Ministry of Mines, Energy and Water Development
Study on the Supply of Petroleum Products into Zambia
FINAL REPORT
November 2014
STUDY ON THE SUPPLY OF PRODUCTS INTO ZAMBIA – FINAL REPORT
Importance Notice
Important message to any person not authorised to have access to this report.
Any person who is not an addressee of this report or who has not signed and returned to a member of the Channoil Consortium (comprising Channoil Consulting Ltd, PricewaterhouseCoopers Associates Africa Limited and Corpus Legal Practitioners) a Release Letter is not authorised to have access to this report.
Should any unauthorised person obtain access to and read this report, by reading this report such person accepts and agrees to the following terms:
1. The reader of this report understands that the work performed by the Channoil Consortium was performed in accordance with the approach agreed in our Technical Proposal submitted to the Ministry of Mines, Energy and Water Development and was performed exclusively in relation to the study on the supply of petroleum products into Zambia.
2. The reader of this report acknowledges that this report was prepared for the direction of Ministry of Mines, Energy and Water Development and may not include all procedures deemed necessary for the purposes of the reader.
The reader agrees that the Channoil Consortium, its partners, principals, employees and agents neither owe nor accept any duty or responsibility to it, whether in contract or in tort (including without limitation, negligence and breach of statutory duty), and shall not be liable in respect of any loss, damage or expense of whatsoever nature which is caused by any use the reader may choose to make of this report, or which is otherwise consequent upon the gaining of access to the report by the reader. Further, the reader agrees that this report is not to be referred to or quoted, in whole or in part, in any prospectus, registration statement, offering circular, public filing, loan, other agreement or document and not to distribute the report without prior written consent from a member of the Channoil Consortium.
Although as part of this study, we have undertaken a high level review of various financial statements, we have not carried out anything in the nature of an audit nor, except where otherwise stated, have we subjected the financial or other information contained in this report to checking or verification procedures. Accordingly, we assume no responsibility and make no representations with respect to the accuracy or completeness of the information in this report, except where otherwise stated.
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TABLE OF CONTENTS
1. BACKGROUND ...... 6 2. EXECUTIVE SUMMARY ...... 8 3. CURRENT STATUS - EXECUTIVE SUMMARY OF TASKS 1-3 ...... 19 4. STORAGE ...... 24 5. METHODOLOGY ...... 28 5.1 PRICING MODEL - CRUDE & PRODUCT PRICING FORECASTS ...... 28 5.2 REFINING ...... 33 5.2.1 MASS BALANCES ...... 33 5.2.2 CAPEX ...... 39 5.2.3 OPERATING COSTS ...... 41 5.3 PIPELINE ...... 42 5.3.1 CASE BY CASE ANALYSIS ...... 43 5.3.2 BUILDING A NEW PIPELINE ...... 52 5.3.3 RECOMMENDATIONS ...... 53 6. DEMAND/CONSUMPTION ...... 55 7. OPTIONS ...... 57 7.1 OPTIONS – INTRODUCTION ...... 57 7.2 UPGRADING INVESTMENT ...... 58 7.3 NEW REFINERY ...... 63 7.4 TERMINAL AND PIPELINE ...... 66 7.5 ROAD ONLY ...... 69 8. COST BENEFIT ANALYSIS ...... 72 8.1 METHODOLOGY ...... 72 8.2 KEY FINANCIAL METRICS AND ASSUMPTIONS ...... 75 8.2.1 KEY FINANCIAL METRICS ...... 75 8.2.2 ASSUMPTIONS...... 75 8.2.3 CALCULATIONS ...... 78 8.2.4 OUTPUTS ...... 80 8.2.5 PRICE ...... 80 9. RESULTS SUMMARY ...... 97 9.1 MODEL OUTPUTS SUMMARY ...... 97 9.2 SENSITIVITES ...... 99
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9.3 RESULTS SUMMARY ...... 100 10. STRATEGIC ISSUES ...... 101 11. CONCLUSIONS ...... 105 12. RECOMMENDATIONS ...... 106 13. NEXT STEPS ...... 107 APPENDICES ...... 108 APPENDIX 1: TERMS OF REFERENCE - CHECKLIST ...... 108 APPENDIX 2: PROCESS DESCRIPTIONS FOR THE NEW REFINERY ...... 111 APPENDIX 3: GLOSSARY ...... 121
FIGURES
FIGURE 1: ZAMBIA LIQUID FUELS MIX 2003 TO 2030 BASE CASE- LOWER ...... 9 FIGURE 2: FOUNDATION BLOCKS FOR DEVELOPING THE MODEL ...... 10 FIGURE 3: OIL PRODUCT SUPPLY ALONG THE CHAIN (METRIC TONNES) ...... 19 FIGURE 4: ARABIAN GULF REFINING MARGINS ...... 30 FIGURE 5: ARABIAN GULF CRACK SPREADS ...... 30 FIGURE 6: PROFILE HIGH CONVERSION REFINERY- MURBAN CRUDE ...... 38 FIGURE 7 : PROFILE HIGH CONVERSION REFINERY- UPPER ZUKUM CRUDE ...... 38 FIGURE 8: NUMBER OF DETECTED LEAKS PER YEAR ...... 46 FIGURE 9: LINE PIPE REPLACEMENT TRENDS PER ANNUM METAL LOSS ...... 47 FIGURE 10: ZAMBIA LIQUID FUELS MIX 2003 TO 2030 BASE CASE- LOWER ...... 55 FIGURE 11: ZAMBIA LIQUID FUELS MIX 2003 TO 2030 BASE CASE- UPPER ...... 56 FIGURE 12: SCENARIO 1A – UPGRADE REFINERY WITH GASOIL HYDROTREATER & ISOMERISATION UNIT BY 2017, NEW CRUDE PIPELINE OVER 6 YEARS ...... 58 FIGURE 13: SCENARIO 1B UPGRADE REFINERY WITH GASOIL HYDROTREATER & ISOMERISATION UNIT BY 2017, NEW CRUDE PIPELINE OVER 1-2 YEARS ...... 60 FIGURE 14: SCENARIO 2 – BUILD A NEW 50,000 BPD/2.5MTPA REFINERY BY 2023, AND BUILD A NEW CRUDE PIPELINE BY 2017...... 63 FIGURE 15: SCENARIO 3 MOTHBALL/SHUTDOWN REFINERY IN 2017, BUILD NEW PRODUCTS PIPELINE BY 2017 ...... 66 FIGURE 16: MOTHBALL/SHUT DOWN REFINERY AND PIPELINE IN 2017, IMPORT BY ROAD ...... 69 FIGURE 17: FOUNDATION BLOCKS FOR DEVELOPING THE MODEL ...... 73 FIGURE 18: FINANCIAL MODEL STRUCTURE ...... 74
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TABLES
TABLE 1: MODEL OUTPUTS SUMMARY – COST BENEFIT ANALYSIS ...... 12 TABLE 2: MODEL OUTPUTS SUMMARY – COST BENEFIT ANALYSIS ...... 13 TABLE 3: 2013 STRATEGIC STORAGE IN ZAMBIA – DAYS STOCK HOLDING ...... 25 TABLE 4: INCREMENTAL STRATEGIC STORAGE –50% GOVT STORAGE STRATEGIC ...... 25 TABLE 5: INCREMENTAL STRATEGIC STORAGE –100% GOVT STORAGE STRATEGIC ...... 26 TABLE 6: CRUDE OIL PRICE FORECASTS ...... 31 TABLE 7: PRODUCT PRICE FORECASTS ...... 32 TABLE 8: INDENI 5-YEAR AVERAGE MASS BALANCE ...... 34 TABLE 9: NEW PROCESS UNITS ...... 34 TABLE 10: NAMEPLATE CAPACITY- MASS BALANCE/PRODUCT YIELD ...... 34 TABLE 11: NEW PROCESS UNITS ...... 35 TABLE 12: NEW REFINERY- UPPER ZUKUM CRUDE...... 36 TABLE 13: NEW REFINERY- MURBAN CRUDE...... 37 TABLE 14: REFINERY PRODUCTION VS DEMAND ...... 37 TABLE 15: BUILT- UP TIC FACTORS ...... 39 TABLE 16: CAPEX – EXISTING & INCREASE TO NAMEPLATE CAPACITY ...... 40 TABLE 17: CAPEX – NEW REFINERY ...... 40 TABLE 18: MAINLINE PUMPS REPLACEMENT PROGRAMME COSTS ...... 44 TABLE 19: 2013/2014 PRESENT LINE PIPE REPLACEMENT ...... 44 TABLE 20: LINE PIPE REPLACEMENT – METAL LOSS TRENDS – LEAK DETECTED VISUALLY TREND ...... 45 TABLE 21: PIPELINE REPLACEMENT PROGRAM COSTS ...... 48 TABLE 22: CRUDE PIPELINE CAPITAL COSTS ...... 50 TABLE 23: MULTI-PRODUCT PIPELINE CAPITAL COSTS ...... 51 TABLE 24: SCENARIO 1A ...... 59 TABLE 25: SCENARIO 1B ...... 62 TABLE 26: SCENARIO 2 ...... 65 TABLE 27: SCENARIO 3 ...... 68 TABLE 28: SCENARIO 4 ...... 71 TABLE 29: OPTION SUMMARY ...... 72 TABLE 30: BEST PRACTICE MODELLING TECHNIQUES ...... 73 TABLE 31: FINANCING ASSUMPTIONS ...... 77 TABLE 32: DEPRECIATION RATES ...... 78
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TABLE 33: ESTIMATED ROAD TRANSPORT FEE ...... 79 TABLE 34: CURRENT PRICE FOR WHOLESALE PETROLEUM PRODUCTS TO OMC’S ...... 80 TABLE 35: SCENARIO 1A – PRICE BUILD-UP ...... 82 TABLE 36: SCENARIO 1A – TOTAL WEIGHTED COST ...... 83 TABLE 37: SCENARIO 1B – PRICE BUILD-UP ...... 85 TABLE 38: SCENARIO 1B – TOTAL WEIGHTED COST ...... 86 TABLE 39: SCENARIO 2 – PRICE BUILD-UP ...... 88 TABLE 40: SCENARIO 2 – TOTAL WEIGHTED COST...... 89 TABLE 41: SCENARIO 3 – PRICE BUILD-UP ...... 91 TABLE 42: SCENARIO 3 – TOTAL WEIGHTED COST...... 92 TABLE 43: SCENARIO 4 – PRICE BUILD-UP ...... 94 TABLE 44: SCENARIO 4 – TOTAL WEIGHTED COST...... 95 TABLE 45: MODEL OUTPUTS SUMMARY ...... 97 TABLE 46: MODEL OUTPUTS SUMMARY – COST BENEFIT ANALYSIS ...... 98 TABLE 47: MODEL OUTPUTS – SENSITIVITY ANALYSIS...... 99
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1. BACKGROUND
The Channoil consortium comprising Channoil Consulting, PWC and Corpus Legal Practitioners have been appointed to complete a detailed study on the Supply of Petroleum Products into Zambia. The objectives of the study are to investigate options that will:
a. Ensure that the country’s supply system meets its petroleum requirements up to the year 2030; b. Implement the best options for meeting the country’s supply requirements; and c. Ensure that petroleum products are supplied efficiently and at the most economic cost to the country, taking into account the current strategic development objectives.
The study has been divided into 6 tasks:
TASK 1 - REVIEW OF CURRENT PETROLEUM SUPPLY AND POLICY This first Task enabled the project team to come fully up-to-speed with the status of the petroleum sector in Zambia and its supply, and gather the basic data and information necessary to commence the detailed evaluation work
TASK 2 - PETROLEUM PRODUCTS DEMAND ANALYSIS Develop a view on the demand projections up to 2030. The specific task involved a provisional overview of Zambian petroleum demand growth which was incorporated into the Inception Workshop and Report.
TASK 3 - REVIEW OF EXISTING INFRASTRUCTURE Undertake a high level technical, commercial and financial review of the existing oil refinery at Indeni, the Tazama pipeline, and oil storage facilities currently in place. An Inception Report summarising the following has been produced:
• Condition of assets along the Indeni supply and logistics chain and overall skills and capability of existing workforce to maintain and operate the existing assets • Financial status of existing businesses and ability to continue/grow operations
TASK 4 - COST BENEFIT ANALYSIS The development and population of an economic model to demonstrate the estimated costs and benefits associated with each of the development options already identified in the scope of work, together with any further options identified in the course of the study. The provisional findings were presented and discussed at the Interim Workshop.
TASK 5 - INFRASTRUCTURE DEVELOPMENT Whilst there will be some overlap with Task 4 in that the refinery options will impact on the development of the associated supply infrastructure, there were further considerations in respect of the possible development of the Tazama pipeline and storage assets in Zambia and these were considered in this parallel Task 5. The Interim Report findings were presented at the Interim Workshop.
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TASK 6 - DEVELOPMENT OF RECOMMENDATIONS Finally, we have brought the results of our work on the above Tasks together in order to produce a clear and concise set of recommendations in the Final Report for consideration by Government of Zambia.
PROCESS
Tasks 1-3 have been reported separately in the Inception Report of March 2014. However, key aspects of the executive report have been included in Section 3 for completeness and reference.
We have now completed Tasks 4-6 following a presentation of our initial findings at the Interim workshop on 7 May 2014. This was followed up by a further conference session on 5 June 2014 which addressed the questions raised at the workshop and provided more detail and explanation of our provisional conclusions and recommendations.
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2. EXECUTIVE SUMMARY
CURRENT STATUS
Up until recently, Zambia has met demand for oil products through crude oil imports via Tanzania (Tazama Pipeline) that are refined domestically at the Government-owned Indeni refinery at Ndola which was commissioned in 1973 with a nameplate capacity of 1.1 million tonnes per annum (mtpa).
The 1,710km Tazama pipeline, which comprises 954 kilometres of 8” diameter and 798 kilometres of 12” diameter looped pipelines, is old and corroded. This has been confirmed following the recently completed Tazama Pipelines commissioned intelligent pigging of the entire pipeline.
As a result, the pipeline capacity has been reduced to a volume throughput of around 0.75mtpa. The continued maintenance of the existing pipeline is not considered to be a sustainable option going forward, given the existing levels of corrosion and the increase in throughput required to meet current and projected demand.
The Indeni refinery is operating within the constraints of an older straight run spiked crude refinery where the demand profile has changed significantly over the years. With higher growth in demand for gasoil and petrol, crude oil imports have had to be heavily spiked to include greater than 50% of lighter fractions of naphtha (15-20%) and gasoil (35-55%) and throughput is currently limited by Tazama pipeline constraints.
LSGO demand cannot be met by the refinery’s current configuration and feedstock and is imported. Indeni refinery also receives some of the high Octane petrol imported by the Government for blending purposes to improve the quality of the excess light gasoline produced at the refinery, which is due to the shortage of heavy naphtha in the spiked crude mix.
Excess fuel oil will continue to be produced at Indeni, despite the recent commissioning of a 50MW power plant and upgrading of the bitumen plant.
DEMAND FORECAST TO 2030 The two oil product demand forecasts reflect a doubling and tripling of annual demand over the period to 2030:
• A base case - lower where growth continues but both the copper price and copper output drop by 20% versus the high case and the rate of petroleum growth slows but demand nearly doubles to 2.2mtpa by 2030. • A base case - higher where current growth continues, copper prices are maintained and the copper sector continues to expand and petroleum demand is forecast to grow to over 3.7mtpa.
Key observations for the base case – lower as depicted in Figure 1 below:
• Demand growth for the primary products of petrol and gasoil/diesel (in particular LSGO used in the mines) are forecast to grow at an average annual rate of between 3% and 6.8% during the forecast period.
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• Gasoil is forecast to increase from 61% to 70% of total demand with Petrol’s share of product demand declining from 25% to 21%, reflecting the continued increase in mining demand for LSGO.
FIGURE 1: ZAMBIA LIQUID FUELS MIX 2003 TO 2030 BASE CASE- LOWER
Source: Channoil Consulting
The Petroleum Sector in Zambia is at a critical point, as the current pipeline and refinery infrastructure cannot meet the current, let alone the forecast future demand requirements. The options and recommendations to address this shortfall are described below.
OPTIONS
Four key options (“Scenario’s”) were identified and agreed including a key assumption that by 2017 all gasoil consumed in Zambia should be of 0.5% sulphur or lower, which is in line with regulations already in place internationally and in South Africa.
• Scenario 1a: “Upgrading investment” – Invest in Indeni refinery to improve the refinery efficiency and product quality (install a Gasoil Hydrotreater and Isomerisation unit by 2017) and replace the Tazama crude oil pipeline over six years. Major Capital Costs: Refinery $64m. New crude pipeline $735m.
• Scenario 1b: “Upgrading investment” – Invest in Indeni refinery to improve the refinery efficiency and product quality (install a Gasoil, Hydrotreater and Isomerisation unit by 2017) and replace the Tazama crude oil pipeline over two years. Major Capital Costs: Refinery $64m. New crude pipeline $668m.
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• Scenario 2: “New refinery” – Mothball the Indeni refinery, build a new refinery (50,000 bpd/2.5mtpa) by 2023 and replace the Tazama crude oil pipeline by 2017. Major Capital Costs: New Refinery $1.275 billion. New crude pipeline $668m.
• Scenario 3: “Terminal and pipeline” – Decommission the Tazama pipeline, replace with a new petroleum products pipeline, mothball Indeni refinery and utilise parts of the refinery for a petroleum products receiving terminal. Major Capital Costs: Refinery $0. New multi-product pipeline $707m.
• Scenario 4: “Road only” – Mothball Indeni refinery and decommission the Tazama pipeline by 2017 and revert to using road tankers for delivery of products into the country. No major capital costs.
“No investment” options were not considered, as considerable investment is required in both the Tazama crude oil pipeline and the Indeni refinery in order to continue operations out to 2030.
Crude oil discoveries were also not considered as an option, as it is thought unlikely that Zambia would discover and produce large quantities of crude oil within the time period being considered.
COST BENEFIT ANALYSIS METHODOLOGY AND INPUT
Drawing from the review of Zambia’s existing oil infrastructure and the petroleum products demand analysis, we developed a Financial Model (“Model”) that is built on the capital costs, operating costs and volume assumptions for each option.
The foundation blocks for developing the Model are illustrated and summarised below.
FIGURE 2: FOUNDATION BLOCKS FOR DEVELOPING THE MODEL
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Pricing Model
A price forecasting model was developed to forecast the crude and product prices and refining margins on a landed cost basis to Dar es Salaam for the period to 2030. Transport costs were then determined to Zambia.
Refining Section
Each of the refinery scenarios were investigated, evaluated and costed within a Class 5 estimate to establish the refinery yields and capital and operating costs for each of the refining options. This included consideration of both sweet and sour crude oils for the new refinery.
Pipeline Section
The 1,710km buried pipeline runs from Dar es Salaam to Ndola and it was designed for a lifetime of 25 years although it is now 40 years old. Throughput is now limited to 0.75mtpa, which is below design capacity of both the pipeline and refinery and well below current demand.
Our expert view is that maintenance and repair costs on the pipeline will increase at a rate requiring significant funding, eventually outreaching new pipeline costs. Thus, we have considered the following pipeline replacement options to provide security of supply to 2030 and beyond.
Option 1: Replace the existing pipeline with a new 12” crude pipeline, either over 2-3 years or 6 years (i.e. gradual replacement by sections if finance-raising is an issue).
Option 2: Replace the existing pipeline with a new 12” oil products pipeline over 2-3 years.
There are two further options regarding the method of construction; either using a traditional welding approach, or using the newer technology ZAP-LOK construction approach favoured by many pipeline companies today.
For Option 1, the estimated capital costs of replacing the crude pipeline using the traditional welding construction methodology are $989m (2.5 years) or $1.06 billion (6 years), and using ZAP-LOK the costs are $668m (1.3 years) or $735m (6 years).
For Option 2, the estimated capital cost of replacing the crude pipeline with an oil products pipeline using the traditional welding methodology is $1.03 billion (2.5 years), and using ZAP-LOK the cost is $707m (1.3 years).
Given the significant savings in construction time, manpower and cost, the ZAP-LOK system has been used in the cost benefit analysis
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COST BENEFIT ANALYSIS
The ultimate objective of developing a financial model is to assess the ‘Costs and Benefits’ of each option open to the Government. The purpose of this Cost Benefit Analysis is to evaluate the viability of each defined Scenario, with a view to determining the optimal solution for Zambia’s petroleum industry - measured as the least cost to secure the supply of petroleum products to Zambia while meeting the projected demand for petroleum products out to 2030.
The key financial outputs derived from the model based are:
Financial Statements: Drawing from the assumptions and calculations in the Model, we constructed financial statements in accordance with International Financial Reporting Standards in the form of a Profit and Loss Statement, Balance Sheet and Cash Flow Statement for the 17 year projection period.
Price: When calculating the total cost of each Scenario in order to assess the most viable option to the Government, we adopted the existing ‘Cost-Plus Pricing Method’ that is currently used by the Energy Regulatory Board in Zambia. Given our analysis looks at Non-Road and Road costs for each of the options, we have determined a ‘weighting’ dependent on the volumes throughput via roads, and alternatively via the Pipeline and Refinery (referred to collectively as ‘Non-Road’ volumes).
Weighted Average Formula: We further demonstrate the price build-up for each Scenario over the 17 year projection period, after which we determine the price today based on a weighted average formula.
TABLE 1: MODEL OUTPUTS SUMMARY – COST BENEFIT ANALYSIS
Upgrade Upgrade New refinery Close refinery All road from Refinery Refinery from 2023 in 2017 2017 by 2017 by 2017 New crude New crude New crude New product Close refinery & $/tonne oil pipeline oil pipeline oil pipeline pipeline 2017 pipeline 2017 2021 2017 2017 2014-2030 2014-2030 2014-2030 2014-2030 2014 to 2017
Scenario 1a 1b 2 3 4 Petroleum Feedstock 873 872 832 904 873 Wharfage 11 11 10 11 11 Finance Charges 44 44 42 45 44 Insurance (Dar-Ndola) 2 2 2 2 2 Pipeline Fee 114 98 89 89 54 Pipeline Storage Fee 2 2 2 2 2 Pipeline Losses 6 2 2 2 14 Tazama Agency Fee 5 5 5 5 5 Refinery Fee 62 61 111 6 62 Refinery Fuel + Losses 88 88 55 10 92 Exports Disposal 19
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Total Non-Road Cost 1,208 1,186 1,169 1,076 1,159
2014-2030 2014-2030 2014-2030 2014-2030 2014 to 2030 Petroleum Feedstock 896 894 886 853 896 Wharfage 11 11 11 11 11 Finance Charges 46 46 45 44 46 Insurance (Dar-Ndola) 2 2 2 2 2 Tazama Agency Fee 5 5 5 5 5 Road Transport Fee 199 198 198 200 201 Road Maintenance 50 50 50 50 50 Total Road Cost 1,209 1,206 1,198 1,164 1,211
Average Weight: Pipeline/Refinery 53% 59% 80% 82% 8% Average Weight: Road 47% 41% 20% 18% 92% Total Weighted Cost 1,208 1,194 1,175 1,092 1,207
TABLE 2: MODEL OUTPUTS SUMMARY – COST BENEFIT ANALYSIS
Upgrade Upgrade New refinery Close refinery All road from Refinery Refinery from 2023 in 2017 2017 by 2017 by 2017 New crude New crude New crude Close refinery New product $/tonne oil pipeline oil pipeline oil pipeline & pipeline pipeline 2017 2021 2017 2017 2017 Scenario 1a 1b 2 3 4 Total Cost 1,208 1,194 1,175 1,092 1,207 Rank 5 3 2 1 4 Differential ($/t) 116 102 83 - 115 Total incremental cost 2014 – 3,114 2,737 2,210 - 3,067 2030 v Lowest Cost ($m)
The options considered have clearly indicated that installing a product pipeline (Scenario 3) is the most economically efficient solution. Indicated savings relative to the other Scenarios are between $2.2/ZMK 13.7 billion and $3.1/ZMK 19.3 billion over the period 2014-2030. This approximates to a range of 0.5% to 0.7% of Total Annualised GDP for Zambia.
Of the refinery options, the new, larger refinery (Scenario 2) is marginally more attractive than the upgrading options (Scenarios 1a and 1b) under the base case of 30% equity and 70% gearing. We have conservatively assumed a premium of $50/tonne for road maintenance and repair. The road option, even without this provision for secondary costs, is significantly more expensive than the pipeline option.
Sensitivities
In order to stress test the Model, we carried out a sensitivity analysis by varying different input components.
Based on the results of the sensitivity analysis, Scenario 3 remains the most economically efficient option under all sensitivities.
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The ranking of the options remains consistent for the sensitivities except for the 100% equity case where the new refinery option (Scenario 2), given its large capital expenditure, is significantly more expensive ($148/tonne or incremental cost of $3.9 billion) than Scenario 3.
Results Summary
The product pipeline option (Scenario 3) provides Zambia with the most cost effective solution. It also provides the country with more flexibility as future unforeseen changes in demand can be more easily accommodated by acquiring a different mix and/or volume of products, whereas this would require expensive capital investments with any of the refinery options.
STRATEGIC ISSUES
There are a number of strategic issues that the country needs to consider in conjunction with the output of the Scenarios’ analysis considered above.
