feasibility report p 073620 003

East African Community (EAC)

Feasibility Study for a Natural Gas Pipeline from Dar es Salaam to Tanga (Tanzania) and Mombasa (Kenya)

Final Feasibility Report

June 2011


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Table of Contents

1 Executive summary 3

2 List of Abbreviations and Units 5

3 Introduction 8

3.1 Structure of the report 8

3.2 Background 8

3.3 Socio-economic context 9

3.4 Project objectives and focus 10

3.5 Least cost solution 10

4 Market analysis 13

4.1 Assumptions 13

4.2 Demand projections 13

5 Pipeline routing options 20

5.1 Objective 20

5.2 Proposed Routes 20

6 Conceptual design and cost estimates 22

6.1 Assumptions 22

6.2 Conceptual Design Basis 23

7 Environmental and social impact assessment 25

7.1 Assumptions 25

7.2 Environmental impacts 25

7.3 Socio-economic impacts 26

8 Financial analysis 28

8.1 Assumptions 28

8.2 Methodology 28

8.3 Revenue 29

8.4 Costs 30

8.5 Financial calculations 32

8.6 Financing plan 35


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9 Economic analysis 41

9.1 Assumptions 41

9.2 Methodology 41

9.3 Costs 41

9.4 Benefits 42

9.5 Economic calculation 45

10 Risk assessment 46

10.1 Sensitivity analysis 46

10.2 Risk analysis 47

11 Logical Framework 50

11.1 Logical framework assessment 50

11.2 Monitoring of project benefits 52

12 Conclusion 54

13 Recommendations 56

14 Appendices 58

14.1 Binder 2 58

14.2 Binder 3 58

14.3 Binder 4 58


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1 Executive summary

The East African Community has commissioned COWI to undertake a feasibil-

ity study of a pipeline to supply natural gas to Mombasa for power generation

and other industrial applications both in Mombasa and Tanga and along the

route. The feasibility study is prepared by COWI A/S in association with

COWI Tanzania Ltd and Runji & Partners, Kenya.

The study is based on information from existing studies supplemented by in-

formation received from stakeholders. It is an overall assumption for the study

that the gas infrastructure in Tanzania is upgraded to be able to deliver the re-

quired volumes of gas at Ubungo for the proposed pipeline.

The feasibility study comprises four on-shore routing options and one off-shore

option. The investment cost of the on-shore options are in the range of 515-630

million USD. Analyses are made for three market scenarios (low, medium and

high) and four options for requested return on the investment. The financial

calculations include four (4) scenarios with different discount factors (WACC)

to reflect different capital structures of the pipeline company.

The analysis shows that an expansion of the gas pipeline system along the coast

to reach Tanga and Mombasa is a feasible project both financialle and eco-

nomically even with a conservative low growth demand scenario. Sensitivity

analysis shows that the routing along the coast is robust to changes in market,

investment costs and required return on invested capital. The off-shore option is

very expensive and thus not feasible. A route in inland Tanzania to reach the

potential markets in Arusha and Moshi will require an increased investment of

more than 20% compared to the coastal routing.

The direct benefits from the project will be distributed as follows:

• Tanzanian government will benefit from royalties and other benefit

from the gas sale;

• The pipeline owner will benefit from the profit share of the transport

tariff;

• Power consumers and industries in Kenya and Tanzania will benefit

from cost reductions caused by improved efficiency and improved secu-

rity of supply;

• Climate will benefit from reduced emissions from power plants and in-

dustries.


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Figure 1 Overview Map, showing alternative routes.


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2 List of Abbreviations and Units

Abbreviations

AfDB African Development Bank

CC Combined Cycle

CCS Carbon Capture Storage

CIF Cost, Insurance and Freight

CNG Compressed Natural Gas

EAC East African Community

ENPV Economic Net Present Value

ERC Energy Regulatory Commission, Kenya

EWURA Energy and Water Utilities Regulatory Authority, Tanzania

EIRR Economic Internal Rate of Return

FIRR Financial Internal Rate of Return

FNPV Financial Net Present Value

GPTC Guide Gas Piping Technology Committee Guide for Gas Transmis-

sion and Distribution Piping Systems.

HFO Heavy Fuel Oil

KenGen Kenya Electricity Generating Company

KPC Kenya Pipeline Company

LCU Local currency

LIBOR London Inter Bank Offered Rate

LNG Liquefied Natural Gas


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LCPDP Least Cost Power Development Plan, Kenya

NBV Netback Value

NGCC Natural Gas Combined Cycle

NPV Net Present Value

Orca Orca Exploration Group Inc.

PAT PanAfrican Energy Tanzania

ROE Return on Equity

Songas Songas Limited

TANESCO Tanzania Electric Supply Company

TPDC Tanzania Petroleum Development Corporation

Volumes

Scf Standard Cubic Feet

Scfd Standard Cubic Feet per day

Mscf 10^3 Standard Cubic Feet

MMscf 10^6 Standard Cubic Feet

MMscfd 106 Standard Cubic Feet per day

Bcf 10^9 Standard Cubic Feet

Nm^3 Normal Cubic Metre

1 scf 0.0268 Nm^3

1 scf 0.028 Sm^3

Energy

kW 10^3 Watt

MW 106 Watt


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1 kJ 1.055 BTU = 10^3 Joule

1 MJ 10^6 Joule

1 kWh 3.6 MJ

1 scf 1,025 BTU

1 Nm^3 39.9 MJ

1 Sm^3 36.35 MJ


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3 Introduction

3.1 Structure of the report

The financial and economic analyses are based on estimates, projections and

assumptions presented in the appendices: market study, pipeline routing options

(survey report), conceptual design and cost estimates report, and reflects the

comments received from counterparts to the reports and comments received

from the Steering Committee at the EAC Phase 2 Workshop in Dar es Salaam

on 20 January 2011 and at the EAC Phase 3 Workshop in Arusha on 18 March

2011 and at EAC Stakeholdres Workshop in Mombasa on 10 May 2011.

The market study in appendix A is based on existing information available in

paper or electronic form as well as from interviews with the counterparts.

The pipeline routing options (survey report) in appendix B are made based on

road surveys in Tanzania and in Kenya.

The conceptual design and cost estimates in appendix C is based on the survey

report and the market study.

The ESIA Outline report in appendix D is based on existing information, route

surveys and preliminary field surveys.

The subject for the analysis is a potential pipeline that will transport gas from

Dar es Salaam through Tanga to Mombasa. A gas pipeline is a natural monop-

oly with a transport tariff based on a cost recovery basis and regulated by a

regulatory authority. In the present case decisions must be made about the re-

sponsibility to regulate the transport tariff for a trans-border pipeline.

3.2 Background

The 3rd East African Community (EAC) Development Strategy 2006-2010

identified the need for a natural gas pipeline from Dar es Salaam to Tanga and

Mombasa. In March 2009, the EAC Sectoral Council on Energy approved the

terms of reference for the feasibility of the pipeline to supply natural gas to

Mombasa for power generation and other industrial applications both in Mom-

basa and Tanga and along the route. The 9th June 2010 the contract was signed

with COWI A/S (Denmark) in association with COWI Tanzania Ltd, and Runji

& Partners (Kenya). The study commenced on 5th July 2010.


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3.3 Socio-economic context

The Treaty for the Establishment of the EAC was signed in Arusha on 30 No-

vember 1999 and inaugurated in January 2001. In 2005 a customs union was

established, and in November 2009 the member states signed a common market

protocol to create a larger market and more attractive single investment area

with a view to provide the opportunity to the region to be more competitive and

more amenable to effective participation in the global economy1. A monetary

union is expected to be operational by 2012 and a free trade zone to be fully

operational by 2015.2 All countries have allowed duty-free regional trade and

all five countries have an identical tax applied to imports from outside the un-

ion.

The EAC comprises a combined market of 126 million people and a total GDP

of $73 billion. The East African countries are using over 50% of their foreign

currency revenues on importation of oil products. The Songo Songo gas fields

is now being developed and the pipelines and other infrastructure developments

have been built to secure commercial utilisation of the gas discoveries in Tan-

zania. The EAC Member States have agreed to promote the use of gas and

other natural resources so as to raise the standard of living and to improve the

quality of life of the people3.

The Tanzanian government will receive a considerable income in royalties and

other benefits over the lifetime of the project.

With its strategic location and well developed business infrastructure Mombasa

is the major trading centre in Kenya with East Africa's largest seaport. Indus-

tries in Mombasa include cement factories. Also tourist related industries, tex-

tile and engineering attract a labour force from the entire region. This makes

Mombasa an important growth centre of the EAC.

Crude oil prices are expected to increase in the longer term as a result of in-

creasing demand primarily in the transport sector combined with reduced sup-

ply globally. In addition the present situation in the Middle East shows that po-

litical instability results in increasing oil prices. The establishment of alterna-

tive energy sources becomes increasingly important to the African economies.

In the longer perspective renewable energy will replace fossil fuels but until

these technologies are competitive in the market natural gas is foreseen as a low

cost and low emission alternative to fuel oil in power generation and industrial

processing.

The Dar es Salaam-Tanga-Mombasa pipeline project is designed to facilitate a

supply of natural gas to Tanga and Mombasa from Tanzania (Songo Songo Is-

land). These gas fields and the Mnazi Bay gas fields in southern Tanzania com-

prise proven gas reserves that exceed the expected domestic demand.

1 EAC Development Strategy 2006-2010 2 http://www.eac.int/about-eac.html 3 Regional Integration in East Africa: Creating the framework for energy development and

trade in Africa. Parliamentarian Forum on Energy Legislation and Sustainable Develop-

ment, Cape Town, 5-7 October 2005


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3.4 Project objectives and focus

The key problem to be addressed is to secure the increasing demand for energy

in the EAC in general and specific the demand for energy in Tanga (Tanzania)

and Mombasa/Nairobi (Kenya). Kenya is strengthening its power transmission

network with the construction of a double circuit line between Nairobi and

Mombasa which will allow Nairobi to benefit from future power capacity ex-

pansion in Mombasa.

The feasibility study shall analyse the technical, environmental, financial and

economic feasibility of transporting gas from Dar es Salaam to Mombasa

through a pipeline. Based on the Terms of Reference for the assignment, the

main objective is summarised as:

Improving economic opportunities by providing a reliable and clean fuel for

power generation and industrial production in target areas.

