) of this regulation shall be provided with a vapour collection system approved by the Administration based on the standards developed by the Organization3, and shall use such system during the loading of such cargoes. Terminals which have installed vapour emission control systems in accordance with this regulation may accept existing tankers which are not fitted with vapour collection systems for a period of three years after the effective date identified in Paragraph (2).

2 Reference is made to MSC/Circ. 585 Standards for Vapour Emission Control Systems. 3 Reference is made to MSC/Circ. 585 Standards for Vapour Emission Control Systems.

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(6) This regulation shall only apply to gas carriers when the type of loading and containment systems allow safe retention of non-methane VOC's on board, or their safe return ashore.

Regulation 16: Shipboard Incineration

(1) Except as provided in paragraph (5), shipboard incineration shall be allowed only in a shipboard incinerator.

(2) Each incinerator installed on board a ship on or after [1 January 2000] shall meet the requirements contained in appendix IV. Each such incinerator shall be approved by the Administration based on the standard specifications for shipboard incinerators developed by the 0rganization4.

(3) Nothing in this regulation affects the prohibition in, or other requirements of, the Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matters (London, 1972, as amended).

(4) Shipboard incineration of the following substances shall be prohibited:

(a) Annex I, II and III cargo residues and related contaminated packing materials;

(b) polychlorinated biphenyls (PCBs);

(d) refined petroleum products containing halogen compounds.

(5) Shipboard incineration of sewage sludge aud sludge oil may also take place in the main or auxiliary power plant but, in those cases, shall not take place inside ports, harbours and estuaries.

(6) Shipboard incineration of polyvinyl chlorides (PVCs) shall be prohibited, except in shipboard incinerators for which IMO Type Approval Certificates have been issued5.

(7) All ships with incinerators subject to this regulation shall possess a manufacturer's operating manual which shall specify how to operate the incinerator within the limits described in paragraph 2 of appendix IV.

4 Reference is made to the standard specification for shipboard incinerators contained in Appendix 2 to the Revised Guidelines for the Implementation of Annex V of MARPOL 73/78 (resolution MEPC.59(33)). 5 Reference is made to the standard specification for shipboard incinerators contained in Appendix 2 to the Revised Guidelines for the Implementation of Annex V of MARPOL 73/78 (resolution MEPC.59(33)).

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(8) Personnel responsible for operation of any incinerator shall be trained and capable of implementing the guidance provided in the manufacturer's operating manual.

(9) Monitoring of combustion flue gas outlet temperature shall be required at all times and waste shall not be fed into a continuous-feed shipboard incinerator when the temperature is below the minimum allowed temperature of 850°C. For batch-loaded shipboard incinerators, the unit shall be designed so that the temperature in the combustion chamber shall reach 600°C within 5 minutes after start-up.

(10) Nothing in this regulation precludes the development, installation and operation of alternative design shipboard thermal waste treatment devices that meet or exceed the requirements of this regulation.

4.4 CONTRACTS BETWEEN TULLOW OIL AND CONTRACTORS

In order to ensure that the requirements of Clause 11 of the Petroleum Agreement are met, Tullow Oil will incorporate appropriate clauses in its contract(s) with contractors.

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Part A, Section 5: Stakeholder Meetings

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Part A, Section 5: Stakeholder Meetings

5. STAKEHOLDER MEETINGS ______5-1

5.1 IDENTIFICATION OF KEY ISSUES ______5-1 5.2 THE APPROACH TO THE SCOPING PHASE OF THE EIA STUDY ______5-1 5.3 IDENTIFICATION OF I&APS ______5-1 5.4 PROCEDURE FOR THE SCOPING MEETINGS______5-2 5.4.1 Joint Kudu gas field development/KPP scoping meetings ______5-2 5.4.2 Separate Kudu gas field development scoping meetings______5-2 5.4.3 Separate Kudu gas field development postal scoping ______5-2 5.4.4 2004: Interministerial Review Group and public information meetings ______5-2 5.5 RESULTS OF THE SCOPING PROCESS______5-2 5.5.1 Kudu Gas Field: Size, Economic Life, etc. ______5-3 5.5.2 Availability of Deep Drilling Technology ______5-4 5.5.3 Design and Capacity of Pipeline ______5-4 5.5.4 Pipeline Operation______5-5 5.5.5 Environmental Impact of the Pipeline ______5-5 5.5.6 Effect of the Pipeline on Fishing and Navigation ______5-6 5.5.7 Disposal of Effluent from the Gas Conditioning Plant______5-6 5.5.8 Impact of Discharges from Offshore Facility______5-7 5.5.9 Handling and Fate of Monoethylene Glycol (MEG) and Condensate______5-7 5.5.10 Safety/Contingency Plans______5-8 5.5.11 Post Construction Rehabilitation Plan______5-8 5.5.12 Effect on Transport Infrastructure ______5-9 5.5.13 Greenhouse Effect ______5-9 5.5.14 Desalination Plant at Lüderitz ______5-9 5.5.15 Sperrgebiet Management Plan ______5-9 5.5.16 Relationship between Kudu and Kunene (Epupa) Projects ______5-10 5.5.17 Research Co-operation______5-10

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5. STAKEHOLDER MEETINGS

5.1 IDENTIFICATION OF KEY ISSUES

Because the basic design of the Kudu gas field development project has not changed significantly since 2001 it was decided with the approval of the Interministerial Review Group for the Kudu Gas to Power project not to initiate a new round of scoping. Instead it was decided to use the issues raised in the public meetings held in 1998 and by the postal scoping undertaken in 2001 to guide the impact assessment component of the EIA. The issues raised are presented in Section 5.5 below.

5.2 THE APPROACH TO THE SCOPING PHASE OF THE EIA STUDY

The objective of the Kudu gas field development project is to provide gas to the Combined Cycle Gas Turbine (CCGT) power station planned to be located at near Oranjemund, the Kudu Power Project (KPP). The terrestrial component of the gas field development, the gas conditioning plant, will be located immediately adjacent to the CCGT. Consequently it was decided to combine the scoping exercises for the two projects. Three combined meetings were held during February 1998 in Windhoek, Oranjemund and Alexander Bay, South Africa. In addition, for the Kudu gas field development project alone, an Interministerial Review Group Meeting in Windhoek, and a scoping meeting in Lüderitz were held. The former was held in accordance with the terms of the Petroleum Agreement between SEPN and the Namibian Government, and the latter to ensure that all the other interested and affected parties (I&APs) potentially affected by the Kudu gas field development project would have the opportunity to express their views.

Because more than three years had elapsed since the EIA for the Kudu gGas fField development pProject was initiated, it was considered necessary both by Shell Exploration and Production Namibia B.V. and the Ministry of Environment and Tourism to provide the interested and affected parties (I&APs) with the opportunity to review the questions and concerns raised at the scoping meetings held in February 1998. This was undertaken by means of an information leaflet and reply-paid response form being distributed to all the I&APs during May 2001. The additional issues raised are included in Section 5.5 below.

5.3 IDENTIFICATION OF I&APs

The identification of the key I&APs at the beginning of the project is essential for scoping to be successful. The initial list was drawn up through liaison between Shell, Eskom, NamPower, CSIR, Walmsley Environmental Consultants (WEC) and relevant Government authorities. However, it was realised that such a list may overlook certain I&APs thus, all invitees were requested to bring any such omissions to the attention of the CSIR. To achieve this “cross- referral”, each invitee was provided with a list of all the other identified I&APs.

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5.4 PROCEDURE FOR THE SCOPING MEETINGS

5.4.1 Joint Kudu gas field development/KPP scoping meetings

The following joint scoping meetings were held:

Windhoek, 10 February 1998 Oranjemund, 11 February 1998 Alexander Bay, South Africa, 11 February 1998.

5.4.2 Separate Kudu gas field development scoping meetings

The following Kudu-specific scoping meetings were held:

Interministerial Review Group Meeting, Windhoek, 13 February 1998 Lüderitz, 13 February 1998.

5.4.3 Separate Kudu gas field development postal scoping

An information leaflet and reply-paid form was distributed to all I&APs in May 2001.

5.4.4 2004: Interministerial Review Group and public information meetings

Following Energy Africa Kudu Limited taking over as operator for the Kudu gas field development an environmental impact assessment for the project was prepared (CSIR Report ENV-S-C 2004- 066). In discussion with the Ministry of Mines and Energy it was agreed that consultation should be limited to meetings with the Interministerial Review Group and a public information session to be held in Lüderitz. The following meetings were held:

Joint Energy Africa and Nampower Interministerial Review Group Meeting, Windhoek, 23 March 2004. Interministerial Review Group Meeting, Windhoek, 18 November 2004. Public information session, Lüderitz, 19 November 2004.

5.5 RESULTS OF THE SCOPING PROCESS

This section focuses on issues arising from the proposed Kudu gas field development project. A separate scoping document: Kudu Power Project: Minutes of Public Meetings held at Windhoek, Alexander Bay and Oranjemund, 10th and 11th February 1998 compiled by Walmsley Environmental Consultants details issues mainly arising from the proposed Kudu Power Project.

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Note: The issues listed in each section below have been reported verbatim.

5.5.1 Kudu Gas Field: Size, Economic Life, etc.

Why is it referred to as Kudu gas? What is the size of the gas reserve at the moment? What volume of gas is expected to be produced annually? How certain is the estimate of the size of the gas field? Is there any possibility to extend the life of the proposed Kudu Gas Project i.e. after 20 years? There are rumours that there is more gas and that after 20 years you will probably upgrade or build more plants. Does 20 years refer to the economical lifetime, technical lifetime of the power plant or the gas field?

COMMENTS

Kudu is the name that the original discoverers, Chevron, Texaco and Soekor gave to the find in 1974. The gas reserve is estimated to be 1.8 trillion cubic feet of which at least 60-70% is expected to be recovered. Estimated production will be 90-120 million cubic feet per day i.e. 32-44 billion cubic feet annually. If additional markets can be found then larger volumes could be produced. SEPN proposes to spend more than US $400 million in developing the Kudu gas field. This demonstrates SEPN’s confidence that there are more than sufficient reserves to meet the requirements of the Kudu Power Project. There is sufficient gas to extend the life of the Kudu Power Project after the initial 20 year contract period. Further exploration, seismic surveys and drilling, is planned. It is necessary to prove the existence of additional gas reserves before commitments to any significant expansion are made. If more gas is found, it is likely to be exported to South Africa although additional generating capacity may be built in Oranjemund. The size of the gas field reserves govern the life of the project. There is enough gas to extend beyond 20 years but this is the contract period agreed by the KPP and Kudu gas field development partners.

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5.5.2 Availability of Deep Drilling Technology

Do you have the available technology for drilling and operating at 4 000 m and what is the cost?

COMMENT

Four wells have already been drilled in Kudu to depths in excess of 4 000 m and hence the Project will use proven technology. The wells are expensive because of the depth, with each development well estimated to cost US $ 35 - 40 million.

5.5.3 Design and Capacity of Pipeline

What will be the material of the pipeline? I know that there is a problem with telephone lines being broken by underwater currents. The pipeline is directly in the way of the Benguela current, which is not strong, but during storms is there a possibility of the current breaking the pipeline? What will be the environmental effect of this? Will the capacity of the pipe be an issue if the upgrade to 1 500 MW is contemplated? In terms of the cost of the pipeline, doesn’t the foundation of the pipeline rather than its size cost the most?

COMMENTS

The pipeline will be made of steel. Internal corrosion will be very limited since the gas is not corrosive (it contains no H2S and little CO2). External corrosion will be controlled by the application of an external anti-corrosion coating and the use of sacrificial anodes spaced along the length of the pipeline. The pipeline will be designed to withstand the current. A year-long current measurement programme along the pipeline route has been initiated to ensure that the representative data for near bottom currents is available in advance of the design phase. In high current regions the pipe may be coated with concrete to add weight and thus prevent it from moving on the bottom. Installing a large pipe now would raise initial costs. Should circumstances warrant it a second pipe will be laid, or the capacity of the existing line will be raised by the installation of a compressor at the wellhead. Doubling the capacity of the pipeline will not double the cost of laying it. However, it does not make economic sense to install excess capacity which may not be used for 10-20 years.

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5.5.4 Pipeline Operation

Will you stabilise the pressure by letting off gas? Can you vary the pressure? What is the gas speed or velocity and how do you control the flow?

COMMENTS

Gas vented is money wasted. The process scheme is being designed to avoid venting during normal operations. Venting may only occur during abnormal conditions such as an emergency shutdown of the offshore facilities. The maximum pressure is at the wellhead and the minimum pressure is at the power station. As the pressure decreases so the flow velocity increases. The velocity/flow will be determined by demand. The objective is to provide gas to the KPP at a constant pressure. The complete pipeline will be designed to withstand a pressure which is far higher than that required by the KPP. This, along with the compressibility of the gas, means that it is possible to use the pipeline as if it were a very large storage tank. As a result, the supply of gas to the KPP can be varied without immediately changing the gas rates at the pipe inlet. For changes in KPP demand lasting more than a few hours valves at the wellhead can be used to control the gas entering the pipeline. Maximum pressure is at the wellhead and minimum pressure at the power station: as the pressure decreases so does the flow velocity.

5.5.5 Environmental Impact of the Pipeline

I am concerned about the economic impact of the pipeline through the subsea diamond areas. What is the possible impact of the pipeline on sea currents? Taking silt out into bays? Currents take the silt out, won’t the pipeline change the speed of the tides? Thermal exchange between pipeline and seawater (150°C/12°C). Area of exchange? Effect on marine environment (long term) monitoring?

COMMENTS

Negotiations between Shell and Namdeb are currently taking place in order to optimise the pipeline route i.e. one that does not prevent the mining of diamond-rich areas yet does not incur excessive construction costs. The natural features on the ocean floor are much larger than the pipeline. The only critical area is the dynamic surf-zone. The pipe either will be trenched through this

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area or be constructed above the sea on a pipe jetty with widely spaced supports. Either approach will have a negligible effect on sediment (silt) movement. It is unlikely that the hot gas in the pipeline will have any environmental impact. The heat will be dissipated rapidly by the surrounding very cold sea water, e.g. it is expected that the gas will reach ambient sea temperatures within only 5 km from the offshore platform.

ACTION: The environmental impacts of the laying and operation of the pipeline will be addressed in the environmental impact assessment (EIA).

5.5.6 Effect of the Pipeline on Fishing and Navigation

Bottom trawl, mining and ship traffic: structures and pipeline (need to be) clearly marked. Possible conflict with bottom trawlers and fishermen within exclusion zone around well and pipeline. Information is required concerning the position of the pipeline in relation to the lobster fishing grounds.

COMMENTS

Once the position of the platform and pipeline route have been confirmed a Notice to Mariners will be issued advising shipping of the potential hazard. A 500 m-radius exclusion zone will be enforced around the platform. At present no bottom trawling is permitted in waters of less than 200 m depth in the vicinity of the Kudu gas field (the offshore development is expected to be located in 170 m water depth). Consequently there should be no conflict between the project and fishermen for the foreseeable future. The most likely landfall for the pipeline is immediately north (5-10 km) of the mouth of the Orange River. This is well to the south of the nearest important lobster fishing grounds at Kerbehuk.

ACTION: The potential effect of the pipeline and platform on fishing and navigation will be discussed in the EIA.

5.5.7 Disposal of Effluent from the Gas Conditioning Plant

Will the water which is pumped into the sea have a poison which will kill our fish? Is there a disposal plan for the wastewater which will contain antifreeze? Quality of water to be discharged from onshore facility into the ocean? Effect on intertidal/subtidal in discharge area?

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COMMENT

A number of options for the disposal of water from the conditioning plant are being investigated. The option selected will be influenced by the location of the power station and final processing scheme selected.

ACTION: The potential impact of the selected option(s) will be discussed in the EIA.

5.5.8 Impact of Discharges from Offshore Facility

Effect of released oil (and gas) on marine environment in case of pipeline burst - oil slick? Effect on subtidal/intertidal environment. Dumping of human offal. Excess plastic, etc. Human pollution. Where from? What qualifications? (? regulations). What vetting? Dumping of engineering scrap from rig? Potential “unplanned” discharges from offshore facility.

COMMENTS

The gas contains very small (trace) amounts of condensate and no oil. Hence in the remote event of a burst or leakage the discharge will consist almost entirely of methane. Methane is lighter than air and will disperse rapidly into the atmosphere i.e. the fire risk will be very low. Shell’s environmental management systems and criteria are designed to ensure a high standard of housekeeping and includes regular auditing. Discharges to sea will meet MARPOL criteria for such discharges. No solid waste will be discarded from the rig or platform. Such material will be compacted and brought ashore for disposal in an approved dump site.

ACTION: The impacts and management of waste disposal will be addressed in the EIA.

5.5.9 Handling and Fate of Monoethylene Glycol (MEG) and Condensate

Volume of MEG recycled and transported back to Lüderitz? (Increased road traffic.) What will happen to the stored condensate from the slug catchers?

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COMMENT

At this stage the method of transport for the recycled MEG has not been determined. It could either be by road tanker for transhipment at Lüderitz for return to the platform, or it may be pumped back to the platform via a separate “piggyback” pipeline adjacent to the gas pipeline. Depending on the volume of condensate produced it may either be burnt as fuel in the power station or sold elsewhere.

ACTION: The handling of recycled MEG and the utilization of condensate will be discussed in the EIA.

5.5.10 Safety/Contingency Plans

Will a safety plan (in case of a major disaster) be developed? If so, by who? Contingency plan - medevac. Contingency plan(s) for accidents. Contingency plans related to vessel accidents.

COMMENT

The risks associated with construction and operation of the platform, pipeline and gas conditioning plant will be identified in the EIA. Shell will prepare contingency plans for emergencies associated with all the components and phases of the project.

5.5.11 Post Construction Rehabilitation Plan

Is there a planned rehabilitation programme for post construction?

COMMENT

Rehabilitation plans will be drawn up and implemented both after the construction phase of the project has been completed, and at the end of the project life. The wellheads and the platform will be removed. The pipeline will be left in a condition such that it poses no environmental or safety risks. As a minimum hydrocarbons will be displaced by an inert material and a system will be provided to ensure that no pressure remains in the pipeline. The gas conditioning plant and terrestrial pipeline will be dismantled at the same time as the power station.

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5.5.12 Effect on Transport Infrastructure

Will there be any impact on Oranjemund/Alexander Bay aerodrome, i.e. increased traffic? Duration and volume of increase in harbour traffic (in Lüderitz) during construction (of the platform and pipeline).

COMMENT

The airfields at Oranjemund and Alexander Bay have sufficient capacity to handle the increase in traffic that might occur during the construction phase. The use of Lüderitz harbour as a base for the gas field development (installation of the platform and laying of the pipeline) will depend upon the facilities available at the port during the construction period and upon the competitive situation.

5.5.13 Greenhouse Effect

CO2: Greenhouse effect - change in global weather.

COMMENT

While burning Kudu gas will add to greenhouse gases in the atmosphere, in terms of the overall input to the atmosphere it will be negligible. It is also to be noted that the use of gas is a far cleaner method of generating power than the coal-based stations that provide the bulk of the electrical power in southern Africa.

5.5.14 Desalination Plant at Lüderitz

Possibility of power to Lüderitz for desalination plant.

COMMENT

The Kudu gas field development and CCGT power station projects are commercial ventures. Supply of power for a desalination plant is not being considered as part of these projects. However, should the Namibian Government locate a desalination plant in Lüderitz, power to operate it may be supplied from the Kudu Gas-to- Electricity scheme.

5.5.15 Sperrgebiet Management Plan

(Will there be) co-ordination with Sperrgebiet land management plan?

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COMMENT

Planning and execution of the gas field and power station projects will take full cognizance of the Sperrgebiet and other environmental and spatial development (management) plans.

5.5.16 Relationship between Kudu and Kunene (Epupa) Projects

Will the Kudu Project eliminate the need for the Kunene hydroelectric project?

COMMENT

The Kudu Project is not designed as an alternative to the Kunene Project and questions relating to the Kunene (Epupa) Project should be addressed to the Namibian Government.

5.5.17 Research Co-operation

Possibility of research co-operation e.g. automatic weather station on offshore facility.

COMMENT

Shell will consider any well-motivated proposal for research co-operation e.g. the automatic weather station mentioned above.

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Part A, Section 6: Environmental Impact Assessment

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Part A, Section 6: Environmental Impact Assessment

6. ENVIRONMENTAL IMPACT ASSESSMENT ______6-1

6.1 INTRODUCTION ______6-1 6.2 DEVELOPMENT ______6-1 6.2.1 Supply Base ______6-1 6.2.2 Production Drilling______6-2 6.2.2.1 Mooring of the semi-submersible drilling unit/production platform______6-2 6.2.2.2 Interference with shipping and fisheries______6-3 6.2.2.3 Interference with nocturnal animals______6-4 6.2.2.4 Disposal of drilling muds and cuttings, and surplus cement ______6-5 6.2.2.5 Waste discharges to sea and atmosphere______6-7 6.2.2.6 Discharge of wastes to land ______6-10 6.2.2.7 Helicopter operations ______6-11 6.2.3 Production Facilities ______6-13 6.2.3.1 Phase 1 Development ______6-13 6.2.3.2 Phase 2 Development ______6-13 6.2.4 Submarine Pipeline______6-13 6.2.5 Landfall Structure ______6-14 6.2.6 Onshore Pipeline______6-14 6.2.7 Onshore Gas Conditioning Plant ______6-15 6.3 PRODUCTION______6-18 6.3.1 Production Drilling______6-18 6.3.2 Operation of the Subsea Production Facility______6-18 6.3.3 Pipeline ______6-18 6.3.4 Gas Conditioning Plant ______6-19 6.4 DECOMMISSIONING ______6-20 6.5 CONCLUSIONS AND RECOMMENDATIONS ______6-20 6.5.1 Key Finding ______6-20 6.6 RECOMMENDATIONS ______6-20 6.7 REFERENCES ______6-22

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Figures

Figure 6.1: Orange River mouth and environs showing Ramsar site, airports and sensitive bird habitats____ 6-12 Figure 6.2: Location of the CCGT power station site at Uubvlei. ______6-16 Figure 6.3: Route of gas pipeline from the landfall to the gas conditioning plant at Uubvlei. ______6-17

Tables Table 6.1: Summary of Impacts: Normal Operations ______6-21

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6. ENVIRONMENTAL IMPACT ASSESSMENT

6.1 INTRODUCTION

The objectives of this environmental impact assessment are:

to identify any interactions between all phases of the life cycle (development, production and closure) of the Kudu gas field development project and the environment; to consider which of these, if any, are likely to have a negative impact on the environment; to recommend the measures which can be taken to avoid or mitigate any adverse impact and to ensure adequate protection of the environment under routine and non- routine operational conditions.

6.2 DEVELOPMENT

6.2.1 Supply Base

It is planned to use the Port of Lüderitz as a supply base for the drilling of up to four Phase 1 production wells as well as for the laying of the gas pipeline, and subsequently during the life time of the gas field.

In the past the Port of Lüderitz suffered from periodic congestion. Concern was expressed that the supply vessels serving the drilling units would add to the problem. However, a new deepwater quay has been constructed and should enable Lüderitz to serve as the base for drilling the production wells. Walvis Bay was the base for the supply vessels during the drilling of the Kudu-4 and -5 exploration wells. However, Lüderitz was used successfully as the supply base during the drilling of Kudu-6 and Kudu-7 appraisal wells.

Potential impacts

The use of the Port of Lüderitz as a supply base could have the following impacts:

Increased port congestion (ship’s berths); Demand for storage space in the port; Demand for accommodation; Demand for potable water; and Spillage of materials and chemicals in the pipe fabrication yard.

Mitigation measures

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Discussions will be held with the management of the Port of Lüderitz to ensure that there will be adequate berth and storage space throughout the project life cycle, particularly the development phases.

The demand for accommodation will be limited to that necessary for the personnel operating the supply base and the pipe preparation yard. It is not foreseen that this accommodation requirement will have an adverse effect on the accommodation availability in Lüderitz.

The availability of fresh water is always a matter of concern for the town of Lüderitz. It is possible that the water requirements of the development phase of the Kudu gas field will not be able to be met by this source. Fresh water may have to be obtained from either Walvis Bay or Cape Town.

Any spillage of hydraulic fluid used to perform pre-commissioning checks on the subsea control system before it is sent offshore will be cleaned up by using for example absorbent materials. Spillage of materials in the pipe preparation yard will be managed by ensuring that all dry (powder) materials are screened from the wind during handling and use. The impact of the yard is expected to be negligible.

6.2.2 Production Drilling

An environmental impact assessment (EIA) for exploration drilling in Licence Area 2814A was completed in 1996 (CSIR, 1996). This report provides a full description of typical drilling operations, the materials used (drilling mud composition, etc.) and the interactions with the environment. At the specific request of NAMCOR the EIA included a detailed study of the trajectory and fate of hypothetical oil spills (well blowout) originating from the well site. A further EIA for gas exploration and appraisal drilling in Licence Area 2814A was completed in 2001 (Shell E&P Norway and DNV, 2001). This EIA included the results of mathematically modelling the dispersion of discharged drilling muds and cuttings.

Plans have been developed to drill two exploration wells which will not be different in operations and impact from the planned production wells. Consequently the Ministry of Mines and Energy has approved that this EIA will be deemed to cover these activities as well.

The present plan (Phase 1) is to drill up to four sub-sea production wells using a semi- submersible drilling unit. A further four wells may be drilled in Phase 2 of the gas field development programme.

6.2.2.1 Mooring of the semi-submersible drilling unit/production platform

Potential impacts:

An array of eight anchors will be used to position the drilling unit to and keep it in place throughout the drilling operation. The impact of the anchors on the environment will be negligible,

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the area disturbed by them can be expected to be rapidly recolonised by benthic organisms after their removal.

Impact evaluation:

The impact on the benthic populations will be negligible.

6.2.2.2 Interference with shipping and fisheries

The Kudu gas field lies to the east of the main shipping lanes from the Cape to the Northern Hemisphere and west of the coastal shipping route between the Cape and Namibia. The gas field does, however, coincide with hake and tuna fishing grounds.

Potential impacts:

The presence of the platform and/or drilling unit and its supply vessels travelling plying between the platformto and from and Lüderitz and/or Walvis Bay in waters used by fishing and other vessels could result in:

damage to fishing gear and to vessels caused by collisions with the unit and/or the supply vessels; damage to the unit and/or the supply vessels caused by fishing gear or vessels.

Impact evaluation:

The well sitegas field area is located in a water depth of 170 m which lies inshore of the trawling zone which is demarcated by the 200 m isobath, i.e. trawling is confined to waters deeper than 200 m. The only vessels likely to be operating in the vicinity of the Kudu gas field are those of the hake and tuna fleets (see Chapter 3, Section 3.1.3.5 Fishing Activities, offshore hook-and-line fishing). The numbers of hake and tuna vessels that operate in the area of the gas field is small, approximately 20 – 25 licenced vessels of each type.

Mitigation measures:

The drilling unit to be used by Energy Africa in the Kudu gas field will be certified for seaworthiness through an appropriate internationally recognized marine certification programme. The certification as well as existing Energy Africa standards will require that safety precautions are taken to minimise the possibility of an offshore incident or accident. Collision prevention equipment includes multi frequency radio, foghorns, etc. Additional precautions include a 24-hour standby vessel, 24-hour watches, the establishment of a 1000 m-radius exclusion zone around the unit, cautionary notices to mariners, and access to current weather service information. The unit will be fully illuminated during twilight and at night. Equipment and training to ensure the safety and survival of the crew in the event of an accident will also be required and provided.

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6.2.2.3 Interference with nocturnal animals

Seabirds, fish and cephalopods (squid) may be attracted to the operating lights and the gas flare of the drilling unit during the short periods that is in use.

(i) Drilling unit illumination

Potential impacts:

Drilling is a continuous operation. The strong lighting used to illuminate the unit at night could disturb and disorientate pelagic seabirds feeding in the area. Fish and squid may be drawn to the lights where they may be more easily preyed upon by other fish and by seabirds.