Security of Supply
Security of supply is critical and non-oil producing landlocked countries will require more product stock in country to cover the risk of a serious supply disruption whether fed by road, rail or pipeline. This can be complemented by additional product stocks held outside the country; currently Zambia has ownership to 231,000m 3 of storage in Dar es Salaam. Our recommendation is have 40 days product stock in country and a further 20 days available overall.
Another key consideration is physical security of the pipeline, particularly if a new product pipeline (Scenario 3) is implemented. The security risk increases as product can be readily used / sold, unlike the contents of the current crude pipeline.
In evaluating this issue some of the factors that will need to be considered include:
• Product pipelines are successfully operating elsewhere in East Africa. • The product pipeline includes a $25 million provision for a SCADA system, which remotely monitors the entire pipeline electronically, providing real time information on potential leaks/sabotage. • The incremental operational cost of security versus the crude pipeline will need to be evaluated in any detailed feasibility study. Increased surveillance to mitigate theft, damage, and sabotage could be cost effectively introduced using airborne drone cameras.
Rail
Rail transport globally is considered a cheaper alternative to road. Zambia and its neighbours have a rail infrastructure which needs upgrading. This is definitely an alternative to road transport and could complement the product pipeline and therefore should be considered as a medium term
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incremental development option. However, the current transport focus appears to be on the key Link Zambia 8000 project to improve the road infrastructure.
Access to investment capital and Commercial Structuring
The ability to access investment capital and optimise the commercial structuring of the capital is critical to the long term success of the investment in Zambian supply infrastructure.
Some key issues to consider:
• Ownership of the assets; would Tazama Pipelines’ shareholding structure remain the same in the new pipeline or would there be other shareholders? • Risk profile; the appetite of potential investors will depend on the level of perceived risk in the project type and the security of future income flows. It is likely that there will be a different perceived risk profile for refinery investment versus pipeline investment.
Regulatory framework
The current regulatory structure is a cost plus system as opposed to an import parity pricing system. Current product and crude supply are based on one to two year tenders and are based on the CIF plus financing cost to Dar es Salaam or Lusaka/Ndola for products.
Consideration should be given to revising the system where:
• Pricing including transport, insurance and freight are tendered more frequently. In Tanzania and Kenya the import of product is tendered on a monthly basis based on forecast demand as provided by the respective OMC’s. This has resulted in keen competition between the major international traders and product CIF prices have decreased over the period. • Prices are changed on a monthly basis to incorporate product price and currency changes on a transparent basis. This also prevents the GRZ from having to subsidise prices.
Pipeline route expansion and/or alternative routes
Consideration was given to alternate routes for product pipelines, by either: • Extending the Beira to Harare pipeline to Lusaka; or, • Developing a new pipeline from Lobito via Lubumbashi to Ndola, given the planned Refinery at Lobito.
These are both medium to long term options that can be considered, however they are not likely to take place within the current timeframe for a number of reasons: • The most complicated factor in a new pipeline is negotiating with land owners the ‘right of way’ and getting planning permission and agreement from all the respective landowners along the route. In our experience this can take many years. • Both of these options are cross border and would need time and effort to negotiate the terms with the respective state entities. • The new Lobito refinery has not yet been built although the feasibility studies have been completed and the EPC’s are being tendered. It will take a number of years to complete.
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• The country needs a new pipeline now given the state of the existing pipeline and the infrastructure; right of way and bilateral agreements are already in place on the existing route. • Storage tanks and pipeline connections to the SBM are in place, as are the pumping stations.
Consideration can be given to extending the pipeline, in particular from Ndola to Lusaka and potentially to Kitwe and Solwezi. These potential extensions can form part of a detailed feasibility study on the pipeline replacement. The issues raised on the right of way above would also need to be considered when considering the time scale, although these extensions could be completed later.
Human resource and environmental implications
In the final evaluation of the options, if the refinery is closed the human resource issues relating to redeployment, retrenchment and/or re-training of the workforce would need to be carefully considered and planned.
Overall, we would expect employment in Zambia to be positively impacted by these changes to the petroleum sector, as the whole economy would benefit.
Similarly, the environmental impact of any closures of refinery or pipeline would need to be reviewed and agreed.
Export of product
The main opportunity available for exports is to the Southern DRC in the Copper belt area around Lubumbashi, which is currently fed by road haul primarily via Dar es Salaam and Beira. The best estimates we have of this volume is 30,000 tonne/mth of LSGO, which provides a major upside for a new product pipeline in the initial period and after 2023 for both the new refinery and the new product pipeline options.
CONCLUSIONS
In summary, following a comprehensive review of Zambia’s current oil supply chain and supply demand balance, a forecast of the future demand and supply outlook and pricing outlook, and modelling and evaluation of the options using a robust commercial and financial model, we have the following conclusions:
• The demand outlook even on the lower base case shows an increase in demand to 2.2 million tonnes p.a. by 2030, doubling current demand. • The current pipeline needs replacement and cannot meet the current demand levels nor future projected needs. • New pipeline technology has reduced both costs and implementation time. • The current refinery, even with upgrading, remains a costly spiked crude option and will not meet future demand as it will be limited to close to its nameplate capacity of 1.1 million tonnes.
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• A new, larger refinery from 2023 is capital intensive at an estimated $1.2 billion and is a significantly more expensive option than a new product pipeline, remembering that a new crude pipeline would still need to be constructed. • The results from the cost benefit analysis of the defined Scenarios clearly show that Scenario 3, the replacement of the crude pipeline with a new 12” product pipeline and the mothballing of the existing refinery, is the most economically advantageous option with a forecast saving of between $2.2 billion and $3.1 billion over the forecast period against the other available options. It also provides flexibility in the supply of products to meet varying demand and product mixes. • The strategic product stockholding in-country should be increased to 40 days with an overall stockholding of 60 days.
RECOMMENDATIONS
The key recommendations for the petroleum sector are: i) Purchase of imported product including transport, insurance and freight should tendered more frequently and prices should be changed on a monthly basis in line with the tender period. ii) Increase the strategic product stockholding in-country to 40 days with an overall stockholding of 60 days to provide security of supply in a land-locked country without oil reserves. iii) Replace the crude pipeline with a new 12” product pipeline and mothball the existing refinery as soon as practically possible. iv) The key stakeholders need to consider whether any strategic issues may dictate that an alternative option be adopted or investigated further. v) It is vitally important that, assuming the recommendations are accepted, a detailed implementation plan is prepared to ensure that this multi-disciplinary project is successfully driven to ensure that fuel is supplied efficiently and at the most economic cost to the country for the foreseeable future to 2030 and beyond.
NEXT STEPS i) Decisions are required on recommendations from the Inception Report, which include:
• Optimisation of the internal storage efficiencies in the country. This includes a combination of pump overs from the existing strategic storage to the large OMC terminals, direct deliveries of product imports to OMC’s and double shifting. Discussions need to be held between all key stakeholders to prioritise and implement. • A clean up of Balance Sheets is required, in particular in respect of long term debt (GRZ) in Tazama Pipelines and Petroleum Products, in order to present bankable solutions for new financing. • Similarly, lease and management fees need to be reviewed in Tazama Petroleum Products Energy policy and pricing. • Tanzanian government must be approached to discuss plans and their proposed role in the new product pipeline.
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• Regarding energy policy and pricing, a review of: safeguards in procurement processes; market player role in infrastructure investments and product procurements; and, continuation of the 25% premium charged on direct product imports by the OMC’s, especially for the mining industry.
ii) Review of Final Report recommendations and consider whether any strategic issues merit further investigation. iii) Assuming the new product pipeline is adopted, there will be a need then for comprehensive implementation planning covering all aspects (i.e. technical, legal, financial, regulatory and commercial). iv) The detailed pipeline project would need to commence as soon as possible to avoid incremental costs, particularly given the existing level of pipeline corrosion.
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3. CURRENT STATUS - EXECUTIVE SUMMARY OF TASKS 1-3
Key extracts from the executive summary of the Inception Report which covered Tasks 1 to 3 have been set out below as background. The complete Inception Report is available separately.
OVERVIEW - OIL SUPPLY AND DEMAND Up until recently (late 2000s), Zambia has met demand for oil products through crude oil imports via Tanzania (Tazama Pipeline) that are refined domestically at the Government-owned Indeni refinery at Ndola which was commissioned in 1973 with a nameplate capacity of 1.1 million tonnes per annum (mtpa). Crude oil imports have always been spiked, originally to include 22.5% of a mix between gasoil and heavy naphtha. Zambia historically exported any excess production to neighbouring countries.
With higher growth in demand for gasoil, primarily for use in the copper mining sector, crude oil imports have had to be heavily spiked to include greater than 50% (at times as high as 60%) of lighter fractions of naphtha (15-20%) and gasoil (35-55%). The effect of the spiking reduced Indeni’s refinery capacity to around 0.75mtpa. As gasoil demand continued to increase, imports by road increasingly made up the difference between supply from Indeni and demand. The same is true for petrol, however to a lesser extent than for gasoil.
Supply, by product grade, along the supply chain is shown in the chart below.
FIGURE 3: OIL PRODUCT SUPPLY ALONG THE CHAIN (METRIC TONNES)
Source: Tazama Pipeline, ERB, Ministry of Energy
• Spiked crude oil imports through Dar es Salaam and the Tazama pipeline equate to around 0.65mtpa. • Indeni refinery also requires imports of petroleum product for blending purposes to improve the quality of the refined petrol. This is due to a shortage of heavy naphtha which has been replaced by light naphtha in the spiked crude mix.
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• Petrol and gasoil, including low sulphur gasoil (LSGO) are imported directly by Government to the Ndola Fuel Terminal (NFT) and from July 2013 to the new terminal in Lusaka (LFT). • Oil product imports are predominantly procured by the Government (supplied in 2014 by Dalbit and in 2013 by Dalbit and Trafigura), supplemented by some additional imports from Oil Marketing Companies (OMC and Government import volumes (for 2013) not shown in the chart above as data unavailable). • OMCs uplift products from the Ndola and Lusaka terminals and supply to end users via their own storage depots or directly, in the case of smaller OMC’s. • OMC’s also import LSGO directly at the request of some of the mines. This is a safeguard to ensure security of supply even though direct imports are charged an incremental 25% duty. • Total oil product imports accounted for some 45% of demand in 2012 and are expected to be close to 50% in 2013.
ENERGY POLICY AND PRICING
A reasonably developed framework for the regulation of the petroleum sector exists in Zambia. What appears to be missing within the law and policy framework are provisions for cost-effective pricing and appropriate safe-guards against inefficiency in procurement.
The expansion or upgrading of the existing infrastructure, particularly at Indeni and Tazama, to sustain the projected increased consumption of petroleum products in Zambia is also legally feasible within the current regulatory framework. However, what may prove challenging is the involvement of another country, such as Tanzania, at the bilateral level in order to attend to infrastructure and operational issues of the new or upgraded infrastructure outside Zambia.
Current policy also appears to discourage market entry at the midstream and upper end of the downstream levels (i.e. pipeline transportation, refinery operation and bulk importation of refined products) to help meet some of the excess consumption requirements for petroleum products.
TAZAMA PIPELINE
The 1,710km Tazama pipeline comprises 954 kilometres of 8” diameter and 798 kilometres of 12” diameter loops pipelines, and it is old and corroded. The pipeline capacity has been reduced to a volume throughput of around 750,000mt per year.
Tazama Pipelines commissioned an intelligent pigging of the entire pipeline which has recently been completed and which we have evaluated. This confirms high levels of corrosion. Options to upgrade the pipeline from an 8” to 12” pipeline have been considered by Tazama pipelines and are discussed later in this Interim Report.
The capacity can no longer meet the country’s demands, even though maintenance and some upgrading have kept the pipeline operational to date.
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INDENI REFINERY
The Indeni refinery is operating within the constraints of an older straight run spiked crude refinery where the demand profile has changed significantly over the years. Premium unleaded petrol and LSGO demand are key requirements which cannot be met by the refinery’s current configuration. LSGO is imported directly as this product cannot currently be produced at Indeni. The refinery also receives some of the high Octane petrol imported by the Government for blending purposes to improve the quality of the excess light gasoline produced at the refinery, which is due to the shortage of heavy naphtha in the spiked crude mix.
Excess fuel oil will continue to be produced despite the recent commissioning of the 50 MW Ndola power plant and the current upgrading of the bitumen plant.
The nameplate capacity of the refinery is 1.1mtpa, which is currently limited by the Tazama pipeline to 0.75mtpa.
The installation of a diesel hydrotreater to produce LSGO and an Isomerisation unit to increase the Octane level of the petrol will form part of the options to be considered in the next phase.
STORAGE
The development and commissioning of the Lusaka Fuel terminal and the future terminals at Mpika, Mongu and Solwezi, have greatly increased the product storage capacity within the country. This, together with the crude and OMC storage, should be sufficient to meet current strategic stock needs.
An optimisation of the current logistics, operation and remuneration of the storage mechanisms between Government and the OMC’s could further enhance the efficiency and operation of storage and handling of petroleum products. This is explored further later in this Interim Report.
FINANCIAL REVIEW
The key findings of the high level financial review of Tazama Pipelines Limited, Indeni Petroleum Refinery Company Limited and Tazama Petroleum Products Limited, are set out below.
TAZAMA PIPELINES LIMITED (“TAZAMA”)
• Tazama’s revenues have increased since FY2008 (Financial Year 2008) following increased throughput of comingled crude. However, annual revenue increases slowed down after FY11 following reductions in pumping fees and agency fees per mt by GRZ. • Pumping costs and administrative expenses have continued to increase year-on-year, resulting in EBITDA percentage reducing from a high of 60% in FY11 to 8% in FY14. In the event costs are not controlled and revenue per mt is not increased, Tazama’s margins will be eroded further. • The company’s working capital has been negative over the review period, mainly driven by the unpaid interest and short term obligations on the various debt facilities, as well as the
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accrual of various provisions relating to unpaid statutory obligations. The bulk of these provisions are as a result of Tazama not being able to settle its obligations during the two- year Indeni shutdown from May 1999. • Reported long term debt obligations have remained relatively unchanged between ZMK250m in 2008 to ZMW270m as at 31 December 2013. The increase has mainly resulted from exchange rate movements and accumulated interest. A significant portion of Tazama’s long term debt obligations relate to loans contracted by GRZ and various Development Finance Institutions (“DFI”), which were subsequently on lent to Tazama. Although a number of the facilities with the DFIs were written off after Zambia attained the Highly Indebted Poor Country (“HIPC”) status in 2005, GRZ has not passed on this benefit to Tazama. Tazama management have advised us that discussions have been ongoing with GRZ to write off these debts, however no formal agreement has been reached. • Nevertheless, despite Tazama continuing to report these debts in its account, the significant value of Tazama’s non-current assets results in Tazama still being a solvent entity.
INDENI PETROLEUM REFINERY COMPANY LIMITED (“INDENI”)
• Indeni’s revenues, which predominately consist of refining fees levied to GRZ, have increased in line with increased production from ZMW116m in FY08 to ZMW190m in FY12. This is despite GRZ reducing the processing fees payable to Indeni from US $61.10/mt to US $56.10/mt in FY11. • Cost of sales per mt of crude refined significantly dropped from ZMW144/mt in FY08 to ZMW80/mt in FY10. Subsequently, costs of sales as well as administrative and other operating expenses have increased resulting in a gradual reduction of Indeni’s margins at various levels. • Nonetheless, Indeni has reported positive EBITDA and PAT from FY09 to FY12. This has cumulatively resulted in the movement of Indeni’s retained reserves from negative ZMW155m in FY08 to positive ZMW40m in FY12. • Indeni has also managed to increase its net working capital position from negative ZMW113m to positive ZMW44m in FY12. The company has significantly reduced its trade receivables, which predominately relate to GRZ receivables, over the review period to almost nil in FY12. The increased ability to collect its receivables has resulted in increased cash reserves as well as Indeni’s ability to finance its maintenance and rehabilitation requirements. • In addition, following the settlement of the Total Outré Mer SA debts in FY09, Indeni has remained debt free and continues to operate as a solvent entity with the ability to attract external debt finance should this be required for any capital expansion projects.
TAZAMA PETROLEUM PRODUCTS LIMITED (“TPPL”)
• As with Tazama and Indeni, TPPL’s revenues have increased in line with the increased amount of petroleum products uplifted. TPPL’s revenues, which consist of throughput fees (charged to OMCs at ZMW25/m 3), storage fees and rental income, have increased by a CAGR of 19.5% between FY08 and FY13.
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• TPPL’s cost of sales per m 3 of throughput increased from ZMW20/m 3 in FY09 to ZMW34/m 3 in FY11. This gradually reduced to ZMW24/m 3 as at 31 December 2013. The largest components in TPPL’s cost of sales include labour costs, Tazama management fees, terminal lease fees payable to GRZ and storage lease fees for ZT1 (fuel tanks) to Tazama. However, we understand that the storage lease fees for ZT1 were erroneously charged to TPPL by Tazama and instead, these should have been charged to GRZ who owns the petroleum products stored in these tanks? • These significant charges have resulted in TPPL continuing to operate in a loss position throughout the review period. • TPPL’s net working capital position has moved from negative ZMW512k in FY08 to negative ZMW26m in FY12, and subsequently reducing to negative ZMW13m as at 31 December 2013. The main reason for the increased constraints on TPPL has been the accumulation of the Tazama management and storage charges, as well the GRZ lease fees. We understand the reduction in net working capital in FY13 was due to the reversal of the ZT1 storage fees which were accrued to March 2012, but were erroneously charged to TPPL by Tazama. • The negative working capital position of TPPL coupled with the fact that the company has been in a negative equity position from 31 March 2008 to 31 December 2013 means that the company is not able to pay its dues as they become due in the normal course of business and the value of its liabilities is greater than the value of its assets, technically rendering the company insolvent. TPPL only continues to operate because Tazama and GRZ (both being related parties) have not taken action to recover the amounts owed to them.
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4. STORAGE
As described in the Inception Report under Section 3.3, sufficient fuel storage is a fundamental for any country to ensure that there is security of supply and to protect against emergency shortages that result from natural disasters, key plant failures or geopolitics. Companies do not voluntarily hold strategic stocks so Governmental input is needed to either hold the stocks, require commercial companies to hold stocks or a combination of both.
The International Energy Agency (IEA), whose members are all OECD countries, has been tasked with monitoring the mandatory stock levels in member countries. The mandated USA government strategic petroleum reserve is 700 million barrels of crude, whereas the EU country’s mandate is 90 days of net imports or 61 days of average demand, of which a minimum of one third has to be refined product stocks, whichever is the greater. South Africa has also recommended that Government holds strategic stocks equivalent of 60 days net imports and licensed wholesalers hold 14 days product stock equivalent to their market share.
Non IEA nations have also reviewed their stock levels and strategic stocks. In 2007 China announced an expansion of their crude reserves into a two party system; a government-controlled strategic reserve complemented by mandated commercial reserves. India has developed a government strategic crude oil reserve currently equating to 70 days of demand.
As a land-locked country with longer supply lines and no indigenous crude, the need for sufficient buffer stocks in Zambia is critical and the prime emphasis should be on refined products within the country.
This has been recognized by Government and additional product storage has been built and commissioned in Lusaka (2013) and Mpika (2014), with additional storage planned for Solwezi and Mongu to complement the Ndola Fuel Terminal storage.
When considering fuel storage it is important to include all storage terminals and to understand the balance between commercial/operational and strategic storage, crude and product storage and their respective locations.
The storage terminals need to complement the current and future regional demand profile and to ensure that the country has sufficient product stocks available in the event of an emergency, whether it is a problem in the pipeline, the refinery or the arrival of shipments. It is considered that a prudent level of strategic stockholding would equate to a minimum of 60 days of demand with a minimum of two thirds of the quantity held as refined products and all of the product stockholding held within the country. The storage capacities for strategic products stockholding should also reflect the changing pattern of oil demand within the country.
The level of strategic stockholding is driven by demand and is therefore consistent across all the supply scenarios. It has therefore been reviewed independently of the supply options considered in this report.
The strategic storage noted in Table 3 below is storage held within Zambia and excludes the pipeline and storage terminal in Dar es Salaam.
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TABLE 3: 2013 STRATEGIC STORAGE IN ZAMBIA – DAYS STOCK HOLDING
Strategic Days Stock if Days Stock if storage Demand Storage Storage at at 50 % capacity m3 m3 capacitym3 m3 LPG 3,493 1,900 199 99 Petrol 367,472 63,310 63 31 Gasoil 715,967 76,850 39 20 LSGO 79,346 10,800 50 25 Jet A1 demand 62,016 6,200 36 18 Dom Kerosene 15,438 5,500 130 65 Heavy fuel oil 50,793 33,000 237 119 Bitumen 2,450 TOTAL 1,294,525 200,010 58 29
LPG and fuel oil storage is only located at the refinery. Currently the majority of LPG produced at the refinery is exported primarily to Tanzania and Kenya, whereas there is still surplus stock of fuel oil.
The government owned strategic stocks currently form a dual role both as operational stocks for the smaller OMC’s who do not have their own terminals and as strategic stocks. In assessing the strategic stock requirement we have looked at the incremental requirement at both the 50% and 100% levels.
We have assumed that OMC’s only hold operational stocks.
Based on the low case product demand growth, the following Tables provide forecasts in terms of incremental product storage required to maintain in-country stock security at 40 days.
TABLE 4: INCREMENTAL STRATEGIC STORAGE –50% GOVT STORAGE STRATEGIC
2015 2021 2026 2030 TOTAL m3 m3 m3 m3 m3 Premium Class 1 5,000 15,000 15,000 - 35,000
Gasoil Class 3 40,000 20,000 20,000 10,000 90,000
LSGO Class 3 40,000 20,000 - 10,000 60,000
Jet Class 2 5,000 5,000 - - 10,000
TOTAL 90,000 60,000 35,000 20,000 205,000
CAPEX $ @ $200/m 3 $18m $ 12m $7m $4m $41m
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TABLE 5: INCREMENTAL STRATEGIC STORAGE –100% GOVT STORAGE STRATEGIC
2015 2021 2026 2030 TOTAL m3 m3 m3 m3 m3 Premium Class 1 - - - - Gasoil Class 3 - - 20,000 10,000 30,000 LSGO Class 3 40,000 - 20,000 - 60,000 Jet Class 2 - 5,000 - 5,000 10,000 TOTAL 40,000 5,000 40,000 15,000 100,000
CAPEX $ @ $200/m3 $8m $1m $8m $3m $20m
If the incremental storage built is to be held purely as strategic stock, the level of tankage required would diminish as 100% of these incremental stocks would be maintained and not used operationally to service the OMC’s.
This would reduce the cumulative level of incremental tankage required to 2030 to meet the strategic stock levels from 205,000m 3 to approximately 100,000m 3 and the level of investment at an assumed capital cost of $200/m 3 from $41 to $20 million, on the basis that it is linked to the existing/planned terminals.
It is also possible, as an alternative, to require the OMC’s to hold a minimum level of stock which would complement the GRZ strategic stocks. This would reduce the level of investment by GRZ in incremental strategic tankage. The OMC’s would need to be remunerated to cover the incremental working capital cost and investment in terminal infrastructure. This can be accommodated in the current price build up but would need to be monitored and controlled.
The existing crude/product storage tanks at Dar es Salaam of 231,000m 3 plus the pipeline storage of 90,000m 3 provides additional storage capability ranging from 101 days in 2015 to 54 days in 2030 using the base case lower demand case. In addition, the 60,000m 3 crude storage at Indeni provides additional cover. This is greater than the balance of 20 days strategic storage recommended. In the event that a product pipeline is installed the crude tankage will need to be converted into product storage.
Consideration needs to be given to optimising the storage and transport logistics, particularly with the forecast increase in demand. At present there is double handling on the majority of product stored at Lusaka and Ndola fuel terminals, especially for the OMC’s as they uplift product, then transport it down the road to their depots and store it prior to dispatch to the customer. The provision of pump-over connections to the adjacent OMC storage should be investigated from an operational and economic perspective, with a view to increasing the overall throughput capacity of the terminal and alleviating truck loading and off-loading restrictions caused by double handling at both the NFT and LFT terminals and the OMC depots.
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Recommendations:
• Increase the strategic stock levels to 40 days in country and a minimum of 60 days in total – review the option of a complementary solution with the OMC’s.
• Optimise the internal storage efficiencies through a combination of pump overs to the large OMC terminals, direct deliveries and double shifting.
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5. METHODOLOGY
555.15.1 PRICING MODEL --- CRUDE & PRODUCT PRICING FORECASTS
METHODOLOGY
• A price forecasting methodology has been utilised based on a deep understanding of historical crude oil and product price relationships and refining margins.
• Refining margins tend to have natural “floor” levels and “ceiling” levels:
– If margins are too high, new investment is stimulated and margins later fall as more capacity comes on stream and product supply increases ahead of demand.
– If margins are too low, less advantaged refineries cease to operate as they become unprofitable, leading to a reduction in supply and higher product prices relative to crude oil prices (product crack spreads) and hence margins increase again.
• As a result of such pricing dynamics, linked to product supply and demand, it is possible to predict product crack spreads, check what these mean for product prices and refining margins, and then adjust crack spreads until a robust and defensible margin forecast is generated.