The financial analysis will focus on the financial viability of an investment pro-

ject as a means to transport gas to Tanga and Mombasa and compete with alter-

native fuels in these markets. The economic analysis will focus on the benefits

for the society. These benefits are economic growth as a result of improved en-

ergy efficiency in the power sector and industry in Mombasa, reduced CO2

emission as result of replacement of diesel and coal by natural gas, and im-

proved security of supply in Mombasa. These benefits shall outweigh the in-

vestment cost in the transmission system and conversion to natural gas in

Tanga and Mombasa.

3.5 Least cost solution

So far natural gas has not been an option for power plant and industries in

Tanga and Mombasa. Transportation of natural gas from Dar es Salaam to

Mombasa will be a least cost solution when gas is the least cost fuel for the end

users and when the transport of energy as gas is a least cost option compared to

transportation as electricity.

3.5.1 End-user least cost solution

From an end-user point of view gas has to compete with the fuels presently

used by power plants and industries in the area.

Calculations of the price at which electricity is generated from a specific source

to break even (levelized energy costs) show that natural gas combined cycle

(NGCC) is a least cost solution depending on the cost of transporting the gas

from wellhead to the power plant.


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Table 1 Levelized energy costs

According to the International Energy Agency (IEA)4 there are several reasons

why natural gas combined cycle (NGCC) plants are now preferred over con-

ventional coal-fired plants:

Capital costs of NGCC plants amounts to USD 600-750 pr kW whereas in-

vestment in typical coal-fired plants costs USD 1,400-2,000 per kW;

NGCC plants have a relative short construction time;

NGCC plants emit less than half the CO2 emissions of similar rated coal-fired

plants.

An important barrier to introduction of high efficiency natural gas combustion

technology is that the price of natural gas per energy unit is generally higher

than the price of coal per energy unit.

3.5.2 Energy transport least cost solution

Natural gas from Tanzania could be transported to Tanga and Mombasa as

natural gas in pipe, as Liquefied Natural Gas (LNG) by ship or transformed into

electricity and transported by high voltage transmission lines.

More electricity generating facilities world wide is being fuelled by natural gas.

If an electricity generating facility is built far away from the location where it is

4 Energy Technology Perspectives 2008, IEA 2008


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needed a new transmission line must be built in order to transmit the electricity

to the location of consumption. A joint study by the Bonneville Power Admini-

stration and the North West Gas Association5 has analysed the cost efficiency

of transporting energy as gas in pipes or electricity in power lines. The study

concludes that natural gas pipelines are significantly less costly to build than

electric wires (50-60% of the cost of electric power transmission per unit of

energy delivered). Even though the annual cost to operate and maintain the

electric transmission line is nearly half the cost to operate and maintain the gas

pipeline, this however does not change the overall cost differences between the

two options.

The cost differences between a gas pipeline solution and a Compressed Natural

Gas (CNG) or LNG solution is analysed in several studies concluding that for

transport distances below 2,000 km the pipeline solution is economically more

advantageous.6

5 Comparing Pipes & Wires, Bonneville Power Administration and Northwest Gas Associa-

tion, 2004 6 The Growing Competition between Pipelines and LNG for Gas Markets, Houston 2000

and Comparative Economy of LNG and Pipelines in Gas Transmission, Osaka Gas Com-

pany, Japan 2004


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4 Market analysis

The market study in appendix A is made to determine the demand of gas in

Mombasa and Tanga. The market study is based on existing information and

gathered information.

4.1 Assumptions

The scope is the pipeline from Ubungo to Mombasa.

It is assumed that gas will be available at Ubungo for transport to Tanga and

Mombasa in 2015. It is further assumed that the gas sales price will be equiva-

lent to the present gas sales price of (average) $3.6 /Mscf in 2009 adjusted to

2015 prices. The gas sales price at Ubungo includes the transportation tariff

from Songo-Songo to Ubungo.

The industrial customers in Tanga and Mombasa will convert to gas in 2015 by

receiving a discount in the gas price to cover the conversion costs.

The power plants will convert to gas when the existing power plant retires and

a new one replaces the existing power plant and the improved efficiency is a

sufficient incentive for the power sector to convert to gas.

It is assumed that there will be a sufficient supply of gas to accommodate the

demand from Tanga and Mombasa. As pointed out in the market study (appen-

dix A) report there may be limitations on the reserves at Songo Songo, but it is

outside the scope of this study to investigate other sources of natural gas in

Tanzania.

It is further assumed that processing and transportation costs from Songo Songo

are reflected in the present transport tariff from Songo Songo to Ubungo.

The customers in Tanga and Mombasa will keep and maintain alternative fuels

storage in case of cut in the gas supply.

4.2 Demand projections

The demand projections are based on the present consumption in Mombasa and

Tanga.


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Peak demand in Kenya was around 1100 MW in 2009 and is expected to grow

with 10% per year until 20157. To meet projected demand new capacity of 400

MW geothermal, 475 MW of wind, 619 MW of coal, 360 MW of diesel and 60

MW of hydro will be established in Kenya up till 2015. In addition to domestic

generation imports from Ethiopia is expected. So far natural gas is not included

in the expansion plans. The Least Cost Power Development Plan (LCPDP)

states that "Preliminary analyses predict that use of coal and natural gas would

result in comparatively lower generation costs"8. The LCPDP mentions that

"natural gas is likely to be imported from Tanzania which has discovered sub-

stantial deposits".9

In Tanga a major cement factory will benefit from improved energy efficiency

in the increasing competition from imported cement and there are also plans of

a new power plant with a total of 100MW. Due to the timing of this informa-

tion the 100 MW are not included in the calculations.

Power sector

The Market Study in appendix A comprises all existing power plants located in

the Mombasa area as well as new power plant expected according to the Least

Cost Power Development Plan for Kenya.

Existing Plants.

Kipevu I: Consists of 6*12.5 MW heavy fuel oil (HFO) fuelled engines started

operation in 1999. Kipevu I is expected to retire in 2019 and then assumed re-

placed by a NGCC plant of same generating capacity with a load factor of 90%

and an efficiency of 50% equivalent to a consumption of 4.136 MMscf per year

based on a conversion factor of 3,497 Mscf/MWh.

Kipevu II: The contract for developing the Kipevu II project was awarded to

Wärtsilä Development & Financial Services, Inc. (WDFS) in 1997. The Kipevu

II project is owned by the special-purpose company Tsavo Power Company

Limited of Kenya, and the power plant is operated by Wärtsilä Operations as a

contractor for Tsavo Power Company LTD. Kipevu II is a HFO fuelled power

plant with a total installed electrical output of 74.5 MW and an electrical effi-

ciency of 42.5%. Kipevu II started operation in 2001 and is expected to retire in

2021 and assumed replaced by a NGCC plant of same generating capacity with

a load factor of 90% and an efficiency of 50% equivalent to a consumption of

4.080 MMscf per year based on a conversion factor of 3,497 Mscf/MWh.

Kipevu GT: A gas turbine (LNG) with unit I a 30 MW turbine started operation

in 1987 and was re-commissioned in 1997, and unit II a 30 MW turbine started

operation in 1999. It is assumed that Kipevu GT can be converted to NG from

2015 with a load factor of 90% and an efficiency of 50% equivalent to a con-

sumption of 3.308 MMscf per year based on a conversion factor of 3,497

Mscf/MWh.

7 Report of the 17th Meeting of the Energy Committee, EAC Secretariat, June 2010 8 Least Cost Power Development Plan, Study Period 2010-2030, Ministry of Energy, 31

March 2010, p.66 9 Ibid p. 67


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Rabai: The 90MW Rabai power plant is owned by Rabai Power Limited and

consist of five 17.5 MW 18V46 Wärtsilä 4-stroke medium speed diesel engines

each coupled to a generator. Rabai power plant started operation late 2009 and

it is assumed that it will be converted to NG from year 2015 with a load factor

of 90% and an efficiency of 50% equivalent to a consumption of 4.963 MMscf

per year based on a conversion factor of 3,497 Mscf/MWh.

New Plants

Kipevu III: KenGen is constructing Kipevu III as a 110-120 MW using HFO;

medium speed diesel engines which will initially operate on heavy fuel oil

(HFO) and which will be converted to dual fuel in the future which means that

there will be adequate space for future gas system. According to the technical

specifications10the gas system shall be considered complete with all necessary

plant, equipment, valves and pipe work to provide fuel to the engines with a

load factor of 90% and an efficiency of 50% equivalent to a consumption of

6.617 MMscf per year based on a conversion factor of 3,497 Mscf/MWh.

According to the Least Cost Power Development Plan for Kenya, a feasibility

study undertaken for installation of coal plants in Kenya recommended 2*300

MW. It is assumed that the expected 2* 300 MW will be constructed as natural

gas combined cycle in stead of coal fired generation. It is assumed that these

plants will commence in 2015 and 2017 with a load factor of 90% and an effi-

ciency of 50%.

Industry

Existing industries is expected to convert to natural gas assuming that the dis-

count on the gas price will cover conversion costs and include an incentive. It is

further assumed that the industries will be ready for natural gas consumption

from year 2015.

The industrial market is estimated in the Market Study (appendix A).

The incentive for coal fired industries to convert from coal to gas will depend on the age of their equipment and the environmental requirements regarding emissions from cement factories. In Dar es Salaam the Wazo Hill cement plant is a major gas consumer with a consumption in 2009 of around 500 MMscf or 25% of total industrial consumption. The average gas price for industrial con-sumers for 2009 is informed to be 8.36 USD/Mscf which indicates that the relevant replacement cost of coal is higher than the fuel replacement cost of around 3 USD/Mscf.

4.2.1 Demand scenarios

The financial calculations are made using 3 demand scenarios: low, medium

and high.

Low scenario

10 KenGen Kipevu III Power Project, Volume II Technical Specifications, 18 June 2009.


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In the low scenario it is assumed that existing power plants are replaced by

Natural Gas Combined Cycle (NGCC) plants when the existing plants retire.

New power plants like Kipevu III and the power plants serving the Nairobi

market will be established as NGCC plants. When the power plants are in op-

eration the demand will be constant, i.e. increases in national demand for elec-

tricity will be provided by plants using other sources than natural gas.

It is assumed that the industrial consumers are converting to natural gas when

the gas arrives in Tanga and Mombasa by 2015 against a negotiable discount in

the natural gas price compared to the price of the replaced fuel. In the low sce-

nario there is not expected any annual increases in gas demand from industry.

Table 2 Demand in Mombasa and Tanga, low growth.