Impact evaluation:

Although collisions between seabirds and the drilling unit are unlikely, little can be done to prevent this from occurring. The overall impact on seabird populations will be negligible.

The significance to the populations of fish and squid of increased predation as a result of being attracted to the unit’s lights is likely to be insignificant.

Mitigation measures:

Shielding and/or reducing the number of lights shining directly down onto the water would reduce the number of fish and squid drawn to them.

Disorientated, but otherwise unharmed, seabirds should be recovered and kept in dark containers (e.g. cardboard boxes) and released during daylight. Injured birds should be destroyed humanely. Ringed/banded birds should be reported to the appropriate ringing/banding scheme. All dead birds should be refrigerated and made available to the State Museum, Windhoek for research purposes.

(ii) Gas flare

Migratory land birds may be attracted to light sources at night, especially under conditions of low visibility caused by fog or mist (e.g. Merrie 1979, Verheijen 1981). Where the light source is a gas flare, mortalities by incineration could occur, although it is now considered that early accounts of the dangers of this were exaggerated (Bourne & Merrie 1978, Bourne 1979, Hope Jones 1980, 1981, Bourne 1982).

Since the Kudu gas field lies far offshore and there are no known migratory routes for land birds in the vicinity, incineration of land birds is unlikely to occur, although it is possible that occasional land birds, blown out to sea by poor weather conditions, will be attracted from time to time to the drilling unit, either as a resting site or by the gas flare itself.

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Gas flares seem not to cause harm to seabirds. No records of seabirds being incinerated or otherwise adversely affected were have been located. However, seabirds are attracted to the sea surface below gas flares at night to feed on plankton and other organisms undergoing diel vertical movements. Hope Jones (1980) and Bourne (1982) report Northern Fulmars Fulmarus glacialis, Greater Blackbacked Gulls Larus marinus, Herring Gulls L. argentatus, Blackheaded Gulls L. canus and Kittiwakes Rissa tridactyla as being attracted in this way in the North Sea.

Impact evaluation:

Flaring will only take place towards the end of the drilling period to clean out the well bore and will be of short duration (hours). Consequently, the period during which the flare potentially poses a hazard to seabirds will be limited. The impact on the seabird population of the area will be negligible.

Mitigation measures:

No practical measures to reduce this potential impact can be implemented, although if practical flaring could be carried out during daylight hours to reduce the possibility of attracting bird and sea life.

6.2.2.4 Disposal of drilling muds and cuttings, and surplus cement

The total amount of cuttings to be disposed of is approximately 530 m3 for each drilled production well. Mud will be recycled but some drilling mud is always lost with the cuttings. Mud will also be discharged at an intermediate stage in the drilling programme and on completion of each well. The total volume of mud that will be discharged should be no more than approximately 600 m3.

The processes which determine the ultimate fate of drilling-derived particulates include the particle size distribution, initial plume dynamics, passive current transport, wave-current re- suspension, chemical weathering, bioturbation, burial and biological uptake. Other effects that also may have an influence are flocculation and density gradient influenced effects (Coats, 1994).

Immediately on contact with seawater, the majority of cuttings material sinks rapidly to the sea bottom near to the discharge point. Much of the mud adhering to the cuttings together with the finer particles will wash out during this sinking process and form a turbid plume. A typical plume extends some 30 - 40 m vertically, is 40 - 60 m wide and extends 100 - 4000 m from the discharge point. Estimates of dilution in the plume indicate that concentrations of solids are 3 - 4 orders of magnitude less at 50 m from the discharge point, than at the point itself. This is supported by the findings of studies off Point Conception, California (Coats, 1994) which suggest that drill cuttings are dispersed over a wide area thus significantly reducing their impact: Platform Hidalgo in approximately 180 m of water was surrounded by a 200 km2 “footprint” aligned roughly along the isobaths. The footprint was the result of ca.12000 m3 of drilling mud discharged over three years (Coats, 1994). An interesting feature of the study is that the depositional flux of drilling muds represented less than 2% of the total particulate flux indicating that, amongst others, a dynamic benthos responsible for resuspending sedimentary material. A benthic survey of the Kudu gas field area was conducted in 2002 which demonstrated that the benthic fauna is highly diverse, 104 species being identified (ERM, 2002).

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Following cementing of the casing excess cement will be circulated out of the well bore and discharged into the sea.

Potential impacts:

The benthic fauna of the Kudu gas field was surveyed by ERM (2002). The survey showed that a large number of species occur in the area: 104 species of 21 orders in nine phyla were identified. This benthic macrofauna consists of four distinct communities whose distribution could not be correlated with substratum particle size.

A study of the benthic communities in the Atlantic 1 Diamond Mining Licence Area, which will be traversed by the gas pipeline, was conducted by Field et al. (in Environmental Evaluation Unit 1996). The study area lay approximately 18 nautical miles off the coast in water depths of 110- 130 m. In terms of their contribution to benthic production the following phyla were the most important:

Annelida, e.g. the polychaete worm Terebellides spp. Mollusca, e.g. the gastropod Nassarius spp. and the bivalve macoma spp. Crustacea, e.g. the crab Hippomedon spp. and the amphipod Ampelisca spp.

The Atlantic 1 area is notable for its almost complete lack of echinoderms. This may be a consequence of the characteristically oxygen-deficient shelf-water along the west coast of southern Africa.

A modelling study of the discharge of drilling muds and cuttings in the Kudu gas field area, conducted by Shell E&P Norway and DNV (2001), showed that deposition of both the cuttings themselves and the sedimentation of particulates in the plume, may exert a smothering effect on benthic organisms within approximately 200 m of the discharge point. The primary impact, therefore, particularly from the smaller particles, is physical, such as clogging of fish gills, and smothering of filter feeding animals. However, the effects will be transient and, in the absence of toxic components, recolonisation will be rapid.

Chemical effects caused by mud and cuttings waste will depend on the toxicity of the mud additives and the dilution following discharge. Drilling mud additives also contain heavy metals, mostly as impurities in barite and bentonite as impurities. Most organisms actively swimming in the water column are exposed only for very short periods, minutes rather than hours. Floating planktonic organisms such as small crustaceans and algae that cannot avoid the plume are exposed for the period of time they float through the plume. Fixed benthic organisms will be most affected by chronic exposure to these chemicals.

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Mitigation measures:

Widespread sedimentation will be prevented by centrifuging the returning mud to remove as much of the finer drilled particles as possible, i.e. optimally recycled for use downhole, thereby minimising mud disposal.

Chemical (toxic) effects caused by the dumped waste mud will be mitigated by the use of water- based rather than the more toxic oil-based drilling muds, and by using low toxicity mud additives. The drilling mud will be formulated to meet the International Finance Corporation’s Environmental, Health and Safety Guidelines: Oil and Gas Development (Offshore) which set 96 hr LC-50 toxicity limits for the drilling fluid, and mercury (1 ppm Hg) and cadmium (3 ppm Cd) limits for barite.

Cleaning the mud and optimal recycling for use downhole will minimise the quantities of mud to be disposed of and thereby reduce the concentrations of mud chemicals in the water.

The low toxicity of the mud and cement chemicals, the dilution factor upon disposal, and the very short exposure times of actively swimming organisms, combine to make the risk of toxic effects to these species insignificant. Although individuals in the floating planktonic community may be at risk, overall effects at the population level are not significant.

Further to the approval of the first version of the EIA in terms of the Petroleum (Exploration and Production) Act, 1991 and in consultation with other Ministries with responsibility for marine environmental protection the Ministry of Mines and Energy has given explicit approval for the discarding offshore of water based muds and cuttings in terms of the Petroleum (Exploration and Production) Amendment Act, 1997.

6.2.2.5 Waste discharges to sea and atmosphere

[MARPOL standards for discharges to the atmosphere and to sea are presented in Chapter 4, Section 4.1.11].

(i) Gaseous emissions

Potential impacts:

Diesel fuel is used aboard the drilling unit and the supply vessels for fuel for generators and motors. Diesel exhaust gases comprise SO2, CO and CO2 and NOx, plus “carbon-black” (soot) which contains some polyaromatic hydrocarbon particulates. There is some concern that soot is carcinogenic.

Burning of waste, e.g. domestic packaging materials, aboard can release soot as well as CO,

CO2 and possibly dioxins depending upon the composition of the materials to be burned.

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The well flow testing will release CO2, CO, NOx and traces of (unburned) hydrocarbons. These compounds are known to contribute to atmospheric problems such as the greenhouse effect, ozone depletion etc. The gas does not contain any sulphur.

Mitigation measures:

Diesel motors and generators will be adequately maintained such that the exhaust gases contain the minimum of soot, and are vented to the open air.

(ii) Deck drainage

Potential impacts:

Water washing off the deck areas of the drilling unit could contain small amounts of oils, solvents, cleaners, drilling mud additives etc., which are potentially toxic to marine organisms.

Mitigation measures:

The oily water system is designed to collect waste waters for treatment prior to discharge to sea.

Any spillage of diesel, cleaning solvents or mud chemicals on the supply vessels could end up in the sea. The risk of contaminants washing off the decks to the sea is combatted by ensuring that all crew members are aware of the possibilities for contamination arising from spills, and that they mop up spills completely as soon as they occur. Biodegradable detergents, low in toxicity, will be used preferentially.

(iii) Machinery space drainage and ballast water

Small quantities of oil, such as diesel fuel from engines, lubricants, grease etc. used aboard the drilling unit could enter the marine environment.

Potential impacts:

Oil is a complex mixture of hydrocarbons. Once oil is released into the marine environment, transformation of the molecular structure and composition occurs, mediated by photo-chemical and microbial processes, forming reactive radicals potentially toxic intermediate peroxides and hydroperoxides and oxidation products such as carboxylic acids, esters, oxygenated aromatics, carbonyl compounds and carbon dioxide. Many marine microorganisms such as bacteria can metabolise hydrocarbons to some degree, and rapid biodegradation of certain oil fractions can occur. Other fractions are relatively persistent.

Low concentrations of petroleum hydrocarbons in water are readily absorbed or ingested by most marine organisms, with significant concentrations being taken up in a few hours. Deposit and filter feeding animals take up substantial amounts from the water column, with environmental factors such as temperature and salinity affecting uptake rates. Many marine organisms possess mixed-function oxidase systems (MFOs) which activate and/or deactivate absorbed

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hydrocarbons; these MFOs may determine the sensitivity or tolerance of the particular organism to hydrocarbons, and the rate of metabolism and/or bioaccumulation in the organism.

The toxicity of the water soluble fraction of oil to marine life varies with species, stage and development of the individual and environmental factors. Generally:

fish and decapod crustaceans are the most sensitive species to chronic exposure, but those in warmer water (18-22°C) are somewhat more tolerant; in acute toxicity tests, the 96h LC50 of crude oil (soluble aromatic fraction) is in the range 1 - 10 mg/R, for flora, finfish, crustaceans, bivalves, gastropods and other benthic invertebrates. 96 h LC50 values for larvae (all species) is in the range 0.5-5 mg/R, and for juveniles 5-10 mg/R (Miller, 1982); inter-tidal species are more tolerant than sub-tidal species.

The vertical distribution and concentration of hydrocarbons in the water column after any discharge depends on the temperature and salinity of the water, the turbulence of the water and the chemical composition of the discharged oil (National Research Council, 1989; Delvigne, 1988).

Mitigation measures:

The drilling unit and supply vessels will comply fully with internationally agreed standards regulated under MARPOL 73/78 (IMO, 1990).

Annex 1, Regulations 9 and 21 for ships outside special areas stipulate that the oil content of discharges originating from machinery space drainage of vessels will not exceed 100 ppm (mg/l) without dilution. This would cover oily wastes from generators, fuel tanks and pumps (Read, 1985).

Machinery space drainage is led through an oily water filter. Discharges are monitored and limited to 15 mg/ℓ oil in water which complies with MARPOL requirements. Negative effects of these concentrations are expected to be restricted to a few metres from the discharge point and are therefore considered negligible.

(iv) Sewage

Potential impacts:

Untreated sewage poses an organic and bacterial load on the natural degradation processes of the sea. Many marine microorganisms such as bacteria metabolise sewage, resulting in rapid biodegradation. The availability of raw sewage as a food source lead to a rise in bacterial levels in the water and an increased demand for oxygen. Treated sewage also poses an increased biological oxygen demand (BOD), but no bacterial load.

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Mitigation measures:

All sewage will be properly treated according to MARPOL requirements prior to disposal at sea.

(v) Galley wastes

Potential impacts:

Galley waste comprises biodegradable food waste which can pose an organic and bacterial load on the sea. Untreated galley waste can attract large number of seabirds (gulls) which may become a hazard to helicopter operations.

Mitigation measures:

According to MARPOL 73/78, biodegradable food waste macerated to less than 25 mm size can be disposed of to the sea at a distance of more than 12 miles (22 km) from shore. Maceration increases the availability of the food waste to marine organisms which utilise this as a food source; without maceration, the waste is subject to slower natural biodegradation processes.

6.2.2.6 Discharge of wastes to land

(i) Solid waste

Solid waste comprises non-biodegradable domestic waste, packaging materials and industrial waste from operations.

Potential impacts:

Solid wastes pose a hazard to seabirds and larger marine life as it, may contain chemical contaminants. It and may also constitute a visual pollutant as flotsam, before ending up on the shore or on the sea bed.

Mitigation measures:

The generation of solid waste will be minimised by using materials with the minimum of packaging material.

Chemically contaminated waste such as empty drums which had contained drilling mud and cement additives will be rinsed (the rinse water can be added to the drilling mud), punctured and will be packaged on board, stored separately in skips and brought to shore by the supply vessels for disposal at the municipal landfill site at Lüderitz and/or Walvis Bay . This will apply to the operations associated with the drilling of production wells. It is possible that Lüderitz will be used as a base for the drilling of the production wells.

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All other domestic and industrial rubbish e.g. empty sacks and other containers will be packaged on board, stored and sent ashore by supply vessels for disposal at the municipal landfill site at Lüderitz and/or Walvis Bay.

(ii) Chemicals and hazardous wastes

No chemical or hazardous wastes are expected to be generated other than those that have been addressed elsewhere in this report. Caustic soda, a drilling fluid component, will be disposed of at sea where dilution and the buffering capacity of seawater will effectively mitigate any localised effect on the pH. Disposal of any unexpected hazardous substance will be done on a case-by- case basis using specialist waste disposal contractors.

6.2.2.7 Helicopter operations

Crew changes will be effected by transfer by helicopter transfer from Oranjemund.

Potential impacts:

Low altitude overflying of seabird and seal colonies can cause disturbances leading to mortalities of the young of these animals. Cormorants, gannets and penguins may abandon their nests temporarily thereby exposing the eggs and chicks to predation by Kelp Gulls. Seal pups may be crushed to death by panicking adults heading for the safety of the sea.

Mitigation measures:

Maintain an altitude of not less than 500 m within 2 km of the island seabird colonies. Seal colonies should not be overflown at altitudes of less than 300 m. Similarly, whenever possible an altitude of 300 m should be maintained over the Orange River wetlands between the Opperheimer Bridge and the sea.

The aircrew of the helicopter company contracted to service the drilling unit should be informed that the Orange River mouth is a Ramsar site of high conservation value. Maps indicating the areas most sensitive to disturbance by aircraft should be distributed to the pilots (Figure 6.1). Pilots should be instructed not to fly over the most sensitive areas in the estuary unless under special circumstances, i.e. emergencies. The wetland should only be crossed at the northern end of the designated Ramsar area since the largest concentrations of waterbirds occur at the southern end. No low flights should follow the central axis (north-south) unless under special circumstances. Pilots should avoid flying over any large flocks of birds especially flamingos, pelicans and terns.

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Figure 6.1: Orange River mouth and environs showing Ramsar site, airports and sensitive bird habitats

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6.2.3 Production Facilities

6.2.3.1 Phase 1 Development

The subsea production system for the Phase 1 development (Chapter 2, Section 2.4) will be remotely controlled from Uubvlei.

Potential impacts:

An extremely limited impact on the benthic community in the vicinity of the tie back pipelines may occur.

Mitigation measures:

There is no realistic mitigation measure for the benthic community.

6.2.3.2 Phase 2 Development

The Phase 2 development will be similar to Phase 1. The potential impacts and mitigation measures are the same as for Phase 1 (see Section 6.2.1).

6.2.4 Submarine Pipeline

The pipeline will be laid from the landward end and will terminate at the gas field some 170 km offshore. At this stage the design of the landfall structure has not been selected (see Section 6.2.5 below). The landfall structure acts as an “anchor” from which the pipelaying barge lays the pipeline. The pipeline will be laid in a continuous operation (see Chapter 2, Section 2.5) along a pre-selected route to be identified by a geophysical and geotechnical survey.

Potential impacts:

Effect on benthos: The pipeline will be laid directly on the seabed and thus will “smother” all organisms which lie in its path. However, the impact will be negligible. By contrast De Beers Marine Namibia mines approximately 3 km2 of the Atlantic 1 Mining Lease (through which the pipeline will pass) per annum.

Effect on diamond mining: The pipeline will not be laid in an actively mined area, however it may pass close to such operations.

Mitigation measures:

Effect on benthos: There are no practical mitigation measures which can be applied.

Effect on diamond mining: Close liaison with De Beers Marine Namibia is essential to ensure that each party’s vessels keep well clear of each other.

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6.2.5 Landfall Structure

A number of options for the pipeline landfall are discussed in Chapter 2, Section 2.6. These include:

dredging a trench through the surfzone up to the backshore area; jetting the pipe into the seafloor by eroding the sediments with high pressure water jets.

Potential impacts:

From an environmental impact perspective there is little difference between the various options for the pipeline landfall. The main impact will arise from the construction activities rather than from the finished structure. However, since the pipeline landfall will be located in an area already heavily disturbed by diamond mining the environmental impact will be negligible. The most significant potential impact could be on Namdeb’s mining operations in the immediate vicinity of the pipeline.

Mitigation measures:

The key is to minimise the scale of the impact on Namdeb’s operations as far as possible. The construction area must be kept as small as is consistent with being able to execute the construction of the landfall structure cost-effectively. This will also minimise the potential impact on the African Black Oystercatcher. A management plan for the construction site must be drawn up, in consultation with Namdeb as necessary.

This management plan must provide details of:

site demarcation - the construction contract must include clauses to prevent and/or penalise unnecessary or unauthorised excursions from the area;

the construction operations e.g. earthmoving, cement mixing, raw materials storage, etc.

day-to-day management of the site, e.g. refuse and sewage disposal, vehicle servicing, etc.

6.2.6 Onshore Pipeline

A site within Diamond Area 1 at Uubvlei has been selected as the site for the location of the CCGT power station. This is Site D (now known as the CCGT site) which is This site lies some 25 km north of Oranjemund and approximately 500 m from the sea (Figure 6.2).

The route of the pipeline from the landfall to the gas conditioning plant adjacent to the CCGT power station is shown in Figure 6.3. The pipeline will be constructed to ASME standards and will have a designed safe operational life of at least 30 years. The pipeline will be buried along

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those sections of the route where there could be the risk of accidental damage e.g. by heavy haulage vehicles.

6.2.7 Onshore Gas Conditioning Plant

The location of the Gas Conditioning Plant and associated slug catchers preferably has to be next to the power station and is, therefore, entirely dependent upon the site chosen for the power station. Essentially the impacts arising from the construction of the gas conditioning plant will be the same as those from construction of the power station. The following discussion of impacts arising from construction at the CCGT site is based on the findings of the Environmental Impact Assessment for the CCGT Power Station (CSIR, 2005).

Potential impacts:

The main impacts which may result from construction at the CCGT site and the related cooling water abstraction and discharge points are:

the impact of accommodating the workforce on services, safety and security, community facilities and social integration; the impact of heavy haulage vehicles delivering materials to the construction site. the impact of noise and dust generated by construction activities.

Mitigation measures:

The prime objective should be to minimise the spatial impact of the construction operations by clearly demarcating the boundaries of the site and preventing and/or penalising unauthorised excursions from it.

Good housekeeping on site is essential and a detailed environmental management plan for the site and construction operations must be drawn up. The plan should include measures for disposal of sewage, refuse, waste lubricants and hydraulic fluids, stormwater run-off, etc.

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Figure 6.2: Location of the CCGT power station site at Uubvlei.

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OS 04 U1

Figure 6.3: Route of gas pipeline from the landfall to the gas conditioning plant at Uubvlei.

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6.3 PRODUCTION

6.3.1 Production Drilling

The EIA for exploration drilling (CSIR 1996) and appraisal drilling (Shell E&P Norway and DNV, 2001) in Licence Area 2814A concluded that normal drilling operations effectively will have no impact on the environment. Essentially a drilling unit differs little from a ship with a crew of 90 lying at anchor for 2 - 3 months. The discharge of drilling mud and cuttings will have a spatially limited short to medium term impact on the benthic fauna. However, in comparison with marine diamond mining operations which entirely disrupt the sedimentary structure, the impact is insignificant.

6.3.2 Operation of the Subsea Production Facility

The subsea production facility will be controlled from Uubvlei and integrated with the operation of the gas conditioning plant.

Potential impacts:

Interference with fishing activities: The gas field, with the wellheads standing up to 5 m above the sea floor, poses a potential hazard to bottom trawlers. Technically no trawling should occur in the gas field area as it lies with the no-trawling zone, i.e. inshore of the 200 m isobath.

Operation of the well control system: The well control system is operated hydraulically with the hydraulic fluid being discharged into the water column on completion of each operation. The impact of the hydraulic fluid discharges is likely to be negligible since the total volume of fluid discharged is estimated to be 21 m3 per year (see Chapter 2, Section 2.11.1).

Mitigation measures:

Interference with fishing activities: An exclusion zone around the well field will be proclaimed and communicated to the fishing industry both directly and by means of a Notice to Mariners.

Operation of the well control system: A low toxicity water-based hydraulic fluid (96 hr LC50 > 1020 mg/ℓ), approved for use in the North Sea and in other locations where stringent requirements apply, will be used. In addition only small volumes of hydraulic fluid, out of the total annual volume of 21 m3, will be released per operation.

6.3.3 Pipeline

The pipeline will be an inert structure resting on the seafloor. The pipeline has a design life of 25-30 years i.e. equivalent to the life of the gas field.

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Potential impacts:

There will be no discharges from the gas pipeline and the piggyback MEG pipeline during normal operations. Fluids would only be released in the event of a leak or rupture as a result of an impact from an anchor or a trawl board.

Mitigation measures:

An exclusion corridor 250 m in width on either side of the pipeline through the Atlantic 1 diamond mining concession is being negotiated with Namdeb. At present no bottom trawling is permitted inshore of the 200 m isobath thus trawlers pose no threat to the pipeline. However, should inshore trawling be permitted an active information programme to alert the fishing industry of the location of the pipeline should be initiated in addition to the formal Notice to Mariners.

Emergency shut down (ESD) valves are provided to manage the pipeline in the event of a leak. Immediately upon detection of a leak, the gas production will cease and the pipeline isolated from the wellhead(s) and the treatment plant.

6.3.4 Gas Conditioning Plant

The gas conditioning plant is designed to deliver dry methane to the CCGT power station at Uubvlei. The conditioning plant removes water and hydrocarbon condensate from the gas, recovers the MEG (“antifreeze”) for recycling, and dries the gas.

Potential impacts - commissioning phase:

During the approximately 5 – 6 month commissioning period of the first of the two turbines of the power station any gas in excess of the minimum production volume necessary to operate the production system, in particular the multi-phase pipeline, has to be flared. The volume is subject to the final turbine selection but could be up to a maximum of approximately 2,997 mmscf in total over approximately 85 days amounting to a daily average of approximately 35 mmscfd.

The impact of this flaring will be limited to the commissioning phase and will be contained within the fenced flame installation. The overall environmental will be insignificant since methane is a clean-burning gas with no particulate residues.

Mitigation measures:

A fence will be installed around the flare, based on the heat radiation calculation, to ensure that personnel cannot enter. The distance of the fence from the flare, 225 m, is based on not exceeding a maximum noise level of 85dB(A) at the fence. The maximum expected heat intensity at the fence is 0.1kW/m2, resulting in an insignificant temperature increase. This is significantly below the level of 1.58kW/m2 which is reckoned to be safe for an exposure of up to 12 hours.

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Potential impacts - operational phase:

The waste- and by-products from the gas conditioning plant are (see Chapter 2, Section 2.4):

Waste products - condensed water: 900 bpd max ≅ 143 m3/day - free and dissolved hydrocarbons < 10 mg/litre average By-products - condensate: 300 bpd ≅ 48 m3/day - MEG (recycled).

Mitigation measures:

No water from the gas conditioning plant will be discharged to sea. The water will be discharged in the form of vapour via a heater exhaust stack. At maximum gas production of 140 MMscft vapour production will be at the rate of 6100 kg/hr but under typical operating conditions it is more likely to be 3000 kg/hr. The water vapour will contain 0.3 ppm hydrocarbons (95% methane) and 650 ppm MEG.

6.4 DECOMMISSIONING

Plans for the decommissioning and abandonment of the wellheads in the gas field, the removal of the floating production system, the pipeline itself, the shore crossing structure (if any) and the gas conditioning plant will be drawn up when the design of the structures has been finalised.

6.5 CONCLUSIONS AND RECOMMENDATIONS

6.5.1 Key Finding

Normal operations will have a negligible impact on the environment. A summary of the potential impacts is presented in Table 6.1.

6.6 RECOMMENDATIONS

Implement an Environmental Management Plan (EMP) for all project phases i.e. development, production and decommissioning. Implement Energy Africa Kudu Limited’s EHS policy, in all aspects of the operation. Implement the Waste Management Plan for all aspects of the operation which will comply with the International Finance Corporation’s Environmental, Health and Safety Guidelines: Oil and Gas Development (Offshore) and the World Bank Group’s Pollution Prevention and Abatement Handbook: Guidelines for Oil and Gas Development (Onshore). Audit the operation of all project phases and components to ensure compliance with the EHS policy, procedures, standards, etc. and with the waste management plan. Follow international and national requirements for maritime safety and communications.

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Well abandonment procedures must ensure that the wells are securely plugged and that no structures protrude above the seabed.

Table 6.1: Summary of Impacts: Normal Operations

ENVIRONMENTAL IMPACT MITIGATION COMPONENT Benthos Negligible Avoid use of oil-based drilling muds and toxic compounds in drilling mud. Fish eggs and larvae Negligible - Fishing industry Negligible Advise mariners and fishermen with regard to location of production facilities and pipeline and their exclusion zones and corridors respectively. Birds Negligible Helicopters to avoid overflying wetlands. Whales and dolphins Negligible Supply vessels to avoid whales whenever possible. Seals Negligible - Terrestrial Minimal Rehabilitate terrestrial pipeline route environment Wetlands Negligible Helicopters to avoid overflying wetlands. Intertidal zone None Recreation/tourism None - Angling/coastal None - resource utilization

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6.7 REFERENCES

BOURNE, W R P (1979). Birds and gas flares. Mar. Poll. Bull. 10: 124-125.

BOURNE, W R P (1982). Birds at North Sea oil and gas platforms. Mar Poll. Bull. 13: 5-6.

BOURNE, W R P and MERRIE, T D H (1978). Birds and offshore oil platforms. Br. Trust Orn. News. 94: 5.

COATS D A (1994). Deposition of drilling particulates off Point Conception, California. Marine Environmental Research 37: 95-127.

CSIR (1998). Environmental Impact Assessment for the proposed Kudu Gas Field Development Project on the Continental Shelf of Namibia. Prepared for SEPN. Stellenbosch. CSIR Report No. ENV-S-C 98053 (revised June 2001).

CSIR (2005). Environmental Impact Assessment of Proposed Kudu CCGT Power Plant at Uubvlei, near Oranjemund, Republic of Namibia. Stellenbosch. CSIR Report ENV-S-C 2005-057.

DELVIGNE, G A L (1989). Measurements on natural dispersion. In: Oil Dispersants, New Ecological Approaches (M. Flaherty, Ed.) ASTM Committee F-20 Hazardous Substances and Oil Spill Response. ASTM Special Technical Publication: 1018, Philadelphia, USA.