• This iterative process has been used to generate the crude oil and product price forecasts for this project.
ASSUMPTIONS
• All forecasts are in constant 2014 US Dollars.
• Crude oils
– Dated Brent crude oil is assumed to be at a constant $100/bbl.
– Murban premium differential to Brent is assumed to be $1.44/bbl, same as 2013/14 average.
– Murban freight to Dar es Salaam is assumed to be 80% of gasoil freight for the same journey (based on typically cheaper freight costs for larger cargoes and for black products).
– The past spiked crude recipe was assessed and it has changed over time hence it is assumed to be 45% Murban, 40% gasoil and 15% naphtha for the forecast period.
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– CIF Spiked crude forecast at the calculated spiked crude price (based on the assumed recipe) plus a trading and financing premium.
– The trading and financing premium is assumed to be below historical levels, starting at $30/tonne and declining to $25/tonne.
• Products
– Clean products are assumed to be in deficit so are priced on import parity.
– Petrol, jet and diesel product freight costs to Dar es Salaam are based on 2013 and limited 2014 actual data.
– LPG and HFO freight to Dar es Salaam estimated based on other freight rates.
• Crack Spreads
– Product price forecasts based on crack spreads.
– Gasoline cracks fall then stay flat, reflecting plentiful supply.
– Middle distillate crack spreads fall then strengthen more strongly, reflecting strong deficits in some regions globally.
– Fuel oil cracks fall then recover slightly as demand tightens due to the amount of conversion and on-going bunker fuel use.
• Margins
– Hydroskimming margins assumed to be around breakeven on a variable cost basis, negative on a cash cost basis.
o This reflects spare capacity that exists at many refineries, i.e. distillation unit capacity over and above what is needed for the main conversion units.
o Such spare capacity can easily be utilised if margins improve too much and hence this forms a natural level for hydroskimming margins.
– Cracking (FCC) margins are positive, falling to 2017 then recovering but never to the levels seen in 2004-2008 ‘good years’.
o Margins can increase but cannot be sustained at levels that are above historical high level.
o If margins were to stay high for a sustained period, additional FCC based refining capacity would be built, increasing supply and hence reducing margins again.
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MARGIN FORECAST
Figures 4 and 5 below show actual (2010-2013) and our forecast refining margins and Murban crack spreads respectively.
FIGURE 4: ARABIAN GULF REFINING MARGINS
$/bbl Arabian Gulf Refining Margins 4.0
3.0
2.0 Growing demand means margins 1.0 Ref capacity additions improve but not to 0.0 outpacing demand growth levels seen in 2004-08
-1.0
-2.0 Refining Refining Margin -3.0
-4.0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
AG Hydroskimmer FOB Margins AG Cracker FOB Margins
AG Hydroskimming VC margin
FIGURE 5: ARABIAN GULF CRACK SPREADS
$/tonne Arabian Gulf Crack Spreads 200
150
100
50 LPG 0 Naphtha -50 Petrol
-100 Jet/kero Diesel -150 HFO
Crack spreadsCrack to Murban -200
-250
-300
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
The actual crude oil and product prices used in the financial model are show in Tables 6 and 7 below.
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TABLE 6: CRUDE OIL PRICE FORECASTS
US $/bbl (forecasts in 2014 $) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Brent FOB NW Europe 79.6 111.3 111.6 108.6 100.0 100.0 100. 0 100.0 100.0 100.0 100.0
Murban FOB Abu Dhabi 79.2 110.6 113.0 110.1 101.4 101.4 101 .4 101.4 101.4 101.4 101.4 Murban-Brent -0.4 -0.7 1.3 1.5 1.4 1.4 1.4 1.4 1.4 1.4 1.4
US $/bbl (forecasts in 2014 $) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Murban CIF Dar es Salaam 83.4 114.8 117.2 114.8 105.0 103. 0 101.0 100.0 101.0 102.0 103.0 Spiked crude oil CIF Dar es Salaam 98.7 132.6 141.1 123. 8 113.0 112.7 112.4 112.1 112.1 112.1 112.2
US $/bbl (forecasts in 2014 $) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Brent FOB NW Europe 100.0 100.0 100.0 100.0 100.0 100.0 100 .0 100.0 100.0 100.0 Murban FOB Abu Dhabi 101.4 101.4 101.4 101.4 101.4 101.4 10 1.4 101.4 101.4 101.4
Murban-Brent 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4
US $/bbl (forecasts in 2014 $) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Murban CIF Dar es Salaam 104.0 105.0 106.0 107.0 108.0 109 .0 110.0 111.0 112.0 113.0
Spiked crude oil CIF Dar es Salaam 112.3 112.5 112.6 112 .7 112.8 112.9 113.0 113.0 113.1 113.2
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TABLE 7: PRODUCT PRICE FORECASTS
AG FOB Price Product Price US $/t (forecasts in 2014 $) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 LPG 713.0 850.0 910.0 859.6 798.5 794.5 792.5 791.5 792.5 793.5 794.5 Naphtha 695.7 906.3 908.2 887.9 826.2 821.2 818.2 816.2 817.2 818.2 819.2 Petrol 735.9 998.9 1,030.8 994.4 933.4 928.4 925.4 923.4 923.4 923.4 923.4 Jet/kero 692.6 968.0 975.9 946.4 888.8 883.8 878.8 874.8 876.8 878.8 880.8 Diesel 835.4 835.4 833.4 831.4 833.4 835.4 837.4 653.5 912.4 923.5 894.1 HFO 456.8 632.7 651.0 603.6 554.5 549.5 544.5 539.5 539.5 539.5 539.5 Dar es Salaam CIF Price Product Price US $/t (forecasts in 2014 $) 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 LPG 813.0 950.0 1,010.0 959.6 898.5 894.5 892.5 891.5 892.5 893.5 894.5 Naphtha 750.7 961.3 963.2 945.0 891.5 886.5 883.5 881.5 882.5 883.5 884.5 Petrol 790.9 1,053.9 1,085.8 1,051.5 998.7 993.7 990.7 988.7 988.7 988.7 988.7 Jet/kero 762.6 1,038.0 1,045.9 1,018.7 934.2 929.2 924.2 920.2 922.2 924.2 926.2 Diesel 693.5 952.4 963.5 938.6 872.7 872.7 870.7 868.7 870.7 872.7 874.7 HFO 486.8 662.7 681.0 633.6 584.5 579.5 574.5 569.5 569.5 569.5 569.5 AG FOB Price Product Price US $/t (forecasts in 2014 $) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 LPG 795.5 796.5 797.5 797.5 797.5 797.5 797.5 797.5 797.5 797.5 Naphtha 820.2 821.2 822.2 823.2 824.2 825.2 826.2 827.2 828.2 829.2 Petrol 923.4 923.4 923.4 923.4 923.4 923.4 923.4 923.4 923.4 923.4 Jet/kero 882.8 884.8 886.8 887.8 888.8 888.8 889.8 890.8 891.8 892.8 Diesel 839.4 841.4 843.4 845.4 847.4 848.4 849.4 850.4 851.4 852.4 HFO 539.5 539.5 539.5 539.5 539.5 539.5 539.5 539.5 539.5 539.5
Dar es Salaam CIF Price Product Price US $/t (forecasts in 2014 $) 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 LPG 895.5 896.5 897.5 897.5 897.5 897.5 897.5 897.5 897.5 897.5 Naphtha 885.5 886.5 887.5 888.5 889.5 890.5 891.5 892.5 893.5 894.5 Petrol 988.7 988.7 988.7 988.7 988.7 988.7 988.7 988.7 988.7 988.7 Jet/kero 928.2 930.2 932.2 933.2 934.2 934.2 935.2 936.2 937.2 938.2 Diesel 876.7 878.7 880.7 882.7 884.7 885.7 886.7 887.7 888.7 889.7 HFO 569.5 569.5 569.5 569.5 569.5 569.5 569.5 569.5 569.5 569.5
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555.25.2 REFINING
555.2.15.2.1.2.1.2.1 MASS BALANCES Scenarios 1 a & b
This scenario sees the refinery continuing to operate with upgrade investments to improve the quality of gasoil by the addition of a Diesel Hydrotreater unit (DHTU) and increased premium gasoline production by the addition of a C5/C6 Isomerisation unit (Isom). The capacity of the Tazama pipeline is assumed to increase from current throughput levels and hence the refinery can operate to the design capacity of 1.1mtpa throughput.
The analysis was done in two steps:
• Build-up of costs and throughput based on current capacity. • Build-up of costs and throughput based on increasing this to nameplate capacity.
Current Capacity
The installation of a DHTU would allow the refinery to produce a low sulphur gasoil. Currently, straight run gasoil is produced, with a 5,000 ppm sulphur specification. The mines are driving the demand for low sulphur gas (LSGO) at 500 ppm in Zambia and they are currently importing this higher specification gasoil to meet their needs.
The DHTU is fed with gasoil from the crude distillation unit (mixture of atmospheric gasoil and VGO). The DHTU can produce low-sulphur gasoil (<10 ppm wt) complying with EN590 (European) specifications if required.
The installation of a C5/C6 Isom unit would process the light gasoline currently produced, which has a low octane number, typically RON 72. Isomerisation is a process that increases the octane number of light gasoline components and converts to a higher value product, typically a RON of 90+ is achievable.
To generate the refinery mass balance for this scenario, the last 5 years actual refinery throughput has been analysed and the average for this period has been calculated to determine the throughput of the refinery, which was seen to be 618,785 tpa feedstock. The refinery yield calculated has been determined by considering the actual products yield for the last 5 years. The table below provides the product mass balance and product yield. Light naphtha production is processed in the new Isom unit and is used to size the unit, and the resultant product has been added to the Premium Gasoline Pool. The gasoil stream has been used to size a new DHTU which will produce LSGO as shown in Table 8.
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TABLE 8: INDENI 5-YEAR AVERAGE MASS BALANCE
Feedstock (tpa) 618,785 Finished Products (tpa) Product yield (%) LPG 12,376 2% Premium Gasoline 161,010 26% Kerosene 17,286 3% Jet A1 27,401 4% LS Gasoil 282,391 46% HSFO 66,316 11% RFCL 52,006 8%
The new process units based on an on stream factor of 0.9, or 330 days of operation per annum, for this case are shown in Table 9:
TABLE 9: NEW PROCESS UNITS
C5/C6 Isomerisation unit 1,100 bpd Diesel Hydrotreater unit 6,500 bpd
Increase to Nameplate capacity
This scenario sees the refinery continuing to operate with upgrade investments to improve the quality of gasoil by the addition of a DHTU and increased premium gasoline production by the addition of a C5/C6 Isom. The capacity of the Tazama pipeline is assumed to increase from current throughput levels and hence the refinery can operate to its design capacity of 1.1mtpa throughput. The refinery will also need to be returned to its design onstream factor of 0.9 or in operation for 330 days per annum.
To generate the refinery mass balance for this scenario the same philosophy has been adopted for the refinery product yield in Case 1a, but the throughput is increased to the design capacity of 1.1 mtpa of feedstock. Table 10 below provides the product mass balance and product yield. Light naphtha production is processed in the new Isom unit and is used to size the unit and the product has been added to the Premium Gasoline Pool. The gasoil stream has been used to size a new DHTU which will produce LSGO:
TABLE 10: NAMEPLATE CAPACITY- MASS BALANCE/PRODUCT YIELD
Feedstock (tpa) 1,1 million Finished Products (tpa) Product yield (%) LPG 22,000 2% Premium Gasoline 286,223 26% Kerosene 30,729 3% Jet A1 48,710 4% LSGO 502,000 46% HSFO 117,889 11% RFCL 92,449 8%
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The new process units based on an on stream factor of 0.9, or 330 days of operation per annum for this case are shown in Table 11.
TABLE 11: NEW PROCESS UNITS
C5/C6 Isomerisation unit 2,000bpd Diesel Hydrotreater unit 11,500bpd
Scenario 2
This scenario sees the construction of a new refinery to replace the existing Indeni refinery.
A key parameter for a new refinery is the optimum crude capacity. As a general rule a larger capacity refinery will enjoy economies of scale which will reduce the investment costs on a USD $/bpd basis and operating costs on a $/bpd basis. Typically new refinery builds are in the range of 200,000 to 400,000bpd to gain these economies.
As an example, the Hydrocarbon processing 2011 Refining Handbook stated that for a Crude Distillation Unit the installation cost for a capacity of 100,000bpd to 50,000bpd ranged from $1,700 - $2,200 per bpd. This can be seen to be true in Section 5.2.2 CAPEX below.
For this scenario the national demand projections up to 2030 have been considered. The base case shows that the total national demand would require a refinery capacity of nearly 45,000bpd by 2030. For the high demand case, the total national products demand would require a refinery capacity of nearly 70,000bpd. For this scenario a refinery capacity of 50,000bpd has been considered.
A second key parameter to consider is the product yield and volumes that the refinery needs to produce. Again, based on the demand projections by product type, it is clear that middle distillates would need to be maximised, especially LSGO. National demand only has been considered and the export of products to nearby countries has not been assumed at this stage. A brief discussion on refinery configuration and selection is considered below.
Finally, the crude availability is a key logistical issue that would need to be addressed. For this scenario, two crude cases have been considered, a light crude case and heavy crude case. The light crude case is Murban crude and the heavy crude case considered is Upper Zakum. Both are UAE export crudes available in the international market.
Refinery Configuration
The configuration case used for this scenario has been run for the two feedstock cases described above with the production objective of maximum diesel and minimum fuel oil which has led to a choice of a refinery with a hydrocracker with coker unit. The on stream factor for a modern refinery is considered to be 0.94, or 344 operating days per annum. The full configuration consists of:
• Crude Atmospheric Distillation
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• Vacuum Distillation • Refinery Gas Plant • Naphtha Hydrotreater (NHT) • C5/C6 Isomerisation (Isom) • Catalytic Reformer (CCR) • Kerosene Hydrotreater (KTU) • Diesel Hydrotreater (DHT) • VGO Hydrocracker • Delayed Coker • LPG Plant • Hydrogen Production Unit • Sulphur Recovery Plant • Offsites & Utilities
Tables 12 and 13 below present the Unit Capacities and product yields for each of the two crude cases.
TABLE 12: NEW REFINERY- UPPER ZUKUM CRUDE
Basis 50,000bpd, UZ crude, API 33.8, S 1.78 wt % Unit Capacity (bpd) Product tpd tpa CDU 53,191 VDU 23,500 RGP 1,643 (tpd) LPG Merox 2,888 LPG 249 85,656 NHT 11,934 C5/C6 Isom 3,366 Gasoline CCR 8,568 Gasoline 1,404 482,976 KHT 1,279 Kero/Jet 679 233,576 DHT 25,590 LSD 5,232 1,799,808 DCU 8,300 Coke 293 100,792 HCR 15,899
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TABLE 13: NEW REFINERY- MURBAN CRUDE
Basis 50,000bpd, Murban Crude, API 40.2, S 0.79 wt % Unit Capacity (bpd) Product tpd tpa CDU 53,191 VDU 17,400 RGP 1,828 (tpd) LPG Merox 580 LPG 50 17,200 NHT 14,841 C5/C6 Isom 4,182 Gasoline CCR 10,659 Gasoline 1,746 600,624 KHT 1,466 Kero/Jet 188 64,672 DHT 24,135 LSD 4,654 1,600,976 DCU 3,290 Coke 116 39,904 HCR 13,522
Table 14 below highlights the production of the chosen refinery for this case and it can be seen that all product demand is met by at least one of the crude cases, with the exception of the gasoline demand in 2030 and the LSGO in the same year for the high demand case.
TABLE 14: REFINERY PRODUCTION VS DEMAND
Production Demand (High case) Light Case Heavy Case 2020 2025 2030 Premium 600,624 482,976 440,000 580,000 750,000 Jet/Kero 64,672 233,576 110,000 150,000 180,000 LSGO 1,600,976 1,799,808 1,320,000 1,770,000 2,370,000 Production Demand (Base case) Light Case Heavy case 2020 2025 2030 Premium 600,624 482,976 300,000 370,000 470,000 Jet/Kero 64,672 233,576 80,000 100,000 120,000 LSGO 1,600,976 1,799,808 960,000 1220,000 1,530,000
The indicative diagrams of these new refinery configurations for Murban and Upper Zakum are shown in Figures 6 and 7, respectively.
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FIGURE 6: PROFILE HIGH CONVERSION REFINERY- MURBAN CRUDE
FIGURE 7: PROFILE HIGH CONVERSION REFINERY- UPPER ZUKUM CRUDE
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555.5...2.22.22.22.2 CAPEX The CAPEX for each of the refinery options has been based on the AACE International Recommended Practice no. 18R-97, which is the Cost Estimate Classification System – as applied in engineering, procurement and construction for the process industries. The estimate class provided is a Class 5 estimate and has the following characteristics:
Level of Project Definition: 0 – 2% Purpose of Estimate: Concept Screening Methodology: Capacity factored and judgment Expected Accuracy: -/+ 50%
Class 5 estimates are generally prepared based on very limited information, and subsequently have wide accuracy ranges. To obtain a more accurate estimate, further work is recommended such as a feasibility study, followed by front end engineering (FEED) design and detailed design.
The capital cost estimate for the various options has been developed using in-house data. Process unit ISBL (Inside Battery Limits) costs have been developed using costs from similar projects such as refinery configuration and feasibility studies. The OSBL (Outside Battery Limits) costs have been taken as a percentage of the ISBL costs. For this purpose, 50% has been assumed for the Scenario 2, new refinery case. For cases 1b and 2, 15% has been assumed to modify and expand existing refinery OSBL facilities required for the refinery upgrade projects. This has provided the costs deemed as DFC (Direct Field Costs). In order to consider the TIC (Total Installed Cost) the following factors have been considered.
TABLE 15: BUILT- UP TIC FACTORS
Indicative built -up TIC/DFC factor Indirect Field Cost (1) 12% Temporary facilities Construction management Engineering & Home office cost (1) 12% Other Cost (1) 8% Freight Vendor Representatives Escalation (2), (3) 1% Contingency (2), (4) 16%
(1) Applied over DFC cost (2) Applied over all above costs (3) Escalation is a provision for cost escalation for the total project duration (4) Estimating contingency is defined as a special monetary provision in the project budget and Total Installed Cost (TIC), to cover estimating errors, omissions and lack of information and technical documentation.
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The following have not been included in the estimate:
• Land Purchase and Preparation Cost • Start-up costs • Technology License Costs. These costs are negotiated with the technology provider and the agreement reached is specific to each project • Other costs not included are company project management, equipment and tools for the maintenance building, fire station and other safety systems
Scenario’s 1a & 1b
TABLE 16: CAPEX – EXISTING & INCREASE TO NAMEPLATE CAPACITY
Units Current Throughput US$ Nameplate Throughput US$ Capacity million Capacity million C5/C6 Isomerisation unit bpd 1,100 8 2,000 12 Diesel Hydrotreating unit bpd 6,500 29 11,500 44 Total Process Unit 37 55 Utility & Offsites Expansion 6 8 Total project cost 43 64
Scenario 2
TABLE 17: CAPEX – NEW REFINERY
Light Case - Murban Heavy Case – Upper Zakum Unit Units Capacity US$ million Capacity US$ million Crude Distillation bpd 53,191 121 53,191 121 Vacuum Distillation bpd 17,400 41 23,500 50 Gas Plant bpd 15,421 32 14,822 31 Naphtha HDT bpd 14,841 37 11,934 32 C5/C6 Isom bpd 4,182 20 3,366 17 Catalytic Reformer bpd 10,659 93 8,568 80 Kerosene HDT bpd 1,466 6 1,279 5 Diesel HDT bpd 24,135 73 25,590 76 Hydrocracker bpd 13,522 232 15,899 260 Delayed Coking bpd 3,290 59 8,300 112 LPG Treating bpd 580 3 2,888 10 Hydrogen Plant tpd 70 68 70 68 Sulphur Recovery tpd 80 38 80 38 Amine Regeneration m3/h 115 17 115 17 Sour Water Stripper m3/h 25 10 25 10 Total Process Units 850 928 Utility & Offsites 425 464 Total project cost 1,275 1,392
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555.5...2.32.32.32.3 OPOPOPERATING OP ERATING COSTS Operating costs for a Refinery typically include the following:
• Labour Costs • Maintenance • Natural gas • Electricity • Raw Water • Catalysts and Chemicals • Insurance • Land rental
During the conceptual stage of a project it is typical to calculate the operating costs of a project on the basis of a benchmark from other similar executed projects or using a percentage of the Investment Cost. Typically the annual cost can be calculated as follows:
• Labour Costs = No. of expected employees x average salary at project site • Maintenance = 1% of investment cost • Insurance = 0.15% of total investment • Other operating costs = 1.5% of operating costs (above) excluding depreciation
For Scenario 1, which is an upgrade of the existing refinery, the Indeni Refinery Annual Report and Annual Financial Statements have been used to calculate the operating costs in USD/bbl of feedstock processed. To consider this, the cost of sales for 2012 has been analysed together with the annual feedstock throughput and the on stream factor (or operating days) in that particular year. This provides a rate of $2.7/bbl. This has been used in the financial analysis for Scenario 1.
For Scenario 2, the installation of a new 50,000bpd complex refinery, typical current market rates have been used provided by previous executed projects. Data has been sourced from Refinery Technology Licensor providers such as UOP, Shell Global solutions and Axens as well as refinery consultancy companies. For the Murban and Upper Zakum case, $1.75/bbl and $2.0/bbl have been used respectively. We would expect a difference in operating cost for the two feedstock’s due to the increased sulphur levels in Upper Zakum which would require more hydrogen, catalysts and chemicals as well as increased power to drive the increased capacity of the DCU, HCU that is required for this crude feedstock.
We would also expect that the operating costs on a $/bbl basis for a new high conversion refinery to be lower than the existing operating Indeni refinery due to its age and of course high maintenance cost as well as low on stream factor (OSF). For 2012 the OSF for Indeni was slightly above 0.8 whereas for a modern refinery we would expect it to be 0.94, and of course the efficiency of the new refinery would be higher in terms of both design and operations especially with regards to heat integration between process units and operating efficiency of modern machinery including pumps, compressors, and turbines.
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5.3 PIPELINE
The original pipeline design describes a buried pipeline system for its entire length 1,710km of standard industry design pressure, reaching a maximum allowable operating pressure of 100 bar. The pipeline consists of line pipe joint by and large double random lengths, circumferentially butt- welded in-line. The pipeline is externally coated, as are the welded joints, to protect the metal from external corrosion. There is no internal lining or coating in the design.
Cathodic protection is provided for all sections and maintained by current measurement to analyse the efficiency and mitigate external corrosion losses.
The drive and pump units are matched to deliver the required calculated throughput. Pumping units with sparing capacity sized to transport crude through each section to meet a minimum delivery pressure to subsequent pump stations. The subsequent pressure losses due to pipe wall friction and topographical profile combine to give a hydraulic profile (altitude and friction loss) pressure curve throughout the pipeline system.
The pump stations are relatively straightforward ‘fit-for-purpose’ design and have little automation, and data gathering is manually recorded and not distributed immediately. Telephone and mobile phones are the main line of communications between Dar es Salaam operations and the pump stations and refinery. Between ship and terminal there is ship-to-shore radio.
The longer intermediate sections have non-communicable additional pigging stations.
As with all pipelines worldwide, the line pipe corrodes with time. This has been compounded by the amount of sea water that has been ingested and settled in the storage tanks and pipeline system over time.
The metal loss is indicated in 2 pigging runs conducted 10 years apart using an internal inspection tool called an intelligent pig. The pig and measurement equipment are propelled along from pump station pig traps to the next pig trap at either a pigging station or a pumping station where the pig and its recorded data are collected. The data is analysed for anomalies and statistically represented in the pipeline inspection reports. The data shows where the line pipe wall thickness is less than the installed pipeline wall thickness. Significant metal loss is reported at the pipe bottom due to pitting corrosion.
The Tazama and Rosen reports substantiate by fact of extensive line pipe replacement throughout the system that the inevitable outcome of operational effects and corrosion loss is the failure of many lengths of pipe as time progresses.
It is true to say that:
• Corrosion metal loss is a constant factor in the pipe wall along the bottom of the entire pipeline system and can only be halted by replacement of pipe. • Corrosion metal loss in the pipe wall along the bottom of the entire pipeline can be only partially mitigated using various injected inhibitors.
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• Corrosion metal loss in the pipe wall along the bottom of the entire pipeline will eventually require total replacement of the pipeline.
As a consequence of the above facts Tazama Pipelines has implemented a pipe replacement and repair program. Unfortunately this program is under-funded and will not be able to catch the receding metal loss front along the pipeline. The lifetime design of the original pipeline was 25 years and now over 40 years on the pipeline system is now operating at a lower efficiency and in constant risk of leaking. The pressure rating of the system is de-rated due to significant metal loss as recorded in the Rosen inspection reports. How much time is left is a matter of interpretation of the nature of corrosive pitting on a joint-by-joint basis. However, it is obvious from the inspection reports showing the periodic deterioration that a far more holistic approach is necessary if Zambia is to rely on a pipeline system along this route for decades to come.