MMscf 2015 2035

Power sector

31,430

56,188

Industry

9,817

9,817

Total

41,248

66,006

Medium scenario

The medium scenario is build up as the low scenario but the demand is ex-

pected to increase with 1% per year from 2010. This increase represents an in-

crease in the demand from the power sector and an increase in production by

existing industries and connection of new customers. An annual increase of 1%

is equivalent to an increase in the demand of 22% after a 20 year period be-

cause of the annual compounded growth rate.

Table 3 Demand in Mombasa and Tanga, medium (1%) growth.

MMscf 2015 2035

Power sector

33,364

72,778

Industry

10,421

12,716

Total

43,785

85,494

High scenario

The high scenario is build up as the low and medium scenario but the demand

is expected to increase with 2% per year from 2010. This increase represents an

increase in the demand from the power sector and an increase in production by

existing industries and connection of new customers. An annual increase of 2%

is equivalent to a 49% increase in 20 years due to the annual compounded

growth rate. The high scenario assumes that further power generation capacity

is established in Mombasa in accordance with the LCPDP.


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Table 4 Demand in Mombasa and Tanga, high growth (2%).

MMscf 2015 2035

Power sector

35,396

94,027

Industry

11,056

16,429

Total

46,451

110,455

The demand is composed by the power sector that account for 76-85% (year

2015 and 2035) of the total demand and industrial customers that accounts for

the residual; 24-15% of the total gas demand.

Figure 2 The demand in Tanga, the 3 demand scenarios, MMscf.

The market in Mombasa has a significantly larger potential demand of gas than

Tanga. The potential demand in Tanga amounts at 5-6 % of the demand in

Mombasa not including the proposed new power plant of around 100 MW.

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000 Tanga Market, MMscf

Tanga, 2 % growth Tanga, 1% growth Tanga, low growth


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Figure 3 The demand in Mombasa, the 3 demand scenarios, MMscf.

The demand scenarios are summarized in the table below divided into power

sector; existing consumers and future consumers, and industry; existing con-

sumers and future consumers.

Table 5 Demand in Tanga and Mombasa, 2015-2035

Bcf Low Medium (1%) High (2%)

Power sector

1,085

1,283

1,519

Existing consumers

285

339

404

Future consumers

801

944

1,115

Industry

206

242

285

Existing consumers

206

242

285

Future consumers

- - -

Total

1,291

1,525

1,805

The table below illustrates the split in the demand between Tanga and Mom-

basa in the period 2015-2035 for the three (3) scenarios. The Market in Tanga

account for less than 10% of the total demand from Tanga and Mombasa. The

market in Tanga is in this analysis only represented by the cement factory.

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Mombasa Market, MMscf

Mombasa, 2% growth Mombasa, 1% growth Mombasa, low growth


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Table 6 Demand split between Tanga and Mombasa 2015-2035.

Bcf Low Medium (1%) High (2%)

Tanga

77

90

106

Mombasa

1,215

1,435

1,699

Total

1,291

1,525

1,805


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5 Pipeline routing options

The pipeline routing options (survey report) in appendix B is made to analyse

various options for the routing see the map in section 1 Executive summary.

The pipeline routing options is based on map and road surveys in Tanzania and

in Kenya.

5.1 Objective

The primary objective is to locate different routes and evaluate on their suitability

based on right of way, geotechnical issues and general construction constraints.

5.2 Proposed Routes

The routes from Dar es Salaam to Mombasa have been verified by a road sur-

vey in car. The following rotes have been selected to be relevant as possible

routes. Reference is made to Appendix B for further explanation.

Route T1 follows the existing tarmac road from Dar es Salaam to Tanga and

from Tanga to Lunga Lunga at the Kenyan border it follows the gravel road

which is right now under construction to be tarmaced. The total length of route

T1 is 385 km. The geotechnical conditions are fine for a buried pipeline. The

main crossings are Ruvu, Wami and Pangani rivers.

Route T2 follows the coastal road from Dar es Salaam to Tanga, which is today

a gravel road. There is a feasibility study for upgrading the road to tarmac.

From Tanga route T2 follows the same route as for route T1 to Lunga Lunga at

the Kenyan border. The total length of route T2 is 298 km. The geotechnical

conditions are fine for a buried pipeline with the exception that for a length of

around 80 km at Saadani area the pipeline must be secured for buoyancy. Route

T2 needs to cross the same rivers as Route T1, but the rivers are wider and

heavier at the coast, therefore the crossings are more difficult (and costly) for

Route T2 than for Route T1. Especially crossing of Pangani river is a challenge.

Route K1 (from Lunga Lunga to Mombasa) follows the existing tarmac road

A14 Lunga Lunga-Mombasa road, up to a place near Ngomeni. It takes a right

turn to follow a power line way leave up to Mazeras. It continues to Vipingo

where by most parts it follows the power line way leave. The total length of

route K1 is 144 km. The geotechnical conditions are fine for a buried pipeline.

Route K2 follows a gravel road (C106 Lunga Lunga-Kinango-Mazeras) up to

Kinango. The pipe then passes through shrubs before connecting route no K1.


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The total length of route K2 is 124 km. The geotechnical conditions are fine for

a buried pipeline.

Route OS1 is the offshore route which has only been studied on maps. The total

length of Route OS1 is 360 km. The offshore solution still needs to pass the

congested areas of Dar es Salaam, Tanga and Mombasa and as it is not more

than 10% shorter than the onshore routes. Therefore Route OS1 should only be

chosen if the onshore routes have high costs on Right of Way or river crossings.

Maintenance of route OS1 can be very costly in case of any damages during

operation as well as during construction.

Route T3 is the railway route which has only been studied on maps. The total

length of route T3 is 430 km. The railway solution is very dependable on utiliz-

ing the rail track for transport of construction materials. The solution therefore

depends more or less on whether the normal rail traffic can be put on hold dur-

ing the construction period of 6-12 months.

In Tanzania there are two (2) main alternative routes. One along the Chalinze

road (T1) and one along the coastal road (T2). Further to this an option where

the route is following the existing rail road is described (T3).

In Kenya there are also two (2) main alternative routes. One along the tourist

and industrial area along the coast (K1) and one along the hilly, less populated,

inland road (K2).

In addition to these five (5) onshore routes an offshore route is described

(OS1).

At the survey the vegetation and soil conditions were noted and all possible ob-

stacles were observed. Especially rivers were noted and possible crossings of

these were considered.

After the survey the proposed routes have been marked on maps, where also the

main findings are marked. These maps/drawings and photos can be seen in Ap-

pendix B.

All 5 onshore routes have been found suitable for a buried pipeline, and the off-

shore route is considered suitable for an offshore gravity or dredged pipeline.

The routes are shown at the overview map, in section 1 Executive summary.


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6 Conceptual design and cost estimates

Five different pipeline routes have been proposed in this report and estimated

costs have been summarized.

1. Route no. 1 (Local market option in Tanzania and Kenya, T1+K1);

This route is going along the main road which makes it more accessible,

and there would be a possibility of providing gas for Arusha/Moshi and

Morogoro in the future. In Kenya the route follows the coast and will

serve hotels along the south beaches and any industries that may come

up along the coast.

2. Route no. 2 (Local market option Tanzania and least cost option Kenya,

T1+K2);

This route is going along the main road which makes it more accessible,

and there would be a possibility of providing gas for Arusha/Moshi and

Morogoro in the future. In Kenya the route avoids the high populated

coastal area.

3. Route no. 3 (Least cost option Tanzania and local market option Kenya,

T2+K1);

Basically, this route is going along the coast up to Tanga which makes

it shorter in comparison with the first routes. However, there are two (2

) wide rivers in between which adds the time and cost of construction.

In Kenya the route follows the coast and will serve hotels along the

south beaches and any industries that may come up along the coast.

4. Route no. 4 (Least cost option in Tanzania and Kenya, T2+K2);

Basically, this route is going along the coast up to Tanga which makes

it shorter in comparison with the first routes. However, there are two (2)

wide rivers in between which adds the time and cost of construction. In

Kenya the route avoids the high populated coastal area.

Route no. 5 (Offshore); this is an offshore route from Dar es Salaam to Mom-

basa with a small branch to Tanga.

6.1 Assumptions

The route T3 (Railway) has been excluded for further investigation due to the

fact that it is not possible to occupy the railway during the whole construction

period, and the fact that access roads for maintenance are not available, and are

to be constructed.


23

.

The overall time schedule has been based on the following assumptions:

The owner will be assisted by his consultant to prepare basic design for the gas

pipeline. In this phase a more accurate alignment of the preffered route is out-

lined, class locations are further detailed and crossings are also to be further

detailed. All to make a better basis for contractors to bid and prepare detailed

design. The duration is estimated to around 1 year in total.

The tendering for pipeline construction contract will be based on basic design.

The contractor will purchase all materials and construct and commission the

pipeline.

It is anticipated to have a gap after submitting of this feasibility study to estab-

lish the financing of the project. This allows for signing of consultancy agree-

ments for the basic design of the pipeline in 2012.

The capacity for the pipeline construction contractor should match approx. 800

m per day including crossings.

6.2 Conceptual Design Basis

Based on demand for gas the pipeline has been estimated to be a 24" line all the

way from Ubungo in Dar es Salaam to Vipingo in Mombasa. The pipeline is

coated and buried at 1 meter and is designed for a pressure of 100 bar. The web

thickness of the pipeline varies from 10 mm to 14.3mm depending on the class

location, which is decided based on the GPTC Guide. The design has been cho-

sen to suite a situation where the proposed production of electricity for Nairobi

is not changed to be produced on gas. However if the decision is made to have

the Nairobi electricity to be produced on gas, the pipeline can still be used, but

a compressor station needs to be constructed at Dar es Salaam.

T-sections are introduced to suite possible local markets (Morogoro, Arusha,

Zanzibar and Kenya Coast).

The pipeline sizing has been performed in accordance with API RP 14E "Off-

shore Production Platform Pipng Systems", Panhandle Equation.

As it is shown in the figure below a 24" pipeline is capable to cover the normal

consumption and minimum delivery pressure of 35 bar from 2015 until 2035.

As the 600MW power plant comes to plan the pipeline will still be able to fulfil

the high scenario usage by adding a compressor station at Dar es Salaam and

increase the inlet up to 94 bar.

A proposed construction program for Route no. 1 has been made, refer Appen-

dix C. For further details on the design parameters please also refer to Appen-

dix C.


24

.

Figure 4 Pipeline design.

Total cost estimates for 5 different route-alternatives and the compressor station

have been summarized in below table:

Table 7 Specifications of the routing options.