ERM (2002). Kudu gas field: Marine Survey Report, Unpublished.

HOPE JONES, P (1980). The effect on birds of a North Sea gas flare. Br. Birds 73: 547-555.

HOPE JONES, P (1981). Birds from Bravo. Birds 8 (7): 30.

MERRIE, T D H (1979). Birds and North Sea oil production platforms. Scottish Birds 10: 271- 276.

NATIONAL RESEARCH COUNCIL (1989). Using Oil Dispersants on the Sea. Committee on Effectiveness of Oil Spill Dispersants, Marine Board, Commission on Engineering and Technical Systems, National Research Council. National Academy Press, Washington D.C., U.S.A.

PULFRICH, A (2002). The potential effects of sediments derived from proposed pocket beach mining in the Bogenfels Licence Area on intertidal and subtidal benthic communities. Specialist Study prepared for Namdeb Diamond Corporation by Pisces Environmental Services, 116 pp.

READ, A D (1985). The application of MARPOL 73/78 to fixed platforms and mobile offshore drilling units. Paper presented at the Seminar on Aspects of the Prevention of Oil Pollution in the Mediterranean Sea, organised by CONCAWE and E & P Forum in association with the Co-ordinating Unit of the Mediterranean Action Plan UNEP, Athens, 11-13 February 1985.

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SHELL E&P NORWAY and DNV (2001). Environmental Impact Assessment for Gas Exploration and Appraisal Drilling in Licence Area 2814A on the Continental Shelf of Namibia: SEPN/D/01.003.

VERHEIJEN, F J (1981). Bird kills at tall lighted structures in the USA in the period 1935-1973 and kills at a Dutch lighthouse in the period 1924-1928 show similar lunar periodicity. Ardea 69: 199-203.

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Part B: Environmental Management Programme

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CONTENTS

ENVIRONMENTAL MANAGEMENT PROGRAMME REPORT

SECTION 1: TULLOW OIL’S ENVIRONMENTAL MANAGEMENT SYSTEM 1.1 INTRODUCTION ______1-1 1.2 THE ENVIRONMENTAL MANAGEMENT PROGRAMME (EMP) ______1-3

SECTION 2: DEVELOPMENT 2. DEVELOPMENT ______2-1 2.1 ESTABLISHMENT OF LÜDERITZ BASE______2-1 2.1.1 Pre-establishment ______2-1 2.1.1.1 Pre-establishment planning ______2-1 2.1.1.2 Financial provision______2-1 2.1.1.3 Emergency procedure planning______2-2 2.1.2 Establishment ______2-2 2.1.2.1 Compliance with Environmental Management Programme______2-2 2.2 PRODUCTION DRILLING______2-3 2.2.1 Pre-establishment ______2-3 2.2.1.1 Pre-operation planning ______2-3 2.2.1.2 Financial provision______2-3 2.2.1.3 Emergency procedure preparation ______2-4 2.2.1.4 Approval of EMPR ______2-5 2.2.2 Establishment ______2-5 2.2.2.1 Compliance with Environmental Management Programme______2-5 2.2.2.2 Notifying other users of the sea______2-6 2.2.2.3 Well/anchor position to avoid any other seabed obstacles/installations ______2-6 2.2.2.4 Rig installation and anchor laying ______2-7 2.2.2.5 Ensure integrity of anchor system ______2-7 2.2.3 Production drilling ______2-8 2.2.3.1 Introduction ______2-8 2.2.3.2 Adherence to the EMP______2-8 2.2.3.3 Ongoing communication with other users of the sea and resource managers ______2-9 2.2.3.4 Prevention of emergencies ______2-10 2.2.3.5 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refueling, blow-out, etc.) ______2-10 2.2.3.6 Blow out prevention during well drilling ______2-11 2.2.3.7 Disposal of drilling mud and cuttings ______2-12 2.2.3.8 Well testing ______2-12 2.2.3.9 Pollution control and waste management of products disposed of into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), and to land (used oils, metals, plastics, glass, etc) ______2-13 2.2.3.10 Transport, storage and handling of explosives ______2-15

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2.2.3.11 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels) ______2-15 2.2.3.12 Equipment loss ______2-16 2.2.3.13 Oil bunkering / refueling at sea ______2-16 2.2.3.14 Use of helicopters for crew changes, servicing, etc. ______2-17 2.2.4 Decommissioning ______2-17 2.2.4.1 Well completion ______2-17 2.2.4.2 Drilling unit to leave area ______2-18 2.2.4.3 Inform relevant parties of completion of well drilling ______2-18 2.2.4.4 Final waste disposal ______2-19 2.2.5 Monitoring, compliance auditing and the submission of information ______2-19 2.2.5.1 Monitoring activities and effects______2-19 2.2.5.2 Compile well drilling “close-out” report for all activities relating to environmental management ______2-20 2.3 INSTALLATION OF GAS PIPELINE AND PRODUCTION FACILITIES ___2-21 2.3.1 Introduction ______2-21 2.3.2 Pre-establishment ______2-32 2.3.2.1 Pre-operation planning ______2-32 2.3.2.2 Financial provision______2-32 2.3.2.3 Preparation for emergencies ______2-33 2.3.2.4 Approval of EMPR ______2-34 2.3.3 Establishment ______2-34 2.3.3.1 Compliance with Environmental Management Programme______2-34 2.3.3.2 Notifying other users of the sea______2-35 2.3.3.3 Anchor position to avoid any other seabed obstacles/installations ______2-35 2.3.3.4 Anchor laying______2-36 2.3.3.5 Ensure integrity of anchor system ______2-36 2.3.4 Operations______2-37 2.3.4.1 Adherence to the EMP______2-37 2.3.4.2 Continue to communicate with other users of the sea and resource managers ______2-38 2.3.4.3 Prevention of emergencies ______2-39 2.3.4.4 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refuelling, blow-out, etc.) ______2-39 2.3.4.5 Pollution control and waste management of products disposed of: into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), to land (used oils etc, metals, plastics, glass, etc) ______2-40 2.3.4.6 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels) ______2-42 2.3.4.7 Equipment loss ______2-43 2.3.4.8 Oil bunkering / refueling at sea ______2-43 2.3.4.9 Use of helicopters for crew changes, servicing, etc. ______2-44 2.4 CONSTRUCTION OF THE SHORE CROSSING ______2-45 2.4.1 Introduction ______2-45 2.4.2 Pre-establishment ______2-45 2.4.2.1 Pre-establishment planning ______2-45 2.4.2.2 Financial Provision______2-45 2.4.2.3 Emergency procedures ______2-46 2.4.2.4 Development and implementation of EMP compliance system______2-46 2.4.3 Construction ______2-48 2.4.3.1 Responsibility, timing and reporting______2-48 2.4.3.2 Site clearing and landscaping ______2-48 2.4.3.3 Site Management______2-49 2.4.3.4 Water Use Management Plan ______2-52 2.4.3.5 Materials Handling and Storage Management ______2-53

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2.4.3.6 Fire Control and Emergency Procedures ______2-55 2.4.3.7 Leak and Spillage Management ______2-57 2.4.3.8 Solid Waste Management ______2-59 2.4.3.9 Dust management ______2-61 2.4.3.10 Wastewater Management ______2-62 2.4.3.11 Transportation Management ______2-63 2.4.3.12 Noise Management ______2-64 2.4.3.13 Management of recruitment, labour, skills development and training ______2-65 2.4.3.14 Investment, Procurement and Sales Management ______2-66 2.4.3.15 Environmental and HIV/AIDS awareness training for employees and contract workers ______2-67 2.5 CONSTRUCTION OF THE GAS CONDITIONING PLANT ______2-69 2.5.1 Pre-establishment Phase ______2-69 2.5.1.1 Pre-establishment planning ______2-69 2.5.1.2 Financial Provision______2-69 2.5.1.3 Emergency procedures ______2-70 2.5.1.4 Development and implementation of EMP compliance system______2-70 2.5.2 Construction ______2-72 2.5.2.1 Responsibility, timing and reporting______2-72 2.5.2.2 Site clearing and landscaping ______2-72 2.5.2.3 Site Management______2-74 2.5.2.4 Water Use Management Plan ______2-77 2.5.2.5 Materials Handling and Storage Management ______2-77 2.5.2.6 Fire Control and Emergency Procedures ______2-79 2.5.2.7 Leak and Spillage Management ______2-81 2.5.2.8 Solid Waste Management ______2-83 2.5.2.9 Dust management ______2-85 2.5.2.10 Wastewater Management ______2-86 2.5.2.11 Transportation Management ______2-87 2.5.2.12 Noise Management ______2-88 2.5.2.13 Management of recruitment, labour, skills development and training ______2-89 2.5.2.14 Investment, Procurement and Sales Management ______2-91 2.5.2.15 Environmental and HIV/AIDS awareness training for employees and contract workers ______2-91

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Part B, Section 1: Tullow Oil’s Environmental Management System

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Part B, Section 1: Tullow Oil’s Environmental Management System

1.1 INTRODUCTION ______1 1.2 THE ENVIRONMENTAL MANAGEMENT PROGRAMME (EMP)______3

Figures

Figure 1.1. Organisation during Development Phase...... 6 Figure 1.2. Organisation during Production Phase...... 7

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1.1 INTRODUCTION

It is central to Tullow Oil’s Environmental Health and Safety Policy that an effective management system forms an integral part of all Company business. Tullow Oil has established an Integrated Management System (IMS) which sets the minimum standards to be used for all the Company's activities and those of its subsidiaries such as Energy Africa Kudu Limited (Appendix A). The IMS is hierarchical descending from the overarching IMS framework, through corporate guidelines, to local compliance documents and local/operational procedures. The key objective of the IMS is to ensure:

Clear assignment of responsibilities; High standards in EH&S performance; Sound risk management, planning and decision making; Efficient and cost effective planning and conduct of operations; Legislative compliance throughout all operations; A systematic approach to critical business activities; and Continuous improvement.

The IMS consists of 18 Elements for each of which standards and expectations have been set. Whilst all of the Elements are of importance for Tullow Oil’s activities, and are therefore covered in full in Annex A, of particular relevance to the EMP are Element 13: Environmental Management, and Element 17: Performance Measurement, Monitoring and Reporting:

Element 13 Environmental Management

Standards

Environmental assessments and environmental management plans shall be implemented in order to minimise harmful environmental impacts before they occur.

Expectations

The environmental impacts of business activities are assessed qualitatively and quantitatively as appropriate. Environmental Impact Statements (EIS) are prepared where required by legislation or where significant risk of environmental damage is possible. Pollution prevention, waste and emissions minimisation, and the efficient and effective use of energy and natural resources are addressed for all operations and business activities.

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Disposal of waste material takes place only at approved sites. Pollution controls are tested and undergo preventative maintenance. Proper abandonment and decommissioning are considered for all assets and operations, taking into account the environmental impact of such operations.

Element 17 Performance Measurement, Monitoring and Reporting

Standards

All activities are measured and monitored locally against defined EH&S expectations and reported in accordance with a documented schedule.

Expectations A system is in place (including schedules) for performance measurement, monitoring and reporting, for both internal and external monitoring, and active and reactive monitoring. The level of detail of performance measurement, monitoring and reporting is determined by the EH&S risk associated with the activity. Performance measurement, monitoring and reporting are undertaken by competent personnel. All measuring and monitoring equipment is calibrated and maintained, and appropriate records are kept. Performance of EH&S critical measures is verified against their minimum performance criteria, with under-performance being flagged for further investigation or action as appropriate. The results of performance measurement and monitoring will be documented and records maintained according to document control procedures. Performance is communicated to the workforce.

This Environmental Management Programme (EMP) has been prepared to identify and provide standards and procedures to help prevent, avoid or minimize both actual and potential negative impacts identified during the environmental impact assessment (Part A of this document) as resulting from the development activities. In addition, positive impacts must be maximized.

The scope of the EMP includes management actions applicable to the development, production and decommissioning phases of the project:

1) Development Operation of the Luderitz Base; Production well drilling;

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Pipelaying and installation of umbilicals and wellfield infrastructure; Uubvlei pipeline shore crossing; and Construction of the gas conditioning plant.

2) Production Offshore Gas production; and Onshore Gas conditioning plant.

3) Decommissioning

1.2 THE ENVIRONMENTAL MANAGEMENT PROGRAMME (EMP)

The EMP does not provide specific details on how impacts are to be managed and on how management actions are to be implemented but is structured around a number of identified activities and risk sources where more detailed Method Statements and Management Plans are required. The structure of the following sections is as follows:

1) Identified activities and potential risk sources arising from the three project phases listed above.

2) Details of the objectives to be achieved by the management of the identified activities and risk sources are presented. These are based on managing the environmental impacts identified during the EIA process. The objectives state how negative impacts should be minimised and how positive impacts should be enhanced.

3) Management controls and actions that need to be implemented may take one of three forms:

a. ‘Preventative’ or ‘proactive’ management: Design and management of project activities and facilities to ensure no impacts in the first place. b. ‘Curative’ or ‘reactive’ management: Mitigation of impacts after they have occurred. c. ‘Capacity’ management: Overarching management that aims to ensure that the necessary capacity exists to implement both preventative and curative management. This management involves building capacity within the company, as well as the capacity of external organisations that would be required to assist with curative management.

As part of management actions, the requirement for Method Statements and Management Plans are identified. These are to be prepared by sub-contractors and the Contractor respectively and will specify how they shall manage potential environmental impacts in line with best practice principles, and how the management actions will be implemented and complied with to ensure that the objectives of the EMP are achieved. The EMP identifies the

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environmental principles that should be reflected in the Method Statement and Management Plans, and details the scope of issues to be addressed and additional information requirements. Where necessary, the sub-contractors will be required to submit detailed Method Statements to the Contractor for review. The Method Statements of the various sub- contractors will be consolidated by the Contractor into Management Plans for specific activities or risk sources. The Contractor’s Management Plans will be reviewed by the Tullow Oil SHE Department prior to submission to the authorities. As the project proceeds and new sub-contractors start work, they will be required to submit Method Statements which are aligned with the existing Management Plan. Management Plans will therefore be updated as and when new sub-contractors come on site and new Method Statements are submitted.

4) Responsibilities for implementation are assigned to the different parties involved in implementing the management controls and actions. The Tullow Oil management structures for the development and production phases of the Kudu gas field development are presented in Figures 1 and 2 respectively.

5) Timing, i.e. duration of the identified activity.

6) Reporting requirements: It is necessary to monitor and assess on a continuous basis, and to conduct periodic compliance audits. Monitoring programmes are required to ensure that the mitigation measures identified in the impact assessment are effective. These monitoring programmes, if required, are to be designed by specialists in consultation with Tullow Oil and relevant stakeholders. Where monitoring programmes are required, these should be designed to be pragmatic and implementable. As far as possible, measurement parameters should be selected which provide immediate results in order for appropriate management actions to be taken as soon as possible, in the event of an exceedance of guideline values or accepted performance levels. Sections of the Monitoring Programmes that are specific to particular Management Plans must be included in those Management Plans. Monitoring programmes should be described in detail and include the following information:

a. Monitoring objectives b. Monitoring procedure: method applied, monitoring location/s, timing and frequency of monitoring c. Instrumentation to be used (where applicable) d. Measurement parameters and environmental data required for performance assessment e. Performance indicators and targets that indicate the effectiveness of implementing the Construction EMP (compliance monitoring) and the effectiveness of managing environmental impacts (environmental monitoring). f. Data recording and reporting procedures g. Responsible person(s) h. Data recording sheet.

The EMP therefore provides the starting point of a system of proactive environmental management for the Kudu gas field development project. This is achieved through including the development of more detailed Method Statements and Management Plans; monitoring

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programmes; and reporting, auditing and review procedures. All incidents of non-compliance with the EMP are to be identified and corrective actions taken will be recorded.

The EHS Advisor working on the Kudu project must ensure that the Line Managers carry out performance measuring and monitoring during all phases of the development activities, and that these comply with the requirements of the Tullow Oil IMS standard and are appropriately recorded.

Periodic reviews and audits must be undertaken by senior staff and Line Managers to ensure full implementation of Tullow Oil’s management systems in respect of activities under their control. An annual audit should be carried out as part of the Tullow Oil EHS Audit Programme.

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KUDU Field Development Tullow Oil - Construction (Post-Sanction) Organisation

A. Heavey CEO

P. McDade C.O.O.

K. Stallbom M. O'Donoghue NAMPOWER Commercial KUDU Business Manager Director of Projects

NAMPOWER R. Nel G. Kegge P. Padayachee Commercial/ D. Mac Raild Technical Interface Drilling Manager Country Manager Reservoir Engineer Legal/Financial Facilities Project Manager (Namibia) Contracts

EPIC Execution Pre-production Operations

Figure 1.1. Organisation during Development Phase

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KUDU Field Development Tullow Oil – Production Operations Organisation

A. Heavey CEO

P. McDade C.O.O.

G. Kegge Reservoir Engineering Country Manager (Namibia)

Government Liasion Kudu Commercial/ Site Operations Reservoir Engineering Legal/Financial and Maintenance Contracts

Figure 1.2. Organisation during Production Phase

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Part B, Section 2: Development

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Part B, Section 2: Development

2. DEVELOPMENT ______2-1

2.1 ESTABLISHMENT OF LÜDERITZ BASE ______2-1 2.1.1 Pre-establishment______2-1 2.1.1.1 Pre-establishment planning ______2-1 2.1.1.2 Financial provision ______2-1 2.1.1.3 Emergency procedure planning ______2-2 2.1.2 Establishment ______2-2 2.1.2.1 Compliance with Environmental Management Programme ______2-2 2.2 PRODUCTION DRILLING ______2-3 2.2.1 Pre-establishment______2-3 2.2.1.1 Pre-operation planning ______2-3 2.2.1.2 Financial provision ______2-3 2.2.1.3 Emergency procedure preparation ______2-4 2.2.1.4 Approval of EMPR ______2-5 2.2.2 Establishment ______2-5 2.2.2.1 Compliance with Environmental Management Programme ______2-5 2.2.2.2 Notifying other users of the sea ______2-6 2.2.2.3 Well/anchor position to avoid any other seabed obstacles/installations ______2-6 2.2.2.4 Rig installation and anchor laying ______2-7 2.2.2.5 Ensure integrity of anchor system ______2-7 2.2.3 Production drilling ______2-8 2.2.3.1 Introduction ______2-8 2.2.3.2 Adherence to the EMP ______2-8 2.2.3.3 Ongoing communication with other users of the sea and resource managers______2-9 2.2.3.4 Prevention of emergencies ______2-10 2.2.3.5 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refueling, blow-out, etc.) ______2-10 2.2.3.6 Blow out prevention during well drilling ______2-11 2.2.3.7 Disposal of drilling mud and cuttings ______2-12 2.2.3.8 Well testing ______2-12 2.2.3.9 Pollution control and waste management of products disposed of into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), and to land (used oils, metals, plastics, glass, etc) ______2-13 2.2.3.10 Transport, storage and handling of explosives ______2-14 2.2.3.11 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels) ______2-15 2.2.3.12 Equipment loss ______2-16 2.2.3.13 Oil bunkering / refueling at sea ______2-16 2.2.3.14 Use of helicopters for crew changes, servicing, etc. ______2-17 2.2.4 Decommissioning ______2-17 2.2.4.1 Well completion ______2-17

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2.2.4.2 Drilling unit to leave area______2-18 2.2.4.3 Inform relevant parties of completion of well drilling______2-18 2.2.4.4 Final waste disposal______2-19 2.2.5 Monitoring, compliance auditing and the submission of information ______2-19 2.2.5.1 Monitoring activities and effects ______2-19 2.2.5.2 Compile well drilling “close-out” report for all activities relating to environmental management______2-20 2.3 INSTALLATION OF GAS PIPELINE AND PRODUCTION FACILITIES ___ 2-21 2.3.1 Introduction ______2-21 2.3.2 Pre-establishment______2-32 2.3.2.1 Pre-operation planning ______2-32 2.3.2.2 Financial provision ______2-32 2.3.2.3 Preparation for emergencies ______2-33 2.3.2.4 Approval of EMPR ______2-34 2.3.3 Establishment ______2-34 2.3.3.1 Compliance with Environmental Management Programme ______2-34 2.3.3.2 Notifying other users of the sea ______2-35 2.3.3.3 Anchor position to avoid any other seabed obstacles/installations ______2-35 2.3.3.4 Anchor laying ______2-36 2.3.3.5 Ensure integrity of anchor system ______2-36 2.3.4 Operations ______2-37 2.3.4.1 Adherence to the EMP ______2-37 2.3.4.2 Continue to communicate with other users of the sea and resource managers ______2-38 2.3.4.3 Prevention of emergencies ______2-39 2.3.4.4 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refuelling, blow-out, etc.) ______2-39 2.3.4.5 Pollution control and waste management of products disposed of: into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), to land (used oils etc, metals, plastics, glass, etc)______2-40 2.3.4.6 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels) ______2-42 2.3.4.7 Equipment loss ______2-43 2.3.4.8 Oil bunkering / refueling at sea ______2-43 2.3.4.9 Use of helicopters for crew changes, servicing, etc. ______2-44 2.4 CONSTRUCTION OF THE SHORE CROSSING ______2-45 2.4.1 Introduction ______2-45 2.4.2 Pre-establishment______2-45 2.4.2.1 Pre-establishment planning ______2-45 2.4.2.2 Financial Provision______2-45 2.4.2.3 Emergency procedures ______2-46 2.4.2.4 Development and implementation of EMP compliance system ______2-46 2.4.3 Construction ______2-48 2.4.3.1 Responsibility, timing and reporting______2-48 2.4.3.2 Site clearing and landscaping ______2-48 2.4.3.3 Site Management______2-49 2.4.3.4 Water Use Management Plan ______2-52 2.4.3.5 Materials Handling and Storage Management ______2-53 2.4.3.6 Fire Control and Emergency Procedures ______2-55 2.4.3.7 Leak and Spillage Management______2-57 2.4.3.8 Solid Waste Management ______2-59 2.4.3.9 Dust management______2-61 2.4.3.10 Wastewater Management ______2-61

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Part B, Section 2 ENERGY AFRICA KUDU LIMITED

2.4.3.11 Transportation Management______2-63 2.4.3.12 Noise Management ______2-64 2.4.3.13 Management of recruitment, labour, skills development and training ______2-65 2.4.3.14 Investment, Procurement and Sales Management ______2-66 2.4.3.15 Environmental and HIV/AIDS awareness training for employees and contract workers ______2-67 2.5 CONSTRUCTION OF THE GAS CONDITIONING PLANT______2-69 2.5.1 Pre-establishment Phase ______2-69 2.5.1.1 Pre-establishment planning ______2-69 2.5.1.2 Financial Provision______2-69 2.5.1.3 Emergency procedures ______2-70 2.5.1.4 Development and implementation of EMP compliance system ______2-70 2.5.2 Construction ______2-72 2.5.2.1 Responsibility, timing and reporting______2-72 2.5.2.2 Site clearing and landscaping ______2-72 2.5.2.3 Site Management______2-74 2.5.2.4 Water Use Management Plan ______2-77 2.5.2.5 Materials Handling and Storage Management ______2-77 2.5.2.6 Fire Control and Emergency Procedures ______2-79 2.5.2.7 Leak and Spillage Management______2-81 2.5.2.8 Solid Waste Management ______2-83 2.5.2.9 Dust management______2-85 2.5.2.10 Wastewater Management ______2-86 2.5.2.11 Transportation Management______2-87 2.5.2.12 Noise Management ______2-88 2.5.2.13 Management of recruitment, labour, skills development and training ______2-89 2.5.2.14 Investment, Procurement and Sales Management ______2-91 2.5.2.15 Environmental and HIV/AIDS awareness training for employees and contract workers ______2-91

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Part B, Section 2 ENERGY AFRICA KUDU LIMITED

Figures

Figure 2.3.1. Kudu Gas Field Overview ...... 2-22 Figure 2.3.2. Pre Installation Preparation...... 2-23 Figure 2.3.3. Lay Flowlines ...... 2-24 Figure 2.3.4. Install manifold and SDU ...... 2-25 Figure 2.3.5. Install Pipelines...... 2-26 Figure 2.3.6. Manifold Tie-in Spool Installation ...... 2-27 Figure 2.3.7. Pipeline and MEG Line Purging ...... 2-28 Figure 2.3.8. Install Main Umbilical ...... 2-29 Figure 2.3.9. Install In-Field Umbilicals ...... 2-30 Figure 2.3.10. Xmas Tree Hook-up...... 2-31

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia

Part B, Section 2 ENERGY AFRICA KUDU LIMITED

2. DEVELOPMENT

2.1 ESTABLISHMENT OF LÜDERITZ BASE

2.1.1 Pre-establishment

2.1.1.1 Pre-establishment planning

Objective Liaison with Namport and Lüderitz Municipality.

Management Action In order to ensure the smooth running of all support operations for both offshore and onshore operations:

• Establish the environmental management requirements for the operation of the base in alignment with Namport's ISO 14000 system;

• Liaise with the Lüderitz Municipality with respect to the provision of services to the base.

Responsibility Tullow Oil, and Supply Base Management and other relevant Contractors

Timing Prior to commencement of operations.

Reporting Requirements Retain records of meetings.

2.1.1.2 Financial provision

Objective Compliance with legislative requirements.

Management Action Ensure that financial provision is in place to execute the requirements of this EMP and to ensure rehabilitation of the base site on completion of drilling and construction.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

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Reporting Requirements Confirm that financial provision has been made.

2.1.1.3 Emergency procedure planning

Objective Preparation for any emergency that could have an environmental impact. Note: this does not include medical emergencies as a result of accident or illness.

Management Action Management plans in place for the following:

• Company Emergency Response Plan (including medical evacuation);

• Contractor's site management plan;

• Contractor's insurance cover for pollution incidents.

Responsibility Tullow Oil, and Supply Base Management and other relevant Contractors. Timing Prior to commencement of operations.

Reporting Requirements Confirm compliance and justify any omissions.

2.1.2 Establishment

2.1.2.1 Compliance with Environmental Management Programme

Objective Tullow Oil and Contractors to commit to adherence to EMP.

Management Action • Ensure that all Contractors, Namport and MME are provided with copies of the EMPR;

• Ensure that all systems and procedures for compliance are in place;

• Ensure that responsibilities are allocated to personnel, and that all relevant personnel are trained in pollution response procedures and appropriate equipment is available.

Responsibility Tullow Oil, and Supply Base Management and other relevant Contractors.

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Timing Prior to commencement of operations.

Reporting Requirements All Contractors to sign EMPR prior to commencement of operations.

2.2 PRODUCTION DRILLING

2.2.1 Pre-establishment

2.2.1.1 Pre-operation planning

Objective Accommodation of needs for environmental monitoring and liaison with fishing industry.

Management Action In order to minimise disruption to the operation and resolve any conflict over the allocation of user rights prior to the commencement of operation:

• Determine the extent of local fishing activities and/or other prospecting and mining activities within the drilling area;

• Communicate with the fishing and prospecting and mining industry regarding exclusion areas around the drilling unit and timing of the operation.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Retain records of meetings held and notices issued.

2.2.1.2 Financial provision

Objective Compliance with legislative requirements.

Management Action Ensure that financial provision is in place to execute the requirements of this EMP.

Responsibility Tullow Oil.

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Timing Prior to commencement of operations.

Reporting Requirements Confirm that financial provision for EMP has been made.

2.2.1.3 Emergency procedure preparation

Objective Preparation for any emergency that could result in an environmental impact. Comply with the requirements and/or conditions of:

• MME;

• Petroleum Agreement/Production Licence; • Petroleum (Exploration and Production) Act 1991: Regulations relating to the health, safety and welfare of persons employed, and protection of other persons, property, the environment and natural resources, in, at or in the vicinity of exploration and production areas (1999);

• MARPOL.