In summary, inspection and replacement on a piecemeal basis cannot solve the continual aggressive metal loss and pipeline renewal to maintain operational targets.
5.3.1 CASE BY CASE ANALYSIS As the requirement for higher flow-rate increases, the pipeline system’s capacity in annual throughput terms will struggle to support demand, eventually resulting in increased maintenance downtime or shutting down altogether through multitudinous failures.
The logical holistic approach is to analyse the demand over the agreed demand lifetime and build a new pipeline system to better suit the needs of that demand for, say, 25 to 40 years hence.
Comparison studies performed on the following four cases vary in amount, length of pipeline replacement, and whether flow is comingled crude or batched oil products.
CASE 0: FOLLOW PRESENT REPLACEMENT STRATEGY
The level of metal loss and corrosion following the present replacement strategy is not an option going forward as it does not provide a sustainable solution. This is illustrated below.
Tazama provided, as requested, a comprehensive Engineering & Operations Information Report for this project addressing the present status, information on the recent pigging report from Rosen, the planned replacement strategy to keep the pipeline operational, and upgrading required to meet the forecast in increased product demand. This report was used as a basis for further analysis and evaluation. In addition, we conducted a more comprehensive analysis of the Rosen report.
In summary, the proposed pipeline replacement program consists of two elements:
• The Pump Station upgrade program which is presently underway; and • Pipeline replacement program.
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Pump Station upgrade
Two pump stations have received new Caterpillar engines 630HP at Kigamboni and Elphon’s Pass with planned expenditure for a further 5 stations by 2017.
TABLE 18: MAINLINE PUMPS REPLACEMENT PROGRAMME COSTS
MAINLINE PUMPS REPLACEMENT PROGRAM COSTS
Location Pump Total $ Upgrade Status Remaining Scheduled Station # Expenditure Completion Kigamboni PS 1 $5,500,000 2014 Installed Morogoro PS 2 $5,500,000 $5,500,000 2017 Elphon's Pass PS 3 $5,500,000 2014 Installed Iringa PS 4 $5,500,000 $5,500,000 2017 Mbeya PS 5 $5,500,000 $5,500,000 2017 Chinsali PS 6 $5,500,000 $5,500,000 2017 Kalonje PS 7 $5,500,000 $5,500,000 2017 $38,500,000 $27,500,000
Pipeline replacement programme
Pipeline Investment from the Tazama Pipelines Ltd. Engineering and Operations Information (2001 – 2013) has various details of replacement plans and strategies. However, the reality of what replacement took place in the last operating year (2012/13) is shown in Table 19.
TABLE 19: 2013/2014 PRESENT LINE PIPE REPLACEMENT
2013 / 2014 PRESENT LINE PIPE REPLACMENT
Last operating Year No. of Leaks Total Length of all line pipe By inch diameter each detected replaced in km pipeline section replaced in metres From To # kms 8 8 12 2012 2013 26 1.672 240 278 1154
Using the data provided in Tazama Pipelines Ltd. Engineering and Operations Information (2001 – 2013) the analysis of pipe replacement assessment is shown in Table 20 and Figure 8.
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TABLE 20: LINE PIPE REPLACEMENT – METAL LOSS TRENDS – LEAK DETECTED VISUALLY TREND
LINE PIPE REPLACEMENT - METAL LOSS TRENDS - LEAK DETECTED VISUALLY TREND No. of Leaks Total Length of all line By inch diameter each pipeline Report Cycle detected per pipe replaced per annum section replaced per annum in Year on Year annum in km meters From To # kms 8 8 12 2000 2001 16 0 2001 2002 31 0 2002 2003 26 0.084 84 2003 2004 36 0.036 36 2004 2005 25 0 2005 2006 38 0.012 12 2006 2007 24 0 2007 2008 34 0.214 214 2008 2009 30 4.5 4,500 2009 2010 23 0 2010 2011 24 0 2011 2012 25 7 7,000 2012 2013 26 1.718 240 278 1,200 2013 2018 ? 11.626 636 10,990 358 25.19 5,086 914 19,190
Source: Tazama Pipelines Ltd Engineering & Operations Information (2001-2013)
Firstly, we consider the metal loss trend from the line replacement history and leaks observed.
The leaks are visibly detected during maintenance drives along the right of way using four-wheel drive vehicles. The frequency of these security and inspection drives was not disclosed.
Judging by the low number of leaks detected it would appear that only those visible at the surface are recorded primarily as the pipeline system does not have the technology to detect non-visible leaks.
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FIGURE 8: NUMBER OF DETECTED LEAKS PER YEAR
Number of detected leaks per year 400
350
300
250
200 Leak Events
150
100
50
0 1 2 3 4 5 6 7 8 9 10 11 12 13 2000 - 2013 Data from Annual Report
Source: Tazama Pipelines Ltd Engineering & Operations Information (2001-2013)
The frequency of leaks detected has remained almost the same and in any case less than 50 per annum, whilst the pipe replacement and saddle welding reinforcement has increased significantly. Again, this is consistent with a leak having to be of a visible size to be seen during maintenance drive by. The pipeline system does not have the overall technology to detect non-visible leaks. It would require a modern SCADA system. Alternatively, as reported in the Tazama Eng & Ops Report, a significant leak may be detected and reacted to by the local population of farmers.
Secondly, the implementation of the Tazama Pipelines program for pipeline replacement to be completed by the end 2017 is limited by funding available. The ultimate aim is to meet a rising demand. However, there is no calculation of future operational risk due to deteriorating pipeline. The program offers a minimal solution to the ever increasing problem of leaks due to significant pitting and corrosion issues.
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FIGURE 9: LINE PIPE REPLACEMENT TRENDS PER ANNUM METAL LOSS
Line Pipe Replacement Trends Per Annum Metal loss >80% Red Line
18
16
14 Kms
12
10 replaced
8 pipe
6 line
of
4
Length 2
0 1 2 3 4 5 6 7 8 2000-20139 10 11 12 13 14 15 16 17 18 -2 Data from Annual Report
The drive to maintain an ‘operational capacity’, whilst accommodating system downtime due to leak related incident shutdowns, has not been analysed. Figure 9 shows the historical line pipe replacement required to maintain the system throughput and a projected trend of future replacement needs. Even using a straight line trend curve, the predictive result is a greatly increased pipeline replacement requirement.
It should be remembered that this program addresses only the current pigging study by Rosen and does not predict the metal loss and leakages, which will occur in practise.
There is no further planned forecast for pipeline data gathering using In-Line Inspection (ILI) by Rosen. Rosen did not suggest a program or were not requested to do so. Rosen has completed only two inspections and these were almost 10 years apart.
Rosen in their website offer many solutions to maintaining and extending the life-time of pipeline systems and may, under their present contractual arrangement, offer a Pipeline Integrity Management System (PIMS) to handle all the necessary data to constantly redefine the pipeline capacity Estimated Repair Factor (ERF). Rosen point out the Client’s input in assessing the acceptance criteria often leads to different outcomes than would be the case if following the API Guidelines. At the and at the Pipeline Operators Forum in 2009, most of the main pipeline integrity service companies along with international operators explained the various options to operators and the pitfalls of ignoring other options offered by a suitable PIMS and ILI pigging program.
The pipeline in its present condition is deteriorating rapidly and along its entire length although notably more so in the unique 8” sections required for continual use. Without these sections there is no pipeline system to transport crude.
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The majority of the historical work including this year has been 8” pipeline replacement, about 5km. However, since 2011 over 8.2km of 12” has been installed. The strategy is now to commence replacing 8” with 12” line where possible, but even here only in extremely small lengths and in patchwork fashion due to the limited funding provided.
The Tazama Eng & Ops Report also sets out the extent of planned pipeline section replacements and sleeving up to 2018. The pipeline replacement program of line with more than 60% wall loss is shown in Table 21.
TABLE 21: PIPELINE REPLACEMENT PROGRAM COSTS
PIPELINE REPLACEMENT PROGRAM COSTS Tazama Figure 1km Upgrade Total length to Scheduled Location pipeline = $670,000 Status be replaced km Completion Kigamboni PS 1 2018 Morogoro PS 2 2018 Elphon's Pass PS 3 Not started 2018 Iringa PS 4 $7,789,420 awaiting 11.626 2018 Mbeya PS 5 funds 2018 Chinsali PS 6 2018 Kalonje PS 7 2018 Note: The plan is to replace 10,990m of 8” & 636m of 12” in sections suffering greater than 60% metal loss .
In addition, the Report mentions the planned sleeve repairs of 347m 9-8” pipeline and 71.5m of 12” pipeline over the same period.
The entire program is dependent on the availability of funds.
No reference is made to the origin of the claim of ‘extended life in operation’ analysis.
In view of the amount of pipe presently “being planned” to be replaced, presumably as a result of the Rosen Report detection sheets, it is difficult to assume no further deterioration or leaks will occur in the years from now through to the end of period (2018).
It should be stated that there was also a proposed plan included in the Tazama Eng & Ops Report, following an initial analysis of the intelligent pigging report, consisting of the following:
Replace about 105km of 12” pipeline where metal loss >40% $319 million
Replacement of 486km of 8” pipeline $ 70 million
Total capital cost $389 million
The problem is that maintenance and repair costs on the balance of the pipeline will increase at a rate not supported by significant funding, eventually outreaching new pipeline costs. Thus, having
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taken cognisance of the ongoing corrosion and current state of the pipeline we have considered three different sustainable pipeline replacement options to provide security of supply to 2030 and beyond.
SCENARIOS 1A AND 1B: REPLACE THE PIPELINE WITH A NEW 12” CRUDE ONLY PIPELINE
In these options the 954km of deteriorating, corroding, 8” diameter pipeline and the existing 12” pipeline sections are replaced with a new 12” diameter crude pipeline whilst maintaining the pump station configuration but reducing the intermediate pigging stations.
From an operational perspective, the new pumping units and new 12” pipeline operating pressure results in an increase in annual and daily throughput to above the capacity of the refinery. The pipeline system capacity is not the bottle-neck in this scenario.
This option has been incorporated into Scenarios 1a and 1b. The key difference between the Scenarios is timing of implementation and as a result some incremental costs.
Scenario 1a is a slower process where the total pipeline is replaced over six years, focussing in the initial years on replacing the 8” diameter pipeline and thereafter the 12” pipeline. This option may be attractive if raising finance is difficult.
Scenario 1b is an optimal pipeline construction process where the pipeline is replaced over 2 years.
It is assumed in both Scenarios that:
• The Pump Station upgrade as set out In Table 18 and costing $38.5 million will continue to be implemented • The existing pipeline would be decommissioned*, costing $6 million • Annual Operating costs would be in line with international norms at 3% per annum of total capital expenditure
*The decommissioning costs US$6Million includes:
• Cost of water winning and filtering from suitable water source (not seawater) • Cleaning, testing and treatment of water using suitable biocide • Cost of biocide including break-tanks to treat water with biocide so as not to damage pumps or pump station piping during the operation • Pigging for 8-inch and 12-inch sections • Temporary quick couple manifold piping
The process of decommissioning and pumping out the crude in the pipeline is explained below:
• The schedule for total pipeline evacuation is approximately 20 days. However, isolating and capping the water filled pipeline sections can be a maintenance programme.
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• Using the main pipeline pumps operating at reduced pressure and low flow-rate, water which has been dosed with biocide is pumped through the entire pipeline system from Kigamboni Pump Station Terminal to Indeni Storage Tanks. • The process of salvaging the remaining residual crude in the pipeline starts at the first section. A number of Pipeline Intervention Gadgets (pigs) (probably 3 or 4 in series) are placed in the first pipeline section. These are used to create a boundary between crude and treated water. • As the pumping starts, water replaces crude from section to section. Temporary portable pig traps can be used if necessary. • As the pig approaches a receiving pig trap at the end of a section, it is isolated and removed. The next pig train is launched from the launching pig trap in the next section maintaining the separation between crude and water. • Where there are two sections in parallel (8 and 12 inch) the pigging can be done one section at a time with correct valve and crossover management. • The pumping then continues until all of the salvageable crude, i.e. all 1,720 Km of crude, is collected into storage tanks at Indeni for processing. • Emulsified water / crude mix will inevitably occur between the pigs due to residual crude bypassing the pig cups however this will be very small in quantity. This emulsion is discharged to a suitably prepared hold pit and weathered for a number of months before reclaiming and reinstating the pit to former use.
The capital cost of replacing the crude pipeline using both the traditional welding and ZAP-LOK construction methodologies are reflected below, in Table 22.
TABLE 22: CRUDE PIPELINE CAPITAL COSTS
PIPELINE CONSTRUCTION TRADITIONAL WELDING ZAP -LOK CONSTRUCTION Estimate Cost (USD) Estimate Cost (USD) Total Material Costs $343,000,000 $343,000,000 Total Construction Costs $616,000,000 $280,000,000 Other Costs $1,000,000 $1,000,000 Total Engineering Cost $20,000,000 $20,000,000 Total Owners Cost $9,000,000 $24,000,000 Total Project Cost over 2 years -1b * $989,000,000 $668,000,000 Total Project Cost over 6 years -1a $1,056,000,000 $735,000,000 *Note: although both are shown as 2 years, in reality the traditional welding method would take 2-5 years and the ZAP-LOK approach 1.3 years.
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SCENARIO 2: REPLACE THE PIPELINE WITH A NEW 12” MULTI-PRODUCT PIPELINE
In this option the existing crude pipeline is replaced by a 12” multi-product pipeline.
A multi-product pipeline can transport multiple different oil products sequentially down the pipeline using batching pigs or interfaces to separate the products. Products such as Fuel Oil and LPG are not generally pipeline fed and would have to be imported via alternative means. This represents a flexible approach to meeting demand per product type. Elements that need to be considered and controlled include:
• Pump station layout and configuration would require a design verification of the pump hydraulics and impellers, pressure profile of the pipeline under new operating single flow media, valving and manifolds. • Some form of storage required at pump stations if any of these are to be developed into distribution centres for gasoline and diesel. This option is noted but has not been costed in the scenario analysis. • The batching pigs or interfaces will contain some mixing of the grades which can be separated and downgraded as per industry practise. • Operating procedures would need to be set up to maintain market quality to the end user.
It is assumed that:
• The Pump Station upgrade as set out in Table 18 and costing $38.5 million will continue to be implemented. • The existing pipeline would be decommissioned costing $6 million. • Annual operating costs would be in line with international norms at 3% per annum of total capital expenditure.
The capital cost of the new multi-product pipeline using both the traditional welding and ZAP-LOK construction methodologies are reflected in Table 23.
TABLE 23: MULTI-PRODUCT PIPELINE CAPITAL COSTS
PIPELINE CONSTRUCTION TRADITIONAL WELDING ZAP -LOK CONSTRUCTION Cost (USD) Cost (USD) Total Material Costs $343,000,000 $343,000,000 Total Construction Costs $616,000,000 $300,000,000 SCADA & Communications $25,000,000 $25,000,000 Total Engineering Cost $22,000,000 $19,000,000 Total Owners Cost $20,000,000 $20,000,000 Total Project Cost $1,026,000,000 $707,000,000
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The timeframes for completing the construction work are the same as those under Scenarios 1b, i.e. 2.5 years and 1.3 years.
The capital expenditure includes: • Incremental costs of operations for flushing, batching, cleaning, pigging, costs for new infrastructure piping manifold for distribution at Dar es Salaam and Ndola. • Additional storage at Dar es Salaam and Ndola. • A new supervisory control and data acquisition system (SCADA) costing approximately $25 million, which is a sophisticated system that allows online remote control of the entire pipeline system including leak detection and flow rates.
5.3.2 BUILDING A NEW PIPELINE In the past the cost of building an infrastructure project of this magnitude was calculated using traditional construction techniques. The cost for construction and line pipe alone for a pipeline of this length is likely to have exceeded the US$ 1 billion mark. The bulk of these cost calculations is not in the line pipe purchase per se, but in the type and duration of construction method applied.
Traditionally, pipelines have been constructed using joint welding techniques, initially these were fully manual and later semi-automatic welding machines were used to speed up welding and improve welded joint quality. The fully automated systems failed to improve greatly on the semi- automatic systems for onshore overland welding. An acceptable welded joint is affected by the skill of the welder, the quality of the welding materials, the welding machinery and current control, the quality and end bevel preparation of the line pipe to be welded, line pipe ovality, pre and post heating where required, and largely by ambient conditions. These factors are difficult to manage and maintain consistent results.
The joints are tested using radiographic and x-ray, gamma-ray techniques, then visually assessed by adequately qualified inspectors. This represents an anomaly because most pipeline contracts do not require that every joint is radio-graphically tested or inspected unless specified at 100 % inspection. This means that until the joint is hydrostatically water tested at 1.25 times the operating pressure it is expected to pass. However, there have been quite dramatic failures. These are repaired eventually and retested. That is the traditional method of onshore overland pipeline construction. It is costly, time consuming, and not always fail safe.
Since 1973 patents have been given to a different type of field joint method, which entails preparing the ends of each joint of pipe into a swaged fit (male – female type connection). A line up and mating machine draws both ends together and an extrusion mandrel expands one joint as the second joint is forced in to produce a tight pressure holding interface fit. This is patented under the name ZAP-LOK.
A ZAP-LOK joint takes a fraction of the time to perform compared to a welded joint. It requires no welding, no welders or machinery, no radiographic inspection, and, if the coating is factory applied, it requires no field joint coating.
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The advantages of such a system are clear to see, which is why this has become the preferred method of construction in shale gas field in the USA and other countries with 1000’s of kilometres already in operation. It is even used in subsea locations such as the North Sea by one of the main operators in the UKCS.
Some of the advantages of ZAP-LOK over traditional welding are: • The line pipe cost is the same as for welded line pipe joint ends • One joint takes about 2-3 minutes to complete as opposed to 5-15 minutes by traditional methods • No fit up equipment needed • No NDT/x-ray spread needed • No field joint coating needed • Training of 6 local personnel to run one machine takes 2 weeks • The construction schedule and time is halved • Construction costs are less than 50% of traditional pipe-lay • Can be used in traditionally welded pipelines for any length from 3m to innumerable number of pipe lengths using a joint of pipe prepared to suit at no extra cost of materials
Given these clear advantages, the ZAP-LOK costs have been utilised in the analysis of the new pipeline Scenarios.
A more detailed feasibility and implementation plan will need to be conducted if the decision to is taken to replace the current pipeline with a new product or crude pipeline.
5.3.3 RECOMMENDATIONS
Replacement of pipeline
It is clear that the level of corrosion in the existing pipeline is endemic and escalating and that replacement of the existing 40 year old pipeline is crucial to Zambia’s security of supply.
Other recommendations stemming from our review and analysis:
Maintain the right of way
Effective inspection and security of the right of way is a key necessity when converting from spiked crude to a multi-product pipeline system. Increased presence on the ground is essential to prevent theft and damage and to maintain operations.
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Surveillance of the Pipeline
Increased surveillance to mitigate theft, damage, and sabotage can be cost effectively introduced using airborne drone cameras. Such drones have an effective flight recording distance of up to 100km and can produce extremely good high definition satellite imagery of the entire pipeline system month-in and month-out.
Automation of the pipeline system, storage, delivery, metering
To aid the day-to-day running of the operations in remote areas, some form of communications other than telephone, cellphone, or radio needs to be installed as the system’s main backbone. Increased automated control and mimic panels can be introduced relatively inexpensively using a web-based platform to gather and reproduce data, maintain historical data, create an asset database, and control batches of product by volume, weight and physical properties. This can be accessed from any location with an internet connection on any laptop, or device, including a mobile phone.
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6. DEMAND/CONSUMPTION
The two oil product demand forecasts to 2030 as discussed in detail in the Inception Report are included in this report for reference purposes and as an aide memoire before considering the supply chain options.
• A base – low case where growth continues but both the copper price and copper output drop by 20% versus the high case and the rate of petroleum growth slows but demand nearly doubles to 2,600 megalitres / 2.2mtpa by 2030. • A base – high case where current growth continues, copper prices are maintained and the copper sector continues to expand and petroleum demand is forecast to grow to over 4,000 megalitres / 3.7mtpa.
There are a couple of important observations about these forecasts:
• Demand growth for the primary products of petrol and gasoil/diesel (in particular LSGO used in the mines) are forecast to grow at an average annual rate of between 3% and 6.8% during the forecast period from 2013 to 2030, which is significant in comparison to global growth and on the high side for projected growth in Africa. • However, petrol and diesel (gasoil) are expected to grow at a slower rate in the future to 2030 than it did in the past decade. The growth trend is similar for jet and fuel oil. • Gasoil is forecast to increase from 61% to 70% of total demand with Petrol’s share of product demand declining from 25% to 21%, reflecting the continued increase in mining demand for LSGO.
FIGURE 10: ZAMBIA LIQUID FUELS MIX 2003 TO 2030 BASE CASE- LOWER
Source: Channoil Consulting
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FIGURE 11: ZAMBIA LIQUID FUELS MIX 2003 TO 2030 BASE CASE- UPPER
Diesel the dominant fuel – all fuels converted to megalitres.
Source: Channoil Consulting
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7. OPTIONS
777.17.1 OPTIONS ––– INTRODUCTION
In this section we will consider several options for Zambia to secure the supply of petroleum products to meet demand out to 2030. Realistic options have been developed taking into account a detailed review of the current oil supply situation in Zambia and the energy and infrastructure sector development plans being considered by the Zambian government. We have also taken into account future minimum quality specification requirements for gasoil. Our key assumption is that by 2017 all gasoil consumed in Zambia should be of 0.5% sulphur or lower – this is in line with regulations already in place internationally and in South Africa. A brief summary of the options considered is provided below:
• “Upgrading investment” – Invest in Indeni refinery to improve the refinery efficiency and product quality (to meet future minimum specifications) and replace the Tazama crude oil pipeline. • “New refinery” – Mothball Indeni refinery, build a new refinery and replace the Tazama crude oil pipeline. • “Terminal and pipeline” – Decommission the Tazama pipeline, replace with a new petroleum products pipeline, mothball Indeni refinery and utilise parts of the refinery for a petroleum products receiving terminal. • “Road only” – Mothball the Indeni refinery, decommission the Tazama pipeline and revert to using road tankers for delivery of all products into the country.
“No investment” and “Improvement investment”, options were not considered, as considerable investment is required in both the Tazama crude oil pipeline and the Indeni refinery in order to continue operations out to 2030. In terms of the Tazama pipeline, upgrading would cost just as much, if not more, than replacing with a new crude oil pipeline using new technology with unknown results, and is therefore not considered.
In terms of considering new crude oil discoveries in Zambia, Zambia is in very early stages of crude oil exploration, it would typically take several years to complete seismic testing and drilling programs to ascertain whether commercially viable quantities exist. Following a review of policy, companies would then take several years to produce the crude oil. It is therefore highly unlikely that Zambia would discover and produce large quantities of crude oil within the time period being considered. If commercial quantities are discovered, it is likely that the crude oil would be exported whilst the country continues to import petroleum products. Refining only on a very large scale is feasible in today’s global market. Nevertheless, if crude oil gets supplied to a refinery in Zambia, the difference would be in the commodity cost – where the price in Zambia would be determine as a net back from market (Middle East) prices providing a saving on the cost of shipping and pipeline transport that would have been incurred for imports. We comment on the impact of this saving further below when discussing the cost benefit results.
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For each option considered, we assess what each means in terms of the quantity and quality of petroleum products that can be supplied into Zambia, the capital cost and financing requirement, and the effective delivered cost for these products to wholesalers. We provide a qualitative and quantitative cost-benefit analysis and a relative ranking of the various options.
Capital, operating and finance costs are modelled using an economic model for which the methodology, assumptions and results are discussed and provided later in this section. Detailed descriptions of the various options considered are discussed below.
777.27.2 UPGRADING INVESTMENT
Investing in the refinery to build and commission new upgrading plants in order to improve the refinery yield structure is not an optimal solution. The major constraint on refinery output is due to the smaller capacity in the Tazama crude oil pipeline supplying the refinery (around 0.7mtpa). Replacement of the crude oil pipeline with a larger pipeline can lead to an increase in refinery output to close to the nameplate capacity of 1.1mtpa. Some investment in Indeni refinery is required to improve the quality of gasoil produced in order to meet future minimum quality specifications and to the quality of petroleum in order to reduce requirements of imports for blending. Quality improvements do not impact on the yield.
The Tazama crude oil pipeline also has to be fully replaced in order to continue operations out to 2030 given severe corrosion and leakages as outlined in Section 5. Investment in a new crude oil pipeline with a capacity of 1.1mtpa, to better match Indeni refinery capacity, is considered under two scenarios: over a longer period, replacing the whole pipeline over six years (Scenario 1a), and over the short term, replacing the whole pipeline within 2 years by 2017 (Scenario 1b). These options are portrayed pictorially in Figures 12 and 13, with the detailed volumes provided in Tables 24 & 25, further below.