Route Length

(km)

Major

road

crossing

Rail

crossing

Major

river

crossing

Estimated Price

(Million USD)

[incl. Design, pro-

curement, supervi-

sion and compensa-

tion]

Route no. 1

(T1 & K1)

558 9 4 17 550

Route no. 2

(T1 & K2)

538 8 4 15 526

Route no. 3

(T2 & K1)

463 9 3 15 460

Route no. 4

(T2 & K2)

443 8 3 13 435

Route no. 5

(OS1)

360 558

Compressor

Station

80

For more detailed cost estimates please refer to Appendix C.


25

.

7 Environmental and social impact assessment

The purpose of the ESIA is to provide evidence for the Feasibility Study on

environmental and social impacts and opportunities of the routes included in

the study. Further, the ESIA will allow the environmental authorities to make

their decision on the scope and content of the full ESIA for the detailed design

stage, once a specific gas pipeline solution has been identified and agreed upon

in the EAC. The below information is based on the report Outline of Environ-

mental and Social Impact Assessment, Appendix D.

7.1 Assumptions

The following assumptions have been made as a basis for the ESIA study in the

Feasibility Study:

A full ESIA will be required when the project enters the detailed design stage

and will be registered with the environmental authorities in Kenya (NEMA)

and Tanzania (NEMC);

The full ESIA will include public consultations and consultations with key

stakeholders along the selected alignment;

Sacred forest plots (kayas) in Kenya can be avoided by the actual alignment;

Ecologically sensitive coastal forests along the coastal route in Kenya can be

avoided by the actual alignment.

7.2 Environmental impacts

The main environmental impacts of this project are expected to include the fol-

lowing:

1. Vegetation clearance within in the construction belt along the gas pipe-

line. The construction belt has a proposed width of 22 m. After con-

struction no restrictions will be limited and minor plantation is allowed

on top of the pipeline;

2. Disturbance (temporary) of fauna and livestock in and around the con-

struction belt, particularly in the immediate vicinity of the construction

works;


26

.

3. The coastal route alternative goes through a national park (Saadani Na-

tional Park). As other infrastructure like roads which have higher im-

pacts than a buried pipeline currently cross national parks, the construc-

tion of the gas pipeline is assessed as being insignificant in terms of en-

vironmental impacts. A refusal of permission from TANAPA is ther-

fore not foreseen;

4. Disturbance of littoral and benthic communities near or in rivers where

the pipeline will cross;

5. Air pollution from dust particles raised from construction activities;

6. Noise and vibrations as a result of construction activities;

7. Potential disturbance of other infrastructure that may be present in the

identified areas. However, it is not anticipated that there will be signifi-

cant disruption;

8. Pollution of the surrounding areas in the case of a leak, fire or explosion

of the pipe. This risk is considered to be extremely low;

9. Soil erosion risks in dry areas with loose soil (though can be mitigated

during construction).

7.3 Socio-economic impacts

The main potential socio-economic impacts (positive and negative) of this pro-

ject are expected to include the following:

Disturbance of current land use and agricultural activities during the construc-

tion of the pipe; Employment opportunities during construction as well as op-

eration phase of the project. In the long run during operations phase those who

have technical skills will benefit as well;

The project will supply alternative fuel source to industries and economic cen-

tres in the EAC;

Resettlement activities may be necessary but this will depend on the final de-

sign of the project. Resettlement can potentially be an issue along urban sec-

tions of the alignment, where the pipeline can not be located off plots with

houses etc. However, if resettlement would be necessary all procedures for

compensation will be applied accordingly;

The influx of people from other parts of the country and from outside Tanzania

who come for employment could potentially change the social dynamics of the

area. This may increase the risk of people being exposed to STD as well as

HIV/AIDS.

Overall the project will widen and deepen the economic, social and cultural in-tegration in the EAC and will improve the quality life of citizens in the EAC. Specifically during operation of the gas pipeline impacts may include the fol-lowing positive impacts:


27

.

1. The project will contribute to the Clean Development Mechanism as

defined in the Kyoto protocol11

2. Employment generation (formal and informal);

3. Increase revenue (trade and manufacturing);

4. Investment opportunities (trade and manufacturing);

5. Increase in land values.

Negative impacts include the following:

1. Permanent loss of (few) land plots and houses, when passing through

urban and semi-urban areas as a consequence of the suggested safety

zone of 50 m to each side of the gas pipeline;

2. Increased air pollution and green house gases and negative impacts on

climate change due to incremental increase of energy consumption;

3. Public health from work operations - occupational health and safety

(though expected to be insignificant);

4. Risk of accidents during operation (though considered extremely low).

11 Natural gas emits less carbon oxides, nitrogen oxides and particulates than coal when

combusted.


28

.

8 Financial analysis

The objective of the financial analysis is to see whether the project is feasible

or not. The financial analysis is based on the Market Study in appendix A, the

Survey report in appendix B, the Conceptual Design Report in appendix C and

the Outline of Environmental and Social Impact Assessment in appendix D.

8.1 Assumptions

It will be possible to find investors and debt financing to the project.

All values are in USD in real values (excluding inflation).

The discount factor is equivalent to the weighted average cost of capital

(WACC).

The market demand is calculated with 3 different growth scenarios: low, me-

dium and high as described in section 4.2.1

8.2 Methodology

The methodology used is the discounted cash flow approach where only cash

inflows and outflows are considered (depreciation, reserves and other account-

ing items are disregarded). The analysis is made in constant 2010 prices in

USD.

The transmission project is a feasible project when the netback value of gas at

the feed-in point in Ubungo exceeds the cost of gas at this feed-in point. The

netback value is the levelized price of competing fuels at the markets in Tanga

and Mombasa minus the transport tariff.

The levelized transport tariff is calculated as the NPV (transport costs) divided

by NPV (transported volumes).

The levelized price of competing fuels is calculated as the NPV (sales revenue)

divided by NPV (demand).

According the Annual Report 2009 from Orca Exploration Group Inc. (field

operator), the weighted average price for gas at Dar es Salaam in 2009 was 3.60

USD/Mscf. This price is calculated as a replacement cost in Dar es Salaam de-

pending on the oil prices.


29

.

The industrial market in Tanga counts for less than 10% of the total market in

Tanga and Mombasa and therefore the pipeline solution is only relevant for

Tanga if the pipeline to Mombasa is feasible. The transport tariff from Ubungo

to Mombasa will therefore be a regular tariff independent on the distance be-

tween feed-in and take-out.

After having analysed the feasibility of the pipeline extension, the sources of

financing is discussed and the sources of financing are included in the analysis.

8.3 Revenue

The revenue for the calculation of financial return is a product of the amount

sold in Tanga and Mombasa and the selling price of gas in Tanga and Mom-

basa.

8.3.1 Potential market

The demand projections are based on the present consumption in Mombasa and

Tanga. Described in section 4.2 above.

8.3.2 Selling price of gas

Natural gas will be sold at a price that is competitive, i.e. the price per useful

energy unit shall be below the similar price for the fuel presently used. This

means that the price will depend on the energy content per unit of the present

fuel and efficiency of conversion technology.

The LCPDP study operates with a reference forecast with an average crude oil

price of USD 70/bbl in 2009. Low and high forecast scenarios for the least cost

plan were done with crude oil prices of USD 63/bbl and USD 100/bbl respec-

tively. After a period from 2003 to 2008 with rapidly increasing oil prices and a

major decrease in 2008, crude oil prices seem to have stabilised on a level be-

tween USD 70/bbl and USD 80/bbl12. The Heavy Fuel Oil (HFO) and diesel

prices are linked to the crude oil price as 70% and 125% of the crude oil price

respectively.

The LCPDP operates with CIF price for coal in the reference case of USD 90/t

in 2010. However, contact with some of the potential industrial consumers in

Mombasa report prices of USD 110/t.

Traditionally natural gas prices have been linked to oil prices. The International

Energy Agency reports in their 2010 World Energy Outlook that world crude

oil price has been 50-60% above the wellhead price of natural gas per energy

unit over the last 15 years which means that long term gas contracts with the

gas price linked to the oil price have been very profitable for suppliers of gas.

The energy content (calorific value) of coal is 25 GJ/t and the energy content in

Heavy Fuel Oil (HFO) is 40.7 GJ/t, 42.7 GJ/t in diesel and 39.9 GJ/m3 for natu-

ral gas.

12 IEA Oil Market Report, Average cif cost of imported crude oil, November 2010


30

.

It is assumed that crude oil prices will increase over time due to limited re-

serves and increasing demand from the transport sector. Coal prices are as-

sumed to be constant in fixed prices due to the larger reserves.

Fuel prices in Mombasa

The February 2010 Mombasa prices are informed by KENGEN and Athi River

Mining Ltd.

Table 8 Fuel prices in Mombasa 2010 and February 2011.

Assumption 2010 February 2011 Mombasa

USD/t USD/t

HFO 410 495

Diesel 733 -

Coal 110 125

LPG 733 -

We have assumed an increase in oil prices of around 20% from 2010 to 2011

which corresponds with the actual prices above.

8.3.3 Discount for conversion and back up

A high utilisation of the pipeline capacity ensures a good economy and there-

fore incentives can be used to attract customers. In this financial analysis it is

assumed that existing power plants are replaced by NGCC when they retire.

The increased efficiency of NGCC plants is assumed to be sufficient incentives

for the power sector to chose this technology and connect to the pipeline. In-

dustries will need an incentive to connect. It has been informed that the dis-

count in Dar es Salaam is around 30% of the price of the fuel that is being re-

placed13. In the calculation of revenues from gas sales to industries in Tanga

and Mombasa the same discount is used. However, the size of the discount is

negotiable between the relevant partners.

8.4 Costs

8.4.1 Pipeline costs

There are various routing options.

The local market option (T1+K1) is a routing along the main road from Dar to

Tanga and along the cost from Tanga to Mombasa. The strength of this solution

is opportunity of making future low cost branches to Morogoro and Arusha and

Moshi on the Tanzanian side and along the coastal area on the Kenyan side.

The weakness is the higher investment costs. This option will cost 550 million

USD in investment. There might be a need for compressors stations at a cost of

around USD 80 million depending on the demand.

13 Meeting with TPDC


31

.

The least cost option (T2+K2) is the routing along the coast line from Dar to

Tanga and from Tanga directly to Mombasa. The feasibility of this pipe routing

is determined by the market in Tanga and Mombasa. The strength of this solu-

tion is the low cost while the weakness is the limited market that can be reached

from Dar to Tanga and from Tanga to Mombasa. In addition there is a risk that

this pipeline will be interrupted during floods. This option will cost 435 million

USD. There might be a need for compressors stations at a cost of around USD

80 million depending on the demand.