Management Action Have the following emergency plans, equipment and personnel in place to deal with all emergencies:

• Company Emergency Response Plan, including MEDIVAC plan;

• Company Oil Spill Contingency Plan;

• Drilling Contractor Emergency Response Plan;

• Support Vessel Contractor Emergency Response Plan;

• Helicopter Operator Emergency Response Plan;

• The drilling unit’s own Oil Pollution Emergency Plan;

• Pollution Safety Certificate for the drilling rig (issued by the South African Maritime Safety Authority (SAMSA) in SA);

• Adequate protection and indemnity insurance cover for oil pollution incidents. Note that in case of a major oil spill, emergency responses and/or Oil Pollution Contingency Plan(s) refer to the Namibia National Oil Spill Contingency Plan.

Responsibility Tullow Oil, Drilling and other relevant Contractors.

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Timing Prior to commencement of operations.

Reporting Requirements Confirm compliance and justify any omissions.

2.2.1.4 Approval of EMPR

Objective Compliance with legislative and MME requirements.

Management Action Ensure that the EMPR for the Production Licence area has been approved by MME.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Retain copy of MME approval.

2.2.2 Establishment

2.2.2.1 Compliance with Environmental Management Programme

Objective Tullow Oil and Contractors to commit to adherence to EMP and MME requirements

Management Action • Ensure that a copy of the approved EMPR is on board the drilling unit and all other activity centres during the operation;

• Ensure procedures and systems for compliance are in place;

• Appropriately inform the drilling unit’s and other activity centre’s personnel of the purpose and requirements of the EMP;

• Ensure correct equipment and personnel are available to meet the requirements of the EMP;

• Ensure responsibilities are allocated to personnel;

• Tullow Oil to commit organisation and contractors to meet the requirements of the EMP.

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Responsibility Tullow Oil, and Drilling and other relevant Contractors.

Timing Prior to commencement of operations and during operations.

Reporting Requirements Retain a copy of the EMPR signed by Tullow Oil and Contractors’ management.

2.2.2.2 Notifying other users of the sea

Objective • Ensure that other users are aware of the forthcoming drilling programme;

• Compliance with Safety of Life at Sea Convention.

Management Action • In writing (through the appropriate Namibian authorities), request the South African Naval (SAN) Hydrographic Office to put out Radio Navigation Warnings and Notices to Mariners throughout the operational period. (Marine chart updates for safety/exclusion zones will only be issued once the production phase has been entered.);

• Notify fishing operators and vessels through local Fishing Associations, the Ministry of Fisheries and Marine Resources (MFMR), the Ministry of Mines and Energy (MME) and the Ministry of Works, Transportation and Communication (MWTC);

• Notify overlapping and neighbouring users with delineated boundaries in the offshore petroleum/mining industry.

Responsibility Tullow Oil.

Timing 30 days prior to start of operations.

Reporting Requirements Retain copy of standard notice and list of those to whom it was sent.

2.2.2.3 Well/anchor position to avoid any other seabed obstacles/installations

Objective Ensure that well/anchor positions will not affect other obstacles/installations on the seabed.

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Management Action • Ensure that no other prospecting/mining/exploration/telecommunication activity will be compromised in any way;

• Avoid any shipwrecks and notify the Namibian National Monuments Council regarding requirements to disturb any such wrecks;

• Carry out surveys over the well locations and ensure that Drilling Contractor obtain well location approval from its underwriters.

Responsibility Tullow Oil, and Drilling and other relevant Contractors

Timing Prior to commencement of drilling operations.

Reporting Requirements Retain copies of records.

2.2.2.4 Rig installation and anchor laying

Objective Minimise disturbance to the sea floor.

Management Action Ensure that no construction debris or dropped equipment is left on the seabed.

Responsibility Tullow Oil and Drilling Contractor

Timing Throughout installation (from the start of the production well drilling till demobilisation).

Reporting Requirements If equipment placed or dropped on the sea floor cannot be recovered, record and report the presence of such items to MME, MWTC and MFMR.

2.2.2.5 Ensure integrity of anchor system

Objective Reduce environmental risk by minimising risk of failures during anchoring and de- anchoring operations.

Management Action Undertake and/or have in place the following in order to minimise environmental risk:

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• A hazard identification and risk assessment document;

• Application of relevant national codes and standards in accordance with good oilfield practice;

• Operations in accordance with procedures laid down in the drilling unit’s marine operations manual as approved by the relevant classification society;

• The captains of the anchor handling vessels must record and report the position of any anchoring equipment dropped;

• All anchor chains and anchors must be certified;

• The drilling unit must be maintained to class standard throughout the project.

Responsibility Drilling Contractor.

Timing Prior to and throughout drilling operations.

Reporting Requirements Tullow Oil in-house requirements.

2.2.3 Production drilling

2.2.3.1 Introduction

A full description of the drilling operation is presented in Part A of this report (see Section 2, subsections 2.3.2 – 2.3.6).

2.2.3.2 Adherence to the EMP

Objective Operate in an environmentally responsible manner.

Management Action • Compliance with the EMP (compliance means that all activities were undertaken successfully and details recorded and included in the Close-out Report);

• Subscribe to the principles of an internationally acceptable Environmental Management System onboard the drilling unit and support vessels. This includes environmental awareness training, waste management, environmental monitoring, record keeping and continuous improvement;

• Ensure all hazardous materials are correctly labeled, stored, packed and sealed with proper markings for shipping.

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Responsibility Tullow Oil and Drilling Contractor.

Timing Throughout operations.

Reporting Requirements Provide copies of records to Tullow Oil’s Project EHS Advisor.

2.2.3.3 Ongoing communication with other users of the sea and resource managers

Objective • Promote co-operation and successful multiple use of the sea, including promotion of safe navigation;

• Comply with EMPR requirements;

• Ensure ISO 14001 Compliance.

Management Action Through normal communication channels, Radio Navigation Warnings and Notices to Mariners, keep the following interested and affected parties updated on the drilling programme:

• Overlapping and neighbouring users with delineated boundaries in the petroleum and mining industries;

• Namibian and foreign fishing vessels, who can be informed through the recognised fishing associations. Direct communication with fishing companies and agents is also advisable;

• Government departments with jurisdiction over marine activities, particularly MME, MFMR and MWTC;

• SAN Hydrographic Office (through Namibian authorities), SAMSA (because of the proximity of Kudu to the South African border) and local Port Captains. Take steps to share information and co-operate with other marine users and resource managers in the marine environment for mutual benefit. Keep constant watch for approaching vessels during operations, and warn by radio and standby vessel, if required.

Responsibility Tullow Oil

Timing During operations as required, and on completion.

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Reporting Requirements Provide updates on progress and/or changes in the drilling programme to MME, MFMR, MWTC and local Fishing Associations.

2.2.3.4 Prevention of emergencies

Objective Minimise the chance of emergency and subsequent damage to the environment from occurring.

Management Action • Prevent collisions by ensuring that the drilling unit displays correct signals by day and lights by night, by visual radar watch and standby vessel(s);

• Service safety and fire equipment regularly and practice drills frequently.

Responsibility Tullow Oil and Drilling Contractor

Timing Throughout operations.

Reporting Requirements Comply with Tullow Oil’s ISO 14001 reporting requirements for safety systems.

2.2.3.5 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refueling, blow-out, etc.)

Objective • Minimise damage to the environment by implementing response procedures efficiently;

• Comply with Prevention and Combating of Pollution of the Sea by Oil Act, 1981 and the 1991 Amendment Act (Act No 24);

• Comply with MME, MWTC and MFMR requirements;

• Comply with EMPR requirements;

• Comply with Law of the Sea Convention (LOSC).

Management Action • In the event of a major oil spill immediately implement: - Namibian National Oil Spill Contingency Plan; - Vessel’s Emergency Response Plan;

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- Company’s Oil Spill Contingency Plan.

• Adhere to obligations regarding other vessels in distress;

• Implement health and safety procedures (see emergency plans above);

• Notify MWTC and MME about wrecked or abandoned vessels (safety and pollution), and the Ministry of Finance (salvage, customs, royalties). Give location details to SAN Hydrographic Office (through Namibian authorities).

Responsibility Tullow Oil.

Timing In event of spill.

Reporting Requirements • Record of all spill details (Spill Record Book), including spill reports, emergency exercise reports, and audit reports;

• Report details of spill to MME, MWTC, MFMR and GACG.

2.2.3.6 Blow out prevention during well drilling

Objective • Ensure that the necessary safeguards are in place to avoid any uncontrolled release of drilling fluids and/or hydrocarbons;

• Adhere to international oil industry best practice.

Management Action • Safe well design to minimise the risk of the uncontrolled release of hydrocarbons;

• Fully inspect the blow out preventers (BOPs) on the rig(s) in accordance with the American Petroleum Industries (API) recommended practices (or equivalent) prior to and during well drilling operations;

• Ensure that all responsible personnel are qualified in accordance with International Well Control Forum requirements or equivalent;

• Follow written procedures for well control;

• Identify hazards and put risk control systems in place.

Responsibility Tullow Oil and Drilling Contractor.

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Timing Prior to and during drilling and well testing operations.

Reporting Requirements Tullow Oil in-house requirements.

2.2.3.7 Disposal of drilling mud and cuttings

Objective Minimise discharges into the sea.

Management Action • Optimally recycle the mud for use downhole to minimise disposal overboard and reduce concentrations of mud chemicals released;

• Use water-based drilling muds (WBM) and low toxicity mud additives;

• Note that the use of any oil-based mud requires a further, special application to MME (see letter of exemption for WBM discharges in Appendix C);

• Estimate the volume of rock cuttings dumped onto the sea floor before connection of the marine riser pipe;

• Estimate the volume of drill cuttings disposed overboard.

Responsibility Tullow Oil and Drilling Contractor.

Timing During drilling operations.

Reporting Requirements Record and provide MME with estimates of actual volumes of mud and drill cuttings disposed of overboard.

2.2.3.8 Well testing

Objective Ensure that there are minimal discharges into the sea and minimise product burned.

Management Action • Use high efficiency flare to maximise combustion of hydrocarbons;

• Use well test procedures to ensure that there are no discharges into the sea;

• For each flow test, provide an estimate of the volume of any condensate spilt into the sea and the size of the resulting slick.

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Responsibility Tullow Oil, Drilling and other relevant Contractors.

Timing During well testing.

Reporting Requirements Record quantity of gas burned.

2.2.3.9 Pollution control and waste management of products disposed of into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), and to land (used oils, metals, plastics, glass, etc)

Objective • Minimise pollution and maximise recycling by implementing and maintaining pollution control and waste management procedures at all times;

• Adhere to MARPOL standards (see Appendix B);

• Comply with Prevention and Combating of Pollution of the Sea by Oil Act, 1981 and the 1991 Amendment Act (Act No 24);

• Comply with EMPR requirements.

Management Action Implement project Waste Management Plan. Comply with legal requirements for waste management and pollution control (for air and water quality levels at sea), and employ "good housekeeping" and monitoring practices:

• General waste: Initiate a waste minimisation system. No disposal overboard or burning of waste;

• Galley (food) waste: Dispose overboard after macerating according to MARPOL standard (less than 25 mm size) – prohibited if distance to nearest land is < 3 nmiles;

• Medical waste: Seal in aseptic containers for appropriate onshore incineration;

• Neon lights: Crush discarded tubes and send to shore in designated, marked containers for disposal at hazardous waste site;

• Metal: Send to shore for recycling or disposal;

• Other waste: Send remaining waste to a licensed waste site in Namibia. Ensure waste disposal is carried out in accordance with appropriate laws and ordinances;

• Waste oil: Return used oil to a port with a registered facility for processing or disposal;

• Empty oil drums: Not to be filled with chemicals. Send to shore for recycling or disposal;

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• Empty chemical containers: Mark and seal appropriately and send to shore for recycling or disposal;

• CFCs: No CFC based fire-fighting or refrigeration equipment may be used;

• Waste water: Use an oily-water separator to release <15ppm oil in water. Retain sludge for disposal on shore;

• Minor oil spill: Use oil absorbent (also see oil spill emergencies above);

• Emissions to the atmosphere: Properly tune and maintain main engines and all auxiliary power to contain the minimum of soot and unburned diesel;

• Deck drainage: Ensure that weather decks are kept free of spillage. Mop up any spills immediately with biodegradable low toxicity detergents;

• Machinery space drainage: Drilling unit and supply vessels must comply with international agreed standards regulated under MARPOL:

- oily mixture discharge not to exceed 15 ppm; - retain sludge and dispose of in port. • Sewage: use approved treatment plants to meet the MARPOL standard – comminute and disinfect sewage discharges. Effluent must not produce visible solids in, or cause discoloration of the surrounding water;

• Ensure that waste returned to port is disposed of by a licensed waste disposal contractor using an approved landfill site e.g. Walvis Bay or Windhoek.

Responsibility Tullow Oil and Drilling Contractor.

Timing Throughout operations.

Reporting Requirements • Record types and volumes of chemical and hazardous substances brought on board (e.g. radioactive devices/materials, neon lights, toner cartridges, etc.), and destination of wastes;

• Provide summary of waste record book;

• Report to MME and MWTC occurrence of minor oil spills and destination of wastes.

2.2.3.10 Transport, storage and handling of explosives

Objective • Avoid human injury and material or environmental damage by explosives;

• Compliance with Explosives Act, 1956.

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Management Action • Comply with necessary regulations for the transport, storage and handling of explosives;

• Designate competent person in charge. Handling only by authorised personnel with the necessary training and certification;

• Follow explosives storage and utilization procedures;

• Keep register of explosives on board the drilling unit;

• Keep explosives in designated safe place.

Responsibility Tullow Oil and Supply vessel Contractor.

Timing As required throughout operations.

Reporting Requirements Provide MME with record of usage (and losses) of explosives.

2.2.3.11 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels)

Objective • Minimise disruption to other legitimate users of the sea by respecting their rights;

• Adhere to International Law of the Sea;

• Comply with EMPR requirements.

Management Action • Co-operate with other legitimate users of the sea to minimise disruption to other marine activities and marine life;

• Use effective communication channels (see section 2.2.2 above) to inform all other potential users about the location, timing, priority of passage and size of exclusion zones (500 m from edge of the drilling unit). In addition it is suggested that the Notice to Mariners advises of a “stay clear” area of 1 500 m from the corners of the drilling unit.

Responsibility Tullow Oil.

Timing Prior to and during operations.

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Reporting Requirements Daily vessel logs and incident report when/if required.

2.2.3.12 Equipment loss

Objective • Minimise hazards left on the seabed or floating in the water column;

• Inform relevant parties in the event of any loss of equipment, i.e. MME, MWTC, MFMR, local Fishing Associations.

Management Action • When any items that constitute a seafloor or navigational hazard are lost or left on the seabed, or become adrift in the sea, complete a standard form, which records the date, position and cause of loss, details of equipment type, etc.;

• Notify MME, MWTC, MFMR SAN Hydrographic Office (through Namibian authorities), relevant mining companies and fishing associations. SAN Hydrographic Office will send out Notice to Mariners with this information.

Responsibility Tullow Oil and Drilling contractor.

Timing Throughout operations.

Reporting Requirements Retain records of hazards left on the seabed or floating in the water column.

2.2.3.13 Oil bunkering / refueling at sea

Objective • Minimise disturbance or damage to marine life;

• Adhere to MARPOL 73/78 (Annex 1) and Prevention and Combatting of Pollution of the Sea by Oil Act, 1981 and the 1991 Amendment Act (Act No 24);

• Comply with EMPR requirements.

Management Action • No discharge of any oil whatsoever is permitted within 50 nautical miles of the coast;

• Ensure that bulk transfer hoses (fuel, cement, barite, bentonite) between the drilling unit and the supply vessel are in a good serviceable condition.

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Responsibility Drilling and Supply vessel contractors.

Timing Throughout operations.

Reporting Requirements Tullow Oil in-house requirements.

2.2.3.14 Use of helicopters for crew changes, servicing, etc.

Objective • Minimise disturbance or damage to marine and coastal life;

• Adhere to Air Navigation Regulations.

Management Action • Wherever practical establish, in consultation with the pilots, flight paths that do not over-fly Ramsar sites, islands, bird and seal breeding colonies. In cases where this is not possible, over-flights should be at the maximum practical altitude consistent with safe operations;

• Assess compliance with, and the effectiveness of, set flight paths.

Responsibility Tullow Oil and Helicopter contractor

Timing As required for personnel and/or equipment transportation to and from the drilling unit.

Reporting Requirements Submit copy of set flight path to Tullow Oil.

2.2.4 Decommissioning

2.2.4.1 Well completion

Objective Ensure that there are no leakages in any of the equipment on the seabed.

Management Action Place Christmas trees on the wellheads and ensure they are sealed off.

Responsibility Tullow Oil.

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Timing On completion of well drilling.

Reporting Requirements Provide well completion report to MME and MWTC.

2.2.4.2 Drilling unit to leave area

Objective Leave area as it was prior to well drilling with the exception of the production equipment on the sea floor.

Management Action Ensure that all equipment not required for gas production is retrieved from the seafloor.

Responsibility Tullow Oil.

Timing On completion of well drilling.

Reporting Requirements Confirm through seabed scan and/or video and report to MME and MWTC.

2.2.4.3 Inform relevant parties of completion of well drilling

Objective Ensure that relevant parties are made aware of the completion of the drilling campaign.

Management Action • Inform the SAN Hydrographic Office (through Namibian authorities) that the drilling unit is off location;

• Notify fishing operators and vessels through recognised fishing associations;

• Notify MME, MWTC and MFMR.

Responsibility Tullow Oil and Drilling Contractor.

Timing Directly after completion of drilling operation.

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Reporting Requirements Retain copies of notification documentation.

2.2.4.4 Final waste disposal

Objective Minimise pollution and ensure correct disposal of waste.

Management Action Dispose of all waste onboard at a licensed waste site using a licensed waste disposal contractor.

Responsibility Tullow Oil, and Drilling and other relevant Contractors.

Timing Either when the drilling unit itself is in port or whenever a supply vessel brings wastes from the drilling unit into port for disposal ashore.

Reporting Requirements Receipt required from waste contractor and submitted to Tullow Oil.

2.2.5 Monitoring, compliance auditing and the submission of information

2.2.5.1 Monitoring activities and effects

Objective Implement ongoing operational monitoring programmes (in conjunction with government if required) to check that normal operations are maintained within acceptable limits of deviation and that equipment remains fully functional in accordance with required specifications

Management Action • Compile and submit monitoring/inspection programme and EMP Performance Assessments.

• Undertake appropriate monitoring, and track performance against objectives and targets. Document all activities and results for internal and external auditing, which will be conducted in compliance with ISO 14001 requirements.

• Encourage monitoring/observation of marine animals, including:

- Marine mammals, penguins and turtles sighted from the rig; - Record any unusual bird sightings; - Interaction with other vessels.

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Responsibility Tullow Oil.

Timing Throughout operations.

Reporting Requirements Provide all recorded information for Tullow Oil’s ISO compliance purposes and distribution to appropriate authorities and institutes.

2.2.5.2 Compile well drilling “close-out” report for all activities relating to environmental management

Objective Ensure EMPR compliance, that any identified corrective actions are carried out, and contribute towards improvement of EMP implementation.

Management Action • Close–out Report must be based on requirements of the monitoring and EMP Performance Assessment;

• Provide information/records as indicated in the EMP within 90 days of completion of the drilling operation;

• An operation specific Close-out Report must be compiled subsequent to completion of each well drilling operation;

• Provide copy of report to MME.

Responsibility Tullow Oil.

Timing • On completion of well drilling;

• On completion of close-out report.

Reporting Requirements See Management Action section above.

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2.3 INSTALLATION OF GAS PIPELINE AND PRODUCTION FACILITIES

2.3.1 Introduction

Since the completion of the EIA (see Section A of this report) the details of the gas pipeline and its associated operation and control systems have been finalised. An overview of the Kudu offshore field installation and the sequence in which the components will be installed are presented in Figures 2.3.1 – 2.3.10.

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Figure 2.3.1. Kudu Gas Field Overview P1P1

UTA UTP SDUSDU UTA UMBILICALUMBILICAL UTP

P4P4 GasGas TerminalTerminal

MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE ESDESD ValvesValves

P3P3

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16-Aug-0816-Aug-08 13-Nov-08 13-Nov-08 Figure 2.3.2. Pre UMBILICAL Installation Preparation P1P1 UMBILICAL PULLPULL ININ && TESTTEST SPREADSPREAD

P4P4 PrerequisitesPrerequisites

•• Well Well locationslocations confirmedconfirmed PIPELINEPIPELINE PULLPULL ININ && •• Manifold Manifold andand SDUSDU locationslocations agreedagreed TESTTEST 14-Nov-08 SPREADSPREAD 14-Nov-08 • Surveys and pipeline, flowlines and umbilical routes agreed 11-Feb-0911-Feb-09 • Surveys and pipeline, flowlines and umbilical routes agreed •• Pre Pre laylay surveyssurveys (pipelines,(pipelines, flowlinesflowlines and and umbilicals)umbilicals) completedcompleted P2P2 •• Subsea Subsea layouts layouts completedcompleted andand agreedagreed 12-Feb-0912-Feb-09 •• Onshore Onshore pipeworkpipework preparation preparation andand umbilicalumbilical guideguide tubetube installedinstalled 17-Jun-0917-Jun-09 •• Pull-in Pull-in andand testtest spreadsspreads set-upset-up P3 P3 GasGas TerminalTerminal StatusStatus •• Nitrogen Nitrogen andand MEGMEG packagespackages atat GasGas TerminalTerminal commissionedcommissioned priorprior toto completion completion ofof pipelinepipeline installationinstallation •• Land Land RunRun umbilicalumbilical betweenbetween UTPsUTPs to to bebe installedinstalled andand testedtested andand GasGas TerminalTerminal MeOHMeOH systemsystem commissionedcommissioned priorprior toto methanolmethanol purgingpurging ofof mainmain umbilicalumbilical

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Figure 2.3.3. Lay

UMBILICAL Flowlines P1P1 UMBILICAL PULLPULL ININ && TESTTEST SPREADSPREAD

P4P4

PIPELINEPIPELINE PULLPULL ININ && TESTTEST SPREADSPREAD

P2P2

P3P3 ••PerformPerform seabedseabed preparationpreparation (flowlines(flowlines and and pipelines)pipelines) ••LayLay FlowlinesFlowlines (Prior (Prior toto RigRig Arrival)Arrival) ••FlowlinesFlowlines lowered lowered withinwithin agreedagreed targettarget zoneszones ••Flooding,Flooding, cleaningcleaning && gauginggauging (DSV)(DSV) ••ConductConduct postpost laylay surveysurvey

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Figure 2.3.4. Install

UMBILICAL manifold and SDU P1P1 UMBILICAL PULLPULL ININ && TESTTEST SPREADSPREAD SDUSDU

P4P4

PIPELINEPIPELINE PULLPULL ININ && TESTTEST SPREADSPREAD MANIFOLDMANIFOLD

P2P2

P3P3

••LayLay bargebarge installsinstalls manifoldmanifold andand SDUSDU foundationsfoundations ••LayLay bargebarge installsinstalls manifoldmanifold andand SDUSDU ••ConductConduct postpost installationinstallation surveyssurveys andand teststests ••ConductConduct metrologymetrology onon flowlineflowline to to manifoldmanifold tie-intie-in spoolsspools (DSV)(DSV)

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Figure 2.3.5. Install

UMBILICAL Pipelines P1P1 UMBILICAL PULLPULL ININ && TESTTEST SPREADSPREAD SDUSDU

P4P4

PIPELINEPIPELINE PULLPULL ININ && TESTTEST SPREADSPREAD MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE

••InstallInstall PipelinePipeline andand MEGMEG LineLine • Rockdump lines where required P3P3 • Rockdump lines where required ••CleanClean andand gaugegauge pipelinespipelines && flowlinesflowlines ••FillFill lineslines withwith inhibitedinhibited seawaterseawater ••HydrotestHydrotest Pipeline Pipeline andand MEGMEG lineline ••ConductConduct postpost laylay surveysurvey

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Figure 2.3.6. Manifold UMBILICAL Tie-in Spool Installation P1P1 UMBILICAL PULLPULL ININ && TESTTEST SPREADSPREAD SDUSDU

CorrosionCorrosion P4P4 MonitorMonitor FlyingFlying LeadLead PIPELINEPIPELINE PULLPULL ININ && TESTTEST SPREADSPREAD MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE

••FabricateFabricate flowlineflowline to to manifoldmanifold tie-intie-in spoolsspools (onshore)(onshore)

P3P3 ••ConductConduct metrologymetrology onon pipelinepipeline andand MEGMEG lineline tietie inin spoolsspools ••FabricateFabricate pipelinepipeline andand MEGMEG tie-intie-in spoolsspools (on(on Laybarge)Laybarge) ••InstallInstall tie-intie-in SpoolsSpools (( PipelinesPipelines == Laybarge,Laybarge, flowlinesflowlines = = DSV)DSV) ••LeakLeak testtest pipelinespipelines (Laybarge)(Laybarge) andand flowlinesflowlines (DSV) (DSV) ••InstallInstall corrosioncorrosion monitoringmonitoring flyingflying leadlead ••ConductConduct postpost installationinstallation surveysurvey

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Figure 2.3.7. Pipeline and MEG Line Purging

P1P1

UTP SDUSDU UTP

UMBILICALUMBILICAL PULL IN & P4 PULL IN & P4 TEST TEST GasGas SPREADSPREAD TerminalTerminal

MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE ESDESD ValvesValves

LinesLines connectedconnected toto GasGas TerminalTerminal NitrogenNitrogen andand MEG systems P3P3 MEG systems

••DSVDSV assistsassists inin pigging,pigging, dewateringdewatering andand nitrogennitrogen fillfill ofof pipelinepipeline andand manifoldmanifold ••DSVDSV assistsassists inin pigging,pigging, dewateringdewatering andand flushingflushing MEGMEG lineline throughthrough SDUSDU ••DSVDSV CompletesCompletes leakleak testingtesting andand prepre flowlineflowline purging purging preparationspreparations

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LineLine connectedconnected toto GasGas TerminalTerminal MeOHMeOH System System Figure 2.3.8. Install Main Umbilical

P1P1

UTA SDUSDU UTA UMBILICALUMBILICAL

UMBILICALUMBILICAL PULL IN & P4P4 PULL IN & TEST TEST GasGas SPREADSPREAD TerminalTerminal

MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE ESDESD ValvesValves

P3P3 ••PreparePrepare seabedseabed wherewhere requiredrequired ••LayLay UmbilicalUmbilical toto SDUSDU ••Pull-inPull-in umbilicalumbilical andand terminateterminate ••ConductConduct PrePre UTAUTA installationinstallation flushingflushing andand testingtesting ••ConnectConnect onon shoreshore testtest EquipmentEquipment ••FillFill MeOHMeOH line line inin UmbilicalUmbilical ••InstallInstall I-tubeI-tube sealseal ••LowerLower andand InstallInstall UTAUTA ••InstallInstall FlyingFlying LeadsLeads ••TestTest UmbilicalUmbilical andand SDUSDU fromfrom onon shoreshore

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Figure 2.3.9. Install In- Field Umbilicals

P1P1

UTA UTP SDUSDU UTA UMBILICALUMBILICAL UTP

UMBILICALUMBILICAL P4P4 TESTTEST SPREADSPREAD GasGas TerminalTerminal

MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE ESDESD ValvesValves

P3P3 NotesNotes •• First First endend toto bebe connectedconnected toto SDUSDU ••PreparePrepare FlowlineFlowline Crossings Crossings •• Test Test duringduring layinglaying fromfrom onon shoreshore testtest spreadspread ••InstallInstall In-FieldIn-Field UmbilicalsUmbilicals •• Perform Perform prepre laylay flushingflushing andand testingtesting priorprior toto loweringlowering 22ndndendend ••InstallInstall protectionprotection atat crossingscrossings andand otherother locationslocations •• Lower Lower secondsecond endend onon parkingparking frameframe toto nearnear wellwell targettarget zonezone ••LeakLeak teststests fromfrom onon shoreshore testtest spreadsspreads toto parkingparking framesframes •• Complete Complete leakleak testingtesting fromfrom onshoreonshore toto parkingparking frameframe

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Figure 2.3.10. Xmas Tree Hook-up P1P1

UTA SDUSDU UTA UMBILICALUMBILICAL UTPUTP

P4P4 GasGas TerminalTerminal

MEG PIPELINE MANIFOLDMANIFOLD MEG PIPELINE

P2P2 PIPELINEPIPELINE ESDESD ValvesValves DSVDSV 22 LocatedLocated atat ManifoldManifold

••RigRig providesprovides wellwell handoverhandover certificatescertificates P3P3 ••DeployDeploy 22 xx DSVDSV (1(1 atat XmasXmas TreeTree && 11 atat Manifold)Manifold) ••ConductConduct spoolspool piecepiece metrologymetrology ••LeakLeak testtest tie-intie-in spoolsspools DSVDSV 11 ••FabricateFabricate tie-intie-in spoolsspools onon DSVDSV • Purge & leak test MeOH and MEG lines in In- LocatedLocated atat • Purge & leak test MeOH and MEG lines in In- ••ConnectConnect umbilical'sumbilical's toto XmasXmas TreeTree field umbilical's XmasXmas TreesTrees field umbilical's ••LeakLeak testtest hydraulichydraulic controlcontrol lineslines ••PigPig andand fillfill flowlinesflowlines with with nitrogennitrogen ••InstallInstall flowlineflowline tie-in tie-in spoolsspools ••XmasXmas treetree controlcontrol andand monitoringmonitoring teststests

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2.3.2 Pre-establishment

2.3.2.1 Pre-operation planning

Objective Accommodation of needs for environmental monitoring and liaison with fishing industry.