FIGURE 12: SCENARIO 1A – UPGRADE REFINERY WITH GASOIL HYDROTREATER & ISOMERISATION UNIT BY 2017, NEW CRUDE PIPELINE OVER 6 YEARS
3.50
3.00
2.50
2.00
mtpa 1.50
1.00
0.50
0.00 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Indeni Losses Indeni Petrol Indeni Gasoil Indeni Jet Indeni Kerosene Indeni HFO Road Petrol Road Gasoil Road Low Sulphur GO Road Jet/Ker/HFO Demand - Base Case TAZAMA Pipeline Indeni Refinery Demand - High Case
Source: Channoil Consulting
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TABLE 24: SCENARIO 1A UPGRADE REFINERY WITH GASOIL HYDROTREATER & ISOMERISATION UNIT BY 2017, NEW CRUDE PIPELINE OVER 6 YEARS
mtpa 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Tazama 0.65 0.60 0.65 0.70 0.70 0.70 0.70 0.70 0.70 Pipeline New Crude Oil 0.90 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 Pipeline Indeni Refinery Yield 0.55 0.47 0.58 0.70 0.70 0.70 0.70 0.70 0.70 0.90 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 Petrol 26% 0.12 0.11 0.15 0.18 0.18 0.18 0.18 0.18 0.18 0.23 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 Gasoil * 46% 0.32 0.23 0.27 0.32 0.32 0.32 0.32 0.32 0.32 0.41 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 Jet 4% 0.04 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 Kerosene 3% 0.02 0.01 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 HFO 11% 0.05 0.10 0.06 0.08 0.08 0.08 0.08 0.08 0.08 0.10 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 LPG 2% 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 Road
Petrol 0.16 0.18 0.11 0.08 0.07 0.08 0.09 0.10 0.12 0.08 0.04 0.06 0.07 0.09 0.10 0.12 0.14 0.16 0.18
LS Gasoil 0.15 0.07 0.17 0.20 0.23 0.52 0.56 0.60 0.64 0.59 0.55 0.60 0.65 0.71 0.77 0.83 0.89 0.95 1.02
Gasoil 0.30 0.43 0.32 0.25 0.25
Jet 0.03 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.03 0.04 0.04 0.05 0.05 0.05 0.06 0.06 0.07
Kerosene (0.00) (0.01) (0.01) (0.01) (0.01) (0.01) (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02)
HFO (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.04) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06)
LPG (0.01) (0.01) (0.01) (0.01) (0.01) (0.01) (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02)
* LSGO post 2016 following investment in gasoil hydrotreater meeting minimum specifications
Source: Channoil Consulting
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Indeni upgraded:
Indeni refinery output is increased from 0.62mtpa to 1.1mtpa as more crude oil can be supplied to the refinery from the new larger crude oil pipeline. Though the mix or proportions of the different products produced is still the same, installing a Gasoil Hydrotreater and Isomerisation unit will allow for LSGO and better quality petroleum (91 RON) to be produced. Costs of the Gasoil Hydrotreater and Isomerisation unit are estimated to be $48m and $16m respectively. As the mix or proportions of product output are still the same, increased output only adds to the surplus fuel oil problem currently faced by Indeni.
New Tazama crude pipeline:
In this option the Tazama crude oil pipeline is replaced with a new 12” crude oil pipeline over a period of 6 years at an estimated cost of $735m, split over the 6 year construction period, including decommissioning of the existing pipeline. Initially some pumps are replaced by 2017 under existing plans at an estimated cost of $39m (including the $11m expected to be incurred in 2014). Once fully replaced by Year 6, capacity is increased from 0.7mtpa to 1.1mtpa, with an assumed ramp-up period of 1 year at 0.9mtpa.
Balance imported by Road: The remaining demand is met through additional imports of petroleum products by road. As demand for other products is relatively low, road imports are only required for LSGO.
FIGURE 13: SCENARIO 1B UPGRADE REFINERY WITH GASOIL HYDROTREATER & ISOMERISATION UNIT BY 2017, NEW CRUDE PIPELINE OVER 1-2 YEARS
3.50
3.00
2.50
2.00
mtpa 1.50
1.00
0.50
0.00 2012201320142015201620172018201920202021202220232024202520262027202820292030
Indeni Losses Indeni Petrol Indeni Gasoil Indeni Jet Indeni Kerosene Indeni HFO Road Petrol Road Gasoil Road Low Sulphur GO Demand - Base Case TAZAMA Pipeline Indeni Refinery New Pipeline Demand - High Case
Source: Channoil Consulting
Scenario 1b is the same as for Scenario 1a, apart from replacement of the crude oil pipeline over the period 2015-16, hence allowing for an increase in the Indeni refinery capacity (to 1.1mtpa) and output by 2017. Unlike Scenario 1a, pump replacement would not be required as this is included in
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the capital costs for a new pipeline, estimated at $668m. Decommissioning costs of $6m for the Tazama pipeline are also included. Hence, the comparison between Scenario 1a and 1b is to understand the costs and benefits of early investment and reduced requirement for imports by road, versus a pro-longed but potentially easier investment but having to rely more on road imports until completed.
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TABLE 25: SCENARIO 1B UPGRADE REFINERY WITH GASOIL HYDROTREATER & ISOMERISATION UNIT BY 2017, NEW CRUDE PIPELINE OVER 1-2 YEARS
mtpa 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Tazama Pipeline 0.65 0.60 0.65 0.70 0.70
New Crude Oil 0.90 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 Pipeline Indeni Refinery Yield 0.55 0.47 0.58 0.70 0.70 0.90 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 1.10 Petrol 26% 0.12 0.11 0.15 0.18 0.18 0.23 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 0.29 Gasoil * 46% 0.32 0.23 0.27 0.32 0.32 0.41 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 Jet 4% 0.04 0.02 0.02 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 Kerosene 3% 0.02 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 0.03 HFO 11% 0.05 0.10 0.06 0.08 0.08 0.10 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 0.12 LPG 2% 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 Road
Petrol 0.16 0.18 0.11 0.08 0.07 0.03 (0.01) 0.00 0.01 0.03 0.04 0.06 0.07 0.09 0.10 0.12 0.14 0.16 0.18
LS Gasoil 0.15 0.07 0.17 0.20 0.23 0.43 0.37 0.41 0.46 0.50 0.55 0.60 0.65 0.71 0.77 0.83 0.89 0.95 1.02
Gasoil 0.30 0.43 0.32 0.25 0.25
Jet 0.03 0.03 0.03 0.03 0.02 0.02 0.03 0.03 0.03 0.04 0.04 0.05 0.05 0.05 0.06 0.06 0.07
Kerosene (0.00) (0.01) (0.01) (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02)
HFO (0.01) (0.02) (0.02) (0.04) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06) (0.06)
LPG (0.01) (0.01) (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02)
* LSGO post 2016 following investment in gasoil hydrotreater meeting minimum specifications
Source: Channoil Consulting
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777.37.3 NEW REFINERY
The option for a building a new refinery is considered in Scenario 2. The capacity of the new refinery is assumed to be 50,000bpd (~2.3mtpa). This is considerably larger than the capacity of the existing Indeni refinery and larger than current demand for petroleum products in Zambia. Nevertheless, a new refinery with capacity of at least 2mtpa would be needed to meet projected demand post 2020 and would provide significant economies of scale and lower unit costs for refining crude oil. The results are shown in Figure 14 and Table 26.
FIGURE 14: SCENARIO 2 – BUILD A NEW 50,000 BPD/2.5MTPA REFINERY BY 2023, AND BUILD A NEW CRUDE PIPELINE BY 2017
3.50
3.00
2.50
2.00
mtpa 1.50
1.00
0.50
0.00 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Indeni Petrol New Ref Petrol Indeni Jet New Ref Jet Indeni Kerosene New Ref Kerosene Indeni Gasoil New Ref LPG New Ref Coke New Ref Gasoil Indeni HFO Road Petrol Road Gasoil Road Low Sulphur GO Road Jet/Ker/HFO Demand - Base Case TAZAMA Pipeline Indeni Refinery New Pipeline New Refinery Demand - High Case
Source: Channoil Consulting
Indeni upgraded and new Tazama pipeline built:
As with Scenario 1b, we have assumed that the existing Indeni refinery gets upgraded and continues to operate until 2023, served by a new crude oil pipeline:
• Gasoil hydrotreater installed by 2017 to produce lower sulphur gasoil ($48m) • Isomerisation unit installed by 2017 to produce 91 RON petrol ($16m) • Tazama crude oil pipeline decommissioned ($6m) and replaced with new crude oil pipeline with maximum capacity of 2.5mtpa by 2017 ($668m) – throughput of 1.1mtpa initially
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New refinery built adjacent to Indeni:
By 2023 Zambian demand is projected to have increased to a high enough level to justify bringing the new refinery online. A construction period of four years is assumed for the new refinery starting in 2019. The throughput of the new crude oil pipeline is assumed to increase to 2.3mtpa to match capacity in the new refinery through bringing on additional pumping stations. As the new refinery comes online, the Indeni refinery starts to be decommissioned at an estimated cost of $10m. The cost of the new refinery is estimated to be $1,275m, with costs spread evenly over the 4 year construction period. The new refinery is assumed to be designed to better meet the demand for different petroleum products in Zambia – largely gasoil (69% yield) and petroleum (26% yield).
Balance imported by Road:
Up until the new refinery comes online, demand that is not met by supply from the Indeni refinery will be met through additional imports of petroleum products by road. As with Scenario 1a and 1b, road imports are only required for LSGO.
When the new refinery comes online, no road imports are required prior to 2030. Excess supply of products would be expected until demand catches up. Excess supply is not easily avoided as running refineries at lower utilisation damages the economics and furthermore, it is not feasible to increase capacity in phases. Any excess production is likely to be exported by road. Exports to the Democratic Republic of Congo are assumed to achieve premium prices, but exports back into Tanzania or back along the supply chain are assumed to be sold at a discount to the value of the products at the new refinery.
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TABLE 26: SCENARIO 2 BUILD NEW 50,000 BPD/2.5MTPA REFINERY BY 2023, AND BUILD A NEW CRUDE PIPELINE BY 2017
mtpa 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Tazama Pipeline 0.65 0.60 0.65 0.70 0.70
New Crude Oil 0.90 1.10 1.10 1.10 1.10 1.10 2.32 2.32 2.32 2.32 2.32 2.32 2.32 2.32 Pipeline Indeni Refinery Yield 0.55 0.47 0.58 0.70 0.70 0.90 1.10 1.10 1.10 1.10 1.10 Petrol 26% 0.12 0.11 0.15 0.18 0.18 0.23 0.29 0.29 0.29 0.29 0.29 Gasoil * 46% 0.32 0.23 0.27 0.32 0.32 0.41 0.51 0.51 0.51 0.51 0.51 Jet 4% 0.04 0.02 0.02 0.03 0.03 0.04 0.04 0.04 0.04 0.04 0.04 Kerosene 3% 0.02 0.01 0.02 0.02 0.02 0.03 0.03 0.03 0.03 0.03 0.03 HFO 11% 0.05 0.10 0.06 0.08 0.08 0.10 0.12 0.12 0.12 0.12 0.12 LPG 2% 0.01 0.01 0.01 0.01 0.01 0.02 0.02 0.02 0.02 0.02 0.02 New Refinery 2.32 2.32 2.32 2.32 2.32 2.32 2.32 2.32 Petrol 24% 0.56 0.56 0.56 0.56 0.56 0.56 0.56 0.56 LS Gasoil 67% 1.56 1.56 1.56 1.56 1.56 1.56 1.56 1.56 Jet 5% 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 Kerosene 0.5% 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 HFO 2.5% 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 LPG 0.7% 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 Road
Petrol 0.16 0.18 0.11 0.08 0.07 0.03 (0.01) 0.00 0.01 0.03 0.04 (0.22) (0.21) (0.19) (0.17) (0.16) (0.14) (0.12) (0.10)
LS Gasoil 0.15 0.07 0.17 0.20 0.23 0.43 0.37 0.41 0.46 0.50 0.55 (0.45) (0.40) (0.34) (0.29) (0.23) (0.16) (0.10) (0.03)
Gasoil 0.30 0.43 0.32 0.25 0.25
Jet 0.03 0.03 0.03 0.03 0.02 0.02 0.03 0.03 0.03 (0.03) (0.03) (0.02) (0.02) (0.01) (0.01) (0.01) (0.00)
Kerosene (0.00) (0.01) (0.01) (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.00) (0.00) (0.00) (0.00) (0.00) (0.00) (0.00) (0.00)
HFO (0.01) (0.02) (0.02) (0.04) (0.06) (0.06) (0.06) (0.06) (0.06) (0.00) (0.00) (0.00) (0.00) (0.00) (0.00) (0.00) (0.00)
LPG (0.01) (0.01) (0.01) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02) (0.02)
* LSGO post 2016 following investment in gasoil hydrotreater meeting minimum specifications
Source: Channoil Consulting
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777.47.4 TERMINAL AND PIPELINE
The option for building a new products import pipeline is considered in Scenario 3. The capacity of the new products pipeline is assumed to be 2.5mtpa, coming online in 2017, initially at a lower throughput of 1.25mtpa to better meet Zambian demand at that time. Throughput is assumed to increase to match the increase in demand, through bringing on additional pumping stations, thereby increasing to 1.5mtpa in 2022, 1.75mtpa in 2026 and 2.0mtpa by 2029. With direct imports of products by pipeline, the existing Indeni refinery and Tazama crude oil pipeline are no longer required, and are mothballed/shutdown and decommissioned, post 2016. This Scenario is depicted in Figure 15 and Table 27.
FIGURE 15: SCENARIO 3 MOTHBALL/SHUTDOWN REFINERY IN 2017, BUILD NEW PRODUCTS PIPELINE BY 2017
3.50
3.00
2.50
2.00
mtpa 1.50
1.00
0.50
0.00 2012201320142015201620172018201920202021202220232024202520262027202820292030 Prod Pipe Petrol Prod Pipe Gasoil Indeni Petrol Indeni Gasoil Indeni Jet Indeni Kerosene Indeni HFO Road Petrol Road Gasoil Road Low Sulphur GO Road Jet/Ker/HFO Indeni Losses Products Pipeline Indeni Refinery Demand - Base Case Demand - High Case TAZAMA Pipeline
Source: Channoil Consulting
Indeni refinery and Tazama crude oil pipeline mothballed/shutdown:
In 2017, or shortly after the new products pipeline comes online, Indeni refinery and Tazama crude oil pipeline are decommissioned at a cost of $6m and $10m respectively. Hence, no upgrade investment is made unlike in Scenarios 1 and 2. At Indeni, the existing tankage is converted to product storage and linked with the nearby Ndola fuel terminal. Crude oil storage at Dar es Salaam would also have to be converted to products storage and additional product storage at Dar es Salaam may be required.
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New products pipeline built:
The new products pipeline would be constructed over 2015 and 2016, and planned to come online in 2017. The cost of the new products pipeline is estimated to be $707m. Only the two key products consumed in Zambia, gasoil and petroleum, are assumed to be imported by pipeline, on a batched basis (75% gasoil 25% petroleum). Demand for other products is considerably lower and will add significant complexity to operations, management and storage requirements, if also batched with the gasoil and petroleum.
Balance imported by Road: Hence, all other products (Jet, Kerosene, HFO and LPG) are assumed to be imported by road. With increases in pipeline capacity made feasible through addition pumping, gasoil and petroleum imports and supply are assumed to be able to match demand relatively well. Hence, requirement for exports of excess supply by road is much less than for the new refinery as described in Scenario 2.
.
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TABLE 27: SCENARIO 3 MOTHBALL/SHUTDOWN REFINERY IN 2017, BUILD NEW PRODUCTS PIPELINE BY 2017
mtpa 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Tazama Pipeline 0.65 0.60 0.65 0.70 0.70 New Products Pipeline 1.25 1.25 1.25 1.25 1.25 1.50 1.50 1.50 1.50 1.75 1.75 1.75 2.00 2.00 Petrol 25% 0.31 0.31 0.31 0.31 0.31 0.38 0.38 0.38 0.38 0.44 0.44 0.44 0.50 0.50 LS Gasoil 75% 0.94 0.94 0.94 0.94 0.94 1.13 1.13 1.13 1.13 1.31 1.31 1.31 1.50 1.50 Indeni Refinery Yield 0.55 0.47 0.54 0.62 0.62 Petrol 26% 0.12 0.11 0.14 0.16 0.16 Gasoil 46% 0.32 0.23 0.25 0.28 0.28 Jet 4% 0.04 0.02 0.02 0.02 0.02 Kerosene 3% 0.02 0.01 0.02 0.02 0.02 HFO 11% 0.05 0.10 0.06 0.07 0.07 LPG 2% 0.01 0.01 0.01 0.01 0.01 Road Petrol 0.16 0.18 0.12 0.10 0.10 (0.05) (0.04) (0.03) (0.01) 0.00 (0.05) (0.03) (0.02) (0.00) (0.05) (0.03) (0.01) (0.05) (0.03) LS Gasoil 0.15 0.07 0.17 0.20 0.23 (0.10) (0.06) (0.02) 0.03 0.07 (0.07) (0.02) 0.04 0.09 (0.04) 0.02 0.08 (0.04) 0.03 Gasoil 0.30 0.43 0.34 0.29 0.28 Jet 0.03 0.03 0.04 0.06 0.07 0.07 0.07 0.07 0.08 0.08 0.09 0.09 0.09 0.10 0.10 0.11 0.11 Kerosene (0.00) (0.01) (0.01) 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 HFO (0.00) (0.01) (0.01) 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 LPG (0.01) (0.01) (0.01) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Source: Channoil Consulting
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777.57.5 ROAD ONLY
Scenario 4 considers mothballing the existing supply chain in favour of importing all petroleum products by road. This is depicted in Figure 16 and Table 28.
FIGURE 16: MOTHBALL/SHUT DOWN REFINERY AND PIPELINE IN 2017, IMPORT BY ROAD
4.00 3.50 3.00 2.50 2.00 mtpa 1.50 1.00 0.50 0.00 2012201320142015201620172018201920202021202220232024202520262027202820292030 Indeni Losses Indeni Petrol Indeni Gasoil Indeni Jet Indeni Kerosene Indeni HFO Road Petrol Road Gasoil Road Low Sulphur GO Road Jet/Ker/HFO/LPG Demand - Base Case TAZAMA Pipeline Indeni Refinery Demand - High Case
Source: Channoil Consulting
As with Scenario 3 above, Indeni refinery and Tazama crude oil pipeline are decommissioned in 2017, with some crude oil storage at Indeni converted to store petroleum products. All demand is then met through imports by road from neighbouring countries.
Imports are likely to continue to come from Tanzania, Mozambique and South Africa. However, given the large increase in imports required with the Indeni refinery being brought offline, imports may also have to be sourced from Angola. Angola is the only neighbouring country with a new refinery under construction. Several other neighbouring countries have plans for new refineries (Tanzania (x1), Namibia (x1), Mozambique (x2), South Africa (x1 in addition to the five refineries currently in operation)), but few, if any, are likely to be realised. The main reason for this is the competitiveness of Indian and Middle Eastern refineries, which means is it likely to be cheaper to import products rather than import crude oil and refine domestically in this region.
Relying solely on imports by road poses some security of supply issues. However, with a number of different supply sources and the government being able to import volumes themselves through Dar es Salaam, this is somewhat alleviated. However, importing petroleum products by road is likely to be more costly than importing products by pipeline.
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Petroleum product imports by rail, particularly from the new refinery at neighbouring Angola, can be considered in conjunction to imports by road in this Scenario. The reason for not considering rail in as much detail as part of this study, is due to the lower priority placed by the government on extending the rail network from Angola/DRC to Zambia and within Zambia. Whilst the necessary level of investment and development planning would be substantial and the time for implementation extensive, it is an option that merits further consideration in the future especially if no new pipeline is built.
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TABLE 28: SCENARIO 4 MOTHBALL/SHUT DOWN REFINERY AND PIPELINE IN 2017, IMPORT BY ROAD
mtpa 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Tazama Pipeline 0.65 0.60 0.65 0.70 0.70
Indeni Refinery Yield 0.55 0.47 0.54 0.62 0.62 Petrol 26% 0.12 0.11 0.14 0.16 0.16 Gasoil 46% 0.32 0.23 0.25 0.28 0.28 Jet 4% 0.04 0.02 0.02 0.02 0.02 Kerosene 3% 0.02 0.01 0.02 0.02 0.02 HFO 11% 0.05 0.10 0.06 0.07 0.07 LPG 2% 0.01 0.01 0.01 0.01 0.01 Road
Petrol 0.16 0.18 0.12 0.10 0.10 0.26 0.28 0.29 0.30 0.31 0.33 0.34 0.36 0.37 0.39 0.41 0.43 0.45 0.47
LS Gasoil 0.15 0.07 0.17 0.20 0.23 0.84 0.88 0.92 0.96 1.01 1.06 1.11 1.16 1.22 1.27 1.33 1.39 1.46 1.53
Gasoil 0.30 0.43 0.34 0.29 0.28
Jet 0.03 0.03 0.04 0.06 0.07 0.07 0.07 0.07 0.08 0.08 0.09 0.09 0.09 0.10 0.10 0.11 0.11
Kerosene (0.00) (0.01) (0.01) 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01
HFO (0.00) (0.01) (0.01) 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06 0.06
LPG (0.01) (0.01) (0.01) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Source: Channoil Consulting
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8. COST BENEFIT ANALYSIS
888.18.1 METHODOLOGY
The objective of developing a financial model is to assess the ‘Costs and Benefits’ of each option to the Government. The purpose of this Cost Benefit Analysis is to evaluate the viability of each option, with a view to determining the optimal solution for Zambia’s petroleum industry - measured as the least cost to the Government while meeting the projected demand for petroleum products.
For completeness, we list in Table 29 the options analysed during the financial modelling stage:
TABLE 29: OPTION SUMMARY Description
Option 1a • Upgrade Refinery with Gasoil, Hydrotreater and Isomerisation unit by 2017. • New Crude Pipeline over 6 years. Option 1b • Upgrade Refinery with Gasoil, Hydrotreater and Isomerisation unit by 2017. • New Crude Pipeline over 1-2 years. • New 50,000bpd/2.5mtpa Refinery by 2023 Option 2 • New Crude Pipeline by 2017 Option 3 • Shutdown Refinery in 2017, • Build new Products Pipeline by 2017
Option 4 • Shutdown Refinery and Pipeline by 2017 • Import all by Road
Drawing from the review of Zambia’s existing oil infrastructure and the petroleum products demand analysis, we developed a Financial Model (“The Model”) that is built on the capital costs, operating costs and volume assumptions for each option as defined earlier in this Report.
Figure 17 illustrates the foundation blocks for developing the model.
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FIGURE 17: FOUNDATION BLOCKS FOR DEVELOPING THE MODEL
The model is designed to envelop two key characteristics:
1. Transparency – The architecture and calculations can be easily followed
2. Flexibility – The model can be readily updated in a timely and low risk manner.
We have applied best practice modelling techniques as set out in Table 30 in developing the model.
TABLE 30: BEST PRACTICE MODELLING TECHNIQUES
Best Practice Modelling Techniques
• Keep input, calculation and output areas separate: this decreases the margin for error and reduces the complications for testing, and resolution of, errors. • Think about what the input and output areas need to look like during the design phase, before we start modelling, taking full account of the particular requirements of our client.
• Clearly identify those cells in the input areas which actually drive the model.
• Keep it simple – we break complex calculations down into simpler steps. This makes the model much easier for others to interpret and use, and for us to identify and eliminate any errors. The techniques we use make the model easier to interpret and they reduce the amount of work required if any of the calculations need to be changed in the future (as the change is made in one place). They will also have a direct impact on the speed at which the model calculates, thus improving efficiency of the model mechanics.
• Include adequate “audit trail” information so that the model is useful to those less familiar with it and not just another faceless spreadsheet.
• Include error checking mechanisms – th is varies according to the complexity of the model, but could include for example input checks, consistency checks, output checks etc.
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• Maintain consistency of time periods – we always agree up front the desired length of the accounting periods to be modelled and maintain this as constant throughout the model (e.g. annual, semi-annual, quarter or monthly).
• Keep positives positive and negatives negative – in our models we always show costs, cash outflows, or liabilities as negative and revenues, cash inflows, or assets as positives so that simple SUM statements may be used throughout the model. This greatly assists in interpretation particularly, for instance, in the odd circumstances where items that should be inflows are negative, or assets become liabilities.
The diagram show in Figure 18 outlines the broad structure of the model and the associated relationship between the input, calculation and evaluation sheets driven by our viability analysis.
FIGURE 18: FINANCIAL MODEL STRUCTURE
The model is structured to separate assumptions, calculations, outputs and price for each of the following:
1. Non-Road • Tazama Pipeline • Indeni Refinery
2. Road
These are then further analysed for each option identified above.
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888.28.2 KEY FINANCIAL METRICS AND ASSUMPTIONS
888.2.18.2.1 KEY FINANCIAL METRICS There are a number of financial metrics the model adopts in order to determine the price build up for each option:
Internal Rate of Return : Each of the options analysed in the Financial Model has been structured to ensure an Equity IRR of 15% to each entity.
Overall cash flow : We considered the real (projected) cash flows of each option to understand whether there are any periods in which an overdraft occurs, to ensure the funding options have been optimised for each entity.