There is an option of establishing an offshore connection between Dar, Tanga

and Mombasa. However, this is a very expensive solution with no potential for

connecting local markets in the coastal area.

Table 9 Cost estimate in million USD

No Million

USD

1 Local market option in Tanzania and Kenya (T1+K1) 550

2 Local market option Tanzania and least cost option Kenya

(T1+K2)

526

3 Least cost option Tanzania and local market option Kenya

(T2+K1)

460

4 Least cost option in Tanzania and Kenya (T2+K2) 435

Compressor for all options 80

While the difference between the local option and least cost option is 90 million

USD in Tanzania the difference in Kenya is 24 million USD.

The local market option results in a cost increase of around 25% compared to

the least cost option. Choosing the local option in Kenya will result in an in-

crease of around 5% while the local option in Tanzania will result in an in-

crease of around 20% compared to the least cost option. These cost increases

should reflect additional revenues from the local markets to make them attrac-

tive.

The cost estimates for all 4 routing options includes compensation costs to land

owners.

8.4.2 Gas price

The feed-in point for gas will be Ubungo and it is assumes that gas is delivered

from Songo Songo at conditions similar to the purchase agreements for Addi-


32

.

tional Gas from Songo Songo. According to the Annual Report 200914 from the

field operator, the weighted average price for gas at Dar es Salaam in 2009 was

3.60 USD/Mscf. This price is a weighted average of a gas price for industry of

8.36 USD/Mscf and a power gas price of 2.40 USD/Mscf. The gas prices are

replacement costs in Dar es Salaam and depending on the oil price develop-

ment.

8.5 Financial calculations

The financial calculations use the discounted cash flow approach and are based

on assumptions regarding the discount rate, the market demand and the routing

of the pipeline. The results of the calculations are presented as a comparison of

netback value at Ubungo and cost of gas at Ubungo, with the netback value cal-

culated as the levelized price of competing fuels at the market in Tanga and

Mombasa minus the transport tariff.

The levelized price of competing fuels is calculated as the NPV (sales revenue)

divided by NPV (demand).

The levelized transport tariff is calculated as the NPV (transport costs) divided

by NPV (transported volumes)15.

8.5.1 Discount factors

The calculations have been made with 4 different discount factors that are

based on weighted average cost of capital (WACC) calculations.

WACC = E/V * Re + D/V * Rd

Where:

The WACC calculations are based on 2 different capital structures of the pipe-

line company. WACC 1 and WACC 2 are 100% debt financed with different

interest rates.

14 Annual Report 2009, Orca Exploration group Inc. Strategic Growth. 15 It is assumed that NPV(demand) = NPV(transported volumes).

Re = cost of equity

Rd = cost of debt

E = market value of the firm's equity

D = market value of the firm's debt

V = E + D

E/V = percentage of financing that is equity

D/V = percentage of financing that is debt


33

.

Table 10 WACC calculations for 100% debt financed structure.

WACC 1 WACC 2

Loan A 33% 33%

Interest rate A (LIBOR + bank margin) 2.45% 4.45%

Loan B 66% 66%

Interest rate B (LIBOR + bank margin) 5.45% 10.45%

WACC 4.41% 8.38%

WACC 1 consists of 33% of one loan (A) with an interest rate of 2.45% (0.45%

LIBOR16 + 2% bank margin) and 66% of another loan (B) with an interest rate

of 5.45% (0.45% LIBOR + 5% bank margin).17

The structure of WACC 2 is similar to WACC 1 only with higher bank margins

of 4% and 10% (the LIBOR is unchanged).

WACC 3 and WACC 4 consist of 33% equity financing and 66% debt financ-

ing with different interest rates.

Table 11 WACC calculation with a 33% equity and 66% debt financing structure.

WACC 3 WACC 4

Equity 33% 33%

Return on equity (ROE) 20% 20%

Loan 66% 66%

Interest rate (LIBOR + bank margin) 5.45% 10.45%

WACC 10.26% 13.56%

WACC 3 consists of 33% of equity with a required return on equity (ROE) of

20% and 66% of a loan with an interest rate of 5.45% (0.45% LIBOR + 5%

bank margin).

WACC 4 has a similar structure as WACC 3 only with a higher bank margin of

10% (the LIBOR is unchanged).

With these assumptions the highest WACC calculates at 13.56%. It is further

assumed that there is no tax-shield which can be applied on the interest rate

payments.

The calculated WACC is used as the discount rate in the financial analysis. It is

assumed that the WACC is used even if the capital structure is financed by

100% equity as it should be possible to obtain loan (66%) in the market at an

interest rate of 10.45% and thereby reducing the WACC. This WACC is similar

to the WACC approved by EWURA in relation to the expansion project18

16 London Inter Bank Offered Rate 17 African Development Bank and Tanzanian Ministry of Energy and Minerals 18 This is consistent with EWURA, Order no 09-004


34

.

If the governments of the EAC member countries will finance the project with

100% equity from the state budgets then it is definitely an opportunity. The

WACC for this option will be the ROE for alternative investments the govern-

ments could have invested in instead. It is therefore fair to use a lower discount

factor, such as WACC 1 or WACC 2 calculated above.

8.5.2 Routing options

The Conceptual Design Report presents various routing options see overview

map in section 1 (Executive Summary:

Local market option in Tanzania (T1) and Kenya (K1). The potential demand in

the local markets is not known and will have to be assessed in detail before any

decision is taken on this option. This analysis will shows how large a local

HFO fuelled market will be required to justify an increase in investment of

around 25% compared to the least cost option. It is important to highlight that

this is a particular sensitivity analysis to have an indication if this option is fea-

sible.

Local market option in Tanzania (T1) and least cost option in Kenya (K2). This

option represents a lower cost compared to the local market option by choosing

a shorter route in Kenya and keeping the opportunity for connecting local mar-

ket in Tanzania. This option represents an increase in investment of around

20% compared to the least cost option.

Least cost option in Tanzania (T2) and local market option in Kenya (K1). This

is a similar option reaching the local markets in Kenya but choosing a shorter

route in Tanzania. This option represents a 5% increase of investment com-

pared to the least cost option.

Least cost option (T2 + K2). The major issue in the analysis of the least cost

option is the potential industrial market based on replacement of coal. If coal

replacement for industries is not an option the demand for gas is reduced by

around 10%.

8.5.3 Results

The results of the financial calculations are presented as a netback calculation.

The netback values are calculated for the medium demand scenario (1% annual

growth) with the four (4) routing options and the four (4) discount factors.

The transport tariff is calculated as transport cost per transported unit of gas,

i.e. levelized cost of constructing and operating the pipeline and profit to the

pipeline owner/operator in relation to levelized volumes transported over the

lifetime of the project.

The transmission project is a feasible project when the netback value of gas at

the feed-in point in Ubungo exceeds the cost of gas at this feed-in point. The

netback value is the levelized price of competing fuels at the markets in Tanga

and Mombasa minus the transport tariff.


35

.

Table 12 Levelized netback value USD/Mscf, medium demand scenario (1% per an-

num).

Market demand - medium growth

Route 4

(T2 & K2)

Route 3

(T2 & K1)

Route 2

(T1 & K2)

Route 1

(T1 & K1)

Discount factor (4.4%)

Replacement cost 10.27 10.27 10.27 10.27

Transport Tariff 1.09 1.12 1.19 1.22

Netback Ubungo 9.18 9.15 9.08 9.05

Discount factor (8.4%) Replacement cost 10.06 10.06 10.06 10.06


Netback Ubungo 8.67 8.63 8.52 8.47



Netback Ubungo 8.42 8.37 8.23 8.19



Netback Ubungo 7.94 7.87 7.70 7.64

The calculated netback values shall exceed the weighted average price for gas

at Ubungo of 3.6 USD/Mscf for the project to be feasible. The least favourable

case with the highest investment cost (Route 1) and the discount factor (13.6%)

results in a netback value of 7.64 USD/Mscf which is above the average price

of 3.6 USD/Mscf.

Table 13 FIRR, medium demand scenario.

1% growth

Route 4

(T2 & K2)

Route 3

(T2 & K1)

Route 2

(T1 & K2)

Route 1

(T1 & K1)

4.4% 4.2% 4.5% 5.3% 5.6%

8.4% 7.3% 7.7% 8.6% 9.0%

10.3% 8.7% 9.1% 10.2% 10.6%

13.6% 11.3% 11.8% 13.0% 13.4%

The above table illustrates the financial internal rate of returns (FIRR) for the

four (4) routes and the four (4) discount factors (WACCs). The FIRRs for the

medium demand scenario (1% annual growth rate) are in the range of 4.2%-

13.4% depending on the route and the WACC. These FIRRs are preliminary as

the exact cash flow of the pipeline company is unknown.

8.6 Financing plan

8.6.1 Access to capital and funding costs

A key issue is whether the project should primarily seek funding on the local

capital markets or on the international capital markets.


36

.

The key parameters that will have to be taken into account in this are:

The currency in which the project revenues will be available to the pipeline

company (USD or local currency (LCU)).

The local capital market ability provides suitable long term loan products in

LCU.

The pipeline company's ability to access long term loans in USD on the interna-

tional capital markets.

The local capital market

A significant number of international and local banks are present in Kenya and

Tanzania. However, bank lending continues to be conservative and not very

sophisticated. This is likely to limit the ability to secure non-recourse or limited

recourse project financing in LCU.

Interest rates and foreign exchange are liberalized, but there continues to be

restrictions on repatriation of capital although profits and dividends are fully

remittable.

The International Capital Market

It is assumed that the pipeline company will have access to long term loans in

USD on the international capital markets and obtainable loan terms (maturity,

grace period and interest spread).

Project funding costs

Assuming that the project revenue will be available to the pipeline company in

USD and that the pipeline company will be able to access long term loans in

USD on the international capital markets, an assessment of the Weighted Aver-

age Cost of Capital (WACC) for the project is provided in section 8.5.1.

8.6.2 Ownership

The ownership of the gas pipeline infrastructure from Dar es Salaam to Mom-

basa can be organised in several ways.

There are several ways of structuring the pipeline company. This feasibility

study will assess the following two options:

Special Purpose Vehicle (SPV) with state guaranteed loans

A Special Purpose Vechicle for the purpose created governments owned com-

pany (the SPV) would implement the project and based on the state guarantee

be able to access funds on the capital market at terms similar to the govern-

ments.

Public Private Partnership (PPP)

A PPP is a long term contract based cooperation where the public sector trans-

fers the general responsibility for the delivery of a public service to a private

company but still keeps the political responsibility. The private company would


37

.

be responsible for implementing the project under a concession agreement and

would directly access the domestic and international capital markets.