Management Action In order to minimise disruption to the operation and resolve any conflict over the allocation of user rights prior to the commencement of operation:

• Determine the extent of local fishing activities and/or mineral prospecting and mining activities along the pipeline route;

• Communicate with the fishing and prospecting and mining industry regarding exclusion areas around the pipe and umbilical laybarges and timing of the operation.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Provide records of meetings held and copies of issued notices to MME, MWTC and MFMR.

2.3.2.2 Financial provision

Objective Compliance with legislative requirements.

Management Action Ensure that financial provision is in place to execute the requirements of this EMP.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Confirm that financial provision for EMP has been made.

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2.3.2.3 Preparation for emergencies

Objective Preparation for any emergency that could result in an environmental impact. Comply with the requirements and/or conditions of:

• MME;

• Petroleum Agreement/Production Licence;

• Petroleum (Exploration and Production) Act 1991: Regulations relating to the health, safety and welfare of persons employed, and protection of other persons, property, the environment and natural resources, in, at or in the vicinity of exploration and production areas (1999);

• MARPOL.

Management Action Have the following emergency plans, equipment and personnel in place to deal with all emergencies:

• Project Emergency Response Plan, including MEDIVAC plan;

• Project Oil Spill Contingency Plan;

• Pipelaying Contractor Emergency Response Plan;

• Umbilical Lay Contractor Emergency Response Plan;

• Support Vessel Contractor Emergency Response Plan;

• Helicopter Operator Emergency Response Plan;

• Pollution Safety Certificate for the pipe and umbilical lay barges;

• Adequate protection and indemnity insurance cover for oil pollution incidents. Note that in case of a major oil spill, refer to the Namibia National Oil Spill Contingency Plan.

Responsibility Tullow Oil and relevant Contractors.

Timing Prior to commencement of operations.

Reporting Requirements Confirm compliance and justify any omissions to MME and MWTC.

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2.3.2.4 Approval of EMPR

Objective Compliance with legislative and MME requirements

Management Action Ensure that the EMPR for the Production Licence area had been approved by MME.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Retain notice of MME approval from MME.

2.3.3 Establishment

2.3.3.1 Compliance with Environmental Management Programme

Objective Tullow Oil and Contractors to commit to adherence to EMP and MME requirements.

Management Action • Ensure that a copy of the approved EMPR is on board the pipelaying barge and other activity centres during the operation;

• Ensure procedures and systems for compliance are in place;

• Appropriately inform the pipelaying barge’s and other activity centre’s personnel of the purpose and requirements of the EMP;

• Ensure correct equipment and personnel are available to meet the requirements of the EMP;

• Ensure responsibilities are allocated to personnel;

• Tullow Oil to commit their organisation and Contractors to meet the requirements of the EMP.

Responsibility Tullow Oil and relevant Contractors.

Timing Prior to and during operations.

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Reporting Requirements Ensure that a copy of the EMPR is signed by Pipelaying and Umbilical installation contractors.

2.3.3.2 Notifying other users of the sea

Objective • Ensure that other users are aware of the pipe and umbilical laying programmes.

• Comply with the Safety of Life at Sea Convention.

Management Action • In writing (through the Namibian authorities), request the SAN Hydrographic Office to put out Radio Navigation Warnings and Notices Mariners throughout the operational period. (Marine chart updates for safety/exclusion zones will only be issued once the production phase has been entered into;

• Notify fishing operators and vessels through recognised Fishing Associations, the Ministry of Fisheries and Marine Resources, MME and MWTC;

• Notify overlapping and neighbouring users with delineated boundaries in the offshore petroleum/mining industry.

Responsibility Tullow Oil.

Timing 30 days prior to start of operations.

Reporting Requirements Retain copy of standard notice and list of those to whom it was sent.

2.3.3.3 Anchor position to avoid any other seabed obstacles/installations

Objective Ensure that anchor positions will not affect other obstacles/installations on the seabed.

Management Action • Ensure that no other prospecting/mining/exploration/telecommunication activity will be compromised by the pipe laying and umbilical installation activities;

• Avoid any shipwrecks and if necessary, notify the Namibian National Monuments Council regarding requirements to disturb any such wrecks;

• Carry out surveys along the pipeline/umbilical route and ensure that the Pipelaying and Umbilical installation Contractor obtain approval from their underwriters.

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Responsibility Tullow Oil and Pipelaying and Umbilical Installation Contractors.

Timing Prior to commencement of pipelaying and umbilical installation operations.

Reporting Requirements Retain copies of records.

2.3.3.4 Anchor laying

Objective Minimise disturbance to the sea floor.

Management Action Ensure that no construction debris or dropped equipment is left on the seabed.

Responsibility Pipelaying and Umbilical Installation contractors.

Timing Throughout pipelaying and umbilical installation operations.

Reporting Requirements If equipment placed or dropped on the sea floor cannot be recovered, record and report the presence of such items to MME, MWTC and MFMR.

2.3.3.5 Ensure integrity of anchor system

Objective Reduce environmental risk by minimising risk of failures during anchoring and de- anchoring operations.

Management Action Undertake and/or have in place the following in order to minimise environmental risk:

• A hazard identification and risk assessment document;

• Application of relevant national codes and standards in accordance with good oilfield practice;

• Operations in accordance with procedures laid down in the vessel’s marine operations manual as approved by the relevant classification society;

• The captains of the anchor handling vessels must take and report the position of any anchoring equipment dropped as a result of the vessels’ operations;

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• All anchor chains and anchors must be certified;

• The pipelaying and umbilical installation barges must be maintained to class standard throughout the project.

Responsibility Pipelaying and Umbilical Installation Contractors.

Timing Prior to and throughout pipelaying and umbilical installation operations.

Reporting Requirements • Provide copies of chain and anchor certification to Tullow Oil;

• Report nature and location of any anchor and chain losses to MME, MWTC, MFMR and Tullow Oil.

2.3.4 Operations

2.3.4.1 Adherence to the EMP

Objective Operate in an environmentally responsible manner.

Management Action • Ensure compliance with the EMP;

• Subscribe to the principles of an internationally acceptable Environmental Management System onboard the drill rig and support vessels. This includes environmental awareness training, waste management, environmental monitoring, record keeping and continuous improvement;

• Ensure all hazardous materials are correctly labeled, stored, packed and sealed with proper markings for shipping.

Responsibility Tullow Oil.

Timing Throughout operations.

Reporting Requirements Tullow Oil in-house reporting requirements .

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2.3.4.2 Continue to communicate with other users of the sea and resource managers

Objective • Promote co-operation and successful multiple use of the sea, including promotion of safe navigation;

• Comply with EMPR requirements.

Management Action Through normal communication channels, Radio Navigation Warnings and Notices to Mariners, keep the following interested and affected parties updated on the pipelaying programme:

• Overlapping and neighbouring users with delineated boundaries in the offshore petroleum and mineral industries;

• Namibian and foreign fishing vessels, who can be informed through the recognised fishing associations. Direct communication with fishing companies and agents is also advised;

• Government departments with jurisdiction over marine activities, particularly MME, MFMR and MWTC;

• SAN Hydrographer (through Namibian authorities), SAMSA (because of the proximity to South African territorial waters) and local Port Captains. Take steps to share information and co-operate with other marine users and resource managers in the marine environment generally, to mutual benefit. Keep constant watch for approaching vessels during operations and warn by radio and standby vessel, if required.

Responsibility Tullow Oil, and Pipelaying and Umbilical Installation contractors.

Timing • During compilation of EMPR, as well as during operations as required;

• During, and on completion of pipelaying and umbilical installation;

• Throughout operations.

Reporting Requirements See Management Action section above.

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2.3.4.3 Prevention of emergencies

Objective • Minimise the chance of emergency and subsequent damage to the environment from occurring;

• Comply with navigation rights, safety and licensing requirements;

• Comply with EMPR requirements.

Management Action • Prevent collisions by ensuring that the pipelaying and umbilical installation barges display correct signals by day and lights by night, by visual radar watch and standby vessel(s);

• Service equipment regularly and practice safety and fire drills weekly.

Responsibility Tullow Oil, and Pipelaying and Umbilical installation Contractors.

Timing Throughout operations.

Reporting Requirements Provide reports on regular safety drills and inspections to Tullow Oil.

2.3.4.4 Dealing with emergencies including major oil spills (resulting from collision, vessel breakup, refuelling, blow-out, etc.)

Objective • Minimise damage to the environment by implementing response procedures efficiently;

• Comply with Prevention and Combating of Pollution of the Sea by Oil Act, 1981 as amended in 1991;

• Comply with MME, MWTC and MFMR requirements;

• Comply with EMPR requirements;

• Comply with Law of the Sea Convention (LOSC);

• Comply with Merchant Shipping Act,1951 as amended in 1991.

Management Action In the event of a major oil spill immediately implement:

• the Namibian National Oil Spill Contingency Plan;

• the vessel’s Emergency Response Plan and Project’s Oil Spill Contingency Plan.

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Adhere to obligations regarding other vessels in distress. Implement health and safety procedures (see emergency plans above). Notify MME, MWTC and GACG about safety and pollution aspects of wrecked or abandoned vessels and the Department of Finance about salvage, customs and royalties. Give location details to the SAN Hydrographic Office (via Namibian authorities).

Responsibility Tullow Oil.

Timing In event of spill.

Reporting Requirements • Record of all spills (Spill Record Book), including spill reports; emergency exercise reports; audit reports;

• Report spills to MME and other relevant authorities.

2.3.4.5 Pollution control and waste management of products disposed of: into the air (exhausts, CFCs and incinerators), to sea (sewage, food, oils), to land (used oils etc, metals, plastics, glass, etc)

Objective • Minimise pollution, and maximise recycling by implementing and maintaining pollution control and waste management procedures at all times;

• Comply with MARPOL standards (see Appendix B);

• Comply with Prevention and Combating of Pollution of the Sea by Oil Act 1981 and the 1991 Amendment Act (Act No 24);

• Comply with EMPR requirements.

Management Action • Implement Project Waste Management Plan;

• Comply with legal requirements for waste management and pollution control (for air and water quality levels at sea), and employ "good housekeeping" and monitoring practices:

- General waste: Initiate a waste minimisation system. No disposal overboard or burning of waste;

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- Galley (food) waste: Dispose overboard after macerating according to MARPOL standard (less than 25 mm size) – prohibited if distance to nearest land is < 3 nmiles;

- Medical waste: Seal in aseptic containers for appropriate onshore incineration; - Neon lights: Crush discarded tubes and send to shore in designated, marked containers for disposal at hazardous waste site;

- Metal: Send to shore for recycling or disposal; - Other waste: Send remaining waste to the licensed waste site in Namibia. Ensure waste disposal is carried out in accordance with appropriate laws and ordinances;

- Waste oil: Return used oil to a port with a registered facility for processing or disposal;

- Empty oil drums: Not to be filled with chemicals. Send to shore for recycling or disposal;

- Empty chemical containers: Mark and seal appropriately and send to shore for recycling or disposal;

- CFCs: No CFC based fire-fighting or refrigeration equipment may be used; - Waste water: Use an oily-water separator to release <15ppm oil in water. Retain sludge for disposal on shore;

- Minor oil spill: Use oil absorbent (also see oil spill emergencies above); - Emissions to the atmosphere: Properly tune and maintain main engines and all auxiliary power to contain the minimum of soot and unburned diesel;

- Deck drainage: Ensure that weather decks are kept free of spillage. Mop up any spills immediately with biodegradable low toxicity detergents;

- Machinery space drainage: Drilling unit and supply vessels must comply with international agreed standards regulated under MARPOL:

o oily mixture discharge not to exceed 15 ppm; o retain sludge and dispose of in port. - Sewage: use approved treatment plants to meet the MARPOL standard – comminute and disinfect sewage discharges. Effluent must not produce visible solids in or cause discoloration of the surrounding water;

• Record types and volumes of chemical and hazardous substances brought on board (e.g. radioactive devices/materials, neon lights, toner cartridges, etc.), and destination of wastes;

• Ensure that waste returned to port is disposed of by a licensed waste disposal contractor using an approved landfill site e.g. Walvis Bay or Windhoek.

Responsibility Tullow Oil, and Pipelaying and Umbilical Installation Contractors.

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Timing Throughout operations.

• Provide summary of waste record book;

• Report to Tullow Oil occurrence of minor oil spills and destination of wastes for reporting to Government authorities.

2.3.4.6 Exclusion of other marine users from access to the operational area for safety reasons (shipping, including fishing and mining vessels)

Objective • Minimise disruption to other legitimate users of the sea by respecting their rights;

• Comply with the Marine Traffic Act (Act 2 of 1981 amended by Act 15 of 1991);

• Comply with the International Law of the Sea;

• Comply with EMPR requirements.

Management Action • Co-operate with other legitimate users of the sea to minimise disruption to other marine activities and marine life;

• Use effective communication channels to inform all other potential users about the location, timing, priority of passage and size of exclusion zones (500 m from the pipelaying barge). To avoid any interference with anchors and anchor chains it is suggested that the Notice to Mariners advises of a stay clear area of 1 500 m from the pipelaying and umbilical installation barges.

Responsibility Tullow Oil and Pipelaying and Umbilical installation Contractors.

Timing During planning and operations.

Reporting Requirements Record any incidents outside of normal occurrence to Tullow Oil for reporting to Government authorities.

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2.3.4.7 Equipment loss

Objective Minimise hazards left on the seabed or floating in the water column, and inform MME, MWTC and MFMR.

Management Action • Keep a record of lost equipment and all items lost overboard and not recovered;

• When any items that constitute a seafloor or navigational hazard are lost or left on the seabed, or become adrift in the sea, complete a standard form, which records the date, position and cause of loss, details of equipment type, etc.;

• Pass information to MME and MWTC. Notify SAN Hydrographer (through Namibian authorities), relevant mining companies and fishing associations. SAN Hydrographer will send out Notice to Mariners with this information.

Responsibility Tullow Oil, and Pipelaying and Umbilical installation Contractors

Timing Throughout operations.

Reporting Requirements Copy of record sheet submitted to Tullow Oil.

2.3.4.8 Oil bunkering / refueling at sea

Objective • Minimise disturbance / damage to marine life;

• Comply with MARPOL 73/78 (Annex 1);

• Comply with the Prevention and Combatting of Pollution of the Sea by Oil Act, 1981 as amended in 1991;

• Comply with EMPR requirements.

Management Action No discharge oil within 50 nautical miles of the coast.

Responsibility Tullow Oil, and Pipelaying and Umbilical installation Contractors.

Timing Throughout operation

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Reporting Requirements MWTC permit for offshore bunkering, to be applied for via MME, to retained by Tullow Oil.

2.3.4.9 Use of helicopters for crew changes, servicing, etc.

Objective • Minimise disturbance / damage to marine and coastal life;

• Comply with Air Navigation Regulations.

• Assess compliance with, and the effectiveness of, set flight paths.

Responsibility Tullow Oil and Helicopter contractor.

Timing As required (Whenever personnel or equipment is transported to and from the vessels)

Reporting Requirements Submit copy of set flight path to Tullow Oil.

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2.4 CONSTRUCTION OF THE SHORE CROSSING

2.4.1 Introduction

This section deals with the construction of the shore crossing (pipeline landfall) and the terrestrial section of the pipeline between the landfall and the gas conditioning plant.

2.4.2 Pre-establishment

2.4.2.1 Pre-establishment planning

Objective Liaison with NamPower and Namdeb.

Management Action In order to ensure the smooth simultaneous running of the construction of the shore crossing and terrestrial pipeline with the construction of the CCGT power station:

• Establish the environmental management requirements for the operation of the construction site so as to align them with Namdeb’s environmental management plan for Mining Area 1;

• Liaise with NamPower and Namdeb with respect to the provision of shared services to the construction site.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Retain records of meetings.

2.4.2.2 Financial Provision

Objective Compliance with legislative requirements.

Management Action Ensure that financial provision is in place to execute the requirements of this EMP and to ensure rehabilitation of the shore crossing and terrestrial pipeline at the end of the gas field’s life.

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Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Confirm that financial provision has been made.

2.4.2.3 Emergency procedures

Objective Preparation for any emergency that may have an environmental impact. Note: this does not include medical emergencies as a result of accidents or illness.

Management Action Management plans for the following should be in place:

• Company Emergency Response Plan (including medical evacuation);

• Contractor's site management plan;

• Contractor's insurance cover for pollution incidents.

Responsibility Tullow Oil and relevant Contractors.

Timing Prior to commencement of operations.

Reporting Requirements Confirm compliance and justify any omissions to MME, MFMR, MWTC and MET.

2.4.2.4 Development and implementation of EMP compliance system

Objective To ensure that all the environmental management requirements and actions in the EMPR are implemented, monitored and complied with by the Contractors.

Management Action • Tullow Oil is to ensure that the following conditions are incorporated into the contractual agreements with the Contractor prior to the commencement of construction activities:

- Contract documentation for the Contractor and sub-contractors to include requirements for preferential use of local labour and local goods and services;

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- Contract documentation for the Contractor and sub-contractors to include requirements for the multi-skilling of construction workers;

- A performance-based requirement with regard to environmental impact management must be included in all contracts related to any activity associated with the construction of the onshore facilities.

• A protocol for managing infringements by the Contractor or sub-contractors must be developed by Tullow Oil in consultation with the Contractor. This may include, for example, monthly report backs at the SHE and Risk Management sub-committee meetings at which any infringements are reviewed, and compensation or remediation measures are proposed by the Contractor, as well as actions to be taken to prevent repeat infringements from occurring. Important principles to be included in this protocol are:

- Ensure all relevant personnel are trained in environmental management and pollution response procedures and that the appropriate equipment is available;

- Assurance of a rapid response to stop infringements and to the taking of corrective action;

- Minimisation of impacts and avoidance of repeat infringements; - Identification of appropriate forms of direct compensation or remediation (financial or non-financial) that are agreed upon and applied. Of importance is that if financial compensation is agreed upon, compensation payments must be used to rectify the damage incurred or transferred into a fund which would be used to support local environmental management initiatives;

- Records are kept of all infringements, corrective actions taken and compensation awarded;

- Infringements, corrective action and compensation details are included in scheduled reporting processes.

• Ensure that all Contractors, NamPower, Namdeb and MME are provided with copies of the EMPR.

Responsibility Tullow Oil and relevant Contractors.

Timing Prior to commencement.of construction

Reporting Requirements All Contractors must demonstrate that they meet the monitoring and reporting requirements as determined by their contracts and by the Project EHS Advisor.

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2.4.3 Construction

2.4.3.1 Responsibility, timing and reporting

The responsibility for ensuring compliance with the EMPR ultimately rests with Tullow Oil. However, the day-to-day responsibility for ensuring compliance and reporting rests with the Contractor who will be required to monitor all environmental aspects throughout the construction phase (see Section 2.4.2.4 above).

2.4.3.2 Site clearing and landscaping

Objective • To minimize the amount of land and indigenous fauna and flora disturbed through construction activities;

• To re-vegetate and rehabilitate the site on completion of construction with locally indigenous vegetation as far as possible.

Management action Site clearance is to be undertaken in accordance with the following principles:

• Avoidance of unnecessary removal of vegetation;

• Only those areas of the site where construction and lay-down are going to take place must be cleared. The remaining areas on the site to be clearly demarcated and left intact;

• Stabilisaton of slopes that are disturbed during construction to prevent mobilisation of dust by wind;

• Storage of topsoil removed from the site to ensure that the seed bank is retained. If different categories of topsoil exist these should be stored separately;

• Stockpiles to be covered to reduce dust generation and erosion.

Landscaping The sub-contractor responsible for landscaping is to provide the Contractor with a detailed Landscaping Method Statement. This Landscaping Method Statement will form the basis for the Landscaping Management Plan to be prepared by the Contractor. The detailed Landscaping Management Plan is to be compiled to the satisfaction of MET and Namdeb (compliance with the Namdeb EMPR for Mining Area 1) and landscaping and rehabilitation of the site to take place in accordance with such an approved plan. This plan should take into account and, where required, describe in detail, as a minimum but not limited to, the following considerations:

• Maximum use of construction rubble in landscaping to reduce the amount of construction waste;

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• At the end of construction any excess aggregate, gravel, stone, concrete, bricks, temporary fencing and the like shall be disposed of according to the solid waste management plan. No discarded materials shall be buried on the site without the written approval of Tullow Oil and Namdeb;

• As a general principle, potable water should not be used for irrigation purposes and landscapes must be designed to absorb rainwater run-off;

• Re-vegetation of disturbed areas not occupied by plant infrastructure is to take place as soon as possible. Progressive rehabilitation will be applied, in that areas no longer required for construction activities will be rehabilitated as soon as they become available for rehabilitation;

• Areas that require reshaping shall be cut, filled and compacted as necessary so as to blend with the surrounding landscape;

• The shaping of cut-and-fill slopes to allow for the re-establishment of indigenous vegetation;

• Topsoil removed during construction to be used wherever possible in site landscaping. Care must be taken not to mix the topsoil with the subsoil during shaping operations. Should a crust form on the soil before re-vegetation is commenced, the crust must be broken up by scarifying to a depth of 150 mm;

• Topsoil shall not be compacted in any way, especially by vehicles riding over it;

• The use of anti-erosion compounds should be considered on slopes where there is a risk of erosion;

• Details shall be provided of the topsoil, mulch and manure to be used, seed mix, seed application methods (e.g. hydro seeding), timing of planting, planting density, fertilisation technique (rate of application), weed control, irrigation and any other procedure consistent with good horticultural practice necessary to ensure normal, vigorous and healthy growth of plant material. The selection criteria for topsoil, mulch, manure, fertilizers, binding agents, and other horticultural procedures should be clearly stated and must take into account site specific conditions and the need to minimise negative environmental impacts;

• The use of indigenous vegetation native to the general area in site landscaping and rehabilitation to minimize watering requirements;

• Inclusion of a detailed monitoring programme to assess the progress and success of the site landscaping and rehabilitation.

2.4.3.3 Site Management

Objective • To ensure construction facilities are managed and maintained in accordance with environmental best practice principles and do not negatively impact on the environment;

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• The negative visual impact of structures and lighting on visual/scenic quality shall be minimised.

Management action • A Site Management Plan detailing the layout and method of establishment of the construction camp, including all buildings, offices, lay down areas, vehicle wash areas, fuel storage areas, batching areas, topsoil stockpiles and other infrastructure required for the running of the project must be provided. This is to be approved by Tullow Oil prior to the commencement of construction activities;

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Site Management Plan:

Establishment of boundaries to construction activities • All on-site activities, materials, equipment and personnel shall be restricted to the area specified;

• If additional areas (e.g. for lay down, rest areas for workers) are required, these must be approved in writing by Tullow Oil;

• The Contractor shall erect and maintain permanent and/ or temporary fences of the type and in the locations as directed and approved by Tullow Oil and Namdeb to demarcate the site boundary. Such fences shall, if so specified, be erected before undertaking designated activities;

• Suitable temporary fencing may need to be erected during construction to minimise the risk of injury.

Management of construction workers • Washing whether of personal or personal effects and acts of excretion and urination are strictly prohibited other than at the facilities provided. The Contractor shall provide the necessary ablution facilities for construction personnel prior to the commencement of work and shall ensure that personnel make use of the facilities;

• The Contractor shall designate an on-site eating area for employees. The Contractor shall provide refuse bins with lids in this area. Any cooking on site shall be done on well maintained gas cookers with fire extinguishers present.

Management of natural features and rehabilitated areas • The Contractor and sub-contractors shall not deface, paint, damage or mark any natural features (e.g. rock formations) situated in or around the site for construction or other purposes unless agreed beforehand with Tullow Oil and Namdeb. Any features affected by the contravention of this clause shall be restored/ rehabilitated to the satisfaction of Tullow Oil and Namdeb;

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• Trapping, poisoning and/ or shooting of animals is strictly forbidden unless agreed upon in writing by Namdeb and MET. No domestic pets or livestock are permitted on site;

• Where the use of herbicides, pesticides and other poisonous substances is required, the Contractor shall include details thereof in the Site Management Plan for the approval of Tullow Oil, Namdeb and MET;

• No construction equipment, vehicles or unauthorised personnel shall be allowed onto areas that have been vegetated. Only persons or equipment required for the preparation of areas, application of fertiliser and spreading of topsoil shall be allowed to operate on these areas.

Management of palaeontological/archaeological material found on site If any possible palaeontological/archaeological material is found during excavations, e.g. graves and middens, the Contractor shall stop work immediately and inform Tullow Oil. Tullow Oil will inform the Namibian National Monuments Council and arrange for a palaeontologist/archaeologist to inspect, and if necessary excavate, the material, subject to acquiring the requisite permits.

Management of onsite facilities, infrastructure and equipment • Fire risk management measures applicable to onsite facilities are described in section 2.4.3.6 (below);

• Design and management of facilities, infrastructure and equipment shall be in accordance with management actions to minimise the risk of leaks and spillages which may contaminate soils, groundwater and surface water. These management actions are described in section 2.4.3.7 (below);

• Measures for litter and dust control on the construction site shall be incorporated in all contract documentation for the construction phase.

Management for temporary site closure If the construction site is closed for a period exceeding one week, e.g. over the Christmas holidays, the Contractor in consultation with Tullow Oil shall carry out the following procedure using a checklist:

• Fuels / flammable / hazardous materials stores:

- Ensure fuel stores as low in volume as possible; - No leaks; - Outlet secure / locked; - Bund empty; - Fire extinguisher serviced and accessible; - Area secured from accidental damage e.g. vehicle collision;

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- Emergency and contact numbers available and displayed; - Adequate ventilation; - Safety Officer check prior to closure of site. • Safety:

- All trenches and manholes secured; - Fencing and barriers in place as per the Occupational Health and Safety Act; - Notice boards erected and secured; - Emergency and management contact details displayed; - Site safety officer checks prior to closure as per the Occupational Health and Safety Act;

- Security persons briefed and have facility for contact; - Night hazards checked e.g. reflectors, lighting, and traffic signage; - Fire hazards identified – local authority notified of any potential threats e.g. fuels etc.;

- Scaffolds secured; - Inspection schedule and log by security or contracts staff. • Erosion:

- Wind and dust mitigation in place e.g. straw, brush packs, irrigation; - Slopes and stockpiles at stable angle; - Re-vegetated areas watering scheduled & supply secured; • Water contamination and pollution:

- Fuels/ hazardous stores secured; - Cement and materials stores secured; - Toilets empty and secured; - Refuse bins empty and secured (lids); - Bunding clean and treated e.g. with absorbent material; - Drip trays empty & secured (where possible); - Structures vulnerable to high winds secured.