Tariff : The tariff refers to a cost reflective fee per tonne for the pipeline and the refinery, and is designed to capture the following costs in addition to attaining the 15% return to the assets:
• Debt Repayment • Interest and Finance Costs • Operating Costs • Taxes
Present Value : The present value of the annual tariff over the 17 year projection period presents a ‘current worth’ of the tariff (i.e. the value of the stream of tariffs in 2014 terms), discounted at the required IRR of 15%.
Levelised tariff : The purpose of levelising the tariff is to obtain a harmonised tariff over the 17 year projection period. Essentially, the method of levelising allows for the determination of a ‘single tariff’ per tonne, which if applied to the project life would have the same values as the present value of the tariff.
Weighting : In order to determine the wholesale price of petroleum products to OMCs, the cost for each option has been categorised into ‘Non-Road’ assets (Pipeline and Refinery) and ‘Road’ assets (where all products are imported via Road from Dar es Salaam). Based on the volume throughput of each asset, a weighting is determined, which is then applied when determining the total cost of petroleum products.
888.2.28.2.2 ASSUMPTIONS
Timing
• Model Start Date – 2014 • Projection Period – 17 Years
Macroeconomic Assumptions
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Currency and exchange rates
All monetary values are stated in US dollar terms unless otherwise stated. Reference to Zambia Kwacha has been made at a translation into US dollar at [USD = ZMW 5.46]. (http://www.oanda.com/currency/converter/ , January 2014) .
Inflation
The model is represented in real terms, however reference has been made to US dollar inflation assumed to be 2.22% per annum over the Projection Period.
Accounting Assumptions
The model has been constructed to give financial reporting consistent with International Financial Reporting Standards as displayed in terms of income statement, cash flow statement and balance sheet.
Price, Volume, Capital and Operating Costs
The model is based on the price, volumes, capital and operating costs as defined early in this Report and determined as a result of the technical review, i.e. review of Zambia’s existing oil infrastructure and the demand analysis.
Financing Assumptions
For each asset we have assumed a set of financing assumptions, based on the prevailing Development Finance Institution (DFI) funding terms that have been seen on infrastructure type finance raising projects within the region.
Given the variations in capex and asset treatment for each of the facilities across the various scenarios, we present in Table 31 the financing assumptions for the pipeline company and the refinery company.
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TABLE 31: FINANCING ASSUMPTIONS
Pipeline Company Debt Option 1a Option 1b Option 2 Option 3 Option 4 Gearing (Debt : Equity) 70% 70% 70% 70% 70% Senior Loan 100% 100% 100% 100% 100% Senior Loan (Proportion total funding) 70% 70% 70% 70% 70% Tenor 18 Yr(s) 18 Yr(s) 18 Yr(s) 18 Yr(s) 3 Yr(s) Base Rate (6 month Libor) 0.32% 0.32% 0.32% 0.32% 0.32% Arrangement fee 0.50% 0.50% 0.50% 0.50% 0.50% Commitment fee 0.75% 0.75% 0.75% 0.75% 0.75% Interest Margin 5.00% 5.00% 5.00% 5.00% 5.00% All in Interest Rate 5.32% 5.32% 5.32% 5.32% 5.32% Term: From 2014 2014 2014 2014 2014 Tenor 18 Yr(s) 18 Yr(s) 18 Yr(s) 18 Yr(s) 3 Yr(s) Grace Period End 2017 2017 2017 2017 2015 Grace Period Equal to: 2 Yr(s) 2 Yr(s) 2 Yr(s) 2 Yr(s) 0 Yr(s) End 2032 2032 2032 2032 2017
Equity Proportion of Equity 30% 30% 30% 30% 30% Drawing Method Prorate Prorate Prorate Prorate Prorate Equity Injection Share Capital 100% 100% 100% 100% 100%
Refinery Company Debt Option 1a Option 1b Option 2 Option 3 Option 4 Gearing (Debt: Equity) 70% 70% 70% 70% 70% Senior Loan 100% 100% 100% 100% 100% Senior Loan (Proportion total funding) 70% 70% 70% 70% 70% Tenor 18 Yr(s) 18 Yr(s) 18 Yr(s) 3 Yr(s) 3 Yr(s) Base Rate (6 month Libor) 0.32% 0.32% 0.32% 0.32% 0.32% Arrangement fee 0.50% 0.50% 0.50% 0.50% 0.50% Commitment fee 0.75% 0.75% 0.75% 0.75% 0.75% Interest Margin 5.00% 5.00% 6.00% 5.00% 5.00% All in Interest Rate 5.32% 5.32% 6.32% 5.32% 5.32% Term: From 2016 2016 2019 2014 2014 Tenor 18 Yr(s) 18 Yr(s) 18 Yr(s) 3 Yr(s) 3 Yr(s) Grace Period End 2018 2018 2020 2015 2015 Grace Period Equal to: 1 Yr(s) 1 Yr(s) 0 Yr(s) 0 Yr(s) 0 Yr(s) End 2034 2034 2037 2017 2017
Equity Proportion of Equity 30% 30% 30% 30% 30% Drawing Method Prorate Prorate Upfront Prorate Prorate Equity Injection Share Capital 100% 100% 100% 100% 100%
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Other Assumptions
1. Taxes • Corporate tax = 35% • Tax losses = Carry forward for 5 years
2. Working Capital
For the purposes of this exercise, we have not assumed any working capital in each of the asset companies as they have been modelled as ‘projects’ without considering the existing liabilities on each entities balance sheet.
3. Depreciation
The prevailing depreciation rates that have been reported in the audited financial statements for Tazama Pipeline and Indeni Refinery have been applied during the projection period.
TABLE 32: DEPRECIATION RATES
Tazama Pipeline Straightline Leasehold land and buildings % 2.50% Pipeline and tank farm % 5.00% Plant and machinery % 10.00% Office furniture % 10.00% Motor vehicles, office equipment and residential furniture % 25.00% Loose Tools % 33.33%
Indeni Refinery Straightline Buildings % 1.00% Plant and machinery % 9.09% Motor vehicles % 25.00% Furniture and fittings % 10.00%
888.2.38.2.3 CALCULATIONS
In this section, we discuss three key calculations that will build up to the total cost for each asset i.e. revenue requirement, tariff and road transport fee.
1. Revenue Requirement
The Pipeline Fee and Refinery Fee are determined based on a ‘cost reflective’ tariff. As such, we have calculated each asset’s revenue stream based on three components:
a. Revenue component to meet third party costs
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We have apportioned revenue streams to cover the following costs during the 17 year projection period: - Debt Repayment - Interest and Finance Costs - Operating Costs
b. Revenue required tax component Taxes are a major cost component to both the Pipeline Company and the Refinery Company. While we have calculated a corporate tax liability to be paid annually, we have also considered tax losses that may be incurred during the projection period. The revenue tax component essentially provisions for corporate taxes to be paid in a particular period. We have therefore applied a ‘Gross-Up’ method, where by the taxes are calculated on costs that vary in direct proportion to changes in revenue i.e. third party costs and equity revenue received.
c. Equity Revenue Factor As per the funding structure adopted for each option, we have ensured a 15% return to each asset, to be fully recovered after consideration of the cash inflows (equity investment) and cash outflows (debt obligations, capital and operating costs, and taxes).
2. Tariff
The tariff is therefore calculated to determine a levelised tariff as defined under the key financial metrics.
Essentially, a $/tonne value is determined based on the total revenue requirement and volumes for each asset under the various options for the 17 year projection period. The present value based on the 15% rate of return is then calculated for the stream of values for the projection period to obtain a levelised tariff in 2014 terms.
3. Road Transport Fee
For the road transport aspect of each of the options, we have determined a road transport fee that is calculated based on the anticipated volumes throughput via road, and the estimated road transport fee as shown the Table 33.
TABLE 33: ESTIMATED ROAD TRANSPORT FEE
$/t Petrol 216 Low Sulph ur Gasoil 197 Gasoil 197 Jet 191 Kerosene 191 HFO 215 LPG 238
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888.2.48.2.4 OUTPUTS Drawing from the assumptions and calculations in the Financial Model, we constructed financial statements in accordance with International Financial Reporting Standards in the form of a Profit and Loss Statement, Balance Sheet and Cash Flow Statement for the 17 year projection period.
Given the distinguished treatment of each asset, we have also prepared separate financial statements for the Refinery Company and the Pipeline Company for each option.
The macro designed to assist with the ‘revenue required tax component’ is dependent on the profit and loss statement in each option.
888.2.58.2.5 PRICE When calculating the total cost of each option in order to assess the most viable option to the Government, we adopted the existing ‘Cost-Plus Pricing Method’ that is currently used by the Energy Regulatory Board in Zambia. We present in Table 34 the current price for wholesale petroleum products to Oil Marketing Companies (OMCs), which has been mirrored during this stage of the financial modelling exercise for the projection period.
TABLE 34: CURRENT PRICE FOR WHOLESALE PETROLEUM PRODUCTS TO OMC’S
Pricing Units Price Assumptions
CIF Spiked Crude Oil Price $/t ( a ) 947.26
Wharfage $/t ( b ) 11.84 = 1.25% * ( a ) Finance charges $/t ( c ) 48.36 = (5.00% + 1.00 ) * (a) Insurance (Dar-Ndola) $/t ( d 2.32 = 0.23% * (( a ) + (b) + (c)) Taz Storage + Pumping Fee $/t ( e ) 50.52
Pipeline Losses $/t ( f ) 15.60 = 1.45% * (( a ) + ( b ) + ( c ) + ( d ) + ( e )) Tazama Agency Fee $/t ( g ) 5.00
Refinery Fee $/t ( h ) 56.10
= 9.00% * (( a ) + ( b ) + ( c ) + ( d ) + ( e ) + ( f ) + Refinery Fuel + Losses $/t ( i ) 112.45 ( g ) + ( h )) = 1.00% * (( a ) + ( b ) + ( c ) + ( d ) + ( e ) + ( f ) + Terminal Losses $/t ( j ) 13 ( g ) + ( h ) + ( i )) Diesel Truck
Petrol Truck
Wholesale to OMC $/t 1,262
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Given that our analysis looks at Non-Road and Road costs for each of the options, we have determined a ‘weighting’ dependent on the volumes throughput via roads, and alternatively via the Pipeline and Refinery (referred to collectively as ‘Non-Road’ volumes).
We further demonstrate the price build-up for each option over the 17 year projection period, after which we determine the price today based on a weighted average formula which we will explore in more detail per option. These are shown for each of the Scenarios 1A-4 in the remainder of this section.
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TABLE 35: SCENARIO 1A – PRICE BUILD-UP
All figures are $ per tonne. Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Operating Period 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Volumes
Non Road 53% 48% 56% 55% 52% 50% 49% 47% 56% 64% 61% 59% 57% 54% 52% 50% 48% 46% Road 47% 52% 44% 45% 48% 50% 51% 53% 44% 36% 39% 41% 43% 46% 48% 50% 52% 54%
Price today
Petroleum Feedstock 873 876 873 871 868 868 868 869 870 871 872 873 874 875 875 876 876 877 Wharfage 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Finance Charges 45 45 45 45 44 44 44 44 45 45 45 45 45 45 45 45 45 45 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Fee 114 57 58 64 88 91 90 89 54 39 33 29 24 21 18 15 13 11 Pipeline Storage Fee 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Losses 6 15 15 15 15 15 15 15 ------Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Refinery Fee 62 56 49 45 43 39 34 29 25 21 18 16 14 12 10 9 8 7 Refinery Fuel + Losses 88 93 92 92 94 94 93 93 88 87 86 85 85 85 84 84 84 83 Total Non-Road Cost 1,208 1,161 1,151 1,152 1,172 1,171 1,165 1,160 1,101 1,082 1,074 1,067 1,062 1,057 1,052 1,049 1,046 1,043
Petroleum Feedstock 896 899 893 889 887 890 892 894 892 889 892 895 898 900 902 903 905 906 Wharfage 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Finance Charges 46 46 46 45 45 45 46 46 46 45 46 46 46 46 46 46 46 46 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Road Transport Fee 199 200 199 199 199 199 199 199 199 198 198 198 198 199 199 199 199 199 Road Maintenance * 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 Total Road Cost 1,203 1,213 1,206 1,202 1,199 1,202 1,205 1,208 1,204 1,200 1,204 1,208 1,211 1,213 1,215 1,217 1,219 1,220
Total Cost 1,208 706 844 841 840 842 843 845 1,084 1,320 1,325 1,328 1,332 1,334 1,337 1,339 1,340 1,342
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*Note: An annual road maintenance fee of USD 50 per tonne has been factored in to account for any additional costs the Government would incur, in maintaining and repairing the roads as a result of transporting petroleum products via roads.
We explain in more detail in Table 36 how the total weighted cost has been determined to better understand the methodology adopted in determining a price in today’s terms:
TABLE 36: SCENARIO 1A – TOTAL WEIGHTED COST
Assumption Unit Price Comments Petroleum Weighted Average calculation of projected petroleum feedstock by the annual Non- a. $/t 873 Feedstock Road volumes portion. Weighted Average calculation of projected Wharfage charge by the annual Non-Road b. Wharfage = 1.25% * (a.) $/t 11 volumes portion. Weighted Average calculation of projected Finance charges by the annual Non-Road c. Finance Charges = 5.00% * (a.) $/t 45 volumes portion. Insurance (Dar- Weighted Average calculation of projected Insurance by the annual Non-Road d. = 0.23% * ((a.)+(b.)+(c.)) $/t 2 Ndola) volumes portion. e. Pipeline Fee $/t 114 Levelised Tariff
Pipeline Storage f. $/t 2 Based on Cost Plus Model Fee Weighted Average calculation of projected pipeline losses by the annual Non-Road g. Pipeline Losses = 1.45% * ((a.)+(b.)+(c.)+(d.)+(e.)) $/t 6 volumes portion. h. Tazama Agency Fee $/t 5 Based on Cost Plus Model i. Refinery Fee $/t 62 Levelised Tariff
Refinery Fuel + = 8.00% * Weighted Average calculation of projected refinery fuel and losses by the annual Non- j. $/t 88 Losses ((a.)+(b.)+(c.)+(d.)+(e.)+(f.)+(g.)+(h.)) Road volumes portion. Total Non-Road ( i ) 1,208 Cost
Petroleum Weighted Average calculation of projected petroleum feedstock by the annual Road k. $/t 896 Feedstock volumes portion. CHANNOIL CONSULTING LTD 83 | Page
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Weighted Average calculation of projected Wharfage charge by the annual Road l. Wharfage = 1.25% * (j.) $/t 11 volumes portion. Weighted Average calculation of projected Finance charges by the annual Road m. Finance Charges = 5.00% * (j.) $/t 46 volumes portion. Insurance (Dar- Weighted Average calculation of projected Insurance by the annual Road volumes n. = 0.23% * ((j.)+(k.)+(l.)) $/t 2 Ndola) portion. o. Tazama Agency Fee $/t 5 Based on Cost Plus Model Weighted Average calculation of projected Road Transport Fee by the annual Road p. Road Transport Fee $/t 199 volumes portion. Weighted Average calculation of projected Road Maintenance by the annual Road q. Road Maintenance $/t 50 volumes portion. Total Road Cost ( ii ) 1,208
Total Weighted $/t 1,208 = 53%* ( i ) + 47% * ( ii ) Cost
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TABLE 37: SCENARIO 1B – PRICE BUILD-UP
All figures are $ per tonne. Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Operating Period 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Volumes Non-Road 59% 48% 56% 55% 65% 74% 72% 69% 66% 64% 61% 59% 57% 54% 52% 50% 48% 46% Road 41% 52% 44% 45% 35% 26% 28% 31% 34% 36% 39% 41% 43% 46% 48% 50% 52% 54%
Price today Petroleum Feedstock 872 876 873 871 868 868 868 869 870 871 872 873 874 875 875 876 876 877 Wharfage 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Finance Charges 45 45 45 45 44 44 44 44 45 45 45 45 45 45 45 45 45 45 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Fee 98 57 60 68 85 67 58 50 43 37 31 27 23 20 17 14 12 11 Pipeline Storage Fee 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Losses 2 15 15 15 ------Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Refinery Fee 61 56 49 45 41 37 32 28 24 21 18 16 14 12 10 9 8 7 Refinery Fuel + Losses 88 93 92 92 92 90 89 88 87 86 86 85 85 84 84 84 84 83 Total Non-Road Cost 1,186 1,161 1,153 1,155 1,151 1,127 1,112 1,099 1,089 1,080 1,072 1,066 1,060 1,055 1,051 1,048 1,045 1,043
Petroleum Feedstock 894 899 893 889 879 874 876 881 885 889 892 895 898 900 902 903 905 906 Wharfage 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Finance Charges 46 46 46 45 45 45 45 45 45 45 46 46 46 46 46 46 46 46 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Tazama Agency 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Road Transport Fee 198 200 199 199 198 196 196 197 197 198 198 198 198 199 199 199 199 199 Road Maintenance * 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 Total Road Cost 1,206 1,213 1,206 1,202 1,190 1,183 1,185 1,191 1,196 1,200 1,204 1,208 1,211 1,213 1,215 1,217 1,219 1,220
Total Cost 1,194 1,386 1,342 1,353 415 312 336 371 403 436 467 497 525 553 579 605 630 654
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*Note: An annual road maintenance fee of USD 50 per tonne has been factored in to account for any additional costs the Government would incur, in maintaining and repairing the roads as a result of transporting petroleum products via roads.
We explain in more detail in Table 38 how the total weighted cost has been determined to better understand the methodology adopted in determining a price in today’s terms:
TABLE 38: SCENARIO 1B – TOTAL WEIGHTED COST
Assumption Unit Price Comments Weighted Average calculation of projected petroleum feedstock by the a. Petroleum Feedstock $/t 872 annual Non-Road volumes portion. Weighted Average calculation of projected Wharfage charge by the annual b. Wharfage = 1.25% * (a.) $/t 11 Non-Road volumes portion. Weighted Average calculation of projected Finance charges by the annual c. Finance Charges = 5.00% * (a.) $/t 45 Non-Road volumes portion. Weighted Average calculation of projected Insurance by the annual Non-Road d. Insurance (Dar-Ndola) = 0.23% * ((a.)+(b.)+(c.)) $/t 2 volumes portion. e. Pipeline Fee $/t 98 Levelised Tariff f. Pipeline Storage Fee $/t 2 Based on Cost Plus Model Weighted Average calculation of projected pipeline losses by the annual Non- g. Pipeline Losses = 1.45% * ((a.)+(b.)+(c.)+(d.)+(e.)) $/t 2 Road volumes portion. h. Tazama Agency Fee $/t 5 Based on Cost Plus Model i. Refinery Fee $/t 61 Levelised Tariff
= 8.00% * Weighted Average calculation of projected refinery fuel and losses by the j. Refinery Fuel + Losses $/t 88 ((a.)+(b.)+(c.)+(d.)+(e.)+(f.)+(g.)+(h.)) annual Non-Road volumes portion. Total Non-Road Cost ( i ) 1,186
Weighted Average calculation of projected petroleum feedstock by the k. Petroleum Feedstock $/t 894 annual Road volumes portion. l. Wharfage = 1.25% * (j.) $/t 11 Weighted Average calculation of projected Wharfage charge by the annual
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Road volumes portion. Weighted Average calculation of projected Finance charges by the annual m. Finance Charges = 5.00% * (j.) $/t 46 Road volumes portion. Weighted Average calculation of projected Insurance by the annual Road n. Insurance (Dar-Ndola) = 0.23% * ((j.)+(k.)+(l.)) $/t 2 volumes portion. o. Tazama Agency Fee $/t 5 Based on Cost Plus Model Weighted Average calculation of projected Road Transport Fee by the annual p. Road Transport Fee $/t 198 Road volumes portion. Weighted Average calculation of projected Road Maintenance by the annual q. Road Maintenance 50 Road volumes portion. Total Road Cost ( ii ) 1,206
Total Weighted Cost $/t 1,194 = 59%* ( i ) + 41% * ( ii )
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TABLE 39: SCENARIO 2 – PRICE BUILD-UP
All figures are $ per tonne. Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Operating Period 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Volumes
Non-Road 80% 48% 56% 55% 65% 74% 72% 69% 66% 64% 100% 100% 100% 100% 100% 100% 100% 100% Road 20% 52% 44% 45% 35% 26% 28% 31% 34% 36% 0% 0% 0% 0% 0% 0% 0% 0%
Price today
Petroleum Feedstock 832 876 873 871 868 868 868 869 870 871 804 804 804 804 804 804 804 804 Wharfage 10 11 11 11 11 11 11 11 11 11 10 10 10 10 10 10 10 10 Finance Charges 43 45 45 45 44 44 44 44 45 45 41 41 41 41 41 41 41 41 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Fee 89 57 60 68 85 67 58 50 43 37 18 16 13 12 10 9 7 6 Pipeline Storage Fee 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Losses 2 14.55 14.56 14.64 ------Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Refinery Fee 111 58 51 47 48 40 44 70 88 102 45 39 33 29 25 21 18 17 Refinery Fuel + Losses 55 93 92 93 93 90 90 92 93 93 29 28 28 28 28 28 28 27 Export Disposal 19 1 3 3 5 8 7 7 7 7 47 42 37 32 27 21 16 10 Total Non-Road Cost 1,169 1,164 1,158 1,160 1,163 1,138 1,131 1,152 1,165 1,175 1,003 989 977 965 954 943 933 925
Petroleum Feedstock 886 899 893 889 879 874 876 881 885 889 ------Wharfage 11 11 11 11 11 11 11 11 11 11 ------Finance Charges 45 46 46 45 45 45 45 45 45 45 ------Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 ------Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 ------Road Transport Fee 198 200 199 199 198 196 196 197 197 198 ------Road Maintenance * 50 50 50 50 50 50 50 50 50 50
Total Road Cost 1,198 1,213 1,206 1,202 1,190 1,183 1,185 1,191 1,196 1,200 ------
Total Cost 1,175 1,189 1,179 1,179 1,172 1,150 1,147 1,164 1,175 1,184 1,003 989 977 965 954 943 933 925
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*Note: An annual road maintenance fee of USD 50 per tonne has been factored in to account for any additional costs the government would incur, in maintaining and repairing the roads as a result of transporting petroleum products via roads links.
We explain in more detail in Table 40 how the total weighted cost has been determined to better understand the methodology adopted in determining a price in today’s terms:
TABLE 40: SCENARIO 2 – TOTAL WEIGHTED COST
Assumption Units Price Comments Weighted Average calculation of projected petroleum feedstock by the annual a. Petroleum Feedstock $/t 832 Non-Road volumes portion. Weighted Average calculation of projected Wharfage charge by the annual Non- b. Wharfage = 1.25% * (a.) $/t 10 Road volumes portion. Weighted Average calculation of projected Finance charges by the annual Non- c. Finance Charges = 5.00% * (a.) $/t 43 Road volumes portion. Weighted Average calculation of projected Insurance by the annual Non-Road d. Insurance (Dar-Ndola) = 0.23% * ((a.)+(b.)+(c.)) $/t 2 volumes portion. e. Pipeline Fee $/t 89 Levelised Tariff f. Pipeline Storage Fee $/t 2 Based on Cost Plus Model = 0.00% * ((a.)+(b.)+(c.)+(d.)+(e.)) Weighted Average calculation of projected pipeline losses by the annual Non-Road g. Pipeline Losses (1.45% before new pipeline is $/t 2 volumes portion. commissioned) h. Tazama Agency Fee $/t 5 Based on Cost Plus Model i. Refinery Fee $/t 111 Leve5lised Tariff
= 3.00% * ((a.)+(b.)+(c.)+(d.)+(e.)+(f.)+(g.)+(h.)) Weighted Average calculation of projected refinery fuel and losses by the annual j. Refinery Fuel + Losses $/t 55 (8.00% before new refinery is Non-Road volumes portion. commissioned) Weighted Average calculation of projected cost of disposal for excess products by k. Export Disposal $/t 19 the annual Non-Road volume portion Total Non-Road Cost ( i ) 1,169
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Weighted Average calculation of projected petroleum feedstock by the annual l. Petroleum Feedstock $/t 886 Road volumes portion. Weighted Average calculation of projected Wharfage charge by the annual Road m. Wharfage = 1.25% * (k.) $/t 11 volumes portion. Weighted Average calculation of projected Finance charges by the annual Road n. Finance Charges = 5.00% * (k.) $/t 45 volumes portion. Weighted Average calculation of projected Insurance by the annual Road volumes o. Insurance (Dar-Ndola) = 0.23% * ((k.)+(l.)+(m.)) $/t 2 portion. p. Tazama Agency Fee $/t 5 Based on Cost Plus Model Weighted Average calculation of projected Road Transport Fee by the annual Road q. Road Transport Fee $/t 198 volumes portion. Weighted Average calculation of projected Road Maintenance by the annual Road r. Road Maintenance $/t 50 volumes portion. Total Road Cost ( ii ) 1,198
Total Weighted Cost $/t 1,175 = 80%* ( i ) + 20% * ( ii )
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TABLE 41: SCENARIO 3 – PRICE BUILD-UP
All figures are $ per tonne. Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Operating Period 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Volumes
Non Road 82% 45% 50% 49% 90% 90% 90% 88% 85% 91% 91% 89% 86% 92% 90% 87% 92% 91% Road 18% 55% 50% 51% 10% 10% 10% 12% 15% 9% 9% 11% 14% 8% 10% 13% 8% 9%
Price today
Petroleum Feedstock 904 876 873 871 899 900 902 903 905 906 908 909 911 911 912 913 914 914 Wharfage 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Finance Charges 46 45 45 45 46 46 46 46 46 46 46 46 47 47 47 47 47 47 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Fee 89 57 61 69 69 65 56 48 41 30 26 22 19 15 13 11 8 7 Pipeline Storage Fee 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Pipeline Losses 2 15 15 15 ------Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Refinery Fee 6 58 56 49 ------Refinery Fuel + Losses 10 93 93 93 ------Total Non-Road Cost 1,076 1,163 1,162 1,161 1,034 1,031 1,024 1,017 1,012 1,004 1,001 999 997 993 992 991 990 989
Petroleum Feedstock 853 899 895 892 771 775 778 797 817 791 796 815 833 806 818 838 817 831 Wharfage 11 11 11 11 10 10 10 10 10 10 10 10 10 10 10 10 10 10 Finance Charges 44 46 46 46 40 40 40 41 42 41 41 42 43 41 42 43 42 43 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Road Transport Fee 200 200 199 199 201 201 201 200 199 200 200 199 199 200 199 198 199 199 Road Maintenance* 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 Total Road Cost 1,164 1,214 1,209 1,205 1,078 1,082 1,086 1,104 1,125 1,099 1,103 1,123 1,142 1,114 1,126 1,147 1,126 1,139
Total Cost 1,092 151 120 116 970 967 960 954 950 1,129 1,126 1,123 1,122 1,304 1,302 1,301 1,484 1,484
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*Note: An annual road maintenance fee of USD 50 per tonne has been factored in to account for any additional costs the government would incur, in maintaining and repairing the roads as a result of transporting petroleum products via roads links.