Special Purpose Vehicle (SPV) with state guaranteed loans

The equity of the SPV could be owned by the Government of Tanzania, the

Government of Kenya, the Government of Uganda, the Government of Rwanda

and the Government of Burundi and the SPV could obtain a loan with a state

guarantee (e.g. based on bonds). The degree of equity required from the owners

(Governments of the EAC countries) would have to be assessed in the onward

work but the international experience indicates that a state that guarantees the

debt component enables a relatively high degree of debt financing thereby re-

ducing the combined cost of financing (WACC). The loan guaranteed however

commits the owners (the governments of the EAC countries) to service the debt

obligations in case the company is not able to do so.

The SPV will be responsible for designing, building, financing and operating

the gas pipeline. The revenue of the SPV will come from the transportation tar-

iffs and will initially be allocated to operational costs and to service the debt

obligations of the SPV. Any profit accrued at the termination of the SPV will

be allocated to the owners (the Governments of the EAC countries).

Pros and cons of the SPV

Lower risk of cost overruns

International studies show that large government sponsored infrastructure pro-

jects often have cost overruns. The SPV has an incentive to assess more risks

from the beginning and reflect risks associated with the project as the SPV is

commercially run and has debt obligations to service.

Special Purpose

Vehicle

The Governments of

the EAC countries

Contractors Service Providers

Loan Security

Bank

State

guarantee

Service

contract

Construction

contract

Shareholders

agreement

Figure 5 The structure of the setup around a SPV.


38

.

Efficiency in the construction period

The SPV has an incentive to be efficient in the construction period as the SPV

will not start to generate any revenue until the construction is finished and the

infrastructure is ready for operation.

Innovative solutions

The SPV has an incentive to optimise the economy of the project and be inno-

vative to reduce operating and maintenance costs during the contract period.

Loss of flexibility

There is a higher flexibility in the SPV project compared to the PPP after the

project has started as it is easier for the customer (the EAC member countries)

to make changes in the project scope, content and framework conditions, as the

owners of the SPV are the EAC member countries.

Cost of financing

A SPV is most likely to have lower higher cost of financing compared to the

PPP as the SPV has a state guarantee. This depends on the credit rating of the

countries owning the SPV.

Higher transaction costs

A SPV contract and tender process is not very complex and it will therefore

often not result in costly transaction advice as the PPP model.

Public Private Partnership

The equity of the PPP Company will typically be owned by an investor group

representing the main contractors and service providers for the project as well

as financial investors (e.g. pension funds). In this context it should be consid-

ered whether the key users of the transportation service, TPDC and Songas in

Tanzania and KPC in Kenya, could be one of the equity holders. It also needs

to be considered whether this will jeopardize the independency and make pos-

sible later third party access difficult.

A PPP Company is typically financed by 60-90% loan and 10-40% equity from

private investors. i.e. a debt component of 60-90%. This setup normally in-

creases the cost of financing compared to the SPV model as it is not possible to

obtain a loan with a similar low interest rate as the state guaranteed loan. Fur-

ther the expected return on equity is also higher which increases the weighted

average cost of capital (WACC) further. This conclusion may however be dif-

ferent if the PPP Company is better able to access funds on the international

capital markets.

In the PPP model the Governments of Tanzania and Kenya enters a Concession

agreement or a DBFO agreement with the PPP Company under which the PPP

Company will design, build, finance and operate the infrastructure over a pe-

riod of e.g. 30 years. The PPP Company will own the infrastructure in the con-

tract period after which the asset will be handed over to the state. The PPP

Company has a strong incentive to optimise the economy of the project in the

contract period as the PPP Company is not only responsible for designing and

building the infrastructure but also operating it during the contract period.


39

.

Under a Concession agreement the PPP Company will receive the revenue from

the transportation tariffs in the operating period. Under a DBFO agreement the

PPP Company will receive periodical payments (annual, semi annual or

monthly) in the operating period. Both models create an incentive for PPP

Company to finish the construction within (or before) the agreed construction

period so the operation can begin and the PPP Company can start generating a

revenue.

A typical PPP structure is shown in the chart below.

Pros and cons of PPPs

Lower risk of cost overruns

International studies show that large government sponsored infrastructure pro-

jects often have cost overruns. The studies also show that when implemented as

PPPs the projects more often stays within the budget as the PPP companies

have an incentive to assess all risks from the beginning and reflect all risks as-

sociated with the project in the tender price.

Efficiency in the construction period

PPPs has a great incentive to be efficient in the construction period as the PPP

will not start to generate any revenue until the construction is finished and the

infrastructure is ready for operation.

Innovative solutions

The PPP Company has an incentive to optimise the economy of the project and

be innovative to reduce operating and maintenance costs during the contract

period.

Loss of flexibility

There is less flexibility in the PPP project compared to the SPV after project

has started as the nature of the PPP contract significantly limits the ability of

Public-Private

Partnership

Bank Investors

Contractors Service Providers

Loan

Security

Service

contract

Shareholders

agreement

Construction

contract

Figure 6 The structure of setup around a PPP.


40

.

the government to make changes in the project scope, content and framework

conditions after contract signature.

Cost of financing

A PPP may have higher cost of financing compared to the SPV as the PPP does

not have a state guarantee. At the same time, the PPP may however also have

better accesses to international funding than the sponsoring government(s) de-

pending on the credit rating of the country.

Higher transaction costs

A PPP contract and tender process is very complex and it will therefore often

require more costly transaction advice than a SPV model.

Table 14 Pros and cons of the different ways of structuring the organisation.

Pros and cons Government

financed (Public)

Private

financed

SPV PPP

Low risk of cost overruns - + o +

Incentive for efficiency in

the construction period - + o +

Innovative solution - + o /+ -

Flexibility + - o /+ -

Low cost of financing + - + -

Low transaction costs + - o -

The table above summarizes the pros and cons of the different ways of structur-

ing the organisation of the pipeline company.

Taxation

The tax calculations have been excluded from this analysis as the high uncer-

tainties in relation to how the pipeline company will be structured, in which

country will the pipeline company be registred, will there be any tax exemption

and for how long.

Until the final route, the capital structure of the pipeline company, the country

where the pipeline company will be registered as a legal entity is known there

are too many ubncertainties and there will have to be made too many assump-

tions in order to be able to calculate the tax payments for the pipeline company.

Depreciation

The depreciation is only interesting when the tax is analysed as the depreciation

is tax deductable. The depreciation has been excluded hence the exclusion of

the tax calculations.


41

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9 Economic analysis

The objective of the economic analysis is to identify the direct benefits of the

project. The economic analysis is based on the financial analysis.

9.1 Assumptions

Social discount rate: 5.5%19 and 10%20 as described in the Methodology Re-

port.

Market: low, medium and high as described in section 4.2

The gas hubs around the world are efficient i.e. the gas prices reflect the de-

mand and supply and are not tied up to the oil price.

9.2 Methodology

The economic analysis is undertaken from the point of view of society. The

economic analysis uses the incremental method, i.e. the project is evaluated on

the basis of the difference in costs and benefits between the scenario with the

project and an alternative scenario without the project.

The economic analysis starts from the financial cash flow and adjusts financial

costs and revenues into economic costs and benefits.

The adjustments to market prices will be fiscal correction, i.e. corrections for

subsidies whenever the scenario without the project operates with subsidies to

reduce fuel prices. There will also be corrections for externalities, i.e. reduced

emissions for combustion of coal and oil. Finally indirect economic benefits

and impacts will be discussed.

9.3 Costs

The economic costs are:

Investment and maintenance costs of the pipeline;

Incremental costs of replacing retired HFO fired plants with combined cycle

power plant as well as end-user conversion of industries;

19 EU standard: 5.5%. 20 WB standard: 10%.


42

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Gas cost at the feed-in point in Ubungo.

9.3.1 Investment costs

Estimates of the pipeline costs are presented in section 8.4.1.

9.3.2 Conversion costs

Estimates of conversion costs for power plants is a rather comprehensive exer-

cise requiring individual assessment for each power plant. Existing power

plants are assumed to be in operation with present fuel until retirement and then

replaced by NGCC fired plants. According to table 1 in section 3.5.1 there is a

clear indication that investment costs for combined cycle plants will not exceed

the investment cost for comparable coal and diesel fired plants because of envi-

ronmental requirements. Therefore no incremental costs are included for gas

fired plants compared to new coal and diesel power plants

The costs of converting industries are included in the discount on the gas price for these customers and not included in the economic calculation.

9.3.3 Gas costs at Ubungo

The wellhead production costs are not known. During the last decades with emerging gas markets in USA and Europe, regional gas markets have estab-lished referred to as gas hubs. Assuming these hubs are efficient a hub gener-ates a reference price that is believed to reflect the real market prices and is not, like long-term contracts, bound to the oil price development. There is not a hub in East Africa which means that the prices available from the operator of the Songo Songo gas field is an operating netback price based on sales prices of oil in Dar es Salaam and thus linked to the world market oil prices. The operating netback price was 2.21 USD/Mscf in 2009 which was a decrease from 2.6 USD/Mscf in 2008 due to the decrease in world market oil prices in that period. In the calculation of the economic cost of gas delivered in Ubungo it is as-sumed that the netback price in 2009 is following the estimate for crude oil price development. The weighted average unit cost at Ubungo is informed by Songas to be 3.60 USD/Mscf for 2009 which is a reduction from 4.01 USD/ Mscf for 2008.

9.4 Benefits

The economic benefits from establishing a gas pipeline will be:

Revenue from sales of gas in Tanga and Mombasa.

Reduced primary energy consumption by end-users due to higher efficiencies

in gas fuelled technologies compared to coal and oil fuelled technologies;

Reduced emissions;

Security of supply;


43

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Indirect economic effects and impact on employment and economic growth as a

result of the investment and access to a reliable and price stable fuel. Some of

these benefits can be quantified and monetised while other benefits will be

qualitative and long term impacts.

The below table illustrates how the different economic benefits contribute to

the total economic benefit.

Table 15 Monetised economic benefit by category.

Category

(Million USD)

Social Discount

Factor

5,5%

Social Discount

Factor

10%

ENPV(Sales revenue) 8,752 5,027

ENPV(Energy efficiency) 848 486

ENPV(CO2 reductions)21

314 185

Total 9,914 5,699

The major component of the economic benefits is the sales revenue accounting

for around 90% of the total economic benefits.