2.4.3.4 Water Use Management Plan

Objective Minimise the amount of water used during construction.

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Management action The Contractor shall provide Tullow Oil with a Water Use Management Plan. This must detail construction activities for which water will be required, quantities of water required and management actions for minimising unnecessary water consumption and loss. Water conservation best practice measures shall be adopted and reflected in the Water Use Management Plan.

2.4.3.5 Materials Handling and Storage Management

Objective • Ensure materials are safely handled to minimize risk to employees’ health;

• Minimise risk of leaks and spillages which have the potential to contaminate soils, groundwater and surface water.

Management action • The Contractor shall submit a Materials Handling and Storage Management Plan to Tullow Oil for written approval prior to the commencement of construction activities. If potentially hazardous substances are to be stored or used on site, the Contractor shall include in the Materials Handling and Storage Management Plan details of the substances/materials to be used, together with the storage, handling and disposal procedures for the materials. The Materials Handling and Storage Management Plan shall also specify the proposed access route and the proposed transportation schedule for transport of significant quantities of hazardous materials to and from the site;

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Materials Handling and Storage Management Plan.

Materials handling management • Cement and concrete are regarded as hazardous to the natural environment on account of their very high pH and the chemicals contained therein. Therefore the Contractor shall ensure that:

- concrete is not mixed directly on the ground; - the visible remains of concrete, either solid or from washings, are physically removed immediately and disposed of as waste. Washing the residues into the ground is not acceptable.

• The Contractor shall not handle dry cement during windy periods without taking precautions to prevent wind mobilisation of the material (cement dust). Special care shall be taken when working in the vicinity of the mining ponds because of the possible damage caused by cement entering the water bodies. Special care shall also be taken to avoid creating dust in the vicinity of the following areas:

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- thoroughfares; - residential areas; - environmentally sensitive areas. • As far as possible loading and unloading of materials shall occur in bunded areas to contain any spillage which may occur;

• Materials handling equipment shall be properly maintained and serviced regularly to ensure the proper functioning of the systems designed to minimize dust, fugitive emissions and spillages;

• If spillages occur as a result of faulty equipment, equipment shall be repaired immediately;

• If petrol, diesel or oil refuelling is to take place on the construction site then the surface under the refuelling area shall be protected against pollution to the satisfaction of Tullow Oil. A properly equipped service vehicle for re-fuelling shall be available;

• Prior to any refuelling or maintenance activities, Tullow Oil must approve the absorbent material available to absorb/breakdown spillages, or where possible, refuelling areas are to be designed to encapsulate minor hydrocarbon spillages i.e. to be able to handle a minimum of 200 ℓ of hydrocarbon liquid spill;

• Materials shall be appropriately secured to ensure safe passage between destinations. Loads including but not limited to sand, stone chip, refuse, paper and cement, which could cause contamination of the air or ground, shall be appropriately covered to prevent materials spilling from the vehicles during transit;

• The Contractor shall comply with all the applicable local, regional and national by- laws with regard to road safety and the transport of materials, especially hazardous and/or toxic materials;

• Further measures to minimize the risk of spillage during transportation include:

- Use of appropriate vehicles and load labeling; - Facilitate proper driver training to minimise the risk of accidents leading to materials spills.

Materials storage management • All storage facilities for hazardous substances to comply with the relevant South African Bureau of Standards (SABS) codes of practice for the handling and storage of hazardous substances, including adequate bunding of such facilities in order to contain possible spillages;

• All manufactured and/ or imported materials shall be stored within the Contractor's camp, and, if so required, out of the reach of moisture e.g. wet fog and rain;

• All materials storage areas and stockpiles shall be designed and managed so as to reduce the risk of spillages, contamination of soils, groundwater, surface water and

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stormwater or damage to materials as a result of strong wind. Methods of protection for stored materials shall be included in the Materials Handling and Storage Management Plan;

• Tanks containing fuels shall have lids and shall remain firmly shut. Only clean, empty tanks may be stored on the bare ground. Fuel stores shall be placed on a bunded sealed base. The bund should accommodate 110% of the total volume for single tanks. Where two or more tanks are installed within the same bund, the bund should accommodate 110% of the largest tank or 25% of the total capacity of all tanks, whichever is the greater;

• Used oil shall be stored at a central location on site prior to removal off site for disposal at an approved disposal site.

Hazardous substances • The Contractor shall comply with all applicable national, regional and local legislation with regard to the transport, use and disposal of hazardous materials. Hazardous chemical substances (as defined in the Regulations for Hazardous Chemical Substances) used during construction shall be stored in secondary containers. The relevant Material Safety Data Sheets (MSDS) shall be available on site. Procedures detailed in the MSDSs shall be followed in the event of an emergency situation;

• The Contractor shall be responsible for the training and education of all personnel on site who will be handling hazardous materials about their proper use, handling and disposal;

• The Contractor shall ensure that no oil, petrol, diesel, etc. is discharged onto the ground.

2.4.3.6 Fire Control and Emergency Procedures

Objective • Minimize the risk of the outbreak of fire and other upset conditions;

• Ensure that incidents are effectively contained and negative environmental impacts minimised.

Management action • The Contractor shall submit a Fire Control and Emergency Procedures Management Plan for dealing with emergency procedures to Tullow Oil prior to the start of construction. Emergency procedures shall include, but shall not be limited to, fire, flooding, storms, accidents to employees, use of hazardous substances, etc. Procedures detailed in the MSDSs for hazardous materials shall be included in the Fire Control and Emergency Procedures Management Plan and followed in the event of an emergency;

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• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Fire Control and Emergency Procedures Management Plan.

Fire risk management • The Contractor shall take all the necessary precautions to ensure that fires are not started as a result of their activities on site, including the workers’ camp. No open fires shall be permitted on or off site. No on site burning of any waste materials, vegetation, litter or refuse shall occur;

• Smoking shall not be permitted in those areas where there is a fire hazard. Such areas shall include the workshop and fuel storage areas and any areas where or other material capable of supporting the rapid spread of an initial flame;

• The Contractor shall take all necessary precautions to prevent fires or spills at the fuel store. No smoking shall be allowed in the vicinity of the store. Failure to adhere to this requirement shall be cause for a spot fine being imposed on the offender;

• The Contractor shall ensure that there is adequate and appropriate fire-fighting equipment at the fuel storage area;

• The Contractor shall ensure that there is basic fire fighting equipment available on site at all times. This shall include at least one fire extinguisher of the appropriate type when welding or other “hot” activities are undertaken;

• The Contractor shall ensure that all sub-contractors and construction workers are aware of the procedures to be followed in the event of a fire both on site and at the workers’ camp;

• Any fires that occur shall be reported by the Contractor to Tullow Oil and to Namdeb’s chief of emergency services;

• The Contractor shall appoint a Fire Officer who shall be responsible for ensuring immediate and appropriate actions in the event of a fire and shall ensure that employees are aware of the procedures to be followed. The Contractor shall forward the name of the Fire Officer to Tullow Oil and Namdeb.

Emergency procedures • Emergency procedures, including the names of responsible personnel, contact details of emergency services, etc. shall be made available to all the relevant personnel and shall be clearly demarcated at appropriate locations around the site;

• Telephone numbers of emergency services, including the local (Oranjemund) fire fighting service, shall be posted conspicuously in the Contractor’s site office near the telephone. In the event of an emergency, the Contractor shall contact the Namdeb emergency department;

• The Contractor shall advise Tullow Oil immediately of any emergencies on site, together with a record of the immediate actions taken. The Contractor will submit a full

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report on the handling of the emergency as soon as possible (i.e. within the following hours or days commensurate with the severity of the incident).

2.4.3.7 Leak and Spillage Management

Objective Where leaks and spillages do occur, to minimise negative environmental impacts through rapid and effective containment and clean-up actions.

Management action • The Contractor shall submit a Leak and Spillage Management Plan to Tullow Oil prior to the start of construction activities. Procedures detailed in the MSDSs for hazardous materials shall be included in the Leak and Spillage Management Plan and followed in the event of an emergency situation. [See also section 2.4.3.6 and 2.4.3.7];

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Leak and Spillage Management Plan.

Containment of leaks and spillages • The Contractor shall ensure that in any workshop and other equipment maintenance facilities, including those areas where, after obtaining Tullow Oil approval, the Contractor carries out emergency equipment maintenance, i.e. after an on-site breakdown, there is no contamination of the soil;

• Any workshop shall have a smooth impermeable (concrete or thick plastic covered with sand) floor. The floor shall be bunded and sloped towards an oil trap or sump to contain any spillages;

• Pumps and other machinery requiring oil, diesel, etc. that is to remain in one position for longer than two days shall be placed on drip trays. The drip trays shall be emptied regularly and the contaminated water disposed of off site at a facility capable of handling such wastewater [See section 2.4.3.11]. Drip trays shall be cleaned before any possible rain events that may result in the drip trays overflowing and before long weekends and holidays;

• All vehicles and equipment shall be kept in good working order and serviced regularly;

• All equipment that leaks onto the ground shall be repaired immediately or removed;

• If servicing and fuelling of vehicles and equipment takes place on site, this shall occur at dedicated and properly equipped facilities agreed upon by Tullow Oil. All waste generated by these activities shall be managed as per the Solid Waste Management Plan and the Wastewater Management Plan [see section 2.4.3.9 and 2.4.3.11];

• If petrol, diesel or oil refuelling is to take place on the construction site then the surface under the refuelling area shall be protected against pollution to the

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satisfaction of Tullow Oil. A properly equipped service vehicle for re-fuelling shall be available prior to any refuelling activities being undertaken;

• When servicing equipment, drip trays shall be used to collect the waste oil and other lubricants. Drip trays shall also be provided in construction areas for stationary plant (such as compressors) and for "parked" plant (such as scrapers, loaders, vehicles);

• The Contractor shall not change oil or lubricants anywhere on site except at designated locations, except if there is a breakdown or an emergency repair. If emergency repairs are required outside of designated areas, the Contractor shall obtain the approval of Tullow Oil prior to commencing such activities and shall ensure that he has appropriate absorbent materials (or equivalent) and/or drip trays available to collect any oil, fluid, etc.

Clean-up of leaks and spillages • Emergency procedures shall be developed and communicated to all personnel such that they are aware of the procedures to be followed for dealing with spills and leaks. The procedures shall include identification of responsible personnel and reporting procedures, contact details of emergency services, etc.;

• Procedures detailed in the MSDSs for hazardous materials shall be followed in the event of an emergency situation;

• The Contractor shall ensure that the necessary materials and equipment for dealing with spills and leaks is available on site at all times;

• The Contractor shall ensure that there is always a supply of absorbent material readily available to absorb/ breakdown or where possible, be designed to encapsulate minor hydrocarbon spillages. The quantities of such materials shall be able to handle a minimum of 200 ℓ of hydrocarbon liquid spill;

• Any wastewater or spilled fuel collected within the bund around the refuelling area shall be disposed of as hazardous waste. [See section 2.4.3.9 and 2.4.3.11];

• The Contractor shall remove all oil, petrol, and diesel-soaked sand immediately and shall dispose of it as hazardous waste;

• If spillages of materials occur during transportation, spillages shall be cleaned up immediately and disposed of at the appropriate disposal facility;

• Treatment and remediation of the spill areas shall be undertaken to the reasonable satisfaction of Tullow Oil. In the event of a hydrocarbon spill, the source of the spillage shall be isolated and the spillage contained. The area shall be cordoned off and secured;

• Any spillages shall be reported immediately to Tullow Oil.

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2.4.3.8 Solid Waste Management

Objective • To maximise the internal and external recycling of materials;

• To minimise the volume of solid waste requiring disposal by landfill.

Management action The Contractor to compile and submit a detailed Waste Classification Report before commencement of construction. This report must:

• Classify all waste generated during the construction of the gas treatment plant, in accordance with both the primary (SABS Code 0228) and secondary classification of waste as specified in the Minimum Requirements for the Handling, Classification and Disposal of Hazardous Waste of the South African Department of Water Affairs (DWAF, 1998);

• Indicate management endpoints such as recycling or disposal destinations of each individual waste stream;

• A Solid Waste Management Plan shall be designed and implemented for the construction phase of the development. The Solid Waste Management Plan shall:

- Record quantities and composition of waste streams, sources of waste streams, length of storage on site, and final destinations. This would constitute the basis for a continuous improvement programme in waste minimisation;

- Incorporate the following waste management hierarchy to mitigate environmental impacts:

o minimise the generation of waste; o re-use the waste during construction; o re-use or recycle waste streams to other users at other locations; o dispose unusable waste streams at permitted waste disposal facilities. - Incorporate the Waste Classification Report; • Be in place prior to the start of construction and be updated at regular intervals, as specified in the plan;

• The legal requirements of the Contractor and all sub-contractors shall be identified and included in contractual agreements. These requirements include:

- In their tender documents, all sub-contractors supplying equipment and raw materials are to provide a detailed breakdown of all waste associated with their supplies (e.g. packaging waste), including classification by type (general, hazardous etc) and quantity. This information shall inform the development of the Solid Waste Management Plan;

- The Contractor and its sub-contractors shall comply with all applicable national, regional and local legislation with regard to the disposal of hazardous materials;

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- Adherence to the Solid Waste Management Plan shall be a contractual obligation between Tullow Oil and the Contractor, as well as with all sub-contractors;

- The Contractor’s sub-contractors shall submit Solid Waste Management Method Statements for the management of hazardous substances that detail the disposal procedures for these materials and the handling different types of wastes.

• The system for collecting, sorting, disposal and recycling of waste shall be clearly described in the Solid Waste Management Plan. This shall include:

- A separate waste disposal area shall be designated on the construction site, which contains clearly demarcated skips and bins to allow different types of waste to be separated at source: domestic, metal scrap, used oil, paper, hazardous etc. In addition, separation along the lines of potential re-use and recycling opportunities shall be undertaken;

- The Contractor shall provide sufficient bins with lids to store the solid waste produced on a daily basis. Bins shall not be allowed to become overfull and shall be emptied as a minimum on a weekly basis. The waste may be temporarily stored on site in a central waste area that is weatherproof and scavenger proof, and which Tullow Oil and Namdeb have approved;

- No on site burning, burying or dumping of any waste materials, vegetation, litter or refuse shall occur.

• Moved earth and the associated rubble is unlikely to be contaminated and require disposal. This could therefore potentially be re-used on site to construct landscape features and thereby minimize the amount of waste requiring disposal by landfill;

• The amount of waste sent to landfill can be further reduced by investigating opportunities for recycling or re-use of waste. This investigation shall include potential treatment options which would increase the recyclability and re-usability of these waste streams;

• The waste sorting and temporary storage area shall be permanently controlled by a dedicated waste management officer to ensure compliance with the waste sorting and disposal requirement;

• The Contractor shall ensure that waste management contractors are suitably qualified and equipped to manage the waste generated during construction;

• The Contractor shall ensure that disposal facilities (whether landfill, or processing plants) have the necessary permits required in order to process the waste or by- product received from the construction site;

• All solid waste shall be disposed of at an approved landfill site. The Contractor shall supply Tullow Oil with a certificate of disposal.

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2.4.3.9 Dust management

Objective • To minimise the nuisance impact on the work force of dust generation during construction;

• To minimise potential risks from dust generation to vegetation and animals.

Management action A Dust Management Plan shall be compiled and implemented for the construction phase of the development and the following key issues included:

• Avoidance of unnecessary removal of vegetation;

• Routine spraying of unpaved site roads and access roads with water;

• Limiting vehicle-entrained dust from unpaved roads through traffic control measures e.g. limiting vehicle speeds;

• Re-vegetation of disturbed areas not occupied by plant infrastructure to take place as soon as possible;

• Covering of materials with the potential to result in dust and air contamination during transportation;

• Avoid handling dry cement during windy periods without taking precautions to prevent mobilization of the material (cement dust);

• Where possible, cover construction areas that generate dust with temporary shade- cloth or plastic sheeting to minimise dust generation. Each sub-contractor whose activities on site may contribute to dust will be required to submit a Dust Management Method Statement to the Contractor. In the Method Statement, the sub-contractor must detail how the management objectives and principles for dust management are to be met. Consequently, the Method Statements will largely inform the Dust Management Plan to be prepared by the Contractor and submitted to Tullow Oil for written approval prior to the commencement of the relevant construction activities.

2.4.3.10 Wastewater Management

Objective • Minimise deterioration of groundwater and surface water quality.

• Limit degradation of landscape through erosion.

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Management action The Contractor shall compile and implement a Wastewater Management Plan, which shall be prepared prior to commencing construction and approved by Tullow Oil and Namdeb. The Wastewater Management Plan shall include the following details:

• The plan shall identify sources of wastewater; and state the collection facilities that are to be used to prevent pollution, as well as the method of disposal of the contaminated water;

• No cement-laden water may be discharged overland, i.e. washings from trowels, wheelbarrows and concrete mixers. The quantity to be discharged needs to be approved by Tullow Oil before any discharge takes place. The quality shall also conform to the general standards for effluent discharge;

• Water from washing large concrete-mixing equipment (mixers and the like) shall not be discharged overland. Such water shall be removed from the site and disposed of in the correct manner. The Contractor may consider recycling this water to minimise discharges;

• All washing operations shall take place at a location where wastewater can be disposed of in the correct manner;

• All washing of equipment or machinery shall be undertaken in designated areas (e.g. workshop or maintenance areas), and these areas must be equipped with a suitable impermeable floor and sump/oil trap. The use of detergents for washing shall be restricted to low phosphate and nitrate containing and low sudsing type detergents;

• Workshops, refuelling depots and washing areas shall be bunded;

• Oils collected in grease traps shall be collected by the appointed waste disposal contractor;

• Any wastewater or spilled fuel collected within bunded areas around the refuelling area shall be disposed of as hazardous waste;

• Approved wastewater discharges need to be monitored weekly by the Contractor to ensure that the General Limit values are not exceeded. Monitoring shall include, as a minimum, the following characteristics:

- PH; - Conductivity; - Total Dissolved salts/solids; - Faecal Coliforms; - Lead. • In the event that quality changes are detected in discharges, the sampling frequency shall increase to daily samples until the problem has been solved and the water quality returned to concentrations prior to the incident. Samples will be taken during working activities and not during shut-down periods;

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• The Contractor or his designated authority, will interpret the water quality results and provide Tullow Oil with a regular update of the effluent quality;

• Ablution facilities not linked to the sewage reticulation system will be located in remoter areas of the site;

• All sensitive material storage areas shall be designed to reduce risk of spillages. All materials shall be covered during transport to prevent them from spilling. If there is a risk of contamination of stormwater, all stockpiles shall be covered to be kept out of the rain and wet fog;

• Contaminated stormwater and other run-off from the construction site shall be contained. Construction of the dirt trap, interceptor pond and the attenuation dam shall commence as early as possible in the construction phase;

• In the event of a spill which may contaminate stormwater, the spill management procedures shall be implemented immediately.

2.4.3.11 Transportation Management

Objective • Minimise risks to other road users related to construction traffic and use of heavy vehicles;

• Minimise degradation of road structure due the use of heavy vehicles

Management action The Contractor shall compile and implement a Transportation Management Plan, which shall be prepared prior to commencing construction and approved by Tullow Oil. If necessary for the development of this plan, sub-contractors will be required to submit Transportation Method Statements to the Contractor which shall form the basis for the Transportation Management Plan. The Transportation Management Plan shall include the following details:

• The Contractor shall comply with all applicable national, regional and local legislation with regard to the transport of hazardous materials. Of importance is the training and education of personnel and drivers in handling these hazardous materials. This includes road safety when transporting these materials;

• Properly trained drivers and well maintained vehicles shall be used during the construction phases of the development. The Contractor shall ensure that all delivery drivers are informed of all procedures and restrictions on routes. The Contractor shall also ensure that delivery drivers are supervised during offloading by someone with an adequate understanding of the requirements of the EMP;

• Overloading of vehicles shall be avoided to limit the impact on the structural capacity of roads along which materials and waste are transported. Transporters shall comply

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with Namibian vehicle loading regulations and routes should be selected accordingly to ensure that damage to road infrastructure is minimised;

• Only transport operators appointed through the Transport Tender Process shall be used for the transport of materials and personnel.

2.4.3.12 Noise Management

Objective The Contractor to comply with the Labour Act, 1992: Regulations relating to the Health and Safety of Employees at Work (1997)

Management action The Contractor shall compile and implement a Noise Management Plan, which shall be prepared prior to commencing construction and approved by Tullow Oil. The Noise Management Plan shall include the following details:

• The Contractor and sub-contractors to comply with the measures for good practice with regard to management of noise-related impacts during construction. The following measures for good practice shall be incorporated:

- All equipment shall be kept in good working order; - Equipment shall be operated within specifications and capacity (eg. don't overload machines);

- Regular maintenance of equipment will be undertaken particularly with regards to lubrication;

- Equipment shall be operated with appropriate noise abatement accessories such as sound hoods and the Contractor shall ensure that these accessories are correctly maintained;

- Equipment shall be operated in as diversified a manner as possible (i.e. if possible, spread operation of equipment throughout working periods rather than operating several items simultaneously);

- Equipment shall be turned off when not in use; - Pumps, generators, compressors and saws shall be positioned in sheltered locations;

- Partly finished buildings shall be used to accommodate pumps, generators, compressors and saws;

- When using pile drivers, jack hammers, rock drills and for blasting activities, times when the environment is least sensitive to noise impact shall be selected, preferably during daytime hours and during normal working days.

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2.4.3.13 Management of recruitment, labour, skills development and training

Objective • Maximise opportunities for employment of local labour;

• Promote skills development, training of the construction workforce and expansion of the local skills base;

• Minimise the pressures associated with the in-migration of job seekers on surrounding communities and on existing infrastructure and services;

• Minimise security risks at the construction site.

Management action • Comply with recruitment and labour management legislation and regulations;

• In order to minimise the risk of accidents and illnesses amongst the construction workforce the Contractor shall submit an Occupational Health and Safety Management Plan in accordance with the Occupational Health and Safety Act, and regulations promulgated thereunder prior to any construction on site;

• To optimise the employment creation benefits of the construction phase of the power station project, the Contractor shall undertake the following actions as part of their recruitment and labour management processes: - Maximise the use of Namibian nationals as far as possible; - Consider employment opportunities and the needs of disabled people during the planning of construction activities; - Construction workers to be housed in facilities provided by the Contractor/Tullow Oil.

Training and skills development To optimize the benefits of training and skills development associated with the power station project the Contractor and Tullow Oil shall ensure that the following actions are undertaken:

• Each sub-contractor shall provide a Training and Skills Development Method Statement detailing the actions they shall undertake to promote local skills development and capacity building. These Method Statements will be consolidated into a Training and Skills Development Management Plan by the Contractor which will be submitted to Tullow Oil;

• A skills development and training programme shall be implemented;

• Make multi-skilling of construction workers an important priority as employment opportunities during construction are only temporary;

• During construction, ensure that regular audits of training providers are conducted to ensure that appropriate skills and capacity are built effectively;

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• For the operational phase, where the required skills do not occur locally, and where appropriate and applicable, ensure that relevant local (Namibian) individuals are trained. Such training shall be pro-active and shall start during the construction phase in order to have trained personnel available once the power station becomes operational.

In-migration of job seekers In-migration of job seekers is already occurring within the Karas Region e.g. at Rosh Pinah. In order to minimise in-migration, Tullow Oil will implement the following actions:

• Ensure that measures designed to minimise the number of induced migrants, is being implemented and adhered to by the Contractor and sub-contractor;

• Actively downplay (through clear, simple and persistent communication) inflated expectations of employment opportunities. Also, communicate in the same manner that recruitment will only take place, at designated recruitment centres and not on- site;

• Establish a forum with Namdeb, Rosh Pinah, Skorpion and relevant departments of the Karas Regional local government to formalise discussions around the management of job-seekers and to ensure that support can be given if situations in certain areas become critical.

Management of security risks Management of general security within Oranjemund lies within Namdeb’s responsibility. The Contractor will be responsible for security matters on the construction site including the workers’ camp. Management actions include:

• Ensuring compliance with Diamond Area security requirements;

• Ensuring no unauthorised firearms are permitted on site;

• Providing assistance to the Oranjemund Town Management to address the potential for increased criminal activity.

2.4.3.14 Investment, Procurement and Sales Management

Objective • Ensure benefits of foreign direct investment in Namibia and in the Karas Region are maximised;

• Maximise procurement of local goods and services;

• Contribute to an increase in local and national Gross Domestic Product (GDP) and Gross National Disposable Income (GNDI).

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Management action In order for Namibia to best realize the economic benefits of the Kudu gas field development project, Tullow Oil and the Contractors are to ensure that, as far as possible, use is made of local raw materials and goods and services during development and production.

2.4.3.15 Environmental and HIV/AIDS awareness training for employees and contract workers

Objective • Reduce the number and severity of incidents during the construction phase that lead to a negative impact on the natural environment and human health;

• Minimise the risk of construction activities contributing to the increased spread of HIV/AIDS amongst the construction workforce and the surrounding communities.

Management action In order to promote awareness of environmental and health issues Tullow Oil, in conjunction with Namdeb, shall ensure that the following actions are undertaken:

• An HIV/AIDS policy and programme to be implemented;

• Before any work is commenced on the site, the Contractor’s site management staff, including foremen, shall attend an environmental awareness training course, of approximately one-hour duration, during normal working hours, presented by the Contractor. The Contractor shall ensure that all attendees sign an attendance register, and shall provide Tullow Oil and Namdeb with a copy of the attendance register;

• The information presented at the course shall be communicated to the Contractor’s employees on the site, to any new employees coming onto site after the initial training course and to any sub-contractors and suppliers;

• A general environmental awareness programme aimed at all employees of the Contractor, sub-contractors and suppliers is to be made available from the Contractor. If there are persistent breaches of the specifications contained in this document and/or if new environmental issues arise during the course of construction, Tullow Oil may require additional environmental training sessions to be given to relevant employees. Tullow Oil in consultation with the Contractor will determine attendance at those sessions;

• The Contractor shall erect and maintain information posters for the information of their employees depicting actions to be taken to ensure compliance with all aspects of the Construction EMP. Such posters shall be well positioned by the Contractor (e.g. in eating areas, information areas and along walkways). They must be secured and weather-proof. Simple language and cartoons that are understood by the majority of employees must be used;

• The Contractor shall ensure that all employees are aware of the procedures to be followed in the event of a fire;

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• The Contractor shall be responsible for the training and education of all personnel on site who will be handling and transporting hazardous materials about their proper use, handling, transportation and disposal;

• The Contractor shall ensure that all employees are aware of the procedures to be followed for dealing with emergencies, which shall include notifying Tullow Oil, Namdeb and the relevant authorities;

• Emergency procedures, including the names of responsible personnel, contact details of emergency services, etc. shall be made available to all the relevant personnel and shall be clearly demarcated at the relevant locations around the site. In order to minimise the impact of the construction activities in contributing to the increased spread of HIV/AIDS, Tullow Oil is to work together with other institutions in implementing the following actions:

• Draw on the Namibian national programme for HIV/AIDS awareness and management;

• Consult with other major industries in the Karas Region, for example, Namdeb, Skorpion and Rosh Pinah, regarding current HIV/AIDS programmes which they have in place, to refine the Tullow Oil HIV/AIDs programme.

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2.5 CONSTRUCTION OF THE GAS CONDITIONING PLANT

2.5.1 Pre-establishment Phase

2.5.1.1 Pre-establishment planning

Objective Liaison with NamPower and Namdeb

Management Action In order to ensure the smooth running of the construction of the gas conditioning plant simultaneously with the construction of the CCGT power station:

• Establish the environmental management requirements for the operation of the construction site so as to align them with Namdeb’s environmental management plan for Mining Area 1;

• Liaise with NamPower and Namdeb with respect to the provision of shared services to the construction site.

Responsibility Tullow Oil.

Timing Prior to commencement of operations.

Reporting Requirements Provide record of meetings to NamPower and Namdeb.