We explain in more detail in Table 42 how the total weighted cost has been determined to better understand the methodology adopted in determining a price in today’s terms:
TABLE 42: SCENARIO 3 – TOTAL WEIGHTED COST
Assumption Unit Price Comments Weighted Average calculation of projected petroleum feedstock by the annual a. Petroleum Feedstock $/t 904 Non-Road volumes portion. Weighted Average calculation of projected Wharfage charge by the annual Non- b. Wharfage = 1.25% * (a.) $/t 11 Road volumes portion. Weighted Average calculation of projected Finance charges by the annual Non- c. Finance Charges = 5.00% * (a.) $/t 46 Road volumes portion. Weighted Average calculation of projected Insurance by the annual Non-Road d. Insurance (Dar-Ndola) = 0.23% * ((a.)+(b.)+(c.)) $/t 2 volumes portion. e. Pipeline Fee $/t 89 Levelised Tariff f. Pipeline Storage Fee $/t 5 Based on Cost Plus Model = 0.00% * ((a.)+(b.)+(c.)+(d.)+(e.)) Weighted Average calculation of projected pipeline losses by the annual Non- g. Pipeline Losses (1.45% before products pipeline is $/t 2 Road volumes portion. commissioned) h. Tazama Agency Fee $/t 5 Based on Cost Plus Model
Weighted Average calculation of projected $/t tariff by the annual Non-Road volumes portion.
Note: the refinery fee for this scenario has been treated differently as there exists ‘Non-Road’ assets for 17 years i.e. the products pipeline. As such, the i. Refinery Fee $/t 6 refinery is averaged over the 17 year period, hence a lower value.
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= 8.00% * Weighted Average calculation of projected refinery fuel and losses by the annual j. Refinery Fuel + Losses $/t 10 ((a.)+(b.)+(c.)+(d.)+(e.)+(f.)+(g.)+(h.)) Non-Road volumes portion. Total Non-Road Cost ( i ) 1,076
Weighted Average calculation of projected petroleum feedstock by the annual k. Petroleum Feedstock $/t 853 Road volumes portion. Weighted Average calculation of projected Wharfage charge by the annual Road l. Wharfage = 1.25% * (j.) $/t 11 volumes portion. Weighted Average calculation of projected Finance charges by the annual Road m. Finance Charges = 5.00% * (j.) $/t 44 volumes portion. Weighted Average calculation of projected Insurance by the annual Road n. Insurance (Dar-Ndola) = 0.23% * ((j.)+(k.)+(l.)) $/t 2 volumes portion. o. Tazama Agency Fee $/t 5 Based on Cost Plus Model Weighted Average calculation of projected Road Transport Fee by the annual p. Road Transport Fee $/t 200 Road volumes portion. Weighted Average calculation of projected Road Maintenance by the annual q. Road Maintenance $/t 50 Road volumes portion. Total Road Cost ( ii ) 1,164
Total Weighted Cost $/t 1,092 = 82%* ( i ) + 18% * ( ii )
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TABLE 43: SCENARIO 4 – PRICE BUILD-UP
All figures are $ per tonne. Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Operating Period 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Volumes
Non-Road 8% 45% 50% 49% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Road 92% 55% 50% 51% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Price today
Petroleum Feedstock 873 876 873 871 ------Wharfage 11 11 11 11 ------Finance Charges 45 45 45 45 ------Insurance (Dar-Ndola) 2 2 2 2 ------Pipeline Fee 54 52 48 42 ------Pipeline Storage Fee 2 2 2 2 Pipeline Losses 14 14 14 14 ------Tazama Agency Fee 5 5 5 5
Refinery Fee 62 58 56 49 ------Refinery Fuel + Losses 92 93 92 90 ------Total Non-Road Cost 1,159 1,157 1,147 1,131 ------
Petroleum Feedstock 896 899 895 892 884 886 888 890 892 894 896 898 900 901 902 903 904 905 Wharfage 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11 Finance Charges 46 46 46 46 45 45 45 45 46 46 46 46 46 46 46 46 46 46 Insurance (Dar-Ndola) 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Tazama Agency Fee 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 Road Transport Fee 201 200 199 199 201 201 201 201 201 201 201 201 201 201 201 201 201 201 Road Maintenance* 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 Total Road Cost 1,211 1,214 1,209 1,205 1,198 1,201 1,203 1,205 1,207 1,209 1,211 1,213 1,215 1,216 1,218 1,219 1,220 1,221
Total Cost 1,207 1,188 1,178 1,168 1,198 1,201 1,203 1,205 1,207 1,209 1,211 1,213 1,215 1,216 1,218 1,219 1,220 1,221
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*Note: An annual road maintenance fee of USD 50 per tonne has been factored in to account for any additional costs the government would incur, in maintaining and repairing the roads as a result of transporting petroleum products via roads links.
We explain in more detail in Table 44 how the total weighted cost has been determined to better understand the methodology adopted in determining a price in today’s terms:
TABLE 44: SCENARIO 4 – TOTAL WEIGHTED COST
Assumption Unit Price Comments Petroleum Weighted Average calculation of projected petroleum feedstock by the annual Non-Road a. $/t 873 Feedstock volumes portion. Weighted Average calculation of projected Wharfage charge by the annual Non-Road b. Wharfage = 1.25% * (a.) $/t 11 volumes portion. Weighted Average calculation of projected Finance charges by the annual Non-Road c. Finance Charges = 5.00% * (a.) $/t 45 volumes portion. Insurance (Dar- Weighted Average calculation of projected Insurance by the annual Non-Road volumes d. = 0.23% * ((a.)+(b.)+(c.)) $/t 2 Ndola) portion. e. Pipeline Fee $/t 54 Levelised Tariff
Pipeline Storage f. $/t 2 Based on Cost Plus Model Fee Weighted Average calculation of projected pipeline losses by the annual Non-Road volumes g. Pipeline Losses = 1.45% * ((a.)+(b.)+(c.)+(d.)+(e.)) $/t 14 portion. h. Tazama Agency Fee $/t 5 Based on Cost Plus Model i. Refinery Fee $/t 62 Levelised Tariff
= 8.00% * Refinery Fuel + Weighted Average calculation of projected refinery fuel and losses by the annual Non-Road j. ((a.)+(b.)+(c.)+(d.)+(e.)+(f.)+(g.)+(h $/t 92 Losses volumes portion. .)) Total Non-Road ( i ) 1,159 Cost
Petroleum Weighted Average calculation of projected petroleum feedstock by the annual Road k. $/t 896 Feedstock volumes portion.
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Weighted Average calculation of projected Wharfage charge by the annual Road volumes l. Wharfage = 1.25% * (j.) $/t 11 portion. Weighted Average calculation of projected Finance charges by the annual Road volumes m. Finance Charges = 5.00% * (j.) $/t 46 portion. Insurance (Dar- n. = 0.23% * ((j.)+(k.)+(l.)) $/t 2 Weighted Average calculation of projected Insurance by the annual Road volumes portion. Ndola) o. Tazama Agency Fee $/t 5 Based on Cost Plus Model Weighted Average calculation of projected Road Transport Fee by the annual Road volumes p. Road Transport Fee $/t 201 portion. Weighted Average calculation of projected Road Maintenance by the annual Road volumes q. Road Maintenance $/t 50 portion. Total Road Cost ( ii ) 1,211
Total Weighted 1,207 = 8%* ( i ) + 92% * ( ii ) Cost
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9. RESULTS SUMMARY
999.19.1 MODEL OUTPUTS SUMMARY
TABLE 45: MODEL OUTPUTS SUMMARY
Upgrade Upgrade New refinery Close refinery All road from Refinery Refinery from 2023 in 2017 2017 by 2017 by 2017 New crude New crude New crude Close refinery New product $/tonne oil pipeline oil pipeline oil pipeline & pipeline pipeline 2017 2021 2017 2017 2017 2014-2030 2014-2030 2014-2030 2014-2030 2014 to 2017
Option 1a 1b 2 3 4 Petroleum Feedstock 873 872 832 904 873 Wharfage 11 11 10 11 11 Finance Charges 45 45 43 46 45 Insurance (Dar-Ndola) 2 2 2 2 2 Pipeline Fee 114 98 89 89 54 Pipeline Storage Fee 2 2 2 2 2 Pipeline Losses 6 2 2 2 14 Tazama Agency Fee 5 5 5 5 5 Refinery Fee 62 61 111 6 62 Refinery Fuel + Losses 88 88 55 10 92 Exports Disposal 19 Total Non-Road Cost 1,208 1,186 1,169 1,076 1,159
Petroleum Feedstock 896 894 886 853 896 Wharfage 11 11 11 11 11 Finance Charges 46 46 45 44 46 Insurance (Dar-Ndola) 2 2 2 2 2 Tazama Agency Fee 5 5 5 5 5 Road Transport Fee 199 198 198 200 201 Road Maintenance 50 50 50 50 50 Total Road Cost 1,209 1,206 1,198 1,164 1,211
Average Weight: Pipeline/Refinery 53% 59% 80% 82% 8% Average Weight: Road 47% 41% 20% 18% 92%
Total Weighted Cost 1,208 1,194 1,175 1,092 1,207
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TABLE 46: MODEL OUTPUTS SUMMARY – COST BENEFIT ANALYSIS
Upgrade Upgrade New refinery Close refinery in All road from Refinery Refinery from 2023 2017 2017 by 2017 by 2017 New crude New crude New crude New product Close refinery & $/tonne oil pipeline 2021 oil pipeline 2017 oil pipeline 2017 pipeline 2017 pipeline 2017
2014-2030 2014-2030 2014-2030 2014-2030 2014 to 2017
Option 1a 1b 2 3 4
Total Cost 1,208 1,194 1,175 1,092 1,207 Rank 5 3 2 1 4
Differential ($/t) 116 102 83 - 115 Total incremental cost 3,114 2,737 2,210 - 3,067 2014 – 2030 ($m)
The options considered have clearly indicated that installing a product pipeline (Scenario 3) is the most economically efficient solution. Indicated savings relative to the other options are between $2.2 /ZMK 13.7 billion and $3.1/ZMK 19.3 billion over the period 2014-2030. This approximates to a range of 0.5% to 0.7% of Total Annualised GDP.
Of the refinery options, the new, larger refinery (Scenario 2) is marginally more attractive than the upgrading options (Scenarios 1a and 1b) under the base case of 30% equity and 70% gearing. We have conservatively assumed a premium of $50/tonne for road maintenance and repair. The road option, even without this provision for secondary costs, is significantly more expensive than the pipeline option.
The sensitivities have been run to test that the base results are robust under the different scenarios and confirm that the product pipeline is still the most cost effective option.
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999.29.2 SENSITIVITES
In order to stress test the model we carried out a sensitivity analysis by varying different input components.
As important as it is to test the flexibility and transparency of a model, it is critical to carry out this analysis as it allows us to determine the impact on the actual outcome of the various options, by assessing possible variations in key input assumptions.
This type of testing will determine how volatile each option is to different probabilities and offer a more concrete assessment of the most viable and cost efficient option.
We carried out the following sensitivities and compared them to the base results as presented above: 1. Equity – Increase equity contribution from 30% to 100%
2. Equity – Increase equity contribution from 30% to 40%
3. Capital costs – Increase capital costs by 20%
4. Capital costs – Reduce capital costs by 20%
5. Rate of Return – Increase rate of return from 15% to 20%
6. Rate of Return – Reduce rate of return from 15% to 10%
TABLE 47: MODEL OUTPUTS – SENSITIVITY ANALYSIS
Upgrade refinery Upgrade refinery Close refinery in by 2017 by 2017 New refinery 2017 All road from New pipeline by New pipeline by from 2023 Product pipeline 2017 2021 2017 from 2017
$/tonne Scenario 1a Scenario 1b Scenario 2 Scenario 3 Scenario 4
Base Case: 1,208 1,194 1,175 1,092 1,207 30 % Equity & 15% RoR
100% Equity & 15% RoR 1,228 1,213 1,257 1,109 1,207
40% Equity 1,211 1,197 1,186 1,094 +20% Capex 1,217 1,204 1,197 1,104 -20% Capex 1,200 1,184 1,152 1,080
20% RoR 1,209 1,197 1,189 1,096
10% RoR 1,207 1,192 1,161 1,087
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Note: The sensitivities identified above will not have a significant impact on Scenario 4, as these variations largely relate to the Non-Road assets. We have therefore omitted the results for this option as they are deemed not comparable to the other options for the purpose of this exercise.
Based on the results of the sensitivity analysis, Scenario 3 remains the most economically efficient option in all sensitivities above.
The ranking of the options remains consistent in the sensitivities except for the 100% Equity case where the new refinery option, given its large Capital expenditure, is significantly more expensive by $148/tonne ($3.9 billion) than Scenario 3.
999.9...3333 RESULTS SUMMARY
The product pipeline option provides the country with the most cost effective solution. It also provides the country with more flexibility as future unforeseen changes in demand can be more easily accommodated by acquiring a different mix and/or volume of products, whereas this would require expensive capital investments with any of the refinery options.
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10. STRATEGIC ISSUES
There are a number of strategic issues that the country needs to be considered in conjunction with the output of the scenarios and options considered above.
Security of supply
As discussed in Section 4, security of supply is critical and non-oil producing landlocked countries will require more product stock in country to cover the risk of a serious supply disruption whether by road, rail or pipeline. This can be complemented by additional product stocks held outside the country, currently Zambia has ownership to 231,000m3 of storage in Dar es Salaam. Our recommendation is have 40 days product stock in country and a further 20 days available overall.
Another key consideration is physical security of the pipeline, particularly if a new product pipeline (Scenario 3) is implemented. The security risk increases as product is resaleable / usable, unlike the contents of the current crude pipeline.
In evaluating this issue some of the factors that will need to be considered include:
• Product pipelines are successfully operating in East Africa, in Kenya from Mombasa to Eldoret via Nairobi and other locations as well as Beira to Harare pipeline between Mozambique and Zimbabwe. There are proposals for the Kenyan pipeline to be extended into Uganda and Rwanda. • The product pipeline includes a $25 million provision for the SCADA system which remotely monitors the entire product pipeline electronically, providing real time information on potential leaks/sabotage. • The incremental operational cost of security versus the crude pipeline will need to be evaluated in the detailed feasibility study. Increased surveillance to mitigate theft, damage, and sabotage can be cost effectively introduced using airborne drone cameras. Such drones have an effective flight recording distance of 100km and can produce extremely good high definition satellite imagery of the entire pipeline system.
Rail
Rail transport for petroleum products globally, although more expensive than pipeline, is considered a cheaper alternative to road. The major terminals in Ndola and Lusaka have rail sidings set up for rail transport of petroleum product but these are not currently used. Sub Saharan Africa (excluding South Africa), Zambia and its neighbours have a rail infrastructure which needs major upgrading and investment, policy review and a framework to restore the competitiveness of rail networks (summarised from the SSATP Africa Transport Policy Program Working Paper No 94 March 2013). This is definitely an alternative to road transport and could complement the product pipeline and therefore should be considered as a medium term incremental development option. As discussed later, the recently completed Benguela railway line to the DRC border opens additional rail options. CHANNOIL CONSULTING LTD 101 | P a g e
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The current transport focus appears to be on the key Link Zambia 8000 project to improve the road infrastructure.
Access to investment capital and Commercial Structuring
The ability to access investment capital and optimise the commercial structuring of the capital is critical to the long term success of the investment Zambian supply infrastructure.
Some key issues to consider:
• Ownership of the assets; Would Tazama Pipelines shareholding remain the same in the new pipeline or would there be external shareholders? • Risk profile; The appetite of potential investors will depend on the level of perceived risk in the project type and the security of future income flows. For example, there will be a different risk profile for refinery investment versus pipeline investments.
Regulatory framework
The current regulatory structure is a cost plus system as opposed to an import parity pricing system. Current product and crude supply are based on one to two year tenders and are based on the CIF plus financing cost to Dar es Salaam or Lusaka/Ndola for products.
Consideration should be given to revising the system where:
• Pricing including transport, insurance and freight are tendered more frequently. In Tanzania and Kenya the import of product is tendered on a monthly basis based on forecast demand as provided by the respective OMC’s. This has resulted in keen competition between the major international traders and product CIF prices have dropped over the period. • Prices are changed on a monthly basis to incorporate product price and currency changes on a transparent basis. This also prevents the GRZ from having to subsidise prices.
Pipeline route expansion and/or alternative routes
Consideration was given to alternate routes for product pipelines, by either: • Extending the Beira to Harare pipeline to Lusaka; or, • Developing a new pipeline from Lobito via Lubumbashi to Ndola, given the planned Refinery at Lobito.
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These are both medium to long term options that can be considered, however it is not likely to take place within the current timeframe for a number of reasons: • The most complicated factor in a new pipeline is negotiating with the land owners the ‘right of way’ and getting planning permission and agreement from all the respective landowners along the route. In our experience this can take many years. • Both of these options are cross border and would need time and effort to negotiate the terms with the respective state entities. • The new Lobito refinery has not yet been built although the feasibility studies have been completed and the EPC’s are being tendered. It will take a number of years before completion. Forecasts vary from 2015 to 2017. o The planned refinery appears, according to reports, to be a phased development starting at 120,000 bpd and then ramping up to 200,000 bpd 2 years later. Angola 2013 demand per EIA is 133,000 bpd, which at a growth rate of 5% will increase to 238,000 bpd by 2025. This indicates that a large portion of the refinery production will be absorbed locally. o The current routing of the recently rebuilt Benguela rail line is from Lobito to Luau on the eastern border of DRC which is intended to connect to the mines around Lubumbashi and then link up with Zambian rail. This line has been designed to be used to export the copper to Lobito. o In the future a pipeline could be considered along this route to import product but it would be a complete greenfield project potentially across two country borders with all the contractual negotiations and infrastructural requirements this would entail. • The country needs a new pipeline now given the state of the existing pipeline and the infrastructure; right of way and bilateral agreements are in place on the existing route. • Storage tanks and pipeline connections to the SBM are in place, as are the pumping stations.
However, once the new railway line has been extended both to Lubumbashi and to the Zambian copper belt, the use of rail tank cars to import product can be considered as a supplement and back up for pipeline product imports from the East particularly for the Copperbelt product requirements.
Consideration can be given to extending the pipeline, in particular from Ndola to Lusaka and potentially to Kitwe and Solwezi. These potential extensions can form part of a detailed feasibility study on the pipeline replacement. The issues raised on the right of way above would also need to be considered when considering the time scale although these extensions could be completed later.
Human resource and environmental implications
In the final evaluation of the options, if the refinery is closed the human resource issues relating to redeployment, retrenchment and/or re-training of the workforce would need to be carefully considered and planned.
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Overall, we would expect employment in Zambia to be positively impacted by these changes to the petroleum sector, as the whole economy would benefit.
Similarly, the environmental impact of any closures of refinery or pipeline would need to be reviewed and agreed.
Export of product
The main opportunity available for exports is to the Southern DRC in the Copper belt area around Lubumbashi, which is currently fed by road haul primarily via Dar es Salaam and Beira. The best estimates we have of this volume is 30,000 tonne/mth of LSGO, which provides a major upside for a new product pipeline in the initial period and after 2023 for both the new refinery and the new product pipeline options.
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11. CONCLUSIONS
In summary, following a comprehensive review of Zambia’s current oil supply chain and supply demand balance, a forecast of the future demand and supply outlook and pricing outlook, the options have been modelled and evaluated using a robust commercial and financial model, we have the following conclusions:
• The strategic product stockholding in-country should be increased to 40 days with an overall stockholding of 60 days, which should provide security of oil product supply in a land-locked country without oil reserves. • The demand outlook even on the lower base case shows an increase in demand to 2.2 million tonnes p.a. by 2030, doubling current demand. • The current pipeline needs replacement and cannot meet the current demand levels nor future needs. • New pipeline technology has reduced costs and implementation time. • The current refinery, even with upgrading, remains a costly spiked crude option and will not meet future demand as it will be limited to close to its nameplate capacity of 1.1 million tonnes. • A new refinery from 2023 is capital intensive an estimated $1.2 billion and is a significantly more expensive option than a new product pipeline, remembering that a new crude pipeline would still need to be constructed. • The results from the cost benefit analysis from the defined scenarios clearly show that Scenario 3, the replacement of the crude pipeline with a new 12” product pipeline and the mothballing of the existing refinery, is the most economically advantageous option with a forecast saving of between $2.2 billion and $3.1 billion over the forecast period. It also provides flexibility in the supply of products in years of varying demand and product mix.
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12. RECOMMENDATIONS
The key recommendations are:
Imported product including transport, insurance and freight should tendered more frequently and prices should be changed on a monthly basis in line with the tender period.
Increase the strategic product stockholding in-country to 40 days with an overall stockholding of 60 days to provide security of supply in a land-locked country without oil reserves.
Replace the crude pipeline with a new 12” product pipeline and mothball the existing refinery as soon as practically possible.
The key stakeholders need to consider whether any strategic issues may dictate that an alternative option be adopted or investigated further.
It is vitally important that, assuming the recommendations are accepted, a detailed implementation plan is prepared to ensure that this multi-disciplinary project is successfully driven to ensure that fuel is supplied efficiently and at the most economic cost to the country for the foreseeable future to 2030 and beyond.
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13. NEXT STEPS
Decisions are required on recommendations from the Inception Report, which include:
• Optimisation of the internal storage efficiencies in the country. This includes a combination of pump overs from the existing strategic storage to the large OMC terminals, direct deliveries of product imports to OMC’s and double shifting. Discussions need to be held between all key stakeholders to prioritise and implement. • A clean up of Balance Sheets is required, in particular in respect of long term debt (GRZ) in Tazama Pipelines and Petroleum Products, in order to present bankable solutions for new financing. • Similarly, lease and management fees need to be reviewed in Tazama Petroleum Products Energy policy and pricing. • Tanzanian government must be approached to discuss plans and their proposed role in the new product pipeline. • Regarding energy policy and pricing, review of: safeguards in procurement processes; market player role in infrastructure investments and product procurements; and, continuation of the 25% premium charged on direct product imports, especially for the mining industry.
Review of Final Report recommendations and consider whether any strategic issues merit further investigation.
Assuming the new product pipeline is adopted, there will be a need then for comprehensive implementation planning covering all aspects (i.e. technical, legal, financial, regulatory and commercial).
The detailed pipeline project would need to commence as soon as possible to avoid incremental costs, particularly given the existing level of pipeline corrosion.
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APPENDICES
APPENDIX 1: TERMS OF REFERENCE --- CHECKLIST
BACKGROUND The Ministry of Finance floated a tender for consultancy services for a Detailed Study on the Supply of Petroleum Products into Zambia. Several interested bidders responded to the tender out of which three bidders were short listed. The three bidders were requested to submit proposals and only two bidders submitted their proposals. Evaluations were carried out to select the final bidder who shall carry out the consultancy. The objectives of the study are to investigate options that will:
a. Ensure that the country’s supply system meets its petroleum requirements up to the year 2030. Done
b. Implement the best options for meeting the c ountry’s Done supply requirements.
c. Ensure that petroleum products are supplied efficiently and at the most economic cost to the country, taking Done into account the current strategic development objectives.
INDENI OIL REFINERY The Consultancy shall also carry out cost benefit analysis taking into account but not limited to the following options for the future of petroleum infrastructure in Zambia: 1. Carry on with the current status of the See Section 7.1 Refinery.
2. Improve the efficiency and operational reliability of the Scenario 1a & 1b current Refinery and revamp any idle units.