9.4.1 Sales revenue

Sales revenue will be taken directly from the financial analysis assuming that

there are neither taxes nor subsidies related to cost of fuels being replaced by

gas.

9.4.2 Improved energy efficiency

The volumes in energy units will be reduced compared to the present consump-

tion of oil and coal as a result of the higher efficiency in the gas fired power

plants compared to conventional oil and coal fired plants. Most combined cycle

units, especially the larger units, have peak, steady state efficiencies of at least

50% compared to around 40% for Kipevu II. It is assumed that efficiency in-

creases with 10% point when using gas fired combined cycle compared to HFO

generation. The efficiency improvement means a reduction of primary energy

consumption. Combined with the increase in load factor from 80% to 90% the

total reduction of primary energy per power plant is 10%.

The improved energy efficiency could result in reduced electricity prices or ex-

pansion of the national grid and improved competitiveness for industries in the

target areas.

9.4.3 Environmental benefits

The environmental benefits are caused by the low carbon content of natural gas

per unit of primary energy. CO2 emissions from combustion of coal are 95

kg/GJ and from combustion of HFO 78 kg/GJ compared to 56.9 kg/GJ for natu-

ral gas.

21 This is based on a CO2 price of 10 USD/t.


44

.

Natural gas emits lower levels of nitrogen oxides and particulates and produces

virtually no sulphur dioxide and mercury emissions. These benefits are not cal-

culated and monetised.

9.4.4 Security of supply

The gas pipeline shall provide at least the same level of security of supply as

the present oil and coal based solutions in Tanga and Mombasa. With a gas

pipeline of approximately 500 km, there is a risk of interruption which is fur-

ther discussed in section 10.2 Risk analysis. Security of supply can be main-

tained through the contracts with customers in Tanga and Mombasa. Customers

will receive a discount in the gas prise against keeping and maintaining their

existing fuel storage tanks and reserves to be used in the dual fuel plants in case

of interruptions of the gas supply. The specific costs of maintaining reserve ca-

pacity will require detailed assessments. This financial and economic analysis

operates with an assumption that a negotiated discount in gas price compared to

the price of competing fuel will compensate customers for these extra costs.

This arrangement is cost efficient compared with central gas storage solution

for local and regional gas supply systems which will be far too expensive and

not feasible.

In addition to the physical security of supply there is an economic security of

supply with a gas contract being more independent from the fluctuations in

crude oil prices. The present development in crude oil prices as a result of the

situation in the Middle East illustrates the value of increased security of supply.

The benefit of increased security of supply is not calculated and monetised.

9.4.5 Indirect economic benefits and impacts

The direct economic effects of the investment in pipeline extension are the ini-

tial direct investment and the direct revenue as presented above. However the

initial investment may have a larger impact on the economies of the countries

affected by the investment. This impact depends on the economic multipliers.

An economic multiplier is a single number that summarises the total economic

benefits resulting in an increase in economic output. The number summarises

economic impacts which can be expected from changes in a given economic

activity. The economic multiplier can be decomposed into direct, indirect and

induced economic effects:

Direct effects are mainly the increase in employment in the construction sector

during the implementation of the project;

Indirect effects are changes in transactions with sectors that provide inputs and

services to the construction sector;

Induced economic effects are changes in household spending associated with

income changes as a result of an increase in employment.


45

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There is a 2008 study22 of multipliers in Tanzania based on an updated Social

Accounting Matrix (SAM). The SAM-based multiplier model is a general equi-

librium model. The study shows that the construction sector has an economic

multiplier of 1 meaning that there will mainly be direct effects, i.e. employment

effect during construction.

The direct employment effect can be calculated by using a rule of thumb saying

3 person years per million USD invested.

The improved energy efficiency will reduce household spending on electricity

and improve the competitiveness of industries in the area, assuming that the

electricity prices will be reduced. This will have an effect on economic growth

in the region but it is not easy to quantify this effect.

9.5 Economic calculation

The economic calculations use the discounted cash flow approach and are

based on assumptions regarding the social discount rate, the market and the

routing of the pipeline. The results of the calculations are presented as the NPV

of net economic benefits.

9.5.1 Results

The results are presented for the high demand scenario for the 4 routing options

and the 2 discount factors.

Table 16 Economic NPV, million USD, medium demand scenario.

Social Disc. factor

Route 4

(T2 & K2)

Route 3

(T2 & K1)

Route 2

(T1 & K2)

Route 1

(T1 & K1)

5.5% 2,778

2,755

2,696

2,674

10% 1,454

1,433

1,378

1,358

EIRR 32.1% 31.1% 28.8% 28.1%

The project is economic viable with a social discount factor below 22%. In ad-

dition all the non-quantified and non-monetised economic benefits will increase

the economic internal rate of return (EIRR).

22 Economic multipliers for Tanzania: implications on developing poverty reduction pro-

grams, prepared by a cooperation between researchers from Sokoine University of ASgri-

culture, Tanzania, Maruku Research Institute, Tanzania, Ministry of Livestock develop-

ment, Tanzania and Southern University and A&M College, USA.


46

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10 Risk assessment

10.1 Sensitivity analysis

The critical variables are investment cost, fuel replacement cost, demand, gas

purchase price and discount factor.

10.1.1 Investment increase

An increase in the investment cost will result in an increase in the transport tar-

iff as the tariff is based in a full cost recovery. A 20 % increase of the invest-

ment cost for the local market option (T1+K1) with the high discount factor

will reduce the netback value from 7.64 USD/Mscf to 7.30 USD/Mscf which is

far from the switching value for the scenario i.e. cost of gas at Ubungo (3.6

USD/Mscf).

10.1.2 Discount increase

Industrial customers will receive a discount in the gas price to compensate for

the required storage facilities. An increase in the assumed discount will mean a

reduction in the revenue from the gas sale.

The levelized sales price of gas (NPV(sales revenue of competing fu-

els)/NPV(demand)) is highly sensitive to changes in the demand.

The levelized transportation tariff (NPV(transportation cost)/NPV(transported

volumes)) is not sensitive to changes in the market size.

The transport tariff is independent of the replacement costs and therefore the

pipeline company will not be affected by changes in the sales price of gas.

10.1.3 Demand reduction

The sensitivity on changes in the demand of gas is analysed for two perform-

ance indicators:

The levelized sales price of gas (NPV(sales revenue of competing fu-

els)/NPV(demand)) is not significantly sensitive to changes in the market size.

The levelized transportation tariff (NPV(transportation cost)/NPV(transported

volumes)) is highly sensitive to changes in the demand.


47

.

The transport tariff will increase from a demand reduction and therefore the

pipeline company will be affected by changes in the demand for gas.

10.1.4 Increase of the gas price at Ubungo

An increase of the gas price at Ubungo will either be caused by an increase in

the well head price or an increase in the transportation tariff.

An increase in the well head price caused by an increase in the worldwide oil

prices will be not have a direct affect as the price of competing fuels in Mom-

basa and Tanga will increase accordingly.

Today the transportation tariff (Songo Songo - Ubungo) account for 17% of

average gas price at Ubungo. An increase in the transport tariff of 10% will

mean an increase in the Ubungo gas price of 1.7%.

10.1.5 Discount factor

The discount factor is the chosen WACC and thereby the capital structure of

the pipeline company, i.e. the combination of the equity and debt and the re-

quested return on equity and debt.

The lowest WACC is assumed to be 4.4%, see section 8.5.1 if the WACC is

increased to the highest WACC at 13.6% this will result in a reduction of the

netback value.

The analysed WACCs are not critical for any of the routing alternatives but for

the local Tanzania market options (Route 1 and Route 2) the netback value at

Ubungo is close to the selling price at Ubungo for the high discount factor.

10.2 Risk analysis

The major risk relates to (1) investment cost (2) demand and supply.

Risks affecting investment costs

Increasing steel prices

There is a close historical correlation between IMF global GDP growth and

world steel demand. Steel is produced by iron from ores or from scrap.

The global market in iron ore is dominated by a few mining companies. Tradi-

tionally iron was sold on annual fixed prices but now the minors have switched

to three month contracts. Demand has increased during 2009 and prices have

increased as well. The price increases is a result of under supply because of un-

der investing in mining and milling capacity. The increasing steel prices will

result in increasing capacity which will stabilise the steel price.

During the last year the global composite carbon steel price has increased from

700 USD/t in March 2010 to around 900 USD/t in March 2011.


48

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The risk analysis is not based on a probability distribution but is referring to

experience from similar projects as referred to in the EU guide to Cost-Benefit

analysis of investment projects23.

The EU Guide refers to cost overruns and too optimistic estimates of benefits as

classic risks for major infrastructure projects. The local market option with a

netback value close to the selling price, represents an extra cost of 20% com-

pared to the least cost option. It can therefore be concluded that the least cost

option is robust up to a cost overrun of 20% as described in section 9.1.1 above.

However, the local market option will be extremely sensitive to cost overruns

unless it is possible to identify a substantial market in Arusha and Moshi. The

extra investment costs for the local market option in Tanzania compared to the

least cost option in Tanzania is around 90 million USD which is 18% of the

least cost option. In order to achieve a financial viability comparable to the

least cost option, a market in Arusha and Moshi shall be at a volume which is

18% of the Mombasa market. This is equivalent to the double of the market in

Tanga. It is not possible to conclude if a market of this size is available in

Arusha and Moshi. This will require a detailed market study.

As mentioned it is very likely with cost overruns and the mitigation measure is

to ensure that the project is a robust project that will still be financial viable

even with a 20% cost overrun

Interruptions

The least cost route is following the coast and therefore exposed for risk of in-

terruptions caused by flooding. During the rainy season it can be difficult to

repair the line which may cause interruptions over a longer period. To mitigate

this risk the more expensive local market route (T1+K1) can be selected or lo-

cal storage capacity can be established at the customers in Tanga and Mom-

basa. Today all customers in Tanga and Mombasa are major customers who

have storage capacity for the competing fuels used today. These customers will

be interruptible customers who will require a discount to compensate for the

cost of maintaining their storages as described in section 9.4.4.

It is not possible to judge about the probability of flooding interrupting the

coastal routing. It is recommended that a detailed risk assessment is undertaken

before the final routing decision is made. The detailed risk assessment will

show if a solution with interruptable customers are sufficient or the more ex-

pensive choice of the local market routing (T1+K1) will be required.

Risk affecting the demand and supply

It is a precondition that the gas resources will be available at Ubungo. This

availability will require that reserves are available and that processing and

transport capacity is available. There are ongoing investigations about the re-

serves and negotiations about the new processing plant and the new pipeline

23 Guide to Cost-Benefit Analysis of investment projects, European Commission, June

2008.