2.5.1.2 Financial Provision

Objective Compliance with legislative requirements.

Management Action Ensure that financial provision is in place to execute the requirements of this EMP and to ensure rehabilitation of the gas conditioning plant site at the end of the gas field’s life.

Responsibility Tullow Oil and relevant Contractors.

Timing Prior to commencement of operations.

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Reporting Requirements Confirm that financial provision has been made.

2.5.1.3 Emergency procedures

Objective Preparation for any emergency that may have an environmental impact. Note: this does not include medical emergencies as a result of accidents or illness.

Management Action Management plans for the following should be in place:

• Company Emergency Response Plan (including medical evacuation);

• Contractor's site management plan;

• Contractor's insurance cover for pollution incidents.

Responsibility Tullow Oil and relevant Contractors.

Timing Prior to commencement of operation.

Reporting Requirements Confirm compliance and justify any omissions to Tullow Oil.

2.5.1.4 Development and implementation of EMP compliance system

Objective To ensure that all the environmental management requirements and actions in the EMPR are implemented, monitored and complied with by the contractors.

Management Action • Tullow Oil is to ensure that the following conditions are incorporated into the contractual agreements with the Contractor prior to the commencement of their construction activities:

- Contract documentation for the Contractor and sub-contractors to include requirements for preferential use of local labour and local goods and services;

- Contract documentation for the Contractor and sub-contractors to include requirements for the multi-skilling of construction workers;

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- A performance-based requirement with regard to environmental impact management must be included in all contracts related to any activity associated with the construction of the onshore facilities.

• A protocol for managing infringements by the Contractors or sub-contractors needs to be developed by Tullow Oil in consultation with the Contractors. This may include, for example, monthly report backs at the HSE and Risk Management sub-committee meetings at which any infringements are reviewed and compensation or remediation measures are proposed by the Contractor, as well as actions to be taken to prevent repeat infringements from occurring. Important principles to be included in this protocol are:

- Ensure all relevant personnel are trained in environmental management and pollution response procedures and that the appropriate equipment is available;

- Assurance of a rapid response to stop infringements and to the taking of corrective action;

- Minimisation of impacts and avoidance of repeat infringements; - Identification of appropriate forms of direct compensation or remediation (financial or non-financial) are identified, agreed upon and applied. Of importance is that if financial compensation is agreed upon, compensation payments must be used to rectify the damage incurred or transferred into a fund which would be used to support local environmental management initiatives;

- Records are kept of all infringements, corrective actions and compensation; - Infringements, corrective action and compensation details are included in scheduled reporting processes.

• Ensure that all Contractors, NamPower, Namdeb and MME are provided with copies of the EMPR.

Responsibility Tullow Oil and relevant Contractors.

Timing • Prior to commencement of construction all relevant conditions of the EMPR must be incorporated into contractual agreements with Contractors;

• Prior to commencement of construction Tullow Oil must have a protocol for managing infringements of the EMPR conditions in place and fully understood by all Contractors.

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Reporting Requirements All Contractors must ensure that they meet the monitoring and reporting requirements as determined by their contracts and by the Project EHS Advisor (see Section 2.5.1.4 above).

2.5.2 Construction

2.5.2.1 Responsibility, timing and reporting

The responsibility for ensuring compliance with the EMPR ultimately rests with Tullow Oil. However, the day-to-day responsibility for ensuring compliance and reporting rests with the Contractors who will be required to monitor all environmental aspects throughout the construction operations.

2.5.2.2 Site clearing and landscaping

Objective • To minimize the amount of land and indigenous fauna and flora disturbed through construction activities;

• To re-vegetate and rehabilitate the site on completion of construction with locally indigenous vegetation as far as possible.

Management action Site clearance is to be undertaken in accordance with the following principles:

• Avoidance of unnecessary removal of vegetation;

• Only those areas of the site where construction and lay-down are going to take place must be cleared. The remaining areas on the site to be clearly demarcated and left intact;

• Stabilisaton of slopes that are disturbed during construction to prevent mobilization of dust by wind;

• Storage of topsoil removed from the site to ensure that the seedbank is retained. If different categories of topsoil exist these should be stored separately;

• Stockpiles to be covered to reduce dust generation and erosion.

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The detailed Landscaping Management Plan is to be compiled to the satisfaction of MET and Namdeb and landscaping and rehabilitation of the site to take place in accordance with such an approved plan. This plan should take into account and, where required, describe in detail, amongst others but not limited to, the following considerations:

• Maximum use of construction rubble in landscaping to reduce the amount of construction waste;

• As a general principle, potable water should not be used for irrigation purposes and landscapes must be designed to absorb rainwater run-off;

• Re-vegetation of disturbed areas not occupied by plant infrastructure to take place as soon as possible. Progressive rehabilitation will be applied, in that areas no longer required for construction activities will be rehabilitated as soon as they become available for rehabilitation;

• Areas that require reshaping shall be cut, filled and compacted as necessary so as to blend with the surrounding landscape;

• The shaping of cut-and-fill slopes to allow for the re-establishment of indigenous vegetation;

• Topsoil shall not be compacted in any way, especially by vehicles riding over it;

• The use of anti-erosion compounds should be considered on slopes where there is a risk of erosion;

• The use of indigenous vegetation native to the general area in site landscaping and rehabilitation to minimize watering requirements;

• Inclusion of a detailed monitoring programme to assess the progress and success of the site landscaping and rehabilitation.

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2.5.2.3 Site Management

Objective • To ensure construction facilities are managed and maintained in accordance with environmental best practice principles and do not negatively impact on the environment;

• The negative visual impact of structures and lighting on visual/scenic quality shall be minimised.

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Site Management Plan.

Establishment of boundaries to construction activities • All on-site activities, materials, equipment and personnel shall be restricted to the areas specified;

• If additional areas (e.g. for lay down, rest areas for workers) are required, these must be approved in writing by Tullow Oil;

• Suitable temporary fencing may need to be erected during construction to minimise the risk of injury.

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Management of natural features and rehabilitated areas • The Contractor and sub-contractors shall not deface, paint, damage or mark any natural features (e.g. rock formations) situated in or around the site for survey or other purposes unless agreed beforehand with Tullow Oil and Namdeb. Any features affected by the contravention of this clause shall be restored/ rehabilitated to the satisfaction of Tullow Oil and Namdeb;

• Trapping, poisoning and/ or shooting of animals is strictly forbidden unless agreed upon in writing by Namdeb and MET. No domestic pets or livestock are permitted on site;

Management of onsite facilities, infrastructure and equipment • Fire risk management measures applicable to onsite facilities are described in section 2.5.2.7 (below);

• Measures for litter and dust control on the construction site shall be incorporated in all contract documentation for the construction phase.

• Fuels / flammable / hazardous materials stores:

- Ensure fuel stores as low in volume as possible;

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- No leaks; - Outlet secure / locked; - Bund empty; - Fire extinguisher serviced and accessible; - Area secured from accidental damage e.g. vehicle collision; - Emergency and contact numbers available and displayed; - Adequate ventilation; - Safety Officer check prior to closure of site. • Safety:

- Scaffolds secured; - Inspection schedule and log by security or contracts staff. • Erosion:

- Wind and dust mitigation in place eg. straw, brush packs, irrigation; - Slopes and stockpiles at stable angle; - Re-vegetated areas watering scheduled & supply secured. • Water contamination and pollution:

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2.5.2.4 Water Use Management Plan

Objective Minimise the amount of water used during construction.

2.5.2.5 Materials Handling and Storage Management

Objective • Ensure materials are safely handled to minimize risk to employees’ health;

• Minimise risk of leaks and spillages which have the potential to contaminate soils, groundwater and surface water.

Management action • The Contractor shall submit a Materials Handling and Storage Management Plan to Tullow Oil for written approval prior to the commencement of construction activities. If potentially hazardous substances are to be stored or used on site, the Contractor shall include in the Materials Handling and Storage Management Plan details of the substances/ materials to be used, together with the storage, handling and disposal procedures for the materials. The Materials Handling and Storage Management Plan shall also specify the proposed access route and the proposed transportation schedule for transport of significant quantities of hazardous materials to and from the site;

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Materials Handling and Storage Management Plan.

- concrete is not mixed directly on the ground;

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- the visible remains of concrete, either solid or from washings are physically removed immediately and disposed of as waste. Washing the residues into the ground is not acceptable.

- thoroughfares; - residential areas; - environmentally sensitive areas. • As far as possible loading and unloading of materials shall occur in bunded areas to contain any spillage which may occur;

• Materials handling equipment shall be properly maintained and serviced regularly to ensure the proper functioning of the systems designed to minimize dust, fugitive emissions and spillages;

• If spillages occur as a result of faulty equipment, equipment shall be repaired immediately;

• The Contractor shall comply with all the applicable local, regional and national by- laws with regard to road safety and the transport of materials, especially hazardous and/or toxic materials;

• Further measures to minimize the risk of spillage during transportation include:

- Use of appropriate vehicles and load labeling; - Facilitate proper driver training to minimise the risk of accidents leading to materials spills.

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• All manufactured and/ or imported materials shall be stored within the Contractor's camp, and, if so required, out of the reach of moisture e.g. wet fog and rain;

• All materials storage areas and stockpiles shall be designed and managed so as to reduce the risk of spillages, contamination of soils, groundwater, surface water and stormwater or damage to materials as a result of strong wind. Methods of protection for stored materials shall be included in the Materials Handling and Storage Management Plan;

• Used oil shall be stored at a central location on site prior to removal off site for disposal at an approved disposal site.

• The Contractor shall be responsible for the training and education of all personnel on site who will be handling hazardous materials about their proper use, handling and disposal;

• The Contractor shall ensure that no oil, petrol, diesel, etc. is discharged onto the ground.

2.5.2.6 Fire Control and Emergency Procedures

Objective • Minimize the risk of the outbreak of fire and other upset conditions;

• Ensure that incidents are effectively contained and negative environmental impacts minimised.

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Management action • The Contractor shall submit a Fire Control and Emergency Procedures Management Plan for dealing with emergency procedures to Tullow Oil prior to the start of construction. Emergency procedures shall include, but shall not be limited to, fire, flooding, storms, accidents to employees, use of hazardous substances, etc. Procedures detailed in the Material Safety Data Sheets (MSDS) for hazardous materials shall be included in the Fire Control and Emergency Management Plan and followed in the event of an emergency;

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Fire Control and Emergency Procedures Management Plan.

• The Contractor shall ensure that there is adequate and appropriate fire-fighting equipment at the fuel storage area;

• The Contractor shall ensure that all sub-contractors and construction workers are aware of the procedures to be followed in the event of a fire both on site at the workers’ camp;

• Any fires that occur shall be reported by the Contractor to Tullow Oil and to Namdeb’s chief of emergency services;

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• The Contractor shall advise Tullow Oil immediately of any emergencies on site, together with a record of the immediate actions taken. The Contractor will submit a full report on the handling of the emergency as soon as possible (i.e. within the following hours or days).

2.5.2.7 Leak and Spillage Management

Objective Where leaks and spillages do occur, to minimise negative environmental impacts through rapid and effective containment and clean-up actions.

• The Contractor must ensure compliance with the following and, where necessary, include details of how this will be achieved in the Leak and Spillage Management Plan.

• Any workshop shall have a smooth impermeable (concrete or thick plastic covered with sand) floor. The floor shall be bunded and sloped towards an oil trap or sump to contain any spillages;

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handling such wastewater [See section 2.5.2.11]. Drip trays shall be cleaned before any possible rain events that may result in the drip trays overflowing and before long weekends and holidays;

• All vehicles and equipment shall be kept in good working order and serviced regularly;

• All equipment that leaks onto the ground shall be repaired immediately or removed;

• Procedures detailed in the MSDSs for hazardous materials shall be followed in the event of an emergency situation;

• The Contractor shall ensure that the necessary materials and equipment for dealing with spills and leaks is available on site at all times;

• Any wastewater or spilled fuel collected within the bund around the refuelling area shall be disposed of as hazardous waste. [See section 2.5.2.9 and 2.5.2.11];

• The Contractor shall remove all oil, petrol, and diesel-soaked sand immediately and shall dispose of it as hazardous waste;

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• If spillages of materials occur during transportation, spillages shall be cleaned up immediately and disposed of at the appropriate disposal facility;

• Any spillages shall be reported immediately to the Tullow Oil.

2.5.2.8 Solid Waste Management

Objective • To maximise the internal and external recycling of materials.

• To minimise the volume of solid waste requiring disposal by landfill.

Management action The Contractor to compile and submit a detailed Waste Classification Report before commencement of construction. This report must:

• Indicate management endpoints such as recycling or disposal destinations of each individual waste stream. A Solid Waste Management Plan shall be designed and implemented for the construction operations. The Solid Waste Management Plan shall:

• Record quantities and composition of waste streams, sources of waste streams, length of storage on site, and final destinations. This would constitute the basis for a continuous improvement programme in waste minimisation;

• Incorporate the following waste management hierarchy to mitigate environmental impacts:

- minimise the generation of waste; - re-use the waste during construction; - re-use or recycle waste streams to other users at other locations; - dispose unusable waste streams at permitted waste disposal facilities. • Incorporate the Waste Classification Report;

• Be in place prior to the start of construction and be updated at regular intervals, as specified in the plan;

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• The legal requirements of the Contractor and all sub-contractors shall be identified and included in contractual agreements. These requirements include:

- The Contractor and its sub-contractors shall comply with all applicable national, regional and local legislation with regard to the disposal of hazardous materials;

- Adherence to the Solid Waste Management Plan shall be a contractual obligation between Tullow Oil and the Contractor, as well as with all sub- contractors;

• The system for collecting, sorting, disposal and recycling of waste shall be clearly described in the Solid Waste Management Plan. This shall include:

- No on site burning, burying or dumping of any waste materials, vegetation, litter or refuse shall occur.

• The waste sorting and temporary storage area shall be permanently controlled by a dedicated waste management officer to ensure compliance with the waste sorting and disposal requirement;

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• The Contractor shall ensure that waste management contractors are suitably qualified and equipped to manage the waste generated during construction;

• All solid waste shall be disposed of at an approved landfill site. The Contractor shall supply Tullow Oil with a certificate of disposal.

2.5.2.9 Dust management

Objective • To minimise the nuisance impact on the work force of dust generation during construction;

• To minimise potential risks from dust generation to vegetation and animals.

Management action A Dust Management Plan shall be compiled and implemented for the construction phase of the development and the following key issues included:

• Avoidance of unnecessary removal of vegetation;

• Routine spraying of unpaved site roads and access roads with water;

• Limiting vehicle-entrained dust from unpaved roads through traffic control measures e.g. limiting vehicle speeds;

• Re-vegetation of disturbed areas not occupied by plant infrastructure to take place as soon as possible;

• Covering of materials with the potential to result in dust and air contamination during transportation;

• Avoid handling dry cement during windy periods without taking precautions to prevent mobilization of the material (cement dust);

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2.5.2.10 Wastewater Management

Objective • Limit degradation of landscape through erosion.

• Minimise deterioration of groundwater and surface water quality.

• The plan shall identify sources of wastewater; and state the collection facilities that are to be used to prevent pollution, as well as the method of disposal of the contaminated water;

• All washing operations shall take place at a location where wastewater can be disposed of in the correct manner;

• Workshops, refuelling depots and washing areas shall be bunded;

• Oils collected in grease traps shall be collected by the appointed waste disposal contractor;

• Any wastewater or spilled fuel collected within bunded areas around the refuelling area shall be disposed of as hazardous waste;

- PH; - Conductivity; - Total Dissolved salts/solids; - Faecal Coliforms;

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- Lead. • In the event that quality changes are detected in discharges, the sampling frequency shall increase to daily samples until the problem has been solved and the water quality returned to concentrations prior to the incident. Samples will be taken during working activities and not during shut-down periods;

• The Contractor or his designated authority, will interpret the water quality results and provide Tullow Oil with a regular update of the effluent quality;

• Ablution facilities not linked to the sewage reticulation system will be located in remoter areas of the site;

• In the event of a spill which may contaminate stormwater, the spill management procedures shall be implemented immediately.

2.5.2.11 Transportation Management

Objective • Minimize risks to other road users related to construction traffic and use of heavy vehicles;

• Minimise degradation of road structure due the use of heavy vehicles

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Contractor shall also ensure that delivery drivers are supervised during offloading by someone with an adequate understanding of the requirements of the EMP;

• Overloading of vehicles shall be avoided to limit the impact on the structural capacity of roads along which materials and waste are transported. Transporters shall comply with Namibian vehicle loading regulations and routes should be selected accordingly to ensure that damage to road infrastructure is minimised;

• Only transport operators appointed through the Transport Tender Process shall be used for the transport of materials and personnel.

2.5.2.12 Noise Management

Objective The contractor to comply with the Labour Act, 1992: Regulations relating to the Health and Safety of Employees at Work (1997).

• The Contractor - and sub-contractors to comply with the measures for good practice with regard to management of noise-related impacts during construction. The following measures for good practice shall be incorporated:

- All equipment shall be kept in good working order; - Equipment shall be operated within specifications and capacity (eg. don't overload machines);

- Regular maintenance of equipment will be undertaken particularly with regards to lubrication;

- Equipment shall be operated with appropriate noise abatement accessories such as sound hoods and the Contractor shall ensure that these accessories are correctly maintained;

- Equipment shall be operated in as diversified a manner as possible (i.e. if possible, spread operation of equipment throughout working periods rather than operating several items simultaneously);

- Equipment shall be turned off when not in use; - Pumps, generators, compressors and saws shall be positioned in sheltered locations;

- Partly finished buildings shall be used to accommodate pumps, generators, compressors and saws;

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2.5.2.13 Management of recruitment, labour, skills development and training

Objective • Maximise opportunities for employment of local labour;

• Promote skills development, training of the construction workforce and expansion of the local skills base;

• Minimise the pressures associated with the in-migration of job seekers on surrounding communities and on existing infrastructure and services;

• Minimise security risks at the construction site.

Management action • Comply with Namibian recruitment and labour management legislation and regulations.

• In order to minimise the risk of accidents and illnesses amongst the construction workforce the Contractor shall submit an Occupational Health and Safety Management Plan in accordance with the Occupational Health and Safety Act and regulations promulgated there under prior to any construction on site.

- Maximise the use of Namibian nationals as far as possible; - Consider employment opportunities and the needs of disabled people during the planning of construction activities;

- Construction workers to be housed in facilities provided by the Contractor/ Tullow Oil.

Training and skills development To optimize the benefits of training and skills development associated with the power station project, the Contractor and Tullow Oil, shall ensure that the following actions are undertaken:

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• A skills development and training programme shall be implemented;

• Make multi-skilling of construction workers an important priority as employment opportunities during construction are only temporary;

• During construction, ensure that regular audits of training providers are conducted to ensure that appropriate skills and capacity are built effectively;

• Ensure that measures designed to minimise the number of induced migrants, is being implemented and adhered to by the Contractor and sub-contractor;

• Compliance with Diamond Area security requirements;

• No unauthorised firearms are permitted on site;

• Provide assistance to the Oranjemund Town Management to address the potential for increased criminal activity.

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Part B, Section 2, page 2-90 ENERGY AFRICA KUDU LIMITED

2.5.2.14 Investment, Procurement and Sales Management

Objective • Ensure benefits of foreign direct investment in Namibia and in the Karas Region are maximised;

• Maximise procurement of local goods and services;

• Contribute to an increase in local and national Gross Domestic Product (GDP) and Gross National Disposable Income (GNDI).

Management action In order for Namibia to best realize the economic benefits of the Kudu gas field development project, Tullow Oil and the Contractor are to ensure that, as far as possible, use is made of local raw materials and goods and services.

2.5.2.15 Environmental and HIV/AIDS awareness training for employees and contract workers

Objective • Reduce the number and severity of incidents during the construction phase that lead to a negative impact on the natural environment and human health;

• Minimise the risk of construction activities contributing to the increased spread of HIV/AIDS amongst the construction workforce and the surrounding communities.

Management action In order to promote awareness of environmental and health issues, Tullow Oil, in conjunction with Namdeb, shall ensure that the following actions are undertaken:

• An HIV/AIDS policy and programme to be implemented;

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Tullow Oil may require additional environmental training sessions to be given to relevant employees. Tullow Oil in consultation with the Contractor will determine attendance at those sessions;

• The Contractor shall ensure that all employees are aware of the procedures to be followed in the event of a fire;

• Draw on the Namibian national programme for HIV/AIDS awareness and management;

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Part B, Section 2, page 2-92 ENERGY AFRICA KUDU LIMITED

Part B, Section 3: Production

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia

Part B, Section 3 ENERGY AFRICA KUDU LIMITED

Part B, Section 3: Production

3. PRODUCTION______3-1

3.1 OPERATION OF LÜDERITZ BASE ______3-1 3.1.1 Compliance with EMP______3-1 3.1.2 Pollution control and waste management______3-1 3.2 OPERATING PIPELINE AND PRODUCTION FACILITIES ______3-3 3.3 OPERATING GAS CONDITIONING PLANT ______3-3

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Part B, Section 3 ENERGY AFRICA KUDU LIMITED

3. PRODUCTION

3.1 OPERATION OF LÜDERITZ BASE

3.1.1 Compliance with EMP

Objective Operate in an environmentally responsible manner i.e. in compliance with the requirements of the EMP.

Management Action Comply fully with the requirements of the EMP:

Subscribe to the principles of an internationally acceptable environmental management system (ISO 14 000) including environmental awareness training, waste management, environmental monitoring, record keeping and continuous improvement. Ensure that all storage facilities on the base are designed to minimise the impact of spillages e.g. bunding of fuel and chemical tanks, screening of particulate materials storage facilities to minimise wind-blown transport, etc. Ensure that all hazardous materials are stored securely, correctly labeled, packed and sealed.

Responsibility Tullow Oil and relevant Contractors.

Timing Throughout operations required for well intervention and infill drilling.

Reporting Requirements All contractors to sign EMPR prior to commencement of operations.

3.1.2 Pollution control and waste management

Objectives Implementation and maintenance of pollution control and waste management procedures at all times to minimise pollution and maximise recycling.

Management Action Comply with Namibian legal requirements for waste management and pollution control. Employ "good housekeeping" and monitoring practices.

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Part B, Section 3, page 3-1 ENERGY AFRICA KUDU LIMITED

All bulk material handling equipment must be designed to minimise the formation and release of dust. All personnel to be equipped with personal protective equipment; particularly dust masks. Cement coating of pipe sections must be undertaken under controlled conditions i.e. in a shed or hangar to protect materials from the environment and vice versa. Contractor is responsible for containing spillages and ensuring the safe disposal of spilled materials. General waste: implement a waste minimisation system in compliance with Lüderitz Municipality waste disposal procedures. Food waste: comply with Lüderitz Municipality waste disposal procedures. Waste oil: store on site for collection and disposal by specialist waste disposal contractor. Empty oil drums and chemical containers: mark and seal appropriately for disposal and/or recycling. CFCs: no CFC-based fire-fighting or refrigeration equipment may be used. Waste water: no waste water will be permitted to run off from the base site but must be contained and either pumped into containers or evaporated on site. Minor oil spills: oil absorbent material must be used for remedial action. Sewage: on-site toilet facilities must either be connected to the municipal sewerage system or chemical toilets must be used. The waste from the latter must be disposed of in accordance with Lüderitz municipal procedures.

Record types and volumes of all materials handled on site. Record types, volumes and fate of all hazardous and other wastes. All hazardous wastes must be consigned to specialist contractors for disposal.

Responsibility Tullow Oil and relevant Contractors.

Timing Throughout operations.

Reporting Requirements • Regular reports on volumes of materials handled, volumes lost through spillages and wastes disposed of to be submitted to Tullow Oil.

• A close-out report should be prepared when operations cease.

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3.2 OPERATING PIPELINE AND PRODUCTION FACILITIES

Objective To ensure the reliable flow of gas to the gas conditioning plant.

Management Action • Monitor temperature, pressure and flow rate at the wells and onshore.

• Minimise the operation of the control valves in order to protect the gas reservoir.

• Install a pipeline management system to measure and predict the behaviour of the fluids in the pipeline and to monitor for losses.

• Inspect subsea system by ROV annually and to check for any visible leakages in the system.

Responsibility Tullow Oil, and Operations and Maintenance contractor.

Timing Throughout life of gas field.

Reporting Requirements • All data from monitoring systems and all ROV video footage to be stored on electronic data base for management and trouble-shooting purposes.

3.3 OPERATING GAS CONDITIONING PLANT

Objectives To provide clean dry gas to the CCGT plant at the required rate.

Management Action

Monitor all fluid flows: - Gas to flare - Condensate recovery - MEG recovery - Water production Continuous monitoring of the Gas Conditioning plant for leakages, capture leakages and, as appropriate, re-inject into the process system.

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Part B, Section 3, page 3-3 ENERGY AFRICA KUDU LIMITED

Treatment of sewage to NamPower’s requirements and discharge by injection into the power station sewage treatment and disposal facility. Excess stormwater to be treated to MARPOL standards (15 ppm oil in water) and dispose by injection into power station cooling water discharge system. All personnel to be equipped with personal safety equipment. General waste: implement a waste minimisation system. Comply with NamPower and Namdeb’s waste disposal procedures. Food waste: comply with NamPower and Namdeb’s waste disposal procedures. Waste oil: store on site for collection and disposal by specialist waste disposal contractor. Empty oil drums and chemical containers: mark and seal appropriately for disposal and/or recycling. CFCs: no CFC-based fire-fighting or refrigeration equipment may be used. Waste water: no untreated waste water may be permitted to run off from the site. Waste water must be contained and treated before disposal. Minor oil spills: use oil absorbent materials. Record types and volumes of all materials handled on site. Record types, volumes and fate of all hazardous and other wastes. All hazardous wastes must be consigned to specialist contractors for disposal.

Responsibility Tullow Oil, and Operating and Maintenance Contractor.

Timing Throughout life of gas field.

Reporting Requirements All data from monitoring systems to be stored on electronic data base for management and trouble shooting..

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Part B, Section 3, page 3-4 ENERGY AFRICA KUDU LIMITED

Part B, Section 4: Decommissioning

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Part B, Section 4 ENERGY AFRICA KUDU LIMITED

Part B, Section 4: Decommissioning

4. DECOMMISSIONING ______4-1

4.1 WELL ABANDONMENT ______4-1 4.2 PIPELINE AND PRODUCTION FACILITIES ABANDONMENT ______4-1 4.3 DECOMMISSIONING AND ABANDONMENT OF TERRESTRIAL COMPONENT – GAS CONDITIONING PLANT, ETC. ______4-2

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Part B, Section 4 ENERGY AFRICA KUDU LIMITED

4. DECOMMISSIONING

4.1 WELL ABANDONMENT

Objective To leave the well site free of all obstructions, i.e. remove wellheads and retrieve all anchors and other items that may constitute a seafloor hazard.

Management Action • Remove Christmas tree and flow base. Cut riser pipe at least 2 m below seafloor and plug well with cement.

• Undertake a visual (ROV-video) survey of the well site after wellhead removal.

Responsibility Tullow Oil.

Timing At cessation of production.

Reporting Requirements Abandonment report with video footage to be provided to MME, MWTC and MFMR.

4.2 PIPELINE AND PRODUCTION FACILITIES ABANDONMENT

Objective To leave the wellfield and pipeline route free of all obstructions that may interfere with future use of the area. In practice this will mean the removal of the manifold and controls distribution skids and flooding the pipeline, flowlines and control umbilical.

Management Action Remove manifold and control skids and associated infrastructure. Drain MEG line and flush with seawater. Flush clean the gas pipeline and flood with seawater Cover end of pipeline with weighted mattress. Undertake visual (ROV-video) survey of wellfield and pipeline route. Flush the control umbilical with seawater and abandon in situ. Arrange for abandoned pipelines to be marked on hydrographic charts.

Responsibility Tullow Oil.

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Timing At cessation of production.

Reporting requirements Abandonment report with video footage to be provided to MME, MWTC and MFMR.