3. Improve the efficiency and operational reliability of the Scenario 1a & 1b current Refinery by modernising it (adding units that can improve the Refinery outputs). 4. Build a new Refinery to replace the current one . Scenario 2
5. Decommission the current refinery and convert the Scenario 3 pipeline to be able to transport finished products; or 6. Decommission both the refinery and the pipeline and Scenario 4 start using rail and road.
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In carrying out the cost benefit analysis the study should take into consideration the following scenarios:
a. The possibility of discovering crude oil in See Section 7.1 Zambia.
b. The possibility of supplying petroleum products to Considered in the Scenarios neighbouring countries. In considering this scenario, the study should highlight the potential market for petroleum products in the sub region and also take into consideration the impact of the construction of modern refineries in Angola, South Africa and Mozambique to be commissioned in the near future.
c. The possibility that Zambia does not discover crude oil. See Section 7.1
Under items 1 to 4 of Indeni Oil Refinery , where applicable the study should assess and recommend the appropriate technology that can be implemented at the refinery to perform the following:
a. Reduce the sulphur content of gasoil produced at the Scenario 1a & 1b refinery to at least 50 ppm within a three year period.
b. Sustainable production of unleaded petrol with a Scenario 1a & 1b minimum octane number of 93 within a three year period.
c. `Enable the refinery to process crude oils (both sweet Scenario 2 and sour) as a feedstock and not the current spiked crude (i.e. Installation of a cracker unit). This is in case the country discovers commercial reserves of crude oil.
d. To meet projected or forecast increase in demand of Scenario 2 petroleum products.
In carrying out the cost benefit analysis, the study will propose Done . a time frame and resource requirement for implementation of options mentioned under Indeni Oil Refinery as well as determine the economic and financial incentives that may be required to encourage long-term investment in the Petroleum Sector. The study shall also take into consideration the policy and legal processes required under each of the scenarios.
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TAZAMA PIPELINES The study will also: See Section 5.3 a. Propose rehabilitation and/or modernization works required to ensure sustainability of pipeline operations and capacity to meet to demand up to 2030.
b. Assess the feasibility of using electrical motors to drive Considered but retained the pumps as compared to gasoil/crude oil powered gasoil/crude oil powered engines currently being used. engines as electricity is not considered to be reliable enough particularly in the remote stations. c. Assess the feasibility of the construction of an additional See Section 9.1 pipeline linking in country distribution points such as Kapiri, Mposhi and Lusaka.
STORAGE FACILITIES
The study shall also: See Section 4
a. Determine the required storage capacity to ensure adequate supply of petroleum products to the country, including storage of strategic reserves. This should include an indication of where the additional storage capacity should be located.
b. Propose a tailored financing mechanism for achieving This will require a review once a the country’s optimum storage capacity. decision is made on who will invest in the incremental storage. PRI CING
In carrying out the TOR ’s the study should also demonstrate the See Section 8.1 impact of implementing the proposed options on the petroleum pump price in Zambia. OTHER ISSUES
The study shall also establish the amount of capacity building See Se ction 10 required for local staff to ensure sustainable operation of the petroleum sector.
In the Consultancy’s professional judgement, the study should See Section 12 make any other recommendations on issues not explicitly mentioned in the bid document but has the potential to improve the pricing, supply and delivery of petroleum products in Zambia.
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APPENDIX 2: PROCESS DESCRIPTIONS FOR THE NEW REFINERY
Process Descriptions
This section of the report provides typical high level process descriptions for process units that are located ISBL of the Refinery. The units described are a mixture of Licensor Technology and ‘open art’ technology. Licensor companies who provide the required process units have been provided for each unit.
Crude Distillation Unit (CDU)
The CDU separates crude oil into its main constituent fractions:
Light Gases SR Naphtha Kerosene Atmospheric Gasoil Atmospheric Residue
Crude is heated in a pre-heat exchanger train against product run downs, crude overhead and pump- around systems prior to entering the crude desalter. In the crude desalter the crude is washed with water (stripped water from SWS) to remove salts. This is required for overhead system corrosion protection.
Desalted crude is then further preheated in heat exchangers against other product and pump around streams and further heated in the crude heater. Crude from the heater then enters the atmospheric column from which the required fractions listed above are produced, as well as a bottoms product (atmospheric residue, AR).
Crude Distillation is normally considered ‘open art’ technology. Crude Units can be designed by competent engineering firms. (Technip, Bechtel, Fluor, Foster Wheeler are examples.)
Refinery Gas Plant (RGP Unit)
The gas plant receives light gases and wild naphtha (naphtha with LPG and light ends) from the CDU, as well as other light end streams from several refinery units, and separates these streams into:
Light Gases (mainly C1, C2) LPG (C3 and C4) for routing to LPG Merox Stabilized Naphtha (routed to NHT)
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The gas plant consists of an absorber/stripper system (separating C1-C2 overhead from C3+ bottoms) and naphtha stabilizer (separating stabilized naphtha from LPG). The sour light gas and LPG streams from the gas plant are treated with amine to remove H 2S. Treated light gases are routed to the fuel gas system while treated LPG is routed to the LPG Merox unit. Stabilized naphtha is routed to the Naphtha Hydrotreater (NHT). Compression of light gases that feed the gas plant is also included.
Just as the CDU, gas plant technology is considered “open art” so this plant can be designed by any competent engineering firm.
LPG Merox
The LPG produced in the gas plant is treated in the LPG Merox Unit to remove final traces of H 2S
(residual H 2S after amine treatment in the gas plant) and to remove mercaptans (R-SH).
The LPG Merox consists of a pre-contactor in which traces of H 2S are removed by contacting the LPG with circulating Caustic of low strength (liquid-liquid contacting).
Subsequently the LPG is counter currently contacted with high-strength caustic in a liquid-liquid extraction column; the mercaptans partition into the caustic phase. The caustic with mercaptans is sent to a regeneration system, in which air is contacted with the caustic in the presence of a catalyst.
Process conditions in LPG Merox units are mild, with operating temperatures close to ambient and pressures of 15-20 bar (sufficient to keep LPG in the liquid state at operating temperature)
Two Licensors offer equivalent LPG Merox Process Technology
UOP (“Merox”) Axens (“Sulfrex”)
Naphtha Block
Straight run naphtha from the CDU requires hydrotreatment to remove objectionable impurities from the naphtha. The main impurity to be removed is sulphur which is easily removed in a hydrotreating step operating at 300 – 350 °C and typically 20-40 bar using standard hydrotreating catalyst. Light and heavy Naphtha are produced from the Naphtha Hydrotreating Unit (NHT). a naphtha Splitter splitting the hydrotreated naphtha into a light and heavy Naphtha a light naphtha Isomerization unit a Continuous Catalytic Reforming Unit (CCR) processing the heavy naphtha to produce a marketable high octane grade of gasoline. These units use a catalytic process to rearrange low octane hydrocarbon molecules in the naphtha into high octane aromatic molecules.
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Naphtha Hydrotreating can be considered ‘licensed technology’ and various licensors offer technology for naphtha hydrotreating units:
UOP Axens Haldor Topsoe
Products from the CCR
Reformate – typical octane numbers will be 95 RON. The top-end boiling point will typically be 195°C for summer and 185°C for winter grade. There will be no measurable sulphur in the product. Higher octane grades can also be produced if required. Hydrogen/Fuel Gas – this is the by-product of the Reformer. The gas typically contains about 70% hydrogen and 30% hydrocarbons. Some of the gas will be used for heating requirements in the Reformer unit; the excess can be used for other process heating requirements.
The CCR can be considered ‘licensed technology’ and various licensors offer technology for Reformer units:
Axens UOP
The Isomerization unit can be considered ‘licensed technology’ and various licensors offer technology for Isomerisation Units
Axens CDTECH UOP
Kerosene Hydrotreater (KHT )
The kerosene hydrotreater is fed with kerosene from the crude distillation unit and produces low- sulphur kerosene (<10 ppm wt). This low sulphur content (lower than current jet fuel sulphur specifications) ensures that the kerosene product can be partially blended into EN590 gasoil but also that it would also fulfil more stringent future jet fuel sulphur specifications.
Kerosene is mixed with recycle and fresh make-up hydrogen and heated up against hot reactor feed and further heated in a fired heater prior to entering the reactor. Alternatively, the gas can be heated up separately from the feed. Typical operating conditions are 300-350 °C and 30-40 bar. The reactor contains proprietary desulphurization catalyst (CoMo or NiMo). The reactor product is cooled down by exchange against feed and further by air cooling. After separation of gas (which is recycled to the reactor) the kerosene is routed to a stripper for removal of light ends (which are routed to the gas plant). CHANNOIL CONSULTING LTD 113 | P a g e
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Licensors that can offer KHT technology include:
UOP Axens Haldor Topsoe Shell
Diesel Hydrotreater (DHT)
The diesel hydrotreater is fed with gasoil from the crude distillation unit (mixture of atmospheric gasoil and LVGO) and with LCGO from the delayed coking unit if applicable. The presence of LCGO in the feed (which, unlike straight-run gasoil contains some silicon and olefins) requires some silicon removal catalyst and typically increases the operating pressure requirement of the unit. Note that gasoil produced by the Hydrocracker does not require further treatment.
The gasoil hydrotreater produces low-sulphur gasoil (<10 ppm wt) complying with EN590 (European) specifications.
Typical operating conditions area 300-370 °C and 50-75 bar. The reactor contains proprietary desulphurization catalyst (usually NiMo, alternatively CoMo).The reactor product is cooled down by exchange against feed and further by air cooling. After separation of gas (which is recycled to the reactor, potentially after removal of H2S in a high-pressure recycle gas scrubber) the gasoil is routed to a stripper for removal of light ends (which are routed to the gas plant).
Licensors that can offer DHT technology include:
UOP Axens Haldor Topsoe Shell
Hyrdrocracker Unit (HCR)
The Hydrocracker is fed with MVGO and HVGO from the vacuum distillation unit as well as with Heavy Coker Gasoil (HCGO) from the delayed coker. It produces lighter distillates ranging from gasoil and kerosene to naphtha, LPG and light gases, as well as a small amount of ‘unconverted oil’ which is used as refinery fuel oil.
In order to meet the key refinery objective of middle distillate maximization, the Hydrocracker is designed for full conversion and maximum selectivity to middle distillates.
These requirements lead to a recycle design, where unconverted distillate (heavier than gasoil) is recycled to the reactor system. This recycle allows a low ‘per-pass’ conversion (which is conducive to high selectivity to middle distillates) while achieving high overall conversion. A small ‘bleed’ of CHANNOIL CONSULTING LTD 114 | P a g e
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unconverted oil is necessary to prevent operational problems caused by accumulation of Heavy Polynuclear Aromatics (HPNA) in the recycle loop.
Feed to the Hydrocracker is preheated against hot streams from the fractionation unit and further preheated against reactor effluent and in a fired reactor charge heater. Recycle and make-up hydrogen are also fed to the reactor system, either mixed with the oil feed or heated up separately. In the reactor system pre-treatment (for deep removal of H2S and NH3) takes place, followed by hydrocracking (converting heavy into light molecules). “Quenching” between consecutive catalyst beds is normally required for absorbing the considerable heat of reaction. Reactor effluent is cooled down against feed and, after water injection to prevent deposition of NH4HS, further cooled down by air cooling. The reactor products are separated into recycle gas (returned to reactor after optional amine scrubbing), flash gas (hydrogen rich gas routed to amine scrubbing and then to the Hydrocracker Off-Gas PSA or HCOG PSA for hydrogen recovery), sour water (routed to SWS) and hydrocarbons (routed to the fractionation section).
In the fractionation section the hydrocarbons from the reactor section are stripped to remove light ends (to gas plant), and then separated in the Hydrocracker main fractionator into naphtha (routed to NHT naphtha splitter, see above), kerosene, gasoil and unconverted oil (UCO). The UCO is largely recycled to the reactor section, with a small ‘bleed’ being removed from the system for use as fuel oil.
Typical operating conditions for full-conversion Hydrocracking are: reactor pressure 150-200 barg, temperature range of 375-400 °C.
The most prominent licensors for full-conversion Hydrocracking technology are:
UOP Chevron Lummus Global Axens Shell/Criterion
More recently, Haldor Topsoe has established itself as a licensor for Hydrocracking. It is felt that ExxonMobil’s Hydrocracking technology is more appropriate for partial conversion applications.
Delayed Coker Unit (DCU)
The Delayed Coker is fed with Vacuum Residue from Vacuum Distillation. This feed is thermally converted into a solid coke product and a range of liquid products. The heaviest of these, heavy coker gas oil (HCGO) is routed to the Hydrocracker for conversion into (predominantly) valuable middle distillates. The next lighter fraction, light coker gas oil (LCGO) is routed to the DHT for processing into saleable gasoil. Coker naphtha is routed to the NHT for processing into saleable naphtha. Finally the light ends are routed to the gas plant.
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Vacuum residue feed is heated up against coker main fractionator pump around streams and fed to the fractionator sump which acts as feed surge drum. Charge pumps pressurize the feed through the vacuum heater into the operating coke drum at approximately 500 °C. In the coke drum, the feed is thermally converted into coke (which remains in the drum) and lighter hydrocarbons, which exit the drum in the vapour phase. The coke drum vapours, at approximately 450 °C and 1-2 bar feed the main fractionator and are separated into HCGO, LGCO and overhead. The overhead product is separated into gas, LPG and coker naphtha.
When the coke drum is filled with coke, the feed is switched to the other coke drum which is empty at this stage. The full drum is then ‘decoked’. Decoking involves steam stripping (to remove residual hydrocarbons), quenching with water to cool down the coke mass (with vapourised water routed to the ‘blowdown system’ for condensation and re-use), unheading the drum (opening top and bottom flanges) and finally mechanical ‘coke-cutting’ with high-pressure (200-300 bar) water jets which cut the coke mass. The coke falls out of the bottom drum opening into the coke pit. After coke removal the empty drum is ‘reheaded’ (closing top and bottom flanges), purged with steam, pressure tested, and then reheated with a slipstream of overhead hydrocarbon vapour from the other drum (which is in operation). The slipstream condenses to form ‘coker condensate’ which is recycled to the main fractionator, while heating up the coke drum. Finally, feed can be routed to the now heated up drum.
Delayed coking is licensed by the following licensors:
Foster Wheeler ConocoPhillips CB&I
Hydrogen Plant
All hydrogen requirements for the refinery are met by dedicated steam-reforming based hydrogen plants, fed with imported natural gas. The hydrogen plants are – per common practice - designed to produce highly pure (99.9 %+) hydrogen, which minimizes the capital cost of Hydrocracker and DHT. To accommodate outages of natural gas, the hydrogen plant can be designed (without incurring major additional capital cost) to use light naphtha as feedstock.
The H2 plant inherently co-produces a considerable amount of HP steam for export to the refinery. In order to prevent a global excess steam situation, the H2 plant can be designed for minimum steam export (at minimum natural gas supply) of approximately 0.5 kg HP steam / Nm3 H2. This is achieved using maximum preheat of combustion air (to the reforming furnace burners) against hot flue gas – at the expense of steam generation from flue gas. Such a ‘low steam export’ design is commonly proposed by licensors and does not require new technology.
Natural gas feed is preheated and passed through a desulphurization system consisting of a hydroprocessing step (sulphided CoMo catalyst) to convert organic sulphur into H2S, followed by a sacrificial ZnO bed to remove H2S to very small levels by conversion to ZnS. The desulphurised gas is CHANNOIL CONSULTING LTD 116 | P a g e
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further heated and mixed with steam prior to entering an adiabatic ‘pre-reformer’ reactor. In this reactor, reforming reactions take place:
CnH2n+2 + n H2O CO + (n+2) H2
The pre-reformer is highly recommended when feeding heavier hydrocarbons such as light naphtha range material. It also makes low steam co-production easier to achieve. The pre-reformer effluent is further heated and routed to the main reformer tubes. The tubes are located in a fired heater which is fired with preheated combustion air, natural gas and ‘PSA tail gas’. The tube outlet temperature is typically in the 850-900° range, resulting in a high CH4 conversion to CO and H2. The outlet gas is cooled prior to undergoing ‘CO-shift’ in adiabatic catalytic reactors:
CO + H2O CO2 + H2
The CO-shift produces additional H2 from CO in the reformed gas. The shift outlet gas is cooled down to near ambient temperatures at which water (steam fed to the natural gas upstream the reformer, in excess of what is used in the above chemical reactions) is condensed out. This condensate is, after appropriate treatment, converted to steam for recycle into the process.
The resulting gas, a mixture of mainly H2 and CO2 with smaller amounts of CO and CH4 is fed to a Pressure Swing Adsorption Unit which separates the gas into pure H2 product (99.9%+) and ‘tail gas’ (all non-H2 components and approximately 10% of the incoming H20. The ‘tail gas’ is fired in the reforming furnace.
Process conditions in steam reforming based H2 plants are severe. The pressure is normally in the 25-35 bar range. Temperatures range from 850-950 ° (reformer tube outlet temperature) to 200-450 °C (CO-shift) to near ambient (PSA purification).
A number of licensors can offer H2 plant technology. Below the most prominent licensors are listed. Only one of the licensors bases the design on use of its own proprietary catalyst, with other licensors relying on third-party catalyst supply. Also, only one of the licensors offers its own PSA system; again the others rely on third-party PSA system supply.
Technip Uhde Haldor Topsoe (own catalyst) CB&I Howe-Baker Foster Wheeler Linde (own PSA system)
Sulphur Plant
A Sulphur Plant usually consists of two identical trains of 50% capacity (capacity based on the highest sulphur-yielding crude processed in the refinery) for reliability reasons.
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Each train consists of a ‘modified Claus’ type Sulphur Recovery Unit (SRU) that converts H2S into sulphur. The ‘tail gas’ exiting the SRU, which still contains some sulphur-bearing components, is further treated in the Tail Gas Treating Unit (TGTU) to minimize the sulphur content in the treated gas that is finally thermally oxidized prior to discharge. The hydrogenation-amine technology has been selected for tail gas treating, since this technology is considered ‘best available technology’ for this application. It can comfortably achieve 99.8%+ sulphur recovery efficiency.
The SRU is fed with amine acid gas from the amine regeneration units (see below) and with SWS gas from the Sour Water Strippers (see below). The amine acid gas consists primarily of H2S; the SWS gas contains roughly equimolar amounts of NH3, H2S and water vapour.
The two gases are fed to the SRU thermal reaction furnace together with combustion air; in the reaction furnace part of the H2S is burned to SO2 such that a 2:1 ratio of H2S to SO2 is established. At the prevailing temperature in the furnace of typically 1200-1500 °C, the NH3 contained in the SWS gas is decomposed to N2, H2 and H2O. Gas exiting the furnace is cooled down in a waste heat boiler, raising HP steam.
The process gas subsequently undergoes catalytic ‘Claus’ conversion, reacting H2S and SO2 in the stoichiometric 2:1 ratio to sulphur:
2 H2S + SO2 3/8 S8 + 2 H2O
Claus conversion occurs in (typically) two catalytic stages (operating at 200-300 °C) with intermediate cooling for sulphur condensation followed by re-heat. SRU tail gas enters the TGTU and is heated to about 230-300 °C prior to entering the hydrogenation reactor. Here, all remaining sulphur-bearing components in SRU tail gas (SO2, COS, CS2, sulphur vapour) are converted to H2S. After cooling (and condensation of water formed in the upstream SRU, which is routed to sour water stripping) the gas is treated with lean amine (MDEA solution) for H2S removal, and is then routed to a thermal oxidizer for destruction of traces of remaining H2S. The amine with removed H2S is sent to an amine regenerator (included in the TGTU) whose overhead H2S gas is recycled to the upstream SRU.
The entire process operates at low pressure, ranging from approximately 0.7-0.8 barg in the front end (furnace) of the SRU to atmospheric pressure in the thermal oxidizer downstream the TGTU.
Dissolved H2S in the sulphur produced in the SRU is removed to <10 ppmw H2S by an appropriate ‘degassing’ treatment. The degassed sulphur is then solidified into small pellets in the Sulphur Solidification Unit, essentially by cooling down the liquid sulphur in a controlled way. State of the art technologies achieve this by dropping liquid sulphur droplets on an internally water-cooled belt (e.g. Sandvik process), by spraying liquid sulphur onto solidified spheres in a rotating drum which is directly cooled with air (e.g. Enersul process), or by dropping liquid sulphur through water to form droplet-shaped solid sulphur pellets (e.g. Devco process).
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Sulphur recovery and tail gas treating technology is typically licensed by any of the following licensors:
Shell/Jacobs Fluor WorleyParsons Technip KTI Lurgi Siirtec Nigi
For sulphur solidification, the following vendors are the most prominent:
Sandvik Enersul Devco
Amine Regeneration Unit
Lean amine is used to remove H2S from process gases and LPG in the gas plant (in fuel gas and LGP absorbers), optionally in the DHT recycle gas scrubber, optionally in a Hydrocracker recycle gas scrubber and in the Hydrocracker Cold Low Pressure Separator vapour absorber (feed to Refinery Off-Gas PSA). The exact number of absorbers depends on the licensor designs of the various process units.
Rich amine from the various absorbers is collected and regenerated in the Amine Regeneration Unit. Rich amine is first flashed in a rich amine flash drum to remove dissolved gases and any liquid hydrocarbon entrainment. Subsequently the rich amine is heated up against hot lean amine and stripped in the amine regenerator. Internal stripping steam is generated by external reboiling using LP steam. The overhead vapour is cooled down to condense water with the remaining H2S gas being routed to the SRU. Lean amine is cooled down against rich amine, further cooled by air and/or water cooling and pumped to the various absorbers (users). A slipstream of lean amine is filtered (to remove particles) and treated in an active carbon bed for removal of dissolved impurities.
Two amine regeneration units are typically included of each 50% capacity, based on the highest sulphur Crude processed in the refinery. The amine used is MDEA at 45-50% wt concentration, since this amine is also used in the TGTU. Furthermore, MDEA can be used in high concentrations (minimizing circulation) and requires a relatively low amount of stripping steam, as compared to other amines such as MEA, DGA and DEA.
Amine regeneration is normally considered ‘open art’ technology. Amine units can be designed by competent engineering firms.
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Sour Water Stripping
Sour water, containing H2S and NH3, is produced in various refinery units and stripped of its H2S and NH3 contents in the sour water strippers.
Sour water produced in hydroprocessing units (HCR, DHT, smaller amounts from
NHT/KHT) is stripped in the ‘non-phenolic’ Sour Water Stripper. Part of the stripped water is recycled to the HCR for use as make-up wash water. This reduces the total water make-up requirement.
Sour water from the other units (Crude distillation, Coker, TGTU) is stripped in the ‘phenolic SWS’. This water, after stripping, is not suitable for recycle to hydroprocessing units, which is the reason for segregating it from the above ‘non-phenolic’ sour water. The stripped phenolic sour water is used as make-up to the Crude Desalter to reduce total water make-up requirements. Also, contacting with crude in the Crude Desalter re-extracts any phenols in the stripped water into the crude. The phenols are then removed by hydrotreating of the crude fractions. This minimizes the load of phenols on the Waste Water Treatment Plant.
The sour water stripping process resembles the amine regeneration process and is identical for phenolic and non-phenolic SWS.
Sour water is collected in a flash drum for removal of dissolved gases and any entrained liquid hydrocarbons. Sour water is then typically stored in a tank for approximately 24 hours to provide time for final liquid hydrocarbon removal, to even out fluctuations in composition of the incoming sour water, and to provide buffer against any SWS upsets.
Sour water is then heated against stripped water and fed to the stripper itself in which the H2S and NH3 contents are stripped out to 50/10 ppm wt NH3/H2S using reboiling with LP steam. The overhead stream is condensed to about 85 °C to remove most of the water content, without risking deposition of solid NH4HS. The remaining H2S/NH3 gas is then routed to the SRU. Stripped water from the stripper bottoms is cooled against sour water and then further cooled using air and/or water cooling. Stripped water is then routed to the various destinations (recycle, desalter, or waste water treatment plant).
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APPENDIX 333:3: GLOSSARY
BoP Balance of Payments
BoZ Bank of Zambia
Bpd Barrels per day bpsd Barrels per onstream day c. Circa
CAGR Compound Annual Growth
CCPC Consumer Protection Authority
DFI Development Finance Institution
EBITDA Earnings before Interest Tax Amortization and Depreciation
ERB Energy Regulation Board
FY Financial Year
GDP Gross Domestic Product
GRZ Government of the Republic of Zambia
Indeni Indeni Petroleum Refinery Company Limited
ISBL Inside Battery Limits
mb/d Million barrels/day
MT Metric Tonnes
mtpa Million tonnes per annum
NAPSA National Pension Scheme Authority
OECD Organisation of Economic Co-operation and Development (countries)
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OMC Oil Marketing Company
OSBL Outside Battery Limits
PAYE Pay As You Earn ppm parts per million
Tazama Tazama Pipelines Limited tpa tonnes per annum tpd tonnes per day tpsd tonnes per stream day tph tonnes per hour
TPPL Tazama Petroleum Products Limited
US$ United States Dollars wt weight
ZBSA Zambia Bureau of Standards Authority
ZMW Zambian Kwacha (rebased)
ZPPA Zambia Public Procurement Authority
ZRA Zambia Revenue Authority
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