49

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from Songo Songo to Ubungo. A decision about extending the pipeline to

Mombasa must await decisions about extending the gas processing and trans-

port infrastructure in Tanzania.

The financial and economic analysis shows that the project is a viable project

even with a low demand projection. The presence of this market is a precondi-

tion for initiating the project. The risk related to demand can be mitigated with

long term contracts with industries and power plants. Normally a gas transpor-

tation infrastructure project will not be implemented until the market is secured

through long term contract with the industries and the power plants.


50

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11 Logical Framework

11.1 Logical framework assessment

A Logical Framework Approach (LFA) to the project cycle management con-

sists of a causal hierarchy of causes and effects.

The overall objective describes the broad development objectives to which the

project contributes. The East African Community and the national governments

will be focusing on the regional and sectoral level impacts on economic, social

and environmental development

The development outcome at the end of the project or more specific the ex-

pected benefits to the target groups must be access to reliable, cheaper and less

polluting energy for customers connected to the gas system.

The output is tangible results (goods and services) that the project delivers and

which are largely under project management's control

From the point of view of the implementer the LFA matrix will look as follows:


51

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Narrative summary Indicators Source of verification Important Assumptions

Overall objective

Improved economic opportu-

nities and reduced emissions

from power sector and indus-

try.

Annual sales

volumes to

customers

Annual reports from

the pipeline company

Development outcome

Power plants and industries

in Tanga and Mombasa have

access to natural gas.

Increased ener-

gy efficiency

CO2 emission

reductions in

accordance

with estimates

Man month

employed

Annual report from the

power companies and

industries connected to

the pipeline

Development outcome-

overall objective line

Outputs

A gas pipeline connecting

Dar es Salaam and Mombasa

km pipeline

constructed

Progress reports

Output-development

objective line

Customers connected as

planned

Activities

Authority approval, detailed

design, construction and

O&M organisation

Detailed engi-

neering

Budget

Activity-output line

Authority approval of

ESIA

Pre-conditions

A company established as

owner of the pipeline

Enough gas available at

Ubungo.

Regulatory authority cla-

rified


52

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Preconditions:

The feasibility study is based on an assumption that there is sufficient gas in the

Songo Songo fields to supply the market over the life time of the project. This

assumption is justified in the Market Study. However it is not only a question

of physical amounts. There is a need for a firm commitment from the Govern-

ment of Tanzania that the requested amounts of gas will be made available for

export to Kenya. There are options for using the gas in Tanzania but no analysis

of the potential markets in Tanzania to indicate if these markets are more attrac-

tive from a financial and economic point of view. (Information about the poten-

tial gas reserves in relation to local markets in Tanzania (Arusha, Moshi and

Morongoro) and the local coastal markets in Kenya indicates that supply of gas

is not a bottleneck).

There are regulatory authorities in Tanzania and Kenya respectively but so far

there is no decision about who will approve the transport tariff for a pipeline

from Tanzania to Kenya. This legal issue will have to be solved before the pro-

ject can be initiated and should be raised by EAC as an issue related to the inte-

gration of the energy markets.

11.2 Monitoring of project benefits

The benefits from the project are mostly direct benefits represented by:

• Increase in employment during construction

• Increased energy efficiency at end-user level

• Reduced emissions

• Increased security of supply

11.2.1 Energy efficiency

The increased efficiency among end-users could be monitored by recording use

of primary energy in relation to final use of energy. Monitoring should be easy

for power plants that are publishing these figures on an annual basis. Not all

industries are publishing physical amounts of primary energy in relation to out-

put of final products and increased overall efficiency could also be caused by

other initiatives.

11.2.2 Emission reductions

All end users would benefit from emission reductions resulting from fuel shift

to natural gas. The reductions in CO2 emissions have a value if the conversions

are approved under the Clean Development Mechanism. There are very well

defined monitoring procedures under this mechanism.


53

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11.2.3 Employment effects

The increased employment can be monitored through the progress reports from

the contractor.

11.2.4 Security of supply

Today the power plants and industries in Mombasa and Tanga are depending

on imported fuels. The world market price on oil has shown significant varia-

tions over the last years affecting the cost of electricity and manufactured prod-

ucts. By introducing a new option for indigenous fuels the security of supply

increases and there is an opportunity to have more predictable prices included

in the contracts. It is difficult to monitor security of supply.


54

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12 Conclusion

The expansion of the gas pipeline system to reach Tanga and Mombasa is a

feasible project. The main market is in Mombasa consisting of power plants

and industries. The connection of the industrial market in Tanga is a spin-off

from the pipeline to Mombasa as the Tanga market represents less that 10% of

the Mombasa market.

The analysis comprises various demand scenarios and routing options.

The demand scenarios analyse a low, a medium and a high demand scenario

with the high demand scenario representing an annual increase in demand of

2% representing 50% increase in demand over the 20 years of lifetime for the

analysis.

The local market routing option (T1 + K1) is designed to address the opportu-

nity of future connections of local markets in Tanzania (Arusha and Moshi) and

Kenya (coastal area between the border and Mombasa). This result in a longer

pipeline and has the highest investment costs of 630 million USD (550 + 80 for

compressor stations).

The least cost routing option (T2 + K2) is designed to minimize investment

costs resulting in an investment costs of 515 million USD (435 + 80 for com-

pressor stations) or 25% below the investment costs of the local market routing

option.

The criterion for a feasible pipeline project is that the netback value of gas at

Ubungo exceeds the cost of gas at Ubungo. The netback value is the gas price

in Mombasa minus transportation tariff. The gas price in Mombasa is calcu-

lated as the levelized price of competing fuels, i.e. the NPV of future sales

revenue (of the competing fuels) divided by the NPV of the demanded vol-

umes. The NPV is calculated with different discount factors where the different

WACCs have been used under various assumptions of equity/loan share and

size of interest rate.

The financial analysis shows that the least favourable case with the highest in-

vestment cost (the local market routing option, T1+K1) and discount factor of

13.6% results in a netback value of 7.63 USD/Mscf which exceeds the cost of

gas at Ubungo of 3.6 USD/Mscf (2009 price) under the medium demand sce-

nario. The conclusion is that the even the local Tanzanian market routing op-

tions (T1) will be robust financially viable projects.

The sensitivity analysis shows that both the least cost routing option (T2+K2)

and the local market option (T1+K1) are robust to changes in market growth


55

.

and interest rate. An overrun in investment cost of more than 20% will not

bring any of the options in a critical situation. Increases in oil prices will only

have minor impact on the viability of the project.

The economic analysis shows that all routing options have a positive ENPV

with both 5.5% and 10% social discount factor. The project has an economic

internal rate of return (EIRR) of 28-32%. The conclusion is that the local mar-

ket routing option will only be an economic acceptable project when the social

discount rate is below 28%. In this calculation there are not included benefits

like improved security of supply and indirect economic benefits as these are

difficult to monetise. An EIRR of 28% is very acceptable compared to the crite-

rion in the EU guidelines.

Environmental and social impacts and opportunities from the project can be

summarized as follows:

The construction of the pipeline will cause temporary disturbances to human

communities affected directly by the alignment

The construction of the pipeline will cause temporary disturbances to sensitive

natural habitats which are affected directly by the alignment. These habitats

include river beds, forest areas and protected areas (including the Saadani Na-

tional Park, if the coastal route will be selected)

During operation of the gas pipeline the environmental and social impacts are

assessed as being negligible, and resettlement activities are expected to be

minimal;

The project will contribute to the Clean Development Mechanism as defined in

the Kyoto protocol

The ESIA report will allow the environmental authorities to base their decision

on the scope and content of the full ESIA for the detailed design stage, once a

specific gas pipeline solution has been identified and agreed upon in the EAC.

The Beneficiaries of the project will be the following:

Tanzanian government will benefit from royalties and other benefits and TPDC

will benefit from profit gas.

The pipeline owner/operator benefits from the profit from the pipeline.

Power consumers and industries in Kenya and Tanzania will benefit from cost

reductions caused by improved efficiency and thus reduced unit costs for en-

ergy.

Climate will benefit from reduced emissions from power plants and industries

fuelled by gas.


56

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13 Recommendations

The feasibility study has shown that there is an attractive market for selling the

gas at Mombasa and that a pipeline between Ubungo and Mombasa for trans-

porting the gas is a financial and economic viable project.

During the study there has been raised concern on the amount of gas reserves in

Tanzania. The feasibility study shows that there will be a critical balance be-

tween the potential gas supply and the potential gas demand from the markets

in Tanga and Mombasa. The proven gas reserves in Songo Songo are not suf-

fiecient to supply the potential demand from Tanga and Mombasa. However,

with the information of the vast gas reserves in Mnazi Bay there should be suf-

ficient gas to supply the demand from Tanga and Mombasa in all the demand

scenarios analysed.

It is important for getting a broad acceptance of the project, that there will be

made proof of the current expected gas reserves, on amount and accessibility.

When proofs of the expected gas reserves are made the route selection must be

done. The table below shows pros and cons for the 2 relevant routes mentioned

in the previous section.

Route 1 (Local Market) Route 4 (Least Cost)

Serving local markets in

Arusha and Morogoro.

+ 115 mill USD cost saving compared

to Route 1.

+

Serving local markets at

Kenya coast.

+ Less populated areas => Less right

of way issues.

+

Easy access to construction

site.

+ Passing National Park - Acceptance

from TANAPA is pending

-

River crossings more critical -

COWI recommends the following:

A detailed market study in Arusha and Moshi is crucial for the choice of rout-

ing:

1. If the market in Arusha and Moshi are minor, i.e. cannot justify an extra in-

vestment of 115 million USD in pipeline investment, then the least cost

(T2+K2) routing should be implemented;

2. If there is a substantial market in Arusha and Moshi, i.e. can justify an extra

investment of 115 million USD in pipeline investment, then the local market


57

.

(T1+K1) should be implemented. However, in this case the capacity of the

pipeline infrastructure as well as gas reserves should be reviewed.

Along with the above tasks EAC are to seek Developers, Financing and Con-

sultant for the project.


58

.

14 Appendices

Binder 1 is current binder.

14.1 Binder 2

Appendix A- Market Study

Appendix B- Survey report

Appendix C - Conceptual Design Report

Appendix D - Outline of Environmental and Social Impact Assessment

Appendix E - Minutes of workshops

Appendix F - List of people and places contacted

14.2 Binder 3

ESIA Tanzania

14.3 Binder 4

ESIA Kenya

feasibility report p 073620 003

Documents