4.3 DECOMMISSIONING AND ABANDONMENT OF TERRESTRIAL COMPONENT – GAS CONDITIONING PLANT, ETC.

Objectives To leave the terrestrial site in a state appropriate to its future use. Note: The mining area may become part of a Sperrgebiet National Park and a high standard of abandonment and rehabilitation may be required.

Management Actions A detailed abandonment and rehabilitation plan will have to be drawn up closer to the end of project life but removal of all plant and equipment at the gas conditioning plant site and shore crossing to LAT will be the minimum requirement.

Responsibility Tullow Oil.

Reporting requirements Abandonment and rehabilitation plan to be presented to MME and MET for approval.

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Part B, Section 4, page 4-2 ENERGY AFRICA KUDU LIMITED

Appendix A : Tullow Oil : Integrated Management System

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia

INTEGRATED MANAGEMENT SYSTEM

Document Number: TOP-IMS-PRO-08-01

Document Owner: CEO

Date: 01.07.05

Minimum Review Period: 24 months

This sheet must be completed in detail, at each revision once this document has been approved. Details must include revision number, description and indication of which pages and paragraphs have been revised, date of revision approval and approval indication.

2 01/07/05 Updated following review IH GB AH

1 20/03/03 Final version for issue GB LC/JW AH

B 04/02/03 Draft with comments included SPTH GB/LC AH

A 21/10/02 Draft for comment SPTH GB

TECH APP’D REV DATE DESCRIPTION BY REVIEW (Owner)

Corporate IMS Framework Document 1 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01

Contents Revision 02

1. Introduction Purpose Scope IMS Philosophy and Structure

2. Management Standards Introduction

1 Leadership, Accountability and Commitment 2 Organisation and Responsibilities 3 Risk Management 4 Legislative and Regulatory Compliance 5 Management of Change 6 Personnel Selection, Training and Competence 7 Contractor Selection and Management 8 Design and Construction 9 Operations and Maintenance 10 Crisis and Emergency Management 11 Incident Investigation 12 Health Management 13 Environmental Management 14 Security 15 Social, Ethical and Community Awareness 16 Information and Documentation 17 Performance Measurement, Monitoring and Reporting 18 Audit, Review, Assessment and Improvement

Corporate IMS Framework Document 2 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Introduction Revision. 02

Purpose This document, the Tullow Oil, Integrated Management System (IMS), sets the minimum standards to be used throughout Tullow Oil’s activities.

Scope Tullow’s IMS provides the framework for managing all business activity throughout the organisation and will ensure: • Clear assignment of responsibilities; • High standards in EH&S performance; • Sound risk management, planning and decision making; • Efficient and cost effective planning and conduct of operations; • Legislative compliance throughout all operations; • A systematic approach to critical business activities; and • Continuous improvement. Each business unit/asset is responsible for implementing a system that complies with the requirements of this IMS standard.

Figure 1.1. System Hierarchy Tullow IMS

Framework

Tullow Corporate Guidelines

Local Compliance Document

Operational/Local Procedures

IMS As illustrated above, this document provides the overarching framework for corporate and subsidiary management systems. It is supported by a series of Philosophy and corporate guidelines intended to assist in the development and implementation of Structure systems and business practices that comply with Tullow’s stated performance standards.

Corporate IMS Framework Document 3 Rev 2 - 01 July 05

Document Ref. Leadership, Accountability and TOP-IMS-PRO-08-01 Commitment Revision 02

Standard Expectations

Element 1 Management and • Leaders and management establish positive EH&S behaviours by personnel at all levels in personal example, and reinforce and reward positive behaviours. Tullow are responsible for Leadership, leading and participating in • Management establishes clear goals and objectives for the business, Accountability efforts to meet Tullow’s including EH&S; defines roles, responsibilities and performance EH&S goals. measures; allocates competent resources, and where necessary, and specialist expertise. Commitment All Tullow personnel are held responsible and • Management engages in clear two-way communication with accountable for employees, contractors and others, fostering a working environment demonstrating correct that supports and encourages open dialogue about all aspects of the EH&S behaviours. IMS.

• Management integrates EH&S expectations into business planning and decision-making processes.

• EH&S targets are integrated within Tullow’s business activities.

• Managements’ and employees’ leadership in EH&S performance is assessed against their annual objectives.

• Management promotes the sharing of EH&S lessons learned both within and outside the Tullow organisation.

Document Ref. TOP-IMS-PRO-08-01 Organisation and Responsibilities Revision 02

Standard Expectations

Element 2 Management is • Corporate and subsidiary organisational structures and lines of responsible and reporting are clearly defined for all level of Tullow’s operations. accountable for providing Organisation the organisation and • EH&S performance is a line responsibility although specialist EH&S and resource for implementing personnel may be included in organisational structures to act in an Tullow’s IMS, the EH&S advisory and monitoring capacity. Responsibilities Policy and meeting Tullow’s EH&S • Roles and responsibilities, including reference to EH&S requirements, performance standards. are clearly specified and recorded for all job functions. • Suitable numbers of competent resources are assigned to conduct Tullow’s business activities, complying at all times with legislative The EH&S and Corporate requirements and the Company’s IMS, EH&S Policy and EH&S Social Responsibility performance standards. Polices are available from the Tullow Intranet • Management systems are developed, documented, applied and site or by contacting the supported throughout Tullow. These honour the over-arching Corporate EH&S requirements described in the Tullow IMS as well as reflecting local Manager legislative requirements, and environmental and geo-political expectations.

Corporate IMS Framework Document 4 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Risk Management Revision 02

Standard Expectations

Element 3 All activities with a • Line management is responsible for determining whether an EH&S potential EH&S impact are risk review is required. subject to a risk review so Risk that risks can be reduced • The level of detail required for the risk review is determined by the Management to ALARP. magnitude of risks associated with the operations (see Risk Management Guideline). The risk assessment process is used to set • All legislative requirements are identified and addressed. objectives for eliminating hazards and reducing risks • Risk mitigation techniques are considered according to the following priority 1. Avoidance 2. Engineering solutions 3. Administrative controls 4. Personnel protective equipment

• All risk reviews are documented and assigned a unique document number, according to document control procedures.

• A system is in place to ensure that any actions or remedial measures identified under this process are tracked to completion and formally closed-out.

• Procedures will be maintained to ensure that EH&S critical facilities and equipment are suitable for their required purpose.

• Significant findings are communicated to the workforce.

• A Risk Management Guideline has been developed and is applied.

Document Ref. Legislative and Regulatory TOP-IMS-PRO-08-01 Compliance Revision 02

Standard Expectations

Element 4 Identification of legislation • A system is in place to ensure existing and new legislative and and application of regulatory requirements are identified and communicated within internationally acceptable Tullow and to appropriate third parties involved in Tullow business Legislative and standards, procedures and activity. Regulatory specifications for design, construction, start-up, • A system is in place for managing all operations, ventures and Compliance operation and other business activities in compliance with regulatory, legislative and permit business activities is requirements. essential to ensure compliance and achieve • Where regulations do not exist, the system incorporates the use of continual improvement. practices, standards and specifications that embody responsible design, construction, operational and business practices.

• Changes to laws, regulations or permit requirements are identified and incorporated into policies, practices, procedures, documentation, training, design criteria and operations. These changes are communicated to the workforce.

Corporate IMS Framework Document 5 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Management of Change Revision 02

Standard Expectations

Element 5 Business, operational and • A system is in place to ensure that all changes in design, operations, EHS risks resulting from risk management, construction modifications, Company organisation company or legislative and personnel, third party contracts, emergency preparedness, Management of changes are identified, legislation or performance monitoring with the potential for adverse Change assessed and managed to EH&S impact, are identified, assessed and managed by competent limit the severity of their people to limit the severity of this impact. consequences. • Assessment of the EH&S impact of the proposed change may take the form of a risk review.

• It is the responsibility of Line Management to ensure the change management system is implemented.

• It is the responsibility of Line Management, with support from EH&S Co-ordinators, to ensure that changes having potential EH&S impacts are assessed and managed in an appropriate manner.

• Authorisation to proceed with a proposed change is given by a level of management commensurate with the nature and potential EH&S impact of the change.

Document Ref. Personnel Selection, Training and TOP-IMS-PRO-08-01 Competence Revision 02

Standard Expectations

• During external recruitment and internal personnel selection, it is Element 6 Personnel are selected for job functions based on the responsibility of the Line Manager to ensure that the person their competence to fulfil selected is competent to carry out their job function. Personnel the associated roles and Selection, responsibilities including • Line Managers are responsible for preparing job function EH&S. Appropriate descriptions that incorporate clear references to EH&S relevant Training and training is provided where legislative requirements, roles, responsibilities and performance necessary. requirements. Competence • A system exists for Line Managers to periodically monitor and assess personnel performance including EH&S.

• Individuals and Line Managers are jointly responsible for identifying training requirements necessary to ensure personnel are competent to carry out all aspects of their job function. Once identified the required training is carried out in a timely manner.

• All personnel are encouraged to raise any concerns they may have regarding their own competence in carrying out the EH&S aspects of their job function.

• All personnel are familiar with the requirements of Tullow’s Corporate IMS, appropriate Tullow subsidiary management systems and relevant governing EH&S legislation.

• Personnel are informed of their responsibilities with respect to EH&S and the procedure for raising any EH&S concerns relating to Company activities.

Corporate IMS Framework Document 6 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Contractor Selection and Management Revision 02

Standard Expectations

• A system for contractor selection and management is in place. Element 7 The selection and management of contractors shall be • The objective of a selection process shall be to identify a Contractor transparent, auditable and Contractor/Supplier that can deliver the best value for Tullow Selection and align the contractor with during the period of the contract. Tullow’s policies and Management values. • The selection process and the ongoing process of management of the Contractors or Suppliers will satisfy Tullow’s ethical and business standards.

• It is the responsibility of Line Management, with support from Technical, Procurement and EH&S expertise, to select suitable contractors on the basis of a robust and auditable selection process.

• The line manager is responsible for the ongoing performance of the contract. The Contracts and Procurement Manager supports line management in this process.

• Financial, Technical and EH&S audits and other monitoring of contractors are carried out where deemed appropriate by the nature of work involved and the specific Tullow audit standard.

• Corrective actions from audits will be documented and the actions closed out within the specified timeframe.

• The appropriate roles, responsibilities and performance criteria are included in the contract.

Document Ref. TOP-IMS-PRO-08-01 Design and Construction Revision 03

Standard Expectations

• A system is in place for the design, construction, commissioning, Element 8 All facilities are designed and constructed so as to start-up and decommissioning process, which ensures that EH&S reduce the EH&S risk as critical facilities and equipment are fit for the required purpose. Design and low as reasonably Construction practicable (ALARP) and • It is the responsibility of the Country Manager (or equivalent) to ensure compliance with ensure a review of risk and legislative compliance is carried out at relevant EH&S standards the key stages of design, construction, commissioning, start-up and legislation. and decommissioning of a facility which includes identification of:

Relevant EH&S legislation for the project and compliance issues Potential EH&S risk issues associated with the project Proposed measures to minimise the identified EH&S risk issues; Additional measures required to reduce EH&S risk to ALARP.

• A person independent of the project team is required to be involved in critical reviews to ensure that EH&S Policy is not compromised.

• A system is in place to ensure that any actions or remedial measures identified in a risk review or during compliance with legislation are tracked to completion and formally closed out.

Corporate IMS Framework Document 7 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Operations and Maintenance Revision 02

Standard Expectations

• EH&S reviews legislative compliance are carried out and Element 9 All facilities are operated and maintained in a procedures put in place to ensure compliance. manner so as to reduce Operations and the EH&S risk to as low as • An EHS risk assessment process is undertaken for all activities Maintenance reasonably practicable (ALARP) and ensure • The relevant Operations Manager is responsible for ensuring that compliance with relevant procedures are in place for conducting all operations and EH&S standards and maintenance activities, to ensure legislative compliance and to legislation. reduce EH&S risks to ALARP.

• A system is in place to ensure that procedures are adhered to and regularly reviewed and updated to ensure continued effectiveness and legislative compliance.

• A system is in place to ensure that all measures critical to reducing EH&S risks are identified, minimum performance standards established and that these performance standards are met.

• Formal documented review and approval is required to continue operations which fail to meet minimum EH&S performance standards.

Document Ref. TOP-IMS-PRO-08-01 Crisis and Emergency Management Revision 02

Standard Expectations

• A crisis management plan is in place at corporate level to Element 10 Plans are in place to ensure that in the event of address escalation of emergencies or incidents that may have a crisis or an emergency, Company damaging potential. This plan establishes possible Crisis and personnel are aware of the crisis scenarios, designates roles and responsibilities and Emergency actions required to identifies points of contact both internally and externally to Tullow. minimise the risk to Management themselves, others, the • Emergency response plans are in place to address potential environment and property. emergencies, designate roles and responsibilities and identify the requirement to interface with external bodies or persons (eg: media, relatives, partners or legislators).

• Interface procedures and/or bridging documents between Tullow and third parties are developed and implemented as appropriate.

• The crisis management and emergency response plans are communicated to the workforce and regular drills and training exercises carried out and recorded. Significant findings from drills are communicated to the workforce and used to further develop the crisis management and emergency response plans.

• Personnel receive initial and refresher training to ensure they are competent to carry out their designated roles and responsibilities in a crisis or emergency.

• Equipment, facilities and trained personnel for crisis management and emergency response are identified and readily available. Procedures will be in place to ensure periodic assessment of emergency equipment needs.

Corporate IMS Framework Document 8 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Incident Investigation Revision 02

Standard Expectations

• A system is in place to ensure that all incidents, accidents and Element 11 All incidents, accidents and near misses are reported, near misses are reported, investigated and documented. investigated and Incident documented. Contributory • The investigation will attempt to determine the root cause of the Investigation and root causes are incident, any contributing factors, trends in reported incidents and identified and appropriate any measures that are required to be implemented to ensure the actions assigned and incident does not recur. closed out. • Significant findings from investigations will be communicated to the workforce where appropriate.

• A system is in place to ensure that all identified actions are documented, tracked to completion and closed out.

Document Ref. TOP-IMS-PRO-08-01 Health Management Revision 02

Standard Expectations

• A system is in place that provides a comprehensive approach to Element 12 Risks to the occupational health and welfare of managing personnel exposure in the workplace. This includes personnel involved in appropriate levels of occupational health risk assessment and Health Tullow business activity or provides for communicating risks to affected individuals. Management visiting Tullow places of business shall be • Fit for purpose personal protective equipment (PPE) and work assessed and managed to aids provided by Tullow shall be used, in compliance with ALARP standards. legislative requirements and sound operational and EH&S practice.

• Welfare facilities are provided at Tullow worksites as befits their location, type and level of occupancy.

• Suitable systems will be in place to determine the health requirements for a particular country. This will be actively communicated to the travellers.

Corporate IMS Framework Document 9 Rev 2 - 01 July 05

Document Ref. TOP-IMS-PRO-08-01 Environmental Management Revision 02

Standard Expectations

• The environmental impacts of business activities are assessed Element 13 Environmental assessments and qualitatively and quantitatively as appropriate. environmental Environmental management plans shall • Environmental Impact Statements (EIS) are prepared where Management be implemented in order to required by legislation or where significant risk of environmental minimise harmful damage is possible. environmental impacts before they occur. • Pollution prevention, waste and emissions minimisation, and the efficient and effective use of energy and natural resources are addressed for all operations and business activities.

• Disposal of waste material takes place only at approved sites.

• Pollution controls are tested and undergo preventative maintenance.

• Proper abandonment and decommissioning are considered for all assets and operations, taking into account the environmental impact of such operations.

Document Ref. TOP-IMS-PRO-08-01 Travel and Security Revision 02

Standard Expectations

• A system is in place that provides a comprehensive approach to Element 14 Risks to the security of personnel, property and managing personnel security whilst on Company business or at a workplaces shall be Company workplace. This includes appropriate levels of Travel and assessed, managed and personnel security risk assessment and provides for Security communicated to ALARP communicating risks to affected individuals. standards. • Appropriate workplace site security precautions shall be implemented to protect personnel and property.

• Monitoring and advising on the prevailing political and security environment is the responsibility of the Country Manager with support from the Corporate EH&S Manager. Suitable systems will be in place to determine the security requirements for a particular country. This will be actively communicated to the travellers.

Corporate IMS Framework Document 10 Rev 2 - 01 July 05

Document Ref. Social, Ethical and Community TOP-IMS-PRO-08-01 Awareness Revision 02

Standard Expectations

• Open and proactive communications are established and Element 15 Ethical conduct and social and community values maintained with employees, contractors, regulatory agencies, shall be assessed for all public organisations, and communities regarding the EH&S Social, Ethical business activities in order aspects of Tullow’s business. and that stakeholders maintain confidence in the integrity • Ethical business and decision-making processes are applied in Community of Tullow’s operations and the selection of personnel and contractors and the conduct of Awareness commitment to EH&S and operations, in order to ensure that Tullow performance standards CSR performance. are not compromised.

• Tullow recognises and responds to government and community EH&S concerns and expectations that relate to the Company’s operations.

• The social and ethical impact of new business on local communities are openly assessed, communicated and integrated into the business case.

• The social and ethical impact of any divestment or decommissioning activity of existing operations are reviewed, communicated and managed.

• Consistent and well-considered publicity material is used to managing public affairs.

Document Ref. TOP-IMS-PRO-08-01 Information and Documentation Revision 02

Standard Expectations

• A system is in place to securely manage documents, data and Element 16 Accurate and unambiguous information records, including their preparation, revision, approval, on operations and distribution, storage, retrieval and removal from circulation. Information business activities shall be and held securely and be • Tullow standards, working instructions, procedures and readily available. guidelines will be fit for purpose. Documentation Information is • Appropriate regulatory and legislative requirements, codes of communicated in an practice and guidance notes are maintained for reference unambiguous manner and suitable documented • Originals of regulatory consents and approvals are securely instructions are applied to stored with information contained therein still being accessible for managing risks and reference. ensuring excellent operational and EH&S • Communication processes are implemented to allow two-way performance. flow of information.

• Hazards, risks and control measures are properly documented and communicated to those affected.

• Sensitive personnel records are maintained with appropriate confidentiality.

Corporate IMS Framework Document 11 Rev 2 - 01 July 05

Document Ref. Performance Measurement, TOP-IMS-PRO-08-01 Monitoring and Reporting Revision 02

Standard Expectations

Element 17 All activities are measured • A system is in place (including schedules) for performance and monitored locally measurement, monitoring and reporting, for both internal and external against defined EH&S monitoring, and active and reactive monitoring. Performance expectations and reported Measurement, in accordance with a • The level of detail of performance measurement, monitoring and documented schedule. reporting is determined by the EH&S risk associated with the activity. Monitoring and Reporting • Performance measurement, monitoring and reporting are undertaken by competent personnel.

• All measuring and monitoring equipment is calibrated and maintained, and appropriate records are kept.

• Performance of EH&S critical measures is verified against their minimum performance criteria, with under-performance being flagged for further investigation or action as appropriate.

• The results of performance measurement and monitoring will be documented and records maintained according to document control procedures.

• Performance is communicated to the workforce.

Document Ref. Audit, Review, Assessment and TOP-IMS-PRO-08-01 Improvement Revision 02

Standard Expectations

• A system (including schedules) is in place for internal and/or Element 18 Regular audits, reviews and assessments are external audits and assessments based on business EHS risk. conducted to ensure the Audit, Review, effective functioning and • Audits in line with the schedule will be undertaken by auditors Assessment and continued suitability of the independent of the function being audited and written reports management system. produced. Improvement • Periodic reviews, at least once per year, will be undertaken by senior staff and Line Managers to ensure full implementation of Tullow’s management systems in respect of activities under their control.

• A system must be in place to ensure that any actions or remedial measures identified by audits and reviews are tracked to completion and formally closed-out.

Corporate IMS Framework Document 12 Rev 2 - 01 July 05

ENERGY AFRICA KUDU LIMITED

Appendix B: MARPOL Regulations relevant to the maritime aspects of the Kudu Gas Field development operations

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1. MACHINERY SPACE DRAINAGE

MARPOL Annex 1: Regulations for the Prevention of Pollution by Oil, Regulation 9(1)(b) Control of discharge of oil.

"... any discharge into the sea of oil or oily mixtures from ships to which this Annex applies shall be prohibited except when all the following conditions are satisfied:

Regulation 16, Oil Discharge Monitoring and Control System and Oil Filtering Equipment

2. SEWAGE

MARPOL Annex lV: Regulations for the Prevention of Pollution by Sewage from ships, Regulation 8 Discharge of sewage.

"(1) Subject to the provisions of regulation 9 of this Annex, the discharge of sewage into the sea is prohibited, except when:

1 Refer to the Recommendation on International Performance and Test Specifications for Oily-Water Separating Equipment and Oil Content Meters adopted by the Organization by resolution A.393(X).

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less than 4 knots; the rate of discharge shall be approved by the Administration based upon standards developed by the Organization; or

(i) the test results of the plant are laid down in the ship's International Sewage Pollution Prevention Certificate (1973);

(ii) additionally, the effluent shall not produce visible floating solids in, nor cause discolouration of, the surrounding water; or

(c) the ship is situated in the waters under the jurisdiction of a State and is discharging sewage in accordance with such less stringent requirements as may be imposed by such State.

(2) When the sewage is mixed with wastes or waste water having different discharge requirements, the more stringent requirements shall apply."

3. GALLEY WASTES

MARPOL Annex V: Regulations for the Prevention of Pollution by Garbage from Ships, Regulation 3(1)(b), (1)(b)(ii) and (1)(c) Disposal of garbage outside special areas.

4. SOLID WASTE

MARPOL Annex V: Regulation 3(1)(a) and (1)(b).

"(1) Subject to the provisions of regulations 4, 5 and 6 of this Annex:

(a) the disposal into the sea of all plastics, including but not limited to synthetic ropes, synthetic fishing nets and plastic garbage bags is prohibited;

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(b) the disposal into the sea of the following garbage shall be made as far as practicable from the nearest land but in any case is prohibited in the distance from the nearest land is less than:

(i) 25 nautical miles for dunnage, lining and packing materials which will float;

(ii) 12 nautical miles for food wastes and all other garbage including paper products, rags, glass, metal, bottles, crockery and similar refuse;"

5. ATMOSPHERIC EMISSIONS

MARPOL ANNEX VI: REGULATIONS FOR THE PREVENTION OF AIR POLLUTION FROM SHIPS

Regulation 12: Ozone Depleting Substances

(d) The substances referred to in this regulation, and equipment containing such substances shall be delivered to appropriate reception facilities when removed from ships.

Regulation 13: Nitrogen Oxides (NOx)

(1) (a) This regulation shall apply to:

(i) each diesel engine with a power output of more than 130 kW which is installed on a ship constructed on or after 1 January 2000; and

(ii) each diesel engine with a power output of more than 130 kW which undergoes a major conversion on or after 1 January 2000.

(b) This regulation does not apply to:

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not engaged in voyages to ports or offshore terminals under the jurisdiction of other Parties to the Protocol of [1997].

(2) (a) For the purpose of this regulation, "major conversion" means a modification of an engine where:

(i) the engine is replaced by a new engine built on or after 1 January. 2000, or

(ii) any substantial modification, as defined in the N0x Technical Code, is made to the engine, or

(iii) the maximum continuous rating of the engine is increased by more than 10%.

(i) 17.0g/kWh when n is less than 130 rpm

(ii) 45.0*n(-0.2)g/kWh when n is 130 or more but less than [2000 rpm]

(iii) [9.8] g/kWh when n is [2000 rpm] or more

where n = rated engine speed (crankshaft revolutions per minute).

Test procedure and measurement methods shall be in accordance with the N0x Technical Code, taking into consideration the Test Cycles and Weighting Factors outlined in appendix V to this Annex.

(b) Notwithstanding the provisions of sub-paragraph (a) of this paragraph, the operation of a diesel engine is permitted when:

(i) an exhaust gas cleaning system, approved by the Administration in accordance with the N0x Technical Code, is applied to the engine to

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App B, pg 5 ENERGY AFRICA KUDU LIMITED

reduce onboard N0x emissions at least to the limits specified in sub- paragraph (a), or

Regulation 14: Sulphur Oxides (SOx)

General requirements

(1) The sulphur content of any fuel oil used on board ships shall not exceed [5.0% m/m].

(2) The worldwide average sulphur content of residual fuel oil supplied for use on board ships shall be monitored in accordance with guidelines to be developed by the 0rganization.

Requirements within SOx Emission Control Areas

(3) For the purpose of this regulation, SOx Emission Control Areas shall include:

[(a) The Baltic Sea area as defined in regulation 10(1)(b) of Annex I:]

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App B, pg 6 ENERGY AFRICA KUDU LIMITED

(4) While ships are within S0x Emission Control Areas, at least one of the following conditions shall be fulfilled.

(a) The sulphur content of fuel oil used on board ships in a S0x Emission Control Area does not exceed 1.5% m/m.

(5) The sulphur content of fuel oil referred to in paragraph (1) and sub-paragraph (4)(a) of this regulation shall be documented by the supplier as required by regulation 18 of this Annex.

(6) Those ships using separate fuel oils to comply with paragraph (4)(a) of this regulation shall allow sufficient time for the fuel oil service system to be fully flushed of all fuels exceeding 1.5% m/m sulphur content prior to entry into a S0x Emission Control Area. The volume of low sulphur fuel oils (less than or equal to 1.5% sulphur content) in each tank as well as the date, time and position of the ship when any fuel-changeover operation is completed, shall be recorded in such log-book as prescribed by the Administration.

Regulation 15: Volatile Organic Compounds

(2) A Party to the Protocol of [1997] which designates ports or terminals under its jurisdiction in which VOC emissions are to be regulated, shall submit a notification to

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App B, pg 7 ENERGY AFRICA KUDU LIMITED

the 0rganization. This notification shall include information on the size of tankers to be controlled, on cargoes requiring vapour emission control systems, and the effective date of such control. The notification shall be submitted at least six months before the effective date.

(4) The Organization shall circulate a list of the ports and terminals designated by the Parties to the Protocol of [1997] to other Member States of the Organization for their information.

(6) This regulation shall only apply to gas carriers when the type of loading and containment systems allow safe retention of non-methane VOC's on board, or their safe return ashore.

Regulation 16: Shipboard Incineration

(1) Except as provided in paragraph (5), shipboard incineration shall be allowed only in a shipboard incinerator.

(4) Shipboard incineration of the following substances shall be prohibited:

2 Reference is made to MSC/Circ. 585 Standards for Vapour Emission Control Systems. 3 Reference is made to MSC/Circ. 585 Standards for Vapour Emission Control Systems. 4 Reference is made to the standard specification for shipboard incinerators contained in Appendix 2 to the Revised Guidelines for the Implementation of Annex V of MARPOL 73/78 (resolution MEPC.59(33)).

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App B, pg 8 ENERGY AFRICA KUDU LIMITED

(a) Annex I, II and III cargo residues and related contaminated packing materials;

(b) polychlorinated biphenyls (PCBs);

(d) refined petroleum products containing halogen compounds.

(5) Shipboard incineration of sewage sludge aud sludge oil may also take place in the main or auxiliary power plant but, in those cases, shall not take place inside ports, harbours and estuaries.

(6) Shipboard incineration of polyvinyl chlorides (PVCs) shall be prohibited, except in shipboard incinerators for which IMO Type Approval Certificates have been issued5.

(8) Personnel responsible for operation of any incinerator shall be trained and capable of implementing the guidance provided in the manufacturer's operating manual.

5 Reference is made to the standard specification for shipboard incinerators contained in Appendix 2 to the Revised Guidelines for the Implementation of Annex V of MARPOL 73/78 (resolution MEPC.59(33)).

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App B, pg 9 ENERGY AFRICA KUDU LIMITED

Appendix C: Disposal of drilling muds and drill cuttings

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App C, pg 1 ENERGY AFRICA KUDU LIMITED

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App C, pg 2 ENERGY AFRICA KUDU LIMITED

Environmental Management Programme Report for the Development of the Kudu gas field on the continental shelf of southern Namibia App C, pg 3